PG&E Corp quarterly report, Q2 FY2011

Business Context and Reporting Period

PG&E Corporation is a holding company operating principally through Pacific Gas and Electric Company, a regulated electric and natural gas utility serving northern and central California. The combined unaudited Form 10-Q covers the three and six months ended June 30, 2011, with comparisons to 2010. The filing was dated August 4, 2011.

Financial Performance and Position

PG&E Corporation consolidated	Q2 2011	Q2 2010	Six months 2011	Six months 2010
Operating revenues	$3,684 million	$3,232 million	$7,281 million	$6,707 million
Operating income	$692 million	$695 million	$1,176 million	$1,313 million
Net income	$366 million	$337 million	$568 million	$598 million
Income available to common shareholders	$362 million	$333 million	$561 million	$591 million
Diluted EPS	$0.91	$0.86	$1.41	$1.54

Q2 revenue increased 14%; six-month revenue increased 9%. Revenue growth primarily reflected higher CPUC-authorized base revenues and higher pass-through revenues.
Q2 operating margin was approximately 18.8%, compared with 21.5% in the prior-year quarter. Six-month operating margin was approximately 16.2%, compared with 19.6% in 2010.
Q2 income available to common shareholders increased 9%, while six-month income declined 5%. The six-month decline reflected higher pipeline, outage, storm, environmental, legal, and regulatory costs, partly offset by rate-base growth, rate-case recovery, lower taxes, and the absence of 2010 ballot-initiative costs.
Q2 and six-month dividends declared were $0.46 and $0.91 per common share, respectively.

Cash Flow, Liquidity, and Capital Structure

PG&E Corporation generated $1,905 million of operating cash flow during the first six months, compared with $1,373 million in 2010. Capital expenditures were $1,897 million, producing limited cash coverage before financing and other investing activity.
Cash and cash equivalents were $350 million at June 30, 2011, compared with $291 million at December 31, 2010. Restricted cash was $367 million, including amounts associated with energy recovery bonds and Chapter 11 disputed claims.
PG&E Corporation had $11,466 million of long-term debt, $1,210 million of short-term borrowings, and $12,041 million of total equity at June 30, 2011. The Utility had $11,117 million of long-term debt and $1,135 million of short-term borrowings.
New five-year revolving facilities were established in May 2011: $300 million for PG&E Corporation and $3.0 billion for the Utility. Total reported availability was $2,036 million after letters of credit, cash borrowings, and commercial paper backup. Both companies were in compliance with covenants, including a maximum 65% debt-to-capitalization ratio.
The Utility issued $300 million of 4.25% senior notes due 2021 and received $255 million of equity contributions from PG&E Corporation. PG&E Corporation issued common stock for $103 million under its equity distribution program and received additional proceeds from employee and plan-related issuances.
The Utility’s first-half operating cash flow was $1,934 million and capital expenditures were $1,897 million. Its cash balance increased to $110 million from $51 million at year-end 2010.

Material Changes Versus the Prior Comparable Period

Utility operating revenue increased 14% in Q2 and 9% for the first half. Excluding pass-through costs, electric revenue increased $266 million in Q2 and $346 million for the first half; natural gas revenue excluding pass-through costs increased $38 million and $28 million, respectively.
Operating and maintenance expense increased 28% in Q2 and 26% for the first half, driven by pipeline activities, San Bruno claims, Diablo Canyon refueling, storms, environmental remediation, pensions, and other maintenance costs.
Depreciation, amortization, and decommissioning expense increased 26% in Q2 and 18% for the first half, primarily due to higher authorized capital additions and depreciation rates.
The effective tax rate declined to 34% from 37% in Q2 and to 36% from 39% for the first half, partly because 2010 included non-deductible ballot-initiative expenses and a Medicare Part D-related deferred tax adjustment.
The Utility’s net disputed claims liability declined to $835 million from $934 million at December 31, 2010 after supplier settlements, despite accrued interest.

Guidance, Outlook, Risks, and Unusual Items

Management estimated 2011 natural-gas-pipeline-system costs of $350 million to $550 million, of which $126 million had been incurred through June 30. Recoverability through rates and insurance remained uncertain.
The San Bruno accident generated approximately 90 lawsuits involving about 320 plaintiffs. The Utility had accrued $279 million for third-party claims, paid $68 million, and estimated up to $121 million of additional claims, for a possible total loss of $400 million. A $60 million insurance receivable was recognized, but the timing and amount of further recoveries were uncertain.
The CPUC’s independent review panel concluded that the San Bruno explosion resulted from multiple weaknesses in management and oversight of the gas transmission system. The NTSB, CPUC, and criminal investigations remained unresolved.
The Utility had accrued approximately $26 million for a proposed Rancho Cordova penalty, subject to CPUC approval. Potential CPUC penalties related to pipeline recordkeeping could be as high as $20,000 per day per violation, but no loss estimate was available.
Environmental remediation liabilities were $677 million at June 30, 2011, with potential undiscounted future costs as high as $1.3 billion. Expected customer recovery was subject to applicable ratemaking approvals.
Authorized 2011 revenue requirements increased by approximately $450 million, or 8.1%, to approximately $6.0 billion under the CPUC general rate case. Additional attrition increases of $180 million for 2012 and $185 million for 2013 were authorized. The gas transmission and storage revenue requirement was set at $514 million for 2011, with increases authorized through 2014.
The Utility expected future revenue growth from rate-case decisions, but results remained exposed to regulatory approvals, cost recovery decisions, capital spending, energy prices, customer demand, and financing conditions.
The SmartMeter program had installed 8.2 million of approximately 10 million meters and incurred $2.1 billion against a $2.3 billion authorized cost estimate. A $36 million provision was recorded for forecast costs above the current authorized cap.
Diablo Canyon license renewal and seismic studies remained subject to NRC review. Potential new nuclear safety, cooling-water, seismic, or environmental requirements could require significant expenditures or affect continued operations.
The Utility had undiscounted future power-purchase commitments of $68.2 billion, natural gas supply and transportation commitments of $2.9 billion, and nuclear fuel commitments of $1.7 billion at June 30, 2011.

Investor Verification Checklist

Verify the ultimate cost, insurance recovery, penalties, and rate recovery associated with the San Bruno accident and broader gas-pipeline safety program.
Monitor NTSB, CPUC, Department of Justice, and other proceedings for findings, fines, required capital spending, and possible shareholder cost allocation.
Reconcile operating cash flow with capital expenditures, debt maturities, commercial paper usage, and required equity contributions.
Assess whether regulatory assets, balancing accounts, SmartMeter costs, environmental liabilities, and disputed claims remain recoverable or refundable under future decisions.
Track Diablo Canyon seismic and license-renewal developments, including potential NRC requirements and cooling-water compliance costs.
Evaluate the effect of renewable portfolio standards, environmental rules, energy prices, weather, outages, and customer demand on future margins and liquidity.