UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
FORM 10-Q
| [X] | QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 |
For the quarterly period ended June 30, 2008 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 of incorporation, address of principal executive offices, telephone number | I.R.S. Employer Identification Number |
| 1-16305 | PUGET ENERGY, INC. A Washington Corporation 10885 NE 4th Street, Suite 1200 Bellevue, Washington 98004-5591 (425) 454-6363 | 91-1969407 |
| 1-4393 | PUGET SOUND ENERGY, INC. A Washington Corporation 10885 NE 4th Street, Suite 1200 Bellevue, Washington 98004-5591 (425) 454-6363 | 91-0374630 |
Indicate by check mark whether the registrants: (1) have 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 registrants were required to file such reports), and (2) have been subject to such filing requirements for the past 90 days.
| Puget Energy, Inc. | Yes | /X/ | No | / / | Puget Sound Energy, Inc. | Yes | /X/ | No | / / |
Indicate by check mark whether registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer or a smaller reporting company. See definition of “large accelerated filer, accelerated filer and smaller reporting company” in Rule 12b-2 of the Exchange Act.
| Puget Energy, Inc. | Large accelerated filer | /X/ | Accelerated filer | / / | Non-accelerated filer | / / | Smaller reporting company | / / |
| Puget Sound Energy, Inc. | Large accelerated filer | / / | Accelerated filer | / / | Non-accelerated filer | /X/ | Smaller reporting company | / / |
Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act)
| Puget Energy, Inc. | Yes | / / | No | /X/ | Puget Sound Energy, Inc. | Yes | / / | No | /X/ |
As of August 1, 2008, (i) the number of shares of Puget Energy, Inc. common stock outstanding was 129,678,489 ($.01 par value) and (ii) all of the outstanding shares of Puget Sound Energy, Inc. common stock were held by Puget Energy, Inc.
Table of Contents
| Puget Energy, Inc. | ||
| Puget Sound Energy, Inc. | ||
| Combined Notes to Consolidated Financial Statements | ||
| AFUDC | Allowance for Funds Used During Construction |
| ALJ | Administrative Law Judge |
| BPA | Bonneville Power Administration |
| CAISO | California Independent System Operator |
| Consortium | Infrastructure investors led by Macquarie Infrastructure Partners, the Canada Pension Plan Investment Board and British Columbia Investment Management Corporation, and also includes Alberta Investment Management, Macquarie-FSS Infrastructure Trust and Macquarie Capital Group Limited |
| DOR | Montana Department of Revenue |
| EITF | Emerging Issues Task Force |
| EPA | U. S. Environmental Protection Agency |
| ERO | FERC-certified Electric Reliability Organization |
| FASB | Financial Accounting Standards Board |
| FERC | Federal Energy Regulatory Commission |
| FIN | Financial Accounting Standards Board Interpretation |
| FSP | FASB Staff Position |
| GAAP | Generally Accepted Accounting Principles |
| InfrastruX | InfrastruX Group, Inc. |
| kW | Kilowatt |
| kWh | Kilowatt Hour |
| LIBOR | London Interbank Offered Rate |
| MMS | Mineral Management Service of the United States |
| MW | Megawatt (one MW equals one thousand kW) |
| MWh | Megawatt Hour (one MWh equals one thousand kWh) |
| NERC | North American Electric Reliability Corporation |
| Ninth Circuit | United States Court of Appeals for the Ninth Circuit |
| NPNS | Normal Purchase Normal Sale |
| PCA | Power Cost Adjustment |
| PCORC | Power Cost Only Rate Case |
| PGA | Purchased Gas Adjustment |
| PSE | Puget Sound Energy, Inc. |
| PSE Funding | PSE Funding, Inc. |
| Puget Energy | Puget Energy, Inc. |
| PURPA | Public Utility Regulatory Policy Act |
| REP | BPA Residential Exchange Program |
| SFAS | Statement of Financial Accounting Standards |
| Sumas | Sumas Cogeneration Company, L.P. |
| Tenaska | Tenaska Power Fund, L.P. |
| Washington Commission | Washington Utilities and Transportation Commission |
| WECC | Western Electricity Coordinating Council |
| WECO | Western Energy Co |
This Report on Form 10-Q is a combined Quarterly Report filed separately by two different registrants, Puget Energy, Inc. (Puget Energy) and Puget Sound Energy, Inc. (PSE). Any references in this report to the “Company” are to Puget Energy and PSE collectively. PSE makes no representation as to the information contained in this report relating to Puget Energy and the subsidiaries of Puget Energy other than PSE and its subsidiaries.
Puget Energy and PSE are including the following cautionary statements in this Form 10-Q to make applicable and to take advantage of the safe harbor provisions of the Private Securities Litigation Reform Act of 1995 for any forward-looking statements made by or on behalf of Puget Energy or PSE. This report includes forward-looking statements, which are statements of expectations, beliefs, plans, objectives and assumptions of future events or performance. Words or phrases such as “anticipates,” “believes,” “estimates,” “expects,” “future,” “intends,” “plans,” “predicts,” “projects,” “will likely result,” “will continue” or similar expressions identify forward-looking statements.
Forward-looking statements involve risks and uncertainties that could cause actual results or outcomes to differ materially from those expressed. Puget Energy’s and PSE’s expectations, beliefs and projections are expressed in good faith and are believed by Puget Energy and PSE, as applicable, to have a reasonable basis, including without limitation management’s examination of historical operating trends, data contained in records and other data available from third parties. However, there can be no assurance that Puget Energy’s and PSE’s expectations, beliefs or projections will be achieved or accomplished.
In addition to other factors and matters discussed elsewhere in this report, some important factors that could cause actual results or outcomes for Puget Energy and PSE to differ materially from those discussed in forward-looking statements include:
| · | Governmental policies and regulatory actions, including those of the Federal Energy Regulatory Commission (FERC) and the Washington Utilities and Transportation Commission (Washington Commission), with respect to allowed rates of return, cost recovery, industry and rate structures, transmission and generation business structures within PSE, acquisition and disposal of assets and facilities, operation, maintenance and construction of electric generating facilities, operation of distribution and transmission facilities (natural gas and electric), licensing of hydroelectric operations and natural gas storage facilities, recovery of other capital investments, recovery of power and natural gas costs, recovery of regulatory assets and present or prospective wholesale and retail competition; | |
| · | Failure to comply with FERC or Washington Commission standards and/or rules, which could result in penalties based on the discretion of either commission; | |
| · | Failure to comply with electric reliability standards developed by the North American Electric Reliability Corporation (NERC) for users, owners and operators of the power system, which could result in penalties of up to $1.0 million per day per violation; | |
| · | Changes in, adoption of, and compliance with, laws and regulations, including decisions and policies concerning the environment, climate change, emissions, natural resources, and fish and wildlife (including the Endangered Species Act); | |
| · | The ability to recover costs arising from changes in enacted federal, state or local tax laws through revenue in a timely manner; | |
| · | Changes in tax law, related regulations, or differing interpretation or enforcement of applicable law by the Internal Revenue Service (IRS) or other taxing jurisdiction, which could have a material adverse impact on the financial statements; | |
| · | Natural disasters, such as hurricanes, windstorms, earthquakes, floods, fires and landslides, which can interrupt service and/or cause temporary supply disruptions and/or price spikes in the cost of fuel and raw materials and impose extraordinary costs; | |
| · | Commodity price risks associated with procuring natural gas and power in wholesale markets; | |
| · | Wholesale market disruption, which may result in a deterioration of market liquidity, increase the risk of counterparty default, affect the regulatory and legislative process in unpredictable ways, negatively affect wholesale energy prices and/or impede PSE’s ability to manage its energy portfolio risks and procure energy supply, affect the availability and access to capital and credit markets and/or impact delivery of energy to PSE from its suppliers; | |
| · | Financial difficulties of other energy companies and related events, which may affect the regulatory and legislative process in unpredictable ways and also adversely affect the availability of and access to capital and credit markets and/or impact delivery of energy to PSE from it suppliers; | |
| · | The effect of wholesale market structures (including, but not limited to, regional market designs or transmission organizations) or other related federal initiatives; | |
| · | PSE electric or natural gas distribution system failure, which may impact PSE’s ability to deliver energy supply to its customers; | |
| · | Changes in weather conditions in the Pacific Northwest, which could have effects on customer usage and PSE’s revenues, thus impacting net income; | |
| · | Weather, which can have a potentially serious impact on PSE’s ability to procure adequate supplies of natural gas, fuel or purchased power to serve its customers and on the cost of procuring such supplies; | |
| · | Variable hydro conditions, which can impact streamflow and PSE’s ability to generate electricity from hydroelectric facilities; | |
| · | Plant outages, which can have an adverse impact on PSE’s expenses with respect to repair costs, added costs to replace energy or higher costs associated with dispatching a more expensive resource; | |
| · | The ability of natural gas or electric plant to operate as intended; | |
| · | The ability to renew contracts for electric and natural gas supply and the price of renewal; | |
| · | Blackouts or large curtailments of transmission systems, whether PSE’s or others’, which can affect PSE’s ability to deliver power or natural gas to its customers and generating facilities; | |
| · | The ability to restart generation following a regional transmission disruption; | |
| · | Failure of the interstate natural gas pipeline delivering to PSE’s system, which may impact PSE’s ability to adequately deliver natural gas supply or electric power to its customers; | |
| · | The amount of collection, if any, of PSE’s receivables from the California Independent System Operator (CAISO) and other parties and the amount of refunds found to be due from PSE to the CAISO or other parties; | |
| · | Industrial, commercial and residential growth and demographic patterns in the service territories of PSE; | |
| · | General economic conditions in the Pacific Northwest, which might impact customer consumption or affect PSE’s accounts receivable; | |
| · | The loss of significant customers or changes in the business of significant customers or the condemnation of PSE’s facilities, which may result in changes in demand for PSE’s services; | |
| · | The impact of acts of God, terrorism, flu pandemic or similar significant events; | |
| · | Capital market conditions, including changes in the availability of capital or interest rate fluctuations; | |
| · | Employee workforce factors, including strikes, work stoppages, availability of qualified employees or the loss of a key executive; | |
| · | The ability to obtain insurance coverage and the cost of such insurance; | |
| · | The ability to maintain effective internal controls over financial reporting and operational processes; and | |
| · | With respect to merger transactions Puget Energy announced on October 26, 2007: | |
| § | The risk that the merger may not be consummated in a timely manner if at all, including due to the failure to receive any required regulatory approvals; | |
| § | The risk that the merger agreement may be terminated in circumstances that require Puget Energy to pay a termination fee of up to $40.0 million, plus out-of-pocket expenses of the acquiring entity and its members of up to $10.0 million (or if no termination fee is payable, up to $15.0 million); and | |
| § | The effect of the announcement of the merger on our business relationships, operating results and business generally, including our ability to retain key employees. | |
Any forward-looking statement speaks only as of the date on which such statement is made, and, except as required by law, Puget Energy and PSE undertake no obligation to update any forward-looking statement to reflect events or circumstances after the date on which such statement is made or to reflect the occurrence of unanticipated events. New factors emerge from time to time and it is not possible for management to predict all such factors, nor can it assess the impact of any such factor on the business or the extent to which any factor, or combination of factors, may cause results to differ materially from those contained in any forward-looking statement. You are also advised to consult Item 1A-“Risk Factors” in the Company’s most recent annual report on Form 10-K.
