Financial Instruments

We use financial instruments to mitigate commodity price risk and interest rate risk. The objectives and strategies for using financial instruments have been tailored to our regulated and nonregulated businesses. Currently, we utilize financial instruments in our natural gas distribution and nonregulated segments. We currently do not manage commodity price risk with financial instruments in our regulated transmission and storage segment.

Our financial instruments do not contain any credit-risk-related or other contingent features that could cause accelerated payments when our financial instruments are in net liability positions.

As discussed in Note 2, we report our financial instruments as risk management assets and liabilities, each of which is classified as current or noncurrent based upon the anticipated settlement date of the underlying financial instrument. The following table shows the fair values of our risk management assets and liabilities by segment at September 30, 2013 and 2012:



	Natural Gas Distribution			Nonregulated			Total
	(In thousands)
September 30, 2013
Assets from risk management activities, current⁽¹⁾	$	1,837		$	16,262		$	18,099
Assets from risk management activities, noncurrent	109,354			—			109,354
Liabilities from risk management activities, current⁽¹⁾	(1,543		)	—			(1,543		)
Liabilities from risk management activities, noncurrent	—			(6,133		)	(6,133		)
Net assets (liabilities)	$	109,648		$	10,129		$	119,777
September 30, 2012⁽³⁾
Assets from risk management activities, current⁽²⁾	$	6,934		$	17,773		$	24,707
Assets from risk management activities, noncurrent	2,283			—			2,283
Liabilities from risk management activities, current⁽²⁾	(85,366		)	(15		)	(85,381		)
Liabilities from risk management activities, noncurrent	—			(9,206		)	(9,206		)
Net assets (liabilities)	$	(76,149	)	$	8,552		$	(67,597	)


⁽¹⁾	Includes $24.8 million of cash held on deposit to collateralize certain financial instruments. Of this amount, $8.6 million was used to offset current risk management liabilities under master netting arrangements and the remaining $16.2 million is classified as current risk management assets.


⁽²⁾	Includes $23.7 million of cash held on deposit to collateralize certain financial instruments. Of this amount, $5.9 million was used to offset current risk management liabilities under master netting arrangements and the remaining $17.8 million is classified as current risk management assets.


⁽³⁾	The September 30, 2012 amounts are presented net of assets and liabilities held for sale in conjunction with the sale of our Georgia operations. At September 30, 2012, assets and liabilities held for sale included $0.1 million of current assets from risk management activities and $0.3 million of current liabilities from risk management activities.

Regulated Commodity Risk Management Activities

Although our purchased gas cost adjustment mechanisms essentially insulate our natural gas distribution segment from commodity price risk, our customers are exposed to the effects of volatile natural gas prices. We manage this exposure through a combination of physical storage, fixed-price forward contracts and financial instruments, primarily over-the-counter swap and option contracts, in an effort to minimize the impact of natural gas price volatility on our customers during the winter heating season.

Our natural gas distribution gas supply department is responsible for executing this segment’s commodity risk management activities in conformity with regulatory requirements. In jurisdictions where we are permitted to mitigate commodity price risk through financial instruments, the relevant regulatory authorities may establish the level of heating season gas purchases that can be hedged. Historically, if the regulatory authority does not establish this level, we seek to hedge between 25 and 50 percent of anticipated heating season gas purchases using financial instruments. For the 2012-2013 heating season (generally October through March), in the jurisdictions where we are permitted to utilize financial instruments, we hedged approximately 33 percent, or 22.8 Bcf of the winter flowing gas requirements at a weighted average cost of approximately $4.03 per Mcf. We have not designated these financial instruments as hedges.

Nonregulated Commodity Risk Management Activities

In our nonregulated operations, we buy, sell and deliver natural gas at competitive prices by aggregating and purchasing gas supply, arranging transportation and storage logistics and effectively managing commodity price risk.

As a result of these activities, our nonregulated segment is exposed to risks associated with changes in the market price of natural gas. We manage our exposure to such risks through a combination of physical storage and financial instruments, including futures, over-the-counter and exchange-traded options and swap contracts with counterparties. Future contracts provide the right to buy or sell the commodity at a fixed price in the future. Option contracts provide the right, but not the requirement, to buy or sell the commodity at a fixed price. Swap contracts require receipt of payment for the commodity based on the difference between a fixed price and the market price on the settlement date.

