ex9902.htm

SECOND QUARTER EARNINGS CALL July 31, 2014 Exhibit 99.2

* Safe Harbor Statements Management’s statements and assumptions regarding estimated costs, capital expenditures, rate base, equity issuances, general earnings sensitivities, and other factors that can affect PG&E Corporation’s financial results, constitute forward-looking statements that are necessarily subject to various risks and uncertainties. These statements reflect management’s judgment and opinions which are based on current expectations and various forecasts, estimates, and projections, the realization or resolution of which may be outside of management’s control. PG&E Corporation and Pacific Gas and Electric Company (“Utility”) are not able to predict all the factors that may affect future results. Some of the factors that could cause actual results to differ materially include: the timing and outcome of the pending CPUC investigations and enforcement matters related to the Utility’s natural gas system operating practices and the San Bruno accident, including the ultimate amount of fines the Utility will be required to pay to the State General Fund, the ultimate amount of costs the Utility will incur in its natural gas transmission business that it will not recover through rates, including the cost of any remedial actions the Utility may be ordered to perform; the timing and outcome of the federal criminal prosecution of the Utility, including the amount of any criminal fines or penalties imposed; whether the CPUC or a federal judge in the criminal case appoints a monitor to oversee the Utility’s natural gas operations; whether additional investigations are commenced relating to the Utility’s natural gas operating practices or specific incidents; whether PG&E Corporation and the Utility are able to repair the harm to their reputations caused by negative publicity about the San Bruno accident, the CPUC investigations, the criminal prosecution, the Utility’s self-reports of noncompliance with certain natural gas safety regulations, and the ongoing work to remove encroachments from transmission pipeline rights-of-way; the outcomes of pending ratemaking proceedings and whether the cost and revenue forecasts assumed in such outcomes prove to be accurate; higher electricity procurement costs and whether the Utility is able to recover such higher costs timely; the amount and timing of additional common stock issuances by PG&E Corporation; the ability of PG&E Corporation and the Utility to access capital markets and other sources of debt and equity financing in a timely manner on acceptable terms; changes in credit ratings which could result in increased borrowing costs especially if PG&E Corporation or the Utility were to lose its investment grade credit ratings; whether the ultimate outcome of the pending investigations and proceedings relating to the Utility’s natural gas operations affects the Utility’s ability to make distributions to PG&E Corporation, and, in turn, PG&E Corporation’s ability to pay dividends; the outcome of federal or state tax audits and the impact of any changes in federal or state tax laws, policies, regulations, or their interpretation; the impact of changes in GAAP, standards, rules, or policies, including those related to regulatory accounting, and the impact of changes in their interpretation or application; and the other factors disclosed in PG&E Corporation’s and the Utility’s joint 2013 Annual Report and Quarterly Report on Form 10-Q for the quarters ended March 31 and June 30, 2014. This presentation is not complete without the accompanying statements made by management during the webcast conference call held on July 31, 2014. This presentation, including Appendices, and the accompanying press release were attached to PG&E Corporation’s Current Report on Form 8-K that was furnished to the Securities and Exchange Commission on July 31, 2014 and, along with the replay of the conference call, is also available on PG&E Corporation’s website at www.pge-corp.com.

* Key Focus Areas Execute critical gas work Complete regulatory and legal proceedings as soon as possible Rigorous multi-year planning Drive continuous improvement Strengthen local presence Engage in public policy development Resolve gas issues Position company for success Partner effectively

* General Rate Case – Proposed Decision issued June 18; CPUC vote as early as August 14 Gas Transmission rate case – Retroactivity of revenues approved TO 15 – filed settlement at FERC July 15 TO 16 – filed with FERC July 30 Regulatory Update Operational and Regulatory Update Executing on Operations Gas Safety Work since 2011 Tested, or validated through records, 724 miles of pipe Replaced or installed 153 miles of pipeline Installed 157 automatic or remote shutoff valves Received PAS-55 and ISO-55001 safety certifications in May 2014

* Q2 2014: Earnings Results Earnings from Operations is not calculated in accordance with GAAP and excludes items impacting comparability. See Exhibit A in Appendix 2 for a reconciliation of Earnings per Share (“EPS”) from Operations to EPS on a GAAP basis.