CONSOLIDATED STATEMENTS OF INCOME
(Dollars in thousands except per share amounts)
(Unaudited)
Three Months Ended June 30, | Six Months Ended June 30, | |||||||||||||||
| 2008 | 2007 | 2008 | 2007 | |||||||||||||
| Operating revenues: | ||||||||||||||||
| Electric | $ | 478,038 | $ | 435,261 | $ | 1,084,172 | $ | 962,880 | ||||||||
| Gas | 233,840 | 225,175 | 677,077 | 692,184 | ||||||||||||
| Other | 526 | 702 | 2,088 | 9,979 | ||||||||||||
| Total operating revenues | 712,404 | 661,138 | 1,763,337 | 1,665,043 | ||||||||||||
| Operating expenses: | ||||||||||||||||
| Energy costs: | ||||||||||||||||
| Purchased electricity | 198,886 | 172,757 | 471,718 | 454,849 | ||||||||||||
| Electric generation fuel | 32,687 | 23,726 | 79,701 | 49,784 | ||||||||||||
| Residential exchange | (20,298 | ) | (17,562 | ) | (20,305 | ) | (52,040 | ) | ||||||||
| Purchased gas | 137,718 | 139,055 | 413,913 | 449,702 | ||||||||||||
| Net unrealized (gain) loss on derivative instruments | (2,364 | ) | 1,536 | (2,277 | ) | (4,246 | ) | |||||||||
| Utility operations and maintenance | 116,449 | 98,935 | 228,613 | 197,106 | ||||||||||||
| Non-utility expense and other | 1,597 | 2,768 | 2,062 | 4,898 | ||||||||||||
| Merger related costs | 5,738 | -- | 7,049 | -- | ||||||||||||
| Depreciation and amortization | 76,322 | 65,832 | 151,688 | 135,441 | ||||||||||||
| Conservation amortization | 15,525 | 8,749 | 28,891 | 19,078 | ||||||||||||
| Taxes other than income taxes | 63,674 | 63,294 | 157,947 | 150,363 | ||||||||||||
| Total operating expenses | 625,934 | 559,090 | 1,519,000 | 1,404,935 | ||||||||||||
| Operating income | 86,470 | 102,048 | 244,337 | 260,108 | ||||||||||||
| Other income (deductions): | ||||||||||||||||
| Other income | 8,073 | 6,223 | 14,917 | 10,987 | ||||||||||||
| Other expense | (841 | ) | (2,829 | ) | (1,817 | ) | (3,861 | ) | ||||||||
| Interest charges: | ||||||||||||||||
| AFUDC | 1,782 | 2,943 | 4,211 | 5,361 | ||||||||||||
| Interest expense | (48,543 | ) | (52,192 | ) | (99,591 | ) | (103,453 | ) | ||||||||
| Income from continuing operations before income taxes | 46,941 | 56,193 | 162,057 | 169,142 | ||||||||||||
| Income tax expense | 13,287 | 17,593 | 48,590 | 51,480 | ||||||||||||
| Income from continuing operations | 33,654 | 38,600 | 113,467 | 117,662 | ||||||||||||
| Income from discontinued segment (net of tax) | -- | 12 | -- | 12 | ||||||||||||
| Net income | $ | 33,654 | $ | 38,612 | $ | 113,467 | $ | 117,674 | ||||||||
| Common shares outstanding weighted-average (in thousands) | 129,417 | 116,659 | 129,427 | 116,567 | ||||||||||||
| Diluted shares outstanding weighted-average (in thousands) | 129,967 | 117,158 | 129,862 | 117,115 | ||||||||||||
| Basic earnings per common share | $ | 0.26 | $ | 0.33 | $ | 0.88 | $ | 1.01 | ||||||||
| Basic earnings per common share from discontinued operations | -- | -- | -- | -- | ||||||||||||
| Basic earnings per common share | $ | 0.26 | $ | 0.33 | $ | 0.88 | $ | 1.01 | ||||||||
| Diluted earnings per common share | $ | 0.26 | $ | 0.33 | $ | 0.87 | $ | 1.00 | ||||||||
| Diluted earnings per common share from discontinued operations | -- | -- | -- | -- | ||||||||||||
| Diluted earnings per common share | $ | 0.26 | $ | 0.33 | $ | 0.87 | $ | 1.00 | ||||||||
The accompanying notes are an integral part of the financial statements.
CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME
(Dollars in thousands)
(Unaudited)
Three Months Ended June 30, | Six Months Ended June 30, | |||||||||||||||
| 2008 | 2007 | 2008 | 2007 | |||||||||||||
| Net income | $ | 33,654 | $ | 38,612 | $ | 113,467 | $ | 117,674 | ||||||||
| Other comprehensive income: | ||||||||||||||||
| Unrealized gain from pension and postretirement plans, net of tax of $227, $642, $322 and $1,285, respectively | 422 | 1,193 | 598 | 2,386 | ||||||||||||
| Net unrealized gains (losses) on energy derivative instruments during the period, net of tax of $60,710, $(7,465), $86,167 and $(5,551), respectively | 112,747 | (13,863 | ) | 160,024 | (10,309 | ) | ||||||||||
| Reversal of net unrealized gains (losses) on energy derivative instruments settled during the period, net of tax of $(1,802), $(585), $(845) and $1,068, respectively | (3,347 | ) | (1,086 | ) | (1,569 | ) | 1,984 | |||||||||
| Amortization of financing cash flow hedge contracts to earnings, net of tax of $43, $43, $86 and $86, respectively | 79 | 79 | 159 | 159 | ||||||||||||
| Other comprehensive income (loss) | 109,901 | (13,677 | ) | 159,212 | (5,780 | ) | ||||||||||
| Comprehensive income | $ | 143,555 | $ | 24,935 | $ | 272,679 | $ | 111,894 | ||||||||
The accompanying notes are an integral part of the financial statements.
CONSOLIDATED BALANCE SHEETS
(Dollars in thousands)
ASSETS
June 30, 2008 (Unaudited) | December 31, 2007 | |||||||
Utility plant: (at original cost, including construction work in progress of $273,147 and $267,595 respectively) | ||||||||
| Electric plant | $ | 6,048,918 | $ | 5,914,127 | ||||
| Gas plant | 2,392,306 | 2,313,477 | ||||||
| Common plant | 524,198 | 506,211 | ||||||
| Less: Accumulated depreciation and amortization | (3,203,484 | ) | (3,091,176 | ) | ||||
| Net utility plant | 5,761,938 | 5,642,639 | ||||||
| Other property and investments: | ||||||||
| Investment in Bonneville Exchange Power contract | 31,739 | 33,503 | ||||||
| Other property and investments | 115,302 | 114,083 | ||||||
| Total other property and investments | 147,041 | 147,586 | ||||||
| Current assets: | ||||||||
| Cash | 69,092 | 40,797 | ||||||
| Restricted cash | 13,015 | 4,793 | ||||||
| Accounts receivable, net of allowance for doubtful accounts | 160,019 | 218,781 | ||||||
| Secured pledged accounts receivable | 115,000 | 152,000 | ||||||
| Unbilled revenues | 106,202 | 210,025 | ||||||
| Materials and supplies, at average cost | 62,755 | 62,114 | ||||||
| Fuel and gas inventory, at average cost | 85,653 | 99,772 | ||||||
| Unrealized gain on derivative instruments | 247,684 | 17,130 | ||||||
| Prepaid income tax | 274 | 44,303 | ||||||
| Prepaid expense and other | 10,327 | 11,910 | ||||||
| Deferred income taxes | -- | 4,011 | ||||||
| Total current assets | 870,021 | 865,636 | ||||||
| Other long-term and regulatory assets: | ||||||||
| Regulatory asset for deferred income taxes | 96,716 | 104,928 | ||||||
| Regulatory asset for PURPA buyout costs | 124,974 | 140,520 | ||||||
| Power cost adjustment mechanism | -- | 3,114 | ||||||
| Other regulatory assets | 480,784 | 510,998 | ||||||
| Unrealized gain on derivative instruments | 199,368 | 11,845 | ||||||
| Other | 163,307 | 171,470 | ||||||
| Total other long-term and regulatory assets | 1,065,149 | 942,875 | ||||||
| Total assets | $ | 7,844,149 | $ | 7,598,736 | ||||
The accompanying notes are an integral part of the financial statements.
PUGET ENERGY, INC.
CONSOLIDATED BALANCE SHEETS
(Dollars in thousands)
CAPITALIZATION AND LIABILITIES
June 30, 2008 (Unaudited) | December 31, 2007 | |||||||
| Capitalization: | ||||||||
| Common shareholders’ investment: | ||||||||
| Common stock $0.01 par value, 250,000,000 shares authorized, 129,678,489 and 129,678,489 shares outstanding, respectively | $ | 1,297 | $ | 1,297 | ||||
| Additional paid-in capital | 2,273,942 | 2,278,500 | ||||||
| Earnings reinvested in the business | 282,860 | 240,079 | ||||||
| Accumulated other comprehensive income, net of tax | 152,870 | 2,078 | ||||||
| Total shareholders’ equity | 2,710,969 | 2,521,954 | ||||||
| Redeemable securities and long-term debt: | ||||||||
| Preferred stock subject to mandatory redemption | 1,889 | 1,889 | ||||||
| Junior subordinated notes | 250,000 | 250,000 | ||||||
| Long-term debt | 2,278,860 | 2,428,860 | ||||||
| Total redeemable securities and long-term debt | 2,530,749 | 2,680,749 | ||||||
| Total capitalization | 5,241,718 | 5,202,703 | ||||||
| Current liabilities: | ||||||||
| Accounts payable | 258,524 | 310,398 | ||||||
| Short-term debt | 286,566 | 260,486 | ||||||
| Current maturities of long-term debt | 179,500 | 179,500 | ||||||
| Accrued expenses: | ||||||||
| Purchased gas liability | 26,764 | 77,864 | ||||||
| Taxes | 73,994 | 84,756 | ||||||
| Salaries and wages | 27,186 | 28,516 | ||||||
| Interest | 42,709 | 45,133 | ||||||
| Unrealized loss on derivative instruments | 8,546 | 27,089 | ||||||
| Deferred income taxes | 16,923 | -- | ||||||
| Other | 81,904 | 48,918 | ||||||
| Total current liabilities | 1,002,616 | 1,062,660 | ||||||
| Long-term liabilities and regulatory liabilities: | ||||||||
| Deferred income taxes | 908,752 | 818,161 | ||||||
| Unrealized loss on derivative instruments | 9,843 | -- | ||||||
| Power cost adjustment mechanism | 1,252 | -- | ||||||
| Regulatory liabilities | 203,382 | 210,311 | ||||||
| Other deferred credits | 476,586 | 304,901 | ||||||
| Total long-term liabilities and regulatory liabilities | 1,599,815 | 1,333,373 | ||||||
| Total capitalization and liabilities | $ | 7,844,149 | $ | 7,598,736 | ||||
The accompanying notes are an integral part of the financial statements.
