Revolving Credit Facilities
The following table summarizes PG&E Corporation’s and the Utility’s revolving credit facilities at September 30, 2011:
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(in millions)
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Termination
Date
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Facility Limit
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Letters of
Credit
Outstanding
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Borrowings
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Commercial
Paper
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Availability
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PG&E Corporation
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May 2016
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$ 300
(1)
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$ -
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$ 75
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$ -
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$ 225
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Utility
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May 2016
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3,000
(2)
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335
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-
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801
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1,864
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Total revolving credit facilities
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$ 3,300
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$ 335
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$ 75
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$ 801
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$ 2,089
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(1)
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Includes a $100 million sublimit for letters of credit and a $100 million commitment for “swingline” loans, defined as loans that are made
available on a same-day basis and are repayable in full within 7 days.
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(2)
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Includes a $1.0 billion sublimit for letters of credit and a $300 million commitment for swingline loans.
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For the nine months ended September 30, 2011, the average outstanding commercial paper balance was $777 million and the maximum
outstanding balance during the period was $1.2 billion; the average outstanding borrowings on PG&E Corporation’s revolving credit facility was $47 million and the maximum outstanding balance during the period was $75 million; and the
average outstanding borrowings on the Utility’s revolving credit facility was $2 million and the maximum outstanding balance during the period was $208 million.
48
On May 31, 2011, PG&E Corporation entered into a $300 million revolving credit
facility with a syndicate of lenders. This revolving credit facility replaced the $187 million revolving credit facility that PG&E Corporation entered into on February 26, 2007 (amended April 27, 2009). Also on May 31, 2011, the
Utility entered into a $3.0 billion revolving credit facility with a syndicate of lenders. This revolving credit facility replaced the $1.9 billion revolving credit facility that the Utility entered into on February 26, 2007 (amended
April 27, 2009), and the $750 million revolving credit facility that the Utility entered into on June 8, 2010. The revolving credit facilities have terms of five years and all amounts are due and payable on the facilities’ termination
date, May 31, 2016. At PG&E Corporation’s and the Utility’s request and at the sole discretion of each lender, the facilities may be extended for additional periods. The revolving credit facilities may be used for working capital
and other corporate purposes, including commercial paper back-up.
Provided certain conditions are met, PG&E Corporation
and the Utility have the right to increase, in one or more requests, given not more frequently than once a year, the aggregate lenders’ commitments under the revolving credit facilities by up to $100 million and $500 million, respectively, in
the aggregate for all such increases.
Borrowings under the revolving credit facilities (other than swingline loans) will bear
interest based, at PG&E Corporation’s and the Utility’s election, on (1) a London Interbank Offered Rate (“LIBOR”) plus an applicable margin or (2) the base rate plus an applicable margin. The base rate will equal
the higher of the following: the administrative agent’s announced base rate, 0.5% above the federal funds rate, or the one-month LIBOR plus an applicable margin. Interest is payable quarterly in arrears, or earlier for loans with shorter
interest periods. PG&E Corporation and the Utility also will pay a facility fee on the total commitments of the lenders under the revolving credit facilities. The applicable margins and the facility fees will be based on PG&E
Corporation’s and the Utility’s senior unsecured debt ratings issued by Standard & Poor’s Rating Services and Moody’s Investor Service. Facility fees are payable quarterly in arrears.
The revolving credit facilities include usual and customary covenants for revolving credit facilities of this type, including covenants
limiting liens to those permitted under PG&E Corporation’s and the Utility’s senior note indentures, mergers, sales of all or substantially all of PG&E Corporation’s and the Utility’s assets, and other fundamental
changes. In addition, the revolving credit facilities require that PG&E Corporation and the Utility maintain a ratio of total consolidated debt to total consolidated capitalization of at most 65% as of the end of each fiscal quarter. The $300
million revolving credit facility agreement also requires that PG&E Corporation must own, directly or indirectly, at least 80% of the common stock and at least 70% of the voting capital stock of the Utility. At September 30, 2011, PG&E
Corporation and the Utility were in compliance with all covenants under each of the revolving credit facilities.
2011 Financings
Utility
On May 13, 2011, the Utility issued $300 million principal amount of 4.25% Senior Notes due May 15, 2021. The proceeds from this issuance were used to repay a portion of outstanding commercial
paper.
On September 12, 2011, the Utility issued $250 million principal amount of 3.25% Senior Notes due
September 15, 2021. The proceeds from this issuance were used to redeem $200 million principal amount of Series 1996 A pollution control bonds and to repay a portion of outstanding commercial paper.
During the nine months ended September 30, 2011, the Utility received cash contributions of $350 million from PG&E Corporation
to ensure that the Utility had adequate capital to maintain the 52% common equity ratio authorized by the CPUC.
49
PG&E Corporation
On May 9, 2011, PG&E Corporation entered into an Equity Distribution Agreement pursuant to which PG&E Corporation’s sales agents may offer and sell, from time to time, PG&E
Corporation common stock having an aggregate gross offering price of up to $288 million. This amount represents the approximate unissued amount of the $400 million program previously announced on November 4, 2010. Sales of the shares are made
by means of ordinary brokers’ transactions on the New York Stock Exchange, or in such other transactions as agreed upon by PG&E Corporation and the sales agents and in conformance with applicable securities laws. For the nine months ended
September 30, 2011, PG&E Corporation issued 4,388,034 shares of common stock under the Equity Distribution Agreement for cash proceeds of $185 million, net of fees and commissions paid of $2 million. The proceeds from these issuances were
used for general corporate purposes.
In addition, during the nine months ended September 30, 2011, PG&E Corporation
issued 5,332,780 shares of common stock under its 401(k) plan, its Dividend Reinvestment and Stock Purchase Plan, and upon the exercise of employee stock options, generating $206 million of cash.
Future Financing Needs
As the Utility incurs costs associated with the matters discussed below under “Natural Gas Pipeline Matters,” the
Utility’s debt financing and equity needs are expected to increase significantly. The following factors, among others, also will affect the amount and timing of the Utility’s future debt financings and equity needs:
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the amount of cash internally generated through normal business operations;
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•
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the timing and amount of forecasted capital expenditures authorized by the CPUC;
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•
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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);
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•
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the amount of future tax payments (see the discussion of the Tax Relief Act under “Utility – Operating Activities” below); and
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•
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the conditions in the capital markets, and other factors.
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PG&E Corporation contributes equity to the Utility as needed to maintain the Utility’s CPUC-authorized capital structure. PG&E Corporation has issued equity of $391 million during the nine
months ended September 30, 2011 and forecasts that it may need to issue additional equity of approximately $600 million through the end of 2012, including equity issued through the 401(k) plan and the Dividend Reinvestment and Stock Purchase
Plan. Among other assumptions, this forecast assumes that the CPUC timely approves the Utility’s pipeline safety enhancement plan, cost allocation, and ratemaking proposals described below under “Natural Gas Pipeline Matters,” and
excludes the impact of any fines, penalties, or punitive damages that may be imposed on the Utility in connection with the matters discussed below under “Natural Gas Pipeline Matters.” Changes in these assumptions could cause equity needs
to increase.
The Utility’s current authorized capital structure will remain in effect through 2012. The Utility is
required to file an application with the CPUC in April 2012 to begin the cost of capital proceeding in which the CPUC will determine the Utility’s authorized capital structure and rates of return beginning on January 1, 2013. A change in
the Utility’s authorized capital structure also may impact PG&E Corporation’s and the Utility’s future debt and equity financing needs.
Dividends
The following table summarizes PG&E Corporation’s and
the Utility’s dividends paid during the nine months ended September 30, 2011:
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(in millions)
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PG&E Corporation
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Common stock dividends paid
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$
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525
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Utility
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Common stock dividends paid
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$
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537
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Preferred stock dividends paid
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10
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50
On September 21, 2011, the Board of Directors of the Utility declared a dividend on its
outstanding series of preferred stock, payable on November 15, 2011, to shareholders of record on October 31, 2011.
On September 21, 2011, the Board of Directors of PG&E Corporation declared dividends of $0.455 per share, totaling $184 million,
of which $179 million was paid on October 15, 2011 to shareholders of record on October 3, 2011. The remaining $6 million was reinvested under the Dividend Reinvestment and Stock Purchase Plan.
As the Utility focuses on improving the safety and reliability of its natural gas and electric operations, and subject to the outcome of
the matters described under “Natural Gas Pipeline Matters” above, PG&E Corporation expects that its Board of Directors will maintain the current annual common stock dividend of $1.82 per share.
Utility
Operating Activities
The Utility’s cash flows from operating activities primarily consist of receipts from customers less payments of
operating expenses, other than expenses such as depreciation that do not require the use of cash.
