The Utility’s depreciation and amortization expense consists of depreciation and amortization on plant and regulatory assets, and decommissioning expenses associated with fossil fuel-fired generation facilities and nuclear power facilities. The Utility’s depreciation, amortization, and decommissioning expenses decreased by $94 million, or 15%, and by $265 million, or 15%, in the three and nine months ended September 30, 2013, respectively, as compared to the same periods in 2012. The decrease in the three and nine months ended September 30, 2013 is primarily due to the absence of amortization expense of $137 million and $363 million, respectively, for the energy recovery bonds regulatory asset which fully amortized in 2012. The decreases in both periods were partially offset by the impact of capital additions.
The Utility’s depreciation expense for future periods is expected to be affected as a result of changes in capital expenditures and the implementation of new depreciation rates as authorized by the CPUC in the future in the 2014 GRC and 2015 GT&S rate case. Future TO rate cases authorized by the FERC will also have an impact on depreciation rates.
There were no material changes to interest income, interest expense and other income, net for the three and nine months ended September 30, 2013, as compared to the same periods in 2012.
Income Tax Provision
The Utility’s income tax provision decreased by $142 million, or 116%, and $67 million, or 20%, in the three and nine months ended September 30, 2013, respectively, as compared to the same periods in 2012, primarily due to lower pretax income and higher state deductions and benefits described below.
The effective tax rates for the three months ended September 30, 2013 and 2012 were a benefit of 14% and expense of 26%, respectively. The effective tax rate decreased compared to 2012, primarilydue to higher state deductions and benefits received in 2013, including state deductible repairs due to a tax law change and benefits associated with a California research and development claim; and higher deductible software development costs.
The effective tax rates for the nine months ended September 30, 2013 and 2012 were 26% and 29%, respectively. The effective tax rate decreased compared to 2012, primarilydue to the state deductions and benefits mentioned above partially offset by the effect of regulatory treatment of fixed asset timing differences (which reverse over time) related to the cost of removal of fixed assets and decommissioning costs.
LIQUIDITY AND FINANCIAL RESOURCES
Overview
The Utility’s ability to fund operations and make distributions to PG&E Corporation depends on the levels of its operating cash flows and access to the capital and credit markets. The levels of the Utility’s cash flows fluctuate as a result of seasonal load, volatility in energy commodity costs, collateral requirements related to price risk management activities, the timing and effect of regulatory decisions, the timing and amount of long-term financings, and the timing and amount of tax payments or refunds, among other factors. The Utility generally utilizes equity contributions from PG&E Corporation and long-term senior unsecured debt issuances to maintain its CPUC-authorized capital structure consisting of 52% equity and 48% debt and preferred stock. The Utility relies on short-term debt, including commercial paper, to fund temporary financing needs. The CPUC authorizes the aggregate amount of long-term debt and short-term debt that the Utility may issue and authorizes the Utility to recover its related debt financing costs. The Utility has short-term borrowing authority of $4.0 billion, including $500 million that is restricted to certain contingencies.
PG&E Corporation’s ability to fund operations, make scheduled principal and interest payments, fund equity contributions to the Utility, and pay dividends, primarily depends on the level of cash distributions received from the Utility and PG&E Corporation’s access to the capital and credit markets.
PG&E Corporation and the Utility have approximately $1.3 billion of long-term debt maturing within the next 6 months. PG&E Corporation and the Utility plan to repay this debt with capital market financings.
The Utility’s future equity needs will continue to be affected by costs that are not recoverable through rates, including costs related to natural gas matters. The Utility’s equity needs would also increase to the extent it is required to pay fines or penalties in connection with the pending investigations. (See “Natural Gas Matters” below.) Further, given the Utility’s significant ongoing capital expenditures, the Utility will continue to need equity contributions from PG&E Corporation to maintain its authorized capital structure.
PG&E Corporation’s equity contributions to the Utility are funded primarily through common stock issuances. PG&E Corporation also may use draws under its revolving credit facility to occasionally fund equity contributions on an interim basis. PG&E Corporation’s issuance of common stock to fund equity contributions to the Utility has been dilutive to PG&E Corporation’s EPS to the extent that the equity contributions are used by the Utility to restore equity that has been depleted by unrecoverable costs and charges. Future issuances of common stock by PG&E Corporation could have a material dilutive effect on PG&E Corporation’s EPS primarily depending upon the resolution of the CPUC’s pending investigations and the ultimate amount of unrecoverable costs the Utility incurs.
PG&E Corporation’s and the Utility’s credit ratings may be affected by the ultimate outcome of the pending investigations related to natural gas matters and the San Bruno accident. PG&E Corporation’s and the Utility’s credit ratings may affect their access to the credit and capital markets and their respective financing costs in those markets. Credit rating downgrades may increase the cost of short-term borrowing, including the Utility’s commercial paper, as well as the costs associated with their respective credit facilities, and long-term debt.
2013 Financings
Utility
In June 2013, the Utility issued $375 million principal amount of 3.25% Senior Notes due June 15, 2023 and $375 million principal amount of 4.60% Senior Notes due June 15, 2043. The proceeds were used to repurchase $461 million principal amount, net of $15 million of premiums and $6 million of accrued interest, of the Utility’s $1.0 billion outstanding 4.80% Senior Notes due March 1, 2014, to repay a portion of outstanding commercial paper, and for general corporate purposes.
PG&E Corporation
In May 2013, PG&E Corporation entered into a new equity distribution agreement providing for the sale of PG&E Corporation common stock having an aggregate gross sales price of up to $400 million. As of September 30, 2013, PG&E Corporation sold common stock having an aggregate gross sales price of $150 million under this agreement. During the three and nine months ended September 30, 2013, PG&E Corporation paid commissions of $1 million, respectively, under this agreement.
During the nine months ended September 30, 2013, PG&E Corporation issued 18 million shares of its common stock for aggregate net cash proceeds of $724 million in the following transactions:
| · | 7 million shares were sold in an underwritten public offering for cash proceeds of $300 million, net of fees and commissions; |
| | |
| · | 6 million shares that were issued for cash proceeds of $212 million under the PG&E Corporation 401(k) plan, the Dividend Reinvestment and Stock Purchase Plan, and share-based compensation plans; and |
| · | 5 million shares were sold for cash proceeds of $212 million, net of commissions paid of $2 million, under equity distribution agreements. |
The proceeds from these sales were used for general corporate purposes, including the infusion of equity into the Utility. For the nine months ended September 30, 2013, PG&E Corporation made equity contributions to the Utility of $835 million. PG&E Corporation forecasts that it will need to continue to issue additional common stock to fund the Utility’s equity needs.
Revolving Credit Facilities and Commercial Paper Program
In April 2013, PG&E Corporation and the Utility amended and restated their revolving credit facilities to extend their termination dates from May 31, 2016 to April 1, 2018. These agreements contain substantially similar terms as their original 2011 credit agreements.
The following table summarizes PG&E Corporation’s and the Utility’s outstanding borrowings at September 30, 2013:
| | | | | | Letters of | | | | | | | | |
| | Termination | | Facility | | Credit | | | | Commercial | | Facility |
| | Date | | Limit | | Outstanding | | Borrowings | | Paper | | Availability |
| (in millions) | | | | | | | | | | | | | | | | | | | |
| PG&E Corporation | April 2018 | | $ | 300 | (1) | | $ | - | | $ | 260 | | $ | - | | | $ | 40 | |
| Utility | April 2018 | | | 3,000 | (2) | | | 91 | | | - | | | 693 | (3) | | | 2,216 | (3) |
| Total revolving | | | | | | | | | | | | | | | | | | | |
| credit facilities | | | $ | 3,300 | | | $ | 91 | | $ | 260 | | $ | 693 | | | $ | 2,256 | |
| | | | | | | | | | | | | | | | | | | | |
(1) Includes a $100 million sublimit for letters of credit and a $100 million commitment for loans that are made available on a same-day basis and are repayable in full within 7 days.
(2) Includes a $1.0 billion sublimit for letters of credit and a $300 million commitment for loans that are made available on a same-day basis and are repayable in full within 7 days.
(3) The Utility treats the amount of its outstanding commercial paper as a reduction to the amount available under its revolving credit facility.