CONSOLIDATED STATEMENTS OF CASH FLOWS
(Dollars in thousands, Unaudited)
Six Months Ended June 30, | ||||||||
| 2008 | 2007 | |||||||
| Operating activities: | ||||||||
| Net income | $ | 113,467 | $ | 117,674 | ||||
| Adjustments to reconcile net income to net cash provided by operating activities: | ||||||||
| Depreciation and amortization | 151,688 | 135,441 | ||||||
| Conservation amortization | 28,891 | 19,078 | ||||||
| Deferred income taxes and tax credits, net | 41,565 | 19,809 | ||||||
| Power cost adjustment mechanism | 4,366 | 2,788 | ||||||
| Amortization of gas pipeline capacity assignment | (5,257 | ) | (5,411 | ) | ||||
| Non cash return on regulatory assets | (4,972 | ) | (3,517 | ) | ||||
| Net unrealized loss on derivative instruments | (2,277 | ) | (4,246 | ) | ||||
| Change in residential exchange program | 32,473 | (25,673 | ) | |||||
| Storm damage deferred costs | (173 | ) | (16,359 | ) | ||||
| Other | (709 | ) | (7,047 | ) | ||||
| Cash receipt from lease purchase option settlement | -- | 18,909 | ||||||
| Change in certain current assets and liabilities: | ||||||||
| Accounts receivable and unbilled revenue | 199,586 | 195,971 | ||||||
| Materials and supplies | (642 | ) | (16,635 | ) | ||||
| Fuel and gas inventory | 14,119 | 19,945 | ||||||
| Prepaid income taxes | 44,029 | 5,266 | ||||||
| Prepayments and other | 1,583 | (25,730 | ) | |||||
| Purchased gas receivable/payable | (51,100 | ) | 81,425 | |||||
| Accounts payable | (46,347 | ) | (168,806 | ) | ||||
| Taxes payable | (10,762 | ) | 8,404 | |||||
| Accrued expenses and other | (1,740 | ) | (5,382 | ) | ||||
| Net cash provided by operating activities | 507,788 | 345,904 | ||||||
| Investing activities: | ||||||||
| Construction and capital expenditures - excluding equity AFUDC | (255,776 | ) | (375,677 | ) | ||||
| Energy efficiency expenditures | (26,963 | ) | (18,464 | ) | ||||
| Restricted cash | (8,222 | ) | (91 | ) | ||||
| Refundable cash received for customer construction projects | 4,491 | 9,179 | ||||||
| Cash proceeds from property sales | 2,079 | 93 | ||||||
| Other | (4,084 | ) | 1,301 | |||||
| Net cash used by investing activities | (288,475 | ) | (383,659 | ) | ||||
| Financing activities: | ||||||||
| Change in short-term debt and leases, net | 26,080 | (38,201 | ) | |||||
| Dividends paid | (64,838 | ) | (52,653 | ) | ||||
| Issuance of common stock | -- | 3,510 | ||||||
| Long term bond issued | -- | 250,000 | ||||||
| Redemption of trust preferred stock | -- | (37,750 | ) | |||||
| Redemption of bonds, notes and leases | (150,000 | ) | (100,000 | ) | ||||
| Issuance and redemption costs of bonds and other | (2,260 | ) | 1,247 | |||||
| Net cash (used) provided by financing activities | (191,018 | ) | 26,153 | |||||
| Net increase (decrease) in cash | 28,295 | (11,602 | ) | |||||
| Cash at beginning of year | 40,797 | 28,117 | ||||||
| Cash at end of period | $ | 69,092 | $ | 16,515 | ||||
| Supplemental cash flow information: | ||||||||
| Cash payments for interest (net of capitalized interest) | $ | 101,286 | $ | 91,666 | ||||
| Cash payments (refunds) from income taxes | (42,392 | ) | 23,000 | |||||
The accompanying notes are an integral part of the financial statements.
CONSOLIDATED STATEMENTS OF INCOME
(Dollars in thousands)
(Unaudited)
Three Months Ended June 30, | Six Months Ended June 30, | |||||||||||||||
| 2008 | 2007 | 2008 | 2007 | |||||||||||||
| Operating revenues: | ||||||||||||||||
| Electric | $ | 478,038 | $ | 435,261 | $ | 1,084,172 | $ | 962,880 | ||||||||
| Gas | 233,840 | 225,175 | 677,077 | 692,184 | ||||||||||||
| Other | 526 | 702 | 2,088 | 9,979 | ||||||||||||
| Total operating revenues | 712,404 | 661,138 | 1,763,337 | 1,665,043 | ||||||||||||
| Operating expenses: | ||||||||||||||||
| Energy costs: | ||||||||||||||||
| Purchased electricity | 198,886 | 172,757 | 471,718 | 454,849 | ||||||||||||
| Electric generation fuel | 32,687 | 23,726 | 79,701 | 49,784 | ||||||||||||
| Residential exchange | (20,298 | ) | (17,562 | ) | (20,305 | ) | (52,040 | ) | ||||||||
| Purchased gas | 137,718 | 139,055 | 413,913 | 449,702 | ||||||||||||
| Net unrealized (gain) loss on derivative instruments | (2,364 | ) | 1,536 | (2,277 | ) | (4,246 | ) | |||||||||
| Utility operations and maintenance | 116,449 | 98,935 | 228,608 | 197,106 | ||||||||||||
| Non-utility expense and other | 1,657 | 2,609 | 1,713 | 4,576 | ||||||||||||
| Depreciation and amortization | 76,322 | 65,832 | 151,688 | 135,441 | ||||||||||||
| Conservation amortization | 15,525 | 8,749 | 28,891 | 19,078 | ||||||||||||
| Taxes other than income taxes | 63,674 | 63,294 | 157,947 | 150,363 | ||||||||||||
| Total operating expenses | 620,256 | 558,931 | 1,511,597 | 1,404,613 | ||||||||||||
| Operating income | 92,148 | 102,207 | 251,740 | 260,430 | ||||||||||||
| Other income (deductions): | ||||||||||||||||
| Other income | 8,068 | 6,223 | 14,878 | 10,985 | ||||||||||||
| Other expense | (841 | ) | (2,829 | ) | (1,818 | ) | (3,861 | ) | ||||||||
| Interest charges: | ||||||||||||||||
| AFUDC | 1,782 | 2,943 | 4,211 | 5,361 | ||||||||||||
| Interest expense | (48,543 | ) | (52,192 | ) | (99,591 | ) | (103,453 | ) | ||||||||
| Interest expense on Puget Energy note | (209 | ) | (340 | ) | (446 | ) | (674 | ) | ||||||||
| Income before income taxes | 52,405 | 56,012 | 168,974 | 168,788 | ||||||||||||
| Income tax expense | 13,295 | 17,654 | 48,960 | 51,652 | ||||||||||||
| Net income | $ | 39,110 | $ | 38,358 | $ | 120,014 | $ | 117,136 | ||||||||
The accompanying notes are an integral part of the financial statements.
CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME
(Dollars in thousands)
(Unaudited)
Three Months Ended June 30, | Six Months Ended June 30, | |||||||||||||||
| 2008 | 2007 | 2008 | 2007 | |||||||||||||
| Net income | $ | 39,110 | $ | 38,358 | $ | 120,014 | $ | 117,136 | ||||||||
| Other comprehensive income: | ||||||||||||||||
| Unrealized gain from pension and postretirement plans, net of tax of $277, $642, $322 and $1,285, respectively | 422 | 1,193 | 598 | 2,386 | ||||||||||||
| Net unrealized gains (losses) on energy derivative instruments during the period, net of tax of $60,710, $(7,465), $86,167 and $(5,551), respectively | 112,747 | (13,863 | ) | 160,024 | (10,309 | ) | ||||||||||
| Reversal of net unrealized gains (losses) on energy derivative instruments settled during the period, net of tax of $(1,802), $(858), $(845) and $1,068, respectively | (3,347 | ) | (1,086 | ) | (1,569 | ) | 1,984 | |||||||||
| Amortization of financing cash flow hedge contracts to earnings, net of tax of $43, $43, $86 and $86, respectively | 79 | 79 | 159 | 159 | ||||||||||||
| Other comprehensive income | 109,901 | (13,677 | ) | 159,212 | (5,780 | ) | ||||||||||
| Comprehensive income | $ | 149,011 | $ | 24,681 | $ | 279,226 | $ | 111,356 | ||||||||
The accompanying notes are an integral part of the financial statements.
CONSOLIDATED BALANCE SHEETS
(Dollars in thousands)
ASSETS
June 30, 2008 (Unaudited) | December 31, 2007 | |||||||
| Utility plant: (at original cost, including construction work in progress of $273,147 and $267,595, respectively) | ||||||||
| Electric plant | $ | 6,048,918 | $ | 5,914,127 | ||||
| Gas plant | 2,392,306 | 2,313,477 | ||||||
| Common plant | 524,198 | 506,211 | ||||||
| Less: Accumulated depreciation and amortization | (3,203,484 | ) | (3,091,176 | ) | ||||
| Net utility plant | 5,761,938 | 5,642,639 | ||||||
| Other property and investments: | ||||||||
| Investment in Bonneville Exchange Power contract | 31,739 | 33,503 | ||||||
| Other property and investments | 115,302 | 114,083 | ||||||
| Total other property and investments | 147,041 | 147,586 | ||||||
| Current assets: | ||||||||
| Cash | 68,979 | 40,773 | ||||||
| Restricted cash | 13,015 | 798 | ||||||
| Accounts receivable, net of allowance for doubtful accounts | 163,205 | 219,345 | ||||||
| Secured pledged accounts receivable | 115,000 | 152,000 | ||||||
| Unbilled revenues | 106,202 | 210,025 | ||||||
| Materials and supplies, at average cost | 62,755 | 62,114 | ||||||
| Fuel and gas inventory, at average cost | 85,653 | 99,772 | ||||||
| Unrealized gain on derivative instruments | 247,684 | 17,130 | ||||||
| Prepaid income taxes | 274 | 41,814 | ||||||
| Prepaid expenses and other | 9,782 | 11,365 | ||||||
| Deferred income taxes | -- | 4,011 | ||||||
| Total current assets | 872,549 | 859,147 | ||||||
| Other long-term and regulatory assets: | ||||||||
| Regulatory asset for deferred income taxes | 96,716 | 104,928 | ||||||
| Regulatory asset for PURPA buyout costs | 124,974 | 140,520 | ||||||
| Power cost adjustment mechanism | -- | 3,114 | ||||||
| Other regulatory assets | 480,784 | 512,103 | ||||||
| Unrealized gain on derivative instruments | 199,368 | 11,845 | ||||||
| Other | 163,307 | 170,328 | ||||||
| Total other long-term and regulatory assets | 1,065,149 | 942,838 | ||||||
| Total assets | $ | 7,846,677 | $ | 7,592,210 | ||||
The accompanying notes are an integral part of the financial statements.
PUGET SOUND ENERGY, INC.
CONSOLIDATED BALANCE SHEETS
(Dollars in thousands)
CAPITALIZATION AND LIABILITIES
June 30, 2008 (Unaudited) | December 31, 2007 | |||||||
| Capitalization: | ||||||||
| Common shareholder’s investment: | ||||||||
| Common stock ($10 stated value) - 150,000,000 shares authorized, 85,903,791 shares outstanding | $ | 859,038 | $ | 859,038 | ||||
| Additional paid-in capital | 1,294,694 | 1,297,076 | ||||||
| Earnings reinvested in the business | 379,064 | 345,899 | ||||||
| Accumulated other comprehensive income, net of tax | 152,870 | 2,078 | ||||||
| Total shareholder’s equity | 2,685,666 | 2,504,091 | ||||||
| Redeemable securities and long-term debt: | ||||||||
| Preferred stock subject to mandatory redemption | 1,889 | 1,889 | ||||||
| Junior subordinated notes | 250,000 | 250,000 | ||||||
| Long-term debt | 2,278,860 | 2,428,860 | ||||||
| Total redeemable securities and long-term debt | 2,530,749 | 2,680,749 | ||||||
| Total capitalization | 5,216,415 | 5,184,840 | ||||||
| Current liabilities: | ||||||||
| Accounts payable | 257,776 | 310,083 | ||||||
| Short-term debt | 286,566 | 260,486 | ||||||
| Short-term note owed to Puget Energy | 25,026 | 15,766 | ||||||
| Current maturities of long-term debt | 179,500 | 179,500 | ||||||
| Accrued expenses: | ||||||||
| Purchased gas liability | 26,764 | 77,864 | ||||||
| Taxes | 76,846 | 84,756 | ||||||
| Salaries and wages | 27,186 | 28,516 | ||||||
| Interest | 42,769 | 45,209 | ||||||
| Unrealized loss on derivative instruments | 8,546 | 27,089 | ||||||
| Deferred income taxes | 16,923 | -- | ||||||
| Other | 81,904 | 48,918 | ||||||
| Total current liabilities | 1,029,806 | 1,078,187 | ||||||
| Long-term liabilities and regulatory liabilities: | ||||||||
| Deferred income taxes | 909,444 | 821,382 | ||||||
| Unrealized loss on derivative instruments | 9,843 | -- | ||||||
| Power cost adjustment mechanism | 1,252 | -- | ||||||
| Regulatory liabilities | 203,382 | 210,372 | ||||||
| Other deferred credits | 476,535 | 297,429 | ||||||
| Total long-term liabilities and regulatory liabilities | 1,600,456 | 1,329,183 | ||||||
| Total capitalization and liabilities | $ | 7,846,677 | $ | 7,592,210 | ||||
The accompanying notes are an integral part of the financial statements.
