UNITED STATES SECURITIES AND EXCHANGE COMMISSION Washington, D.C., 20549 FORM 10-Q | ||||||||||
(Mark One) | ||||||||||
[X] | QUARTERLY REPORT PURSUANT TO SECTION 13 OR SECURITIES EXCHANGE ACT OF 1934 | |||||||||
For the quarterly period ended OR | ||||||||||
[ ] | TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 | |||||||||
For the transition period from ___________ to __________ | ||||||||||
Commission File Number _______________ | Exact Name of Registrant as specified in its charter _______________ | State or other Jurisdiction of Incorporation ______________ | IRS Employer Identification Number ___________ | |||||||
1-12609 | PG&E Corporation | California | 94-3234914 | |||||||
1-2348 | Pacific Gas and Electric Company | California | 94-0742640 | |||||||
Pacific Gas and Electric Company 77 Beale Street P.O. Box 770000 San Francisco, California 94177 | PG&E Corporation One Market, Spear Tower Suite 2400 San Francisco, California 94105 | |||||||||
Address of principal executive offices, including zip code | ||||||||||
Pacific Gas and Electric Company (415) 973-7000 | PG&E Corporation (415) 267-7000 | |||||||||
Registrant's telephone number, including area code | ||||||||||
Indicate by check mark whether each registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) have been subject to such filing requirements for the past 90 days. [X] Yes [ ] No | ||||||||||
Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller reporting company. See definitions of “large accelerated filer”, “accelerated filer”, and “smaller reporting company” in Rule 12b-2 of the Exchange Act. | ||||||||||
PG&E Corporation: | [X] Large accelerated filer | [ ] Accelerated Filer | ||||||||
[ ] Non-accelerated filer | [ ] Smaller reporting company | |||||||||
Pacific Gas and Electric Company: | [ ] Large accelerated filer | [ ] Accelerated Filer | ||||||||
[X] Non-accelerated filer | [ ] Smaller reporting company | |||||||||
Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act). | ||||||||||
PG&E Corporation: | [ ] Yes [X] No | |||||||||
Pacific Gas and Electric Company: | [ ] Yes [X] No | |||||||||
Indicate the number of shares outstanding of each of the issuer's classes of common stock, as of the latest practicable date. | ||||||||||
Common Stock Outstanding as of | ||||||||||
PG&E Corporation | ||||||||||
Pacific Gas and Electric Company | ||||||||||
PART I. | FINANCIAL INFORMATION | PAGE | ||
CONDENSED CONSOLIDATED FINANCIAL STATEMENTS | ||||
PG&E Corporation | ||||
3 | ||||
4 | ||||
6 | ||||
Pacific Gas and Electric Company | ||||
7 | ||||
8 | ||||
10 | ||||
NOTES TO THE CONDENSED CONSOLIDATED FINANCIAL STATEMENTS | ||||
Organization and Basis of Presentation | 11 | |||
New and Significant Accounting Policies | ||||
Regulatory Assets, Liabilities, and Balancing Accounts | 14 | |||
Debt | 17 | |||
Shareholders' Equity | ||||
Earnings Per Common Share | ||||
Derivatives and Hedging Activities | ||||
Fair Value Measurements | ||||
Related Party Agreements and Transactions | ||||
Resolution of Remaining Chapter 11 Disputed Claims | ||||
Commitments and Contingencies | ||||
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS | ||||
51 | ||||
51 | ||||
53 | ||||
54 | ||||
56 | ||||
58 | ||||
58 | ||||
QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK | ||||
CONTROLS AND PROCEDURES | ||||
PART II. | OTHER INFORMATION | |||
LEGAL PROCEEDINGS | ||||
RISK FACTORS | ||||
UNREGISTERED SALES OF EQUITY SECURITIES AND USE OF PROCEEDS | ||||
OTHER INFORMATION | ||||
EXHIBITS | ||||
PG&E CORPORATION | ||||||||||||||||||||||||||||||||
CONDENSED CONSOLIDATED STATEMENTS OF INCOME | CONDENSED CONSOLIDATED STATEMENTS OF INCOME | |||||||||||||||||||||||||||||||
(Unaudited) | (Unaudited) | |||||||||||||||||||||||||||||||
Three Months Ended | Six Months Ended | Three Months Ended | Nine Months Ended | |||||||||||||||||||||||||||||
June 30, | June 30, | September 30, | September 30, | |||||||||||||||||||||||||||||
(in millions, except per share amounts) | 2008 | 2007 | 2008 | 2007 | 2008 | 2007 | 2008 | 2007 | ||||||||||||||||||||||||
Operating Revenues | ||||||||||||||||||||||||||||||||
Electric | $ | 2,645 | $ | 2,359 | $ | 5,159 | $ | 4,534 | $ | 2,880 | $ | 2,574 | $ | 8,039 | $ | 7,107 | ||||||||||||||||
Natural gas | 933 | 828 | 2,152 | 2,009 | 794 | 705 | 2,946 | 2,714 | ||||||||||||||||||||||||
Total operating revenues | 3,578 | 3,187 | 7,311 | 6,543 | 3,674 | 3,279 | 10,985 | 9,821 | ||||||||||||||||||||||||
Operating Expenses | ||||||||||||||||||||||||||||||||
Cost of electricity | 1,097 | 884 | 2,124 | 1,607 | 1,282 | 998 | 3,406 | 2,606 | ||||||||||||||||||||||||
Cost of natural gas | 487 | 396 | 1,262 | 1,150 | 351 | 281 | 1,613 | 1,431 | ||||||||||||||||||||||||
Operating and maintenance | 991 | 922 | 2,027 | 1,842 | 983 | 953 | 3,010 | 2,794 | ||||||||||||||||||||||||
Depreciation, amortization, and decommissioning | 419 | 430 | 821 | 860 | 419 | 465 | 1,240 | 1,325 | ||||||||||||||||||||||||
Total operating expenses | 2,994 | 2,632 | 6,234 | 5,459 | 3,035 | 2,697 | 9,269 | 8,156 | ||||||||||||||||||||||||
Operating Income | 584 | 555 | 1,077 | 1,084 | 639 | 582 | 1,716 | 1,665 | ||||||||||||||||||||||||
Interest income | 33 | 37 | 59 | 89 | 23 | 36 | 82 | 125 | ||||||||||||||||||||||||
Interest expense | (185 | ) | (185 | ) | (372 | ) | (375 | ) | (178 | ) | (196 | ) | (550 | ) | (571 | ) | ||||||||||||||||
Other income, net | 1 | 10 | 3 | 14 | ||||||||||||||||||||||||||||
Other income (expense), net | (17 | ) | 7 | (14 | ) | 22 | ||||||||||||||||||||||||||
Income Before Income Taxes | 433 | 417 | 767 | 812 | 467 | 429 | 1,234 | 1,241 | ||||||||||||||||||||||||
Income tax provision | 140 | 148 | 250 | 287 | 163 | 151 | 413 | 438 | ||||||||||||||||||||||||
Net Income | $ | 293 | $ | 269 | $ | 517 | $ | 525 | $ | 304 | $ | 278 | $ | 821 | $ | 803 | ||||||||||||||||
Weighted Average Common Shares Outstanding, Basic | 356 | 350 | 355 | 350 | 357 | 352 | 356 | 350 | ||||||||||||||||||||||||
Weighted Average Common Shares Outstanding, Diluted | 357 | 352 | 356 | 352 | 358 | 353 | 357 | 352 | ||||||||||||||||||||||||
Net Earnings Per Common Share, Basic | $ | 0.80 | $ | 0.75 | $ | 1.42 | $ | 1.46 | $ | 0.83 | $ | 0.77 | $ | 2.25 | $ | 2.23 | ||||||||||||||||
Net Earnings Per Common Share, Diluted | $ | 0.80 | $ | 0.74 | $ | 1.42 | $ | 1.45 | $ | 0.83 | $ | 0.77 | $ | 2.24 | $ | 2.22 | ||||||||||||||||
Dividends Declared Per Common Share | $ | 0.39 | $ | 0.36 | $ | 0.78 | $ | 0.72 | $ | 0.39 | $ | 0.36 | $ | 1.17 | $ | 1.08 | ||||||||||||||||
See accompanying Notes to the Condensed Consolidated Financial Statements. | See accompanying Notes to the Condensed Consolidated Financial Statements. | See accompanying Notes to the Condensed Consolidated Financial Statements. |
CONDENSED CONSOLIDATED BALANCE SHEETS | ||||||||||||||||
(Unaudited) | (Unaudited) | |||||||||||||||
Balance At | Balance At | |||||||||||||||
(in millions) | June 30, 2008 | December 31, 2007 | September 30, 2008 | December 31, 2007 | ||||||||||||
ASSETS | ||||||||||||||||
Current Assets | ||||||||||||||||
Cash and cash equivalents | $ | 297 | $ | 345 | $ | 251 | $ | 345 | ||||||||
Restricted cash | 1,322 | 1,297 | 1,325 | 1,297 | ||||||||||||
Accounts receivable: | ||||||||||||||||
Customers (net of allowance for doubtful accounts of $59 million in 2008 and $58 million in 2007) | 2,417 | 2,349 | ||||||||||||||
Customers (net of allowance for doubtful accounts of $75 million in 2008 and $58 million in 2007) | 2,530 | 2,349 | ||||||||||||||
Regulatory balancing accounts | 1,357 | 771 | 1,117 | 771 | ||||||||||||
Inventories: | ||||||||||||||||
Gas stored underground and fuel oil | 251 | 205 | 333 | 205 | ||||||||||||
Materials and supplies | 177 | 166 | 172 | 166 | ||||||||||||
Income taxes receivable | 52 | 61 | - | 61 | ||||||||||||
Prepaid expenses and other | 469 | 255 | 580 | 255 | ||||||||||||
Total current assets | 6,342 | 5,449 | 6,308 | 5,449 | ||||||||||||
Property, Plant, and Equipment | ||||||||||||||||
Electric | 26,693 | 25,599 | 27,146 | 25,599 | ||||||||||||
Gas | 9,860 | 9,620 | 10,016 | 9,620 | ||||||||||||
Construction work in progress | 1,432 | 1,348 | 1,668 | 1,348 | ||||||||||||
Other | 17 | 17 | 16 | 17 | ||||||||||||
Total property, plant, and equipment | 38,002 | 36,584 | 38,846 | 36,584 | ||||||||||||
Accumulated depreciation | (13,297 | ) | (12,928 | ) | (13,422 | ) | (12,928 | ) | ||||||||
Net property, plant, and equipment | 24,705 | 23,656 | 25,424 | 23,656 | ||||||||||||
Other Noncurrent Assets | ||||||||||||||||
Regulatory assets | 4,300 | 4,459 | 4,233 | 4,459 | ||||||||||||
Nuclear decommissioning funds | 1,914 | 1,979 | 1,819 | 1,979 | ||||||||||||
Other | 1,351 | 1,089 | 1,094 | 1,089 | ||||||||||||
Total other noncurrent assets | 7,565 | 7,527 | 7,146 | 7,527 | ||||||||||||
TOTAL ASSETS | $ | 38,612 | $ | 36,632 | $ | 38,878 | $ | 36,632 | ||||||||
See accompanying Notes to the Condensed Consolidated Financial Statements. | See accompanying Notes to the Condensed Consolidated Financial Statements. | See accompanying Notes to the Condensed Consolidated Financial Statements. |
PG&E CORPORATION | ||||||||||||||||
CONDENSED CONSOLIDATED BALANCE SHEETS | ||||||||||||||||
(Unaudited) | (Unaudited) | |||||||||||||||
Balance At | Balance At | |||||||||||||||
(in millions, except share amounts) | June 30, 2008 | December 31, 2007 | September 30, 2008 | December 31, 2007 | ||||||||||||
LIABILITIES AND SHAREHOLDERS' EQUITY | ||||||||||||||||
Current Liabilities | ||||||||||||||||
Short-term borrowings | $ | 156 | $ | 519 | $ | 1,335 | $ | 519 | ||||||||
Long-term debt, classified as current | 600 | - | 600 | - | ||||||||||||
Energy recovery bonds, classified as current | 362 | 354 | 366 | 354 | ||||||||||||
Accounts payable: | ||||||||||||||||
Trade creditors | 1,133 | 1,067 | 962 | 1,067 | ||||||||||||
Disputed claims and customer refunds | 1,588 | 1,629 | 1,588 | 1,629 | ||||||||||||
Regulatory balancing accounts | 924 | 673 | 906 | 673 | ||||||||||||
Other | 388 | 394 | 385 | 394 | ||||||||||||
Interest payable | 744 | 697 | 708 | 697 | ||||||||||||
Income taxes payable | 12 | - | 116 | - | ||||||||||||
Deferred income taxes | 228 | - | 156 | - | ||||||||||||
Other | 1,926 | 1,374 | 1,375 | 1,374 | ||||||||||||
Total current liabilities | 8,061 | 6,707 | 8,497 | 6,707 | ||||||||||||
Noncurrent Liabilities | ||||||||||||||||
Long-term debt | 7,721 | 8,171 | 7,816 | 8,171 | ||||||||||||
Energy recovery bonds | 1,409 | 1,582 | 1,310 | 1,582 | ||||||||||||
Regulatory liabilities | 5,185 | 4,448 | 4,456 | 4,448 | ||||||||||||
Asset retirement obligations | 1,614 | 1,579 | 1,628 | 1,579 | ||||||||||||
Income taxes payable | 230 | 234 | 231 | 234 | ||||||||||||
Deferred income taxes | 3,178 | 3,053 | 3,383 | 3,053 | ||||||||||||
Deferred tax credits | 96 | 99 | 95 | 99 | ||||||||||||
Other | 1,969 | 1,954 | 2,071 | 1,954 | ||||||||||||
Total noncurrent liabilities | 21,402 | 21,120 | 20,990 | 21,120 | ||||||||||||
Commitments and Contingencies | ||||||||||||||||
Preferred Stock of Subsidiaries | 252 | 252 | 252 | 252 | ||||||||||||
Preferred Stock | ||||||||||||||||
Preferred stock, no par value, authorized 80,000,000 shares, $100 par value, authorized 5,000,000 shares, none issued | - | - | - | - | ||||||||||||
Common Shareholders' Equity | ||||||||||||||||
Common stock, no par value, authorized 800,000,000 shares, issued 381,076,783 common and 1,392,583 restricted shares in 2008 and issued 378,385,151 common and 1,261,125 restricted shares in 2007 | 6,211 | 6,110 | ||||||||||||||
Common stock held by subsidiary, at cost, 24,665,500 shares | (718 | ) | (718 | ) | ||||||||||||
Common stock, no par value, authorized 800,000,000 shares, issued 358,198,735 common and 1,315,818 restricted shares in 2008 and issued 378,385,151 common and 1,261,125 restricted shares in 2007 | 5,883 | 6,110 | ||||||||||||||
Common stock held by subsidiary, at cost, 24,665,500 shares in 2007 | - | (718 | ) | |||||||||||||
Reinvested earnings | 3,389 | 3,151 | 3,238 | 3,151 | ||||||||||||
Accumulated other comprehensive income | 15 | 10 | 18 | 10 | ||||||||||||
Total common shareholders' equity | 8,897 | 8,553 | 9,139 | 8,553 | ||||||||||||
TOTAL LIABILITIES AND SHAREHOLDERS' EQUITY | $ | 38,612 | $ | 36,632 | $ | 38,878 | $ | 36,632 | ||||||||
See accompanying Notes to the Condensed Consolidated Financial Statements. | See accompanying Notes to the Condensed Consolidated Financial Statements. | See accompanying Notes to the Condensed Consolidated Financial Statements. |
PG&E CORPORATION | ||||||||||||||||
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS | CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS | |||||||||||||||
(Unaudited) | (Unaudited) | |||||||||||||||
Six Months Ended | Nine Months Ended | |||||||||||||||
June 30, | September 30, | |||||||||||||||
(in millions) | 2008 | 2007 | 2008 | 2007 | ||||||||||||
Cash Flows From Operating Activities | ||||||||||||||||
Net income | $ | 517 | $ | 525 | $ | 821 | $ | 803 | ||||||||
Adjustments to reconcile net income to net cash provided by operating activities: | ||||||||||||||||
Depreciation, amortization, decommissioning, and allowance for equity funds used during construction | 870 | 914 | 1,337 | 1,419 | ||||||||||||
Deferred income taxes and tax credits, net | 346 | 102 | 482 | (33 | ) | |||||||||||
Other changes in noncurrent assets and liabilities | 493 | 130 | 87 | 281 | ||||||||||||
Gain on sale of assets | - | (1 | ) | (1 | ) | (1 | ) | |||||||||
Effect of changes in operating assets and liabilities: | ||||||||||||||||
Accounts receivable | (68 | ) | 142 | (181 | ) | (80 | ) | |||||||||
Inventories | (57 | ) | (22 | ) | (153 | ) | (92 | ) | ||||||||
Accounts payable | 121 | (214 | ) | (100 | ) | (322 | ) | |||||||||
Income taxes receivable/payable | 21 | (61 | ) | 177 | 234 | |||||||||||
