PACIFIC GAS & ELECTRIC Co - FORM 8-K - EX-99.2 - ADDITIONAL SUPPLEMENTAL INFORMATION

Attached files

file	filename
8-K - FORM 8-K DATED NOVEMBER 3, 2011 - PACIFIC GAS & ELECTRIC Co	form8k100311.htm
EX-99.1 - PG&E CORPORATION NEW RELEASE DATED NOVEMBER 3, 2011 - PACIFIC GAS & ELECTRIC Co	ex9901.htm
EX-99.3 - SLIDES RELATING TO WEBCAST CONFERENCE CALL - PACIFIC GAS & ELECTRIC Co	ex9903.htm

Exhibit 99.2



	PG&E Corporation Supplemental Earnings Materials for the Quarter Ended September 30, 2011 Table of Contents	PAGE

Table 1	PG&E Corporation Earnings from Operations and GAAP Income	2

Table 2	Pacific Gas and Electric Company Earnings from Operations and GAAP Income	3

Table 3	Key Drivers of Earnings per Share from Operations	4

Table 4	Share Statistics	5

Table 5	Performance Metrics	6-7

Table 6	Operating Statistics	8

Table 7	Cautionary Language Regarding Forward-Looking Statements on Tables 8 and 9	9-10

Table 8	EPS Guidance and Reconciliation to GAAP	11

Table 9	Earnings Sensitivities	12

Table 10	Cash Flow Sources and Uses	13

Table 11	Consolidated Cash Position	14

Table 12	Description of Selected Regulatory Cases	15-17

CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

PG&E Corporation

Table 13	Condensed Consolidated Statements of Income	18

Table 14	Condensed Consolidated Balance Sheets	19-20

Table 15	Condensed Consolidated Statements of Cash Flows	21-22

Pacific Gas and Electric Company

Table 16	Condensed Consolidated Statements of Income	23

Table 17	Condensed Consolidated Balance Sheets	24-25

Table 18	Condensed Consolidated Statements of Cash Flows	26-27

Table 1: Reconciliation of PG&E Corporation’s Earnings from Operations to Consolidated Income Available for Common Shareholders in Accordance with Generally Accepted Accounting Principles (“GAAP”)

Third Quarter and Year-to-Date, 2011 vs. 2010

(in millions, except per share amounts)

	Three months ended September 30,				Nine months ended September 30,
	Earnings		Earnings per Common Share (Diluted)		Earnings		Earnings per Common Share (Diluted)
	2011	2010	2011	2010	2011	2010	2011	2010

PG&E Corporation Earnings from Operations (1)	$ 436	$ 398	$ 1.08	$ 1.02	$ 1,072	$ 1,054	$ 2.68	$ 2.73
Items Impacting Comparability: (2)
Natural gas pipeline matters (3)	(162)	(141)	(0.40)	(0.36)	(237)	(141)	(0.59)	(0.37)
Environmental-related costs (4)	(74)	-	(0.18)	-	(74)	-	(0.19)	-
Statewide ballot initiative (5)	-	-	-	-	-	(45)	-	(0.12)
Federal healthcare law (6)	-	1	-	-	-	(19)	-	(0.05)
PG&E Corporation Earnings on a GAAP basis	$ 200	$ 258	$ 0.50	$ 0.66	$ 761	$ 849	$ 1.90	$ 2.19

(1)	“Earnings from operations” is not calculated in accordance with GAAP and excludes items impacting comparability as described in Note (2) below.

(2)	Items impacting comparability reconcile earnings from operations with Consolidated Income Available for Common Shareholders as reported in accordance with GAAP.

(3)	During the three and nine months ended September 30, 2011, PG&E Corporation’s subsidiary, Pacific Gas and Electric Company (“Utility”) incurred net costs of $162 million and $237 million, after-tax, respectively, in connection with natural gas pipeline matters. These amounts included pipeline-related costs to review records, validate operating pressures, conduct hydrostatic pressure tests, inspect pipelines, and perform other activities associated with the Utility’s natural gas pipeline system. These costs also included an increase in the provision for estimated third-party claims related to the San Bruno accident, reflecting new information regarding the nature of claims filed against the Utility, experience to date resolving cases, and developments in the litigation and regulatory proceedings. Costs incurred for the nine months ended September 30, 2011 were partially offset by a gain for insurance recoveries.

(after-tax)	Three months ended September 30, 2011	Nine months ended September 30, 2011

Pipeline-related costs	$ (105)	$ (181)
Third-party claims	(57)	(92)
Insurance recoveries	-	36

Natural gas pipeline matters	$ (162)	$ (237)

(4)	During the three and nine months ended September 30, 2011, the Utility recorded a charge of $74 million, after-tax, for environmental remediation and other estimated liabilities associated with the Utility's natural gas compressor site located near Hinkley, California.

(5)	During the nine months ended September 30, 2010, the Utility contributed $45 million to support Proposition 16 - The Taxpayers Right to Vote Act.

(6)	During the nine months ended September 30, 2010, the Utility recognized a charge of $19 million triggered by the elimination of the tax deductibility of Medicare Part D federal subsidies.

Table 2: Reconciliation of Pacific Gas and Electric Company’s Earnings from Operations to Consolidated Income Available for Common Stock in Accordance with GAAP

Third Quarter and Year-to-Date, 2011 vs. 2010

(in millions)

	Three months ended September 30,		Nine months ended September 30,
	2011	2010	2011	2010
Pacific Gas and Electric Company Earnings from Operations (1)	$ 429	$ 402	$ 1,057	$ 1,063
Items Impacting Comparability: (2)
Natural gas pipeline matters (3)	(162)	(141)	(237)	(141)
Environmental-related costs (4)	(74)	-	(74)	-
Statewide ballot initiative (5)	-	-	-	(45)
Federal healthcare law (6)	-	1	-	(19)
Pacific Gas and Electric Company Earnings on a GAAP basis	$ 193	$ 262	$ 746	$ 858

(1)	“Earnings from operations” is not calculated in accordance with GAAP and excludes items impacting comparability as described in Note (2) below.

(2)	Items impacting comparability reconcile earnings from operations with Consolidated Income Available for Common Stock as reported in accordance with GAAP.