CONSOLIDATED STATEMENTS OF CASH FLOWS
(Dollars in thousands)
(Unaudited)
Six Months Ended June 30, | ||||||||
| 2008 | 2007 | |||||||
| Operating activities: | ||||||||
| Net income | $ | 120,014 | $ | 117,136 | ||||
| Adjustments to reconcile net income to net cash provided by operating activities: | ||||||||
| Depreciation and amortization | 151,688 | 135,441 | ||||||
| Conservation amortization | 28,891 | 19,078 | ||||||
| Deferred income taxes and tax credits, net | 39,037 | 19,580 | ||||||
| Power cost adjustment mechanism | 4,366 | 2,788 | ||||||
| Amortization of gas pipeline capacity assignment | (5,257 | ) | (5,411 | ) | ||||
| Non cash return on regulatory assets | (4,972 | ) | (3,517 | ) | ||||
| Net unrealized loss on derivative instruments | (2,277 | ) | (4,246 | ) | ||||
| Change in residential exchange program | 32,473 | (25,673 | ) | |||||
| Storm damage deferred costs | (173 | ) | (16,359 | ) | ||||
| Other | 8,784 | (7,186 | ) | |||||
| Cash receipt from lease purchase option settlement | -- | 18,909 | ||||||
| Change in certain current assets and liabilities: | ||||||||
| Accounts receivable and unbilled revenue | 196,963 | 195,971 | ||||||
| Materials and supplies | (642 | ) | (16,635 | ) | ||||
| Fuel and gas inventory | 14,119 | 19,945 | ||||||
| Prepaid income taxes | 41,540 | 5,266 | ||||||
| Prepayments and other | 1,583 | (25,726 | ) | |||||
| Purchased gas receivable/payable | (51,100 | ) | 81,425 | |||||
| Accounts payable | (46,780 | ) | (168,605 | ) | ||||
| Taxes payable | (7,909 | ) | 8,814 | |||||
| Accrued expenses and other | (1,757 | ) | (4,856 | ) | ||||
| Net cash provided by operating activities | 518,591 | 346,139 | ||||||
| Investing activities: | ||||||||
| Construction expenditures - excluding equity AFUDC | (255,776 | ) | (375,677 | ) | ||||
| Energy efficiency expenditures | (26,963 | ) | (18,464 | ) | ||||
| Restricted cash | (12,216 | ) | (2 | ) | ||||
| Refundable cash received for customer construction projects | 4,491 | 9,179 | ||||||
| Cash proceeds from property sales | 2,079 | 93 | ||||||
| Other | (4,084 | ) | 1,301 | |||||
| Net cash used by investing activities | (292,469 | ) | (383,570 | ) | ||||
| Financing activities: | ||||||||
| Change in short-term debt, net | 26,080 | (38,201 | ) | |||||
| Dividends paid | (81,001 | ) | (52,654 | ) | ||||
| Loan from/to Puget Energy | 9,260 | 164 | ||||||
| Long term bond issued | -- | 250,000 | ||||||
| Redemption of trust preferred stock | -- | (37,750 | ) | |||||
| Redemption of bonds and notes | (150,000 | ) | (100,000 | ) | ||||
| Investment from Puget Energy | ||||||||
| Issuance and redemption cost of bonds and other | (2,255 | ) | 3,988 | |||||
| Net cash (used) provided by financing activities | (197,916 | ) | 25,547 | |||||
| Net increase (decrease) in cash from net income | 28,206 | (11,884 | ) | |||||
| Cash at beginning of year | 40,773 | 28,092 | ||||||
| Cash at end of period | $ | 68,979 | $ | 16,208 | ||||
| Supplemental cash flow information: | ||||||||
| Cash payments for interest (net of capitalized interest) | $ | 101,286 | $ | 91,666 | ||||
| Cash payments (refunds) from income taxes | (39,730 | ) | 23,000 | |||||
The accompanying notes are an integral part of the financial statements.
| (1) | Summary of Consolidation Policy |
Basis of Presentation
Puget Energy, Inc. (Puget Energy) is a holding company that owns Puget Sound Energy, Inc. (PSE). PSE is a public utility incorporated in the state of Washington that furnishes electric and natural gas services in a territory covering 6,000 square miles, primarily in the Puget Sound region.
The 2008 and 2007 consolidated financial statements of Puget Energy reflect the accounts of Puget Energy and its subsidiary, PSE. PSE’s consolidated financial statements include the accounts of PSE and its subsidiaries. Puget Energy and PSE are collectively referred to herein as “the Company.” The consolidated financial statements are presented after elimination of all significant intercompany items and transactions.
The consolidated financial statements contained in this Form 10-Q are unaudited. In the respective opinions of the management of Puget Energy and PSE, all adjustments necessary for a fair statement of the results for the interim periods have been reflected and were of a normal recurring nature. These condensed financial statements should be read in conjunction with the audited financial statements (and the Combined Notes thereto) included in the combined Puget Energy and PSE Report on Form 10-K for the year ended December 31, 2007.
The preparation of financial statements in conformity with generally accepted accounting principles (GAAP) requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities, disclosure of contingent assets and liabilities at the date of the financial statements, and the reported amounts of revenues and expenses during the reporting period. Actual results could differ from those estimates.
PSE collected Washington State excise taxes (which are a component of general retail rates) and municipal taxes of $53.2 million and $129.9 million for the three and six months ended June 30, 2008, respectively, and $48.2 million and $122.9 million for the three and six months ended June 30, 2007, respectively. The Company’s policy is to report such taxes on a gross basis in operating revenues and taxes other than income taxes in the accompanying consolidated statements of income.
| (2) | Earnings per Common Share (Puget Energy Only) |
Puget Energy’s basic earnings per common share have been computed based on weighted-average common shares outstanding of 129,417,000 and 129,427,000 for the three and six months ended June 30, 2008, respectively, and 116,659,000 and 116,567,000 for the three and six months ended June 30, 2007, respectively.
Puget Energy’s diluted earnings per common share have been computed based on weighted-average common shares outstanding and issuable upon exercise of options or expiration of vesting periods of 129,967,000 and 129,862,000 for the three and six months ended June 30, 2008, respectively, and 117,158,000 and 117,115,000 for the three and six months ended June 30, 2007, respectively. These shares include the dilutive effect of securities related to employee and director equity plans.
| (3) | Accounting for Derivative Instruments and Hedging Activities |
Statement of Financial Accounting Standards (SFAS) No. 133, “Accounting for Derivative Instruments and Hedging Activities” (SFAS No. 133), as amended, requires that all contracts considered to be derivative instruments be recorded on the balance sheet at their fair value. The Company enters into contracts to manage its energy resource portfolio and interest rate exposure including forward physical and financial contracts, option contracts and swaps. The majority of these contracts qualify for the normal purchase normal sale (NPNS) exception to derivative accounting rules provided they meet certain criteria. Generally, NPNS applies if PSE deems the counterparty creditworthy, if the counterparty owns or controls energy resources within the western region to allow for physical delivery of the energy and if the transaction is within PSE’s forecasted load requirements and adjusted from time to time. Those contracts that do not meet the NPNS exception or cash flow hedge criteria are marked-to-market to current earnings in the income statement, subject to deferral under SFAS No. 71, “Accounting for the Effects of Certain Types of Regulation” (SFAS No. 71), for energy related derivatives due to the Power Cost Adjustment (PCA) mechanism and Purchased Gas Adjustment (PGA) mechanism.
The nature of serving regulated electric customers with its portfolio of owned and contracted electric generation resources exposes the Company and its customers to some volumetric and commodity price risks within the sharing mechanism of the PCA. The Company’s energy risk portfolio management function monitors and manages these risks using analytical models and tools. The Company is not engaged in the business of assuming risk for the purpose of realizing speculative trading revenues. Therefore, wholesale market transactions are focused on balancing the Company’s energy portfolio, reducing costs and risks where feasible and reducing volatility in wholesale costs and margin in the portfolio. In order to manage risks effectively, the Company enters into physical and financial transactions which are appropriate for the service territory of the Company and are relevant to its regulated electric and gas portfolios.
The following table presents the fair value of electric derivatives that are designated as cash flow hedges or contracts that do not meet the NPNS exception at June 30, 2008 and December 31, 2007:
Electric Derivatives | ||||||||
(Dollars in Millions) | June 30, 2008 | December 31, 2007 | ||||||
| Short-term asset | $ | 115.5 | $ | 11.1 | ||||
| Long-term asset | 143.1 | 6.6 | ||||||
| Total assets | $ | 258.6 | $ | 17.7 | ||||
| Short-term liability | $ | 7.2 | $ | 9.8 | ||||
| Long-term liability | 6.6 | -- | ||||||
| Total liabilities | $ | 13.8 | $ | 9.8 | ||||
If it is determined that it is uneconomical to operate Company-controlled electric generating facilities in the future period, the fuel supply cash flow hedge relationship is terminated and the hedge is de-designated which results in the unrealized gains and losses associated with the contracts being recorded in the income statement. As these contracts are settled, the costs are recognized as energy costs and are included as part of the PCA mechanism.
At December 31, 2007, the Company had an unrealized day one loss deferral of $9.0 million related to a three-year locational power exchange contract which was computed based on a company model and therefore, the day one gain was deferred under Emerging Issues Task Force (EITF) Issue No. 02-3, “Issues Involved in Accounting for Derivative Contracts Held for Trading Purposes and Contracts Involved in Energy Trading and Risk Management Activities” (EITF 02-3). The contract has economic benefit to the Company over its terms. The locational exchange will help ease electric transmission congestion across the Cascade Mountains during the winter months as PSE will take delivery of energy at a location that interconnects with PSE’s transmission system in western Washington. At the same time, PSE will make available the quantities of power at the Mid-Columbia trading hub location. The day one loss deferral was transferred to retained earnings on January 1, 2008 as required by SFAS No. 157, “Fair Value Measurements” (SFAS No. 157) and any future day one loss on contracts will be recorded in the income statement beginning January 1, 2008 in accordance with the statement.
The following tables present the impact of changes in the market value of derivative instruments not meeting the NPNS or cash flow hedge criteria, and ineffectiveness related to highly effective cash flow hedges, to the Company’s earnings during the three and six months ended June 30, 2008 and June 30, 2007:
(Dollars in Millions) Three Months Ended June 30, | 2008 | 2007 | Change |
| Increase (decrease) in earnings | $ 2.4 | $ (1.5) | $ 3.9 |
(Dollars in Millions) Six Months Ended June 30, | 2008 | 2007 | Change |
| Increase (decrease) in earnings | $ 2.3 | $ 4.2 | $ (1.9) |
In the first quarter 2007, the Company reversed a loss reserve due to credit worthiness related to a physically delivered natural gas supply contract for electric generation. The counterparty’s financial outlook had changed and delivery was determined to be probable through the life of the contract, which expired on June 30, 2008.
The amount of net unrealized gain (loss), net of tax, related to the Company’s cash flow hedges under SFAS No. 133 consisted of the following at June 30, 2008 and December 31, 2007:
(Dollars in Millions, net of tax) | June 30, 2008 | December 31, 2007 |
| Other comprehensive income – unrealized gain (loss) | $ 161.9 | $ (3.4) |
The following table presents the fair value of derivative hedges of natural gas contracts to serve natural gas customers at June 30, 2008 and December 31, 2007:
Gas Derivatives | ||||||||
(Dollars in Millions) | June 30, 2008 | December 31, 2007 | ||||||
| Short-term asset | $ | 132.2 | $ | 6.0 | ||||
| Long-term asset | 56.3 | 5.3 | ||||||
| Total assets | $ | 188.5 | $ | 11.3 | ||||
| Short-term liability | $ | 1.4 | $ | 17.3 | ||||
| Long-term liability | 3.2 | -- | ||||||
| Total liabilities | $ | 4.6 | $ | 17.3 | ||||
At June 30, 2008, the Company had total assets of $188.6 million and total liabilities of $4.6 million related to hedges of natural gas contracts to serve natural gas customers. All mark-to-market adjustments relating to the natural gas business have been reclassified to a deferred account in accordance with SFAS No. 71 due to the PGA mechanism. All increases and decreases in the cost of natural gas supply are passed on to customers with the PGA mechanism. As the gains and losses on the hedges are realized in future periods, they will be recorded as natural gas costs under the PGA mechanism.
| (4) | Corporate Guarantees (Puget Energy Only) |
On May 7, 2006, Puget Energy sold InfrastruX Group Inc. (InfrastruX) to an affiliate of Tenaska Power Fund, L.P. (Tenaska) in an all-cash transaction. Puget Energy accounted for InfrastruX as a discontinued operation under SFAS No. 144, “Accounting for the Impairment or Disposal of Long-Lived Assets” (SFAS No. 144) in 2006. As a part of the transaction, Puget Energy made certain representations and warrantees concerning InfrastruX and indemnified Tenaska against certain future losses not to exceed $15.0 million. At the time of the sale, Puget Energy purchased a warrantee insurance policy and deposited $3.7 million into an escrow account, representing the full retention under the insurance policy. Additionally at the time of sale, Puget Energy recorded a $5.0 million loss reserve in connection with the indemnifications, which represented management’s measurement of the fair value of the corporate guarantees using a probability weighted approach.