Regulatory balancing accounts, net | (351 | ) | (483 | ) | (94 | ) | (238 | ) | ||||||||
Other current assets | 431 | 273 | (123 | ) | 120 | |||||||||||
Other current liabilities | (79 | ) | (46 | ) | (68 | ) | 19 | |||||||||
Other | (3 | ) | (23 | ) | (2 | ) | (32 | ) | ||||||||
Net cash provided by operating activities | 2,241 | 1,236 | 2,182 | 2,078 | ||||||||||||
Cash Flows From Investing Activities | ||||||||||||||||
Capital expenditures | (1,712 | ) | (1,320 | ) | (2,691 | ) | (2,035 | ) | ||||||||
Proceeds from sale of assets | 12 | 8 | 21 | 15 | ||||||||||||
Increase in restricted cash | (7 | ) | (13 | ) | (3 | ) | (32 | ) | ||||||||
Proceeds from nuclear decommissioning trust sales | 636 | 548 | 1,121 | 703 | ||||||||||||
Purchases of nuclear decommissioning trust investments | (665 | ) | (606 | ) | (1,161 | ) | (805 | ) | ||||||||
Money market investments (see Note 8) | (62 | ) | - | |||||||||||||
Net cash used in investing activities | (1,736 | ) | (1,383 | ) | (2,775 | ) | (2,l54 | ) | ||||||||
Cash Flows From Financing Activities | ||||||||||||||||
Borrowings under accounts receivable facility and working capital facility | 533 | 600 | ||||||||||||||
Repayments under accounts receivable facility and working capital facility | (250 | ) | (300 | ) | (250 | ) | (300 | ) | ||||||||
(Repayment) issuance of commercial paper, net of $1 million discount in 2008 and $2 million in 2007 | (114 | ) | 109 | |||||||||||||
Net issuance of commercial paper, net of $9 million discount in 2008 and $2 million in 2007 | 524 | 91 | ||||||||||||||
Proceeds from issuance of long-term debt, net of premium, discount, and issuance costs of $2 million in 2008 and $10 million in 2007 | 598 | 690 | 693 | 690 | ||||||||||||
Long-term debt matured, redeemed, or repurchased | (454 | ) | - | |||||||||||||
Long-term debt repurchased | (454 | ) | - | |||||||||||||
Rate reduction bonds matured | - | (143 | ) | - | (217 | ) | ||||||||||
Energy recovery bonds matured | (165 | ) | (160 | ) | (260 | ) | (251 | ) | ||||||||
Common stock issued | 82 | 89 | 150 | 120 | ||||||||||||
Common stock dividends paid | (267 | ) | (242 | ) | (406 | ) | (367 | ) | ||||||||
Other | 17 | 14 | (31 | ) | 38 | |||||||||||
Net cash (used in) provided by financing activities | (553 | ) | 57 | |||||||||||||
Net cash provided by financing activities | 499 | 404 | ||||||||||||||
Net change in cash and cash equivalents | (48 | ) | (90 | ) | (94 | ) | 328 | |||||||||
Cash and cash equivalents at January 1 | 345 | 456 | 345 | 456 | ||||||||||||
Cash and cash equivalents at June 30 | $ | 297 | $ | 366 | ||||||||||||
Cash and cash equivalents at September 30 | $ | 251 | $ | 784 | ||||||||||||
Supplemental disclosures of cash flow information | ||||||||||||||||
Cash paid for: | ||||||||||||||||
Interest (net of amounts capitalized) | $ | 260 | $ | 239 | $ | 449 | $ | 443 | ||||||||
Income taxes paid (refunded), net | (60 | ) | 282 | (146 | ) | 307 | ||||||||||
Supplemental disclosures of noncash investing and financing activities | ||||||||||||||||
Common stock dividends declared but not yet paid | $ | 140 | $ | 128 | $ | 140 | $ | 127 | ||||||||
Capital expenditures financed through accounts payable | 180 | 120 | 224 | 170 | ||||||||||||
See accompanying Notes to the Condensed Consolidated Financial Statements. | See accompanying Notes to the Condensed Consolidated Financial Statements. | See accompanying Notes to the Condensed Consolidated Financial Statements. |
PACIFIC GAS AND ELECTRIC COMPANY | ||||||||||||||||||||||||||||||||
CONDENSED CONSOLIDATED STATEMENTS OF INCOME | CONDENSED CONSOLIDATED STATEMENTS OF INCOME | |||||||||||||||||||||||||||||||
(Unaudited) | (Unaudited) | |||||||||||||||||||||||||||||||
Three Months Ended | Six Months Ended | Three Months Ended | Nine Months Ended | |||||||||||||||||||||||||||||
June 30, | June 30, | September 30, | September 30, | |||||||||||||||||||||||||||||
(in millions) | 2008 | 2007 | 2008 | 2007 | 2008 | 2007 | 2008 | 2007 | ||||||||||||||||||||||||
Operating Revenues | ||||||||||||||||||||||||||||||||
Electric | $ | 2,645 | $ | 2,359 | $ | 5,159 | $ | 4,534 | $ | 2,880 | $ | 2,574 | $ | 8,039 | $ | 7,107 | ||||||||||||||||
Natural gas | 933 | 828 | 2,152 | 2,009 | 794 | 705 | 2,946 | 2,714 | ||||||||||||||||||||||||
Total operating revenues | 3,578 | 3,187 | 7,311 | 6,543 | 3,674 | 3,279 | 10,985 | 9,821 | ||||||||||||||||||||||||
Operating Expenses | ||||||||||||||||||||||||||||||||
Cost of electricity | 1,097 | 884 | 2,124 | 1,607 | 1,282 | 998 | 3,406 | 2,606 | ||||||||||||||||||||||||
Cost of natural gas | 487 | 396 | 1,262 | 1,150 | 351 | 281 | 1,613 | 1,431 | ||||||||||||||||||||||||
Operating and maintenance | 991 | 921 | 2,027 | 1,840 | 982 | 950 | 3,009 | 2,788 | ||||||||||||||||||||||||
Depreciation, amortization, and decommissioning | 418 | 430 | 820 | 859 | 419 | 465 | 1,239 | 1,325 | ||||||||||||||||||||||||
Total operating expenses | 2,993 | 2,631 | 6,233 | 5,456 | 3,034 | 2,694 | 9,267 | 8,150 | ||||||||||||||||||||||||
Operating Income | 585 | 556 | 1,078 | 1,087 | 640 | 585 | 1,718 | 1,671 | ||||||||||||||||||||||||
Interest income | 33 | 35 | 57 | 83 | 20 | 33 | 77 | 116 | ||||||||||||||||||||||||
Interest expense | (178 | ) | (178 | ) | (358 | ) | (360 | ) | (170 | ) | (189 | ) | (528 | ) | (549 | ) | ||||||||||||||||
Other income, net | 7 | 15 | 26 | 24 | ||||||||||||||||||||||||||||
Other income (expense), net | (2 | ) | 13 | 24 | 38 | |||||||||||||||||||||||||||
Income Before Income Taxes | 447 | 428 | 803 | 834 | 488 | 442 | 1,291 | 1,276 | ||||||||||||||||||||||||
Income tax provision | 134 | 154 | 254 | 299 | 167 | 159 | 421 | 458 | ||||||||||||||||||||||||
Net Income | 313 | 274 | 549 | 535 | 321 | 283 | 870 | 818 | ||||||||||||||||||||||||
Preferred stock dividend requirement | 4 | 4 | 7 | 7 | 3 | 4 | 10 | 10 | ||||||||||||||||||||||||
Income Available for Common Stock | $ | 309 | $ | 270 | $ | 542 | $ | 528 | $ | 318 | $ | 279 | $ | 860 | $ | 808 | ||||||||||||||||
See accompanying Notes to the Condensed Consolidated Financial Statements. | See accompanying Notes to the Condensed Consolidated Financial Statements. | See accompanying Notes to the Condensed Consolidated Financial Statements. |
CONDENSED CONSOLIDATED BALANCE SHEETS | ||||||||||||||||
(Unaudited) | (Unaudited) | |||||||||||||||
Balance At | Balance At | |||||||||||||||
(in millions) | June 30, 2008 | December 31, 2007 | September 30, 2008 | December 31, 2007 | ||||||||||||
ASSETS | ||||||||||||||||
Current Assets | ||||||||||||||||
Cash and cash equivalents | $ | 69 | $ | 141 | $ | 57 | $ | 141 | ||||||||
Restricted cash | 1,322 | 1,297 | 1,325 | 1,297 | ||||||||||||
Accounts receivable: | ||||||||||||||||
Customers (net of allowance for doubtful accounts of $59 million in 2008 and $58 million in 2007) | 2,417 | 2,349 | ||||||||||||||
Customers (net of allowance for doubtful accounts of $75 million in 2008 and $58 million in 2007) | 2,530 | 2,349 | ||||||||||||||
Related parties | - | 6 | - | 6 | ||||||||||||
Regulatory balancing accounts | 1,357 | 771 | 1,117 | 771 | ||||||||||||
Inventories: | ||||||||||||||||
Gas stored underground and fuel oil | 251 | 205 | 333 | 205 | ||||||||||||
Materials and supplies | 177 | 166 | 172 | 166 | ||||||||||||
Income taxes receivable | - | 15 | - | 15 | ||||||||||||
Prepaid expenses and other | 468 | 252 | 517 | 252 | ||||||||||||
Total current assets | 6,061 | 5,202 | 6,051 | 5,202 | ||||||||||||
Property, Plant, and Equipment | ||||||||||||||||
Electric | 26,693 | 25,599 | 27,146 | 25,599 | ||||||||||||
Gas | 9,860 | 9,620 | 10,016 | 9,620 | ||||||||||||
Construction work in progress | 1,432 | 1,348 | 1,668 | 1,348 | ||||||||||||
Total property, plant, and equipment | 37,985 | 36,567 | 38,830 | 36,567 | ||||||||||||
Accumulated depreciation | (13,282 | ) | (12,913 | ) | (13,407 | ) | (12,913 | ) | ||||||||
Net property, plant, and equipment | 24,703 | 23,654 | 25,423 | 23,654 | ||||||||||||
Other Noncurrent Assets | ||||||||||||||||
Regulatory assets | 4,300 | 4,459 | 4,233 | 4,459 | ||||||||||||
Nuclear decommissioning funds | 1,914 | 1,979 | 1,819 | 1,979 | ||||||||||||
Related parties receivable | 27 | 23 | 27 | 23 | ||||||||||||
Other | 1,260 | 993 | 1,011 | 993 | ||||||||||||
Total other noncurrent assets | 7,501 | 7,454 | 7,090 | 7,454 | ||||||||||||
TOTAL ASSETS | $ | 38,265 | $ | 36,310 | $ | 38,564 | $ | 36,310 | ||||||||
See accompanying Notes to the Condensed Consolidated Financial Statements. | See accompanying Notes to the Condensed Consolidated Financial Statements. | See accompanying Notes to the Condensed Consolidated Financial Statements. |
PACIFIC GAS AND ELECTRIC COMPANY | ||||||||||||||||
CONDENSED CONSOLIDATED BALANCE SHEETS | ||||||||||||||||
(Unaudited) | (Unaudited) | |||||||||||||||
Balance At | Balance At | |||||||||||||||
(in millions, except share amounts) | June 30, 2008 | December 31, 2007 | September 30, 2008 | December 31, 2007 | ||||||||||||
LIABILITIES AND SHAREHOLDERS' EQUITY | ||||||||||||||||
Current Liabilities | ||||||||||||||||
Short-term borrowings | $ | 156 | $ | 519 | $ | 1,335 | $ | 519 | ||||||||
Long-term debt, classified as current | 600 | - | 600 | - | ||||||||||||
Energy recovery bonds, classified as current | 362 | 354 | 366 | 354 | ||||||||||||
Accounts payable: | ||||||||||||||||
Trade creditors | 1,133 | 1,067 | 962 | 1,067 | ||||||||||||
Disputed claims and customer refunds | 1,588 | 1,629 | 1,588 | 1,629 | ||||||||||||
Related parties | 24 | 28 | 33 | 28 | ||||||||||||
Regulatory balancing accounts | 924 | 673 | 906 | 673 | ||||||||||||
Other | 373 | 370 | 371 | 370 | ||||||||||||
Interest payable | 744 | 697 | 701 | 697 | ||||||||||||
Income taxes payable | 42 | - | 193 | - | ||||||||||||
Deferred income taxes | 234 | 4 | 161 | 4 | ||||||||||||
Other | 1,740 | 1,200 | 1,185 | 1,200 | ||||||||||||
Total current liabilities | 7,920 | 6,541 | 8,401 | 6,541 | ||||||||||||
Noncurrent Liabilities | ||||||||||||||||
Long-term debt | 7,441 | 7,891 | 7,536 | 7,891 | ||||||||||||
Energy recovery bonds | 1,409 | 1,582 | 1,310 | 1,582 | ||||||||||||
Regulatory liabilities | 5,185 | 4,448 | 4,456 | 4,448 | ||||||||||||
Asset retirement obligations | 1,614 | 1,579 | 1,628 | 1,579 | ||||||||||||
Income taxes payable | 82 | 103 | 82 | 103 | ||||||||||||
Deferred income taxes | 3,214 | 3,104 | 3,421 | 3,104 | ||||||||||||
Deferred tax credits | 96 | 99 | 95 | 99 | ||||||||||||
Other | 1,863 | 1,838 | 1,974 | 1,838 | ||||||||||||
Total noncurrent liabilities | 20,904 | 20,644 | 20,502 | 20,644 | ||||||||||||
Commitments and Contingencies | ||||||||||||||||
Shareholders' Equity | ||||||||||||||||
Preferred stock without mandatory redemption provisions: | ||||||||||||||||
Nonredeemable, 5.00% to 6.00%, outstanding 5,784,825 shares | 145 | 145 | 145 | 145 | ||||||||||||
Redeemable, 4.36% to 5.00%, outstanding 4,534,958 shares | 113 | 113 | 113 | 113 | ||||||||||||
Common stock, $5 par value, authorized 800,000,000 shares, issued 283,856,022 shares in 2008 and issued 282,916,485 shares in 2007 | 1,419 | 1,415 | ||||||||||||||
Common stock held by subsidiary, at cost, 19,481,213 shares | (475 | ) | (475 | ) | ||||||||||||
Common stock, $5 par value, authorized 800,000,000 shares, issued 264,374,809 shares in 2008 and issued 282,916,485 shares in 2007 | 1,322 | 1,415 | ||||||||||||||
Common stock held by subsidiary, at cost, 19,481,213 shares in 2007 | - | (475 | ) | |||||||||||||
Additional paid-in capital | 2,269 | 2,220 | 2,150 | 2,220 | ||||||||||||
Reinvested earnings | 5,952 | 5,694 | 5,910 | 5,694 | ||||||||||||
Accumulated other comprehensive income | 18 | 13 | 21 | 13 | ||||||||||||
Total shareholders' equity | 9,441 | 9,125 | 9,661 | 9,125 | ||||||||||||
TOTAL LIABILITIES AND SHAREHOLDERS' EQUITY | $ | 38,265 | $ | 36,310 | $ | 38,564 | $ | 36,310 | ||||||||
See accompanying Notes to the Condensed Consolidated Financial Statements. | See accompanying Notes to the Condensed Consolidated Financial Statements. | See accompanying Notes to the Condensed Consolidated Financial Statements. |
PACIFIC GAS AND ELECTRIC COMPANY | ||||||||||||||||
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS | CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS | |||||||||||||||
(Unaudited) | (Unaudited) | |||||||||||||||
Six Months Ended | Nine Months Ended | |||||||||||||||
June 30, | September 30, | |||||||||||||||
(in millions) | 2008 | 2007 | 2008 | 2007 | ||||||||||||
Cash Flows From Operating Activities | ||||||||||||||||
Net income | $ | 549 | $ | 535 | $ | 870 | $ | 818 | ||||||||
Adjustments to reconcile net income to net cash provided by operating activities: | ||||||||||||||||
Depreciation, amortization, decommissioning and allowance for equity funds used during construction | 870 | 913 | ||||||||||||||
Depreciation, amortization, decommissioning, and allowance for equity funds used during construction | 1,337 | 1,417 | ||||||||||||||
Deferred income taxes and tax credits, net | 316 | 101 | 470 | (35 | ) | |||||||||||
Other changes in noncurrent assets and liabilities | 480 | 129 | 55 | 270 | ||||||||||||
Gain on sale of assets | - | (1 | ) | (1 | ) | (1 | ) | |||||||||
Effect of changes in operating assets and liabilities: | ||||||||||||||||
Accounts receivable | (66 | ) | 143 | (179 | ) | (82 | ) | |||||||||
Inventories | (57 | ) | (22 | ) | (153 | ) | (92 | ) | ||||||||
Accounts payable | 123 | (221 | ) | (85 | ) | (315 | ) | |||||||||
Income taxes receivable/payable | 57 | (59 | ) | 208 | 228 | |||||||||||
Regulatory balancing accounts, net | (351 | ) | (483 | ) | (94 | ) | (238 | ) | ||||||||
Other current assets | 429 | 271 | (125 | ) | 120 | |||||||||||
Other current liabilities | (73 | ) | (48 | ) | (80 | ) | 35 | |||||||||
Other | (3 | ) | (23 | ) | (3 | ) | (32 | ) | ||||||||