(3)	During the three and nine months ended September 30, 2011, the Utility incurred net costs of $162 million and $237 million, after-tax, respectively, in connection with natural gas pipeline matters. These amounts included pipeline-related costs to review records, validate operating pressures, conduct hydrostatic pressure tests, inspect pipelines, and perform other activities associated with the Utility’s natural gas pipeline system. These costs also included an increase in the provision for estimated third-party claims related to the San Bruno accident, reflecting new information regarding the nature of claims filed against the Utility, experience to date resolving cases, and developments in the litigation and regulatory proceedings. Costs incurred were partially offset by insurance recoveries.

(after-tax)	Three months ended September 30, 2011	Nine months ended September 30, 2011

Pipeline-related costs	$ (105)	$ (181)
Third-party claims	(57)	(92)
Insurance recoveries	-	36

Natural gas pipeline matters	$ (162)	$ (237)

(4)	During the three and nine months ended September 30, 2011, the Utility recorded a charge of $74 million, after-tax, for environmental remediation and other estimated liabilities associated with the Utility's natural gas compressor site located near Hinkley, California.

(5)	During the nine months ended September 30, 2010, the Utility contributed $45 million to support Proposition 16 - The Taxpayers Right to Vote Act.

(6)	During the nine months ended September 30, 2010, the Utility recognized a charge of $19 million triggered by the elimination of the tax deductibility of Medicare Part D federal subsidies.

Table 3: Key Drivers of PG&E Corporation Earnings per Common Share (“EPS”) from Operations

Third Quarter and Year-to-Date, 2011 vs. 2010

($/Share, Diluted)


Third Quarter 2010 EPS from Operations (1)	$ 1.02

Increase in rate base earnings	0.10
Miscellaneous items	0.03

Litigation and regulatory matters	(0.04)
Increase in shares outstanding	(0.03)
Third Quarter 2011 EPS from Operations (1)	$ 1.08


2010 YTD EPS from Operations (1)	$ 2.73

Increase in rate base earnings	0.31
Miscellaneous items	0.01

Litigation and regulatory matters	(0.11)
Nuclear refueling outage	(0.06)
Storm and outage expenses	(0.06)
Gas transmission revenues	(0.05)
Increase in shares outstanding	(0.09)
2011 YTD EPS from Operations (1)	$ 2.68

(1)	See Table 1 for a reconciliation of EPS from Operations to EPS on a GAAP basis.

Table 4: PG&E Corporation Share Statistics

Third Quarter, 2011 vs. 2010

(shares in millions, except per share amounts)

	Third Quarter 2011	Third Quarter 2010	% Change

Common Stock Data

Book Value per share – end of period (1)	$ 29.54	$ 28.17	4.86%

Weighted average common shares outstanding, basic	403	390	3.33%
Employee share-based compensation	1	2
Weighted average common shares outstanding, diluted	404	392	3.06%

(1)	Common shareholders’ equity per common share outstanding at period end.

Table 5: Operational Performance Metrics

Third Quarter Year-to-Date Actual 2011 vs. Targets 2011

			2011
		Percentage Weight (1)	YTD Actual	Target

1.	Earnings from Operations (in millions)	50%	$ 1,072	See note (2)

2.	Operational Excellence Index	25%	1.089	1.000

3.	Customer Satisfaction & Brand Health Index	15%	72.7	75.3

4.	Employee Engagement Premier Survey	5%	See note (3)	69.59%

5.	Environmental Leadership Index	5%	0.67	1.00

(1)	Represents weighting used in calculating PG&E Corporation Short-Term Incentive Plan performance for management employees.

(2)	2011 target is not publicly reported but is consistent with the guidance range originally provided for 2011 EPS from operations of $3.65 to $3.80. The current publicly disclosed guidance range for 2011 EPS from operations is $3.45 to $3.60.

(3)	The Employee Engagement Premier Survey was administered in October 2011 with results available in December 2011.

DEFINITIONS OF 2011 OPERATIONAL PERFORMANCE METRICS FROM TABLE 5:

1.	Earnings from Operations:

	Earnings from operations measures PG&E Corporation’s earnings power from ongoing core operations. It allows investors to compare the underlying financial performance of the business from one period to another, exclusive of items that management believes do not reflect the normal course of operations (items impacting comparability). The measurement is not in accordance with GAAP. For a reconciliation of earnings from operations to earnings in accordance with GAAP, see Tables 1 and 2 above. The 2011 target for earnings from operations is not publicly reported but is consistent with the guidance range originally provided for 2011 EPS from operations of $3.65 to $3.80. The current publicly disclosed guidance range for PG&E Corporation’s 2011 EPS from operations is $3.45 to $3.60. For a reconciliation of 2011 EPS guidance on an earnings from operations basis to a GAAP basis, see Table 8.

2.	Operational Excellence Index:

	The Operational Excellence Index is a composite of categories outlined below. Overall, these metrics provide a balanced view on electric reliability, gas reliability, and safety. A higher index score indicates better performance in operational excellence. 1. System Average Interruption Frequency Index (“SAIFI”) – 20% weight 2. Customer Average Interruption Duration Index (“CAIDI”) – 20% weight 3. Gas Immediate Response – 10% weight 4. Gas Leak Survey Quality – 10% weight 5. Occupational Safety & Health Administration (“OSHA”) Recordable Rate – 30% weight 6. Motor Vehicle Incident (“MVI”) Rate – 10% weight SAIFI is a measure of the frequency that customers experience electrical outages. CAIDI is a measure of the average duration of electrical outages. Gas Immediate Response indicates how often calls that require immediate response are responded to within one hour. The Gas Leak Survey Quality metric is a composite that measures both the quality of gas leak survey assessments as well as the number of those assessments. The OSHA Recordable Rate measures the number of OSHA Recordable injuries, illnesses, or exposures. In general, an injury must result in medical treatment beyond first aid or result in work restrictions, death, or loss of consciousness to be OSHA Recordable. The rate measures how frequently OSHA Recordable cases occur for every 200,000 hours worked, or for approximately every 100 employees per year. The MVI Rate measures the number of chargeable motor vehicle incidents per 1 million miles driven. A chargeable incident is one where the Company driver could have prevented an incident, but failed to take reasonable steps to do so.

