PG&E Corporation and Pacific Gas and Electric Company — 2011 Q1 Form 10-Q
Business context and reporting period
Combined unaudited quarterly report for the three months ended March 31, 2011, filed May 4, 2011. PG&E Corporation is the holding company and conducts substantially all operations through Pacific Gas and Electric Company, a regulated electric and natural gas utility serving northern and central California. At March 31, 2011, the Utility served approximately 5.2 million electric distribution customers and 4.3 million natural gas distribution customers.
Key financial metrics
Amounts below are in millions, except per-share data.
| Metric | Q1 2011 | Q1 2010 | Change |
|---|---|---|---|
| Operating revenues | $3,597 | $3,475 | +$122, approximately 4% |
| Operating income | $484 | $618 | -$134, approximately 22% |
| Net income | $202 | $261 | -$59, approximately 23% |
| Income available to PG&E common shareholders | $199 | $258 | -$59, approximately 23% |
| Diluted EPS | $0.50 | $0.67 | -$0.17 |
| Operating cash flow | $1,088 | $395 | +$693 |
| Capital expenditures | $945 | $855 | +$90 |
| Cash used in investing activities | $883 | $848 | Use increased $35 |
- Electric revenue increased to $2,617 million from $2,510 million; natural gas revenue increased to $980 million from $965 million. Much of the increase reflected pass-through costs and authorized rate-base and transmission revenues.
- Operating and maintenance expense rose to $1,226 million from $991 million, driven by San Bruno-related pipeline work, winter storm response, higher legal and environmental costs, pension contributions, and public-purpose program spending.
- Depreciation, amortization, and decommissioning expense increased to $491 million from $451 million.
- Interest expense increased to $177 million from $168 million for PG&E Corporation and to $171 million from $156 million for the Utility.
- PG&E Corporation's approximate operating margin declined to 13.5% from 17.8%; net margin declined to 5.6% from 7.5%.
- PG&E Corporation ended the quarter with $240 million of cash and cash equivalents; the Utility held $52 million. Restricted cash was $431 million, including $384 million held in escrow for remaining Chapter 11 disputed claims.
- PG&E Corporation reported short-term borrowings of $1,288 million, current long-term debt of $922 million, and noncurrent long-term debt of $10,294 million. Energy recovery bonds totaled $730 million, including current and noncurrent portions.
- The Utility had $1.0 billion of commercial paper outstanding at an average yield of 0.39%, no cash borrowings under its $1.9 billion and $750 million revolving credit facilities, and $315 million of letters of credit outstanding. Total reported credit-facility availability was $1,543 million.
- PG&E Corporation declared dividends of $0.455 per share, or $181 million, and paid $174 million of common dividends during the quarter.
Material changes versus the prior comparable period
- Net income and diluted EPS fell primarily because of $31 million after-tax of natural-gas-pipeline costs, a $27 million after-tax unfavorable effect from delayed rate-case decisions, and $18 million after-tax of higher storm and outage costs.
- Q1 2010 included $25 million of PG&E Corporation spending related to a statewide ballot initiative and a $20 million Utility charge related to the elimination of Medicare Part D subsidy tax deductibility; neither negatively affected Q1 2011 to the same extent.
- Operating cash flow improved substantially, primarily because net collateral paid in connection with commodity-risk management activities decreased by $321 million and working-capital movements were favorable.
- Capital expenditures increased, while financing cash flow changed from $184 million provided in Q1 2010 to $256 million used in Q1 2011, reflecting a $500 million long-term debt maturity, energy recovery bond maturities, dividends, and other financing activity.
- PG&E Corporation issued 2.0 million common shares for $82 million and contributed $65 million of equity to the Utility to maintain the CPUC-authorized 52% common-equity ratio.
Guidance, outlook, commentary, risks, and unusual items
- Management estimated incremental 2011 natural-gas-transmission costs of $350 million to $550 million, increased from the prior $200 million to $300 million estimate. Recovery through rates and the timing of recovery remain uncertain.
- The Utility estimated potential total third-party San Bruno claims of up to $400 million, with $198 million accrued at March 31, 2011. No insurance recovery was recorded, although the Utility maintained approximately $992 million of liability coverage above a $10 million deductible.
- The CPUC and NTSB continued investigations of the September 2010 San Bruno pipeline rupture, pipeline recordkeeping, and the 2008 Rancho Cordova accident. Potential penalties could be material; CPUC penalties may be up to $20,000 per day per violation.
- The Utility had $855 million of net remaining Chapter 11 disputed claims liabilities at March 31, 2011. Final claims, interest, refunds, offsets, and settlement timing remain uncertain.
- The Utility's environmental remediation liability was $627 million, with potential undiscounted future costs estimated to reach $1.2 billion if contamination or remediation requirements are greater than anticipated.
- The Utility had approximately $68.8 billion of undiscounted future power-purchase agreement payments, $3.0 billion of natural gas supply, transportation, and storage commitments, and $1.7 billion of nuclear fuel commitments.
- Regulatory outcomes remained important. The 2011 General Rate Case proposed decisions contemplated a 2011 revenue-requirement increase of $448 million or $454 million, but the final decision was pending at quarter-end. A subsequent April 14, 2011 decision authorized $514 million of 2011 gas transmission and storage revenue requirements.
- The SmartMeter program had installed 7.8 million meters and incurred $2.1 billion of costs against a $2.3 billion CPUC-authorized cost cap. A $36 million provision had been recorded for forecast costs expected to exceed the cap.
- New California legislation increased the renewable portfolio standard to 33% of retail sales by 2020. Implementation requirements and potential cost recovery were not yet clear.
- Following the earthquake and tsunami in Japan, the Utility requested that the NRC delay action on Diablo Canyon license renewal pending additional seismic studies. New nuclear safety requirements, license-renewal outcomes, or an eventual shutdown could materially affect costs and operations.
- The filing provides no consolidated earnings-per-share or revenue guidance beyond the operational cost and regulatory estimates described above.
Most important facts for investors to verify
- Progress and ultimate findings of the NTSB and CPUC San Bruno and Rancho Cordova investigations, including potential penalties and recoverability of safety-related expenditures.
- Actual 2011 pipeline-safety spending versus the $350 million to $550 million estimate and the portion ultimately recoverable through rates or insurance.
- Settlement and interest requirements for the $855 million net Chapter 11 disputed-claims liability.
- Final outcomes of the 2011 General Rate Case, gas transmission and storage proceedings, and related retroactive revenue adjustments.
- Potential excess costs under the SmartMeter program and the status of the $2.3 billion cost cap.
- Diablo Canyon seismic-review, license-renewal, cooling-water, and nuclear-regulatory developments.
- Environmental remediation exposure beyond the $627 million accrued liability and the extent of recovery through rates, insurance, or third parties.
- Liquidity needs arising from capital expenditures, commercial paper reliance, debt maturities, San Bruno payments, and expected future PG&E Corporation equity contributions to the Utility.