Net cash provided by operating activities | 2,274 | 1,235 | 2,220 | 2,093 | ||||||||||||
Cash Flows From Investing Activities | ||||||||||||||||
Capital expenditures | (1,712 | ) | (1,320 | ) | (2,691 | ) | (2,035 | ) | ||||||||
Proceeds from sale of assets | 12 | 8 | 21 | 15 | ||||||||||||
Increase in restricted cash | (7 | ) | (13 | ) | (3 | ) | (32 | ) | ||||||||
Proceeds from nuclear decommissioning trust sales | 636 | 548 | 1,121 | 703 | ||||||||||||
Purchases of nuclear decommissioning trust investments | (665 | ) | (606 | ) | (1,161 | ) | (805 | ) | ||||||||
Net cash used in investing activities | (1,736 | ) | (1,383 | ) | (2,713 | ) | (2,154 | ) | ||||||||
Cash Flows From Financing Activities | ||||||||||||||||
Borrowings under accounts receivable facility and working capital facility | 533 | 600 | ||||||||||||||
Repayments under accounts receivable facility and working capital facility | (250 | ) | (300 | ) | (250 | ) | (300 | ) | ||||||||
(Repayment) issuance of commercial paper, net of discount of $1 million in 2008 and $2 million in 2007 | (114 | ) | 109 | |||||||||||||
Net issuance of commercial paper, net of discount of $9 million in 2008 and $2 million in 2007 | 524 | 91 | ||||||||||||||
Proceeds from issuance of long-term debt, net of premium, discount, and issuance costs of $2 million in 2008 and $10 million in 2007 | 598 | 690 | 693 | 690 | ||||||||||||
Long-term debt matured, redeemed, or repurchased | (454 | ) | - | |||||||||||||
Long-term debt repurchased | (454 | ) | - | |||||||||||||
Rate reduction bonds matured | - | (143 | ) | - | (217 | ) | ||||||||||
Energy recovery bonds matured | (165 | ) | (160 | ) | (260 | ) | (251 | ) | ||||||||
Equity infusion | 50 | 200 | ||||||||||||||
Equity contribution | 90 | 200 | ||||||||||||||
Common stock dividends paid | (284 | ) | (254 | ) | (426 | ) | (381 | ) | ||||||||
Preferred stock dividends paid | (7 | ) | (7 | ) | (10 | ) | (10 | ) | ||||||||
Other | 16 | 21 | (31 | ) | 29 | |||||||||||
Net cash (used in) provided by financing activities | (610 | ) | 156 | |||||||||||||
Net cash provided by financing activities | 409 | 451 | ||||||||||||||
Net change in cash and cash equivalents | (72 | ) | 8 | (84 | ) | 390 | ||||||||||
Cash and cash equivalents at January 1 | 141 | 70 | 141 | 70 | ||||||||||||
Cash and cash equivalents at June 30 | $ | 69 | $ | 78 | ||||||||||||
Cash and cash equivalents at September 30 | $ | 57 | $ | 460 | ||||||||||||
Supplemental disclosures of cash flow information | ||||||||||||||||
Cash paid for: | ||||||||||||||||
Interest (net of amounts capitalized) | $ | 246 | $ | 226 | $ | 436 | $ | 416 | ||||||||
Income taxes paid (refunded), net | (60 | ) | 299 | (138 | ) | 403 | ||||||||||
Supplemental disclosures of noncash investing and financing activities | ||||||||||||||||
Capital expenditures financed through accounts payable | $ | 180 | $ | 120 | $ | 224 | $ | 170 | ||||||||
See accompanying Notes to the Condensed Consolidated Financial Statements. | See accompanying Notes to the Condensed Consolidated Financial Statements. | See accompanying Notes to the Condensed Consolidated Financial Statements. |
PG&E Corporation | Utility | PG&E Corporation | Utility | |||||||||||||||||||||||||||||
Three Months Ended June 30, | Three Months Ended June 30, | Three Months Ended September 30, | Three Months Ended September 30, | |||||||||||||||||||||||||||||
(in millions) | 2008 | 2007 | 2008 | 2007 | 2008 | 2007 | 2008 | 2007 | ||||||||||||||||||||||||
Stock options | $ | - | $ | 2 | $ | - | $ | 1 | $ | 1 | $ | 2 | $ | - | $ | 1 | ||||||||||||||||
Restricted stock | 5 | 5 | 4 | 3 | 5 | 6 | 4 | 4 | ||||||||||||||||||||||||
Performance shares | 10 | 6 | 6 | 4 | - | 15 | - | 10 | ||||||||||||||||||||||||
Total compensation expense (pre-tax) | $ | 15 | $ | 13 | $ | 10 | $ | 8 | $ | 6 | $ | 23 | $ | 4 | $ | 15 | ||||||||||||||||
Total compensation expense (after-tax) | $ | 9 | $ | 8 | $ | 6 | $ | 5 | $ | 4 | $ | 14 | $ | 2 | $ | 9 |
PG&E Corporation | Utility | |||||||||||||||
Six Months Ended June 30, | Six Months Ended June 30, | |||||||||||||||
(in millions) | 2008 | 2007 | 2008 | 2007 | ||||||||||||
Stock options | $ | 1 | $ | 4 | $ | 1 | $ | 2 | ||||||||
Restricted stock | 14 | 13 | 9 | 8 | ||||||||||||
Performance shares | 6 | - | 3 | (1 | ) | |||||||||||
Total compensation expense (pre-tax) | $ | 21 | $ | 17 | $ | 13 | $ | 9 | ||||||||
Total compensation expense (after-tax) | $ | 12 | $ | 10 | $ | 8 | $ | 5 |
PG&E Corporation | Utility | |||||||||||||||
Nine Months Ended September 30, | Nine Months Ended September 30, | |||||||||||||||
(in millions) | 2008 | 2007 | 2008 | 2007 | ||||||||||||
Stock options | $ | 2 | $ | 6 | $ | 1 | $ | 3 | ||||||||
Restricted stock | 19 | 19 | 13 | 12 | ||||||||||||
Performance shares | 8 | 15 | 5 | 9 | ||||||||||||
Total compensation expense (pre-tax) | $ | 29 | $ | 40 | $ | 19 | $ | 24 | ||||||||
Total compensation expense (after-tax) | $ | 17 | $ | 24 | $ | 11 | $ | 14 |
Pension Benefits | Other Benefits | Pension Benefits | Other Benefits | |||||||||||||||||||||||||||||
Three Months Ended June 30, | Three Months Ended June 30, | Three Months Ended September 30, | Three Months Ended September 30, | |||||||||||||||||||||||||||||
(in millions) | 2008 | 2007 | 2008 | 2007 | 2008 | 2007 | 2008 | 2007 | ||||||||||||||||||||||||
Service cost for benefits earned | $ | 59 | $ | 59 | $ | 7 | $ | 7 | $ | 59 | $ | 55 | $ | 7 | $ | 7 | ||||||||||||||||
Interest cost | 144 | 135 | 20 | 20 | 148 | 139 | 21 | 20 | ||||||||||||||||||||||||
Expected return on plan assets | (175 | ) | (177 | ) | (24 | ) | (24 | ) | (173 | ) | (178 | ) | (22 | ) | (23 | ) | ||||||||||||||||
Amortization of transition obligation (1) | - | - | 7 | 6 | - | - | 6 | 7 | ||||||||||||||||||||||||
Amortization of prior service cost (1) | 12 | 12 | 4 | 4 | 12 | 12 | 4 | 3 | ||||||||||||||||||||||||
Amortization of unrecognized gain (1) | - | - | (4 | ) | (3 | ) | ||||||||||||||||||||||||||
Amortization of unrecognized gain/(loss) (1) | 1 | 1 | (3 | ) | (1 | ) | ||||||||||||||||||||||||||
Net periodic benefit cost | $ | 40 | $ | 29 | $ | 10 | $ | 10 | $ | 47 | $ | 29 | $ | 13 | $ | 13 | ||||||||||||||||
(1) In 2007, under SFAS No.158, “Employers’ Accounting for Defined Benefit Pension and Other Postretirement Plans, an amendment of FASB Statements No. 87, 88, 106, and 132(R)” (“SFAS No. 158”), PG&E Corporation and the Utility recorded amounts related to other benefits in other comprehensive income, net of related deferred taxes, except for a portion recorded as a regulatory liability in accordance with SFAS No. 71, “Accounting for the Effects of Certain Types of Regulation,” as amended (“SFAS No. 71”). Other comprehensive income does not include amortization of the amounts related to the defined benefit pension plan, which are recorded as a reduction to the existing pension regulatory liability in accordance with the provisions of SFAS No. 71. | ||||||||||||||||||||||||||||||||
(1) In 2007, under SFAS No.158, “Employers’ Accounting for Defined Benefit Pension and Other Postretirement Plans, an amendment of FASB Statements No. 87, 88, 106, and 132(R)” (“SFAS No. 158”), PG&E Corporation and the Utility recorded amounts related to pension and other benefits in other comprehensive income, net of related deferred taxes, except for a portion recorded as a regulatory liability in accordance with SFAS No. 71, “Accounting for the Effects of Certain Types of Regulation,” as amended (“SFAS No. 71”). | (1) In 2007, under SFAS No.158, “Employers’ Accounting for Defined Benefit Pension and Other Postretirement Plans, an amendment of FASB Statements No. 87, 88, 106, and 132(R)” (“SFAS No. 158”), PG&E Corporation and the Utility recorded amounts related to pension and other benefits in other comprehensive income, net of related deferred taxes, except for a portion recorded as a regulatory liability in accordance with SFAS No. 71, “Accounting for the Effects of Certain Types of Regulation,” as amended (“SFAS No. 71”). |
Pension Benefits | Other Benefits | |||||||||||||||
Nine Months Ended September 30, | Nine Months Ended September 30, | |||||||||||||||
(in millions) | 2008 | 2007 | 2008 | 2007 | ||||||||||||
Service cost for benefits earned | $ | 177 | $ | 173 | $ | 22 | $ | 22 | ||||||||
Interest cost | 436 | 408 | 61 | 59 | ||||||||||||
Expected return on plan assets | (522 | ) | (533 | ) | (70 | ) | (72 | ) | ||||||||
Amortization of transition obligation (1) | - | - | 19 | 19 | ||||||||||||
Amortization of prior service cost (1) | 35 | 37 | 12 | 12 | ||||||||||||
Amortization of unrecognized gain/(loss) (1) | 1 | 2 | (11 | ) | (7 | ) | ||||||||||
Net periodic benefit cost | $ | 127 | $ | 87 | $ | 33 | $ | 33 | ||||||||
(1) In 2007, under SFAS No.158, PG&E Corporation and the Utility recorded amounts related to pension and other benefits in other comprehensive income, net of related deferred taxes, except for a portion recorded as a regulatory liability in accordance with SFAS No. 71. |
Pension Benefits Six Months Ended June 30, | Other Benefits Six Months Ended June 30, | |||||||||||||||
(in millions) | 2008 | 2007 | 2008 | 2007 | ||||||||||||
Service cost for benefits earned | $ | 118 | $ | 118 | $ | 15 | $ | 14 | ||||||||
Interest cost | 287 | 270 | 40 | 40 | ||||||||||||
Expected return on plan assets | (349 | ) | (354 | ) | (47 | ) | (48 | ) | ||||||||
Amortization of transition obligation (1) | - | - | 12 | 12 | ||||||||||||
Amortization of prior service cost (1) | 24 | 24 | 8 | 8 | ||||||||||||
Amortization of unrecognized gain (1) | - | - | (8 | ) | (6 | ) | ||||||||||
Net periodic benefit cost | $ | 80 | $ | 58 | $ | 20 | $ | 20 | ||||||||
(1) In 2007, under SFAS No.158, PG&E Corporation and the Utility recorded amounts related to other benefits in other comprehensive income, net of related deferred taxes, except for a portion recorded as a regulatory liability in accordance with SFAS No. 71. Other comprehensive income does not include amortization of the amounts related to the defined benefit pension plan, which are recorded as a reduction to the existing pension regulatory liability in accordance with the provisions of SFAS No. 71. |
Balance At | Balance At | |||||||||||||||
(in millions) | June 30, 2008 | December 31, 2007 | September 30, 2008 | December 31, 2007 | ||||||||||||
Energy recovery bond regulatory asset | $ | 1,668 | $ | 1,833 | $ | 1,571 | $ | 1,833 | ||||||||
Regulatory assets for deferred income tax | 827 | 732 | ||||||||||||||
Utility retained generation regulatory assets | 909 | 947 | 817 | 947 | ||||||||||||
Regulatory assets for deferred income tax | 788 | 732 | ||||||||||||||
Environmental compliance costs | 335 | 328 | 375 | 328 | ||||||||||||
Unamortized loss, net of gain, on reacquired debt | 261 | 269 | 223 | 269 | ||||||||||||
Regulatory assets associated with plan of reorganization | 110 | 122 | 108 | 122 | ||||||||||||
Contract termination costs | 89 | 96 | 86 | 96 | ||||||||||||
Scheduling coordinator costs | 80 | 90 | 66 | 90 | ||||||||||||
Other | 60 | 42 | 160 | 42 | ||||||||||||
Total regulatory assets | $ | 4,300 | $ | 4,459 | $ | 4,233 | $ | 4,459 |
Balance At | Balance At | |||||||||||||||
(in millions) | June 30, 2008 | December 31, 2007 | September 30, 2008 | December 31, 2007 | ||||||||||||
Cost of removal obligation | $ | 2,650 | $ | 2,568 | $ | 2,694 | $ | 2,568 | ||||||||
Price risk management | 803 | 124 | ||||||||||||||
Employee benefit plans | 621 | 578 | 626 | 578 | ||||||||||||
Asset retirement costs | 455 | 573 | 335 | 573 | ||||||||||||
Public purpose programs | 285 | 264 | 318 | 264 | ||||||||||||
California Solar Initiative | 200 | 159 | 206 | 159 | ||||||||||||
Price risk management | 105 | 124 | ||||||||||||||
Other | 171 | 182 | 172 | 182 | ||||||||||||
Total regulatory liabilities | $ | 5,185 | $ | 4,448 | $ | 4,456 | $ | 4,448 |
Balance At | Balance At | |||||||||||||||
(in millions) | June 30, 2008 | December 31, 2007 | September 30, 2008 | December 31, 2007 | ||||||||||||
Electricity revenue and cost balancing accounts | $ | 1,277 | $ | 678 | $ | 1,059 | $ | 678 | ||||||||
Natural gas revenue and cost balancing accounts | 80 | 93 | 58 | 93 | ||||||||||||
Total | $ | 1,357 | $ | 771 | $ | 1,117 | $ | 771 |
Balance At | Balance At | |||||||||||||||
(in millions) | June 30, 2008 | December 31, 2007 | September 30, 2008 | December 31, 2007 | ||||||||||||
Electricity revenue and cost balancing accounts | $ | 828 | $ | 618 | $ | 795 | $ | 618 | ||||||||
Natural gas revenue and cost balancing accounts | 96 | 55 | 111 | 55 | ||||||||||||
Total | $ | 924 | $ | 673 | $ | 906 | $ | 673 |
PG&E Corporation | Utility | PG&E Corporation | Utility | |||||||||||||
(in millions) | Total Common Shareholders' Equity | Total Shareholders' Equity | Total Common Shareholders' Equity | Total Shareholders' Equity | ||||||||||||
Balance at December 31, 2007 | $ | 8,553 | $ | 9,125 | $ | 8,553 | $ | 9,125 | ||||||||
Net income | 517 | 549 | 821 | 870 | ||||||||||||
Common stock issued | 82 | - | 150 | - | ||||||||||||
Share-based compensation amortization | 15 | - | 21 | - | ||||||||||||
Common stock dividends declared and paid | (139 | ) | (284 | ) | (279 | ) | (426 | ) | ||||||||
Common stock dividends declared but not yet paid | (140 | ) | - | (140 | ) | - | ||||||||||
Preferred stock dividends | - | (7 | ) | - | (10 | ) | ||||||||||
Tax benefit from share-based payment awards | 4 | 3 | 5 | 4 | ||||||||||||
Other comprehensive income | 5 | 5 | 8 | 8 | ||||||||||||
Equity infusion | - | 50 | ||||||||||||||
Balance at June 30, 2008 | $ | 8,897 | $ | 9,441 | ||||||||||||
Equity contribution | - | 90 | ||||||||||||||
Balance at September 30, 2008 | $ | 9,139 | $ | 9,661 |
Three Months Ended | Six Months Ended | Three Months Ended | Nine Months Ended | |||||||||||||||||||||||||||||