3.	Customer Satisfaction & Brand Health Index:

	The Customer Satisfaction & Brand Health Index is a combination of a Customer Satisfaction Score, which has a 75 percent weighting and a Brand Favorability Score, which has a 25 percent weighting in the composite. The Customer Satisfaction Score is a measure of overall satisfaction with the Utility’s operational performance in delivering services such as reliability, pricing of services, and customer service experience. The Brand Favorability Score is a measure of the overall favorability towards the Utility’s brand, and measures the emotional connection that customers have with the brand and is based on assessing perceptions regarding the Utility’s images, such as trust, heritage, and social responsibility. The Customer Satisfaction & Brand Health Index measures residential, small business, and medium business customer perceptions with weightings of 60 percent for residential customers and 40 percent for business customers. A higher index score indicates better performance in customer satisfaction and brand health.

4.	Employee Engagement Survey:

	The Employee Engagement Score is derived by averaging the percent favorable responses to 8 survey items. A higher score indicates better performance in employee engagement.

5.	Environmental Leadership Index:

	The Environmental Leadership Index is a combination of environmental compliance, which has a 50 percent weighting and operational footprint, which has a 50 percent weighting in the composite. The environmental compliance is determined by the number of Notice of Violation (“NOV”) notices. The operational footprint is measured by reducing energy and water use, and increasing the diversion of solid waste at company facilities. A higher index score indicates better performance in environmental leadership.

Table 6: Pacific Gas and Electric Company Operating Statistics

Third Quarter and Year-to-Date, 2011 vs. 2010

	Three Months Ended September 30,		Nine Months Ended September 30,
	2011	2010	2011	2010

Electric Sales (in millions kWh)
Residential	8,643	8,430	23,368	23,039
Commercial	9,016	8,883	24,619	24,439
Industrial	3,833	3,779	10,770	10,602
Agricultural	1,919	2,074	3,616	3,949
BART, public street and highway lighting	235	204	607	576
Other Electric Utilities	2	-	2	-
Sales from Energy Deliveries	23,648	23,370	62,982	62,605

Total Electric Customers at September 30			5,193,543	5,158,210

Bundled Gas Sales (in millions MCF)
Residential	24	25	151	146
Commercial	9	9	40	40
Total Bundled Gas Sales	33	34	191	186
Transportation Only	144	160	382	424
Total Gas Sales	177	194	573	610

Total Gas Customers at September 30			4,324,733	4,294,897


Sources of Electric Energy (in millions kWh)
Utility Generation
Nuclear	4,898	5,029	13,573	14,741
Hydro (net)	2,887	2,528	9,634	7,493
Fossil	1,403	934	3,046	2,603
Solar	2	-	4	-
Total Utility Generation	9,190	8,491	26,257	24,837
Purchased Power
Qualifying Facilities, including renewable resources	3,705	3,920	10,468	10,772
Irrigation Districts	1,254	970	3,957	2,580
Renewable Resources, excluding QFs	2,652	2,208	7,149	5,774
Other Purchased Power	1,984	1,700	6,573	4,248
Spot Market Purchases/Sales, net	2,851	3,944	3,435	9,194
Total Purchased Power	12,446	12,742	31,582	32,568

Delivery from DWR	753	1,202	1,904	3,251
Delivery to Direct Access Customers	2,310	1,642	6,258	4,279
Other (includes energy loss)	(1,051)	(707)	(3,019)	(2,330)
Total Electric Energy Delivered	23,648	23,370	62,982	62,605

Diablo Canyon Performance
Overall capacity factor (including refuelings)	99%	102%	93%	102%
Refueling outage period	None	None	5/1/11-6/5/11	None
Refueling outage duration during the period (days)	None	None	35.8	None

Table 7: Cautionary Language Regarding Forward-Looking Statements on Tables 8 and 9

Management's statements regarding guidance for earnings from operations per common share for PG&E Corporation and general earnings sensitivities constitute forward-looking statements that are based on current expectations and various assumptions and estimates that management believes are reasonable. These statements, assumptions, and estimates reflect management's judgment and opinions and are necessarily subject to various risks and uncertainties, the realization or resolution of which may be outside of management’s control. Actual results may differ materially. Factors that could cause actual results to differ materially include:

·	the outcome of pending and future regulatory proceedings and investigations related to the San Bruno accident, the California Public Utilities Commission's (“CPUC”) investigation of a natural gas explosion that occurred on December 24, 2008 in Rancho Cordova, California, and the safety of the Utility’s natural gas transmission pipelines in its northern and central California service territory; the ultimate amount of costs the Utility incurs for natural gas pipeline matters that are not recoverable through rates; the ultimate amount of third-party claims associated with the San Bruno accident that will not be recovered through insurance; and the amount of any civil or criminal fines, penalties, or punitive damages the Utility may incur related to these matters;

·	the outcome of future investigations or proceedings that may be commenced by the CPUC or other regulatory authorities relating to the Utility’s compliance with law, rules, regulations, or orders applicable to the operation, inspection, and maintenance of its electric and gas facilities (in addition to investigations or proceedings related to the San Bruno accident and natural gas pipeline matters);

·	reputational harm that PG&E Corporation and the Utility may suffer depending on whether the Utility is able to adequately and timely respond to the findings and recommendations made by the National Transportation Safety Board (“NTSB”) and the CPUC’s independent review panel; the outcome of the various regulatory proceedings and investigations of the San Bruno accident and natural gas pipeline matters; service disruptions caused by pressure reductions in the Utility’s natural gas pipeline system, the outcome of civil litigation; and the extent to which additional regulatory, civil, or criminal proceedings may be pursued by regulatory or governmental agencies;

·	the adequacy and price of electricity and natural gas supplies, the extent to which the Utility can manage and respond to the volatility of electricity and natural gas prices, and the ability of the Utility and its counterparties to post or return collateral;

·	explosions, fires, accidents, mechanical breakdowns, the disruption of information technology and systems (including the newly installed advanced electric and gas metering system), human errors, and similar events that may occur while operating and maintaining an electric and natural gas system in a large service territory with varying geographic conditions that can cause unplanned outages, reduce generating output, damage the Utility’s assets or operations, which could subject the Utility to third-party claims for property damage or personal injury, or result in the imposition of civil, criminal, or regulatory fines or penalties on the Utility;

·	the impact of storms, earthquakes, floods, drought, wildfires, disease, and similar natural disasters, or acts of terrorism or vandalism, that affect customer demand or that damage or disrupt the facilities, operations, or information technology and systems owned by the Utility, its customers, or third parties on which the Utility relies;