The Utility’s cash
flows from operating activities for the nine months ended September 30, 2011 and 2010 were as follows:
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Nine months ended
September 30,
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(in millions)
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2011
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2010
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Net income
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$ 756
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$ 868
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Adjustments to reconcile net income to net cash provided by operating activities:
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Depreciation, amortization, and decommissioning
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1,648
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1,419
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Allowance for equity funds used during construction
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(64)
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(89)
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Deferred income taxes and tax credits, net
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564
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332
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Other
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193
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175
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Effect of changes in operating assets and liabilities:
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Accounts receivable
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(125)
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(240)
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Inventories
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(60)
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(65)
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Accounts payable
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97
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15
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Income taxes receivable/payable
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(156)
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241
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Other current assets and liabilities
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(153)
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(33)
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Regulatory assets, liabilities, and balancing accounts, net
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70
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(32)
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Other noncurrent assets and liabilities
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491
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(240)
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Net cash provided by operating activities
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$ 3,261
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$ 2,351
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In the nine months ended September 30, 2011, net cash provided by operating activities increased by
$910 million compared to the same period in 2010 primarily due to a decrease of $398 million in net collateral paid by the Utility related to price risk management activities. Collateral payables and receivables are included in other noncurrent
assets and liabilities and other current assets and liabilities within the Condensed Consolidated Statements of Cash Flows. The increase also reflects a decrease in tax payments of $93 million in 2011 compared to 2010. The remaining changes in cash
flows from operating activities consisted of fluctuations in activities within the normal course of business such as the timing and amount of customer billings and collections.
On December 17, 2010, the Tax Relief Act was signed into law, which generally allows the Utility to accelerate depreciation by
deducting up to 100% of the investment cost of certain qualified property placed into service during 2011 (or as late as 2012 under “phase out” or transition rules) and up to 50% of the investment cost of property placed into service in
2012 (or as late as 2013 under the phase out rules). As a result of the accelerated depreciation, the Utility expects that it will not make a federal tax payment in 2011. The Utility also expects that its 2012 federal tax payment will be reduced
depending on the amount and timing of the Utility’s qualifying capital additions. (See “Regulatory Matters – CPUC Resolution Regarding the Tax Relief Act” below.)
Future cash flow from operating activities will be affected by the timing and amount of payments to be made to third parties in
connection with the San Bruno accident, related insurance recoveries, any penalties that may be assessed, and higher operating and maintenance costs associated with the Utility’s natural gas and electric operations. (See “Operating and
Maintenance” above and “Natural Gas Pipeline Matters” below.)
51
Investing Activities
The Utility’s investing activities consist of construction of new and replacement facilities necessary to deliver safe and reliable electricity and natural gas services to its customers. Cash used in
investing activities depends primarily upon the amount and timing of the Utility’s capital expenditures, which can be affected by many factors, including the timing of regulatory approvals and 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 facilities.
The Utility’s cash flows from investing activities for the nine months ended September 30, 2011 and 2010 were as follows:
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Nine months ended
September 30,
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(in millions)
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2011
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2010
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Capital expenditures
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$ (2,968)
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$ (2,794)
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Decrease in restricted cash
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170
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61
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Proceeds from sales and maturities of nuclear decommissioning trust investments
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1,574
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962
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Purchases of nuclear decommissioning trust investments
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(1,604)
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(1,001)
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Other
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13
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15
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Net cash used in investing activities
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$ (2,815)
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$ (2,757)
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Net cash used in investing activities increased by $58 million in the nine months ended
September 30, 2011 compared to the same period in 2010. This increase was primarily due an increase of $174 million in capital expenditures. This increase was partially offset by a decrease of $109 million in restricted cash that was primarily
due to releases from escrow for settled or withdrawn Chapter 11 disputed claims in the nine months ended September 30, 2011, with few similar releases in 2010.
Future cash flows used in investing activities are largely dependent on the timing and amount of capital expenditures. (See “Capital Expenditures” below for further discussion of expected
spending and significant capital projects.)
Financing Activities
The Utility’s cash flows from financing activities for the nine months ended September 30, 2011 and 2010 were as follows:
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Nine months ended September 30,
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(in millions)
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2011
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2010
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Borrowings under revolving credit facilities
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$ 208
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$ 400
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Repayments under revolving credit facilities
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(208)
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-
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Net issuances of commercial paper, net of discount of $2 in 2011 and 2010
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196
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251
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Proceeds from issuance of long-term debt, net of discount and issuance costs of $6 in 2011 and $12 in
2010
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544
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838
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Short-term debt matured
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-
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(500)
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Long-term debt matured or repurchased
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(700)
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(95)
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Energy recovery bonds matured
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(299)
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(285)
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Preferred stock dividends paid
|
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(10)
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(11)
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Common stock dividends paid
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|
(537)
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(537)
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Equity contribution
|
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350
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170
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Other
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12
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(40)
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Net cash (used in) provided by financing activities
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$ (444)
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$ 191
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In the nine months ended September 30, 2011, net cash used in financing activities increased by $635
million compared to the same period in 2010. 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 and the level of cash
provided by or used
52
in investing activities. The Utility generally utilizes long-term senior unsecured debt issuances and equity contributions from PG&E Corporation to fund debt maturities and capital
expenditures and to maintain its CPUC-authorized capital structure, and relies on short-term debt to fund temporary financing needs.
PG&E Corporation
As of September 30, 2011, PG&E Corporation’s affiliates had entered into four tax equity agreements with two privately held
companies to fund residential and commercial retail solar energy installations. Under these agreements, PG&E Corporation has agreed to provide lease payments and investment contributions of up to $398 million to these companies in exchange for
the right to receive the benefits from local rebates, federal investment tax credits or grants, and a share of the customer payments made to these companies. As of September 30, 2011, PG&E Corporation had made total payments of $326 million
under these tax equity agreements and received $115 million in benefits and customer payments. On April 14, 2011, PG&E Corporation borrowed $75 million under its $187 million revolving credit facility to partially fund the obligations under
the tax equity agreements. On May 31, 2011, this borrowing was repaid and $75 million was borrowed under PG&E Corporation’s new $300 million revolving credit facility. (See Note 4 of the Notes to the Condensed Consolidated Financial
Statements.) Lease payments, investment contributions, benefits, and customer payments received are included in cash flows from operating and investing activities within the Condensed Consolidated Statements of Cash Flows. PG&E
Corporation’s financial exposure for these arrangements is generally limited to its lease payments and investment contributions to these companies.
In addition to the investments above, PG&E Corporation had the following material cash flows on a stand-alone basis for the nine months ended September 30, 2011 and 2010: dividend payments,
common stock issuances, and transactions between PG&E Corporation and the Utility.
CONTRACTUAL COMMITMENTS
PG&E Corporation and the Utility enter into contractual commitments in connection with business activities. These
future obligations primarily 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 the purchase of fuel and transportation to support the Utility’s generation activities. (Refer to the 2010 Annual Report, the “Liquidity and Financial Resources” section above and Notes 4 and 10 of
the Notes to the Condensed Consolidated Financial Statements.)
CAPITAL EXPENDITURES
Most of the Utility’s revenue requirements to recover forecasted capital expenditures are authorized in the GRC, TO rate cases, and
GT&S rate cases. (See “Regulatory Matters” below.)
The Utility also collects additional
revenue requirements to recover capital expenditures related to projects that have been specifically authorized by the CPUC, such as new power plants, gas or electric distribution projects, and the SmartMeter
TM
advanced metering infrastructure. As discussed below, the Utility
could incur additional capital expenditures in the future if it acquires the Oakley Generation facility.
Additionally, as
directed by the CPUC, the Utility filed its proposed natural gas transmission pipeline safety enhancement plan on August 26, 2011 to replace certain natural gas pipeline segments, install automatic or remote shut-off valves, and take other
actions to improve its natural gas pipeline system. Under the first phase of the plan, the Utility forecasts that its total capital expenditures over a four-year period (2011-2014) will be approximately $1.4 billion. The Utility is uncertain whether
and when its proposed plan will be approved by the CPUC and what portion of costs will be recoverable from customers. (See “Natural Gas Pipeline Matters – CPUC Rulemaking Proceeding” below.)
Finally, the Utility expects that it will make additional capital investments over the next 20 years related to the deployment of the
“Smart Grid” in California. As required by California state law enacted in 2009, the Utility filed an application with the CPUC on June 30, 2011 requesting that the CPUC approve the Utility’s Smart Grid deployment plan. The
Utility’s plan defines the Smart Grid as a modernized electric infrastructure which integrates advanced communications and control systems to create a highly automated, responsive, and resilient power delivery system that will both optimize
service and empower customers to make informed energy decisions. If approved by the CPUC, the Utility’s plan will provide policy guidance for future Utility investments in Smart Grid projects and initiatives to be reviewed in future CPUC
proceedings. The Utility’s application does not request approval or funding for specific Smart Grid projects or programs.