We use financial instruments, designated as cash flow hedges of anticipated purchases and sales at index prices, to mitigate the commodity price risk associated with deliveries under fixed-priced forward contracts to deliver gas to customers. These financial instruments have maturity dates ranging from one to 55 months. We use financial instruments, designated as fair value hedges, to hedge natural gas inventory used in these operations. We also use storage and basis swaps, futures and various over-the-counter and exchange-traded options primarily to protect the economic value of our fixed price and storage books. These financial instruments have not been designated as hedges.

Our nonregulated risk management activities are controlled through various risk management policies and procedures. Our Audit Committee has oversight responsibility for our nonregulated risk management limits and policies. A risk committee, comprised of corporate and business unit officers, is responsible for establishing and enforcing our nonregulated risk management policies and procedures.

Under our risk management policies, we seek to match our financial instrument positions to our physical storage positions as well as our expected current and future sales and purchase obligations in order to maintain no open positions at the end of each trading day. The determination of our net open position as of any day, however, requires us to make assumptions as to future circumstances, including the use of gas by our customers in relation to our anticipated storage and market positions. Because the price risk associated with any net open position at the end of each day may increase if the assumptions are not realized, we review these assumptions as part of our daily monitoring activities. Our operations can also be affected by intraday fluctuations of gas prices, since the price of natural gas purchased or sold for future delivery earlier in the day may not be hedged until later in the day. At times, limited net open positions related to our existing and anticipated commitments may occur. At the close of business on September 30, 2013, our nonregulated segment had net open positions (including existing storage and related financial contracts) of 0.1 Bcf.

Interest Rate Risk Management Activities

We have periodically managed interest rate risk by entering into financial instruments to fix the Treasury yield component of the interest cost associated with anticipated financings. Prior to fiscal 2012, we used Treasury locks to mitigate interest rate risk; however, in the fourth quarter of fiscal 2012 we started utilizing interest rate swaps and forward starting interest rate swaps to manage this risk.

In August 2011, we entered into three Treasury lock agreements to fix the Treasury yield component of the interest cost associated with $350 million out of a total $500 million of senior notes that were issued on January 11, 2013. This offering is discussed in Note 5. We designated these Treasury locks as cash flow hedges. The Treasury locks were settled on January 8, 2013 with a payment of $66.6 million to the counterparties due to a decrease in the 30-year Treasury rates between inception of the Treasury locks and settlement. Because the Treasury locks were effective, the $66.6 million unrealized loss was recorded as a component of accumulated other comprehensive income and is being recognized as a component of interest expense over the 30-year life of the senior notes.

In the fourth quarter of fiscal 2012 we entered into an interest rate swap to fix the LIBOR component of our $260 million short-term financing facility through December 27, 2012. We recorded an immaterial loss upon settlement of the swap, which was recorded as a component of interest expense as we did not designate the interest rate swap as a hedge.

In October 2012, we entered into forward starting interest rate swaps to fix the Treasury yield component associated with the anticipated issuance of $500 million and $250 million unsecured senior notes in fiscal 2015 and fiscal 2017, which we designated as cash flow hedges at the time the agreements were executed. Accordingly, unrealized gains and losses associated with the forward starting interest rate swaps will be recorded as a component of accumulated other comprehensive income (loss). When the forward starting interest rate swaps settle, the realized gain or loss will be recorded as a component of accumulated other comprehensive income (loss) and recognized as a component of interest expense over the life of the related financing arrangement. Hedge ineffectiveness to the extent incurred will be reported as a component of interest expense.

In September 2010, we entered into three Treasury lock agreements to fix the Treasury yield component of the interest cost associated with $300 million of a total $400 million of senior notes that were issued in June 2011. We designated these Treasury locks as cash flow hedges. The Treasury locks were settled on June 7, 2011 with the receipt of $20.1 million from the counterparties due to an increase in the 30-year Treasury lock rates between inception of the Treasury locks and settlement. Because the Treasury locks were effective, the net $12.6 million unrealized gain was recorded as a component of accumulated other comprehensive income and is being recognized as a component of interest expense over the 30-year life of the senior notes.

