PG&E Corporation Form 10-Q Summary
Business context and reporting period
Combined unaudited quarterly report for PG&E Corporation and Pacific Gas and Electric Company, the regulated California utility, for the three and nine months ended September 30, 2012, compared with the corresponding 2011 periods. The Utility served approximately five million electric distribution customers and four million natural gas distribution customers and is primarily regulated by the CPUC, FERC, and NRC.
Key financial metrics
| PG&E Corporation | Q3 2012 | Q3 2011 | 9M 2012 | 9M 2011 |
|---|---|---|---|---|
| Operating revenues | $3,976 million | $3,860 million | $11,210 million | $11,141 million |
| Operating income | $614 million | $408 million | $1,568 million | $1,584 million |
| Net income | $364 million | $203 million | $839 million | $771 million |
| Income available to common shareholders | $361 million | $200 million | $829 million | $761 million |
| Diluted EPS | $0.84 | $0.50 | $1.96 | $1.90 |
| Operating margin | 15.4% | 10.6% | 14.0% | 14.2% |
| Net margin | 9.2% | 5.3% | 7.5% | 6.9% |
Revenue increased 3% in the quarter and 1% year to date. Quarterly net income increased 79%, while nine-month net income increased 9%. Quarterly results benefited from lower natural gas matters costs, lower environmental remediation costs, and higher rate-base earnings. Nine-month operating income declined slightly because higher depreciation and operating and maintenance costs more than offset revenue growth.
- Electric revenue increased 4% in both the quarter and nine-month period, driven primarily by authorized base-revenue increases and higher pass-through amounts.
- Natural gas revenue declined 3% in the quarter and 11% year to date, primarily because lower natural gas prices reduced pass-through revenue. Revenue excluding pass-through costs increased.
- Operating and maintenance expense decreased 10% in the quarter but increased 5% year to date. Year-to-date expense included $386 million of net natural gas matters costs and $176 million of incremental safety and reliability spending above amounts assumed in prior rate cases.
- Depreciation, amortization, and decommissioning expense increased 9% in the quarter and 10% year to date, primarily because of capital additions.
Cash flow, debt, liquidity, and capitalization
- PG&E Corporation generated $3,452 million of operating cash flow in the first nine months of 2012, compared with $3,232 million in 2011.
- Capital expenditures were $3,361 million, up from $2,968 million, resulting in net investing cash use of $3,359 million.
- Net cash used in financing activities was $310 million. Financing included $1,140 million of long-term debt issuance, $1,247 million of net commercial-paper repayments, $702 million of common-stock proceeds, and $556 million of common dividends paid.
- Cash and cash equivalents declined to $296 million at September 30, 2012 from $513 million at December 31, 2011. The Utility itself held $86 million of cash.
- At September 30, 2012, PG&E Corporation had $12,915 million of long-term debt and $397 million of short-term borrowings. The Utility had $12,566 million of long-term debt, $397 million of short-term borrowings, and $145 million of commercial paper outstanding.
- The Utility had a $3.0 billion revolving facility, with $330 million of letters of credit and reported availability of $2,525 million after commercial paper. PG&E Corporation had $300 million of undrawn revolving capacity. Both companies were in compliance with their debt covenants.
- The Utility received $715 million of equity contributions from PG&E Corporation to maintain its CPUC-authorized capital structure of 52% common equity and 48% debt and preferred stock.
- PG&E Corporation issued common stock through public, equity-distribution, employee, and dividend-reinvestment programs. Shares outstanding increased to approximately 429.4 million at September 30, 2012 from 412.3 million at year-end 2011, creating potential dilution.
- The Utility issued $400 million of 4.45% senior notes in April and $750 million of senior notes in August 2012. Energy recovery bonds outstanding totaled $110 million and mature December 25, 2012.
Material changes versus the prior comparable period
- Quarterly income available to common shareholders rose from $200 million to $361 million, primarily reflecting higher rate-base earnings, lower natural gas-related costs, and lower environmental costs.
- Nine-month income available to common shareholders rose from $761 million to $829 million despite higher safety-related operating expenses, higher depreciation, and increased capital spending.
- Natural gas costs fell 37% year to date to $593 million, mainly because of lower average market prices and lower volumes sold.
- Natural gas matters costs were $386 million year to date versus $398 million in 2011; 2012 included $135 million of insurance recoveries and an $80 million increase in third-party claim accruals.
- Regulatory assets remained substantial at $7,094 million, including $6,527 million of long-term assets. Regulatory accounting assumes that qualifying costs will be recovered from or refunded to customers.
- The Utility’s environmental remediation liability increased to $913 million from $785 million at year-end 2011, including $227 million for Hinkley and $236 million for Topock.
Guidance, outlook, commentary, risks, and unusual items
- Management forecast 2012 unrecoverable pipeline-related expenses of up to $550 million, including $371 million incurred through September 30, 2012. It also forecast approximately $250 million of incremental safety and reliability expenses above prior rate-case assumptions for 2012 and expected similar incremental expenses in 2013.
- The CPUC administrative law judge’s October 2012 proposed decision would limit recovery under the pipeline safety enhancement plan, potentially disallowing $584 million of requested expenses and $401 million of requested capital expenditures and reducing equity earnings by an estimated $130 million. The decision was not final as of the filing date.
- PG&E believes total CPUC penalties related to natural gas investigations and enforcement matters are probable at not less than $200 million, but it cannot estimate potential penalties above that amount. No additional penalty charge was recorded during the first nine months of 2012.
- San Bruno-related third-party claims: the Utility had recorded cumulative charges of $455 million and estimated up to $145 million of additional claims, excluding potentially material punitive damages. Insurance coverage was approximately $992 million above a $10 million deductible; cumulative insurance recoveries were $234 million.
- Approximately 130 San Bruno-related lawsuits involving about 420 plaintiffs remained at September 30, 2012. A criminal investigation by federal, state, and local authorities continued, and the Utility was identified as a target.
- The Utility filed a FERC transmission rate case requesting a $254 million increase in estimated 2013 annual revenue requirements. It also sought new CPUC-authorized capital structure and return parameters beginning in 2013; the requested overall rate of return was 8.45% versus the currently authorized 8.79%.
- Power purchase commitments totaled $53.1 billion undiscounted, primarily extending beyond 2016. Natural gas commitments totaled $2.3 billion and nuclear fuel commitments totaled $1.6 billion.
- Diablo Canyon faces ongoing seismic, spent-fuel, NRC compliance, and license-renewal issues. The NRC delayed site-specific licensing decisions pending further consideration of spent-fuel environmental requirements.
- Other material risks include environmental remediation, regulatory disallowance, tax audits, commodity prices, collateral requirements, nuclear operations, weather and natural disasters, cyber risks, and the ability to access debt and equity markets.
Most important facts for investors to verify
- Final CPUC decisions on pipeline safety cost recovery, penalties, the 2013 cost of capital, and the 2014 General Rate Case.
- Ultimate San Bruno third-party claims, punitive damages, criminal or civil penalties, and timing and collectability of insurance recoveries.
- Whether the Utility can recover planned safety, reliability, environmental, and nuclear compliance costs through customer rates.
- Liquidity after the December 2012 energy recovery bond maturity, ongoing capital expenditures, commercial-paper needs, collateral requirements, and potential additional equity issuances.
- Changes in Hinkley and Topock remediation estimates and the portion ultimately recoverable from customers or other parties.
- Regulatory asset recoverability and the effect of any loss of cost-of-service regulation or adverse ratemaking decisions.
- Final outcomes of Diablo Canyon seismic studies, NRC requirements, spent-fuel proceedings, and license renewal.