For the nine months ended September 30, 2013, the average outstanding borrowings under PG&E Corporation’s revolving credit facility were $199 million and the maximum outstanding balance during the period was $260 million. For the nine months ended September 30, 2013, the Utility’s average outstanding commercial paper balance was $528 million and the maximum outstanding balance during the period was $1.0 billion. The Utility has not borrowed under its credit facility during 2013.
At September 30, 2013, PG&E Corporation and the Utility were in compliance with all covenants under their respective revolving credit facilities.
Dividends
In September 2013, the Board of Directors of PG&E Corporation declared quarterly dividends of $0.455 per share, totaling $204 million, of which $199 million was paid on October 15, 2013 to shareholders of record on September 30, 2013.
In September 2013, the Board of Directors of the Utility declared dividends on its outstanding series of preferred stock, payable on November 15, 2013, to shareholders of record on October 31, 2013.
Utility
Operating Activities
The Utility’s cash flows from operating activities primarily consist of receipts from customers less payments of operating expenses, other than expenses such as depreciation that do not require the use of cash.
The Utility’s cash flows from operating activities for the nine months ended September 30, 2013 and 2012 were as follows:
| | 2013 | | | 2012 | |
| Net income | | $ | 728 | | | $ | 798 | |
| Adjustments to reconcile net income to net cash provided by operating | | | | | | | | |
| activities: | | | | | | | | |
| Depreciation, amortization, and decommissioning | | | 1,542 | | | | 1,807 | |
| Allowance for equity funds used during construction | | | (78 | ) | | | (79 | ) |
| Deferred income taxes and tax credits, net | | | 545 | | | | 633 | |
| PSEP disallowed capital expenditures | | | 196 | | | | - | |
| Other | | | 231 | | | | 189 | |
| Net effect of changes in operating assets and liabilities | | | (338 | ) | | | 157 | |
| Net cash provided by operating activities | | $ | 2,826 | | | $ | 3,505 | |
During 2013, net cash provided by operating activities decreased by $679 million compared to 2012. This decrease was driven by fluctuations in activities within the normal course of business such as the timing and amount of payments, including $86 million of tax payments due to audit settlements in 2013 compared to $174 million in tax refunds during 2012.
Future cash flow from operating activities will be affected by various factors, including:
| | |
| · | the timing and amount of tax payments, tax refunds, net collateral payments, and interest payments; |
| | |
| · | the timing and amount of payments to third parties in connection with the San Bruno accident and related insurance recoveries; |
| | |
| · | the timing and amount of fines or penalties that may be imposed, as well as any costs associated with remedial actions the Utility may be required to implement; |
| | |
| · | the anticipated higher operating and maintenance costs associated with the Utility’s natural gas and electric operations (see “Operating and Maintenance” above and “Natural Gas Matters” below); and |
| | |
| · | the timing of the resolution of the Chapter 11 disputed claims and the amount of interest on these claims that the Utility will be required to pay (see Note 9 of the Notes to the Condensed Consolidated Financial Statements). |
Investing Activities
The Utility’s investing activities primarily consist of construction of new and replacement facilities necessary to deliver safe and reliable electricity and natural gas services to its customers. The amount and timing of the Utility’s capital expenditures is affected by many factors such as the occurrence of storms and other events causing outages or damages to the Utility’s infrastructure. Cash used in investing activities also includes the proceeds from sales of nuclear decommissioning trust investments which are largely offset by the amount of cash used to purchase new nuclear decommissioning trust investments. The funds in the decommissioning trusts, along with accumulated earnings, are used exclusively for decommissioning and dismantling the Utility’s nuclear generation facilities.
The Utility’s cash flows from investing activities for the nine months ended September 30, 2013 and 2012 were as follows:
| | 2013 | | | 2012 | |
| Capital expenditures | | $ | (3,881 | ) | | $ | (3,361 | ) |
| Decrease (increase) in restricted cash | | | 29 | | | | (38 | ) |
| Proceeds from sales and maturities of nuclear decommissioning trust investments | | | 1,152 | | | | 903 | |
| Purchases of nuclear decommissioning trust investments | | | (1,150 | ) | | | (964 | ) |
| Other | | | 14 | | | | 14 | |
| Net cash used in investing activities | | $ | (3,836 | ) | | $ | (3,446 | ) |
Net cash used in investing activities increased by $390 million in 2013 compared to 2012 primarily due to higher capital expenditures.
Future cash flows used in investing activities are largely dependent on the timing and amount of capital expenditures. The Utility forecasts that capital expenditures will total approximately $5.1 billion in 2013, including expenditures related to its pipeline safety enhancement plan. For more information about the types of capital investments made by the Utility, see “Capital Expenditures” in the 2012 Annual Report.
Financing Activities
The Utility’s cash flows from financing activities for the nine months ended September 30, 2013 and 2012 were as follows:
| | 2013 | | | 2012 | |
| Net issuance (repayments) of commercial paper, net of discount of $1 and $3 | | | | | | |
| at respective dates | | $ | 322 | | | $ | (1,247 | ) |
| Proceeds from issuance of long-term debt, net of premium, discount, and issuance | | | | | | | | |
| costs of $9 and $10 at respective dates | | | 741 | | | | 1,140 | |
| Long-term debt matured or repurchased | | | (461 | ) | | | (50 | ) |
| Energy recovery bonds matured | | | - | | | | (313 | ) |
| Preferred stock dividends paid | | | (10 | ) | | | (10 | ) |
| Common stock dividends paid | | | (537 | ) | | | (537 | ) |
| Equity contribution | | | 835 | | | | 715 | |
| Other | | | (14 | ) | | | 25 | |
| Net cash provided by (used in) financing activities | | $ | 876 | | | $ | (277 | ) |
In 2013, net cash provided by financing activities increased by $1.2 billion compared to the same period in 2012. Cash provided by or used in financing activities is driven by the Utility’s financing needs, which depend on the level of cash provided by or used in operating activities, the level of cash provided by or used in investing activities, the conditions in the capital markets, and the maturity date of existing debt instruments. The Utility generally utilizes long-term senior unsecured debt issuances and equity contributions from PG&E Corporation to maintain its CPUC-authorized capital structure, and relies on short-term debt to fund temporary financing needs.
PG&E Corporation and the Utility enter into contractual commitments in connection with future obligations that relate to financing arrangements (such as long-term debt, preferred stock, and certain forms of regulatory financing), purchases of electricity and natural gas for customers, purchases of transportation capacity, purchases of renewable energy, and purchases of fuel and transportation to support the Utility’s generation activities. (Refer to the 2012 Annual Report and “Liquidity and Financial Resources” above.)
Since the San Bruno accident, PG&E Corporation and the Utility have incurred total cumulative charges of approximately $2.3 billion related to natural gas matters that are not recoverable through rates, as shown in the following table:
| | | | | | | | | | |
| | | Cumulative | | | Nine Months Ended | | | Cumulative | |
| | | December 31, | | | September 30, | | | September 30, | |
| (in millions) | | 2012 | | | 2013 | | | 2013 | |
Pipeline-related expenses (1) | | $ | 1,023 | | | $ | 249 | | | $ | 1,272 | |
Disallowed capital (2) | | | 353 | | | | 196 | | | | 549 | |
Accrued fines (3) | | | 217 | | | | - | | | | 217 | |
Third-party liability claims (4) | | | 455 | | | | 110 | | | | 565 | |
Insurance recoveries (4) | | | (284 | ) | | | (70 | ) | | | (354 | ) |
| Contribution to City of San Bruno | | | 70 | | | | - | | | | 70 | |
| Total natural gas matters | | $ | 1,834 | | | $ | 485 | | | $ | 2,319 | |
| | | | | | | | | | | | | |
(1) | Cumulative costs through September 2013 include PSEP-related expenses of approximately $700 million and other gas safety-related work of $300 million. |
(2) | See “Pipeline Safety Enhancement Plan” below. |
(3) | See “Pending CPUC Investigations” below. Amount includes $17 million penalty that was paid in 2012. |
(4) | See “Third-Party Claims” below. |
As described below, there are three pending CPUC investigations against the Utility. As part of those proceedings, the SED has recommended that the CPUC impose what the SED characterizes as a penalty of $2.25 billion on the Utility, allocated as follows: (1) $300 million as a fine to the State General Fund, (2) $435 million for a portion of PSEP costs that were previously disallowed by the CPUC and funded by shareholders, and (3) $1.515 billion to perform PSEP work that was previously approved by the CPUC, implement operational remedies, and for future PSEP costs. If the SED’s penalty recommendation is adopted by the CPUC, the Utility estimates that its total unrecovered costs and fines related to natural gas transmission operations would be in excess of $4 billion.