* Q2 2014: Quarter over Quarter Comparison EPS from Operations Earnings per Share from Operations is not calculated in accordance with GAAP and excludes items impacting comparability. See Exhibit A in Appendix 2 for a reconciliation of EPS from Operations to EPS on a GAAP basis.

* Assumptions for 2014 Return on Equity: 10.4% Equity Ratio: 52% Authorized Cost of Capital* Authorized Rate Base (weighted average) ($ billions) Other Factors Affecting Earnings from Operations - Under-earning on Gas Transmission & Storage Gas expense Gas capital Gas storage revenues + Gas transmission revenues + Energy Efficiency incentive revenues + Monetizing shares in SolarCity CWIP earnings: offset by below-the-line costs Capital Expenditures ($ millions) *Electric Transmission rate base reflects full TO15 request *Includes $400 M previously reserved for limits on PSEP authorized spend *CPUC authorized See the Safe Harbor Statements for factors that could cause actual results to differ materially from the guidance presented and underlying assumptions.

* 2014 Natural Gas Matters Guidance range excludes potential future insurance recoveries and any fines or penalties resulting from the pending gas investigations. See the Safe Harbor Statements for factors that could cause actual results to differ materially from the guidance presented and underlying assumptions. See Exhibit E in Appendix 2 for detailed 2014 Natural Gas Matters Item Impacting Comparability guidance.

* 2014 Equity Issuance 2013 2014* $1,070M $800M - 1,000M * The guidance range for 2014 does not include potential penalties (other than those already accrued). It assumes the midpoint of the 2014 range for capital expenditures (~$5.5B). It excludes any change in depreciation rates associated with the General Rate Case. And it assumes a timely decision in the General Rate Case. See the Safe Harbor Statements for factors that could cause actual results to differ materially from the guidance presented and underlying assumptions. 2013 EOY shares outstanding: 457M Does not reflect resolution of gas investigations - Earning authorized return (except Gas Transmission) - Lower Natural Gas Matters costs + Higher capital expenditures

* Looking Ahead: Capital Expenditures 2014-2016 The high end of the range reflects capex at GRC request levels, including attrition amounts for 2015 and 2016, capex requested in the 2015 Gas Transmission and Storage case, and estimates of future electric proceedings. The low end reflects capex consistent with 2013 spending levels, adjusted for completion of the Cornerstone and Utility-owned Solar PV programs. *Excludes Oakley Plant $5B - 6B $4.5B - 6B $4.5B - 6B 2014 (1) 2015 2016* (1) 2014 capex includes ~$400 million that has already been reserved for PSEP capital exceeding authorized amounts. See the Safe Harbor Statements for factors that could cause actual results to differ materially from the guidance presented and underlying assumptions. ~$5.3B $4.7B - 5.5B Implied by General Rate Case Proposed Decision $4.7 - 5.3B

* Looking Ahead: Rate Base Growth 2014-2016 $32B - 35B $28B - 28.5B *Excludes Oakley Plant The high end of the range reflects capex at GRC request levels, including attrition amounts for 2015 and 2016, capex requested in the 2015 Gas Transmission and Storage case, and estimates of future electric proceedings. The low end reflects capex consistent with 2013 spending levels, adjusted for completion of the Cornerstone and Utility-owned Solar PV programs. 2014 2016* 2015 $30B - 32.5B 2014-2016 Weighted Average Rate Base See the Safe Harbor Statements for factors that could cause actual results to differ materially from the guidance presented and underlying assumptions. $30.5B - 31.5B $33B - 34B ~$28B Implied by General Rate Case Proposed Decision

* Appendix 1 – Regulatory and Guidance Matters Updates to Appendix 1 Since the Previous Quarter slide 13 Rate Cases 2014 CPUC General Rate Case slide 14 2015 CPUC Gas Transmission Rate Case slide 15 FERC Transmission Owner Rate Cases slide 16 Natural Gas Matters Gas Regulatory Proceedings Schedule slide 17 Gas Pipeline Safety Costs slide 18 CPSD Recommended Penalty – Total Shareholder Impact slide 19 Incremental Equity Factors slide 20

