Risk Management and Derivative Financial Instruments

3 Months Ended

Mar. 31, 2012

Risk Management and Derivative Financial Instruments

Risk Management and Derivative Financial Instruments

Note 4— Risk Management and Derivative Financial Instruments

We engage in hedging activities in an effort to minimize our risk from volatile natural gas prices. We enter into both physical and financial contracts with counterparties relating to our future natural gas requirements that lock in prices (with respect to a range of predetermined percentages of our expected future natural gas needs) in an attempt to lessen the volatility in our fuel expenditures and gain predictability. We recognize that if risk is not timely and adequately balanced or if counterparties fail to perform contractual obligations, actual results could differ materially from intended results.

All derivative instruments are recognized at fair value on the balance sheet with the unrealized losses or gains from derivatives used to hedge our fuel costs in our electric segment recorded in regulatory assets or liabilities. All gains and losses from derivatives related to the gas segment are also recorded in regulatory assets or liabilities. This is in accordance with the ASC guidance on regulated operations, given that those regulatory assets and liabilities are probable of recovery through our fuel adjustment mechanism.

Risks and uncertainties affecting the determination of fair value include:  market conditions in the energy industry, especially the effects of price volatility, regulatory and global political environments and requirements, fair value estimations on longer term contracts, the effectiveness of the derivative instrument in hedging the change in fair value of the hedged item, estimating underlying fuel demand and counterparty ability to perform. If we estimate that we have overhedged forecasted demand, the gain or loss on the overhedged portion will be recognized immediately as fuel and purchased power expense in our Consolidated Statement of Income and subject to our fuel adjustment clause.

As of March 31, 2012 and December 31, 2011, we have recorded the following assets and liabilities representing the fair value of derivative financial instruments, (in thousands):

		March 31,		December 31,
ASSET DERIVATIVES		2012		2011
Non-designated hedging instruments due to regulatory accounting	Balance Sheet Classification	Fair Value		Fair Value
	Non-current assets and deferred charges — Other	$	12	$	2
Total derivatives assets		$	12	$	2

LIABILITY DERIVATIVES
Non-designated as hedging instruments due to regulatory accounting		March 31, 2012		December 31, 2011
Natural gas contracts, gas segment	Current liabilities	$	1,097	$	967
	Non-current liabilities and deferred credits	3		86
Natural gas contracts, electric segment	Current liabilities	5,074		3,802
	Non-current liabilities and deferred credits	6,025		4,995
Total derivatives liabilities		$	12,199	$	9,850

Electric

At March 31, 2012, approximately $5.1 million of unrealized losses are applicable to financial instruments which will settle within the next twelve months.

The following tables set forth the actual pre-tax gains/(losses) and the mark to market effect of unsettled positions from the qualified portion of our hedging activities for settled contracts for the electric segment for each of the periods ended March 31, (in thousands):

	Income Statement Classification of	Amount of Gain / (Loss) Reclassed from OCI into Income (Effective portion)
Derivatives in Cash Flow Hedging	Gain / (Loss) on	Three Months Ended				Twelve Months Ended
Relationships - Electric Segment	Derivative	2012		2011		2012		2011
Commodity contracts	Fuel and purchased power expense	$	—	$	—	$	—	$	(5,814	)
Total Effective - Electric Segment		$	—	$	—	$	—	$	(5,814	)

	Statement of	Amount of Gain / (Loss) Recognized in OCI on Derivative (Effective portion)
Derivatives in Cash Flow Hedging	Comprehensive	Three Months Ended				Twelve Months Ended
Relationships - Electric Segment	Income	2012		2011		2012		2011
Commodity contracts	Fuel and purchased power expense	$	—	$	—	$	—	$	(361	)
Total Effective - Electric Segment		$	—	$	—	$	—	$	(361	)

There were no “mark-to-market” pre-tax gains/(losses) from ineffective portions of our hedging activities for the electric segment for the periods ended March 31, 2012 and 2011, respectively.