Pipeline Safety Enhancement Plan
The Utility’s pipeline safety enhancement plan is a multi-year program to modernize and upgrade its natural gas transmission system. In December 2012, the CPUC approved most of the projects proposed in the PSEP but disallowed the Utility’s request for rate recovery of a significant portion of costs the Utility forecasted it would incur through 2014. The CPUC authorized the Utility to recover costs, subject to the adopted capital and expense amounts, for activities including pipeline strength testing, pipeline replacement, in-line inspection, and the installation of automated valves. The CPUC prohibited the Utility from recovering the costs of pressure testing pipeline placed into service after January 1, 1956 for which the Utility is unable to produce pressure test records. The CPUC ordered the Utility to file an update PSEP application after the Utility completes its search and review of records relating to pipeline pressure validation for all 6,750 miles of the Utility’s natural gas transmission pipelines.
On October 29, 2013, the Utility submitted its update application to present the results of its completed records search and review and to request approval of adjusted revenue requirements. Based on the information obtained through the records search and review, the Utility has proposed to change the scope and prioritization of PSEP work, including deferring some projects to after 2014 and accelerating other projects. The Utility has proposed net reductions to authorized costs for both its strength testing program (to test 658 miles rather than 783 miles) and its pipeline replacement program (to replace 143 miles rather than 186 miles). In August 2013, in anticipation of the Utility’s update application, TURN and the CPUC’s DRA requested the assigned ALJ for an order limiting the scope of the revenue requirement changes that the Utility could request in the update application to only those changes resulting from the records search and subsequent pressure validation based on those records, which could result in a disallowance of costs associated with the acceleration of projects. The ALJ has not yet addressed their request and it is uncertain how the information presented in the Utility’s update application about accelerating or changing the scope of PSEP projects will be considered. Under the CPUC’s procedural rules, intervening parties may file protests and responses to the Utility’s application no later than December 2, 2013. The Utility has requested that the CPUC issue a final decision by August 2014 to approve the revised scope of PSEP projects and the net reduction in authorized costs.
Based on the proposed changes in the scope of PSEP projects through 2014, the Utility forecasts that total unrecoverable costs to complete this work will significantly exceed the amount previously forecasted primarily due to higher anticipated unit costs to replace pipeline segments. As a result, for the three months ended September 30, 2013, the Utility recorded a charge of $196 million, reflecting the increase in forecasted capital expenditures through 2014 that are expected to exceed the amount to be recovered. At September 30, 2013, the Utility has recorded cumulative charges of $549 million for disallowed PSEP-related capital expenditures, including $353 million recorded at December 31, 2012. Disallowed expenses are charged to net income in the period incurred. The Utility has incurred cumulative PSEP-related expenses of approximately $700 million through September 30, 2013 that are not recoverable through rates.
At September 30, 2013, capitalized PSEP costs of approximately $170 million are included in Property, Plant, and Equipment on the Condensed Consolidated Balance Sheets. The Utility could record additional charges if the CPUC does not approve the adjusted revenue requirements requested in the Utility’s PSEP update application or if cost forecasts increase in the future. The CPUC also could make ratemaking adjustments to recovery of PSEP costs in connection with the pending CPUC investigations discussed below. The Utility’s ability to recover pipeline safety costs beginning in 2015 also will be affected by the outcome of the 2015 GT&S rate case. See “2015 GT&S rate case” in “Regulatory Matters” below.
Pending CPUC Investigations
There are three CPUC investigative enforcement proceedings pending against the Utility that relate to (1) the Utility’s safety recordkeeping for its natural gas transmission system, (2) the Utility’s operation of its natural gas transmission pipeline system in or near locations of higher population density, and (3) the Utility’s pipeline installation, integrity management, recordkeeping and other operational practices, and other events or courses of conduct, that could have led to or contributed to the San Bruno accident. Evidentiary hearings and briefing have been completed in each of these investigations.
The SED has recommended that the CPUC impose what the SED characterizes as a penalty of $2.25 billion on the Utility, allocated as follows: (1) $300 million as a fine to the State General Fund, (2) $435 million for a portion of PSEP costs that were previously disallowed by the CPUC and funded by shareholders, and (3) $1.515 billion to perform PSEP work that was previously approved by the CPUC, implement operational remedies, and for future PSEP costs. Other parties, including the City of San Bruno, TURN, the CPUC’s DRA, and the City and County of San Francisco, have recommended total penalties of at least $2.25 billion, including fines payable to the State General Fund of differing amounts. The City of San Bruno also recommended that the Utility provide $150 million for a Peninsula Emergency Response Consortium, spend $100 million ($5 million per year for 20 years) to fund an independent advocacy trust (the California Pipeline Safety Trust), and provide funding for an independent monitor to oversee the implementation of the recommended remedial operational measures. TURN also recommended that the Utility bear expenses of $50 million to implement remedial measures and to pay for an independent monitor.
The record for the proceedings was closed on October 15, 2013. The CPUC’s rules call for the CPUC ALJs to issue one or more presiding officers’ decisions within 60 days of this date. The decisions will become the final decisions of the CPUC 30 days after issuance unless the Utility or another party files an appeal with the CPUC, or a CPUC commissioner requests that the CPUC review the decision, within such time. If an appeal or review request is filed, other parties have 15 days to provide comments but the CPUC could act before considering any comments.
At September 30, 2013 and December 31, 2012, PG&E Corporation’s and the Utility’s Condensed Consolidated Balance Sheets included an accrual of $200 million in other current liabilities for the minimum amount of fines deemed probable that the Utility will pay to the State General Fund. The Utility is unable to make a better estimate due to the many variables that could affect the final outcome, including how the total number and duration of violations will be determined; how the various penalty recommendations made by the SED and other parties will be considered; how the financial and tax impact of unrecoverable costs the Utility has incurred, and will continue to incur, to improve the safety and reliability of its pipeline system, will be considered; whether the Utility’s costs to perform any required remedial actions will be considered; and how the CPUC responds to public pressure. Future changes in these estimates or the assumptions on which they are based could have a material impact on PG&E Corporation’s and the Utility’s financial condition, results of operations, and cash flows. The CPUC may impose fines on the Utility that are materially higher than the amount accrued and may disallow PSEP costs that were previously authorized for recovery or other future costs. Disallowed costs would be charged to net income in the period incurred.
Other CPUC Enforcement Matters
In addition to the investigations that are pending against the Utility related to its natural gas operations and the San Bruno accident, the CPUC and/or SED are also considering the following matters. PG&E Corporation and the Utility are unable to estimate the amount or range of reasonably possible losses that may be incurred in connection with these matters.
Gas Safety Citation Program
California gas corporations are required to provide notice to the SED of any self-identified or self-corrected violations of certain state and federal regulations related to the safety of natural gas facilities and the corporations’ natural gas operating practices. The SED is authorized to issue citations and impose fines for violations of certain state and federal regulations. In September 2013, the SED published a document explaining the internal procedures the SED staff intends to follow in assessing gas safety violations and determining appropriate enforcement action. (Also see “Safety Enforcement Legislation” in “Regulatory Matters” below.) The SED can consider several factors in exercising its discretion to impose fines or take other enforcement action based on the totality of the circumstances. Such factors include how the SED assesses the severity of the safety risk associated with each violation; how the SED determines the number of violations; how the SED determines the duration of the violations; how the SED considers other factors such as whether the violation was self-reported, and whether any corrective actions were taken. The SED’s internal procedures also include a schedule of potential fine amounts that vary based on the severity of the safety risk posed by the violation.
In October 2013, the SED issued a citation related to one of the Utility’s self-reports and imposed a fine of $140,000. The Utility has filed 58 self-reports with the SED, plus additional follow-up reports, that the SED has not yet addressed. The SED could issue additional citations and impose fines associated with these self-reports.