Additionally, our original fiscal 2011 financing plans included the issuance of $250 million of 30-year unsecured notes in November 2011 to fund our capital expenditure program. In September 2010, we entered into two Treasury lock agreements to fix the Treasury yield component of the interest cost associated with the anticipated issuance of these senior notes, which were designated as cash flow hedges. Due primarily to stronger than anticipated cash flows primarily resulting from the extension of the Bush tax cuts that allow the continued use of bonus depreciation on qualifying expenditures through December 31, 2011, the need to issue $250 million of debt in November was eliminated and the related Treasury lock agreements were unwound in March 2011. As a result of unwinding these Treasury locks, we recognized a pre-tax cash gain of $27.8 million during the second quarter of fiscal 2011.

In prior years, we entered into several Treasury lock agreements to fix the Treasury yield component of the interest cost of financing for various issuances of long-term debt and senior notes. The gains and losses realized upon settlement of these Treasury locks were recorded as a component of accumulated other comprehensive income (loss) when they were settled and are being recognized as a component of interest expense over the life of the associated notes from the date of settlement. The remaining amortization periods for the settled Treasury locks extend through fiscal 2043.

Quantitative Disclosures Related to Financial Instruments

The following tables present detailed information concerning the impact of financial instruments on our consolidated balance sheet and income statements.

As of September 30, 2013, our financial instruments were comprised of both long and short commodity positions. A long position is a contract to purchase the commodity, while a short position is a contract to sell the commodity. As of September 30, 2013, we had net long/(short) commodity contracts outstanding in the following quantities:



Contract Type	Hedge Designation	Natural Gas Distribution	Nonregulated
		Quantity (MMcf)
Commodity contracts	Fair Value	—	(13,033	)
	Cash Flow	—	31,195
	Not designated	29,185	75,683
		29,185	93,845

Financial Instruments on the Balance Sheet

The following tables present the fair value and balance sheet classification of our financial instruments by operating segment as of September 30, 2013 and 2012. As required by authoritative accounting literature, the fair value amounts below are presented on a gross basis and do not reflect the netting of asset and liability positions permitted under the terms of our master netting arrangements. Further, the amounts below do not include $24.8 million and $23.7 million of cash held on deposit in margin accounts as of September 30, 2013 and 2012 to collateralize certain financial instruments. Therefore, these gross balances are not indicative of either our actual credit exposure or net economic exposure. Additionally, the amounts below will not be equal to the amounts presented on our consolidated balance sheet, nor will they be equal to the fair value information presented for our financial instruments in Note 14.



	Balance Sheet Location	Natural Gas Distribution			Nonregulated			Total
					(In thousands)
September 30, 2013
Designated As Hedges:
Asset Financial Instruments
Current commodity contracts	Other current assets	$	—		$	9,094		$	9,094
Noncurrent commodity contracts	Deferred charges and other assets	107,512			416			107,928
Liability Financial Instruments
Current commodity contracts	Other current liabilities	—			(12,173		)	(12,173		)
Noncurrent commodity contracts	Deferred credits and other liabilities	—			(1,639		)	(1,639		)
Total		107,512			(4,302		)	103,210
Not Designated As Hedges:
Asset Financial Instruments
Current commodity contracts	Other current assets	1,837			65,388			67,225
Noncurrent commodity contracts	Deferred charges and other assets	1,842			40,982			42,824
Liability Financial Instruments
Current commodity contracts	Other current liabilities	(1,543		)	(70,876		)	(72,419		)
Noncurrent commodity contracts	Deferred credits and other liabilities	—			(45,892		)	(45,892		)
Total		2,136			(10,398		)	(8,262		)
Total Financial Instruments		$	109,648		$	(14,700	)	$	94,948



	Balance Sheet Location	Natural Gas Distribution			Nonregulated			Total
		(In thousands)
September 30, 2012
Designated As Hedges:
Asset Financial Instruments
Current commodity contracts	Other current assets	$	—		$	19,301		$	19,301
Noncurrent commodity contracts	Deferred charges and other assets	—			1,923			1,923
Liability Financial Instruments
Current commodity contracts	Other current liabilities	(85,040		)	(23,787		)	(108,827		)
Noncurrent commodity contracts	Deferred credits and other liabilities	—			(4,999		)	(4,999		)
Total		(85,040		)	(7,562		)	(92,602		)
Not Designated As Hedges:
Asset Financial Instruments
Current commodity contracts	Other current assets⁽¹⁾	7,082			98,393			105,475
Noncurrent commodity contracts	Deferred charges and other assets	2,283			60,932			63,215
Liability Financial Instruments
Current commodity contracts	Other current liabilities⁽²⁾	(585		)	(99,824		)	(100,409		)
Noncurrent commodity contracts	Deferred credits and other liabilities	—			(67,062		)	(67,062		)
Total		8,780			(7,561		)	1,219
Total Financial Instruments		$	(76,260	)	$	(15,123	)	$	(91,383	)


