PG&E Corp quarterly report, Q2 FY2009

Business Context and Reporting Period

PG&E Corporation is a holding company whose principal operating subsidiary is Pacific Gas and Electric Company, a regulated electric and natural gas utility serving northern and central California. The combined Form 10-Q covers the quarter and six months ended June 30, 2009, with comparative periods ended June 30, 2008. The financial statements are unaudited and prepared under interim GAAP.

The Utility served approximately 5.1 million electric distribution customers and 4.3 million natural gas distribution customers.
Operations are regulated primarily by the California Public Utilities Commission and the Federal Energy Regulatory Commission.

Financial Performance and Position

PG&E Corporation metric	Three months ended June 30	Six months ended June 30
Total operating revenues	$3.194 billion, versus $3.578 billion	$6.625 billion, versus $7.311 billion
Operating income	$656 million, versus $584 million	$1.169 billion, versus $1.077 billion
Net income	$392 million, versus $297 million	$636 million, versus $524 million
Income available to common shareholders	$388 million, versus $293 million	$629 million, versus $517 million
Diluted EPS	$1.02, versus $0.80	$1.67, versus $1.42
Dividends declared per share	$0.42, versus $0.39	$0.84, versus $0.78

Six-month operating revenue declined 9.4%, primarily reflecting lower natural gas and electricity procurement costs passed through to customers. Operating income increased 8.5%, and net income increased 21.4%.
Approximate consolidated operating margin improved to 17.6% from 14.7% for the six-month periods. Net margin improved to approximately 9.6% from 7.2%.
Electric revenue declined 3% for both the quarter and six months, while natural gas revenue declined 31% for the quarter and 24% for the six months. Lower commodity prices and reduced purchased-power volumes were the principal drivers.
Operating and maintenance expense increased 3% for the six months, including higher wage and benefit costs, natural gas leak surveys, uncollectible accounts, environmental costs, severance, and CAISO collateral-related costs.
The $56 million after-tax benefit from an IRS settlement materially contributed to 2009 earnings. Other favorable items included higher authorized returns on capital investment, $28 million of hydroelectric cost recovery income, and lower storm and outage costs than in 2008.

Cash Flow, Capital Spending, Liquidity, and Debt

PG&E Corporation generated $1.754 billion of operating cash flow in the first six months, down from $2.248 billion. The Utility generated $1.650 billion, down from $2.274 billion, primarily because of a $944 million increase in net collateral paid for commodity risk management.
Capital expenditures were $2.077 billion, compared with $1.712 billion in the prior-year period, producing negative investing cash flow of $2.081 billion for PG&E Corporation and $2.088 billion for the Utility.
PG&E Corporation ended June 30 with $338 million of cash and cash equivalents. The Utility held $158 million, plus $1.285 billion of restricted cash.
PG&E Corporation reported total debt of approximately $10.9 billion, including $9.933 billion of long-term debt, $252 million of current long-term debt, $743 million of short-term borrowings, and $1.409 billion of energy recovery bonds.
The Utility reported $9.585 billion of long-term debt, $743 million of short-term borrowings, $243 million of commercial paper, and $1.409 billion of energy recovery bonds. Its $1.94 billion revolving facility had $303 million of letters of credit outstanding and $1.394 billion of stated availability.
PG&E Corporation had $187 million of revolving-credit availability. Both registrants were in compliance with debt covenants, including the maximum 65% debt-to-capitalization ratio.
During the period, PG&E Corporation issued $350 million of 5.75% senior notes, the Utility issued $550 million of 6.25% senior notes and $500 million of floating-rate notes due June 10, 2010, and PG&E Corporation contributed $653 million of equity to the Utility.
The Utility’s earnings-to-fixed-charges ratio was 3.15; the combined fixed-charges-and-preferred-dividends ratio was 3.09. PG&E Corporation’s ratio was 2.96.