* Updates to Appendix 1 Since the Previous Quarter Slide 14 2014 CPUC General Rate Case Slide 15 2015 CPUC Gas Transmission Rate Case Slide 16 FERC Transmission Owner Rate Cases Slide 17 Gas Regulatory Proceedings Schedule Slide 18 Gas Pipeline Safety Costs

* 2014 2014 CPUC General Rate Case General Rate Case sets base revenue requirement for 2014-2016 Includes operating costs and capital for generation and electric and gas distribution Excludes fuel and purchased power, cost of capital, electric transmission, and gas transmission Proposed Decision recommends an increase of $453 million compared to the requested increase of $1.16 billion PD recommends attrition increases for 2015 and 2016 of $322 million and $371 million, compared to the requested increases of $436 million and $486 million, respectively Compared to the request, the PD recommends reductions in funding for various safety, reliability, and customer service improvements across various parts of the business Assigned Commissioner: Florio Administrative Law Judge: Pulsifer Comments filed with CPUC Final Decision expected Q1 Q2 Q3 Q4 Proposed Decision

* 2015 CPUC Gas Transmission and Storage Rate Case Application filed with the CPUC on December 19, 2013 Request sets revenue requirement for 2015-2017 Includes operating costs and capital for CPUC jurisdictional gas transmission and storage 2015 revenue requirement of $1.3 billion is a requested increase of $555 million Requested attrition increases of $61 million and $168 million in 2016 and 2017, respectively Significant request reflecting expense and capital to comply with new requirements PG&E motion for retroactivity of revenues approved in June 2014 Assigned Commissioner: Peterman Administrative Law Judge: Wong Q4 Q2 Q1 Q3 Q1 2014 Evidentiary hearings Opening & Reply Briefs Prehearing Conference Scoping Memo Retroactivity motion approved SED risk report Intervenor testimony Public Participation hearings 2015 Proposed Decision Final Decision

* FERC Transmission Owner Rate Cases September 2013 – FERC accepted TO15 subject to refund and rates Requested revenue requirement of $1.072 billion and ROE of 10.9% July 15, 2014 – Settlement filed with FERC, with a revenue requirement of $1.0396 billion and a depreciation rate of 2.56% Rates effective from October 1, 2013 through February 28, 2015 TO15 July 30, 2014 – TO16 filed with FERC Requested revenue requirement of $1.366 billion and ROE of 11.26% March 1, 2015 – expected effective date for TO16 revenue requirement and rates, subject to refund TO16

* Gas Regulatory Proceedings Schedule Recordkeeping OII I. 11-02-016 Class Location OII I. 11-11-009 Gas Pipeline OII I. 12-01-007 July May June August Gas Pipeline Safety OIR R. 11-02-019 Orders to Show Cause 5/16: PSEP Update prehearing conference September 2014 6/16: Appeal filed with State Court of Appeals 7/8: CPUC launches proposed rule changes to General Order 112 7/18: Comments on GO 112 rule revisions 7/25: Reply comments on GO 112 rule revisions 7/25: PSEP Update settlement 7/30: PSEP quarterly compliance filing 7/28: Motion by the City of San Bruno for an Order to Show Cause on alleged ex parte communications 7/28: Motion by the City of San Bruno seeking recusal of Assigned Commissioner Peevey 8/12: Parties reply to motions 7/21: Opposition files answers to PG&E appeal 8/15: Replies to answers to PGE appeal

* Gas Pipeline Safety Costs See the Safe Harbor Statements for factors that could cause actual results to differ materially from the guidance presented and underlying assumptions. PSEP Costs: Customer Recovery ($ millions)

* CPSD Recommended Penalty – Total Shareholder Impact (1) Actual and forecast costs borne by shareholders for gas pipeline safety work, 2010 and beyond. See slide 18 for additional detail. (2) The CPSD penalty recommendation proposes a $300 million fine and recognizes only $435 million of shareholder-funded PSEP spending. The CPSD equates its recommendation to a total of $2.25 billion, which would require $1.515 billion in incremental shareholder-funded gas safety work. See the Safe Harbor Statements for factors that could cause actual results to differ materially from the guidance presented and underlying assumptions. Excerpt from Q1 2014 Earnings Presentation