On April 29, 2008, Puget Energy and Tenaska entered into a Joint Notice of Distribution and Termination Agreement (Termination Agreement) which resulted in the extinguishment of all InfrastruX corporate guarantees made by Puget Energy which management believed involved a risk of loss in connection with the sale of InfrastruX. In the second quarter 2008, Puget Energy made the remaining payments under the terms of the Termination Agreement totaling $7.1 million bringing total cash outlays equal to the Company’s original aggregate loss reserve amounts recorded in the second quarter of 2006.
| (5) | Retirement Benefits |
The Company has a defined benefit pension plan covering substantially all PSE employees, with a cash balance feature for all but International Brotherhood of Electrical Workers employees. Benefits are a function of age, salary and service. Puget Energy also maintains a non-qualified supplemental retirement plan for officers and certain director-level employees.
The following table summarizes the net periodic benefit cost for the three months ended June 30:
| Pension Benefits | Other Benefits | |||||||||||||||
| (Dollars in Thousands) | 2008 | 2007 | 2008 | 2007 | ||||||||||||
| Service cost | $ | 3,555 | $ | 3,392 | $ | 43 | $ | 91 | ||||||||
| Interest cost | 7,358 | 6,686 | 283 | 379 | ||||||||||||
| Expected return on plan assets | (10,327 | ) | (9,679 | ) | (197 | ) | (205 | ) | ||||||||
| Amortization of prior service cost | 316 | 511 | 21 | 134 | ||||||||||||
| Recognized net actuarial (gain) loss | 655 | 1,420 | (199 | ) | (56 | ) | ||||||||||
| Amortization of transition obligation | -- | -- | 13 | 105 | ||||||||||||
| Net periodic benefit cost | $ | 1,557 | $ | 2,330 | $ | (36 | ) | $ | 448 | |||||||
The following table summarizes the net periodic benefit cost for the six months ended June 30:
| Pension Benefits | Other Benefits | |||||||||||||||
| (Dollars in Thousands) | 2008 | 2007 | 2008 | 2007 | ||||||||||||
| Service cost | $ | 6,843 | $ | 6,655 | $ | 87 | $ | 183 | ||||||||
| Interest cost | 14,409 | 13,256 | 566 | 759 | ||||||||||||
| Expected return on plan assets | (20,782 | ) | (19,429 | ) | (394 | ) | (410 | ) | ||||||||
| Amortization of prior service cost | 631 | 1,021 | 42 | 267 | ||||||||||||
| Recognized net actuarial (gain) loss | 838 | 2,594 | (398 | ) | (112 | ) | ||||||||||
| Amortization of transition obligation | -- | -- | 25 | 209 | ||||||||||||
| Net periodic benefit cost | $ | 1,939 | $ | 4,097 | $ | (72 | ) | $ | 896 | |||||||
The Company previously disclosed in its financial statements for the year ended December 31, 2007 that it expected to contribute $4.0 million and less than $0.1 million to fund the non-qualified pension and other benefits plans, respectively, for the year ending December 31, 2008. During the three and six months ended June 30, 2008, the actual cash contributions to the Company’s non-qualified pension plans were $0.4 million and $0.8 million, respectively. Based on this activity, the Company anticipates contributing an additional $3.2 million to the Company’s non-qualified pension plan for the remaining period of 2008. PSE plans to contribute $0.4 million to the qualified pension plan. During the three and six months ended June 30, 2008, actual other post-retirement medical benefit plan contributions were less than $0.1 million and the Company does not expect to make additional contributions for the remaining periods of 2008.
During the second quarter 2008, PSE trued-up its actuarial data for employees of the qualified pension plan for 2007. As a result, PSE recorded $8.5 million expense to accumulated other comprehensive income.
| (6) | Regulation and Rates |
On December 3, 2007, PSE filed a general rate case with the Washington Utilities and Transportation Commission (Washington Commission) which proposed an increase in electric rates of $174.5 million, and in an increase in natural gas rates of $56.8 million, effective November 3, 2008. PSE requested a weighted cost of capital of 8.6%, or 7.29% after-tax, and a capital structure that included 45.0% common equity with a return on equity of 10.8%. In July 2008, PSE filed rebuttal testimony and revised its proposed increase in electric rates to $165.2 million and natural gas rates to $55.5 million. PSE expects an order to be issued by the Washington Commission no later than October 31, 2008.
On April 11, 2007, the Washington Commission issued an accounting order that authorized PSE to defer certain ownership and operating costs (and associated carrying costs) related to its purchase of the Goldendale electric generating facility (Goldendale) during the period prior to inclusion in PSE’s retail electric rates in the Power Cost Only Rate Case (PCORC). The deferral was for the time period from March 15, 2007 through September 1, 2007, at which time the Company began recovering Goldendale ownership and operation costs in electric rates. As of June 30, 2008, PSE had established a regulatory asset of $12.1 million. PSE anticipates amortization of the costs will begin no later than November 2008 as determined in PSE’s pending general rate case.
In May 2007, the Washington Commission Staff alleged that PSE’s natural gas system service provider had violated certain Washington Commission recordkeeping rules. On April 3, 2008, the Washington Commission issued an order approving a settlement agreement that required PSE to pay a regulatory penalty of $1.25 million, to establish a quality assurance program to better monitor its subcontractors and to complete an independent audit of natural gas system recordkeeping procedures. PSE paid the $1.25 million regulatory penalty amount in the second quarter of 2008.
In March 2008, Bonneville Power Administration (BPA) and PSE signed an agreement pursuant to which BPA (on April 2, 2008) paid PSE $53.7 million in Residential Exchange Program (REP) benefits for fiscal year ending September 30, 2008, which payment is subject to true-up depending upon the amount of any REP benefits ultimately determined to be payable to PSE. The Washington Commission approved in April 2008 PSE’s tariff filing seeking to pass-through the net amount of the benefits under the interim agreements to residential and small farm customers. The Washington Commission also approved PSE’s request to credit the regulatory asset amount of $33.7 million against the $53.7 million payment and pass-through to customers the remaining amount of approximately $20.0 million, which occurred during the second quarter of 2008. These amounts did not affect PSE’s net income. The accrued carrying charges on the regulatory asset totaling $3.1 million at June 30, 2008 will be addressed in PSE’s pending general rate case (Docket No. UE-072300).
In November 2007, the Western Electricity Coordinating Council (WECC) audited PSE’s compliance with electric reliability standards adopted by Federal Energy Regulatory Commission (FERC), the North American Electric Reliability Corporation (NERC) and/or WECC. Compliance with these standards includes periodic self-certifications of compliance, self-reports of violations after discovery of the violation, spot checks to review self-certifications and external audits that review compliance with designated standards in detail. The WECC audit team identified four potential violations of the standards that PSE had not previously self-reported. Several months after the audit, WECC issued a “Notice of Alleged Violations” to PSE, adding details and proposed penalties to the proposed findings. Under the rules for the process, PSE met with WECC representatives in July to discuss settlement. PSE is hopeful that all issues concerning the four potential violations will be resolved. Resolution of reliability standards issues will be an ongoing concern, however, PSE self-reports violations when they are discovered. Such self-reports could result in settlement of issues or issuances of penalties in the future. PSE has established a loss reserve of $0.6 million related to these alleged violations.
On December 15, 2006, FERC began an audit of PSE’s Open Access Transmission Tariff and Standards of Conduct for the period January 1, 2004 through December 31, 2006. The focus of the audit was PSE’s operation of its electric transmission system and tariff and its energy trading function. On July 16, 2008, FERC issued its final audit report which discussed five areas of non-compliance with certain FERC requirements. PSE was ordered to take several remedial actions and develop a compliance plan, but incurred no penalties as a result of the audit.
| (7) | Litigation |
Residential Exchange. Petitioners in several actions in the United States Court of Appeals for the Ninth Circuit (Ninth Circuit) against BPA asserted that BPA acted contrary to law in entering into or performing or implementing a number of agreements, including the amended settlement agreement (and the May 2004 agreement) between BPA and PSE regarding the REP. BPA rates used in such agreements between BPA and PSE for determining the amounts of money to be paid to PSE by BPA under such agreements during the period October 1, 2001 through September 30, 2006 were confirmed, approved and allowed to go into effect by FERC. Petitioners in several actions in the Ninth Circuit against BPA also asserted that BPA acted contrary to law in adopting or implementing the rates upon which the benefits received or to be received from BPA during the October 1, 2001 through September 30, 2006 period were based. A number of parties have claimed that the BPA rates proposed or adopted in the BPA rate proceeding to develop BPA rates to be used in the agreements for determining the amounts of money to be paid to PSE by BPA during the period October 1, 2006 through September 30, 2009 are contrary to law and that BPA acted contrary to law or without authority in deciding to enter into, or in entering into or performing or implementing such agreements. In March 2008, BPA requested FERC to continue a stay of FERC’s review of such rates in light of the reopened rate proceeding described below arising out of the Ninth Circuit litigation.
On May 3, 2007, the Ninth Circuit issued an opinion in Portland Gen. Elec. v. BPA, No. 01-70003, in which proceeding the actions of BPA in entering into settlement agreements regarding the REP with PSE and with other investor-owned utilities were challenged. In this opinion, the Ninth Circuit granted petitions for review and held the settlement agreements entered into between BPA and the investor-owned utilities being challenged in that proceeding to be inconsistent with statute. On May 3, 2007, the Ninth Circuit also issued an opinion in Golden Northwest Aluminum v. BPA, No. 03-73426, in which proceeding the petitioners sought review of BPA’s 2002-06 power rates. In this opinion, the Ninth Circuit granted petitions for review and held that BPA unlawfully shifted onto its preference customers the costs of its settlements with the investor-owned utilities. On October 5, 2007, petitions for rehearing of these two opinions were denied. On February 1, 2008, PSE and other utilities filed in the Supreme Court of the United States a petition for a writ of certiorari to review the decisions of the Ninth Circuit, which petition was denied in June 2008.
In May 2007, following the Ninth Circuit’s issuance of these two opinions, BPA suspended payments to PSE under the amended settlement agreement (and the May 2004 agreement). On August 29, 2007, the Washington Commission approved PSE’s accounting petition to defer as a regulatory asset the excess REP benefit provided to customers and accrue monthly carrying charges on the deferred balance from June 7, 2007 until the deferral is recovered from customers or BPA. On October 11, 2007, the Ninth Circuit remanded the May 2004 agreement to BPA in light of the Portland Gen. Elec. V. BPA opinion and dismissed the remaining three pending cases regarding settlement agreements.
On February 8, 2008, BPA issued a notice reopening its WP-07 rate proceeding to respond to the various Ninth Circuit opinions. In the notice, BPA proposed to adjust its fiscal year 2009 rates and to determine the amounts of REP benefits paid since 2002 that may be recovered. BPA is proposing to determine an amount that was improperly passed through to residential and small farm customers of PSE and the other regional investor-owned utilities during the 2002 to 2008 rate periods and to recover this amount over time by reducing future benefits under the REP. The amount to be recovered over future periods from PSE’s residential and small farm customers in BPA’s initial proposal is approximately $150.0 million. However, this is an initial proposal and is subject to BPA’s rate case process resulting in a final decision in approximately August 2008, and is also subject to subsequent administrative and judicial review.