June 30, | June 30, | September 30, | September 30, | |||||||||||||||||||||||||||||
(in millions, except per share amounts) | 2008 | 2007 | 2008 | 2007 | 2008 | 2007 | 2008 | 2007 | ||||||||||||||||||||||||
Net income | $ | 293 | $ | 269 | $ | 517 | $ | 525 | $ | 304 | $ | 278 | $ | 821 | $ | 803 | ||||||||||||||||
Less: distributed earnings to common shareholders | 139 | 127 | 278 | 253 | 140 | 127 | 419 | 379 | ||||||||||||||||||||||||
Undistributed earnings | $ | 154 | $ | 142 | $ | 239 | $ | 272 | $ | 164 | $ | 151 | $ | 402 | $ | 424 | ||||||||||||||||
Common shareholders earnings | ||||||||||||||||||||||||||||||||
Basic | ||||||||||||||||||||||||||||||||
Distributed earnings to common shareholders | $ | 139 | $ | 127 | $ | 278 | $ | 253 | $ | 140 | $ | 127 | $ | 419 | $ | 379 | ||||||||||||||||
Undistributed earnings allocated to common shareholders | 146 | 135 | 227 | 258 | 156 | 143 | 382 | 402 | ||||||||||||||||||||||||
Total common shareholders earnings, basic | $ | 285 | $ | 262 | $ | 505 | $ | 511 | $ | 296 | $ | 270 | $ | 801 | $ | 781 | ||||||||||||||||
Diluted | ||||||||||||||||||||||||||||||||
Distributed earnings to common shareholders | $ | 139 | $ | 127 | $ | 278 | $ | 253 | $ | 140 | $ | 127 | $ | 419 | $ | 379 | ||||||||||||||||
Undistributed earnings allocated to common shareholders | 146 | 135 | 227 | 258 | 156 | 143 | 382 | 402 | ||||||||||||||||||||||||
Total common shareholders earnings, diluted | $ | 285 | $ | 262 | $ | 505 | $ | 511 | $ | 296 | $ | 270 | $ | 801 | $ | 781 | ||||||||||||||||
Weighted average common shares outstanding, basic | 356 | 350 | 355 | 350 | 357 | 352 | 356 | 350 | ||||||||||||||||||||||||
9.50% Convertible Subordinated Notes | 19 | 19 | 19 | 19 | 19 | 19 | 19 | 19 | ||||||||||||||||||||||||
Weighted average common shares outstanding and participating securities, basic | 375 | 369 | 374 | 369 | 376 | 371 | 375 | 369 | ||||||||||||||||||||||||
Weighted average common shares outstanding, basic | 356 | 350 | 355 | 350 | 357 | 352 | 356 | 350 | ||||||||||||||||||||||||
Employee share-based compensation | 1 | 2 | 1 | 2 | 1 | 1 | 1 | 2 | ||||||||||||||||||||||||
Weighted average common shares outstanding, diluted | 357 | 352 | 356 | 352 | 358 | 353 | 357 | 352 | ||||||||||||||||||||||||
9.50% Convertible Subordinated Notes | 19 | 19 | 19 | 19 | 19 | 19 | 19 | 19 | ||||||||||||||||||||||||
Weighted average common shares outstanding and participating securities, diluted | 377 | 372 | 376 | 371 | ||||||||||||||||||||||||||||
Net earnings per common share, basic | ||||||||||||||||||||||||||||||||
Distributed earnings, basic (1) | $ | 0.39 | $ | 0.36 | $ | 1.18 | $ | 1.08 | ||||||||||||||||||||||||
Undistributed earnings, basic | 0.44 | 0.41 | 1.07 | 1.15 | ||||||||||||||||||||||||||||
Total | $ | 0.83 | $ | 0.77 | $ | 2.25 | $ | 2.23 | ||||||||||||||||||||||||
Net earnings per common share, diluted | ||||||||||||||||||||||||||||||||
Distributed earnings, diluted | $ | 0.39 | $ | 0.36 | $ | 1.17 | $ | 1.08 | ||||||||||||||||||||||||
Undistributed earnings, diluted | 0.44 | 0.41 | 1.07 | 1.14 | ||||||||||||||||||||||||||||
Total | $ | 0.83 | $ | 0.77 | $ | 2.24 | $ | 2.22 | ||||||||||||||||||||||||
(1) Distributed earnings, basic may differ from actual per share amounts paid as dividends, as the EPS computation under GAAP requires the use of the weighted average, rather than the actual number of, shares outstanding. | (1) Distributed earnings, basic may differ from actual per share amounts paid as dividends, as the EPS computation under GAAP requires the use of the weighted average, rather than the actual number of, shares outstanding. |
Weighted average common shares outstanding and participating securities, diluted | 376 | 371 | 375 | 371 | ||||||||||||
Net earnings per common share, basic | ||||||||||||||||
Distributed earnings, basic (1) | $ | 0.39 | $ | 0.36 | $ | 0.78 | $ | 0.72 | ||||||||
Undistributed earnings, basic | 0.41 | 0.39 | 0.64 | 0.74 | ||||||||||||
Total | $ | 0.80 | $ | 0.75 | $ | 1.42 | $ | 1.46 | ||||||||
Net earnings per common share, diluted | ||||||||||||||||
Distributed earnings, diluted | $ | 0.39 | $ | 0.36 | $ | 0.78 | $ | 0.72 | ||||||||
Undistributed earnings, diluted | 0.41 | 0.38 | 0.64 | 0.73 | ||||||||||||
Total | $ | 0.80 | $ | 0.74 | $ | 1.42 | $ | 1.45 | ||||||||
(1) Distributed earnings, basic may differ from actual per share amounts paid as dividends, as the EPS computation under GAAP requires the use of the weighted average, rather than the actual number of, shares outstanding. |
Total Price Risk Management Derivatives | Price Risk Management Derivatives Designated as Cash Flow Hedges | |||||||||||||||
(in millions) | June 30, 2008(1) | December 31, 2007(2) | June 30, 2008(3) | December 31, 2007(4) | ||||||||||||
Current Assets – Prepaid expenses and other | $ | 307 | $ | 55 | $ | 139 | $ | (2 | )(5) | |||||||
Other Noncurrent Assets – Other | 418 | 171 | 162 | 42 | ||||||||||||
Current Liabilities – Other | 28 | 67 | 9 | 12 | ||||||||||||
Noncurrent Liabilities – Other | 37 | 20 | - | 3 | ||||||||||||
Total Price Risk Management Derivatives | Price Risk Management Derivatives Designated as Cash Flow Hedges | |||||||||||||||
(in millions) | September 30, 2008(1) | December 31, 2007(2) | September 30, 2008(3) | December 31, 2007(4) | ||||||||||||
Current Assets – Prepaid expenses and other | $ | 120 | $ | 55 | $ | 8 | $ | (2 | )(5) | |||||||
Other Noncurrent Assets – Other | 177 | 171 | 18 | 42 | ||||||||||||
Current Liabilities – Other | 88 | 67 | 36 | 12 | ||||||||||||
Noncurrent Liabilities – Other | 117 | 20 | 107 | 3 | ||||||||||||
(1) Balances reflect the allocation of a $220 million cash collateral receivable balance to Current Assets-Prepaid expenses and other for $74 million, $72 million to Other Noncurrent Assets-Other, and $74 million to Current Liabilities-Other in accordance with FIN 39-1. | ||||||||||||||||
(2) Balances reflect the allocation of a $65 million cash collateral receivable balance to Current Assets-Prepaid expenses and other for $3 million, $46 million to Other Noncurrent Assets-Other, and $16 million to Current Liabilities-Other in accordance with FIN 39-1. This collateral was classified as Current Assets-Prepaid expenses and other in the 2007 Annual Report. | ||||||||||||||||
(3) Balances reflect the allocation of a $25 million cash collateral receivable balance to Current Assets-Prepaid expenses and other for $8 million, $7 million to Other Noncurrent Assets-Other, and $10 to Current Liabilities-Other in accordance with FIN 39-1. | ||||||||||||||||
(4) Balances reflect the allocation of a $16 million cash collateral receivable balance to Other Noncurrent Assets-Other for $9 million and $7 million to Current Liabilities-Other in accordance with FIN 39-1. This collateral was classified as Current Assets-Prepaid expenses and other in the 2007 Annual Report. | ||||||||||||||||
(5) $2 million of the cash flow hedges in a liability position at December 31, 2007 relate to counterparties for which the total net derivatives position is a current asset. |
PG&E Corporation | ||||||||||||||||
Fair Value Measurements as of June 30, 2008 | ||||||||||||||||
(in millions) | Level 1 | Level 2 | Level 3 | Total | ||||||||||||
Assets: | ||||||||||||||||
Nuclear Decommissioning Funds(1) | $ | 1,704 | $ | 328 | $ | 7 | $ | 2,039 | ||||||||
Price Risk Management Instruments(2) | 169 | 109 | 382 | 660 | ||||||||||||
Rabbi Trusts(3) | 18 | - | - | 18 | ||||||||||||
Long Term Disability Trust | 25 | - | 95 | 120 | ||||||||||||
Assets Total | $ | 1,916 | $ | 437 | $ | 484 | $ | 2,837 | ||||||||
Liabilities: | ||||||||||||||||
Dividend Participation Rights | $ | - | $ | - | $ | 55 | $ | 55 | ||||||||
Other | - | - | 6 | 6 | ||||||||||||
Liabilities Total | $ | - | $ | - | $ | 61 | $ | 61 | ||||||||
(1) Excludes taxes on appreciation of investment value and cash and cash equivalents. | ||||||||||||||||
(2) Balances include the impact of netting adjustments in accordance with the requirements of FIN 39-1 of $(164) million to Level 1, $(347) million to Level 2, and $(320) million to Level 3. | ||||||||||||||||
(3) Excludes life insurance policies. |
Utility | ||||||||||||||||
Fair Value Measurements as of June 30, 2008 | ||||||||||||||||
(in millions) | Level 1 | Level 2 | Level 3 | Total | ||||||||||||
Assets: | ||||||||||||||||
Nuclear Decommissioning Funds(1) | $ | 1,704 | $ | 328 | $ | 7 | $ | 2,039 | ||||||||
Price Risk Management Instruments(2) | 169 | 109 | 382 | 660 | ||||||||||||
Long-Term Disability Trust | 25 | - | 95 | 120 |
PG&E Corporation | PG&E Corporation | |||||||||||||||||||
Fair Value Measurements as of September 30, 2008 | Fair Value Measurements as of September 30, 2008 | |||||||||||||||||||
(in millions) | Level 1 | Level 2 | Level 3 | Total | ||||||||||||||||
Assets: | ||||||||||||||||||||
Money market investments (held by PG&E Corporation) | $ 192 | $ - | $ 62 | $ 254 | ||||||||||||||||
Nuclear decommissioning trusts(1) | 1,609 | 308 | 7 | 1,924 | ||||||||||||||||
Price risk management instruments(2) | 54 | 4 | 34 | 92 | ||||||||||||||||
Rabbi trusts(3) | 78 | - | - | 78 | ||||||||||||||||
Long-term disability trust | 49 | - | 79 | 128 | ||||||||||||||||
Assets Total | $ | 1,898 | $ | 437 | $ | 484 | $ | 2,819 | $ 1,982 | $ 312 | $ 182 | $ 2,476 | ||||||||
Liabilities: | ||||||||||||||||||||
Dividend participation rights | $ - | $ 49 | $ 49 | |||||||||||||||||
Other | $ | - | $ | - | $ | 6 | $ | 6 | - | 5 | 5 | |||||||||
Liabilities Total | $ | - | $ | - | $ | 6 | $ | 6 | $ - | $ 54 | $ 54 | |||||||||
(1) Excludes taxes on appreciation of investment value and cash and cash equivalents. | ||||||||||||||||||||
(2) Balances include the impact of netting adjustments in accordance with the requirements of FIN 39-1 of $(164) million to Level 1, $(347) million to Level 2, and $(320) million to Level 3. | ||||||||||||||||||||
(1) Excludes taxes on appreciation of investment value. | (1) Excludes taxes on appreciation of investment value. | |||||||||||||||||||
(2) Balances include the impact of netting adjustments in accordance with the requirements of FIN 39-1 of $41 million to Level 1, $26 million to Level 2, and $153 million to Level 3. | (2) Balances include the impact of netting adjustments in accordance with the requirements of FIN 39-1 of $41 million to Level 1, $26 million to Level 2, and $153 million to Level 3. | |||||||||||||||||||
(3) Excludes life insurance policies. | (3) Excludes life insurance policies. |
Utility | |||||||
Fair Value Measurements as of September 30, 2008 | |||||||
(in millions) | Level 1 | Level 2 | Level 3 | Total | |||
Assets: | |||||||
Nuclear decommissioning trusts(1) | $ 1,609 | $ 308 | $ 7 | $ 1,924 | |||
Price risk management instruments(2) | 54 | 4 | 34 | 92 | |||
Long-term disability trust | 49 | - | 79 | 128 | |||
Assets Total | $ 1,712 | $ 312 | $ 120 | $ 2,144 | |||
Liabilities: | |||||||
Other | $ - | $ - | $ 5 | $ 5 | |||
Liabilities Total | $ - | $ - | $ 5 | $ 5 | |||
(1) Excludes taxes on appreciation of investment value. | |||||||
(2) Balances include the impact of netting adjustments in accordance with the requirements of FIN 39-1 of $41 million to Level 1, $26 million to Level 2, and $153 million to Level 3. |
PG&E Corporation | PG&E Corporation | PG&E Corporation | ||||||||||||||||||||||||||||||||||||
(in millions) | Price Risk Management Instruments | Nuclear Decommissioning Funds(3) | Long-term Disability | Dividend Participation Rights | Other | Total | Money Market Investments | Price Risk Management Instruments | Nuclear Decommissioning Trusts (3) | Long-term Disability | Dividend Participation Rights | Other | Total | |||||||||||||||||||||||||
Asset (liability) Balance as of January 1, 2008 | $ | 115 | (1) | $ | 8 | $ | 69 | $ | (68 | )(2) | $ | (4 | ) | $ | 120 | $ - | $ 115(1) | $ 8 | $ 69 | $ (68)(2) | $ (4) | $120 | ||||||||||||||||
Realized and unrealized gains (losses): | ||||||||||||||||||||||||||||||||||||||
Included in earnings | - | - | - | (1 | ) | - | (1 | ) | - | - | - | - | (2) | - | (2) | |||||||||||||||||||||||
Included in regulatory assets and liabilities or balancing accounts | 267 | (1 | ) | (7 | ) | - | (2 | ) | 257 | - | (81) | (1) | (12) | - | (1) | (95) | ||||||||||||||||||||||
Purchases, issuances, and settlements | - | - | 33 | 14 | - | 47 | - | - | - | 22 | 21 | - | 43 | |||||||||||||||||||||||||
Transfers in/out of Level 3 | - | - | - | - | - | - | ||||||||||||||||||||||||||||||||
Asset (liability) Balance as of June 30, 2008 | $ | 382 | $ | 7 | $ | 95 | $ | (55 | ) | $ | (6 | ) | $ | 423 | ||||||||||||||||||||||||
Transfers in (out) of Level 3 | 62 | - | - | - | - | - | 62 | |||||||||||||||||||||||||||||||
Asset (liability) Balance as of September 30, 2008 | $ 62 | $ 34 | $ 7 | $ 79 | $ (49) | $ (5) | $ 128 | |||||||||||||||||||||||||||||||
Earnings for the period were impacted by a $1 million unrealized loss relating to assets or liabilities still held at the reporting date. | ||||||||||||||||||||||||||||||||||||||
Earnings for the period were impacted by a $2 million unrealized loss relating to assets or liabilities still held at September 30, 2008. | Earnings for the period were impacted by a $2 million unrealized loss relating to assets or liabilities still held at September 30, 2008. | |||||||||||||||||||||||||||||||||||||
(1) Includes the impact of the $48 million retrospective adjustment related to the CRRs on January 1, 2008. Additionally, the balance includes the impact of netting adjustments in accordance with the requirements of FIN 39-1 of $6 million. | ||||||||||||||||||||||||||||||||||||||
(2) The discount factor used to value these rights was adjusted on January 1, 2008 in order to comply with the provisions SFAS No. 157, resulting in a $6 million expense to increase the value of the liability. | ||||||||||||||||||||||||||||||||||||||