·	the potential impacts of climate change on the Utility’s electricity and natural gas businesses, the impact of environmental laws and regulations aimed at the reduction of carbon dioxide and other greenhouse gases on the Utility’s electricity and natural gas businesses, and whether the Utility is able to recover associated compliance costs including the cost of emission allowances and offsets that the Utility may incur under cap and trade regulations;

·	changes in customer demand for electricity and natural gas resulting from unanticipated population growth or decline, general economic and financial market conditions, the development of alternative energy technologies including self-generation and distributed generation technologies, or other reasons;

·	the occurrence of unplanned outages at the Utility’s two nuclear generating units at Diablo Canyon, the availability of nuclear fuel, and the ability of the Utility to procure replacement electricity if nuclear generation from Diablo Canyon were unavailable;


·	the outcome of seismic studies the Utility is conducting that could affect the Utility’s ability to continue operating Diablo Canyon or renew the operating licenses for Diablo Canyon, the issuance of Nuclear Regulatory Commission (“NRC”) orders or the adoption of new legislation or regulations to address seismic and other risks at nuclear facilities to avoid the type of damage sustained by nuclear facilities in Japan following the March 2011 earthquake, or to address the operations, decommissioning, storage of spent nuclear fuel, security, safety, cooling water intake, or other operating or licensing matters associated with Diablo Canyon and whether the Utility is able to comply with such new orders, legislation, or regulations and recover the increased costs of compliance through rates;

·	the impact of federal or state laws or regulations, or their interpretation, on energy policy and the regulation of utilities and their holding companies, including how the CPUC interprets and enforces the financial and other conditions imposed on PG&E Corporation when it became the Utility’s holding company;

·	whether the Utility’s newly installed electric and gas SmartMeter™ devices and related software systems and wireless communications equipment continue to accurately and timely measure customer energy usage and generate billing information, whether the Utility can successfully implement the system design changes necessary to accommodate changing retail electric rates, and whether the Utility can continue to rely on third-party vendors and contractors to support the advanced metering system;

·	the extent to which PG&E Corporation or the Utility incurs costs in connection with third-party claims or litigation, that are not recoverable through insurance, rates, or from other third parties;

·	the ability of PG&E Corporation, the Utility, and counterparties to access capital markets and other sources of credit in a timely manner on acceptable terms;

·	the impact of environmental remediation laws and regulations, particularly those affecting the remediation of the Utility’s former manufactured gas plants and natural gas compressor sites, the extent to which the Utility is able to recover compliance and remediation costs from third parties or through rates or insurance, and the ultimate amount of environmental remediation costs the Utility incurs related to the Hinkley compressor station;

·	the loss of customers due to various forms of bypass and competition, including municipalization of the Utility’s electric distribution facilities, increasing levels of “direct access” by which consumers procure electricity from alternative energy providers, and implementation of “community choice aggregation,” which permits cities and counties to purchase and sell electricity for their local residents and businesses;

·	the outcome of federal or state tax audits and the impact of changes in federal or state tax laws, policies, or regulations, such as The Tax Relief, Unemployment Insurance Reauthorization, and Job Creation Act of 2010; and

·	other factors and risks discussed in PG&E Corporation and the Utility’s 2010 Annual Report on Form 10-K and other reports filed with the Securities and Exchange Commission.

Table 8: PG&E Corporation EPS Guidance

2011 EPS Guidance	Low	High
Estimated EPS on an Earnings from Operations Basis	$ 3.45	$ 3.60

Estimated Items Impacting Comparability (1)
Natural gas pipeline matters (2)	(1.28)	(0.65)
Environmental-related costs (3)	(0.18)	(0.18)
Estimated EPS on a GAAP Basis	$ 1.99	$ 2.77

2012 EPS Guidance	Low	High
Estimated EPS on an Earnings from Operations Basis	$ 3.10	$ 3.30

Estimated Items Impacting Comparability (1)
Natural gas pipeline matters (2)	(0.60)	(0.14)
Environmental-related costs (3)	(0.14)	-
Estimated EPS on a GAAP Basis	$ 2.36	$ 3.16

(1)	Items impacting comparability reconcile earnings from operations with Consolidated Income Available for Common Shareholders in accordance with GAAP.

(2)	The estimate includes pipeline-related costs associated with the increased scope of work that the Utility expects to undertake on its natural gas pipeline system, as well as third-party claims in addition to the provision of $220 million recorded in 2010. Total estimated costs are partially offset by insurance recoveries for third-party claims, which include amounts recognized during the nine months ended September 30, 2011.

	2011		2012
(in millions, pre-tax)	Low EPS guidance range	High EPS guidance range	Low EPS guidance range	High EPS guidance range

Pipeline-related costs (a)	$ (550)	$ (350)	$ (200)	$ (100)
Third-party claims (b)	(380)	(155)	(225)	-
Insurance recoveries (c)	60	60	-	-

Natural gas pipeline matters (d)	$ (870)	$ (445)	$ (425)	$ (100)

(a)	The pipeline-related cost range provided for 2012 reflects a range of $100 million to $200 million in costs associated with regulatory and legal proceedings and other gas pipeline-related activities outside the scope of the Utility’s proposed Pipeline Safety Enhancement Program (“PSEP”).

(b)	The range for third-party claims in 2011 is in addition to the provision of $220 million recorded in 2010. The range in 2012 is in addition to the cumulative provision of $375 million, recorded as of September 30, 2011.

(c)	Although the Utility considers it likely that a significant portion of the costs it incurs for third-party claims will be covered through its insurance, insurance recoveries are recognized only when deemed probable under applicable accounting standards.

(d)	The guidance range for 2012 does not include any estimates of future insurance recoveries, potential future fines or penalties, or punitive damages.

(3)	The estimate depends primarily on the outcome of a final groundwater remediation plan and other related activities associated with the Hinkley natural gas compressor site.

Please see the accompanying discussion of factors that could cause actual results to differ materially.