Orders to Show Cause
On August 19, 2013, the CPUC issued two OSCs related to a document submitted by the Utility on July 3, 2013 as “errata” to correct information about some segments in Lines 101 and 147 (two of the Utility’s natural gas transmission pipelines that serve the San Francisco peninsula) that had been previously provided to the CPUC in October 2011 to allow the Utility to restore operating pressure on these pipelines. The first OSC directed the Utility to show why all orders issued by the CPUC to authorize increased operating pressure on the Utility’s gas transmission pipelines should not be immediately suspended pending competent demonstration that the Utility’s natural gas system records are reliable. It is uncertain when the CPUC will issue a decision on the first OSC. The second OSC ordered the Utility to show why it should not be penalized for violating CPUC rules that prohibit any person from misleading the CPUC, in connection with the errata submission. Among other recommendations submitted by intervening parties related to the second OSC, the DRA and TURN have recommended that the CPUC impose penalties of $12.7 million on the Utility for the errata submission. The CPUC is expected to issue a decision on the second OSC before the end of 2013. The CPUC could impose penalties on the Utility or take other enforcement action in connection with the OSCs.
Natural Gas Transmission Pipeline Rights-of-Way
In 2012, the Utility also notified the CPUC and the SED that the Utility is undertaking a system-wide effort to survey its transmission pipelines and identify and remove encroachments (such as building structures and vegetation overgrowth) from pipeline rights-of-way over a multi-year period. The SED could impose penalties on the Utility or take other enforcement action in connection with this matter.
Criminal Investigation
In June 2011, the U.S. Department of Justice, the California Attorney General’s Office, and the San Mateo County District Attorney’s Office began an investigation of the San Bruno accident and indicated that the Utility is a target of the investigation. Although the San Mateo County District Attorney’s Office has publicly indicated that they will not pursue state criminal charges, the U.S. Department of Justice may still bring criminal charges, including charges based on claims that the Utility violated the federal Pipeline Safety Act, against PG&E Corporation or the Utility. It is uncertain whether any criminal charges will be brought against any of PG&E Corporation’s or the Utility’s current or former employees. The Utility is continuing to cooperate with federal investigators. A criminal charge or finding would further harm the Utility’s reputation. PG&E Corporation and the Utility are unable to estimate the amount or range of reasonably possible losses associated with any civil or criminal penalties that could be imposed and such penalties could have a material impact on PG&E Corporation’s and the Utility’s financial condition, results of operations, and cash flows. In addition, the Utility’s business or operations could be negatively affected by any remedial measures that the Utility may undertake, such as operating its natural gas transmission business subject to the supervision and oversight of an independent monitor.
Third-Party Claims
In September 2013, the Utility agreed to settle the claims of substantially all of the remaining plaintiffs who sought compensation for personal injury and property damage, and other relief, including punitive damages, following the San Bruno accident. Approximately 165 lawsuits on behalf of approximately 525 plaintiffs have been filed against the Utility. For the three and nine months ended September 30, 2013, the Utility recorded a charge of $110 million to reflect its best estimate of probable loss for settlements reached in September 2013 and remaining third-party claims for personal injury, property damage, and damage to infrastructure, including claims by government entities. At September 30, 2013, the Utility has recorded cumulative charges of $565 million for third-party claims related to the San Bruno accident and has made cumulative payments of $389 million for settlements.
Through September 30, 2013, the Utility has recognized cumulative insurance recoveries of $354 million for third-party claims and related legal expenses. (The Utility has incurred cumulative legal expenses of $84 million in addition to the $565 million charges above). Insurance recoveries for the three and nine months ended September 30, 2013 were $25 million and $70 million, respectively. These amounts were recorded as a reduction to operating and maintenance expense in PG&E Corporation’s and the Utility’s Condensed Consolidated Statements of Income. Although the Utility believes that a significant portion of costs incurred for third-party claims (and associated legal expenses) relating to the San Bruno accident will ultimately be recovered through its insurance, it is unable to predict the amount and timing of additional insurance recoveries. (See Note 10 to the Condensed Consolidated Financial Statements.)
Class Action Complaint
On August 23, 2012, a complaint was filed in the San Francisco Superior Court against PG&E Corporation and the Utility (and other unnamed defendants) by individuals who seek certification of a class consisting of all California residents who were customers of the Utility between 1997 and 2010, with certain exceptions. The plaintiffs allege that the Utility collected more than $100 million in customer rates from 1997 through 2010 for the purpose of various safety measures and operations projects but instead used the funds for general corporate purposes such as executive compensation and bonuses. The plaintiffs allege that PG&E Corporation and the Utility engaged in unfair business practices in violation of California state law. The plaintiffs seek restitution and disgorgement, as well as compensatory and punitive damages.
PG&E Corporation and the Utility contest the plaintiffs’ allegations. On May 23, 2013, the court granted PG&E Corporation’s and the Utility’s request to dismiss the complaint on the grounds that the CPUC has exclusive jurisdiction to adjudicate the issues raised by the plaintiffs’ allegations. The plaintiffs have appealed the court’s ruling to the California Court of Appeal. PG&E Corporation and the Utility are unable to estimate the amount or range of reasonably possible losses, if any, that may be incurred in connection with this matter.
Other Pending Lawsuits and Claims
At September 30, 2013, there were also four purported shareholder derivative lawsuits outstanding against PG&E Corporation and the Utility seeking recovery on behalf of PG&E Corporation and the Utility for alleged breaches of fiduciary duty by officers and directors, among other claims. Three of these lawsuits are pending in the San Mateo County Superior Court. Although the proceedings have been stayed until further order of the court pending the resolution of the remaining third-party claims, the judge has lifted the stay for the limited purpose of permitting the derivative plaintiffs to obtain the information necessary for them to prepare, file, and serve a consolidated, or master, complaint. A case management conference is scheduled for January 21, 2014. The remaining purported shareholder derivative lawsuit, filed in the U.S. District Court for the Northern District of California, remains stayed pending the resolution of the lawsuits pending in the state Superior Court. PG&E Corporation and the Utility are uncertain when and how these derivative lawsuits will be resolved.
In February 2011, the Board of Directors of PG&E Corporation authorized PG&E Corporation to reject a demand made by another shareholder that the Board of Directors (1) institute an independent investigation of the San Bruno accident and related alleged safety issues; (2) seek recovery of all costs associated with such issues through legal proceedings against those determined to be responsible, including Board of Directors members, officers, other employees, and third parties; and (3) adopt corporate governance initiatives and safety programs. The Board of Directors also reserved the right to commence further investigation or litigation regarding the San Bruno accident if the Board of Directors deems such investigation or litigation appropriate.
PG&E Corporation and the Utility are uncertain when and how the above lawsuits will be resolved.
The Utility is subject to substantial regulation by the CPUC, the FERC, the NRC and other federal and state regulatory agencies. The resolutions of these and other proceedings may affect PG&E Corporation’s and the Utility’s financial condition, results of operations, and cash flows. Significant regulatory developments that have occurred since the 2012 Annual Report was filed with the SEC are discussed below.
2014 General Rate Case
In the GRC, the CPUC will determine the annual amount of revenue requirements that the Utility is authorized to collect through rates from 2014 through 2016 to recover anticipated costs associated with electric generation operations, and electric and natural gas distribution operations, and to provide the Utility an opportunity to earn its authorized ROE on related capital expenditures. The CPUC has concluded evidentiary hearings and briefing in the 2014 GRC and the Utility is now waiting for the CPUC to issue a proposed decision.
The Utility is seeking an increase in its 2014 revenue requirements of $1,160 million over the comparable revenues for 2013 that were previously authorized by the CPUC, for a requested total revenue requirement of $7.8 billion. The Utility’s request is based on detailed expense and capital forecasts for 2014. The Utility also has requested that the CPUC authorize attrition increases in 2015 and 2016 of $436 million and $486 million, respectively. The DRA recommends that the Utility’s 2014 revenue requirements be reduced by $125 million from amounts authorized in 2013, approximately $1,285 million lower than the Utility’s current forecast. The DRA also has recommended attrition increases of $169 million for 2015 and $160 million for 2016. The following table compares the Utility’s updated forecasted annual increases for 2014 through 2016 with the DRA’s recommended amounts:
| | | Increase (Decrease) to Revenue Requirements | | | Difference Between | |
| (in millions) | | Utility's Forecast (1) | | | DRA's Recommendation | | | Utility and DRA | |
| 2014 | | $ | 1,160 | | | $ | (125 | ) | | $ | (1,285 | ) |
| 2015 attrition | | | 436 | | | | 169 | | | | (267 | ) |
| 2016 attrition | | | 486 | | | | 160 | | | | (326 | ) |
| | | | | | | | | | | | | |
(1) Amounts reflect the Utility’s authorized cost of capital for 2013 and other adjustments to amounts requested in the Utility’s November 2012 application as a result of revised calculations.
