NOTE 7: DERIVATIVES

Use of Derivative Instruments

The Utility uses both derivative and non-derivative contracts in managing its customers’ exposure to commodity-related price risk, including:

•

forward contracts that commit the Utility to purchase a commodity in the future;

•

swap agreements that require payments to or from counterparties based upon the difference between two prices for a predetermined contractual quantity; and

•

option contracts that provide the Utility with the right to buy a commodity at a predetermined price and option contracts that require payments from counterparties if market prices exceed a predetermined price.

These instruments are not held for speculative purposes and are subject to certain regulatory requirements. The CPUC allows the Utility to charge customer rates designed to recover the Utility’s reasonable costs of providing services, including the costs related to price risk management activities.

Price risk management activities that meet the definition of derivatives are recorded at fair value on the Condensed Consolidated Balance Sheets. As long as the current ratemaking mechanism discussed above remains in place and the Utility’s price risk management activities are carried out in accordance with CPUC directives, the Utility expects to recover fully, in rates, all costs related to derivatives. Therefore, all unrealized gains and losses associated with the change in fair value of these derivative instruments are deferred and recorded within the Utility’s regulatory assets and liabilities on the Condensed Consolidated Balance Sheets. (See Note 3 above.) Net realized gains or losses are recorded in the cost of electricity or the cost of natural gas with corresponding increases or decreases to regulatory balancing accounts for recovery from or refund to customers.

The Utility elects the normal purchase and sale exception for eligible derivatives. Derivatives that require physical delivery in quantities that are expected to be used by the Utility over a reasonable period in the normal course of business, and do not contain pricing provisions unrelated to the commodity delivered are eligible for the normal purchase and sale exception. The fair value of derivatives that are eligible for the normal purchase and sales exception are not reflected in the Condensed Consolidated Balance Sheets.

Electricity Procurement

The Utility enters into third-party power purchase agreements for electricity to meet customer needs. The Utility’s third-party power purchase agreements are generally accounted for as leases, but certain third-party power purchase agreements are considered derivatives. The Utility elects the normal purchase and sale exception for eligible derivatives.

A portion of the Utility’s third-party power purchase agreements contain market-based pricing terms. In order to reduce volatility in customer rates, the Utility may enter into financial swap contracts or financial option contracts, or both, to effectively fix or cap, or both, the price of future purchases and reduce cash flow variability associated with fluctuating electricity prices. These financial contracts would be considered derivatives.

Electric Transmission Congestion Revenue Rights

The California electric transmission grid, controlled by the California Independent System Operator (“CAISO”), is subject to transmission constraints when there is insufficient transmission capacity to supply the market. The CAISO imposes congestion charges on market participants to manage transmission congestion. The revenue generated from congestion charges is allocated to holders of congestion revenue rights (“CRRs”). CRRs allow market participants to hedge the financial risk of CAISO-imposed congestion charges in the day-ahead market. The CAISO releases CRRs through an annual and monthly process, each of which includes an allocation phase (in which load-serving entities, such as the Utility, are allocated CRRs at no cost based on the customer demand or “load” they serve) and an auction phase (in which CRRs are priced at market and available to all market participants). The Utility participates in the allocation and auction phases of the annual and monthly CRR processes. CRRs are considered derivatives.

Natural Gas Procurement (Electric Fuels Portfolio)

The Utility’s electric procurement portfolio is exposed to natural gas price risk primarily through physical natural gas commodity purchases to fuel natural gas generating facilities, and electricity procurement contracts indexed to natural gas prices. To reduce the volatility in customer rates, the Utility purchases financial instruments, such as swaps and options, and enters into fixed-price forward contracts for natural gas, to reduce future cash flow variability from fluctuating natural gas prices. These instruments are considered derivatives.

Natural Gas Procurement (Core Gas Supply Portfolio)

The Utility enters into physical natural gas commodity contracts to fulfill the needs of its residential and smaller commercial customers known as “core” customers. (The Utility does not procure natural gas for industrial and large commercial, or “non-core,” customers.) Changes in temperature cause natural gas demand to vary daily, monthly, and seasonally. Consequently, varying volumes of natural gas may be purchased or sold in the multi-month, monthly, and to a lesser extent, daily spot market to balance such seasonal supply and demand. The Utility purchases financial instruments, such as swaps and options, as part of its core winter hedging program in order to manage customer exposure to high natural gas prices during peak winter months. These financial instruments are considered derivatives.