Table 9: General Earnings Sensitivities

PG&E Corporation and Pacific Gas and Electric Company

Variable	Description of Change	Estimated 2011 Earnings Impact	Estimated 2012 Earnings Impact

Rate base	+/- $100 million change in allowed rate base	+/- $6 million	+/- $6 million

Return on equity (ROE)	+/- 0.1% change in allowed ROE	+/- $12 million	+/- $12 million

Share count	+/- 1% change in average shares	+/- $.03 per share	+/- $.03 per share

Revenues	+/- $7 million change in at-risk revenue (pre-tax), including Electric Transmission and California Gas Transmission	+/- $.01 per share	+/- $.01 per share

These general earnings sensitivities that may affect 2011 and 2012 earnings are forward-looking statements that are based on various assumptions. Actual results may differ materially. For a discussion of the factors that may affect future results, see Table 7.

Table 10: Cash Flow Sources and Uses

Year-to-Date 2011

PG&E Corporation Consolidated

(in millions)

Cash and Cash Equivalents, January 1, 2011	$ 291

Sources of Cash
Cash from operations	$ 3,232
Decrease in restricted cash	170
Borrowings under revolving credit facilities, net	75
Net proceeds from issuance of commercial paper	196
Net proceeds from issuance of long term debt	544
Common stock issued	391
	$ 4,608

Uses of Cash
Capital expenditures	$ 2,968
Net purchases of nuclear decommissioning trust investments	30
Long-term debt matured	700
Energy recovery bonds matured	299
Common stock dividends paid	525
Other	100
	$ 4,622

Cash and Cash Equivalents, September 30, 2011	$ 277

Source: PG&E Corporation’s Condensed Consolidated Statement of Cash Flows included in PG&E Corporation’s and Pacific Gas and Electric Company’s combined Quarterly Report on Form 10-Q for the quarter ended September 30, 2011.

Table 11: PG&E Corporation’s and Pacific Gas and Electric Company’s Consolidated Cash Position

Third Quarter, 2011 vs. 2010

(in millions)

	2011	2010	Change

Cash Flows from Operating Activities (YTD September 30)
PG&E Corporation	$ (29)	$ (31)	$ 2
Pacific Gas and Electric Company	3,261	2,351	910
	$ 3,232	$ 2,320	$ 912

Consolidated Cash Balance (at September 30)
PG&E Corporation	$ 224	$ 228	$ (4)
Pacific Gas and Electric Company	53	119	(66)
	$ 277	$ 347	$ (70)

Consolidated Restricted Cash Balance (at September 30)
PG&E Corporation	$ -	$ -	$ -
Pacific Gas and Electric Company (1)	405	585	(180)
	$ 405	$ 585	$ (180)

(1) Includes $12 million of restricted cash classified as Other Noncurrent Assets – Other in the Condensed Consolidated Balance Sheets at September 30, 2011 and 2010.

Table 12: Pacific Gas and Electric Company

Description of Selected Regulatory Cases

Name	Brief Description	Docket Number

2009 Energy Efficiency Incentive Claim	On June 27, 2011, the Utility filed its 2009 Energy Efficiency Incentive Claim Application. The Utility requested $32.4 million as an incentive for providing cost-effective energy savings during the 2009 program year. The Utility’s Application complies with those CPUC directives and requirements set forth for the calculation of energy savings and the incentive claim. On October 6, 2011, the CPUC extended the statutory deadline to resolve the Rulemaking to December 12, 2011.		A.11-06-028
2012-14 Demand Response Programs and Budgets	On March 1, 2011, the Utility filed its 2012-14 Demand Response (“DR”) Programs and Budget Application. The Utility’s 2012-14 proposed DR efforts will expand the role and use of DR to support evolving California Independent System Operator markets, smart grid technologies and the introduction of electric vehicles. The Utility’s application forecasts approximately 1,000 MW of event-based demand response in 2012-2014. The Utility requests a total electric revenue requirement of $228 million for the 2012-14 program cycle. The application would increase 2012 average system electric rates approximately 0.6 percent over 2011 rates. A CPUC decision is anticipated by end of Q4 2011.		A.11-03-001
Gas Pipeline Safety Order Instituting Rulemaking	This is a forward-looking CPUC proceeding to establish a new model of natural gas pipeline safety regulation applicable to all California pipelines. On August 26, 2011, the Utility filed its PSEP. The PSEP focuses on the following key areas: Pipeline Modernization, Valve Automation, Pipeline Records Integration, and Interim Safety Enhancement Measures. Phase 1 (2011-2014) targets pipeline segments that are in highly populated urban areas, have vintage seam welds that do not meet modern standards or that are “grandfathered” under current regulations and have not been strength tested. Phase 2 (beginning in 2015) targets pipeline segments that have been previously strength tested or are in rural areas. The Utility forecasts $1.4 billion in capital expenditures and $751 million in expenses, for a total of approximately $2.2 billion, for Phase 1, of which the Utility requests authorization to recover approximately $2.0 billion in rates. The adopted procedural schedule, which assigned hearings in November 2011, is currently suspended.	R.11-02-019 D.11-03-047 D.11-06-017
Gas Transmission System Records Order Instituting Investigation	In February 2011, the CPUC launched a formal investigation to determine whether the Utility violated any rules or requirements pertaining to safety recordkeeping for its gas service and facilities. This proceeding will review the Utility’s safety recordkeeping for the San Bruno, California, gas transmission pipeline that ruptured on September 9, 2010. It will also review and determine whether the Utility’s recordkeeping practices for its entire gas transmission system have been unsafe and in violation of the law. A prehearing conference was held on September 6, 2011 to establish a schedule for the CPUC’s Legal Division to issue its report on the Utility’s recordkeeping practices. Pending the completion of CPUC visits to Utility facilities and future discovery, the CPUC Legal Division could issue a report as early as February 2012.	I.11-02-016
Rancho Cordova Order Instituting Investigation	This is a formal CPUC investigation to determine whether the Utility violated any rules or requirements in regards to its gas service and facilities, pertaining to a gas explosion and fire that occurred on December 24, 2008 in Rancho Cordova, California. On June 20, 2011, the Utility and the CPUC’s Consumer Protection and Safety Division (“CPSD”) requested that the CPUC approve a stipulated resolution of the investigation. Under the stipulation, the Utility would pay a penalty of $26 million. A hearing on the stipulation was held on July 29, 2011. On September 29, 2011, the assigned ALJ issued a Presiding Officer’s Decision (“POD”) which would require a $38 million penalty. On October 19, 2011, the Utility, CPSD and TURN filed a joint motion accepting the POD.	I.10-11-013