⁽¹⁾	Other current assets not designated as hedges in our natural gas distribution segment include $0.1 million related to risk management assets that were classified as assets held for sale at September 30, 2012.


⁽²⁾	Other current liabilities not designated as hedges in our natural gas distribution segment include $0.3 million related to risk management liabilities that were classified as assets held for sale at September 30, 2012.

Impact of Financial Instruments on the Income Statement

Hedge ineffectiveness for our nonregulated segment is recorded as a component of unrealized gross profit and primarily results from differences in the location and timing of the derivative instrument and the hedged item. Hedge ineffectiveness could materially affect our results of operations for the reported period. For the years ended September 30, 2013, 2012 and 2011, we recognized a gain arising from fair value and cash flow hedge ineffectiveness of $18.2 million, $23.1 million and $24.8 million. Additional information regarding ineffectiveness recognized in the income statement is included in the tables below.

Fair Value Hedges

The impact of our nonregulated commodity contracts designated as fair value hedges and the related hedged item on our consolidated income statement for the years ended September 30, 2013, 2012 and 2011 is presented below.



	Fiscal Year Ended September 30
	2013			2012			2011
	(In thousands)
Commodity contracts	$	2,165		$	30,266		$	16,552
Fair value adjustment for natural gas inventory designated as the hedged item	15,938			(5,797		)	9,824
Total decrease in purchased gas cost	$	18,103		$	24,469		$	26,376
The decrease in purchased gas cost is comprised of the following:
Basis ineffectiveness	$	(208	)	$	1,170		$	803
Timing ineffectiveness	18,311			23,299			25,573
	$	18,103		$	24,469		$	26,376

Basis ineffectiveness arises from natural gas market price differences between the locations of the hedged inventory and the delivery location specified in the hedge instruments. Timing ineffectiveness arises due to changes in the difference between the spot price and the futures price, as well as the difference between the timing of the settlement of the futures and the valuation of the underlying physical commodity. As the commodity contract nears the settlement date, spot-to-forward price differences should converge, which should reduce or eliminate the impact of this ineffectiveness on purchased gas cost.

To the extent that the Company’s natural gas inventory does not qualify as a hedged item in a fair-value hedge, or has not been designated as such, the natural gas inventory is valued at the lower of cost or market. During the year ended September 30, 2012, we recorded a $1.7 million charge to write down nonqualifying natural gas inventory to market. We did not record a writedown for nonqualifying natural gas inventory for the years ended September 30, 2013 and 2011.

Cash Flow Hedges

The impact of cash flow hedges on our consolidated income statements for the years ended September 30, 2013, 2012 and 2011 is presented below. Note that this presentation does not reflect the financial impact arising from the hedged physical transaction. Therefore, this presentation is not indicative of the economic gross profit we realized when the underlying physical and financial transactions were settled.



	Fiscal Year Ended September 30, 2013
	Natural Gas Distribution			Regulated Transmission and Storage		Nonregulated			Consolidated
	(In thousands)
Loss reclassified from AOCI for effective portion of commodity contracts	$	—		$	—	$	(10,778	)	$	(10,778	)
Gain arising from ineffective portion of commodity contracts	—			—		97			97
Total impact on purchased gas cost	—			—		(10,681		)	(10,681		)
Net loss on settled interest rate agreements reclassified from AOCI into interest expense	(3,489		)	—		—			(3,489		)
Total impact from cash flow hedges	$	(3,489	)	$	—	$	(10,681	)	$	(14,170	)