Oakley
Generation Facility
53
In December 2010, the CPUC approved a purchase and sale agreement between the Utility and
Contra Costa Generating Station LLC for the development and construction of the Oakley Generation Facility, a 586-megawatt natural gas-fired, combined-cycle generation facility proposed to be located in Oakley, California. After the CPUC denied
various applications for rehearing of its decision, several parties filed appeals with the California Supreme Court and the California Courts of Appeal. These appeals are still pending. Under the CPUC’s decision, if the Utility acquires the
facility before January 1, 2016 the Utility would be unable to recover costs incurred before January 1, 2016 to acquire and operate the facility through rates. Instead, the Utility would have to rely on market revenues received from the
sale of electricity generated by the facility to recover its costs. Costs the Utility incurs after January 1, 2016 would be recoverable through rates. The Utility and the developer are negotiating an amendment to the purchase and sale agreement
to delay the acquisition until January 1, 2016 or later, and to reflect the possibility that the facility may be operated before the Utility acquires the facility. The Utility is uncertain whether and when the proposed amendment will be
executed.
The California Energy Commission (“CEC”) authorized the developer to begin construction of the facility.
Various environmental groups have filed an appeal of the CEC’s decision with the California Supreme Court, which is currently pending.
OFF-BALANCE SHEET ARRANGEMENTS
PG&E Corporation and the Utility do not have any other 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 (PG&E Corporation’s tax equity financing agreements) and Note 10 (the
Utility’s commodity purchase agreements) of the Notes to the Condensed Consolidated Financial Statements.
CONTINGENCIES
In addition to the contingencies described under “Natural Gas Pipeline Matters” below, PG&E Corporation and the Utility have significant contingencies arising from their operations,
including contingencies related to Chapter 11 disputed claims, guarantees, regulatory proceedings, nuclear operations, legal matters, environmental compliance and remediation, and tax matters. (See Notes 9 and 10 of the Notes to the Condensed
Consolidated Financial Statements.)
NATURAL GAS PIPELINE MATTERS
Following the San Bruno accident on September 9, 2010, various regulatory proceedings, investigations, and civil lawsuits were
commenced, as discussed in the 2010 Annual Report. The current status and outcome of these matters as well as new developments are summarized here and described more fully below:
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NTSB Investigation.
On August 30, 2011, the NTSB announced that it had determined the probable cause of the San Bruno accident, placing
most of the blame on the Utility. The NTSB publicly issued its final accident investigation report on September 26, 2011. (See “The NTSB Pipeline Accident Report” below.)
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•
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CPUC’s Independent Review Panel
. On June 8, 2011, the independent review panel appointed by the CPUC issued its report containing the
panel’s findings and recommendations. (See “Report of CPUC’s Independent Review Panel” below.)
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•
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CPUC Investigations Regarding the Utility’s Natural Gas Pipelines
. The CPUC has been investigating the San Bruno accident and other natural
gas transmission matters, including an investigation pertaining to safety recordkeeping for the Utility’s pipeline that ruptured in San Bruno, as well as for its entire gas transmission system. (See “CPUC Investigation Regarding
Utility’s Facilities Records for its Natural Gas Pipelines” below.) These investigations could lead to significant fines and other sanctions being imposed on the Utility.
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•
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CPUC Rulemaking Proceeding.
As directed by the CPUC, on August 26, 2011, the Utility filed its proposed natural gas transmission pipeline
safety and enhancement plan. The Utility also requested that the CPUC approve the Utility’s proposed ratemaking and cost allocation mechanisms. (See “CPUC Rulemaking Proceeding” below.)
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54
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•
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Criminal Investigation
. On June 9, 2011, the Utility received notification that representatives from the U.S. Department of Justice, the
California Attorney General’s Office, and the San Mateo County District Attorney’s Office are conducting an investigation of the San Bruno accident. (See “Criminal Investigation Regarding San Bruno Accident” below.)
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•
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CPUC’s Independent Audit.
The CPUC Consumer Protection and Safety Division (“CPSD”) has engaged an independent auditing firm to
conduct an audit of the Utility’s spending on its natural gas transmission function from 1996 to 2010. The Utility is uncertain when the audit will be completed and what action the CPUC may take in response to the audit results.
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The Utility’s Report Regarding the Class Location Designations for Pipelines
. On June 30, 2011, the Utility submitted a report to the
CPUC containing the results of the Utility’s system-wide review of class location designations for its natural gas transmission pipelines. Under federal and state regulations, the class location designation of a pipeline is used to determine
the pipeline’s maximum allowable operating pressure (“MAOP”) up to which it can be operated. This review of class location designations has indicated that some segments of pipe had an MAOP higher than appropriate for their current
class location designations. The Utility is uncertain whether the CPUC will take action with respect to the foregoing report.
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Pending Lawsuits and Claims
. Various civil lawsuits have been filed by residents of San Bruno in California state courts against PG&E
Corporation and the Utility related to the San Bruno accident. These lawsuits seek compensation for personal injury and property damage and other relief, including punitive damages. (See “Pending Lawsuits and Other Claims” below.)
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Special Review Committees
. The independent special review committees appointed by the Boards of Directors of PG&E Corporation and the
Utility have completed their reviews of the natural gas transmission and distribution practices used in the industry and by the Utility. The committees submitted their reports to the Boards of Directors in August 2011. The outcome of the
committees’ reviews was consistent with the recommendations made in reports from the NTSB and CPUC’s independent review panel.
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CPUC Investigation Regarding Rancho Cordova Accident
. On September 29, 2011, the presiding officer’s decision recommended that the
Utility pay a penalty of $38 million (instead of $26 million as had been originally proposed). (See “CPUC Investigation Regarding Rancho Cordova Accident” below.)
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Natural gas distribution
.
Finally, several natural gas incidents that have recently occurred involve cracking in some of the
Utility’s older natural gas distribution lines that are composed of plastic pipe. The Utility intends to replace over 1,200 miles of its natural gas distribution pipelines that are composed of this plastic pipe. The timing and estimated cost of
replacement has not yet been determined. See Item 1.A. Risk Factors below.
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The resolutions of these
matters, including the amount of any civil or criminal fines or penalties, may have a material impact on PG&E Corporation’s and the Utility’s financial condition, results of operations, and cash flows. (See “Impact on Financial
Condition and Results of Operations” and Part II, Item 1.A., Risk Factors below.)
The NTSB Pipeline Accident Report
On September 26, 2011, the NTSB issued its final investigation report concluding that the probable cause of the San
Bruno accident was as follows:
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The Utility’s inadequate quality assurance and quality control in 1956 during its Line 132 relocation project, which allowed the installation of a
substandard and poorly welded pipe section with a visible seam weld flaw that, over time grew to a critical size, causing the pipeline to rupture during a pressure increase stemming from poorly planned electrical work at the Milpitas Terminal; and
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The Utility’s inadequate pipeline integrity management program, which failed to detect and repair or remove the defective pipe section.
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The NTSB also noted that state and federal exemptions of older pipelines from regulatory requirements to
pressure test the pipelines contributed to the accident because pressure tests likely would have detected the installation defects. The NTSB also found that contributing factors were the lack of either automatic shutoff valves or remote control
valves on the line and the Utility’s flawed emergency response procedures and delay in isolating the rupture to stop the flow of gas. The NTSB stated that several deficiencies revealed by its investigation of the San Bruno accident, such as
“poor quality control during the pipe installation and inadequate emergency response,” were also contributing factors in the Rancho Cordova accident.
Among other recommendations, the NTSB recommended that the Utility establish a comprehensive emergency response procedure for responding to large-scale emergencies on transmission lines; equip its
supervisory control and data acquisition system with tools to assist in recognizing and pinpointing the location of leaks, including line breaks; expedite the
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installation of automatic shutoff valves and remote control valves on transmission lines in certain areas; revise its post-accident toxicological testing program to ensure that testing is timely
and complete; assess every aspect of its pipeline integrity management program and implement a revised program; conduct threat assessments using the revised risk analysis methodology incorporated into the revised integrity management program, and
report the results of those assessments to the CPUC and the federal Pipeline and Hazardous Materials Safety Administration (“PHMSA”).
The NTSB recommended that the CPUC conduct a comprehensive audit of all aspects of the Utility’s operations and require the Utility to correct all deficiencies identified as a result of the
NTSB’s investigation, as well as any additional deficiencies identified through the CPUC’s comprehensive audit, and verify that all corrective actions are completed.
The NTSB also recommended that, with respect to natural gas transmission pipelines nationwide, PHMSA amend its regulations to directly require the installation of automatic shutoff valves or remote
control valves in certain areas, delete the regulatory exemption from hydrostatic pressure-testing requirements for pre-1970 pipelines, and require that all natural gas transmission pipelines be configured so as to accommodate in-line inspection
tools, with priority given to older pipelines.
The Utility is required to submit a report to the NTSB in December 2011 that
addresses the actions taken or intended to be taken by the Utility to implement the NTSB’s recommendations.
Report of CPUC’s
Independent Review Panel
On June 8, 2011, the CPUC’s independent review panel issued its report concluding that
“the explosion of the pipeline at San Bruno was a consequence of multiple weaknesses in PG&E Corporation’s and the Utility’s management and oversight of the safety of its gas transmission system.” Among other findings, the
panel found that the Utility’s pipeline integrity management program had several shortcomings and issued 18 formal recommendations.