Table 12 (continued): Pacific Gas and Electric Company

Description of Selected Regulatory Cases

Name	Brief Description	Docket Number

Transmission Owner (“TO”) 13 Rate Case	On August 10, 2011, FERC approved the uncontested settlement of the Utility’s electric Transmission Owner rate case. The settlement increased the annual retail revenue requirement from $875 million to $934 million with rates effective March 1, 2011.	ER10-2026-000
2010 Long Term Procurement Plan (“LTPP”)	This is a CPUC proceeding to ensure a reliable and cost-effective electricity supply in California. This proceeding supports meeting system capacity needs and adopting products, processes, and procurement strategies to serve bundled customers. On March 25, 2011, the Utility submitted its proposed Bundled Procurement Plan, establishing the upfront achievable standards and criteria for procuring products and executing procurement strategies for bundled customers. On July 1, 2011, the Utility filed its proposals on bid evaluation criteria to effectively compare competing offers for utility-owned generation and Power Purchase Agreement bids, Greenhouse Gas products and risk management strategies, and procurement oversight rules. Also on July 1, 2011, the Utility, jointly with SCE and SDG&E (Joint IOUs), filed the System Resource Plan. The Joint IOUs state that renewable resource integration needs cannot be determined at this time given the complexity of the modeling approach and the uncertainty of the impact on the California system of increased renewable generation. On August 3, 2011, 23 parties, including the Joint IOUs, submitted a Track I Settlement Agreement for the CPUC’s approval recommending the CPUC further examine the system resource need and the integration of intermittent renewable resources into the CAISO grid, and issue its final assessment no later than December 31, 2012. A final Decision is expected by end of Q4 2011.	R.10-05-006
Nuclear Relicensing	On January 29, 2010, the Utility filed an application with the CPUC to recover the costs associated with renewal of the Diablo Canyon Power Plant operating licenses for Units 1 and 2 for an additional 20 years, to 2044 and 2045 respectively. The Utility estimates that these costs will total $85 million. The application requests authority to recover in rates, starting January 1, 2015, an initial revenue requirement of $21.6 million for costs associated with obtaining the federal and state approvals required to seek license renewal. On April 11, 2011, the Utility requested that the NRC delay final action on the Utility’s renewal application until after the Utility completes additional seismic studies and submits a report to the NRC addressing the results of those studies. PG&E is currently awaiting an ALJ Ruling on the issue.	A.10-01-022
Request for New Generation Offers and Potential New Utility-Owned Generation	On December 16, 2010, the CPUC approved the Utility’s purchase and sale agreement (“PSA”) with Contra Costa Generating Station LLC for the development and construction of the Oakley Generating Station, a proposed 586-MW natural gas-fired generation facility to be located in Oakley, California. On January 16, 2011, several consumer interest and environmental groups that opposed the CPUC’s approval of the Oakley PSA filed applications for rehearing of the CPUC’s decision, which the CPUC rejected on May 26, 2011. The two intervening parties have challenged the CPUC’s and California Energy Commission’s decisions approving the project by filing for judicial review before the California Supreme Court.	A.09-09-021 D.10-07-045 D.10-12- 050 D.11-05-049

Table 12 (continued): Pacific Gas and Electric Company

Description of Selected Regulatory Cases

Name	Brief Description			Docket Number

Smart Grid Order Instituting Rulemaking		This is a CPUC proceeding to consider the development of smart grid technologies in California and to establish procedures for the Utility, SCE and SDG&E to obtain CPUC approval for smart grid-related investments through general rate cases or individual applications. This rulemaking proceeding will also consider customer privacy, third party access, and deployment plan metrics in 2011. The Utility filed its Smart Grid Deployment Plan on June 30, 2011. The plan presents a vision, strategy, and roadmap for how the smart grid will enable consumers to capture the benefits of a wide range of energy technologies, products, and services while protecting consumers’ privacy.	R.08-12-009 D.09-12-046 D.10-06-047 A.11-06-026

Most of these regulatory cases are discussed in PG&E Corporation and Pacific Gas and Electric Company’s combined Quarterly Report on Form 10-Q for the quarter ended September 30, 2011, or PG&E Corporation and Pacific Gas and Electric Company’s combined Annual Report on Form 10-K for the year ended December 31, 2010.

Table 13: PG&E Corporation

Condensed Consolidated Statements of Income

(in millions, except per share amounts)

	(Unaudited)
	Three Months Ended		Nine Months Ended
	September 30,		September 30,
(in millions, except per share amounts)	2011	2010	2011	2010
Operating Revenues
Electric	$ 3,188	$ 2,857	$ 8,694	$ 7,882
Natural gas	672	656	2,447	2,338
Total operating revenues	3,860	3,513	11,141	10,220
Operating Expenses
Cost of electricity	1,224	1,102	3,018	2,885
Cost of natural gas	170	182	936	924
Operating and maintenance	1,492	1,225	3,955	3,175
Depreciation, amortization, and decommissioning	566	501	1,648	1,420
Total operating expenses	3,452	3,010	9,557	8,404
Operating Income	408	503	1,584	1,816
Interest income	2	3	7	7
Interest expense	(176)	(167)	(527)	(510)
Other income, net	18	29	56	25
Income Before Income Taxes	252	368	1,120	1,338
Income tax provision	49	107	349	479
Net Income	203	261	771	859
Preferred stock dividend requirement of subsidiary	3	3	10	10
Income Available for Common Shareholders	$ 200	$ 258	$ 761	$ 849
Weighted Average Common Shares Outstanding, Basic	403	390	399	378
Weighted Average Common Shares Outstanding, Diluted	404	392	400	391
Net Earnings Per Common Share, Basic	$ 0.50	$ 0.66	$ 1.91	$ 2.22
Net Earnings Per Common Share, Diluted	$ 0.50	$ 0.66	$ 1.90	$ 2.19
Dividends Declared Per Common Share	$ 0.46	$ 0.46	$ 1.37	$ 1.37

Source: PG&E Corporation’s and Pacific Gas and Electric Company’s Condensed Consolidated Financial Statements and Notes thereto included in PG&E Corporation’s and Pacific Gas and Electric Company’s combined Quarterly Report on Form 10-Q for the quarter ended September 30, 2011.