The DRA’s recommendation reflects reductions across all lines of business represented in the GRC. The DRA has recommended that the CPUC moderate impacts on customer rates by reducing the amount of depreciation recovered through rates throughout the GRC period to approximately $160 million as compared to the $492 million increase supported by the Utility’s depreciation rate study. The DRA has also recommended that the Utility's capital expenditures be reduced by $1.0 billion in 2014, as compared to the Utility’s forecast of average annual capital expenditures of approximately $4.0 billion from 2014 to 2016.
Twelve other parties, including TURN, have also submitted recommendations in the 2014 GRC.TURN’s recommendation reflects reductions across most lines of business represented in the GRC, including significant reductions to the amount of depreciation recovered through rates. In addition, on May 17, 2013, the SED submitted the reports of consultants it engaged to evaluate the Utility’s use of safety risk assessment and risk mitigation measures in developing the Utility’s forecast. Overall, the reports found that most of the Utility’s forecasted projects and costs were generally reasonable but criticized the Utility’s level of risk analysis underlying the forecast.
The Utility believes that the substantial revenue requirement reductions recommended by DRA and TURN could undermine the Utility’s efforts to improve customer safety, reliability and service over the next three years. The Utility also believes that the recommendations fail to consider that the Utility’s currently authorized revenue requirements do not provide sufficient revenue to allow the Utility to recover the Utility’s actual costs to improve the safety and reliability of its operations. In 2012, the Utility incurred expenses that were approximately $250 million higher than the level of authorized revenue requirements and the Utility forecasts that it will incur a comparable amount in 2013. In addition, the Utility forecasts that capital expenditures for additional improvements will exceed currently authorized levels. (See “Operating and Maintenance” above.)
The CPUC’s procedural schedule contemplates a proposed decision to be issued by November 19, 2013 and a final decision to be issued by December 19, 2013. The CPUC has authorized the Utility’s revenue requirement changes to become effective as of January 1, 2014, even if the final decision is issued after that date.
Electric Transmission Owner Rate Cases
The Utility has two TO rate cases pending at the FERC. With respect to the TO rate case that was filed in September 2012, the Utility, the FERC Trial Staff and all active intervening parties reached a settlement that has been submitted to the FERC for approval. The settlement, if approved, will increase the annual retail revenue requirement from $934 million to $1,017 million effective as of May 1, 2013. In future periods, the Utility will refund to customers the difference between revenues collected at the higher as-filed rates and the rates proposed in the settlement. It is uncertain when the FERC will act on the settlement.
On September 24, 2013, the FERC accepted the Utility’s TO rate case that the Utility filed on July 24, 2013, making the proposed rates effective October 1, 2013, subject to refund pending a final decision by the FERC. The Utility requested a retail revenue requirement of $1,072 million and an ROE of 10.9%. The proposed rates represent a $30 million reduction as compared to the revenue requirements that have been in effect since May 1, 2013 (subject to refund) and a $55 million increase to the revenue requirements described in the preceding paragraph. Hearings are currently being held in abeyance while settlement discussions are held.
2015 Gas Transmission and Storage Rate Case
The Utility plans to file its 2015 GT&S rate case application before the end of 2013 to request that the CPUC authorize an increase in revenue requirements beginning on January 1, 2015 for the Utility’s ongoing costs of providing natural gas transmission and storage service, including costs to continue performing work consistent with the PSEP as approved by the CPUC, and financing costs. The Utility has incurred (and forecasts to continue to incur) costs that are substantially higher than amounts authorized by the CPUC in the Utility’s last GT&S and PSEP rate cases, as the Utility works to improve the safety and reliability of its natural gas transmission operations. (See “Natural Gas Matters” above.) The CPUC’s decision approving the PSEP authorizes the Utility to recover PSEP-related revenue requirements only through 2014. The CPUC’s decision in the Utility’s last GT&S rate case authorized revenue requirements through 2014 with an automatic 2% increase in rates on January 1, 2015 which will remain in effect until the CPUC issues a decision in the 2015 GT&S rate case. If the CPUC issued its decision after January 1, 2015, the revenue requirement adjustments would not be retroactive to January 1, 2015, unless ordered otherwise by the CPUC. If the Utility’s spending levels for GT&S services and PSEP work were to remain at the levels currently forecast, the automatic increase on January 1, 2015 would be insufficient for the Utility to recover its ongoing costs of service. The Utility’s continued use of regulatory accounting (which enables it to account for the effects of regulation, including recording regulatory assets and liabilities) for gas transmission and storage service depends on its ability to recover its cost of service. The timing of expense (or gain) recognition differs under GAAP accounting as compared to regulatory accounting. If the Utility was unable to continue using regulatory accounting, the differences in the timing of expense (or gain) recognition could affect the Utility’s financial results.
Under the CPUC’s procedural rules, intervening parties may file protests and responses to the Utility’s application. After the Utility files its reply, a prehearing conference would be held to set the procedural schedule, including the dates for evidentiary hearings. The timing and outcome of the 2015 GT&S rate case are uncertain.
Oakley Generation Facility
In December 2012, the CPUC approved an amended purchase and sale agreement between the Utility and a third-party developer that provides for the construction of a 586-megawatt natural gas-fired facility in Oakley, California. The CPUC authorized the Utility to recover the purchase price through rates. On April 18, 2013, the CPUC denied various applications for rehearing that had been filed with respect to the CPUC’s December 2012 decision. The CPUC’s denial of the rehearing applications has been appealed to the California Court of Appeal. On October 28, 2013, the California Court of Appeal issued a ruling granting review of the CPUC's decision. The Utility is uncertain when the court will issue a decision on these appeals and how the court's decision will impact the ultimate development and construction of the Oakley facility.
Diablo Canyon Nuclear Power Plant
The Utility has filed an application with the NRC to renew the operating licenses for the two operating units at Diablo Canyon. (The current licenses expire in 2024 and 2025.) In May 2011, after the earthquake and tsunami that caused significant damage to the Fukushima-Dai-ichi nuclear facilities in Japan, the NRC granted the Utility’s request to delay processing the Utility’s application until certain advanced seismic studies were completed by the Utility. After the Utility completes its seismic studies as anticipated by June 2014, the Utility will determine whether and when it will request the NRC to resume the relicensing proceeding. In order for the NRC to issue renewed operating licenses, the California Coastal Commission must determine that license renewal is consistent with federal and state coastal laws. The disposition of the Utility’s relicensing application also will be affected by the terms and timing of the NRC’s “waste confidence” decision regarding the environmental impacts of the storage of spent nuclear fuel which is not expected to be issued before September 2014. The NRC has stated that it will not take action in licensing or re-licensing proceedings until it issues a new “waste confidence decision.”
The CPUC is considering the Utility’s December 2012 application to recover estimated costs to decommission the Utility’s nuclear facilities at Diablo Canyon and the retired nuclear facility Humboldt Bay Power Plant Unit 3. The Utility files an application with the CPUC every three years requesting approval of the Utility’s estimated decommissioning costs and authorization to recover those costs through rates. As discussed in the 2012 Annual Report, the estimated discounted cost to decommission Diablo Canyon and Humboldt Bay increased by approximately $960 million and $480 million, respectively. The CPUC bifurcated the proceeding to allow for the decommissioning cost estimate associated with Humboldt Bay to be addressed first and all other matters (including the Diablo Canyon decommissioning cost estimate and all rate-related issues) to be addressed in a second phase. The CPUC is scheduled to issue a proposed decision regarding the decommissioning cost estimate associated with Humboldt Bay in November 2013 with a final decision anticipated in January 2014. The Utility anticipates the CPUC will issue a decision in the second phase during the first quarter of 2014.