In March 2008, BPA and PSE signed an agreement pursuant to which BPA made a payment to PSE related to the REP benefits for the fiscal year ending September 30, 2008, which payment is subject to true-up depending upon the amount of any REP benefits ultimately determined to be payable to PSE. In March and April 2008, Clatskanie People’s Utility District filed petitions in the Ninth Circuit for review of BPA actions in connection with offering or entering into such agreement with PSE and similar agreements with other investor-owned utilities.
It is not clear what impact, if any, such reopened rate proceeding, development or review of such rates, review of such agreements and the above described Ninth Circuit litigation may ultimately have on PSE.
Proceedings Relating to the Western Power Market. PSE is vigorously defending each case in the western power market proceedings. Litigation is subject to numerous uncertainties and PSE is unable to predict the ultimate outcome of these matters. Accordingly, there can be no guarantee that these proceedings, either individually or in the aggregate, will not materially and/or adversely affect PSE’s financial condition, results of operations or liquidity.
Lockyer Case. In March and April 2008, FERC issued orders establishing procedures for the Lockyer remand. The orders commence a seller-by-seller inquiry into the transaction reports filed by entities that sold power in California during 2000. The inquiry is to determine if the transaction reports as filed masked the gathering of more than 20% of the market during the period, by that seller. PSE is confident that it will not be found to have possessed 20% of any relevant market during any relevant time. The order also mandates a settlement process before an Administrative Law Judge (ALJ). FERC staff and the ALJ requested data concerning energy sellers’ transactions, and PSE provided such data to FERC staff. Settlement talks among various parties continue but PSE cannot predict the ultimate outcome of any negotiations or subsequent process before FERC or the ALJ.
California Receivable and California Refund Proceeding. The California Independent System Operator (CAISO) filed status reports in this matter from time to time, but has yet to report its “who owes what to whom” calculation.
Orders to Show Cause. On June 25, 2003, FERC issued two show cause orders pertaining to its western market investigations that commenced individual proceedings against many sellers. One show cause order investigated 26 entities that allegedly had potential “partnerships” with Enron. PSE was not named in that show cause order. On January 22, 2004, FERC stated that it did not intend to proceed further against other parties.
The second show cause order named PSE (Docket No. EL03-169) and approximately 54 other entities that allegedly had engaged in potential “gaming” practices in the CAISO and California PX markets. PSE and FERC staff filed a proposed settlement of all issues pending against PSE in those proceedings on August 28, 2003. The proposed settlement, which admits no wrongdoing on the part of PSE, would result in a payment of a nominal amount to settle all claims. FERC approved the settlement on January 22, 2004. The California parties filed for rehearing of that order. On March 17, 2004, PSE moved to dismiss the California parties’ rehearing request and awaits FERC action on that motion.
Pacific Northwest Refund Proceeding. In October 2000, PSE filed a complaint at FERC (Docket No. EL01-10) against “all jurisdictional sellers” in the Pacific Northwest seeking prospective price caps consistent with any result FERC ordered for the California markets. FERC dismissed PSE’s complaint, but PSE challenged that dismissal. On June 19, 2001, FERC ordered price caps on energy sales throughout the West. Various parties, including the Port of Seattle and the cities of Seattle and Tacoma, then moved to intervene in the proceeding seeking retroactive refunds for numerous transactions. The proceeding became known as the “Pacific Northwest Refund Proceeding,” though refund claims were outside the scope of the original complaint. On June 25, 2003, FERC terminated the proceeding on procedural, jurisdictional and equitable grounds and on November 10, 2003, FERC on rehearing, confirmed the order terminating the proceeding. On August 24, 2007, the Ninth Circuit issued a decision concluding that FERC should have evaluated and considered evidence of market manipulation in California and its potential impact in the Pacific Northwest. It also decided that FERC should have considered purchases made by the California Energy Resources Scheduler and/or the California Department of Water Resources in the Pacific Northwest Proceeding. On December 17, 2007, PSE and PowerEx Corp. separately filed requests for rehearing with the Ninth Circuit of this decision. Those requests remain pending. PSE intends to vigorously defend its position in this proceeding, but it is unable to predict the outcome of this matter.
Colstrip Matters. In May 2003, approximately 50 plaintiffs initiated an action against the owners of Colstrip alleging that (1) seepage from two different wastewater pond areas caused groundwater contamination and threatened to contaminate domestic water wells and the Colstrip water supply pond, and (2) seepage from the Colstrip water supply pond caused structural damage to buildings and toxic mold. The defendants reached agreement on a global settlement with all plaintiffs on April 29, 2008 and PSE paid its share of the settlement in the amount of $10.7 million in July 2008. PSE had previously expensed the settlement in the first quarter 2008. PSE has also filed an accounting petition with the Washington Commission to recover such costs in the future.
The Minerals Management Service of the United States Department of Interior (MMS) has issued a series of orders to Western Energy Company (WECO) to pay additional taxes and royalties concerning coal WECO sold to the owners of Colstrip 3 & 4, and similar orders have been issued in the administrative appellate process. The orders assert that additional royalties are owed in connection with payments received by WECO from Colstrip 3 & 4 owners (including PSE) for the construction and operation of a conveyor system that runs several miles from the mine to Colstrip 3 & 4. The state of Montana has also issued a demand to WECO consistent with the MMS position. WECO has challenged these orders, and the issue has been on appeal for several years. WECO has won some points during the appellate process that have reduced the claims; however under applicable law, to pursue the appeals, the principal in dispute cannot be paid, which causes interest to accrue. Moreover, because the conveyor system continues to be used, the amount in dispute grows. In the aggregate, the accrued interest plus unasserted claims to bring the amount current could make the total claim (principal plus interest) pertaining to PSE’s 25.0% project share as high as $10.0 million. PSE and the other Colstrip 3 & 4 owners authorized WECO to make a settlement offer to the Montana Department of Revenue (DOR) and the MMS in connection with these claims. PSE recorded a $1.2 million pre-tax loss reserve in the second quarter of 2008 in that regard.
Proceeding Relating to the Proposed Merger. On February 6, 2008, the Company entered into a memorandum of understanding providing for the settlement of the consolidated shareholder lawsuit, subject to customary conditions including completion of appropriate settlement documentation, confirmatory discovery and court approval. Pursuant to the memorandum of understanding, the Company agreed to include certain additional disclosures in its proxy statement relating to the merger. The Company does not admit, however, that its prior disclosures were in any way materially misleading or inadequate. In addition, the Company and the other defendants in the consolidated lawsuit deny the plaintiffs��� allegations of wrongdoing and violation of law in connection with the merger. The settlement, if completed and approved by the court, will result in dismissal with prejudice and release of all claims of the plaintiffs and settlement class of the Company’s shareholders that were or could have been brought on behalf of the plaintiffs and the settlement class. In connection with such settlement, the plaintiffs intend to seek a court-approved award of attorneys’ fees and expenses in an amount up to $290,000, which the Company has agreed to pay. As of June 30, 2008, the Company has a loss reserve of $290,000 related to this matter.
| (8) | Related Party Transactions |
On June 1, 2006, PSE entered into a revolving credit facility with its parent, Puget Energy, in the form of a Demand Promissory Note (Note). Through the Note, PSE may borrow up to $30.0 million from Puget Energy, subject to approval by Puget Energy. Under the terms of the Note, PSE pays interest on the outstanding borrowings based on the lowest of the weighted-average interest rate of (a) PSE’s outstanding commercial paper interest rate; (b) PSE’s senior unsecured revolving credit facility; or (c) the interest rate available under the receivable securitization facility of PSE Funding, Inc. (PSE Funding), a PSE subsidiary, which is the London Interbank Offered Rate (LIBOR) plus a marginal rate. At June 30, 2008 and December 31, 2007, the outstanding balance of the Note was $25.0 million and $15.8 million, respectively and the interest rate was 2.87% and 5.31% respectively. The outstanding balance and the related interest under the Note are eliminated by Puget Energy upon consolidation of PSE’s financial statements. The $30.0 million credit facility with Puget Energy is unaffected by the pending merger.
The Company has a general liability claim from AEGIS Insurance Services Inc. (AEGIS) and an insurance claim which AEGIS is a co-insurer. The total of all insurance receivables is $15.0 million as of June 30, 2008, of which approximately $8.7 million is being sought from AEGIS. One nonemployee director of Puget Energy and PSE also serves on the board of AEGIS and a PSE management employee serves on one of AEGIS’ risk management committees.
| (9) | Other |
Financial Accounting Standards Board (FASB) Interpretation No. 46R, “Consolidation of Variable Interest Entities” (FIN 46R) requires that if a business entity has a controlling financial interest in a variable interest entity, the financial statements of the variable interest entity must be included in the consolidated financial statements of the business entity. The Company has evaluated its power purchase agreements and determined that two counterparties during the six months ended June 30, 2008 may be considered variable interest entities. Consistent with FIN 46R, PSE submitted requests for information to those two entities; however, the entities have refused to submit to PSE the necessary information for PSE to determine whether they meet the requirements of a variable interest entity. PSE also determined that it does not have a contractual right to such information. PSE will continue to submit requests for information to the counterparties in accordance with FIN 46R.
Sumas Cogeneration Company, L.P. (Sumas), an entity that potentially could have been considered a variable interest entity prior to May 7, 2007, delivered a letter to PSE on May 7, 2007, stating that it had sold its dedicated natural gas reserves to a third party and that it no longer intended to deliver energy to PSE through the remaining term of the contract, which expires on April 15, 2013. The last energy delivered to PSE by Sumas occurred on March 15, 2007. PSE purchased from Sumas its 125 megawatt (MW) power plant located in Sumas, Washington in a transaction effective July 25, 2008, resolving any dispute between the parties.
For the two power purchase agreements that may be considered variable interest entities under FIN 46R as of the second quarter 2008, PSE is required to buy all the generation from these plants, subject to displacement by PSE, at rates set forth in the power purchase agreements. If at any time the counterparties cannot deliver energy to PSE, PSE would have to buy energy in the wholesale market at prices which could be higher or lower than the power purchase agreement prices. PSE’s purchased electricity expense for the three months ended June 30, 2008 and 2007 was $36.9 million and $30.6 million, respectively, for the two entities and for the six months ended June 30, 2008, and 2007 was $91.8 million and $97.2 million, respectively, for the two entities.
In November 2006, PSE’s Crystal Mountain Generation Station had an accidental release of approximately 18,000 gallons of diesel fuel. PSE crews and consultants responded and worked with applicable state and federal agencies to control and remove the spilled diesel. On July 11, 2007, PSE received a Notice of Completion for work performed pursuant to the Administrative Order for Removal from the U. S. Environmental Protection Agency (EPA). The Notice stated that PSE had met the requirements of the Order and the accompanying scope of work. Total removal costs as of June 30, 2008 were approximately $14.5 million. PSE estimates the total remediation cost to be approximately $15.0 million, which has been accrued or paid. At June 30, 2008, PSE had an insurance receivable recorded in the amount of $7.2 million associated with this fuel release. PSE received a partial payment of $5.0 million on this receivable in January 2008. On February 13, 2008, the U.S. Department of Justice, on behalf of the EPA, notified PSE of its intent to issue a fine of $0.5 million under the Clean Water Act. PSE paid this fine in July 2008. On April 15, 2008, the Washington State Department of Ecology fined PSE $0.4 million as a civil penalty pursuant to the Clean Water Act. PSE reserved $0.9 million for the penalties.
| (10) | New Accounting Pronouncements |
On September 15, 2006, FASB issued SFAS No. 157, which clarifies how companies should use fair value measurements in accordance with GAAP for recognition and disclosure purposes. SFAS No. 157 establishes a common definition of fair value and a framework for measuring fair value under GAAP, along with expanding disclosures about fair value to eliminate differences in current practice that exist in measuring fair value under the existing accounting standards. The definition of fair value in SFAS No. 157 retains the notion of exchange price; however, it focuses on the price that would be received to sell the asset or paid to transfer a liability (i.e. an exit price), rather than the price that would be paid to acquire the asset or received to assume the liability (i.e. an entrance price). Under SFAS No. 157, a fair value measure should reflect all of the assumptions that market participants would use in pricing the asset or liability, including assumptions about the risk inherent in a particular valuation technique, the effect of a restriction on the sale or use of an asset, and the risk of nonperformance. To increase consistency and comparability in fair value measures, SFAS No. 157 establishes a three-level fair value hierarchy to prioritize the inputs used in valuation techniques between observable inputs that reflect quoted market prices in active markets, inputs other than quoted prices with observable market data, and unobservable data (e.g. a company’s own data).