(3)Excludes taxes on appreciation of investment value and cash and cash equivalents. | ||||||||||||||||||||||||||||||||||||||
(1) Includes the impact of the $48 million retrospective adjustment related to the CRRs on January 1, 2008. Additionally, the balance includes the impact of netting adjustments of $6 million made in accordance with the requirements of FIN 39-1. | (1) Includes the impact of the $48 million retrospective adjustment related to the CRRs on January 1, 2008. Additionally, the balance includes the impact of netting adjustments of $6 million made in accordance with the requirements of FIN 39-1. | |||||||||||||||||||||||||||||||||||||
(2) The discount factor used to value these rights was adjusted on January 1, 2008 in order to comply with the provisions of SFAS No. 157, resulting in a $6 million expense to increase the value of the liability. | (2) The discount factor used to value these rights was adjusted on January 1, 2008 in order to comply with the provisions of SFAS No. 157, resulting in a $6 million expense to increase the value of the liability. | |||||||||||||||||||||||||||||||||||||
(3) Excludes taxes on appreciation of investment value. | (3) Excludes taxes on appreciation of investment value. | |||||||||||||||||||||||||||||||||||||
Utility | Utility | Utility | |||||||||||||||||||||||||
(in millions) | Price Risk Management Instruments | Nuclear Decommissioning Funds(2) | Long-term Disability | Other | Total | Price Risk Management Instruments | Nuclear Decommissioning Trusts (2) | Long-term Disability | Other | Total | |||||||||||||||||
Asset (liability) Balance as of January 1, 2008 | $ | 115 | (1) | $ | 8 | $ | 69 | $ | (4 | ) | $ | 188 | $ 115(1) | $ 8 | $ 69 | $ (4) | $188 | ||||||||||
Realized and unrealized gains (losses): | |||||||||||||||||||||||||||
Included in earnings | - | - | - | - | - | - | - | - | - | - | |||||||||||||||||
Included in regulatory assets and liabilities or balancing accounts | 267 | (1 | ) | (7 | ) | (2 | ) | 257 | (81) | (1) | (12) | (1) | (95) | ||||||||||||||
Purchases, issuances, and settlements | - | - | 33 | - | 33 | - | - | 22 | - | 22 | |||||||||||||||||
Transfers in/out of Level 3 | - | - | - | - | - | ||||||||||||||||||||||
Asset (liability) Balance as of June 30, 2008 | $ | 382 | $ | 7 | $ | 95 | $ | (6 | ) | $ | 478 | ||||||||||||||||
Transfers in (out) of Level 3 | - | - | - | - | - | ||||||||||||||||||||||
Asset (liability) Balance as of September 30, 2008 | $ 34 | $ 7 | $ 79 | $ (5) | $ 115 | ||||||||||||||||||||||
Earnings for the period were not impacted by unrealized gains or (losses) relating to assets or liabilities still held at the reporting date. | |||||||||||||||||||||||||||
Earnings for the period were not impacted by unrealized gains or (losses) relating to assets or liabilities still held at September 30, 2008. | Earnings for the period were not impacted by unrealized gains or (losses) relating to assets or liabilities still held at September 30, 2008. | ||||||||||||||||||||||||||
(1) Includes the impact of the $48 million retrospective adjustment related to the CRRs on January 1, 2008. Additionally, the balance includes the impact of netting adjustments in accordance with the requirements of FIN 39-1 of $6 million. | |||||||||||||||||||||||||||
(2)Excludes taxes on appreciation of investment value and cash and cash equivalents. | |||||||||||||||||||||||||||
(1) Includes the impact of the $48 million retrospective adjustment related to the CRRs on January 1, 2008. Additionally, the balance includes the impact of netting adjustments of $6 million made in accordance with the requirements of FIN 39-1 | (1) Includes the impact of the $48 million retrospective adjustment related to the CRRs on January 1, 2008. Additionally, the balance includes the impact of netting adjustments of $6 million made in accordance with the requirements of FIN 39-1 | ||||||||||||||||||||||||||
(2) Excludes taxes on appreciation of investment value. | (2) Excludes taxes on appreciation of investment value. | ||||||||||||||||||||||||||
PG&E Corporation | PG&E Corporation | PG&E Corporation | |||||||||||||||||||||||||||||||||||
(in millions) | Price Risk Management Instruments | Nuclear Decommissioning Funds(1) | Long-term Disability | Dividend Participation Rights | Other | Total | Money Market Investments | Price Risk Management Instruments | Nuclear Decommissioning Trusts (1) | Long-term Disability | Dividend Participation Rights | Other | Total | ||||||||||||||||||||||||
Asset (liability) Balance as of March 31, 2008 | $ | 299 | $ | 7 | $ | 103 | $ | (63 | ) | $ | (2 | ) | $ | 344 | |||||||||||||||||||||||
Asset (liability) Balance as of June 30, 2008 | $ - | $ 382 | $ 7 | $ 95 | $ (55) | $ (6) | $ 423 | ||||||||||||||||||||||||||||||
Realized and unrealized gains (losses): | |||||||||||||||||||||||||||||||||||||
Included in earnings | - | - | - | 1 | - | 1 | - | - | - | - | (1) | - | (1) | ||||||||||||||||||||||||
Included in regulatory assets and liabilities or balancing accounts | 83 | - | (1 | ) | - | (4 | ) | 78 | - | (348) | - | (5) | - | 1 | (352) | ||||||||||||||||||||||
Purchases, issuances, and settlements | - | - | (7 | ) | 7 | - | - | - | - | - | (11) | 7 | - | (4) | |||||||||||||||||||||||
Transfers in/out of Level 3 | - | - | - | - | - | - | |||||||||||||||||||||||||||||||
Asset (liability) Balance as of June 30, 2008 | $ | 382 | $ | 7 | $ | 95 | $ | (55 | ) | $ | (6 | ) | $ | 423 | |||||||||||||||||||||||
Transfers in (out) of Level 3 | 62 | - | - | - | - | - | 62 | ||||||||||||||||||||||||||||||
Asset (liability) Balance as of September 30, 2008 | $ 62 | $ 34 | $ 7 | $ 79 | $ (49) | $ (5) | $ 128 | ||||||||||||||||||||||||||||||
Earnings for the period were impacted by a $1 million unrealized loss relating to assets or liabilities still held at September 30, 2008. | Earnings for the period were impacted by a $1 million unrealized loss relating to assets or liabilities still held at September 30, 2008. | ||||||||||||||||||||||||||||||||||||
(1) Excludes taxes on appreciation of investment value. | (1) Excludes taxes on appreciation of investment value. | ||||||||||||||||||||||||||||||||||||
Utility | Utility | Utility | ||||||||||||||||||||||||||
(in millions) | Price Risk Management Instruments | Nuclear Decommissioning Funds(1) | Long-term Disability | Other | Total | Price Risk Management Instruments | Nuclear Decommissioning Trusts (1) | Long-term Disability | Other | Total | ||||||||||||||||||
Asset (liability) Balance as of March 31, 2008 | $ | 299 | $ | 7 | $ | 103 | $ | (2 | ) | $ | 407 | |||||||||||||||||
Asset (liability) Balance as of June 30, 2008 | $ 382 | $ 7 | $ 95 | $ (6) | $ 478 | |||||||||||||||||||||||
Realized and unrealized gains (losses): | ||||||||||||||||||||||||||||
Included in earnings | - | - | - | - | - | - | - | - | - | - | ||||||||||||||||||
Included in regulatory assets and liabilities or balancing accounts | 83 | - | (1 | ) | (4 | ) | 78 | (348) | - | (5) | 1 | (352) | ||||||||||||||||
Purchases, issuances, and settlements | - | - | (7 | ) | - | (7 | ) | - | - | (11) | - | (11) | ||||||||||||||||
Transfers in/out of Level 3 | - | - | - | - | - | |||||||||||||||||||||||
Asset (liability) Balance as of June 30, 2008 | $ | 382 | $ | 7 | $ | 95 | $ | (6 | ) | $ | 478 | |||||||||||||||||
Transfers in (out) of Level 3 | - | - | - | - | - | |||||||||||||||||||||||
Asset (liability) Balance as of September 30, 2008 | $ 34 | $ 7 | $ 79 | $ (5) | $ 115 | |||||||||||||||||||||||
Earnings for the period were not impacted by unrealized gains or (losses) relating to assets or liabilities still held at the reporting date. | ||||||||||||||||||||||||||||
Earnings for the period were not impacted by unrealized gains or (losses) relating to assets or liabilities still held at September 30, 2008. | Earnings for the period were not impacted by unrealized gains or (losses) relating to assets or liabilities still held at September 30, 2008. | |||||||||||||||||||||||||||
(1) Excludes taxes on appreciation of investment value and cash and cash equivalents. | ||||||||||||||||||||||||||||
(1) Excludes taxes on appreciation of investment value. | (1) Excludes taxes on appreciation of investment value. | |||||||||||||||||||||||||||
Three Months Ended | Six Months Ended | Receivable (Payable) Balance Outstanding at | Three Months Ended | Nine Months Ended | ||||||||||||||||||||||||||||||||||||
June 30, | June 30, | June 30, | December | September 30, | September 30, | |||||||||||||||||||||||||||||||||||
(in millions) | 2008 | 2007 | 2008 | 2007 | 2008 | 2007 | 2008 | 2007 | 2008 | 2007 | ||||||||||||||||||||||||||||||
Utility revenues from: | ||||||||||||||||||||||||||||||||||||||||
Administrative services provided to PG&E Corporation | $ | 1 | $ | 1 | $ | 2 | $ | 2 | $ | - | $ | 2 | $ | - | $ | 1 | $ | 2 | $ | 3 | ||||||||||||||||||||
Utility employee benefit assets due from PG&E Corporation | - | - | - | - | 27 | 27 | - | - | - | - | ||||||||||||||||||||||||||||||
Interest from PG&E Corporation on employee benefit assets | - | 1 | - | 1 | - | - | - | - | - | 1 | ||||||||||||||||||||||||||||||
Utility expenses from: | ||||||||||||||||||||||||||||||||||||||||
Administrative services received from PG&E Corporation | $ | 34 | $ | 31 | $ | 86 | $ | 83 | ||||||||||||||||||||||||||||||||
Utility employee benefit assets due to PG&E Corporation | 1 | 1 | 2 | 3 |
Administrative services received from PG&E Corporation | $ | 28 | $ | 28 | $ | 52 | $ | 52 | $ | (24 | ) | $ | (28 | ) | ||||||||||
Utility employee benefit assets due to PG&E Corporation | 1 | 1 | 1 | 2 | - | - |
(in millions) | ||||||||
2008 | $ | 1,526 | $ | 565 | ||||
2009 | 2,877 | 2,384 | ||||||
2010 | 2,653 | 2,345 | ||||||
2011 | 2,609 | 2,309 | ||||||
2012 | 2,481 | 2,231 | ||||||
Thereafter | 19,924 | 18,639 | ||||||
Total | $ | 32,070 | $ | 28,473 |
(in millions) | ||||
2008 | $ | 29 | ||
2009 | 50 | |||
2010 | 50 | |||
2011 | 50 | |||
2012 | 50 | |||
Thereafter | 253 | |||
Total fixed capacity payments | 482 | |||
Less: Amount representing interest | (120 | ) | ||
Present value of fixed capacity payments | $ | 362 |
(in millions) | ||||
202008 | $ | 11 | ||
202009 | 50 | |||
202010 | 50 | |||
202011 | 50 | |||
202012 | 50 | |||
Thereafter | 254 | |||
T Total fixed capacity payments | $ | 465 | ||
Less: Amount representing interest | (115 | ) | ||
Present value of fixed capacity payments | $ | 350 |
(in millions) | ||||
2008 | $ | 1,074 | ||
2009 | 915 |
(in millions) | ||||||||
2008 | $ | 429 | ||||||
2009 | 804 | |||||||
2010 | 93 | 93 | ||||||
2011 | 80 | 80 | ||||||
2012 | 49 | 49 | ||||||
Thereafter | 199 | 199 | ||||||
Total | $ | 2,410 | $ | 1,654 |
· | After assumption, the Utility's issuer rating by Moody’s Investors Service (“Moody's”) will be no less than A2 and the Utility's long-term issuer credit rating by Standard and Poor’s Rating Service (“S&P”) will be no less than A. The Utility’s current issuer rating by Moody’s is A3 and the Utility’s long-term issuer credit rating by S&P is BBB+; |
· | The CPUC first makes a finding that the DWR power purchase contracts to be assumed are just and reasonable; and |
· | The CPUC has acted to ensure that the Utility will receive full and timely recovery in its retail electricity rates of all costs associated with the DWR power purchase contracts to be assumed without further review. |
(in millions) | ||||||||
Balance at December 31, 2007 | $ | 30 | $ | 30 | ||||
Additional severance accrued | 15 | 17 | ||||||
Less: Payments | (13 | ) | (18 | ) | ||||
Balance at June 30, 2008 | $ | 32 | ||||||
Balance at September 30, 2008 | $ | 29 |
· | Approximately |
· | Approximately $83 million related to remediation at divested generation facilities; |
· | Approximately |
· | Approximately |
· | The Outcome of Regulatory Proceedings and the Impact of Ratemaking Mechanisms. The amount of the Utility’s revenues and the amount of costs that the Utility is authorized to recover from customers are primarily determined through regulatory proceedings. Most of the Utility’s revenue requirements are set based on its costs of service in proceedings such as the General Rate Case (“GRC”) filed with the CPUC and transmission owner (“TO”) rate cases filed with the FERC. |
· | Capital Structure and Return on Common Equity. On May 29, 2008, the CPUC adopted a new three-year cost of capital mechanism to replace the CPUC’s annual cost of capital proceeding. The Utility’s current authorized capital structure, including a 52% common equity component, will be maintained through 2010. The Utility’s current authorized cost of capital, including a ROE of 11.35% on its electric and natural gas distribution and electric generation rate base, will be maintained through 2010, unless the annual automatic adjustment mechanism established by the CPUC is triggered. The Utility can apply for an adjustment to either the capital structure or cost of capital sooner based on extraordinary circumstances. (See “Regulatory Matters” below.) |
· | The Ability of the Utility to Control Costs While Improving Reliability. The Utility’s revenue requirements are primarily set based on forecasted operating expenses and capital expenditures. The Utility’s revenue requirements are designed to allow the Utility to earn an ROE, as well as to recover depreciation, tax, and interest expense associated with authorized capital expenditures. |
· | The |
· | the Utility’s ability to manage capital expenditures and operating expenses within authorized levels and recover such costs through rates in a timely manner; |
· | the outcome of regulatory proceedings, including pending and future ratemaking proceedings at the CPUC and the FERC; |