The Utility filed comments on the panel’s report stating that the Utility agreed with the panel’s overall conclusions and in principle with its recommendations. Other parties filed comments to
the panel’s report, including a suggestion that the deficiencies identified by the panel in the Utility’s management of its gas transmission system may also apply to its gas distribution system, and urged the CPUC to review the
Utility’s gas distribution system as soon as possible.
The independent review panel report also contained findings and
recommendations about the structure, culture, and resources of the CPUC. In response to recommendations to provide the CPSD staff with additional enforcement tools, on September 30, 2011, the CPUC released a draft resolution that
would delegate authority to the CPSD staff (and other staff as may be directed by the CPUC’s Executive Director) to levy citations and impose fines to enforce compliance with certain state and federal regulations related to the safety of
natural gas facilities and utilities’ natural gas operating practices. The proposed resolution states that any citation issued by the staff must assess the maximum penalty that could be imposed by the CPUC under state law. Under current
state law, the maximum penalty that the CPUC could impose is $20,000 per day, per violation. In October 2011, the California Governor signed legislation that will increase the maximum penalty to $50,000 per day, per violation, effective
January 1, 2012. The proposed resolution is scheduled to be considered by the CPUC on November 10, 2011.
PG&E Corporation and the Utility are uncertain how the CPUC will use the independent review panel’s and the NTSB’s findings
and recommendations concerning the Utility’s operations or whether the CPUC will commence additional investigations or proceedings.
CPUC Investigation Regarding Rancho Cordova Accident
On September 29, 2011, a CPUC administrative law judge (“ALJ”) denied a request to approve stipulations previously submitted by the Utility, the CPSD, and The Utility Reform Network
(“TURN”), to resolve the CPUC’s investigation of the Rancho Cordova accident including the proposed payment of a $26 million penalty by the Utility. Instead, the ALJ recommended that the Utility pay a penalty of $38 million based on
the ALJ’s determination that (1) CPUC case law warrants a higher penalty when a fatality has occurred and (2) the Utility could be fined as much as $97 million if the case were fully litigated and all allegations were proven.
On October 19, 2011, the Utility, CPSD, and TURN filed a joint motion to accept the increased penalty amount. The
Utility has agreed to pay the CPUC for the costs it incurred in connection with the investigation and that it would not seek to recover the penalty or costs through rates. On October 31, 2011, the ALJ issued a proposed decision extending the
statutory 12-month deadline to conclude the investigation. The proposed decision, to be voted on by the CPUC on November 10, 2011, will give the CPUC time to consider and rule on the joint motion accepting the increased penalty.
As of September 30, 2011, approximately $39 million was accrued for penalties and other costs associated with the
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Rancho Cordova accident in PG&E Corporation’s and the Utility’s Condensed Consolidated Financial Statements.
CPUC Investigation Regarding Utility’s Facilities Records for its Natural Gas Pipelines
On February 24, 2011, the CPUC issued an order instituting a formal investigation pertaining to safety recordkeeping for the Utility’s gas transmission pipeline (Line 132) that ruptured in the
San Bruno accident, as well as for its entire gas transmission system.
The first phase of the CPUC’s investigation has
been limited to (1) whether the Utility’s gas transmission pipeline recordkeeping and its knowledge of its own transmission gas system (and, in particular, the San Bruno pipeline) was deficient and unsafe, and (2) whether the Utility
thereby violated applicable law and safety standards. In particular, this phase will determine, among other matters, whether the San Bruno tragedy would have been preventable by the exercise of safe procedures and/or accurate and effective technical
recordkeeping in compliance with the law. The CPUC will consider whether the Utility’s approach to recordkeeping stems from corporate-level management policies and practices and, if so, whether those management practices and policies
contributed to recordkeeping violations that adversely affected safety.
During the first two quarters of 2011, the Utility
reviewed its records dating back to 1955 and provided extensive information to the CPUC about the regulatory history applicable to gas transmission and recordkeeping practices, the Utility’s recordkeeping policies and practices, actions the
Utility has taken since 1955 to promote safety on its gas transmission pipeline system, and safety risk assessments.
If the
CPUC determines that the Utility violated gas safety recordkeeping requirements, the CPUC will schedule a later phase or phases to determine whether penalties are warranted, and if so the amount of such penalties. If the CPUC determines that the
Utility violated applicable requirements, the CPUC could impose penalties on the Utility of up to $20,000 per day, per violation, or up to $50,000 per day, per violation, for violations occurring on or after January 1, 2012.
PG&E Corporation and the Utility are unable to estimate a possible loss or range of loss associated with any penalties that may be
imposed by the CPUC on the Utility.
Criminal Investigation Regarding San Bruno Accident
On June 9, 2011, the Utility was notified that representatives from the U.S. Department of Justice, the California Attorney
General’s Office, and the San Mateo County District Attorney’s Office are conducting an investigation of the San Bruno accident. The Utility is cooperating with the investigation. The investigation is in the early stages and PG&E
Corporation and the Utility are unable to estimate a possible loss or range of loss associated with any criminal fines or penalties that may be imposed on the Utility.
CPUC Rulemaking Proceeding
As directed by the June 9, 2011 CPUC
order, on August 26, 2011, the Utility filed its proposed natural gas transmission pipeline safety enhancement plan to conduct pressure tests, replace certain natural gas pipeline segments, install automatic or remote shut-off valves, and
perform other activities to improve its natural gas pipeline system. The Utility’s proposed plan contains two phases:
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In the first phase, to be completed over a four-year period (2011 through 2014), the Utility would focus on older pipeline segments in highly populated
areas that have not been pressure tested previously. The Utility plans to replace at least 186 miles of pipeline, conduct pressure testing on 783 miles of pipeline, conduct in-line inspections of 234 miles of pipeline, and retrofit 199 miles of
pipeline to accommodate in-line inspections.
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In the second phase, beginning in 2015, the Utility would focus on pipeline segments that have been previously pressure tested or are in rural areas.
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The Utility has requested that the CPUC approve the proposed scope of activities for both
phases and authorize recovery of certain phase 1 costs in rates, as described below. The Utility proposed to address phase 2 timing and cost recovery in a separate application to change rates beginning on January 1, 2015, consistent with the
GT&S rate case cycle.
The Utility forecasts that its total expenditures over the four-year period of phase 1 will be
approximately $2.2 billion, which includes an estimated $1.4 billion in capital expenditures and $750 million in expenses. The Utility has proposed that plan-related costs incurred after 2011, and certain costs to be incurred from 2012 through 2014,
be recovered through rates. The Utility would recover capital costs in rates only after specific projects have been placed into operation and the actual costs of the projects are known. For non-capital-related expenses, the Utility would recover in
rates its forecast of annual expenses subject to true-up at the end of each year to reflect actual costs incurred by the Utility. Any forecasted amounts that the Utility does not spend by the end of phase 1 would be refunded to ratepayers.
The Utility’s cost estimate and project schedule assumes that the CPUC will issue a proposed decision early in 2012
authorizing the Utility to proceed with phase 1. If there is a significant delay in issuing the CPUC decision or if the CPUC requires material modifications to the plan, the Utility may need to change the scope of work or schedule which could result
in changes to cost estimates. On November 2, 2011, an amended scoping memo was issued that establishes a revised procedural schedule. Under the revised schedule, hearings will begin on March 12, 2012 and conclude on March 23, 2012. The Utility
expects that it will incur costs to perform pipeline-related work within the scope of the proposed plan before the CPUC issues a decision which, in light of the new schedule, may not occur until mid-2012 or later. The Utility has requested that the
CPUC authorize the Utility to track costs incurred under the plan after January 1, 2012 so that the CPUC can consider whether such costs will be recoverable from customers after a final decision on the plan is issued. If the CPUC does not
authorize this request, plan-related costs the Utility incurs before the CPUC issues a final decision on the plan may not be recoverable through rates.
Finally, the CPUC has not yet acted on the proposed stipulation to resolve an order to show cause (“OSC”) that the CPUC issued on March 24, 2011 to require the Utility to show why it should
not be penalized for failing to present evidence that it “aggressively and diligently searched” its pipeline records as previously ordered. On September 12, 2011, the Utility filed its report with the CPUC stating that the Utility had
completed validation of the MAOPs on high-priority pipelines.
Pending Lawsuits and Other Claims
In addition to the investigations and proceedings discussed above, approximately 100 lawsuits involving third-party claims for personal
injury and property damage, including two class action lawsuits, have been filed against PG&E Corporation and the Utility in connection with the San Bruno accident on behalf of approximately 370 plaintiffs. The lawsuits seek compensation for
personal injury and property damage, and other relief, including punitive damages. These cases have been coordinated and assigned to one judge in the San Mateo County Superior Court. On October 6, 2011, the judge overseeing the consolidated San
Bruno civil litigation set a trial date for July 23, 2012 for the first of these cases.
