Risk Management and Derivative Financial Instruments

9 Months Ended

Sep. 30, 2011

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 volatility in 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. In conjunction with the implementation of the Missouri fuel adjustment clause, the unrealized losses or gains from new derivatives used to hedge our fuel costs in our electric segment are recorded in regulatory assets or liabilities. All gains and losses from derivatives related to the gas segment are 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 September 30, 2011 and December 31, 2010, we have recorded the following assets and liabilities representing the fair value of derivative financial instruments, (in thousands):

		September 30,		December 31,
ASSET DERIVATIVES		2011		2010
Non-designated hedging instruments due to regulatory accounting	Balance Sheet Classification	Fair Value		Fair Value
Natural gas contracts, gas segment	Current assets	$	—	$	39
	Non-current assets and deferred charges	—		117
Natural gas contracts, electric segment	Current assets	—		—
	Non-current assets and deferred charges	—		77
Total derivatives assets		$	—	$	233

		September 30,		December 31,
LIABILITY DERIVATIVES		2011		2010
Non-designated hedging instruments due to regulatory accounting	Balance Sheet Classification	Fair Value		Fair Value
Natural gas contracts, gas segment	Current liabilities	$	469	$	252
	Non-current liabilities and deferred credits	73		2
Natural gas contracts, electric segment	Current liabilities	2,933		508
	Non-current liabilities and deferred credits	2,912		3,562
Total derivatives liabilities		$	6,387	$	4,324

Electric

At September 30, 2011, approximately $2.9 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 September 30, (in thousands):

Derivatives in Cash Flow Hedging	Income Statement Classification of	Amount of Gain / (Loss) Reclassed from OCI into Income (Effective portion)
Relationships -	Gain / (Loss) on	Three Months Ended					Nine Months Ended					Twelve Months Ended
Electric Segment	Derivative	2011		2010			2011		2010			2011		2010
Commodity contracts	Fuel and purchased power expense	$	—	$	(4,864	)	$	—	$	(5,814	)	$	—	$	(6,703	)
Total Effective — Electric Segment		$	—	$	(4,864	)	$	—	$	(5,814	)	$	—	$	(6,703	)

Derivatives in Cash Flow Hedging	Statement of	Amount of Gain / (Loss) Recognized in OCI on Derivative (Effective portion)
Relationships -	Comprehensive	Three Months Ended					Nine Months Ended					Twelve Months Ended
Electric Segment	Income	2011		2010			2011		2010			2011			2010
Commodity contracts	Net change in fair value	$	—	$	(1,934	)	$	—	$	(7,258	)	$	(896	)	$	(9,278	)
Total Effective — Electric Segment		$	—	$	(1,934	)	$	—	$	(7,258	)	$	(896	)	$	(9,278	)

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 September 30, 2011 and 2010, respectively.

In accordance with the Missouri fuel adjustment clause discussed above, the recoverable portion of any gain or loss is recorded in a regulatory asset or liability account. 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 September 30, (in thousands):

Non-Designated Hedging Instruments - Due to	Balance Sheet Classification of	Amount of (Loss) Recognized on Balance Sheet
Regulatory Accounting	Gain / (Loss) on	Three Months Ended						Nine Months Ended						Twelve Months Ended
Electric Segment	Derivatives	2011			2010			2011			2010			2011			2010
Commodity contracts	Regulatory (assets)/liabilities	$	(2,022	)	$	(1,646	)	$	(2,758	)	$	(3,384	)	$	(3,165	)	$	(3,840	)
Total Electric Segment		$	(2,022	)	$	(1,646	)	$	(2,758	)	$	(3,384	)	$	(3,165	)	$	(3,840	)

Non-Designated Hedging Instruments - Due to	Statement of Operations Classification of	Amount of (Loss) Recognized in Income
Regulatory Accounting	Gain / (Loss) on	Three Months Ended						Nine Months Ended						Twelve Months Ended
Electric Segment	Derivatives	2011			2010			2011			2010			2011			2010
Commodity contracts	Fuel and purchased power expense	$	(966	)	$	(363	)	$	(1,358	)	$	(760	)	$	(1,441	)	$	(859	)
Total Electric Segment		$	(966	)	$	(363	)	$	(1,358	)	$	(760	)	$	(1,441	)	$	(859	)

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 October 21, 2011, the following volumes and percentage of our anticipated volume of natural gas usage for our electric operations for the remainder of 2011 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 2011	44	%	327,500	—	$	7.085
2012	60	%	2,325,000	1,420,000	$	6.618
2013	41	%	2,020,000	1,440,000	$	6.079
2014	20	%	460,000	1,120,000	$	5.607
2015	7	%	—	700,000	$	5.562

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 September 30, 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 Actual Cost Adjustment (ACA) year at September 1 and illustrates our hedged position as of September 30, 2011.

Season	Minimum % Hedged	Dth Hedged Financial	Dth Hedged Physical	Dth in Storage	Actual % Hedged
Current	50%	790,000	222,200	1,532,769	70	%
Second	Up to 50%	310,000	—	—	7	%
Third	Up to 20%	—	—	—	—	%
Total		1,100,000	222,200	1,532,769

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 September 30, (in thousands).

Non-Designated Hedging	Balance Sheet Classification of	Amount of (Loss) Recognized on Balance Sheet
Instruments Due to Regulatory	Gain / (Loss) on	Three Months Ended						Nine Months Ended						Twelve Months Ended
Accounting - Gas Segment	Derivatives	2011			2010			2011			2010			2011			2010
Commodity contracts	Regulatory (assets)/liabilities	$	(572	)	$	(602	)	$	(842	)	$	(781	)	$	(688	)	$	(283	)
Total - Gas Segment		$	(572	)	$	(602	)	$	(842	)	$	(781	)	$	(688	)	$	(283	)

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 September 30, 2011, is $1.2 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 September 30, 2011, we would have been required to post $1.2 million of collateral with the counterparty.