· | the adequacy and price of electricity and natural gas supplies, and the ability of the Utility to manage and respond to the volatility of the electricity and natural gas markets; |
· | the effect of weather, storms, earthquakes, fires, floods, disease, other natural disasters, explosions, accidents, mechanical breakdowns, acts of terrorism, and other events or hazards on the Utility’s facilities and operations, its customers, and third parties on which the Utility relies; |
· | the potential impacts of climate change on the Utility’s electricity and natural gas businesses; |
· | changes in customer demand for electricity and natural gas resulting from unanticipated population growth or decline, general economic and financial market conditions, changes in technology, including the development of alternative energy sources, or other reasons; |
· | operating performance of Diablo Canyon, the occurrence of unplanned outages at Diablo Canyon, or the temporary or permanent cessation of operations at Diablo Canyon; |
· | whether the Utility can maintain the cost savings it has recognized from operating efficiencies it has achieved and identify and successfully implement additional sustainable cost-saving measures; |
· | whether the Utility incurs substantial unanticipated expense to improve the safety and reliability of its electric and natural gas |
· | whether the Utility achieves the CPUC’s energy efficiency targets and recognizes any incentives the Utility may earn in a timely manner; |
· | the impact of changes in federal or state laws, or their interpretation, on energy policy and the regulation of utilities and their holding companies; |
· | the impact of changing wholesale electric or gas market rules, including new rules of the California Independent System Operator (“CAISO”) to restructure the California wholesale electricity market; |
· | how the CPUC administers the conditions imposed on PG&E Corporation when it became the Utility’s holding company; |
· | the extent to which PG&E Corporation or the Utility incurs costs and liabilities in connection with litigation that are not recoverable through rates, from insurance, or from other third parties; |
· | the ability of PG&E Corporation, |
· | the impact of environmental laws and regulations and the costs of compliance and remediation; |
· | the effect of municipalization, direct access, community choice aggregation, or other forms of bypass; and |
· | the impact of changes in federal or state tax laws, policies, or regulations. |
Three Months Ended | Six Months Ended | Three Months Ended | Nine Months Ended | |||||||||||||||||||||||||||||
June 30, | June 30, | September 30, | September 30, | |||||||||||||||||||||||||||||
(in millions) | 2008 | 2007 | 2008 | 2007 | 2008 | 2007 | 2008 | 2007 | ||||||||||||||||||||||||
Utility | ||||||||||||||||||||||||||||||||
Electric operating revenues | $ | 2,645 | $ | 2,359 | $ | 5,159 | $ | 4,534 | $ | 2,880 | $ | 2,574 | $ | 8,039 | $ | 7,107 | ||||||||||||||||
Natural gas operating revenues | 933 | 828 | 2,152 | 2,009 | 794 | 705 | 2,946 | 2,714 | ||||||||||||||||||||||||
Total operating revenues | 3,578 | 3,187 | 7,311 | 6,543 | 3,674 | 3,279 | 10,985 | 9,821 | ||||||||||||||||||||||||
Cost of electricity | 1,097 | 884 | 2,124 | 1,607 | 1,282 | 998 | 3,406 | 2,606 | ||||||||||||||||||||||||
Cost of natural gas | 487 | 396 | 1,262 | 1,150 | 351 | 281 | 1,613 | 1,431 | ||||||||||||||||||||||||
Operating and maintenance | 991 | 921 | 2,027 | 1,840 | 982 | 950 | 3,009 | 2,788 | ||||||||||||||||||||||||
Depreciation, amortization, and decommissioning | 418 | 430 | 820 | 859 | 419 | 465 | 1,239 | 1,325 | ||||||||||||||||||||||||
Total operating expenses | 2,993 | 2,631 | 6,233 | 5,456 | 3,034 | 2,694 | 9,267 | 8,150 | ||||||||||||||||||||||||
Operating income | 585 | 556 | 1,078 | 1,087 | 640 | 585 | 1,718 | 1,671 | ||||||||||||||||||||||||
Interest income | 33 | 35 | 57 | 83 | 20 | 33 | 77 | 116 | ||||||||||||||||||||||||
Interest expense | (178 | ) | (178 | ) | (358 | ) | (360 | ) | (170 | ) | (189 | ) | (528 | ) | (549 | ) | ||||||||||||||||
Other income, net(1) | 3 | 11 | 19 | 17 | ||||||||||||||||||||||||||||
Other income (expense), net(1) | (5 | ) | 9 | 14 | 28 | |||||||||||||||||||||||||||
Income before income taxes | 443 | 424 | 796 | 827 | 485 | 438 | 1,281 | 1,266 | ||||||||||||||||||||||||
Income tax provision | 134 | 154 | 254 | 299 | 167 | 159 | 421 | 458 | ||||||||||||||||||||||||
Income available for common stock | $ | 309 | $ | 270 | $ | 542 | $ | 528 | $ | 318 | $ | 279 | $ | 860 | $ | 808 | ||||||||||||||||
PG&E Corporation, Eliminations and Other(2) | ||||||||||||||||||||||||||||||||
Operating revenues | $ | - | $ | - | $ | - | $ | - | $ | - | $ | - | $ | - | $ | - | ||||||||||||||||
Operating expenses | 1 | 1 | 1 | 3 | 1 | 3 | 2 | 6 | ||||||||||||||||||||||||
Operating loss | (1 | ) | (1 | ) | (1 | ) | (3 | ) | (1 | ) | (3 | ) | (2 | ) | (6 | ) | ||||||||||||||||
Interest income | - | 2 | 2 | 6 | 3 | 3 | 5 | 9 | ||||||||||||||||||||||||
Interest expense | (7 | ) | (7 | ) | (14 | ) | (15 | ) | (8 | ) | (7 | ) | (22 | ) | (22 | ) | ||||||||||||||||
Other expense, net | (2 | ) | (1 | ) | (16 | ) | (3 | ) | (12 | ) | (2 | ) | (28 | ) | (6 | ) | ||||||||||||||||
Loss before income taxes | (10 | ) | (7 | ) | (29 | ) | (15 | ) | (18 | ) | (9 | ) | (47 | ) | (25 | ) | ||||||||||||||||
Income tax provision (benefit) | 6 | (6 | ) | (4 | ) | (12 | ) | |||||||||||||||||||||||||
Income tax benefit | (4 | ) | (8 | ) | (8 | ) | (20 | ) | ||||||||||||||||||||||||
Net loss | $ | (16 | ) | $ | (1 | ) | $ | (25 | ) | $ | (3 | ) | $ | (14 | ) | $ | (1 | ) | $ | (39 | ) | $ | (5 | ) | ||||||||
Consolidated Total | ||||||||||||||||||||||||||||||||
Operating revenues | $ | 3,578 | $ | 3,187 | $ | 7,311 | $ | 6,543 | $ | 3,674 | $ | 3,279 | $ | 10,985 | $ | 9,821 | ||||||||||||||||
Operating expenses | 2,994 | 2,632 | 6,234 | 5,459 | 3,035 | 2,697 | 9,269 | 8,156 | ||||||||||||||||||||||||
Operating income | 584 | 555 | 1,077 | 1,084 | 639 | 582 | 1,716 | 1,665 | ||||||||||||||||||||||||
Interest income | 33 | 37 | 59 | 89 | 23 | 36 | 82 | 125 | ||||||||||||||||||||||||
Interest expense | (185 | ) | (185 | ) | (372 | ) | (375 | ) | (178 | ) | (196 | ) | (550 | ) | (571 | ) | ||||||||||||||||
Other income, net(1) | 1 | 10 | 3 | 14 | ||||||||||||||||||||||||||||
Other income (expense), net(1) | (17 | ) | 7 | (14 | ) | 22 | ||||||||||||||||||||||||||
Income before income taxes | 433 | 417 | 767 | 812 | 467 | 429 | 1,234 | 1,241 | ||||||||||||||||||||||||
Income tax provision | 140 | 148 | 250 | 287 | 163 | 151 | 413 | 438 | ||||||||||||||||||||||||
Net income | $ | 293 | $ | 269 | $ | 517 | $ | 525 | $ | 304 | $ | 278 | $ | 821 | $ | 803 | ||||||||||||||||
(1) Includes preferred stock dividend requirement as other expense. | (1) Includes preferred stock dividend requirement as other expense. | (1) Includes preferred stock dividend requirement as other expense. | ||||||||||||||||||||||||||||||
(2) PG&E Corporation eliminates all intercompany transactions in consolidation. | (2) PG&E Corporation eliminates all intercompany transactions in consolidation. | (2) PG&E Corporation eliminates all intercompany transactions in consolidation. |
Three Months Ended | Six Months Ended | Three Months Ended | Nine Months Ended | |||||||||||||||||||||||||||||
June 30, | June 30, | September 30, | September 30, | |||||||||||||||||||||||||||||
(in millions) | 2008 | 2007 | 2008 | 2007 | 2008 | 2007 | 2008 | 2007 | ||||||||||||||||||||||||
Electric revenues | $ | 2,948 | $ | 2,868 | $ | 5,789 | $ | 5,594 | $ | 3,255 | $ | 3,172 | $ | 9,044 | $ | 8,765 | ||||||||||||||||
DWR pass-through revenues(1) | (303 | ) | (509 | ) | (630 | ) | (1,060 | ) | (375 | ) | (598 | ) | (1,005 | ) | (1,658 | ) | ||||||||||||||||
Total electric operating revenues | $ | 2,645 | $ | 2,359 | $ | 5,159 | $ | 4,534 | $ | 2,880 | $ | 2,574 | $ | 8,039 | $ | 7,107 | ||||||||||||||||
Total electricity sales (in Gigawatt hours)(2) | 18,141 | 16,177 | 35,477 | 30,955 | ||||||||||||||||||||||||||||
Total electricity sales (in millions of kWh)(2) | 21,183 | 18,688 | 56,660 | 49,643 | ||||||||||||||||||||||||||||
(1)These are revenues collected on behalf of the DWR for electricity allocated to the Utility’s customers under contracts between the DWR and power suppliers, and are not included in the Utility's Condensed Consolidated Statements of Income. | (1)These are revenues collected on behalf of the DWR for electricity allocated to the Utility’s customers under contracts between the DWR and power suppliers, and are not included in the Utility's Condensed Consolidated Statements of Income. | (1)These are revenues collected on behalf of the DWR for electricity allocated to the Utility’s customers under contracts between the DWR and power suppliers, and are not included in the Utility's Condensed Consolidated Statements of Income. | ||||||||||||||||||||||||||||||
(2)These volumes exclude electricity provided by DWR. | (2)These volumes exclude electricity provided by DWR. | (2)These volumes exclude electricity provided by DWR. |
· | Electricity procurement costs |
· | Electric operating revenues to fund public purpose and energy efficiency programs increased by approximately |
· | Base revenue requirements increased by approximately $26 million in the three months ended |
· | Electric transmission revenues increased by approximately |
· | Other electric operating revenues |
Three Months Ended | Six Months Ended | Three Months Ended | Nine Months Ended | |||||||||||||||||||||||||||||
June 30, | June 30, | September 30, | September 30, | |||||||||||||||||||||||||||||
(in millions) | 2008 | 2007 | 2008 | 2007 | 2008 | 2007 | 2008 | 2007 | ||||||||||||||||||||||||
Cost of purchased power | $ | 1,140 | $ | 892 | $ | 2,178 | $ | 1,620 | $ | 1,334 | $ | 990 | $ | 3,511 | $ | 2,609 | ||||||||||||||||
Proceeds from surplus sales allocated to the Utility | (90 | ) | (46 | ) | (135 | ) | (88 | ) | (90 | ) | (26 | ) | (225 | ) | (112 | ) | ||||||||||||||||
Fuel used in own generation | 47 | 38 | 81 | 75 | 38 | 34 | 120 | 109 | ||||||||||||||||||||||||
Total cost of electricity | $ | 1,097 | $ | 884 | $ | 2,124 | $ | 1,607 | $ | 1,282 | $ | 998 | $ | 3,406 | $ | 2,606 | ||||||||||||||||
Average cost of purchased power per kWh | $ | 0.089 | $ | 0.084 | $ | 0.088 | $ | 0.087 | $ | 0.091 | $ | 0.088 | $ | 0.089 | $ | 0.087 | ||||||||||||||||
Total purchased power (in millions of kWh) | 12,862 | 10,629 | 24,652 | 18,683 | 14,726 | 11,291 | 39,377 | 29,975 |
Three Months Ended | Six Months Ended | Three Months Ended | Nine Months Ended | |||||||||||||||||||||||||||||
June 30, | June 30, | September 30, | September 30, | |||||||||||||||||||||||||||||
(in millions) | 2008 | 2007 | 2008 | 2007 | 2008 | 2007 | 2008 | 2007 | ||||||||||||||||||||||||
Bundled natural gas revenues | $ | 849 | $ | 746 | $ | 1,990 | $ | 1,849 | $ | 709 | $ | 620 | $ | 2,699 | $ | 2,469 | ||||||||||||||||
Transportation service-only revenues | 84 | 82 | 162 | 160 | 85 | 85 | 247 | 245 | ||||||||||||||||||||||||
Total natural gas operating revenues | $ | 933 | $ | 828 | $ | 2,152 | $ | 2,009 | $ | 794 | $ | 705 | $ | 2,946 | $ | 2,714 | ||||||||||||||||
Average bundled revenue per Mcf(1) of natural gas sold | $ | 15.72 | $ | 14.08 | $ | 11.92 | $ | 11.21 | $ | 20.85 | $ | 17.22 | $ | 13.36 | $ | 12.35 | ||||||||||||||||
Total bundled natural gas sales (in millions of Mcf) | 54 | 53 | 167 | 165 | 34 | 36 | 202 | 200 | ||||||||||||||||||||||||
(1) One thousand cubic feet | (1) One thousand cubic feet | (1) One thousand cubic feet |
Three Months Ended | Six Months Ended | |||||||||||||||
June 30, | June 30, | |||||||||||||||
(in millions) | 2008 | 2007 | 2008 | 2007 | ||||||||||||
Cost of natural gas sold | $ | 448 | $ | 354 | $ | 1,202 | $ | 1,060 | ||||||||
Cost of natural gas transportation | 39 | 42 | 60 | 90 | ||||||||||||
Total cost of natural gas | $ | 487 | $ | 396 | $ | 1,262 | $ | 1,150 | ||||||||
Average cost per Mcf of natural gas sold | $ | 8.30 | $ | 6.68 | $ | 7.20 | $ | 6.42 |
Three Months Ended | Nine Months Ended | |||||||||||||||
September 30, | September 30, | |||||||||||||||
(in millions) | 2008 | 2007 | 2008 | 2007 | ||||||||||||
Cost of natural gas sold | $ | 314 | $ | 239 | $ | 1,517 | $ | 1,299 | ||||||||
Cost of natural gas transportation | 37 | 42 | 96 | 132 | ||||||||||||
Total cost of natural gas | $ | 351 | $ | 281 | $ | 1,613 | $ | 1,431 | ||||||||
Average cost per Mcf of natural gas sold | $ | 9.24 | $ | 6.64 | $ | 7.51 | $ | 6.50 | ||||||||
Total natural gas sold (in millions of Mcf) | 34 | 36 | 202 | 200 |
· | Public purpose program and customer energy efficiency incentive program expenses increased by approximately |
· | Costs increased by approximately $38 million during the |
· | Labor costs increased by approximately |
· | There was an increase in maintenance costs of approximately $10 million in the nine months ended September 30, 2008 compared to the same period in 2007 due to the longer duration of the planned outage of Diablo Canyon Unit 2 in 2008 compared to the Diablo Canyon Unit 1 outage in 2007. |
· | Costs related to injuries and damages not specifically related to gas or electric lines of business |
· | |
· | Advertising decreased by approximately |
· | |
· | Costs decreased by approximately $12 million for the nine months ended September 30, 2008 due to a larger increase in accrual in 2007 than in 2008 related to compensation for employees’ missed meals. (See Note 11 of the Notes to the |
· | Costs decreased by approximately |
· | Interest expense decreased by approximately $18 million in the three months ended September 30, 2008, and approximately $16 million in the nine months ended September 30, 2008, primarily due to lower FERC interest rates accrued on the liability for disputed claims.