The Utility has recorded a
cumulative provision of $375 million ($220 million in 2010 and $155 million in 2011) for estimated third-party liability claims, and has made payments of $86 million as of September 30, 2011. The Utility estimates it is reasonably possible that
it may incur as much as an additional $225 million for third-party claims, for a total loss of $600 million, increased from the $400 million previously estimated. As more information becomes known, estimates and assumptions regarding the amount of
third-party liability incurred in connection with the San Bruno accident may be subject to further changes. Future changes in estimates may have a material impact on PG&E Corporation’s and the Utility’s financial condition, results of
operations, and cash flows. PG&E Corporation and the Utility are unable to estimate a possible loss or range of loss associated with any punitive damages that may be imposed on the Utility. (See Note 10 to the Condensed Consolidated Financial
Statements.)
The Utility has liability insurance from various insurers who provide coverage at different policy limits that
are triggered in sequential order or “layers.” Generally, as the policy limit for a layer is exhausted the next layer of insurance becomes available. The aggregate amount of this insurance coverage is approximately $992 million in excess
of a $10 million deductible. The Utility submitted insurance claims to certain insurers for the lower layers and recognized $60 million for insurance recoveries in the second quarter of 2011, which were collected during the third quarter. Although
the Utility currently considers it likely that a significant portion of costs incurred for third-party claims 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.)
Additionally, a purported
shareholder derivative lawsuit was filed following the San Bruno accident to seek recovery on behalf of PG&E Corporation and the Utility for alleged breaches of fiduciary duty by officers and directors, among other claims. The judge has ordered
that proceedings in the derivative lawsuit be delayed until further order of the court.
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In February 2011, PG&E Corporation rejected a shareholder demand that had been made
following the San Bruno accident demanding that the PG&E Corporation Board of Directors (“Board”) (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 members, officers, other employees, and third parties; and (3) adopt corporate governance initiatives and safety
programs. The Board authorized PG&E Corporation to reject the demand as had been recommended by the Evaluation Committee, a committee composed of independent directors that had been appointed to evaluate the demand and recommend how the Board
should respond. The Board also reserved the right to commence further investigation or litigation regarding the San Bruno accident if the Board deems such investigation or litigation appropriate.
Impact on Financial Condition and Results of Operations
For the three and nine months ended September 30, 2011, the Utility has incurred incremental pipeline-related costs in operating and maintenance expense of $177 million and $303 million,
respectively, to perform hydrostatic pressure tests and other tests on portions of its natural gas pipeline system, complete its review and validation of pipeline records, respond to regulatory proceedings and investigations, and perform other
activities related to the safety of its natural gas pipeline system. These costs will not be recoverable from customers through rates. (See “Operating and Maintenance” above.)
The Utility projects that it will incur as much as $550 million in total expenses in 2011 to conduct pressure tests and other tests on
portions of its natural gas pipeline system, continue its review and validation of pipeline records, respond to regulatory proceedings and investigations, and to perform pipeline-related activities that are within the scope of the Utility’s
proposed pipeline safety enhancement plan. The Utility also projects that it will incur costs of between $100 million and $200 million in 2012 for pipeline-related activities that are outside the scope of the proposed plan. The Utility will not seek
to recover these 2011 and 2012 costs from customers. In addition, the Utility expects it will incur costs in 2012 and future periods to perform work within the scope of the Utility’s proposed pipeline safety enhancement plan and to comply with
new state or federal requirements applicable to natural gas transmission operators. Although the Utility intends to seek recovery of these costs from customers, it is uncertain what portion of these additional costs ultimately will be recoverable
through rates.
PG&E Corporation’s and the Utility’s future financial condition, results of operations, and cash
flows will be affected by the scope and timing of the Utility’s pipeline safety enhancement plan that is approved by the CPUC; when and whether the CPUC approves the Utility’s request to recover plan-related costs that are incurred before
the CPUC issues a final decision; the ultimate amount of pipeline-related costs that are not recoverable from customers, the amount of civil or criminal fines, penalties, or punitive damages the Utility may be required to pay as a result of the
outcome of the regulatory proceedings, investigations, and civil litigation discussed above, and new state or federal requirements that may be imposed on operators of natural gas transmission pipelines.
REGULATORY MATTERS
The Utility is subject to substantial regulation by the CPUC, the FERC, the NRC and other federal and state regulatory agencies. Significant regulatory developments that have occurred since the 2010
Annual Report was filed with the Securities and Exchange Commission (“SEC”) are discussed below.
2011 General Rate Case
Application
On May 5, 2011, the CPUC issued a final decision in the 2011 GRC to authorize the Utility’s revenue
requirements for 2011 through 2013 for its costs to own and operate its electric and natural gas distribution and electric generation operations. The final decision approves the unopposed October 15, 2010 settlement agreement among the Utility,
the CPUC’s Division of Ratepayer Advocates, and nearly all other intervening parties.
The CPUC
authorized a total 2011 revenue requirement of approximately $6.0 billion, which reflects an overall increase of $450 million, or 8.0%, over the total 2010 authorized amount of $5.6 billion, including $55 million for the recovery of financing costs
and the accelerated return of capital associated with conventional meters that have been replaced by
SmartMeter
TM
devices. PG&E Corporation’s and the
Utility’s financial results for the three and nine months ended September 30, 2011 reflect the additional authorized base revenues from January 1, 2011. (See “Results of Operations” above.) The CPUC decision also authorized
attrition increases of $180 million for 2012 and $185 million for 2013.
As required by the GRC decision, on August 3,
2011, the Utility filed its first annual report with the CPUC containing information about the Utility’s budgeted expense and capital expenditures compared to funding targets set forth in the settlement agreement adopted by the CPUC. Also as
required by the decision, on September 30, 2011, the Utility filed its first semi-annual report on gas distribution safety.
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Electric Transmission Owner Rate Cases
On August 10, 2011, the FERC approved an uncontested settlement of the Utility’s 13
th
TO rate case that increases the Utility’s annual retail revenue
requirement from $875 million to $934 million, with rates effective as of March 1, 2011. The Utility has recorded reserves to refund customers the difference between revenues collected at the higher as-filed rates and the rates included in the
settlement since March 1, 2011. Retail electric rates will be adjusted on January 1, 2012 to reflect the revenue requirement adopted in the settlement and any over-collected amounts will be refunded to customers, with interest.
2011 Gas Transmission and Storage Rate Case
On April 14, 2011, the CPUC issued a final decision that approves the settlement agreement, known as the Gas Accord V Settlement Agreement (“Gas Accord V”), entered into among the Utility
and other parties to determine the rates and terms and conditions of the Utility’s gas transmission and storage services for a four-year period beginning January 1, 2011. The decision also resolves several objections raised by the other
two California gas utilities.
The CPUC authorized a 2011 natural gas transmission and storage revenue requirement of $514
million, an increase of $52 million over the 2010 adopted revenue requirement. PG&E Corporation’s and the Utility’s financial results for the three and nine months ended September 30, 2011 reflect the additional authorized base
revenues from January 1, 2011. (See “Results of Operations” above.)
With attrition increases authorized by the
decision, the Utility’s natural gas transmission and storage revenue requirements for 2012, 2013, and 2014 will be $541 million, $565 million, and $582 million, respectively. The Utility also has been authorized to recover (through natural gas
transmission and storage rates) revenue requirements for other costs, such as the cost of electricity used to operate natural gas compressor stations and other costs, that are determined in the Utility’s 2011 GRC or other Utility regulatory
proceedings.
On July 14, 2011, the CPUC issued a decision in the “safety phase” of the GT&S rate case. The
decision requires the Utility to offer maps of gas transmission facilities and provide free training to fire departments and other emergency response agencies, verify and submit inspection records to the CPUC for pipeline shutoff valves, and expand
customer outreach to promote awareness of gas safety issues, among other required actions. The Utility must fund these activities with the revenues authorized in the Gas Accord V.
Finally, as required by the decision, on September 30, 2011, the Utility filed its semi-annual safety report with the CPUC’s
Energy Division and the CPSD to provide details about the Utility’s use of funds budgeted for pipeline safety, reliability and integrity projects and activities, including an explanation of whether the Utility has under-spent or over-spent
funds.
Energy Efficiency Programs and Incentive Ratemaking
On June 27, 2011, the Utility requested that the CPUC approve an incentive award of $32 million based on the energy savings attributable to the Utility’s energy efficiency programs in 2009. The
CPUC may issue a decision by December 2011 or early 2012.
On June 30, 2011, the California Governor signed Senate Bill
87 (“SB 87”) into law, which includes a provision that allows the transfer of up to $155 million from the statewide gas-consumption surcharge fund to the California General State Fund in the 2011 fiscal year (from July 2011 through June
2012). The surcharge is collected by the Utility, San Diego Gas and Electric Company, and Southern California Gas Company to help fund gas public purpose programs, including energy efficiency programs. On October 6, 2011, the CPUC issued a
final decision that authorizes the utilities to use unspent funds from prior program years to address the shortfall that would result if the transfer to the General Fund is made. The decision effectively allows the Utility to continue operating its
energy efficiency programs at or near the level of funding previously approved by the CPUC.