Table 14: PG&E Corporation

Condensed Consolidated Balance Sheets

(in millions)

	(Unaudited)
	Balance At
	September 30,	December 31,
(in millions)	2011	2010
ASSETS
Current Assets
Cash and cash equivalents	$ 277	$ 291
Restricted cash ($39 and $38 related to energy recovery bonds at September 30, 2011 and December 31, 2010, respectively)	393	563
Accounts receivable
Customers (net of allowance for doubtful accounts of $85 and $81 at September 30, 2011 and December 31, 2010, respectively)	1,011	944
Accrued unbilled revenue	737	649
Regulatory balancing accounts	1,063	1,105
Other	820	794
Regulatory assets	680	599
Inventories
Gas stored underground and fuel oil	198	152
Materials and supplies	219	205
Income taxes receivable	148	47
Other	331	193
Total current assets	5,877	5,542
Property, Plant, and Equipment
Electric	35,120	33,508
Gas	11,700	11,382
Construction work in progress	1,623	1,384
Other	15	15
Total property, plant, and equipment	48,458	46,289
Accumulated depreciation	(15,626)	(14,840)
Net property, plant, and equipment	32,832	31,449
Other Noncurrent Assets
Regulatory assets ($435 and $735 related to energy recovery bonds at September 30, 2011 and December 31, 2010, respectively)	5,714	5,846
Nuclear decommissioning trusts	1,964	2,009
Income taxes receivable	457	565
Other	673	614
Total other noncurrent assets	8,808	9,034
TOTAL ASSETS	$ 47,517	$ 46,025

Table 14 (continued): PG&E Corporation

Condensed Consolidated Balance Sheets

(in millions, except share amounts)

	(Unaudited)
	Balance At
	September 30,	December 31,
(in millions, except share amounts)	2011	2010
LIABILITIES AND EQUITY
Current Liabilities
Short-term borrowings	$ 1,137	$ 853
Long-term debt, classified as current	50	809
Energy recovery bonds, classified as current	418	404
Accounts payable
Trade creditors	1,154	1,129
Disputed claims and customer refunds	673	745
Regulatory balancing accounts	421	256
Other	380	379
Interest payable	789	862
Income taxes payable	107	77
Deferred income taxes	-	113
Other	1,689	1,558
Total current liabilities	6,818	7,185
Noncurrent Liabilities
Long-term debt	11,516	10,906
Energy recovery bonds	110	423
Regulatory liabilities	4,596	4,525
Pension and other postretirement benefits	2,343	2,234
Asset retirement obligations	1,591	1,586
Deferred income taxes	6,212	5,547
Other	2,120	2,085
Total noncurrent liabilities	28,488	27,306
Commitments and Contingencies (Note 10)
Equity
Shareholders’ Equity
Preferred stock	-	-
Common stock, no par value, authorized 800,000,000 shares, 405,169,162 shares outstanding at September 30, 2011 and 395,227,205 shares outstanding at December 31, 2010	7,318	6,878
Reinvested earnings	4,817	4,606
Accumulated other comprehensive loss	(176)	(202)
Total shareholders’ equity	11,959	11,282
Noncontrolling Interest – Preferred Stock of Subsidiary	252	252
Total equity	12,211	11,534
TOTAL LIABILITIES AND EQUITY	$ 47,517	$ 46,025

Table 15: PG&E Corporation

Condensed Consolidated Statements of Cash Flows

(in millions)

	(Unaudited)
	Nine Months Ended
	September 30,
(in millions)	2011	2010
Cash Flows from Operating Activities
Net income	$ 771	$ 859
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation, amortization, and decommissioning	1,648	1,420
Allowance for equity funds used during construction	(64)	(89)
Deferred income taxes and tax credits, net	552	328
Other	223	203
Effect of changes in operating assets and liabilities:
Accounts receivable	(186)	(246)
Inventories	(60)	(65)
Accounts payable	93	17
Income taxes receivable/payable	(71)	252
Other current assets and liabilities	(170)	(34)
Regulatory assets, liabilities, and balancing accounts, net	70	(32)
Other noncurrent assets and liabilities	426	(293)
Net cash provided by operating activities	3,232	2,320
Cash Flows from Investing Activities
Capital expenditures	(2,968)	(2,794)
Decrease in restricted cash	170	61
Proceeds from sales and maturities of nuclear decommissioning trust investments	1,574	962
Purchases of nuclear decommissioning trust investments	(1,604)	(1,001)
Other	(102)	(25)
Net cash used in investing activities	(2,930)	(2,797)
Cash Flows from Financing Activities
Borrowings under revolving credit facilities	358	490
Repayments under revolving credit facilities	(283)	-
Net issuances of commercial paper, net of discount of $2 in 2011 and 2010	196	251
Proceeds from issuance of long-term debt, net of discount and issuance costs of $6 in 2011 and $12 in 2010	544	838
Short-term debt matured	-	(500)
Long-term debt matured	(700)	(95)
Energy recovery bonds matured	(299)	(285)
Common stock issued	391	141
Common stock dividends paid	(525)	(492)
Other	2	(51)
Net cash provided by (used in) financing activities	(316)	297
Net change in cash and cash equivalents	(14)	(180)
Cash and cash equivalents at January 1	291	527
Cash and cash equivalents at September 30	$ 277	$ 347

Table 15 (continued): PG&E Corporation

Condensed Consolidated Statements of Cash Flows

(in millions)

Supplemental disclosures of cash flow information
Cash received (paid) for:
Interest, net of amounts capitalized	$ (536)	$ (526)
Income taxes, net	8	(52)
Supplemental disclosures of noncash investing and financing activities
Common stock dividends declared but not yet paid	$ 184	$ 180
Capital expenditures financed through accounts payable	225	229
Noncash common stock issuances	18	259

Table 16: Pacific Gas and Electric Company

Condensed Consolidated Statements of Income

(in millions)