Safety Enforcement Legislation
On October 5, 2013, the California Governor signed Senate Bill 291 which requires the CPUC to develop a safety enforcement program that authorizes CPUC staff to issue citations for safety violations and assess fines subject to a CPUC-approved limit. The safety programs also must allow the CPUC staff to consider mitigating and aggravating factors in exercising enforcement authority. The CPUC is required to implement the safety enforcement program for gas corporations by July 1, 2014 and for electric corporations by January 1, 2015. The Utility expects that the safety programs to be developed by the CPUC to comply with the new legislation will be substantially similar to the SED’s new internal procedures applicable to the gas safety citation program. See “Natural Gas Matters – Other CPUC Enforcement Matters” above.
The Utility’s operations are subject to extensive federal, state, and local laws and permits relating to the protection of the environment and the safety and health of the Utility’s personnel and the public. (See “Risk Factors” in the 2012 Annual Report.) These laws and requirements relate to a broad range of the Utility’s activities, including the remediation of hazardous wastes; the reporting and reduction of carbon dioxide and other GHG emissions; the discharge of pollutants into the air, water, and soil; and the transportation, handling, storage, and disposal of spent nuclear fuel.
Hinkley Site
The Utility’s remediation and abatement efforts at the Hinkley site are subject to the regulatory authority of the California Regional Water Quality Control Board, Lahontan Region. On July 17, 2013, the Regional Board certified a final environmental report evaluating the Utility’s proposed remedial methods to contain and remediate the underground plume of hexavalent chromium and the potential environmental impacts. The Regional Board is expected to issue waste discharge permits in 2014 to allow for continued treatment of hexavalent chromium and issue a final clean-up order in 2015.
The Utility has implemented interim remediation measures to reduce the mass of the chromium plume, to monitor and control movement of the plume, and provide replacement water to affected residents. As of September 30, 2013, approximately 350 residential households located near the plume boundary were covered by the Utility’s whole house water replacement program and the majority have opted to accept the Utility’s offer to purchase their properties. The Utility is required to maintain and operate the program for five years or until the State of California has adopted a drinking water standard specifically for hexavalent chromium at which time the program will be evaluated. The State of California recently proposed draft regulations for hexavalent chromium and is expected to issue a final standard in 2014.
At September 30, 2013 and December 31, 2012, $197 million and $226 million, respectively, were accrued in PG&E Corporation’s and the Utility’s Condensed Consolidated Balance Sheets for estimated undiscounted future remediation costs associated with the Hinkley site. Remediation costs for the Hinkley site are not recovered from customers through rates. Future costs will depend on many factors, including the levels of hexavalent chromium the Utility is required to use as the standard for remediation, the required time period by which those standards must be met, the extent of the chromium plume boundary, and adoption of a final drinking water standard by the State of California. As more information becomes known regarding these factors, the Utility’s cost estimates and the assumptions on which they are based regarding the amount of liability incurred may be subject to further changes. Future changes in estimates or assumptions may have a material impact on PG&E Corporation’s and the Utility’s future financial condition, results of operations, and cash flows.
GHG Cap-and-Trade
California Assembly Bill 32 requires the gradual reduction of state-wide GHG emissions to the 1990 level by 2020. The CARB is the state agency charged with adopting regulations to implement and enforce AB 32. The CARB has established a state-wide, comprehensive “cap-and-trade” program that sets a gradually declining limit (or “cap”) on the amount of GHGs that may be emitted by the major sources of GHG emissions each year. The cap-and-trade program’s first two-year compliance period, which began on January 1, 2013, applies to the electricity generation and large industrial sectors. The next compliance period, from January 1, 2015 through December 31, 2017, will be expanded to include the natural gas supply and transportation sectors, effectively covering all the capped sectors until 2020.
During each year of the program, the CARB will issue emission allowances (i.e., the rights to emit GHGs) equal to the amount of GHG emissions allowed for that year. Emitters can obtain allowances from the CARB at quarterly auctions held by the CARB or from third parties or exchanges in the market for trading GHG allowances. The CARB will also allocate a fixed number of allowances (which will decrease each year) for free to regulated electric distribution utilities, including the Utility, for the benefit of their electricity customers. The utilities are required to consign their allowances for auction by the CARB. The CPUC has ordered the utilities to allocate their auction revenues among certain classes of their customers in accordance with existing state law. Although the CPUC has previously authorized the utilities to recover their GHG compliance costs through rates, the recovery of these costs has been deferred until the CPUC adopts a final revenue allocation methodology. A final methodology is expected to be issued before the end of 2013.
The Utility expects all costs and revenues associated with GHG cap-and-trade to be passed through to customers.
OFF-BALANCE SHEET ARRANGEMENTS
PG&E Corporation and the Utility do not have any off-balance sheet arrangements that have had, or are reasonably likely to have, a current or future material effect on their financial condition, changes in financial condition, revenues or expenses, results of operations, liquidity, capital expenditures, or capital resources, other than those discussed in Note 2 of the Notes to the Condensed Consolidated Financial Statements (PG&E Corporation’s tax equity financing agreements) and Note 15 of the Notes to the Consolidated Financial Statements in the 2012 Annual Report (the Utility’s commodity purchase agreements).
RISK MANAGEMENT ACTIVITIES
PG&E Corporation and the Utility, mainly through its ownership of the Utility, are exposed to market risk, which is the risk that changes in market conditions will adversely affect net income or cash flows. PG&E Corporation and the Utility face market risk associated with their operations; their financing arrangements; the marketplace for electricity, natural gas, electric transmission, natural gas transportation, and storage; emissions allowances and offset credits, other goods and services; and other aspects of their businesses. PG&E Corporation and the Utility categorize market risks as “price risk” and “interest rate risk.” The Utility is also exposed to “credit risk,” the risk that counterparties fail to perform their contractual obligations.
The Utility actively manages market risk through risk management programs designed to support business objectives, discourage unauthorized risk-taking, reduce commodity cost volatility, and manage cash flows. The Utility uses derivative instruments only for non-trading purposes (i.e., risk mitigation) and not for speculative purposes. The Utility’s risk management activities include the use of energy and financial instruments such as forward contracts, futures, swaps, options, and other instruments and agreements, most of which are accounted for as derivative instruments. Some contracts are accounted for as leases. These activities are discussed in detail in the 2012 Annual Report. There were no significant developments to the Utility and PG&E Corporation’s risk management activities during the nine months ended September 30, 2013.
The preparation of the Condensed Consolidated Financial Statements in accordance with U.S. GAAP involved the use of estimates and assumptions that affect the recorded amounts of assets and liabilities as of the date of the Condensed Consolidated Financial Statements and the reported amounts of revenues and expenses during the reporting period. PG&E Corporation and the Utility consider their accounting policies for regulatory assets and liabilities, loss contingencies associated with environmental remediation liabilities and legal and regulatory matters, asset retirement obligations, and pension and other postretirement benefits plans to be critical accounting policies due, in part, to these accounting policies’ complexity, relevance and materiality to the financial position and results of operations of PG&E Corporation and the Utility, and requirement to use material judgments and estimates. Actual results may differ substantially from these estimates. These accounting policies and their key characteristics are discussed in detail in the 2012 Annual Report.
PG&E Corporation’s and the Utility’s primary market risk results from changes in energy commodity prices. PG&E Corporation and the Utility engage in price risk management activities for non-trading purposes only. Both PG&E Corporation and the Utility may engage in these price risk management activities using forward contracts, futures, options, and swaps to hedge the impact of market fluctuations on energy commodity prices and interest rates. (See the section above entitled “Risk Management Activities” in Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations.)
Based on an evaluation of PG&E Corporation’s and the Utility’s disclosure controls and procedures as of September 30, 2013, PG&E Corporation’s and the Utility’s respective principal executive officers and principal financial officers have concluded that such controls and procedures were effective to ensure that information required to be disclosed by PG&E Corporation and the Utility in reports that the companies file or submit under the Securities Exchange Act of 1934 is recorded, processed, summarized, and reported within the time periods specified in the SEC rules and forms. In addition, PG&E Corporation’s and the Utility’s respective principal executive officers and principal financial officers have concluded that such controls and procedures were effective in ensuring that information required to be disclosed by PG&E Corporation and the Utility in the reports that PG&E Corporation and the Utility file or submit under the Securities Exchange Act of 1934 is accumulated and communicated to PG&E Corporation’s and the Utility’s management, including PG&E Corporation’s and the Utility’s respective principal executive officers and principal financial officers, or persons performing similar functions, as appropriate to allow timely decisions regarding required disclosure.
