RISK MANAGEMENT AND DERIVATIVE FINANCIAL INSTRUMENTS

12 Months Ended

Dec. 31, 2011

RISK MANAGEMENT AND DERIVATIVE FINANCIAL INSTRUMENTS

RISK MANAGEMENT AND DERIVATIVE FINANCIAL INSTRUMENTS

14.   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 December 31, 2011 and 2010, we have recorded the following assets and liabilities representing the fair value of derivative financial instruments held as of December 31, (in thousands):

ASSET DERIVATIVES

Non-designated hedging instruments due to regulatory accounting		2011		2010
	Balance Sheet Classification	Fair Value		Fair Value
Natural gas contracts, gas segment	Current assets — Prepaid expenses and other		—		39
	Non-current assets and deferred charges — Other		2		117
Natural gas contracts, electric segment	Current assets — Prepaid expenses and other		—		—
	Non-current assets and deferred charges — Other				77
Total derivatives assets		$	2	$	233

LIABILITY DERIVATIVES

Derivatives designated as hedging instruments		2011		2010
	Balance Sheet Classification	Fair Value		Fair Value
Natural gas contracts, electric segment	Current liabilities	$	—	$	—
	Non-current liabilities and deferred credits		—		—
Non-designated as hedging instruments due to regulatory accounting
Natural gas contracts, gas segment	Current liabilities		967		252
	Non-current liabilities and deferred credits		86		2
Natural gas contracts, electric segment	Current liabilities		3,802		508
	Non-current liabilities and deferred credits		4,995		3,562
Total derivatives liabilities		$	9,850	$	4,324

Electric

        At December 31, 2011, approximately $3.8 million of unrealized losses are applicable to financial instruments which will settle within the next twelve months. Effective September 1, 2008, in conjunction with the implementation of the Missouri fuel adjustment clause in the July 2008 MPSC rate order, new hedges are non-designated and the unrealized losses or gains are recorded in regulatory assets or liabilities. This is in accordance with ASC guidance on accounting for regulated operations, given that those regulatory assets and liabilities are probable of recovery through our fuel adjustment mechanism. Effective December 2010 all remaining cash flow hedges entered into prior to September 1, 2008 were de-designated and the unrealized loss of $1.0 million was transferred from OCI to a regulatory asset. Unrealized gains and losses are now recorded in regulatory assets or liabilities in accordance with the ASC guidance mentioned.

        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 years ended December 31, (in thousands):

Derivatives in Cash Flow Hedging Relationships — Electric Segment

		Amount of Loss Reclassed from OCI into Income (Effective Portion)
	Income Statement Classification of Loss on Derivative	2011		2010
Commodity contracts	Fuel and purchased power expense	$	—	$	(5,814	)
Total Effective — Electric Segment		$	—	$	(5,814	)

Derivatives in Cash Flow Hedging Relationships — Electric Segment

		Amount of Loss Recognized in OCI on Derivative (Effective Portion)
	Statement of Comprehensive Income	2011		2010
Commodity contracts	Fuel and purchased power expense	$	—	$	(6,362	)
Total Effective — Electric Segment		$	—	$	(6,362	)

        There were no "mark-to-market" pre-tax gains/(losses) from ineffective portions of our hedging activities for the electric segment for the years ended December 31, 2011 and 2010, 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 years ended December 31, (in thousands):

Non-Designated Hedging Instruments — Due to Regulatory Accounting Electric Segment

		Amount of Loss Recognized on Balance Sheet
	Balance Sheet Classification of Loss on Derivative	2011			2010
Commodity contracts — electric segment	Regulatory assets	$	(6,965	)	$	(2,669	)
Total — Electric Segment		$	(6,965	)	$	(2,669	)

Non-Designated Hedging Instruments — Due to Regulatory Accounting Electric Segment

		Amount of Loss Recognized in Income on Derivative
	Statement of Operations Classification of Loss on Derivative	2011			2010
Commodity contracts	Fuel and purchased power expense	$	(2,231	)	$	(752	)
Total — Electric Segment		$	(2,231	)	$	(752	)

        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.

        At December 31, 2011, the following volumes and percentages of our anticipated volume of natural gas usage for our electric operations for 2012 and the next four years are hedged at the following average prices per Dekatherm (Dth):

Year	% Hedged			Dth Hedged Physical		Dth Hedged Financial		Average Price
2012		61	%		2,511,000		1,420,000	$	6.459
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		0	%		—		—	$	—

        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	End of 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 December 31, 2011 we had 1.5 million Dths in storage on the three pipelines that serve our customers. This represents 76% 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 ACA year at September 1 and illustrates our hedged position as of December 31, 2011 (Dth in thousands).

Season	Minimum % Hedged			Dth Hedged Financial		Dth Hedged Physical		Dth in Storage		Actual % Hedged
Current		50	%		420		310		1,436		98	%
Second		Up to 50	%		700		—		—		16	%
Third		Up to 20	%		—		—		—
Total					1,120		310		1,436

        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 the years ended December 31, (in thousands):

Non-Designated Hedging Instruments Due to Regulatory Accounting — Gas Segment

		Amount of Loss Recognized on Balance Sheet
	Balance Sheet Classification of Loss on Derivative	2011			2010
Commodity contracts	Regulatory assets	$	(1,916	)	$	(626	)
Total — Gas Segment		$	(1,916	)	$	(626	)

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 December 31, 2011 is $2.4 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 December 31, 2011, we would have been required to post $2.4 million of collateral with one of our counterparties. On December 31, 2011, we had no collateral posted with this counterparty.