* Incremental Equity Factors Equity Impacting Event Multiplier Fine paid to state General Fund (1) 100% Unrecovered expenses (2) (3) 60% Capital write-off (3) 30% Incremental Equity Factors Associated with Gas Matters (1) Applies to newly issued fines. Fines already accrued: 50% multiplier at time of payment (2) Applies to expenses in the year in which they are incurred (3) Assumes costs tax deductible Excerpt from Q1 2014 Earnings Presentation

* Appendix 2 – Supplemental Earnings Materials Exhibit A: Reconciliation of PG&E Corporation Earnings from Operations to Consolidated slide 22 Income Available for Common Shareholders in Accordance with GAAP Exhibit B: Key Drivers of PG&E Corporation Earnings per Common Share from Operations slide 23 Exhibit C: Operational Performance Metrics slide 24-25 Exhibit D: Sales and Sources Summary slide 26 Exhibit E: Guidance for Items Impacting Comparability slide 27 Exhibit F: General Earnings Sensitivities slide 28 Exhibit G: Summary of Selected Regulatory Cases slide 29-33

* Exhibit A: Reconciliation of PG&E Corporation Earnings from Operations to Consolidated Income Available for Common Shareholders in Accordance with Generally Accepted Accounting Principles (“GAAP”) Second Quarter and Year to Date (“YTD”), 2014 vs. 2013 (in millions, except per share amounts) “Earnings from operations” is not calculated in accordance with GAAP and excludes items impacting comparability as described in Note (2) below. Items impacting comparability reconcile earnings from operations with Consolidated Income Available for Common Shareholders as reported in accordance with GAAP. The Utility incurred net costs of $97 million and $137 million pre-tax, during the three and six months ended June 30, 2014, respectively, in connection with natural gas matters. These amounts included pipeline-related costs to validate safe operating pressures and perform other activities associated with safety improvements to the Utility’s natural gas system, as well as legal and other costs. There were no additional charges recorded for these periods related to fines or third party liability claims, and no insurance recoveries.

* Exhibit B: Key Drivers of PG&E Corporation Earnings per Common Share (“EPS”) from Operations Second Quarter and YTD, 2014 vs. 2013 ($/Share, Diluted) See Exhibit A for a reconciliation of EPS from Operations to EPS on a GAAP basis. Represents additional capital-related expenses during the three months and six months ended June 30, 2014 as compared to the same periods in 2013, with no corresponding increase in revenue. The CPUC has not yet issued a final decision on the Utility’s 2014 General Rate Case request to increase revenues beginning on January 1, 2014. Upon receipt of a final decision, the Utility has been authorized to collect any final adopted increase in revenue requirements from January 1, 2014.

* Exhibit C: Operational Performance Metrics It is possible to meet end-of-year (EOY) target while missing year-to-date (YTD) target, as some metrics have YTD targets that vary from EOY targets. The 2014 target for earnings from operations is not publicly reported. See following page for definitions of the operational performance metrics. Second Quarter and YTD, 2014 vs. 2013

