Note 4— Risk Management and Derivative Financial Instruments

We engage in hedging activities in an effort to minimize our risk from the volatility of natural gas prices and power cost risk associated with exposure to congestion costs. 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 began acquiring Transmission Congestion Rights (TCR) in 2013 in an attempt to mitigate the cost of power we purchase from the Southwest Power Pool (SPP) Integrated Marketplace (IM) due to congestion exposure. TCRs entitle the holder to a stream of revenues (or charges) based on the day-ahead congestion on the transmission path. TCRs can be purchased or self-converted using rights allocated based on prior investments made in the transmission system. 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. The unrealized losses or gains from derivatives used to hedge our fuel and purchased power costs in our electric segment are 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 Accounting Standards Codification (ASC) guidance on regulated operations, given that those gains or losses are probable of refund or recovery, respectively, through our fuel adjustment mechanisms.

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 instruments 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 mechanism.

As of March 31, 2016 and December 31, 2015, we have recorded the following assets and liabilities representing the fair value of derivative financial instruments, (in thousands):

		March 31,		December 31,
ASSET DERIVATIVES		2016		2015
Hedging instruments	Balance Sheet Classification	Fair Value		Fair Value
Natural gas contracts, gas segment	Current assets	$	18	$	2
	Non-current assets and deferred charges — other	—		16

Natural gas contracts, electric segment	Current assets	—		—
	Non-current assets and deferred charges — other	—		—
Transmission congestion rights, electric segment	Current assets	590		1,293

Total derivatives assets		$	608	$	1,311

		March 31,		December 31,
LIABILITY DERIVATIVES		2016		2015
Hedging instruments	Balance Sheet Classification	Fair Value		Fair Value
Natural gas contracts, gas segment	Current liabilities	$	14	$	282
	Non-current liabilities and deferred credits	51		66

Natural gas contracts, electric segment	Current liabilities	4,729		4,190

	Non-current liabilities and deferred credits	3,822		3,630

Total derivatives liabilities		$	8,616	$	8,168

Electric Segment

At March 31, 2016, approximately $4.7 million of unrealized net losses are applicable to natural gas financial instruments which will settle within the next twelve months.

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 — Due to Regulatory Accounting Electric Segment	Balance Sheet Classification of Gain / (Loss) on Derivative	Amount of Gain / (Loss) Recognized on Balance Sheet
		Three Months Ended						Twelve Months Ended
		2016			2015			2016			2015

Commodity contracts	Regulatory (assets)/liabilities	$	(1,709	)	$	(2,540	)	$	(6,022	)	$	(11,077	)

Transmission congestion rights	Regulatory (assets)/liabilities	122			1,105			3,987			13,434

Total Electric Segment		$	(1,587	)	$	(1,435	)	$	(2,035	)	$	2,357

Non-Designated Hedging Instruments — Due to Regulatory Accounting Electric Segment	Statement of Income Classification of Gain / (Loss) on Derivative	Amount of Gain / (Loss) Recognized in Income on Derivative
		Three Months Ended						Twelve Months Ended
		2016			2015			2016			2015

Commodity contracts	Fuel and purchased power expense	$	(1,698	)	$	(1,421	)	$	(8,392	)	$	(3,834	)

Transmission congestion rights	Fuel and purchased power expense	796			3,438			4,826			13,743

Total Electric Segment		$	(902	)	$	2,017		$	(3,566	)	$	9,909

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 exemption contain a price adjustment feature and will account for these contracts accordingly.

As of March 31, 2016, the following volumes and percentage of our anticipated volume of natural gas usage for our electric operations for the remainder of 2016 and for the next four years are shown below at the following average prices per Dekatherm (Dth). 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.

		Dth Hedged				Procurement
Year	% Hedged	Physical	Financial	Average Price		Guidelines
Remainder 2016	56%	2,676,000	3,860,000	$	3.54	Up to 100%
2017	41%	782,900	5,210,000	$	3.35	60%
2018	20%	565,000	2,460,000	$	3.33	40%
2019	10%	—	1,460,000	$	2.96	20%
2020	—	—	—	—		10%

At March 31, 2016, the following transmission congestion rights (TCR) have been obtained to hedge congestion risk in the SPP IM (dollars in thousands):

Year		Monthly MWH Hedged		$ Value
2016		1,430		$	590

Gas Segment

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, 2016, we had 1.3 million Dths in storage on the three pipelines that serve our customers. This represents 61% 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 and illustrates our hedged position as of March 31, 2016 (Dth in thousands).

Season	Target % Hedged by September 1	Dth Hedged — Financial	Dth Hedged — Physical	Dth in Storage	Actual % Hedged
Nov. 2016 - Mar. 2017	50%	200,000	—	1,252,281	47%
Nov. 2017 - Mar. 2018	Up to 50%	280,000	—	—	9%
Nov. 2018 - Mar. 2019	Up to 20%	—	—	—	—

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).

		Amount of Gain / (Loss)
Non-Designated Hedging	Balance Sheet	Recognized on Balance Sheet
Instruments Due to Regulatory	Classification of Gain or	Three Months Ended						Twelve Months Ended
Accounting — Gas Segment	(Loss) on Derivative	2016			2015			2016			2015

Commodity contracts	Regulatory (assets)/ liabilities	$	(67	)	$	(17	)	$	(497	)	$	(478	)

Total - Gas Segment		$	(67	)	$	(17	)	$	(497	)	$	(478	)

Contingent Features

Certain of our derivative instruments contain provisions that are triggered if we fail to maintain an investment grade credit rating with any relevant credit rating agency. If our debt were to fall below investment grade, the counterparties to the derivative instruments could request increased collateralization on derivative instruments in net liability positions. We had no derivative instruments with the credit-risk-related contingent features in a net liability position on March 31, 2016 and have posted no collateral with counterparties in the normal course of business. Amounts reported as margin deposit assets represent our funds held on deposit for our contracts held with our NYMEX broker and other financial contracts with other counterparties that resulted from us exceeding agreed-upon credit limits established by the counterparties. The following table depicts our margin deposit assets at the dates shown. There were no margin deposit liabilities at these dates.

(in millions)		March 31, 2016				December 31, 2015
Margin deposit assets		$	10.3			$	11.2

Offsetting of derivative assets and liabilities

We believe that entering into master trading and netting agreements mitigates the level of financial loss that could result from a default under derivatives agreements by allowing net settlement of derivative assets and liabilities. We generally enter into the following master trading and netting agreements: (1) the International Swaps and Derivatives Association Agreement, a standardized financial natural gas and electric contract; and (2) the North American Energy Standards Board Inc. Agreement, a standardized contract for the purchase and sale of natural gas. These master trading and netting agreements allow the counterparties to net settle sale and purchase transactions. Collateral requirements are calculated at the master trading and netting agreement level by the counterparty.

As shown above, our asset and liability commodity contract derivatives are reported at gross on the balance sheet. ASC guidance permits companies to offset fair value amounts recognized for the right to reclaim cash collateral (a receivable) or the obligation to return cash collateral (a liability) against fair value amounts recognized for derivative instruments that are executed with the same counterparty under the same master netting arrangement. For the periods ended March 31, 2016 and December 31, 2015, we did not hold any collateral posted by our counterparties. The only collateral we have posted is our margin deposit assets described above. We have elected not to offset our margin deposit assets against any of our eligible commodity contracts.