Material Changes Versus the Prior Comparable Period

Profitability improved despite lower revenue because procurement costs fell faster than revenue, reflecting lower electricity and natural gas prices and lower purchased-power volumes.
Purchased-power volume fell 14% for the six months, while the average cost of purchased power declined 8%. Natural gas cost declined 41%.
Cash generation weakened because of increased collateral requirements and higher capital spending, although financing activities provided $446 million of cash compared with a $560 million use in 2008.
Net property, plant, and equipment increased to $27.599 billion from $26.261 billion, while total assets increased to $42.197 billion from $40.860 billion.
The asset-retirement obligation declined to $1.539 billion from $1.684 billion after revised estimated cash flows, while pension and other postretirement liabilities increased.
The adoption of SFAS 160 changed noncontrolling-interest presentation; other accounting pronouncements adopted during the period did not materially affect reported results.

Guidance, Outlook, Commentary, Risks, and Unusual Items

Management stated that operating cash flow, existing liquidity, and future financings should fund operations, obligations, and capital expenditures assuming continued reasonable access to capital markets.
The Utility planned to file a 2011–2013 general rate case by December 1, 2009. Its draft application contemplated approximately $2.7 billion of annual capital expenditures and a requested 2011 revenue increase of $1.069 billion, or 6.5%; these amounts were requests, not approved guidance.
The Utility expected approximately $100 million of 2009 spending for accelerated natural gas leak surveys and related remedial work, with the accelerated work targeted for completion by the second quarter of 2010.
SmartMeter spending totaled approximately $1.01 billion through June 30, 2009, including $854 million of capital costs. The CPUC had authorized additional funding of $466.8 million for upgrades, but cost recovery remained subject to project execution and regulatory conditions.
Remaining Chapter 11 disputed claims totaled $1.752 billion, including $1.552 billion of claims and $694 million of accrued interest, offset by $494 million of receivables. The Utility held $1.214 billion in escrow and expected to transfer $700 million to the California Power Exchange after required approvals became final. Final liability and refund amounts remained uncertain.
Environmental remediation liability was $594 million, with potential undiscounted costs estimated as high as $1 billion if third parties cannot contribute or contamination is greater than expected. The Hinkley liability was not recoverable from customers.
Future EPA and California requirements concerning once-through cooling could require significant capital spending at Diablo Canyon. If cooling towers were required and were not technically or economically feasible, Diablo Canyon operations could potentially be affected.
The Utility had approximately $31.1 billion of undiscounted future power-purchase obligations, $1.188 billion of natural gas purchase and transportation obligations, and $1.739 billion of nuclear-fuel obligations.
The Utility faced additional collateral exposure of approximately $458 million if credit-related provisions in derivative contracts were triggered. Commodity derivative costs and most realized gains or losses were generally recoverable from or passed through to customers under regulatory mechanisms.
The report identifies regulatory outcomes, capital-market access, energy prices, collateral requirements, aging infrastructure, nuclear operations, environmental remediation, climate change, customer demand, litigation, tax audits, and cybersecurity or operational disruptions as material risks.
Management evaluated subsequent events through August 5, 2009. Disclosure controls were considered effective, and no material changes to internal control over financial reporting were reported.

Facts an Investor Should Verify

Whether the IRS settlement benefits, hydroelectric cost recovery, and other favorable items are nonrecurring and how normalized earnings compare with reported EPS.
The timing and final terms of the 2011–2013 general rate case, the requested revenue increases, and recovery of planned infrastructure and safety spending.
The final resolution and cash requirements for the $1.752 billion of disputed Chapter 11 claims, including the proposed $700 million transfer and related interest.
Whether commodity collateral requirements continue to constrain operating cash flow and whether the Utility can maintain adequate liquidity as the $500 million floating-rate notes mature in 2010.
Actual SmartMeter, natural gas leak remediation, environmental, pension, and Diablo Canyon compliance costs versus amounts recoverable through rates.
The outcome of energy-efficiency incentive proceedings, the DOE spent-nuclear-fuel reimbursement claim, transmission-rate proceedings, and other regulatory matters.
Changes in nuclear decommissioning, pension funding, environmental liabilities, and regulatory assets, which depend substantially on future regulatory decisions and estimates.