On October 6, 2011, the CPUC
also extended the statutory deadline to December 12, 2011 for resolving modifications to the incentive ratemaking mechanism for the 2010 through 2012 program cycle and future years. It is uncertain what modifications will ultimately be adopted
by the CPUC.
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CPUC Resolution Regarding the Tax Relief Act
The Tax Relief Act generally allows the Utility to accelerate depreciation by deducting up to 100% of the investment cost of certain
qualified property placed into service during 2011 (or as late as 2012 under “phase out” or transition rules) and up to 50% of the investment cost of certain qualified property placed into service in 2012 (or as late as 2013 under the
phase out rules). Amounts that are not subject to 50% or 100% acceleration will be recovered under normal tax depreciation lives and methods. As a result of the accelerated depreciation, the Utility’s federal tax payments are expected to be
lower. (See “Liquidity and Financial Resources” above.) The resolution authorizes the Utility to use the tax savings to invest in certain additional capital infrastructure, not otherwise funded through rates.
On April 14, 2011, the CPUC adopted a resolution establishing a one-way memorandum account for certain rate-regulated utilities,
including the Utility, to record the net change in the cost of providing utility service associated with the Tax Relief Act. The CPUC adopted an amended resolution on June 23, 2011 that primarily clarified certain language in the April 14,
2011 resolution.
The memorandum account will track: (1) the reduction in revenue requirements that is due to lower rate
base resulting from deferred tax liabilities related to the accelerated federal tax depreciation, (2) the increase in revenue requirements associated with incremental eligible capital investments that meet certain CPUC guidelines as described
in the resolution, and (3) other applicable reductions and increases in revenue requirements as defined in the resolution. The memorandum account will be applicable to CPUC-jurisdictional assets only; however, it is expected to exclude
investments that have separate ratemaking treatment such as the Utility’s program to install an advanced metering system. The net benefits of the Tax Relief Act related to those excluded investments will automatically flow to customers under
existing balancing account mechanisms. The memorandum account will be in effect for capital investments (other than those related to natural gas transmission operations) until 2014, the test year of the Utility’s next GRC. The memorandum
account will be in effect for capital investments related to natural gas transmission operations until 2015, the test year for the Utility’s next GT&S rate case. In each rate case, the CPUC will determine the disposition of the memorandum
account.
Deployment of SmartMeter
TM
Technology
The CPUC has authorized the Utility’s program to install approximately 10 million advanced electric and gas meters throughout the Utility’s service territory. The CPUC has authorized the
Utility to recover $2.3 billion in estimated project costs. Absent CPUC authorization, costs that exceed $2.3 billion will not be recoverable through rates. As of September 30, 2011, the Utility has installed 8.6 million meters and
incurred costs of $2.2 billion. The Utility has recorded a provision of $36 million as of September 30, 2011 and December 31, 2010, representing the current forecast of capital-related costs that are expected to exceed the CPUC-authorized
cost cap and that therefore are not currently recoverable through rates. The Utility will update its forecasts as the project continues and may incur additional non-recoverable costs.
On March 24, 2011, the Utility filed an application with the CPUC seeking approval of the Utility’s proposal to provide
residential customers the option to turn off the radios in their gas and electric SmartMeter™ devices to disable the radio frequency (“RF”) communications used in the wireless meters. The Utility requested that the CPUC authorize
electric and gas revenue requirements totaling $84 million through 2013 to recover the Utility’s estimated costs to provide the “radio-off” option which would be collected through fees charged to customers who choose the radio-off
option. PG&E Corporation and the Utility are unable to predict whether the CPUC will approve the Utility’s proposal. Additionally, the CPUC is considering SmartMeter™ alternatives raised by other parties, including an analog meter, a
digital meter without a radio, and a wired meter. PG&E Corporation and the Utility are uncertain whether the CPUC will approve the Utility’s radio-off proposal or an alternative SmartMeter™ opt-out proposal.
On April 11, 2011, the Kern County Superior Court in Bakersfield, California dismissed the pending class action complaint that had
alleged that the SmartMeter™ system generated inaccurate bills and led to overcharges, among other allegations. The plaintiff filed an appeal of the dismissal on August 26, 2011. The Utility expects the appeal to be heard and decided by
the California Courts of Appeal before the end of 2012.
Diablo Canyon Nuclear Power Plant
The NRC operating license for Diablo Canyon Unit 1 expires in November 2024 and the NRC operating license for Diablo Canyon Unit 2
expires in August 2025. On November 24, 2009, the Utility filed an application to request the NRC to renew each of the operating licenses for Diablo Canyon for 20 years, until November 2044 for Unit 1 and August 2045 for Unit 2. The license
renewal process is expected to take several years as the NRC holds public hearings and conducts safety and environmental analyses and site audits. The Utility’s application has been challenged by local environmental and anti-nuclear power
organizations. On October 24, 2011, the NRC ruled that one of the challengers’ contentions should be admitted for hearing. This contention argues that the environmental report submitted by the Utility in November 2009 in
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support of its renewal application was inadequate because it did not include an analysis of the newly discovered earthquake fault that is located offshore from Diablo Canyon (the “Shoreline
Fault”). In 2010, the Utility performed additional analyses that considered seismic information about the Shoreline Fault and these additional analyses did not change the overall results of the Utility’s severe accident mitigation
alternative analysis that had originally been submitted with the renewal application. The Utility intends to present this additional information to respond to the contention at the NRC hearing that will be held in the future. As discussed below, the
NRC has agreed to delay the licensing renewal process, including any hearings.
As part of the renewal application process,
the NRC will issue an environmental impact report and a safety evaluation report. In May 2011, the NRC agreed to delay issuing its environmental impact report until the Utility completes additional seismic studies. These studies are not expected to
be completed until 2015 or 2016. In early June 2011, the NRC issued its safety evaluation report and concluded that the Utility’s safety plan and processes meet federal requirements for the longer-term operation of the plant. The NRC stated
that its report may change depending on the results of the Utility’s additional seismic studies. PG&E Corporation and the Utility are unable to predict when and whether the NRC will approve the license renewal application.
Following the March 2011 earthquake and tsunami that caused significant damage to nuclear facilities in Japan, the NRC appointed a task
force to develop recommendations about how to improve safety at U.S. nuclear power plants and upgrade protection against earthquakes, floods and power losses. The twelve safety recommendations were released in July 2011 and have been reviewed by the
NRC staff. In October 2011, the NRC directed its staff to begin immediately implementing seven of the recommendations through the NRC’s rulemaking process. It is expected that the NRC will adopt regulations or issue orders requiring nuclear
power plants to implement some of the near-term recommendations within the next year. Although the Utility has already taken significant action at Diablo Canyon to address concerns raised by the events in Japan, the Utility could incur additional
costs to comply with new regulations or orders that may be adopted by the NRC to implement the task force’s recommendations.
Finally, in early August 2011, the NRC found that a report submitted by the Utility to the NRC on January 7, 2011 to provide updated seismological information did not conform to the requirements of
the current Diablo Canyon operating license. On October 21, 2011, the Utility filed a request that the NRC amend the operating license to address this issue. If the NRC does not approve the request the Utility could be required to perform
additional analyses of Diablo Canyon’s seismic design which could indicate that modifications to Diablo Canyon would be required to address seismic design issues. The NRC could order the Utility to cease operations until the modifications were
made or the Utility could voluntarily cease operations if it determined that the modifications were not economical or feasible.
The Utility has previously requested that the CPUC authorize the Utility to recover approximately $85 million for costs estimated to be
incurred during the lengthy NRC relicensing process. In April 2011, a motion to dismiss the Utility’s application was filed but the CPUC has not yet ruled on this motion. On September 23, 2011, the Utility also requested that the CPUC
authorize the Utility to recover an additional $47 million to complete the additional seismic studies that the Utility is conducting. The Utility is uncertain when and whether the CPUC will approve the Utility’s requests for authorization.
Actual costs may be higher than estimates depending on environmental permitting processes and required environmental mitigation.
(See the discussion about risks related to the Utility’s nuclear operations in the 2010 Annual Report under Item 1A. Risk Factors, below.)
Other Matters
In
addition to the ongoing investigations, proceedings, and litigation related to the Utility’s gas pipeline system (see “Natural Gas Pipeline Matters” above), the CPUC is considering the following matters:
On June 10, 2011, the CPUC commenced an investigation to determine whether the Utility should be penalized for failing to comply
with the CPUC’s resource adequacy requirements for March, April, and July 2010. The CPSD recommends that the Utility be fined $7 million for these violations, as calculated in accordance with the penalty provisions previously adopted by the
CPUC. On September 23, 2011, the Utility submitted testimony to the CPSD contending that it had complied with the CPUC’s resource adequacy program. PG&E Corporation and the Utility are unable to predict the outcome of this
investigation.