	Fiscal Year Ended September 30, 2012
	Natural Gas Distribution			Regulated Transmission and Storage		Nonregulated			Consolidated
	(In thousands)
Loss reclassified from AOCI for effective portion of commodity contracts	$	—		$	—	$	(62,678	)	$	(62,678	)
Loss arising from ineffective portion of commodity contracts	—			—		(1,369		)	(1,369		)
Total impact on purchased gas cost	—			—		(64,047		)	(64,047		)
Net loss on settled interest rate agreements reclassified from AOCI into interest expense	(2,009		)	—		—			(2,009		)
Total impact from cash flow hedges	$	(2,009	)	$	—	$	(64,047	)	$	(66,056	)



	Fiscal Year Ended September 30, 2011
	Natural Gas Distribution			Regulated Transmission and Storage		Nonregulated			Consolidated
	(In thousands)
Loss reclassified from AOCI for effective portion of commodity contracts	$	—		$	—	$	(28,430	)	$	(28,430	)
Loss arising from ineffective portion of commodity contracts	—			—		(1,585		)	(1,585		)
Total impact on purchased gas cost	—			—		(30,015		)	(30,015		)
Net loss on settled interest rate agreements reclassified from AOCI into interest expense	(2,455		)	—		—			(2,455		)
Gain on unwinding of interest rate agreement reclassified from AOCI into miscellaneous income	21,803			6,000		—			27,803
Total impact from cash flow hedges	$	19,348		$	6,000	$	(30,015	)	$	(4,667	)

The following table summarizes the gains and losses arising from hedging transactions that were recognized as a component of other comprehensive income (loss), net of taxes, for the years ended September 30, 2013 and 2012. The amounts included in the table below exclude gains and losses arising from ineffectiveness because these amounts are immediately recognized in the income statement as incurred.



	Fiscal Year Ended September 30
	2013			2012
	(In thousands)
Increase (decrease) in fair value:
Interest rate agreements	$	79,963		$	(11,458	)
Forward commodity contracts	(2,057		)	(30,366		)
Recognition of (gains) losses in earnings due to settlements:
Interest rate agreements	2,216			1,342
Forward commodity contracts	6,576			38,232
Total other comprehensive income (loss) from hedging, net of tax⁽¹⁾	$	86,698		$	(2,250	)


⁽¹⁾	Utilizing an income tax rate ranging from approximately 37 percent to 39 percent based on the effective rates in each taxing jurisdiction.

Deferred gains (losses) recorded in AOCI associated with our interest rate agreements are recognized in earnings as they are amortized, while deferred losses associated with commodity contracts are recognized in earnings upon settlement. The following amounts, net of deferred taxes, represent the expected recognition in earnings of the deferred gains (losses) recorded in AOCI associated with our financial instruments, based upon the fair values of these financial instruments as of September 30, 2013. However, the table below does not include the expected recognition in earnings of the interest rate agreements entered into in October 2012 as those financial instruments have not yet settled.



	Interest Rate Agreements			Commodity Contracts			Total
	(In thousands)
2014	$	(2,686	)	$	(3,748	)	$	(6,434	)
2015	(804		)	(425		)	(1,229		)
2016	(634		)	(163		)	(797		)
2017	(735		)	(109		)	(844		)
2018	(936		)	(31		)	(967		)
Thereafter	(24,569		)	—			(24,569		)
Total⁽¹⁾	$	(30,364	)	$	(4,476	)	$	(34,840	)


⁽¹⁾	Utilizing an income tax rate ranging from approximately 37 percent to 39 percent based on the effective rates in each taxing jurisdiction.

Financial Instruments Not Designated as Hedges

The impact of financial instruments that have not been designated as hedges on our consolidated income statements for the years ended September 30, 2013, 2012 and 2011 was an increase (decrease) in purchased gas cost of $3.0 million, $(2.5) million and $(1.4) million. Note that this presentation does not reflect the expected gains or losses arising from the underlying physical transactions associated with these financial instruments. Therefore, this presentation is not indicative of the economic gross profit we realized when the underlying physical and financial transactions were settled.

As discussed above, financial instruments used in our natural gas distribution segment are not designated as hedges. However, there is no earnings impact on our natural gas distribution segment as a result of the use of these financial instruments because the gains and losses arising from the use of these financial instruments are recognized in the consolidated statement of income as a component of purchased gas cost when the related costs are recovered through our rates and recognized in revenue. Accordingly, the impact of these financial instruments is excluded from this presentation.