These decreases were partially offset by The Utility’s interest expense in 2008 and future periods will be impacted by changes in interest rates, as Other Income (Expense), Net The Utility’s other income (expense), net decreased by approximately $14 million, or 156%, in the three months ended September 30, 2008 and $14 million, or 50%, in the nine months ended September 30, 2008 compared to the same periods in 2007. These decreases are primarily due to an increase in costs of approximately $19 million in the three and nine months ended September 30, 2008 due to the Utility’s efforts to oppose the statewide initiative related to renewable energy (Proposition 7) and the City of San Francisco’s municipalization efforts. 45 Income Tax Expense The Utility's income tax expense PG&E Corporation, Eliminations, and Other Operating Revenues and Expenses PG&E Corporation's revenues consist mainly of billings to its affiliates for services rendered, all of which are eliminated in consolidation. PG&E Corporation's operating expenses consist mainly of employee compensation and payments to third parties for goods and services. Generally, PG&E Corporation's operating expenses are allocated to affiliates. These allocations are made without mark-up and are eliminated in consolidation. PG&E Corporation’s interest expense relates to its 9.50% Convertible Subordinated Notes and is not allocated to affiliates. There were no material changes to PG&E Corporation’s operating income in the three and Other Expense, Net PG&E Corporation's other expense increased by approximately Overview PG&E Corporation and the Utility utilize $200 million and $2 billion revolving credit facilities, respectively, along with cash generated from operations, to fund electricity and natural gas purchases on behalf of customers, collateral requirements for commodity contracts and, for short periods of time, capital expenditures, among other things. The level of the Utility's short-term debt fluctuates as a result of seasonal demand for electricity and natural gas, energy commodity costs, collateral requirements, the timing and effect of regulatory decisions and financings, and the amount and timing of capital expenditures, among other factors. The Utility generally utilizes long-term senior unsecured debt and equity issuances, while maintaining its CPUC-authorized capital structure, to fund debt maturities and capital expenditures. PG&E Corporation funds equity contributions to the Utility through the issuance of common stock and long-term debt. Access to the capital markets is essential to the continuation of the Utility’s capital expenditure program. The Utility currently plans to incur additional long-term debt of $3.5 billion to $4.0 billion through the remainder of 2008 and through 2011, excluding the October pollution control bond financing and senior notes issuance discussed below. Of this amount, the Utility expects to incur approximately $1.0 billion of long-term debt within the next six months primarily to finance capital expenditures and to refinance $600 million of long-term debt that will mature in March 2009. In addition, PG&E Corporation expects to issue additional common stock, debt, or other securities to fund a portion of the Utility’s future equity needs through 2011. The recent disruption in the capital markets has made it challenging for companies to access the markets for commercial paper, new credit facilities and unsecured long-term debt. Notwithstanding this volatility, the Utility has continued to have access to the commercial paper market, albeit at higher prices and with shorter duration, and was able to secure a new credit facility to support the pollution control bond financing discussed below. In addition, as discussed below, the Utility was able to issue $600 million of senior unsecured 10-year notes in October 2008. These financings have enabled the Utility to repay its outstanding commercial paper such that the Utility has available liquidity of $1.4 billion as of October 31, 2008, which consists of $1.1 billion of availability under its revolving credit facility and $231 million of unrestricted cash and cash equivalents. PG&E Corporation and the Utility believe that the Utility’s cash flow from operations, existing sources of liquidity, and access to the capital markets on reasonable terms, will provide adequate resources to fund operating activities, meet anticipated obligations, and finance future capital expenditures. The amount and timing of the Utility’s future financing needs will depend on various factors, including: (1) the conditions in the capital markets and the Utility’s ability to access the capital markets; (2) the timing and amount of forecasted capital expenditures, and incremental capital expenditures beyond those currently forecasted, and the ability of the Utility, if necessary, to defer, postpone, or cease certain capital expenditures; (3) the amount of cash internally generated through normal business operations; (4) the amount of collateral required for commodity contract commitments; and (5) the timing of the resolution of the disputed claims and the amount of interest on these claims that the Utility will be required to pay (see Note 10 of the Notes to the Condensed Consolidated Financial Statements). The amount and timing of PG&E Corporation’s future financing needs will depend on various factors, including the need to infuse capital in the Utility to maintain its 52% equity structure and fund capital expenditures. 46 At stand-alone basis had cash and cash equivalents of approximately Each of PG&E Corporation’s and the Utility’s revolving credit facilities include commitments from a well-diversified syndicate of lenders. Neither credit facility permits the lenders to refuse funding a draw solely due to the occurrence of a “material adverse effect” as defined in the facilities. No single lender’s commitment represents more than 11% of total borrowing capacity under either facility. As of As of September 30, 2008, the Utility had On October 21, 2008, the Utility issued $600 million principal amount of In addition to the senior notes issuance, the Utility received $95 million and $309 million from the September 22, 2008 and October 29, 2008 sales of pollution control bonds issued by the California Infrastructure and Economic Development Bank (“CIEDB”) to During the Dividends During the On During the 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
In the In the nine months ended September 30, 2008, net cash provided by operating activities was approximately $2,220 million. For the nine months ended September 30, 2008, net cash provided by operating activities was primarily impacted by net income of $870 million, adjusted for noncash depreciation, amortization, decommissioning and allowance for equity funds used during construction of $1,337 million (see “Results of Operations” above). Additionally, the following changes in
48 The following changes in operating assets and liabilities negatively impacted cash flows during the period:
In the nine months ended September 30, 2007, net cash provided by operating activities was approximately $2,093 million. For the nine months ended September 30, 2007, net cash provided by operating activities was primarily impacted by net income of $818 million, adjusted for noncash depreciation, amortization, decommissioning and allowance for equity funds used during construction of $1,417 million (see “Results of Operations” above). Additionally, increases of approximately $228 million in income tax payable positively impacted cash flows during the nine month period ending September 30, 2007. The following changes in operating assets and liabilities negatively impacted cash flows during the period:
As a result of the resolution of 2001-2004 audits, PG&E Corporation expects to receive a refund of approximately $310 million, excluding interest, in the next several months. Approximately $180 million of the refund will be allocated to the Utility. (See Note 11 of the Notes to the Condensed Consolidated Financial Statements for a discussion of "Tax Matters".) Additionally, future operating cash flow will be impacted by the timing of cash collateral payments and receipts related to price risk management activity, among other 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. The Utility's cash flows from investing activities for the
Net cash used in investing activities increased by approximately 49 Financing Activities The Utility’s cash flows from financing activities for the
In the PG&E Corporation Operating Activities PG&E Corporation's consolidated cash flows from operating activities consist mainly of billings to the Utility for services rendered and payments for employee compensation, and goods and services provided by others to PG&E Corporation. PG&E Corporation also incurs interest costs associated with its debt. PG&E Corporation, on a stand-alone basis, did not have any material cash flow associated with operating activities for the Investing Activities Other than payment of dividends, PG&E Corporation, on a stand-alone basis, did not have any material cash flow associated with investing activities for the Financing Activities PG&E Corporation's primary sources of financing funds, on a stand-alone basis, are dividends from the Utility, equity issuances, and external financing. PG&E Corporation’s uses of cash, on a stand-alone basis, primarily relate to the payment of common stock dividends and common stock repurchases. PG&E Corporation, on a stand-alone basis, did not have any material cash flow associated with financing activities for the 50 PG&E Corporation and the Utility enter into contractual obligations and 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 transportation capacity, natural gas and electricity to support customer demand, and the purchase of fuel and transportation to support the Utility's generation activities. In addition to those commitments disclosed in the 2007 Annual Report and those arising from normal business activities, PG&E Corporation and the Utility’s commitments at million of 6.35% Senior Notes due February 15, On October 21, 2008, the Utility issued $600 million of 8.25% Senior Notes due October 15, 2018. In addition, on October 29, 2008, the California Pollution Control Financing Authority and the CIEDB issued $309 million of pollution control bonds series A through D for the benefit of the Utility. These series of bonds have maturities ranging from 2016 through 2026. (See Notes 4, 5, 10, and 11 of the Notes to the Condensed Consolidated Financial Statements and the 2007 Annual Report for further discussion.) The Utility expects that capital expenditures will total approximately Proposed Electric Distribution Reliability Program (Cornerstone Improvement Program) On May 15, 2008, the Utility requested that the CPUC approve the Utility’s proposed six-year electric distribution reliability improvement program and authorize the Utility to collect revenues to recover forecasted capital expenditures totaling approximately $2.3 billion and operating and maintenance expenses totaling approximately $43 million over the six-year period beginning on January 1, 2009. The amounts requested are incremental to the revenue requirement already authorized by the CPUC in the Utility’s 2007 GRC. The program includes initiatives that are designed to decrease the frequency and duration of electricity outages in order to bring the Utility’s reliability performance closer to that of other investor-owned electric utilities. The Utility expects that the work performed in the six-year program also would provide additional reliability benefits. The Utility proposes to record program costs and related revenue requirements in a separate balancing account so that the revenue requirement increase would be used only to recover costs associated with the proposed initiatives, and to allow the return of unused amounts to customers. The Utility would seek CPUC review and approval to recover any costs that exceed the CPUC’s authorized amount. For the next GRC in 2011, the Utility would provide forecasts that exclude costs related to the proposed reliability improvements. The Utility would continue to record the program costs and related revenue requirements in the balancing account until the GRC following the completion of this program in 2014. The CPUC’s Division of Ratepayer Advocates (“DRA”) and The Utility Reform Network (“TURN”) have objected to the Utility’s request. Among other arguments, the DRA and TURN argue that the Utility’s request should be made in a GRC, that it violates the 2007 GRC settlement, and that the revenue requirement authorized in the 2007 GRC fully funds the reasonable amounts the Utility might need to spend on its electric distribution system. They assert that the Utility’s request raises many issues including: the adequacy of the funding levels approved in the 2007 GRC, the reasonableness of the Utility’s reliability efforts in recent years, the availability of other more appropriate sources of funding between rate cases, including savings in other areas of utility operations, the value of increased reliability to the Utility’s customers, and the need for and efficacy of the Utility’s proposed ratemaking. The Utility filed its response on June 30, 2008, reiterating its position that the proposed program does not violate the 2007 GRC settlement, that the Utility is permitted to seek additional revenue outside of a GRC, and that the factual issues the DRA and TURN cite justify the need for hearings on the Utility’s request. PG&E Corporation and the Utility cannot predict whether the CPUC will approve the Utility’s request. 51 SmartMeter ™ Advanced Metering Project Upgrade The CPUC has previously authorized the Utility to recover approximately $1.4 billion in capital costs in connection with its SmartMeterTM advanced metering project. Of this amount, the Utility has incurred capital expenditures of $504 million through September 30, 2008. The Utility’s request to recover additional expenditures of $572 million, including $463 million of additional capital expenditures to upgrade certain elements of the Utility’s SmartMeterTM program is still pending at the CPUC. On June 30, 2008, the DRA and TURN recommended that the CPUC reject the Utility’s request. In the alternative, the DRA and TURN recommend that the CPUC authorize reduced amounts of $358 million and $324 million, respectively. Neither the DRA nor TURN specified the amount of capital expenditures included in their recommended amounts. On July 23, 2008, the Utility filed a response opposing these recommendations and reaffirming the Utility’s support for On July 31, 2008, the CPUC adopted a decision requiring the Utility to accelerate the deployment of advanced meters and take action to make “dynamic pricing” available to customers in 2010 and 2011. Dynamic pricing will utilize price signals to encourage efficient energy consumption and cost-effective demand response. To meet this accelerated schedule, the Utility will be required to incur additional costs, including costs to design and implement new software and billing systems to integrate the new advanced metering technology. The CPUC has directed the Utility to request recovery of the additional cost required to implement dynamic pricing. The Utility is developing its estimates of the additional costs it will incur to comply with this decision and expects to file a request for cost recovery with the CPUC in early 2009. Colusa Power Plant On June 12, 2008, the CPUC gave its final approval for the Utility to construct the Colusa Project, a 657-megawatt (“MW”) combined cycle generating facility to be located in Colusa County, California after reviewing the final environmental certification issued by the CEC. Final environmental permitting was approved on September 29, 2008 and construction began on October 1, 2008. The Utility’s recovery of costs related to the Colusa Project is subject to the initial capital cost limits of approximately $673 million and operations and maintenance ratemaking previously approved by the CPUC. Subject to meeting operational performance requirements and other conditions, it is anticipated that the Colusa Project will commence operations in 2010. Humboldt Bay Repowering Project On September 24, 2008, the CEC issued its final decision authorizing the construction of the Humboldt Bay Repowering Project ("HBRP"), a 163 MW reciprocating engine electric generating facility to be located in Humboldt County at the site of the Utility's existing Humboldt Bay Power Plant. Demolition of existing structures on the site is complete and construction will commence during November 2008. Subject to meeting operational performance requirements and other conditions, it is anticipated that the HBRP will commence operations in 2010. The Utility’s recovery of costs related to the HBRP is subject to the initial capital cost limits of approximately $239 million and operations and maintenance ratemaking previously approved by the CPUC. Tesla Generating Station On July 18, 2008, the Utility filed an application requesting that the CPUC authorize the Utility to develop and construct a 560-MW generating unit at the Tesla Generating Station, a proposed combined cycle power plant to be located in eastern Alameda County, California. The Utility had requested that the CPUC authorize the Utility to recover up to $850 million of forecasted capital costs associated with the construction of the unit. On September 22, 2008, a CPUC administrative law judge issued a proposed decision which recommends that the Utility’s application be dismissed on the basis that the Utility’s application failed to sufficiently demonstrate that conducting a competitive request for offers (“RFO”) would be infeasible. On October 14, 2008, the Utility filed comments objecting to the proposed decision. The CPUC is expected to issue a final decision by the end of 2008. 52 Request for New Generation Offers and Potential New Utility-Owned Generation On July 21, 2008, the Utility received bids from third parties in response to the Utility’s April 1, 2008 long-term RFO for 800 to 1,200 MW of dispatchable and operationally flexible new generation resources to be on-line no later than May 2015. The Utility is evaluating these offers and plans to develop a shortlist of offers during the fourth quarter of 2008. The Utility’s RFO requested both power purchase agreements and purchase and sale agreements. Under a purchase and sale agreement a new generating facility would be constructed by a third party and then sold to the Utility upon satisfaction of certain contractual requirements. The Utility conducted a similar RFO in 2004-2005 and, as a result of that process, entered into several power purchase agreements with third parties that are contingent on the third party’s development of a new generation facility to provide the power to be purchased by the Utility under the agreement. These agreements were approved by the CPUC in November 2006. Since that time, the development plans for two of the proposed generation facilities have been terminated and the development of a third, the proposed Russell City Energy Center, has been delayed pending CPUC approval of an amendment to the related power purchase agreement. Proposed Electric Transmission Projects The Utility has been exploring the feasibility of obtaining regulatory approval for a potential investment in an electric transmission project that would traverse the Pacific Northwest. On April 17, 2008, the FERC granted part of the Utility’s request for a declaratory order to collect transmission rates designed to provide an incentive to the Utility to continue leading the development of the proposed 1,000-mile, The Utility also has been exploring the development of a new 500-kV electric transmission project, the Central California Clean Energy Transmission line, to increase transmission capacity between northern and southern California and provide needed access to new renewable generation resources. The CAISO has been conducting stakeholder meetings to review the Utility’s proposal and the Utility has been conducting various studies to ensure that the project is designed and located to avoid or minimize potential impacts. Depending on the results of these stakeholder meetings and studies, the Utility will decide whether to request CPUC approval to construct the line. The Utility cannot predict whether the many conditions and challenges to the development of these proposed electric transmission projects will be met. Potential Natural Gas Pipeline Projects PG&E Corporation continues to pursue the development of the proposed 230-mile Pacific Connector Gas Pipeline, along with Fort Chicago Energy Partners, L.P. and Northwest Pipeline Corporation. The development of the Pacific Connector Gas Pipeline is dependent upon the development of the Jordan Cove liquefied natural gas terminal by Fort Chicago Partners, L.P. and the satisfaction of other conditions and requirements. For financing and other business purposes, PG&E Corporation and the Utility maintain certain arrangements that are not reflected in their Condensed Consolidated Balance Sheets. Such arrangements do not represent a significant part of either PG&E Credit Risk The Utility conducts business with wholesale customers and 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 failed to perform on its contractual obligation to deliver electricity, then the Utility may find it necessary to procure electricity at current market prices, which may be higher than the contract prices. Credit-related losses attributable to receivables and electric and gas procurement activities from wholesale customers and counterparties are expected to be recoverable from customers through rates and are not expected to have a material impact on net income. The Utility manages credit risk associated with its wholesale customers and 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 and a detailed credit analysis is performed at least annually. The following table summarizes the Utility's net credit risk exposure to its wholesale customers and counterparties, as well as the Utility's credit risk exposure to its wholesale customers or counterparties with a greater than 10% net credit exposure, at