	(Unaudited)
	Three Months Ended		Nine Months Ended
	September 30,		September 30,
(in millions)	2011	2010	2011	2010
Operating Revenues
Electric	$ 3,187	$ 2,857	$ 8,691	$ 7,882
Natural gas	672	656	2,447	2,338
Total operating revenues	3,859	3,513	11,138	10,220
Operating Expenses
Cost of electricity	1,224	1,102	3,018	2,885
Cost of natural gas	170	182	936	924
Operating and maintenance	1,497	1,224	3,951	3,172
Depreciation, amortization, and decommissioning	566	500	1,648	1,419
Total operating expenses	3,457	3,008	9,553	8,400
Operating Income	402	505	1,585	1,820
Interest income	2	3	6	7
Interest expense	(171)	(161)	(511)	(481)
Other income, net	19	25	52	20
Income Before Income Taxes	252	372	1,132	1,366
Income tax provision	56	107	376	498
Net Income	196	265	756	868
Preferred stock dividend requirement	3	3	10	10
Income Available for Common Stock	$ 193	$ 262	$ 746	$ 858

Table 17: Pacific Gas and Electric Company

Condensed Consolidated Balance Sheets

(in millions)

	(Unaudited)
	Balance At
	September 30,	December 31,
(in millions)	2011	2010
ASSETS
Current Assets
Cash and cash equivalents	$ 53	$ 51
Restricted cash ($39 and $38 related to energy recovery bonds at September 30, 2011 and December 31, 2010, respectively)	393	563
Accounts receivable
Customers (net of allowance for doubtful accounts of $85 and $81 at September 30, 2011 and December 31, 2010, respectively)	1,011	944
Accrued unbilled revenue	737	649
Regulatory balancing accounts	1,063	1,105
Other	821	856
Regulatory assets	680	599
Inventories
Gas stored underground and fuel oil	198	152
Materials and supplies	219	205
Income taxes receivable	203	48
Other	316	190
Total current assets	5,694	5,362
Property, Plant, and Equipment
Electric	35,120	33,508
Gas	11,700	11,382
Construction work in progress	1,623	1,384
Total property, plant, and equipment	48,443	46,274
Accumulated depreciation	(15,612)	(14,826)
Net property, plant, and equipment	32,831	31,448
Other Noncurrent Assets
Regulatory assets ($435 and $735 related to energy recovery bonds at September 30, 2011 and December 31, 2010, respectively)	5,714	5,846
Nuclear decommissioning trusts	1,964	2,009
Income taxes receivable	456	614
Other	338	400
Total other noncurrent assets	8,472	8,869
TOTAL ASSETS	$ 46,997	$ 45,679

Table 17 (continued): Pacific Gas and Electric Company

Condensed Consolidated Balance Sheets

(in millions, except share amounts)

	(Unaudited)
	Balance At
	September 30,	December 31,
(in millions, except share amounts)	2011	2010
LIABILITIES AND SHAREHOLDERS’ EQUITY
Current Liabilities
Short-term borrowings	$ 1,062	$ 853
Long-term debt, classified as current	50	809
Energy recovery bonds, classified as current	418	404
Accounts payable
Trade creditors	1,154	1,129
Disputed claims and customer refunds	673	745
Regulatory balancing accounts	421	256
Other	395	390
Interest payable	779	857
Income taxes payable	115	116
Deferred income taxes	-	118
Other	1,483	1,349
Total current liabilities	6,550	7,026
Noncurrent Liabilities
Long-term debt	11,167	10,557
Energy recovery bonds	110	423
Regulatory liabilities	4,596	4,525
Pension and other postretirement benefits	2,280	2,174
Asset retirement obligations	1,591	1,586
Deferred income taxes	6,341	5,659
Other	2,055	2,008
Total noncurrent liabilities	28,140	26,932
Commitments and Contingencies (Note 10)
Shareholders’ Equity
Preferred stock	258	258
Common stock, $5 par value, authorized 800,000,000 shares, 264,374,809 shares outstanding at September 30, 2011 and December 31, 2010	1,322	1,322
Additional paid-in capital	3,592	3,241
Reinvested earnings	7,304	7,095
Accumulated other comprehensive loss	(169)	(195)
Total shareholders’ equity	12,307	11,721
TOTAL LIABILITIES AND SHAREHOLDERS’ EQUITY	$ 46,997	$ 45,679

Table 18: Pacific Gas and Electric Company

Condensed Consolidated Statements of Cash Flows

(in millions)

	(Unaudited)
	Nine Months Ended
	September 30,
(in millions)	2011	2010
Cash Flows from Operating Activities
Net income	$756	$ 868
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation, amortization, and decommissioning	1,648	1,419
Allowance for equity funds used during construction	(64)	(89)
Deferred income taxes and tax credits, net	564	332
Other	193	175
Effect of changes in operating assets and liabilities:
Accounts receivable	(125)	(240)
Inventories	(60)	(65)
Accounts payable	97	15
Income taxes receivable/payable	(156)	241
Other current assets and liabilities	(153)	(33)
Regulatory assets, liabilities, and balancing accounts, net	70	(32)
Other noncurrent assets and liabilities	491	(240)
Net cash provided by operating activities	3,261	2,351
Cash Flows from Investing Activities
Capital expenditures	(2,968)	(2,794)
Decrease in restricted cash	170	61
Proceeds from sales and maturities of nuclear decommissioning trust investments	1,574	962
Purchases of nuclear decommissioning trust investments	(1,604)	(1,001)
Other	13	15
Net cash used in investing activities	(2,815)	(2,757)
Cash Flows from Financing Activities
Borrowings under revolving credit facility	208	400
Repayments under revolving credit facility	(208)	-
Net issuances of commercial paper, net of discount of $2 in 2011 and 2010	196	251
Proceeds from issuance of long-term debt, net of discount and issuance costs of $6 in 2011 and $12 in 2010	544	838
Short-term debt matured	-	(500)
Long-term debt matured	(700)	(95)
Energy recovery bonds matured	(299)	(285)
Preferred stock dividends paid	(10)	(11)
Common stock dividends paid	(537)	(537)
Equity contribution	350	170
Other	12	(40)
Net cash provided by (used in) financing activities	(444)	191
Net change in cash and cash equivalents	2	(215)
Cash and cash equivalents at January 1	51	334
Cash and cash equivalents at September 30	$ 53	$ 119

Table 18 (continued): Pacific Gas and Electric Company

Condensed Consolidated Statements of Cash Flows

(in millions)

Supplemental disclosures of cash flow information
Cash received (paid) for:
Interest, net of amounts capitalized	$ (525)	$ (504)
Income taxes, net	6	(87)
Supplemental disclosures of noncash investing and financing activities
Capital expenditures financed through accounts payable	$ 225	$ 229

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