* Definitions of 2014 Operational Performance Metrics from Exhibit C Safety Public and employee safety are measured in four areas: (1) Nuclear Operations Safety, (2) Gas Operations Safety, (3) Electric Operations Safety, and (4) Employee Safety. The safety of the Utility’s nuclear power operations, Unit 1 and Unit 2, is an index comprised of 12 performance indicators for nuclear power generation that are regularly benchmarked against other nuclear power generators. The safety of the Utility’s natural gas operations is represented by (a) the number of third party “dig-ins” (i.e., damage resulting in repair or replacement of underground facility) to Utility gas assets per 1,000 Underground Service Alert tickets; and (b) the timeliness (measured in minutes) of on-site response to gas emergency service calls. The safety of the Utility’s electric operations is represented by (a) the percentage improvement in the number of wire down events with resulting sustained unplanned outages compared to the same report period of the previous year, and (b) the percentage of time that Utility personnel are on site within 60 minutes after receiving a 911 call of a potential PG&E electric hazard. The safety of the Utility’s employees is represented by (a) the number of lost workday cases incurred per 200,000 hours worked (or for approximately every 100 employees), and (b) the number of serious preventable motor vehicle incidents that the driver could have reasonably avoided, per one million miles driven. Customer Customer satisfaction and service reliability are measured by: The overall satisfaction (measured as a score of zero to 100) of customers with the products and services offered by the Utility, as measured through a quarterly survey performed by an independent third-party research firm. The Utility’s ability to complete planned in-line inspections and pipeline retrofit projects, measured by two equally weighted components of (a) In-Line Inspections and (b) In-Line Upgrades. The timeliness (measured in days) of gas asset information being entered into the Utility’s gas mapping system after a gas project is completed. The efficient completion of certain committed work for gas operations-related programs. The index is comprised of three components related to the completion of committed work and the cost of completing the work. The total time (measured in minutes) the average customer is without electric power during a given time period. Financial 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). Earnings from operations is not calculated in accordance with GAAP. For a reconciliation of earnings from operations to earnings in accordance with GAAP, see Exhibit A.

* (1) Includes other sources of electric energy totaling 569 kWh and 298 kWh for the three months ended June 30, 2014 and 2013, respectively, and 1,273 kWh and 2,333 kWh for the six months ended June 30, 2014 and 2013, respectively. Exhibit D: Pacific Gas and Electric Company Sales and Sources Summary Second Quarter and YTD, 2014 vs. 2013 Please see the 2013 Annual Report on Form 10-K for additional information about operating statistics.

* Exhibit E: PG&E Corporation Guidance for Items Impacting Comparability (“IIC”) Items impacting comparability are those items that management believes do not reflect the normal course of operations. These items are excluded when calculating “earnings from operations” which is a non-GAAP measure that allows investors to compare the underlying financial performance of the business from one period to another. These items are included in calculating Consolidated Income Available for Common Shareholders in accordance with GAAP. The pre-tax range of costs for specific items included in the range of after-tax costs associated with natural gas matters is shown below. The range of $350 million to $450 million reflects pipeline-related expenses that are not recoverable through rates, including costs to perform work associated with the Utility’s PSEP, costs related to the Utility’s multi-year effort to identify and remove encroachments from transmission pipeline rights-of-way, costs related to the integrity management of transmission pipelines and other gas-related work, including some work at compressor stations, and legal and other expenses. The guidance provided does not include any potential future fines (other than those already accrued). The ultimate amount of fines imposed on the Utility that is payable to the State General Fund could be materially higher than the $200 million previously accrued for the pending CPUC investigations. The CPUC and staff also could impose additional fines or take other enforcement action with respect to the Utility’s self-reported violations, the staff’s audit findings, the Utility’s obligation to monitor and remove encroachments from pipeline rights-of-way, and the Carmel incident on March 3, 2014. The Utility’s best estimate of probable loss for third-party liability claims related to the San Bruno accident is $565 million, the cumulative charges recorded through 2013. The Utility has settled substantially all third-party liability claims. Although the Utility believes that a significant portion of the costs it incurs for third-party liability claims and associated legal expenses will be recovered through its insurance, the amount and timing of future recoveries are uncertain. The Utility recognizes insurance recoveries only when they are deemed probable under applicable accounting standards. (3) Guidance does not include potential environmental-related costs that the Utility could incur in 2014 if the final order for remediation at the Utility’s natural gas compressor station located near Hinkley, California, is more onerous than the Utility’s proposal. Actual financial results for 2014 may differ materially from the guidance provided. For a discussion of the factors that may affect future results, see the Safe Harbor Statements.

* Exhibit F: General Earnings Sensitivities PG&E Corporation and Pacific Gas and Electric Company These general earnings sensitivities on factors that may affect 2014 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 the Safe Harbor Statements.

* Exhibit G: Pacific Gas and Electric Company Summary of Selected Regulatory Cases