On September 15, 2008, Lehman Brothers, Inc. filed a petition under Chapter 11 of the U.S. Bankruptcy Code. The Utility's net credit exposure to various Lehman Brothers, Inc. subsidiaries related to price risk management activity was immaterial. PG&E Corporation and the Utility have significant contingencies, The Utility is subject to substantial regulation. Set forth below are matters pending before the CPUC, the resolution of which may affect PG&E Corporation and the Utility's 2008 Cost of Capital Proceeding On May 29, 2008, the CPUC adopted a uniform three-year cost of capital mechanism in the second phase of the 2008 Cost of Capital proceeding for the Utility and the other two California investor-owned electric utilities that will replace the annual cost of capital proceeding. Under the adopted mechanism, the utilities are required to file full cost of capital applications by April 20 of every third year, beginning on April 20, 2010. Under the decision, the Utility’s 2008 cost of capital (including an 11.35% ROE) will be maintained through 2010, unless the automatic adjustment mechanism described below is triggered. The Utility’s 2008 capital structure (including a 52% equity component) is authorized through 2010. The decision permits the utilities to apply for an adjustment to either the cost of capital or the capital structure sooner based on extraordinary circumstances. The cost of capital mechanism uses an interest rate index (the 12-month October through September average of the Moody's Investors Service utility bond index) to trigger changes in the authorized cost of debt, preferred stock, and equity. In any year in which the 12-month October through September average for the index increases or decreases by more than 100 basis points 54 Spent Nuclear Fuel Storage Proceeding As a consequence of the U.S. Department of Energy’s (“DOE”) failure to develop a permanent national repository for spent nuclear fuel and high-level radioactive waste produced by the nation's nuclear electric generation facilities, the Utility has been storing spent nuclear fuel and high-level radioactive waste resulting from its nuclear operations at Diablo Canyon in on-site storage pools. The Utility believes that the existing spent fuel pools at Diablo Canyon have sufficient capacity to enable the Utility to operate Diablo Canyon until October 2010 for Unit 1 and May 2011 for Unit 2. In addition, the Utility is constructing a dry cask storage facility at Diablo Canyon to store spent nuclear fuel. The construction of this dry cask storage facility, along with modifications to the power plant to support dry cask storage processing, is not expected to be completed until late 2008 with the initial movement of spent nuclear fuel to dry cask storage beginning in June 2009. If the Utility is unable to complete the facility and load spent fuel into the dry cask storage facility by October 2010 for Unit 1 or May 2011 for Unit 2, the Utility would have to curtail or halt operations in the unit until such time as additional safe storage for spent fuel is made available. On In addition, on PG&E Corporation and the Utility are unable to predict the outcome of any rehearing petition. Energy Efficiency Programs and Incentive Ratemaking On November 4, 2008, a proposed decision was issued by the CPUC 55 The alternate proposed decision recommends that the CPUC grant the petition in part and award the Utility interim incentive earnings for 2006-2007 program accomplishments of $59.3 million in 2008 (50% of approximately $119 million) and hold back the remaining 50%. The alternate proposed decision recommends that the interim claims to be submitted in It is On July 21, 2008, the Utility filed its application seeking CPUC approval of the Utility’s energy efficiency programs and funding of $1.87 billion for the 2009-2011 cycle of energy efficiency programs. The CPUC has authorized bridge funding for the Utility to continue offering its existing programs in 2009 until the CPUC issues its final decision on the 2009-2011 energy efficiency application, which is expected in mid-2009. On July 31, 2008, the CPUC issued a decision indicating that The amount of any shareholder incentives the Utility may receive Application to Recover Hydroelectric Generation Facility Divestiture Costs On April 14, 2008, the Utility filed an application with the CPUC requesting authorization to recover approximately $47 million, including $12.2 million of interest, of the costs it incurred in connection with the Utility’s efforts to determine the market value of its hydroelectric generation facilities in 2000 and 2001. These efforts were undertaken at the direction of the CPUC in preparation for the planned divestiture of the facilities to further the development of a competitive generation market in California. In 2003, the CPUC determined that the amount of these costs at the time, $34.8 million, was reasonable and authorized the Utility to track these costs and seek authorization to recover these costs in the future if the hydroelectric generation facilities were ultimately not divested. The Utility continues to own its hydroelectric generation assets. On May 19, 2008, the DRA filed a protest to the Utility’s application. On On Also, on September 30, 2008, the FERC accepted the Utility’s TO rate case that was filed on July 30, 2008 requesting an increase in retail base revenue requirement, to $849 million, and 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, financing arrangements, the marketplace for electricity, natural gas, electricity 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. For a comprehensive discussion of PG&E Corporation’s market risk, see the section entitled “Risk Management Activities” in the 2007 Annual Report. Price Risk Electric Transmission Congestion Rights Among other features, the CAISO’s Market Redesign and Technology Upgrade (“MRTU”) initiative provides that electric transmission congestion costs and credits will be determined between any two locations and charged to the market participants, including load serving entities, 56 The Utility has been allocated and has acquired via auction certain CRRs as of Natural Gas Transportation and Storage The Utility uses value-at-risk to measure the 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 Convertible Subordinated Notes At In accordance with Statement 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 57 The preparation of Condensed Consolidated Financial Statements in accordance with accounting principles generally accepted in the United States of America 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. The accounting policies described below are considered 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. Actual results may differ substantially from these estimates. These policies and their key characteristics are discussed in detail in the 2007 Annual Report. They include:
On January 1, 2008, PG&E Corporation and the Utility adopted the provisions of SFAS No. 157, (see “New Accounting Policies” below and Note 2 and Note 8 of the Notes to the Condensed Consolidated Financial Statements for further discussion), which are also considered critical accounting policies. Additionally, PG&E Corporation and the Utility adopted the provisions of Financial Accounting Standards Board (“FASB”) Staff Position on Interpretation 39, “Amendment of FASB Interpretation No. 39” For the period ended Fair Value Measurements On January 1, 2008, PG&E Corporation and the Utility adopted the provisions of SFAS No. 157. SFAS No. 157 establishes a fair value hierarchy that prioritizes inputs to valuation techniques used to measure fair value. The objective of a fair value measurement is to determine the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date, or the “exit price.” The hierarchy gives the highest priority to unadjusted quoted prices in active markets for identical assets or liabilities (Level 1 measurements) and the lowest priority to unobservable inputs (Level 3 measurements). Assets and liabilities are classified based on the lowest level of input that is significant to the fair value measurement. (See Notes 2 and 8 of the Notes to the Condensed Consolidated Financial Statements for further discussion on SFAS No. 157.) Level 3 Instruments at Fair Value As Level 3 measurements are based on unobservable inputs, significant judgment may be used in the valuation of these instruments. Accordingly, the following table sets forth the fair values of instruments classified as Level 3 within the fair value hierarchy, along with a brief description of the valuation technique for each type of instrument:
58 Level 3 fair value measurements represent Money Market Investments PG&E Corporation invests in AAA-rated money market funds that seek to maintain a stable net asset value. These funds invest in high quality, short-term, diversified money market instruments, such as treasury bills, federal agency securities, certificates of deposit and commercial paper with a maximum weighted average maturity of 60 days or less. PG&E Corporation’s investments in these money market funds are generally valued based on observable inputs such as expected yield and credit quality and are thus classified as Level 1 instruments. Approximately $192 million held in money market funds are recorded as Cash and cash equivalents in PG&E Corporation’s Condensed Consolidated Balance Sheets. As of September 30, 2008, PG&E Corporation classified approximately $62 million invested in one money market fund as a Level 3 instrument because the fund manager imposed restrictions on fund participants’ redemption requests. PG&E Corporation’s investment in this money market fund, previously recorded as Cash and cash equivalents, is recorded as Prepaid expenses and other in PG&E Corporation’s Condensed Consolidated Balance Sheets. (In October 2008, PG&E Corporation received an initial redemption amount of approximately $32 million from the money market fund.) Nuclear Decommissioning The nuclear decommissioning Price Risk Management Instruments The price risk management instrument category is comprised of physical and financial derivative contracts including futures, forwards, options, and swaps that are both exchange-traded and over-the-counter (“OTC”) traded contracts. When necessary, PG&E Corporation and the Utility generally use similar models to value similar instruments. Since the Utility’s contracts are used within the regulatory framework, regulatory accounts are recorded to offset the associated gains and losses of these derivatives, which will be reflected in future rates. The Level 3 price risk management instruments 59
All options (exchange-traded and OTC) are valued using the Black’s Option Pricing Model and classified as Level 3 measurements primarily due to volatility inputs. The Utility receives implied volatility for options traded on exchanges which may be adjusted to incorporate the specific terms of the Utility’s contracts, such as strike price or location. CRRs, FTRs, and demand response contracts are new and/or complex instruments that have immature or limited markets. CRRs allow market participants, including The remaining Level 3 price risk management instruments are OTC derivative instruments that are valued using pricing models based on the net present value of estimated future cash flows based on broker quotations. The Utility receives multiple non-binding broker quotes for certain locations which are generally averaged for valuation purposes. In certain circumstances, broker quotes may be interpolated or Dividend Participation Rights The dividend participation rights Nonperformance Risk In accordance with SFAS No. 157, PG&E Corporation and the Utility incorporate the risk of nonperformance into the valuation of their fair value measurements. Nonperformance risk adjustments on the Utility’s price risk management instruments are based on current market inputs when available, such as credit default swaps spreads. When such information is not available, internal models may be used. The nonperformance risk adjustment for the net price risk management instruments contributed less than 1% of the value on June 30, 2008 and increased to approximately 1% of the value on September 30, 2008. As the Utility’s contracts are used within the regulatory framework, the nonperformance risk adjustments are recorded to regulatory accounts and do not impact earnings. See Notes 2 and 8 of the Notes to the Condensed Consolidated Financial Statements for further discussion on other new accounting policies. Disclosures about Derivative Instruments and Hedging Activities - an amendment of In March 2008, the FASB issued SFAS No. 161, “Disclosures about Derivative Instruments and Hedging ITEM 3: QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK PG&E Corporation and the Utility's primary market risk results from changes in energy prices. PG&E Corporation and the Utility engage in price risk management activities for non-trading purposes only. Both PG&E Corporation and the Utility may engage in these price risk management activities using forward contracts, futures, options, and swaps to hedge the impact of market fluctuations on energy commodity prices and interest rates (see the “Risk Management Activities” above under Item 2: Management's Discussion and Analysis of Financial Condition and Results of Operations). ITEM 4: CONTROLS AND PROCEDURES Based on an evaluation of PG&E Corporation and the Utility's disclosure controls and procedures as of There were no changes in internal controls over financial reporting that occurred during the quarter ended PART II. OTHER INFORMATION ITEM 1. LEGAL PROCEEDINGS Solano County District Attorney’s Office For more information regarding the resolution of this matter, see The discussion of the Utility’s efforts to store spent nuclear fuel appearing in the 2007 Annual Report under the heading “Management’s Discussion and Analysis of Financial Condition and Results of Operations – Risk Factors” under the following caption “The operation and decommissioning of the Utility's nuclear power plants expose it to potentially significant liabilities and capital expenditures that it may not be able to recover from its insurance or other source, adversely affecting its financial condition, results of operations, and cash flow” is updated as follows to reflect the new date that the Utility expects it will begin loading spent fuel into the dry cask storage facility: Because the U.S. Department of Energy has failed to develop a permanent national repository for the nation's spent nuclear fuel and high-level radioactive waste produced by the nation's nuclear electric generation facilities, the Utility has been storing spent nuclear fuel and high-level radioactive waste resulting from its nuclear operations at Diablo Canyon nuclear generating facilities (“Diablo Canyon”) in on-site storage pools. The Utility believes that the existing spent fuel pools at Diablo Canyon have sufficient capacity to enable the Utility to operate Diablo Canyon until October 2010 for Unit 1 and May 2011 for Unit 2. The Utility is also constructing a dry cask storage facility at Diablo Canyon to store spent nuclear fuel which it expects to complete by the end of 2008. Although the Utility expected to begin loading spent nuclear fuel in 2008, the Utility currently expects that the dry cask storage facility and modifications to the power plant to support dry cask storage processing will be completed in late 2008 and that the initial movement of spent nuclear fuel into dry storage will begin in June 2009. If the Utility is unable to complete the facility and load spent fuel into the dry cask storage facility by October 2010 for Unit 1 or May 2011 for Unit 2, the Utility would have to curtail or halt operations of the unit until such time as additional safe storage for spent fuel is made available. The discussion In addition, if the Utility were unable to access the capital markets, the Utility may need to consider additional options, such as decreasing or suspending dividend payments to PG&E Corporation. PG&E Corporation also would need to consider its alternatives, such as contributing capital to the Utility to enable the Utility to fulfill its obligation to serve. These alternatives would be evaluated in the context of market conditions then-prevailing, prudent financial management, and any applicable regulatory requirements. During the On
Ratio of Earnings to Fixed Charges and Ratio of Earnings to Combined Fixed Charges and Preferred Stock Dividends The Utility's earnings to fixed charges ratio for the three and
Pursuant to the requirements of the Securities Exchange Act of 1934, the registrants have duly caused this Quarterly Report on Form 10-Q to be signed on their behalf by the undersigned thereunto duly authorized.
Dated: EXHIBIT INDEX
|