There were no changes in internal control over financial reporting that occurred during the quarter ended September 30, 2013 that have materially affected, or are reasonably likely to materially affect, PG&E Corporation’s or the Utility’s internal control over financial reporting.
In addition to the following legal proceedings, PG&E Corporation and the Utility are involved in various legal proceedings in the ordinary course of their business. For more information regarding PG&E Corporation’s and the Utility’s contingencies, see Note 10 of the Notes to the Condensed Consolidated Financial Statements.
Diablo Canyon Nuclear Power Plant
In June 2013, the United States EPA and environmental group Riverkeeper agreed to extend until November 4, 2013 the deadline for the EPA to issue final regulations under Section 316(b) of the federal Clean Water Act requiring that cooling water intake structures at electric power plants, such as the nuclear generation facilities at Diablo Canyon, reflect the best technology available to minimize adverse environmental impacts. Given the recent federal government shutdown, the EPA and Riverkeeper are currently negotiating an extension to the November 4 deadline.
As part of the implementation process for the California Water Resources Control Board’s once-through cooling policy, the California Water Board’s nuclear review committee is overseeing development of an alternative technology assessment for Diablo Canyon. The deadline for the committee’s consultant to submit the final report to the California Water Board has been extended from October 2013 to December 2013. The EPA’s final regulations and final implementation of California’s once-through cooling policy could affect future negotiations between the Central Coast Regional Water Quality Control Board and the Utility regarding the status of the 2003 settlement agreement. For more information regarding the status of the 2003 settlement agreement between the Central Coast Regional Water Quality Control Board and the Utility, see “Part I, Item 3. Legal Proceedings” in the 2012 Annual Report.
Litigation Related to the San Bruno Accident and Natural Gas Spending
Various lawsuits have been filed in San Mateo County Superior Court against PG&E Corporation and the Utility in connection with the San Bruno accident, including two class action lawsuits. The lawsuits seek compensation for personal injury and property damage, and other relief, including punitive damages.In September 2013, the Utility agreed to settle the claims of substantially all of the remaining plaintiffs who sought compensation for personal injury and property damage, and other relief, including punitive damages, following the San Bruno accident.
At September 30, 2013, there were also four purported shareholder derivative lawsuits outstanding against PG&E Corporation and the Utility seeking recovery on behalf of PG&E Corporation and the Utility for alleged breaches of fiduciary duty by officers and directors, among other claims. Three of these lawsuits are pending in the San Mateo County Superior Court. Although the proceedings have been stayed until further order of the court pending the resolution of the remaining third-party claims, the judge has lifted the stay for the limited purpose of permitting the derivative plaintiffs to obtain the information necessary for them to prepare, file, and serve a consolidated, or master, complaint. A case management conference is scheduled for January 21, 2014. The remaining purported shareholder derivative lawsuit, filed in the U.S. District Court for the Northern District of California, remains stayed pending the resolution of the lawsuits pending in the state Superior Court. PG&E Corporation and the Utility are uncertain when and how these derivative lawsuits will be resolved.
In addition, on August 23, 2012, a complaint was filed in the San Francisco Superior Court against PG&E Corporation and the Utility (and other unnamed defendants) by individuals who seek certification of a class consisting of all California residents who were customers of the Utility between 1997 and 2010, with certain exceptions. The plaintiffs allege that the Utility collected more than $100 million in customer rates from 1997 through 2010 for the purpose of various safety measures and operations projects but instead used the funds for general corporate purposes such as executive compensation and bonuses. PG&E Corporation and the Utility contest the allegations.
For additional information, see “Part I, Item 3. Legal Proceedings” in the 2012 Annual Report and the discussion entitled “Natural Gas Matters” above in Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations and in Note 10 of the Notes to the Condensed Consolidated Financial Statements.
Pending CPUC Investigations
There are three CPUC investigative enforcement proceedings pending against the Utility related to the Utility’s natural gas operations and the San Bruno accident. Evidentiary hearings and briefing on the issue of alleged violations have been completed in each of these investigations. The CPUC has stated that it is prepared to impose significant penalties on the Utility if the CPUC determines that the Utility violated applicable laws, rules, and orders. The SED has recommended that the CPUC impose what the SED characterizes as a penalty of $2.25 billion on the Utility, consisting of a $300 million fine payable to the State General Fund and $1.950 billion of non-recoverable costs to perform work under the Utility’s pipeline safety enhancement plan and to implement the operational remedies. Several other parties have also submitted penalty recommendations.
For additional information, see “Part I, Item 3. Legal Proceedings” in the 2012 Annual Report and the discussion entitled “Natural Gas Matters – Pending CPUC Investigations” above in Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations and in Note 10 of the Notes to the Condensed Consolidated Financial Statements.
Other CPUC Enforcement Matters
California gas corporations are required to provide notice to the SED of any self-identified or self-corrected violations of certain state and federal regulations related to the safety of natural gas facilities and the corporations’ natural gas operating practices. The SED is authorized to issue citations and impose fines for violations of certain state and federal regulations. In September 2013, the SED published a document explaining the internal procedures the SED staff intends to follow in assessing gas safety violations and determining appropriate enforcement action. In October 2013, the SED issued a citation related to one of the Utility’s self-reports and imposed a fine of $140,000. The Utility has filed 58 self-reports with the SED, plus additional follow-up reports, that the SED has not yet addressed. The SED could issue additional citations and impose fines associated with these self-reports.
On August 19, 2013, the CPUC issued two OSCs related to a document submitted by the Utility on July 3, 2013 as “errata” to correct information about some segments in Lines 101 and 147 (two of the Utility’s natural gas transmission pipelines that serve the San Francisco peninsula) that had been previously provided to the CPUC in October 2011 to allow the Utility to restore operating pressure on these pipelines. The CPUC could impose penalties on the Utility or take other enforcement action in connection with the OSCs.
In addition, the Utility has notified the CPUC and the SED that the Utility is undertaking a system-wide effort to survey its transmission pipelines and identify and remove encroachments from pipeline rights-of-way over a multi-year period. The SED could impose penalties on the Utility or take other enforcement action in connection with this matter.
For additional information, see “Part I, Item 3. Legal Proceedings” in the 2012 Annual Report and the discussion entitled “Natural Gas Matters – Other CPUC Enforcement Matters” above in Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations and in Note 10 of the Notes to the Condensed Consolidated Financial Statements.
Criminal Investigation
In June 2011, the U.S. Department of Justice, the California Attorney General’s Office, and the San Mateo County District Attorney’s Office began an investigation of the San Bruno accident and indicated that the Utility is a target of the investigation. Although the San Mateo County District Attorney’s Office has publicly indicated that they will not pursue state criminal charges, the U.S. Department of Justice may still bring criminal charges, including charges based on claims that the Utility violated the federal Pipeline Safety Act, against PG&E Corporation or the Utility. It is uncertain whether any criminal charges will be brought against any of PG&E Corporation’s or the Utility’s current or former employees. The Utility is continuing to cooperate with federal investigators. A criminal charge or finding would further harm the Utility’s reputation. PG&E Corporation and the Utility are unable to estimate the amount or range of reasonably possible losses associated with any civil or criminal penalties that could be imposed and such penalties could have a material impact on PG&E Corporation’s and the Utility’s financial condition, results of operations, and cash flows. In addition, the Utility’s business or operations could be negatively affected by any remedial measures that the Utility may undertake, such as operating its natural gas transmission business subject to the supervision and oversight of an independent monitor.
For information about the significant risks that could affect PG&E Corporation’s and the Utility’s future financial condition, results of operations, and cash flows, see the section of the 2012 Annual Report entitled “Risk Factors,” as supplemented below, and the section of this quarterly report entitled “Cautionary Language Regarding Forward-Looking Statements.”
| The ultimate outcome of the pending investigations related to the Utility’s natural gas operations and the San Bruno accident may require the Utility to incur additional material charges for non-recoverable costs associated with its natural gas operations as well as for civil or criminal fines and penalties. Such charges could negatively affect the availability, amount, and timing of future debt and equity issuances. |
As discussed above in the section entitled “Natural Gas Matters − Pending CPUC Investigations and Enforcement Matters,” in Item 2: Management’s Discussion and Analysis of Financial Condition and Results of Operations, the SED has recommended that the CPUC impose what the SED characterizes as a penalty of $2.25 billion on the Utility, allocated as follows (1) $300 million as a fine to the State General Fund, (2) $435 million for a portion of PSEP costs that were previously disallowed by the CPUC and funded by shareholders, and (3) $1.515 billion to perform PSEP work that was previously approved by the CPUC, implement operational remedies, and for future PSEP costs. If the SED’s penalty recommendation is adopted by the CPUC, the Utility estimates that its total unrecovered costs and fines related to natural gas transmission operations would be in excess of $4 billion. Other parties also have submitted penalty recommendations, including the payment of a fine to the State General Fund of differing amounts.