SFAS No. 157 is effective for fiscal years beginning after November 15, 2007, which was January 1, 2008, for the Company. On February 28, 2008, the FASB issued a final FASB Staff Position (FSP) that partially deferred the effective date of SFAS No. 157 for one year for non-financial assets and non-financial liabilities that are recognized or disclosed at fair value, except for those that are recognized or disclosed at fair value on an annual or more frequent basis. The Company adopted SFAS No. 157 on January 1, 2008, prospectively, as required by the Statement, with certain exceptions, including the initial impact of changes in fair value measurements of existing derivative financial instruments measured initially using the transaction price under EITF 02-3. On January 1, 2008, the difference between the carrying amounts and the fair values of those instruments originally recorded under guidance in EITF 02-3 was recognized as a cumulative-effect adjustment to the opening balance of retained earnings. SFAS No. 157 nullified a portion of EITF 02-3. Under EITF 02-3, the transaction price presumption prohibited recognition of a trading profit at inception of a derivative unless the positive fair value of that derivative was substantially based on quoted prices or a valuation process incorporating observable inputs. For transactions that did not meet this criterion at inception, trading profits that had been deferred were recognized in the period that inputs to value the derivative became observable or when the contract performed.
In December 2007, the FASB issued SFAS No. 141(R), “Business Combinations” (SFAS No. 141(R)). This Statement replaces FASB Statement No. 141, “Business Combinations” and addresses the accounting for all transactions or other events in which an entity obtains control of one or more businesses. The objective of this Statement is to improve the relevance, representational faithfulness and comparability of the information that a reporting entity provides in its financial reports about a business combination and its effects. To accomplish that, this Statement establishes principles and requirements for how the acquirer: 1) Recognizes and measures in its financial statements the identifiable assets acquired, the liabilities assumed and any noncontrolling interest in the acquiree; 2) Recognizes and measures the goodwill acquired in the business combination or a gain from a bargain purchase; and 3) Determines what information to disclose to enable users of the financial statements to evaluate the nature and financial effects of the business combination. This Statement shall be applied prospectively to business combinations for which the acquisition date is on or after the beginning of the first annual reporting period beginning on or after December 15, 2008. The Company does not expect any impact from SFAS No. 141 (R).
On March 19, 2008, FASB issued SFAS No. 161, “Disclosures about Derivative Instruments and Hedging Activities – An Amendment of FASB Statement No. 133” (SFAS No. 161). SFAS No. 161 is effective for the fiscal years and interim years beginning after November 15, 2008, which will be the quarter ended March 31, 2009 for the Company. SFAS No. 161 requires companies with derivative instruments to disclose information that should enable financial statement users to understand how and why a company uses derivative instruments, how derivative instruments and related hedged items are accounted for under SFAS No. 133 and how derivative instruments and related hedged items affect a company’s financial position, financial performance and cash flows. SFAS No. 161 requirements will impact the following derivative and hedging disclosures: objectives and strategies, balance sheet, financial performance, contingent features and counterparty credit risk. The Company is currently assessing the impact of SFAS No. 161.
In May 2008, FASB issued SFAS No. 162, “The Hierarchy of Generally Accepted Accounting Principles” (SFAS No. 162), which identifies the sources of accounting principles and the framework for selecting the principles to be used in the preparation of financial statements of nongovernmental entities that are presented in conformity with generally accepted accounting principles. The FASB Board is responsible for identifying the sources of accounting principles and providing entities with a framework for selecting the principles used in the preparation of financial. The current GAAP hierarchy, as set forth in the American Institute of Certified Public Accountants Statement on Auditing Standards No. 69, “The Meaning of Present Fairly in Conformity With Generally Accepted Accounting Principles,” has been criticized because it is directed to the auditor rather than the entity, it is complex and it ranks FASB Statements of Financial Accounting Concepts, which are subject to the same level of due process as FASB Statements of Financial Accounting Standards, below industry practices that are widely recognized as generally accepted but that are not subject to due process. The Board believes that the GAAP hierarchy should be directed to entities because it is the entity that is responsible for selecting accounting principles for financial statements that are presented in conformity with GAAP. The Company has reviewed the statement and has assessed there will be no significant impact to the financial statements.
On June 16, 2008, FSP No. EITF 03-6-1, “Determining Whether Instruments Granted in Share-Based Payment Transactions Are Participating Securities,” (EITF 03-6-1) was issued. This FSP addresses whether instruments granted in share-based payment transactions are participating securities prior to vesting and, therefore, need to be included in the earnings allocation in computing earnings per share under the two-class method. Unvested share-based payment awards that contain nonforfeitable rights to dividends or dividend equivalents (whether paid or unpaid) are participating securities and shall be included in the computation of EPS pursuant to the two-class method. The Company is currently assessing the financial statement presentation impact of FSP EITF No. 03-6-1.
| (11) | Fair Value Measurements |
As defined in SFAS No. 157, fair value is 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 (exit price). However, as permitted under SFAS No. 157, the Company utilizes a mid-market pricing convention (the mid-point price between bid and ask prices) as a practical expedient for valuing the majority of its assets and liabilities measured and reported at fair value. The Company utilizes market data or assumptions that market participants would use in pricing the asset or liability, including assumptions about risk and the risks inherent in the inputs to the valuation technique. These inputs can be readily observable, market corroborated, or generally unobservable. The Company primarily applies the market approach for recurring fair value measurements and endeavors to utilize the best available information. Accordingly, the Company utilizes valuation techniques that maximize the use of observable inputs and minimize the use of unobservable inputs.
PSE values derivative instruments based on daily quoted prices from numerous independent energy brokerage services. When external quoted market prices are not available for derivative contracts, PSE uses a valuation model that uses volatility assumptions relating to future energy prices based on specific energy markets and utilizes externally available forward market price curves. All derivative instruments are sensitive to market price fluctuations that can occur on a daily basis. The Company is focused on commodity price exposure and risks associated with volumetric variability in the natural gas and electric portfolios. It is not engaged in the business of assuming risk for the purpose of speculative trading. The Company hedges open natural gas and electric positions to reduce both the portfolio risk and the volatility risk in prices. The exposure position is determined by using a probabilistic risk system that models 100 scenarios of how the Company’s natural gas and power portfolios will perform under various weather, hydro and unit performance conditions. PSE has not made any material changes during the reporting period to those techniques or models.
The Company is able to classify fair value balances based on the observability of those inputs. SFAS No. 157 establishes a fair value hierarchy that prioritizes the inputs used to measure fair value. The hierarchy gives the highest priority to unadjusted quoted prices in active markets for identical assets or liabilities (Level 1 measurement) and the lowest priority to unobservable inputs (Level 3 measurement). The three levels of the fair value hierarchy defined by SFAS No. 157 are as follows:
Level 1 – Quoted prices are available in active markets for identical assets or liabilities as of the reporting date. Active markets are those in which transactions for the asset or liability occur in sufficient frequency and volume to provide pricing information on an ongoing basis. Level 1 primarily consists of financial instruments such as exchange-traded derivatives and listed equities.
Level 2 – Pricing inputs are other than quoted prices in active markets included in Level 1, which are either directly or indirectly observable as of the reported date. Level 2 includes those financial instruments that are valued using models or other valuation methodologies. These models are primarily industry-standard models that consider various assumptions, including quoted forward prices for commodities, time value, volatility factors, and current market and contractual prices for the underlying instruments, as well as other relevant economic measures. Substantially all of these assumptions are observable in the marketplace throughout the full term of the instrument, can be derived from observable data or are supported by observable levels at which transactions are executed in the marketplace. Instruments in this category include non-exchange-traded derivatives such as OTC forwards and options.
Level 3 – Pricing inputs include significant inputs that are generally less observable from objective sources. These inputs may be used with internally developed methodologies that result in management’s best estimate of fair value. Level 3 instruments include those that may be more structured or otherwise tailored to customers’ needs. At each balance sheet date, the Company performs an analysis of all instruments subject to SFAS No. 157 and includes in Level 3 all of those whose fair value is based on significant unobservable inputs.
The following table sets forth by level within the fair value hierarchy the Company’s financial assets and liabilities that were accounted for at fair value on a recurring basis as of June 30, 2008. As required by SFAS No. 157, financial assets and liabilities are classified in their entirety based on the lowest level of input that is significant to the fair value measurement. The Company’s assessment of the significance of a particular input to the fair value measurement requires judgment and may affect the valuation of fair value assets and liabilities and their placement within the fair value hierarchy levels. The determination of the fair values incorporates various factors required under SFAS No. 157. These factors include not only the credit standing of the counterparties involved and the impact of credit enhancements (such as cash deposits, letters of credit and priority interests), but also the impact of the Company’s nonperformance risk on its liabilities.
| Recurring Fair Value Measures | At Fair Value as of June 30, 2008 | |||
(Dollars in Millions) | Level 1 | Level 2 | Level 3 | Total |
| Assets: | ||||
| Energy derivative instruments | $ -- | $ 287.7 | $ 159.4 | $ 447.1 |
| Total assets | $ -- | $ 287.7 | $ 159.4 | $ 447.1 |
| Liabilities: | ||||
| Energy derivative instruments | $ -- | $ 6.4 | $ 12.0 | $ 18.4 |
| Total liabilities | $ -- | $ 6.4 | $ 12.0 | $ 18.4 |
The following table sets forth a reconciliation of changes in the fair value of derivatives classified as Level 3 in the fair value hierarchy.
| (Dollars in Millions) | Three Months Ended June 30, 2008 | Six Months Ended June 30, 2008 | ||||||
| Balance at beginning of period | $ | 17.2 | $ | (7.3 | ) | |||
| Realized energy derivative losses | 0.5 | (1.3 | ) | |||||
| Unrealized energy derivative gains | ||||||||
| - included in earnings | 3.5 | 1.9 | ||||||
| - included in other comprehensive income | 116.3 | 145.0 | ||||||
| - included in regulatory assets/liabilities | 3.0 | 3.0 | ||||||
| New energy purchase transactions | -- | -- | ||||||
| Other financial items settled | 7.2 | 7.2 | ||||||
| Energy derivatives transferred out of Level 3 | (0.3 | ) | (1.1 | ) | ||||
| Balance as of June 30, 2008 | $ | 147.4 | $ | 147.4 | ||||
The Company believes an analysis of energy derivative instruments classified as Level 3 should take into account the fact that these items are generally economically hedged as a portfolio with instruments that may be classified in Levels 1 and 2. Realized gains and losses on energy derivatives for Level 3 recurring items are included in Energy Costs in PSE’s income statement under purchased electricity, electric generation fuel or purchased gas when settled.
Unrealized gains and losses for Level 3 on energy derivatives recurring items are included in net unrealized (gain) loss on derivative instruments in PSE’s income statement. SFAS No. 157 requires that financial assets and liabilities be classified in their entirety based on the lowest level of input that is significant to the fair value measurement. As of June 30, 2008, energy derivative instruments are classified in Level 3 because Level 3 inputs are significant to their fair value measurement; however, the valuation of these derivative instruments is primarily based upon observable inputs (Level 2), and the net unrealized gain recognized during the reporting period is primarily due to a significant increase in observable prices.
Energy derivatives transferred out of Level 3 represent existing assets or liabilities that were either previously classified as Level 3 for which the lowest significant input became observable during the period.