Volume of Derivative Activity

At June 30, 2012, the volume of PG&E Corporation’s and the Utility’s outstanding derivatives was as follows:


		Contract Volume ⁽¹⁾
Underlying Product	Instruments	Less Than 1 Year		Greater Than 1 Year but Less Than 3 Years		Greater Than 3 Years but Less Than 5 Years		Greater Than 5 Years ⁽²⁾
Natural Gas ⁽³⁾ (MMBtus ⁽⁴⁾)	Forwards and Swaps		415,332,102		156,732,291		5,680,000		-
	Options		256,620,196		277,662,141		7,000,000		-
Electricity (Megawatt-hours)	Forwards and Swaps		5,010,023		4,314,021		2,009,505		3,081,447
	Options		-		174,559		239,233		183,964
	Congestion Revenue Rights		58,606,638		73,139,741		73,207,008		44,412,837


⁽¹⁾ Amounts shown reflect the total gross derivative volumes by commodity type that are expected to settle in each period. ⁽²⁾ Derivatives in this category expire between 2017 and 2022. ⁽³⁾Amounts shown are for the combined positions of the electric fuels and core gas portfolios. ⁽⁴⁾Million British Thermal Units.

Presentation of Derivative Instruments in the Financial Statements

In PG&E Corporation’s and the Utility’s Condensed Consolidated Balance Sheets, derivatives are presented on a net basis by counterparty where the right of offset exists under a master netting agreement. The net balances include outstanding cash collateral associated with derivative positions.

At June 30, 2012, PG&E Corporation’s and the Utility’s outstanding derivative balances were as follows:


	Commodity Risk
(in millions)	Gross Derivative Balance		Netting		Cash Collateral		Total Derivative Balance
Current assets – other		$ 52		$ (32)		$ 96		$ 116
Other noncurrent assets – other		101		(50)		-		51
Current liabilities – other		(399)		32		212		(155)
Noncurrent liabilities – other		(309)		50		37		(222)

Total commodity risk		$ (555)		$ -		$ 345		$ (210)

At December 31, 2011, PG&E Corporation’s and the Utility’s outstanding derivative balances were as follows:


	Commodity Risk
(in millions)	Gross Derivative Balance		Netting		Cash Collateral		Total Derivative Balance
Current assets – other		$ 54		$ (39)		$ 103		$ 118
Other noncurrent assets – other		113		(59)		-		54
Current liabilities – other		(489)		39		274		(176)
Noncurrent liabilities – other		(398)		59		101		(238)

Total commodity risk		$ (720)		$ -		$ 478		$ (242)

Gains and losses recorded on PG&E Corporation’s and the Utility’s derivatives were as follows:


	Commodity Risk
	Three months ended June 30,				Six months ended June 30,
(in millions)	2012		2011		2012		2011
Unrealized gain/(loss) - regulatory assets and liabilities ⁽¹⁾		$ 219		$ 21		$ 165		$ 158
Realized gain/(loss) - cost of electricity ⁽²⁾		(125)		(122)		(275)		(258)
Realized gain/(loss) - cost of natural gas ⁽²⁾		(5)		(6)		(27)		(61)


Total commodity risk instruments		$ 89		$ (107)		$ (137)		$ (161)



⁽¹⁾ Unrealized gains and losses on commodity risk-related derivative instruments are recorded to regulatory assets or liabilities, rather than being recorded to the Condensed Consolidated Statements of Income. These amounts exclude the impact of cash collateral postings. ⁽²⁾ These amounts are fully passed through to customers in rates. Accordingly, net income was not impacted by realized amounts on these instruments.

Cash inflows and outflows associated with derivatives are included in operating cash flows on PG&E Corporation’s and the Utility’s Condensed Consolidated Statements of Cash Flows.

The majority of the Utility’s derivatives contain collateral posting provisions tied to the Utility’s credit rating from each of the major credit rating agencies. At June 30, 2012, the Utility’s credit rating was investment grade. If the Utility’s credit rating were to fall below investment grade, the Utility would be required to post additional cash immediately to collateralize fully some of its net liability derivative positions.

At June 30, 2012, the additional cash collateral that the Utility would be required to post if the credit risk-related contingency features were triggered was as follows:


(in millions)
Derivatives in a liability position with credit risk-related contingencies that are not fully collateralized			$ (443)
Related derivatives in an asset position			75
Collateral posting in the normal course of business related to these derivatives			209

Net position of derivative contracts/additional collateral posting requirements ⁽¹⁾			$ (159)



⁽¹⁾ This calculation excludes the impact of closed but unpaid positions, as their settlement is not impacted by any of the Utility’s credit risk-related contingencies.