On June 10, 2011, the CPUC also issued an order to investigate whether the Utility failed to comply with
the CPUC’s November 9, 2009 decision granting the Utility’s request for a permit to construct a substation when the Utility removed an almond tree orchard to prepare the site for construction. On September 26, 2011, the Utility
and the CPSD filed a settlement agreement with the CPUC under which the Utility will pay $100,000 in penalties and contribute $50,000 to an environmental group.
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Additionally, on October 14, 2011, the Utility filed a supplemental report with the
CPUC detailing the results of the Utility’s re-inspection of its underground facilities (used to house electric distribution equipment) in the San Jose division and other areas of the Utility’s service territory. The supplemental report
was prompted by the Utility’s earlier report that it had determined that some underground electric facilities had not been inspected as reported by some employees and contractors. The Utility has completed the re-inspections of these facilities
and has taken steps to improve its inspection verification procedures and increase inspection audits. In addition, the Utility has committed to re-inspect approximately 16,000 additional overhead electric facilities. The Utility will report the
results to the CPUC by April 30, 2012.
PG&E Corporation and the Utility are unable to predict how the above matters
will affect the other regulatory proceedings and current investigations involving the Utility, or whether additional proceedings or investigations will be commenced that could result in further regulatory orders or the imposition of fines or
penalties on the Utility.
ENVIRONMENTAL MATTERS
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 2010 Annual Report.) These laws and requirements relate to a broad range of the Utility’s activities, including the
discharge of pollutants into the air, water, and soil; the transportation, handling, storage, and disposal of spent nuclear fuel; remediation of hazardous wastes; and the reporting and reduction of carbon dioxide and other GHG emissions. Significant
developments that have occurred since the 2010 Annual Report was filed with the SEC are discussed below.
Climate Change
The California Global Warming Solutions Act of 2006 (also known as Assembly Bill 32 or “AB 32”) requires the gradual reduction
of GHG emissions in California to 1990 levels by 2020 on a schedule beginning in 2012. In December 2008, the California Air Resources Board (“CARB”) adopted a scoping plan that contains recommendations for achieving the maximum
technologically feasible and cost-effective GHG reductions to meet the 2020 reduction target, including a proposed cap-and-trade program. After the San Francisco County Superior Court ruled that the CARB had failed to comply with the California
Environmental Quality Act (“CEQA”), the CARB issued its proposed report on June 13, 2011 of its further review and analysis of alternatives to the scoping plan measures. The CARB again concluded that a cap-and-trade program continues
to be the preferred alternative. While the CARB’s appeal of the Superior Court’s order is pending, the CARB proceeded with its rulemaking and approved the final cap and trade regulation on October 20, 2011. The cap-and-trade
regulations are expected to become effective on January 1, 2012, but the program will be implemented on a delayed basis by requiring compliance with the initial emissions cap beginning on January 1, 2013 instead of January 1, 2012.
During 2012, the CARB will conduct market simulations and additional cap-and-trade market design activities. It is uncertain when the CARB’s appeal will be decided and how the final decision will affect implementation of the cap-and-trade
program.
Renewable Energy Resources
On April 12, 2011, the California Governor signed new legislation establishing a new renewable portfolio standard (“RPS”) that increases the amount of renewable energy that load-serving
entities (“LSE’s”), such as the Utility, must deliver to their customers from at least 20% of their total retail sales, as required by the prior law, to 33% of their total retail sales. The legislation will become effective on
December 10, 2011. (In response to the enactment of the new RPS law, the CARB abandoned its regulatory efforts to establish a 33% renewable energy standard.) The new RPS law requires that each LSE procure an average of 20% of its retail sales
from renewable resources for the first compliance period of January 1, 2011 to December 31, 2013. The new law directs the CPUC to establish the RPS requirement for each succeeding multi-year compliance period (2014-2016 and 2017-2020) as
well as reasonable progress targets for individual years in each compliance period, by January 1, 2012. (The Utility expects that the CPUC will use the reasonable yearly progress targets to establish the RPS requirement for the relevant
compliance period.)
The new RPS law creates three distinct categories of renewable energy products and imposes minimum or
maximum procurement targets for each of these product categories for each compliance period. With certain exceptions, these categorical requirements will only apply to renewable energy contracts that are entered into after June 1, 2010. The new
law also (1) limits the use of certain types of unbundled renewable energy credits (“RECs”) and (2) restricts the ability to carry forward (or “bank”) RPS volumes from certain types of short-term contracts, to satisfy
compliance obligations.
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The CPUC has opened a new rulemaking proceeding to develop and adopt regulations to
implement the new RPS law, including the establishment of an RPS requirement for each compliance period and determining how different types of renewable energy products will qualify toward meeting the compliance obligations. In addition, the CPUC is
expected to determine whether to change the penalty provisions established under the former RPS law, which permitted a maximum penalty of $25 million per year on each LSE that had an unexcused failure to meet its compliance obligation. Until the
CPUC adopts regulations to implement the new law, it is uncertain how the CPUC’s regulations and decisions issued pursuant to the former 20% RPS statute, including the penalty provisions, will apply to the new RPS requirements.
The costs incurred by the Utility under third-party contracts to meet RPS requirements are tracked in a balancing account and recovered
through rates. The costs of Utility-owned renewable generation projects will be recoverable through traditional cost-of-service ratemaking mechanisms provided that costs do not exceed the maximums authorized by the CPUC for the respective project.
The CEC, which continues under the new RPS law to have responsibility for certifying the eligibility of renewable resources
and verifying LSE compliance with the RPS program, has also initiated a proceeding to implement the new RPS law and expects to issue a draft regulation addressing certain implementation issues by the end of 2011.
Water Quality
Section 316(b) of the federal Clean Water Act requires 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. On April 20, 2011, the U.S. Environmental Protection Agency (“EPA”) published draft regulations that
propose specific reductions for impingement (which occurs when larger organisms are caught on water filter screens) and provide a case-by-case site specific assessment to establish compliance requirements for entrainment (which occurs when organisms
are drawn through the cooling water system). The proposed site specific assessment allows for the consideration of a variety of factors including social costs and benefits, energy reliability, land availability, and non-water quality adverse
impacts. The draft regulations are subject to public comment and final regulations are not expected until July 2012.
The
California Water Resources Control Board (“Control Board”) also has adopted a policy on once-through cooling. The policy, effective October 1, 2010, generally requires the installation of cooling towers or other significant measures
to reduce the impact on marine life from existing power generation facilities by at least 85%. However, with respect to the state’s nuclear power generation facilities, the policy allows other compliance measures to be taken if the costs to
install cooling towers are “wholly out of proportion” to the costs considered by the Control Board in developing its policy or if the installation of cooling towers would be “wholly unreasonable” after considering non-cost
factors such as engineering and permitting constraints and adverse environmental impacts. The Utility believes that the costs to install cooling towers at Diablo Canyon, which could be as much as $4.5 billion, will meet the “wholly out of
proportion” test. The Utility also believes that the installation of cooling towers at Diablo Canyon would be “wholly unreasonable.” If the Control Board disagreed and if the installation of cooling towers at Diablo Canyon were not
technically or economically feasible, the Utility may be forced to cease operations at Diablo Canyon and may incur a material charge. Assuming the Control Board does not require the installation of cooling towers at Diablo Canyon, the Utility could
incur significant costs to comply with alternative compliance measures or to make payments to support various environmental mitigation projects. The Utility would seek to recover such costs in rates. The Utility’s Diablo Canyon operations must
be in compliance with the Control Board’s policy by December 31, 2024.
Remediation
The Utility has been, and may be, required to pay for environmental remediation costs at sites where it is identified as a potentially
responsible party under federal and state environmental laws. These sites include former manufactured gas plant (“MGP”) sites, current and former power plant sites, former gas gathering and gas storage sites, sites where natural gas
compressor stations are located, current and former substations, service center and general construction yard sites, and sites currently and formerly used by the Utility for the storage, recycling, or disposal of hazardous substances. Under federal
and California laws, the Utility may be responsible for remediation of hazardous substances even if it did not deposit those substances on the site.
Hinkley Natural Gas Compressor Site
The Utility is legally
responsible for remediating groundwater contamination caused by hexavalent chromium used in the past at the Utility’s natural gas compressor station located near Hinkley, California. The Utility is also required to take measures to abate the
effects of the contamination on the environment. The Utility’s remediation and abatement efforts are subject to the regulatory authority of the California Regional Water Quality Control Board, Lahontan Region (“Water Board”). The
Utility has been working with the Water Board for several years to implement interim remedial measures to
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both reduce the mass of the underground plume of hexavalent chromium and to monitor and control movement of the plume. In addition, the Utility has been providing bottled water to affected
residents as part of the Utility’s abatement efforts.
In August 2010, the Utility filed a comprehensive feasibility
study with the Water Board that included an evaluation of possible alternatives for a final groundwater remediation plan. The Utility filed several addendums to its feasibility study based on additional analyses of remediation alternatives and
correspondence with the Water Board. The Utility’s recommended alternative for a final remediation plan was submitted to the Water Board in September 2011 and involves a combination of using pumped groundwater from extraction wells to irrigate
agricultural land and in-situ remediation. The Water Board stated that it anticipates it will consider certification of the final EIR, which will include the final approved remediation plan, in July 2012. The Water Board has indicated that
it anticipates releasing a preliminary draft of the EIR for discussion in late 2011.