If the final decision requires the Utility to pay penalties or fines to the State General Fund that are materially higher than the $200 million accrued at September 30, 2013, disallows additional PSEP-related costs that were previously authorized for recovery, or prohibits the Utility from recovering other future pipeline expenses, PG&E Corporation’s and the Utility’s financial condition, results of operations, and cash flows will be materially affected. Future developments in the criminal investigation arising from the San Bruno accident also could have a material effect on PG&E Corporation’s and the Utility’s financial condition, results of operations, and cash flows. (See the sections entitled “Criminal Investigation” under the heading “Natural Gas Matters” in Item 2: Management’s Discussion and Analysis of Financial Condition and Results of Operations.)
The Utility’s financing needs would increase if the Utility were required to incur unrecoverable costs and pay fines as a result of the outcome of the investigations. Such financing may become more difficult to obtain, especially if the outcome affected the Utility’s credit ratings. In addition, the equity component of the Utility’s authorized capital structure could decrease materially as the Utility incurs charges to reflect fines and unrecovered costs the Utility may be required to bear. PG&E Corporation primarily has relied on the public sale of its common stock to raise the funds it contributes to meet the Utility’s equity needs. The market price of PG&E Corporation common stock could decline materially depending on the outcome of the investigations and the amount and timing of future share issuances. Declines in the stock price could increase the dilutive effect of future stock issuances and make it more difficult or expensive for PG&E Corporation to complete future equity offerings.
During the quarter ended September 30, 2013, PG&E Corporation made equity contributions totaling $170 million to the Utility in order to maintain the 52% common equity component of its CPUC-authorized capital structure. Neither PG&E Corporation nor the Utility made any sales of unregistered equity securities during the quarter ended September 30, 2013.
Issuer Purchases of Equity Securities
During the quarter ended September 30, 2013, PG&E Corporation did not redeem or repurchase any shares of common stock outstanding. During the quarter ended September 30, 2013, the Utility did not redeem or repurchase any shares of its various series of preferred stock outstanding.
Ratio of Earnings to Fixed Charges and Ratio of Earnings to Combined Fixed Charges and Preferred Stock Dividends
The Utility’s earnings to fixed charges ratio for the nine months ended September 30, 2013 was 2.34. The Utility’s earnings to combined fixed charges and preferred stock dividends ratio for the nine months ended September 30, 2013 was 2.30. The statement of the foregoing ratios, together with the statements of the computation of the foregoing ratios filed as Exhibits 12.1 and 12.2 hereto, are included herein for the purpose of incorporating such information and Exhibits into the Utility’s Registration Statement No. 333-172394.
PG&E Corporation’s earnings to fixed charges ratio for the nine months ended September 30, 2013 was 2.26. The statement of the foregoing ratio, together with the statement of the computation of the foregoing ratio filed as Exhibit 12.3 hereto, is included herein for the purpose of incorporating such information and Exhibit into PG&E Corporation’s Registration Statement No. 333-172393.
| | *10.1 | | PG&E Corporation 2005 Supplemental Retirement Savings Plan, as amended effective September 17, 2013 |
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| | *10.2 | | PG&E Corporation Defined Contribution Executive Supplemental Retirement Plan, as amended effective September 17, 2013 |
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| | 12.1 | | Computation of Ratios of Earnings to Fixed Charges for Pacific Gas and Electric Company |
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| | 12.2 | | Computation of Ratios of Earnings to Combined Fixed Charges and Preferred Stock Dividends for Pacific Gas and Electric Company |
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| | 12.3 | | Computation of Ratios of Earnings to Fixed Charges for PG&E Corporation |
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| | 31.1 | | Certifications of the Chief Executive Officer and the Chief Financial Officer of PG&E Corporation required by Section 302 of the Sarbanes-Oxley Act of 2002 |
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| | 31.2 | | Certifications of the Chief Executive Officer and the Chief Financial Officer of Pacific Gas and Electric Company required by Section 302 of the Sarbanes-Oxley Act of 2002 |
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| | **32.1 | | Certifications of the Chief Executive Officer and the Chief Financial Officer of PG&E Corporation required by Section 906 of the Sarbanes-Oxley Act of 2002 |
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| | **32.2 | | Certifications of the Chief Executive Officer and the Chief Financial Officer of Pacific Gas and Electric Company required by Section 906 of the Sarbanes-Oxley Act of 2002 |
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| 101.INS | | XBRL Instance Document |
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| 101.SCH | | XBRL Taxonomy Extension Schema Document |
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| 101.CAL | | XBRL Taxonomy Extension Calculation Linkbase Document |
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| 101.LAB | | XBRL Taxonomy Extension Labels Linkbase Document |
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| 101.PRE | | XBRL Taxonomy Extension Presentation Linkbase Document |
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| 101.DEF | | XBRL Taxonomy Extension Definition Linkbase Document |
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| *Management contract or compensatory agreement. |
**Pursuant to Item 601(b)(32) of SEC Regulation S-K, these exhibits are furnished rather than filed with this report.
Pursuant to the requirements of the Securities Exchange Act of 1934, the registrants have duly caused this Quarterly Report on Form 10-Q to be signed on their behalf by the undersigned thereunto duly authorized.
| PG&E CORPORATION |
| |
| KENT M. HARVEY |
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Kent M. Harvey Senior Vice President and Chief Financial Officer (duly authorized officer and principal financial officer) |
| PACIFIC GAS AND ELECTRIC COMPANY |
| |
| DINYAR B. MISTRY |
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Dinyar B. Mistry Vice President, Chief Financial Officer and Controller (duly authorized officer and principal financial officer) |
Dated: October 30, 2013
| *10.1 | PG&E Corporation 2005 Supplemental Retirement Savings Plan, as amended effective September 17, 2013 |
| | |
| *10.2 | PG&E Corporation Defined Contribution Executive Supplemental Retirement Plan, as amended effective September 17, 2013 |
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| 12.1 | Computation of Ratios of Earnings to Fixed Charges for Pacific Gas and Electric Company |
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| 12.2 | Computation of Ratios of Earnings to Combined Fixed Charges and Preferred Stock Dividends for Pacific Gas and Electric Company |
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| 12.3 | Computation of Ratios of Earnings to Fixed Charges for PG&E Corporation |
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| 31.1 | Certifications of the Chief Executive Officer and the Chief Financial Officer of PG&E Corporation required by Section 302 of the Sarbanes-Oxley Act of 2002 |
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| 31.2 | Certifications of the Chief Executive Officer and the Chief Financial Officer of Pacific Gas and Electric Company required by Section 302 of the Sarbanes-Oxley Act of 2002 |
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| **32.1 | Certifications of the Chief Executive Officer and the Chief Financial Officer of PG&E Corporation required by Section 906 of the Sarbanes-Oxley Act of 2002 |
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| **32.2 | Certifications of the Chief Executive Officer and the Chief Financial Officer of Pacific Gas and Electric Company required by Section 906 of the Sarbanes-Oxley Act of 2002 |
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| 101.INS | XBRL Instance Document |
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| 101.SCH | XBRL Taxonomy Extension Schema Document |
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| 101.CAL | XBRL Taxonomy Extension Calculation Linkbase Document |
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| 101.LAB | XBRL Taxonomy Extension Labels Linkbase Document |
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| 101.PRE | XBRL Taxonomy Extension Presentation Linkbase Document |
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| 101.DEF | XBRL Taxonomy Extension Definition Linkbase Document |
| | |
* Management contract or compensatory agreement.
** Pursuant to Item 601(b)(32) of SEC Regulation S-K, these exhibits are furnished rather than filed with this report.