The following tables set forth “mark-to-market” pre-tax gains/(losses) from non-designated derivative instruments for the electric segment for each of the periods ended March 31, (in thousands):

Non-Designated Hedging Instruments	Balance Sheet	Amount of Gain / (Loss) Recognized on Balance Sheet
— Due to Regulatory Accounting	Classification of Gain /	Three Months Ended					Twelve Months Ended
Electric Segment	(Loss) on Derivative	2012			2011		2012			2011
Commodity contracts — electric segment	Regulatory (assets)/liabilities	$	(2,302	)	$	632	$	(9,899	)	$	(2,037	)
Total Electric Segment		$	(2,302	)	$	632	$	(9,899	)	$	(2,037	)

Non-Designated Hedging Instruments	Statement of Operations	Amount of Gain / (Loss) Recognized in Income on Derivative
— Due to Regulatory Accounting	Classification of Gain /	Three Months Ended					Twelve Months Ended
Electric Segment	(Loss) on Derivative	2012			2011		2012			2011
Commodity contracts	Fuel and purchased power expense	$	(24	)	$	160	$	(2,416	)	$	(592	)
Total Electric Segment		$	(24	)	$	160	$	(2,416	)	$	(592	)

We also enter into fixed-price forward physical contracts for the purchase of natural gas, coal and purchased power. These contracts are not subject to fair value accounting because they qualify for the normal purchase normal sale exemption. We have a process in place to determine if any future executed contracts that otherwise qualify for the normal purchase normal sale exception contain a price adjustment feature and will account for these contracts accordingly.

As of March 31, 2012, the following volumes and percentage of our anticipated volume of natural gas usage for our electric operations for the remainder of 2012 and for the next four years are shown below at the following average prices per Dekatherm (Dth).

Dth Hedged

Year	% Hedged		Physical	Financial	Average Price
Remainder 2012	66	%	2,111,000	1,110,000	$	6.363
2013	44	%	2,020,000	1,440,000	$	6.079
2014	20	%	460,000	1,240,000	$	5.514
2015	11	%	—	1,010,000	$	5.439
2016	—		—	—	—

We utilize the following procurement guidelines for our electric segment, allowing the flexibility to hedge up to 100% of the current year’s and 80% of any future year’s expected requirements while being cognizant of volume risk. The 80% guideline is an annual target and volumes up to 100% can be hedged in any given month. For years beyond year four, additional factors of long term uncertainty (including with respect to required volumes and counterparty credit) are also considered.

Year	Minimum % Hedged
Current	Up to 100%
First	60%
Second	40%
Third	20%
Fourth	10%

Gas

We attempt to mitigate our natural gas price risk for our gas segment by a combination of (1) injecting natural gas into storage during the off-heating season months, (2) purchasing physical forward contracts and (3) purchasing financial derivative contracts. We target to have 95% of our storage capacity full by November 1 for the upcoming winter heating season. As the winter progresses, gas is withdrawn from storage to serve our customers. As of March 31, 2012, we had 0.8 million Dths in storage on the three pipelines that serve our customers. This represents 37% of our storage capacity.

The following table sets forth our long-term hedge strategy of mitigating price volatility for our customers by hedging a minimum of expected gas usage for the current winter season and the next two winter seasons by the beginning of the Actual Cost Adjustment (ACA) year at September 1 and illustrates our hedged position as of March 31, 2012 (in thousands).

Season	Minimum % Hedged	Dth Hedged — Financial	Dth Hedged — Physical	Dth in Storage	Actual % Hedged
Current	50%	780,000	81,770	756,565	48	%
Second	Up to 50%	100,000	—	—	2	%
Third	Up to 20%	—	—	—	—
Total		880,000	81,770	756,565

A Purchased Gas Adjustment (PGA) clause is included in our rates for our gas segment operations, therefore, we mark to market any unrealized gains or losses and any realized gains or losses relating to financial derivative contracts to a regulatory asset or regulatory liability account on our balance sheet.

The following table sets forth “mark-to-market” pre-tax gains / (losses) from derivatives not designated as hedging instruments for the gas segment for each of the periods ended March 31, (in thousands).

Non-Designated Hedging	Balance Sheet Classification of	Amount of Gain / (Loss) Recognized on Balance Sheet
Instruments Due to Regulatory	Gain or (Loss) on	Three Months Ended						Twelve Months Ended
Accounting — Gas Segment	Derivative	2012			2011			2012			2011
Commodity contracts	Regulatory assets	$	(655	)	$	(96	)	$	(2,475	)	$	(595	)
Total - Gas Segment		$	(655	)	$	(96	)	$	(2,475	)	$	(595	)

Contingent Features

Certain of our derivative instruments contain provisions that require our senior unsecured debt to maintain an investment grade credit rating with any relevant credit rating agency. If our debt were to fall below investment grade, it would be in violation of these provisions, and the counterparties to the derivative instruments could request increased collateralization on derivative instruments in net liability positions. The aggregate fair value of all derivative instruments with the credit-risk-related contingent features that are in a liability position on March 31, 2012 is $3.1 million for which we have posted no collateral in the normal course of business. If the credit-risk-related contingent features underlying these agreements were triggered on March 31, 2012, we would have been required to post $3.1 million of collateral with one of our counterparties. On March 31, 2012, we had no collateral posted with this counterparty.