Additionally, on October 11, 2011,
the Water Board issued an amended cleanup and abatement order (“CAO”) to require the Utility to provide an interim and permanent replacement water system for certain properties located near the underground plume of hexavalent chromium. The
CAO requires the Utility to propose a method to perform an initial and quarterly evaluation of wells in the affected area to determine if detectable levels of hexavalent chromium that are lower than the background level but higher than the new
public health goal, represent background conditions, or are more likely than not, partially or completely caused by the Utility’s discharge of waste. On October 25, 2011, the Utility filed a petition with the Control Board and requested
that the Control Board determine that the Utility is not required to comply with these provisions of the CAO, in part, because the Utility believes that it is not feasible to implement the ordered actions and that the ordered actions are not
supported by California law.
For the three and nine months ended September 30, 2011, the Utility increased its provision
for environmental remediation liabilities associated with the Hinkley site by $106 million and $132 million, respectively. The increase resulted primarily from changes in costs estimates and assumptions associated with the above developments. As of
September 30, 2011 and December 31, 2010, $150 million and $45 million, respectively, were accrued in PG&E Corporation’s and the Utility’s Condensed Consolidated Balance Sheets for estimated undiscounted future costs for
environmental remediation. Actual costs will depend on many factors, including the certification of a final remediation plan, the extent of the groundwater chromium plume, the levels of hexavalent chromium used as the standard for remediation, and
the scope of requirements to provide a permanent water replacement system to affected residents. The Utility is unable to recover remediation costs for the Hinkley site through customer rates. As a result, future increases to the Utility’s
provision for its remediation liability will impact PG&E Corporation’s and the Utility’s financial results.
(See Note 10 of the Notes to the Condensed Consolidated Financial Statements for a discussion of estimated environmental remediation
liabilities and Legal Proceedings of Part II, Item 1 for discussion of related proceedings.)
LEGAL MATTERS
In addition to the provision made for claims related to the San Bruno accident and the Rancho Cordova accident, PG&E
Corporation’s and the Utility’s Condensed Consolidated Financial Statements also include provisions for claims and lawsuits that have arisen in the ordinary course of business, regulatory proceedings, and other legal matters. See
“Legal and Regulatory Contingencies” in Note 10 of the Notes to the Condensed Consolidated Financial Statements.
RISK MANAGEMENT ACTIVITIES
The Utility and PG&E Corporation, 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; 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.
On July 21, 2010, President Obama signed into law new federal financial reform legislation, the Dodd-Frank Wall
Street Reform and Consumer Protection Act. PG&E Corporation and the Utility are evaluating the new legislation, and will
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review future regulations to assess compliance requirements as well as potential impacts on the Utility’s procurement activities and risk management programs.
Price Risk
The Utility
is exposed to commodity price risk as a result of its electricity and natural gas procurement activities, including the procurement of natural gas and nuclear fuel necessary for electricity generation and natural gas procurement for core customers.
As long as the Utility can conclude that it is probable that its reasonably incurred wholesale electricity procurement costs and natural gas costs are recoverable, fluctuations in electricity and natural gas prices will not affect earnings but may
impact cash flows. The Utility’s natural gas transportation and storage costs for core customers are also fully recoverable through a ratemaking mechanism.
The Utility’s natural gas transportation and storage costs for non-core customers may not be fully recoverable. The Utility is subject to price and volumetric risk for the portion of intrastate
natural gas transportation and storage capacity that has not been sold under long-term contracts providing for the recovery of all fixed costs through the collection of fixed reservation charges. The Utility sells most of its capacity based on the
volume of gas that the Utility’s customers actually ship, which exposes the Utility to volumetric risk.
The Utility uses
value-at-risk to measure its shareholders’ exposure to price and volumetric risks resulting from variability in the price of, and demand for, natural gas transportation and storage services that could impact revenues due to changes in market
prices and customer demand. Value-at-risk measures this exposure over a rolling 12-month forward period and assumes that the contract positions are held through expiration. This calculation is based on a 95% confidence level, which means that there
is a 5% probability that the impact to revenues on a pre-tax basis, over the rolling 12-month forward period, will be at least as large as the reported value-at-risk. Value-at-risk uses market data to quantify the Utility’s price exposure. When
market data is not available, the Utility uses historical data or market proxies to extrapolate the required market data. Value-at-risk as a measure of portfolio risk has several limitations, including, but not limited to, inadequate indication of
the exposure to extreme price movements and the use of historical data or market proxies that may not adequately capture portfolio risk.
The Utility’s value-at-risk calculated under the methodology described above was approximately $7 million at September 30, 2011. The Utility’s approximate high, low, and average
values-at-risk during the 12 months ended September 30, 2011 were $15 million, $7 million, and $10 million, respectively. (See Note 7 of the Notes to the Condensed Consolidated Financial Statements for further discussion of price risk
management activities.)
Interest Rate Risk
Interest rate risk sensitivity analysis is used to measure interest rate risk by computing estimated changes in cash flows as a result of assumed changes in market interest rates. At September 30,
2011, if interest rates changed by 1% for all current PG&E Corporation and Utility variable rate and short-term debt and investments, the change would affect net income for the next 12 months by $11 million, based on net variable rate debt and
other interest rate-sensitive instruments outstanding.
Credit Risk
The Utility conducts business with counterparties mainly in the energy industry, including other California investor-owned electric
utilities, municipal utilities, energy trading companies, financial institutions, and oil and natural gas production companies located in the United States and Canada. If a counterparty fails to perform on its contractual obligation to deliver
electricity or gas, then the Utility may find it necessary to procure electricity or gas at current market prices, which may be higher than the contract prices.
The Utility manages credit risk associated with its counterparties by assigning credit limits based on evaluations of their financial conditions, net worth, credit ratings, and other credit criteria as
deemed appropriate. Credit limits and credit quality are monitored periodically. The Utility ties many energy contracts to master commodity enabling agreements that may require security (referred to as “Credit Collateral” in the table
below). Credit Collateral may be in the form of cash or letters of credit. The Utility may accept other forms of performance assurance in the form of corporate guarantees of acceptable credit quality or other eligible securities (as deemed
appropriate by the Utility). Credit Collateral or performance assurance may be required from counterparties when current net receivables and replacement cost exposure exceed contractually specified limits.
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The following table summarizes the Utility’s net credit risk exposure to its
counterparties, as well as the Utility’s credit risk exposure to counterparties accounting for greater than 10% net credit exposure, as of September 30, 2011 and December 31, 2010:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(in millions)
|
|
Gross Credit
Exposure
Before Credit
Collateral
(1)
|
|
|
Credit
Collateral
|
|
|
Net Credit
Exposure
(2)
|
|
|
Number of
Wholesale
Customers or
Counterparties
>10%
|
|
|
Net Credit
Exposure
to
Wholesale
Customers or
Counterparties
>10%
|
|
|
September 30, 2011
|
|
|
$ 213
|
|
|
|
$ 12
|
|
|
|
$ 201
|
|
|
|
2
|
|
|
|
$ 156
|
|
|
December 31, 2010
|
|
|
269
|
|
|
|
17
|
|
|
|
252
|
|
|
|
2
|
|
|
|
187
|
|
(1)
Gross credit exposure equals mark-to-market value on physically and financially settled contracts, notes receivable, and net
receivables (payables) where netting is contractually allowed. Gross and net credit exposure amounts reported above do not include adjustments for time value or liquidity.
(2)
Net credit exposure is the Gross Credit Exposure Before Credit Collateral minus Credit Collateral (cash deposits and letters
of credit). For purposes of this table, parental guarantees are not included as part of the calculation.
CRITICAL ACCOUNTING POLICIES
The preparation of Condensed Consolidated Financial Statements in accordance with U.S. generally accepted accounting principles involves the use of estimates and assumptions that affect the recorded
amounts of assets and liabilities as of the date of the financial statements and the reported amounts of revenues and expenses during the reporting period. Actual results may differ materially from these estimates and assumptions. PG&E
Corporation and the Utility consider their accounting policies for regulatory assets and liabilities, loss contingencies associated with environmental remediation liabilities and legal matters, asset retirement obligations, and pension plan and
other postretirement plan obligations, to be critical accounting policies, due, in part, to their complexity and because their application is relevant and material to the financial position and results of operations of PG&E Corporation and the
Utility, and because these policies require the use of material judgments and estimates. These policies and their key characteristics are discussed in detail in the 2010 Annual Report. In addition, management has made significant estimates and
assumptions about accruals related to the San Bruno accident. (See Note 10 to the Condensed Consolidated Financial Statements.)
ACCOUNTING STANDARDS ISSUED BUT NOT YET ADOPTED
See Note 2 of the Notes to the Condensed Consolidated Financial
Statements.
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