The Company does not believe that the fair values diverge materially from the amounts the Company currently anticipates realizing on settlement or maturity.
| (12) | Agreement and Plan of Merger (Puget Energy only) |
On October 26, 2007, Puget Energy announced that it had entered into a definitive Agreement and Plan of Merger, dated as of October 25, 2007, pursuant to which Puget Energy will be acquired by a consortium of long-term infrastructure investors led by Macquarie Infrastructure Partners, the Canada Pension Plan Investment Board and British Columbia Investment Management Corporation and which also includes Alberta Investment Management, Macquarie-FSS Infrastructure Trust and Macquarie Capital Group (collectively, the Consortium). At the effective time of the merger, each issued and outstanding share of common stock of Puget Energy, other than any shares in respect of which dissenter’s rights are perfected and other than any shares owned by the Consortium, shall be cancelled and shall be converted automatically into the right to receive $30.00 in cash, without interest.
The consummation of the merger is subject to the satisfaction or waiver of certain closing conditions, including the receipt of shareholder approval of the merger and approval of it by various state and federal regulatory authorities. As of the date of this Quarterly Report, some of these conditions have been satisfied while others remain outstanding or in process. On April 16, 2008, Puget Energy shareholders approved the merger by more than the required two-thirds vote. Also, on April 17, 2008, FERC conditionally approved the transaction pursuant to section 203 of the Federal Power Act subject to reviewing the final conditions of merger approval by the Washington Commission. On December 17, 2007, PSE and the Consortium filed a joint application seeking approval of the merger with the Washington Commission. A revised procedural schedule has been filed in the merger proceeding with a proposed decision by the Washington Commission on October 13, 2008. If approved by the Washington Commission and assuming receipt of approval by the other remaining federal authorities, closing is expected to occur during the fourth quarter 2008.
On July 22, 2008, Puget Energy, the Consortium and several parties involved in the merger proceeding reached a settlement to resolve all issues before the Washington Commission. On July 23, 2008, the parties to the merger agreement filed a multiparty stipulated settlement with the Washington Commission.
The following discussion of the Company’s financial condition and results of operations contains forward-looking statements that involve risks and uncertainties, such as statements of the Company’s plans, objectives, expectations and intentions. Words or phrases such as “anticipates,” “believes,” “estimates,” “expects,” “future,” “intends,” “plans,” “projects,” “predicts,” “will likely result,” and “will continue” and similar expressions are used to identify forward-looking statements. However, these words are not the exclusive means of identifying such statements. In addition, any statements that refer to expectations, projections or other characterizations of future events or circumstances are forward-looking statements. The Company’s actual results could differ materially from those anticipated in these forward-looking statements for many reasons, including the factors described below and under the caption “Forward-Looking Statements” at the beginning of this report. Readers should not place undue reliance on these forward-looking statements, which apply only as of the date of this Form 10-Q.
Overview
Puget Energy, Inc. (Puget Energy) is an energy services holding company and all of its operations are conducted through its subsidiary Puget Sound Energy, Inc. (PSE), a regulated electric and natural gas utility company. Puget Energy is dependent upon the results of PSE since PSE is its most significant asset. PSE is the largest electric and natural gas utility in the state of Washington, primarily engaged in the business of electric transmission, distribution, generation and natural gas distribution. Puget Energy’s business strategy is to generate stable earnings and cash flow by offering reliable electric and natural gas service in a cost effective manner through PSE.
Puget Energy Merger
On October 26, 2007, Puget Energy announced that it had entered into a definitive Agreement and Plan of Merger, dated as of October 25, 2007, pursuant to which Puget Energy will be acquired by a consortium of long-term infrastructure investors led by Macquarie Infrastructure Partners, the Canada Pension Plan Investment Board and British Columbia Investment Management Corporation and which also includes Alberta Investment Management, Macquarie-FSS Infrastructure Trust and Macquarie Capital Group (collectively, the Consortium). At the effective time of the merger, each issued and outstanding share of common stock of Puget Energy, other than any shares in respect of which dissenter’s rights are perfected and other than any shares owned by the Consortium, shall be cancelled and shall be converted automatically into the right to receive $30.00 in cash, without interest.
The consummation of the merger is subject to the satisfaction or waiver of certain closing conditions, including the receipt of shareholder approval of the merger and approval of it by various state and federal regulatory authorities. As of the date of this Quarterly Report, some of these conditions have been satisfied while others remain outstanding or in process. On April 16, 2008, Puget Energy shareholders approved the merger. Also, on April 17, 2008 the Federal Energy Regulatory Commission (FERC) conditionally approved the transaction pursuant to section 203 of the Federal Power Act subject to reviewing the final conditions of merger approval by the Washington Utilities and Transportation Commission (Washington Commission). On December 17, 2007, PSE and the Consortium filed a joint application seeking approval of the merger with the Washington Commission. A revised procedural schedule has been filed in the merger proceeding with a proposed decision by the Washington Commission on October 13, 2008. If approved by the Washington Commission and assuming receipt of approval by the other remaining federal authorities, closing is expected to occur during the fourth quarter 2008.
On July 22, 2008, Puget Energy, the Consortium, and several parties involved in the merger proceeding reached a settlement to resolve all issues before the Washington Commission. On July 23, 2008, the parties to the merger agreement filed a multiparty stipulated settlement with the Washington Commission.
Puget Sound Energy
PSE generates revenues primarily from the sale of electric and natural gas services to residential and commercial customers within Washington State. PSE’s operating revenues and associated expenses are not generated evenly throughout the year. Variations in energy usage by consumers occur from season to season and from month to month within a season, primarily as a result of weather conditions. PSE normally experiences its highest retail energy sales and subsequently higher power costs during the winter heating season in the first and fourth quarters of the year and its lowest sales in the third quarter of the year. Varying wholesale electric prices and the amount of hydroelectric energy supplies available to PSE also make quarter-to-quarter comparisons difficult.
As a regulated utility company, PSE is subject to FERC and Washington Commission regulation which may impact a large array of business activities, including limitation of future rate increases; directed accounting requirements that may negatively impact earnings; licensing of PSE-owned generation facilities; and other FERC and Washington Commission directives that may impact PSE’s long-term goals. In addition, PSE is subject to risks inherent to the utility industry as a whole, including weather changes affecting purchases and sales of energy; outages at owned and contracted generation plants where energy is obtained; storms or other events which can damage natural gas and electric distribution and transmission lines; increasing regulatory standards for system reliability; wholesale market stability over time; and significant evolving environmental legislation.
PSE’s main business objective is to provide reliable, safe and cost-effective energy to its customers. To help accomplish this objective, PSE seeks to become more energy efficient and environmentally responsible in its energy supply portfolio on an ongoing basis. PSE filed its most recent Integrated Resource Plan on May 31, 2007 with the Washington Commission. The plan supports a strategy of significantly increasing energy efficiency programs, pursuing additional renewable resources (primarily wind) and additional base load natural gas fired generation to meet the growing needs of its customers.
Non-GAAP Financial Measures – Energy Margins
The following discussion includes financial information prepared in accordance with generally accepted accounting principles (GAAP), as well as two other financial measures, Electric Margin and Gas Margin, that are considered “non-GAAP financial measures.” Generally, a non-GAAP financial measure is a numerical measure of a company’s financial performance, financial position or cash flows that exclude (or include) amounts that are included in (or excluded from) the most directly comparable measure calculated and presented in accordance with GAAP. The presentation of Electric Margin and Gas Margin is intended to supplement investors’ understanding of the Company’s operating performance. Electric Margin and Gas Margin are used by the Company to determine whether the Company is collecting the appropriate amount of energy costs from its customers to allow recovery of operating costs. The Company’s Electric Margin and Gas Margin measures may not be comparable to other companies’ Electric Margin and Gas Margin measures. Furthermore, these measures are not intended to replace operating income as determined in accordance with GAAP as an indicator of operating performance.
Results of Operations
Puget Energy
All the operations of Puget Energy are conducted through its subsidiary PSE. Net income for the three months ended June 30, 2008 was $33.7 million on operating revenues of $712.4 million as compared to net income of $38.6 million on operating revenues of $661.1 million for the same period in 2007.
Basic and diluted earnings per share for the three months ended June 30, 2008 was $0.26 as compared to basic and diluted earnings per share for the three months ended June 30, 2007 of $0.33. Net income for the three months ended June 30, 2008 as compared to the same period in 2007, was negatively impacted by a $0.9 million decrease in electric margin while it was positively impacted by an $8.4 million increase in gas margin. Net income was negatively impacted by a $17.5 million increase in utility operation and maintenance and by an increase in depreciation and amortization of $10.5 million. The increase in expenses was partially offset by a decrease in taxes other than income taxes, net of revenue sensitive taxes, of $5.0 million. Net income was also positively impacted due to an increase in other income of $1.9 million ($1.2 million after-tax) and by a $3.9 million increase in unrealized gain on energy derivative instruments for PSE. In the second quarter 2008, Puget Energy incurred $5.7 million in costs related to the proposed merger with the Consortium.
For the six months ended June 30, 2008, Puget Energy’s net income was $113.5 million on operating revenues from continuing operations of $1.8 billion, compared to net income of $117.7 million on operating revenues from continuing operations of $1.7 billion for the same period in 2007. Basic and diluted earnings per share for the six months ended June 30, 2008 were $0.88 and $0.87, respectively, compared to basic and diluted earnings per share of $1.01 and $1.00, respectively, for the same period in 2007.
Net income for the six months ended June 30, 2008 was positively impacted by increased electric and gas margins of $24.5 million and $20.9 million, respectively, compared to the same period in 2007. Net income was negatively impacted by an increase of $31.5 million related to utility operation and maintenance which includes the impact of a $10.5 million charge related to PSE’s share of the settlement of a lawsuit against the Colstrip electric generating station project owners, an increase in depreciation and amortization of $16.2 and a decrease in unrealized gain on energy derivative instruments of $2.0 million. The increase in expenses was partially offset by a decrease in non-utility operation and maintenance and other expenses of $2.9 million and an increase in other income of $3.8 million. Net income was also positively impacted due to a decrease in other expense of $2.0 million and a decrease in interest expense of $2.7 million due to lower average debt outstanding as a result of the equity issuance in December 2007. For the six months ended June 30, 2008, Puget Energy incurred $7.0 million in costs related to the proposed merger with the Consortium.
Puget Sound Energy
PSE’s operating revenues and expenses are not generated evenly throughout the year. Variations in energy usage by customers occur from season to season and from month to month within a season, primarily as a result of weather conditions. PSE normally experiences its highest retail energy sales and subsequently higher power costs during the winter heating season in the first and fourth quarters of the year, and its lowest sales in the third quarter of the year. Power cost recovery is seasonal, with underrecovery normally in the first and fourth quarters and over recovery in the second and third quarters. Varying wholesale electric prices and the amount of hydroelectric energy supplies available to PSE also make quarter to quarter comparisons difficult.
Energy Margins
The following table displays the details of electric margin changes for the three months ended June 30, 2008 as compared to the same period in 2007. Electric margin is electric sales to retail and transportation customers less pass-through tariff items and revenue-sensitive taxes, and the cost of generating and purchasing electric energy sold to customers, including transmission costs to bring electric energy to PSE’s service territory.
| Electric Margin | ||||||||||||||||
(Dollars in Millions) Three Months Ended June 30, | 2008 | 2007 | Change | Percent Change | ||||||||||||
Electric operating revenue1 | $ | 478.0 | $ | 435.3 | $ | 42.7 | 9.8 | % | ||||||||
| Less: Other electric operating revenue | (20.3 | ) | (15.8 | ) | (4.5 | ) | (28.5 | ) | ||||||||
| Add: Other electric operating revenue-gas supply resale | 8.3 | 4.7 | 3.6 | 76.6 | ||||||||||||
| Total electric revenue for margin | 466.0 | 424.2 | 41.8 | 9.9 | ||||||||||||
| Adjustments for amounts included in revenue: | ||||||||||||||||
| Pass-through tariff items | (16.2 | ) | (9.7 | ) | (6.5 | ) | (67.0 | ) | ||||||||
| Pass-through revenue-sensitive taxes | (32.9 | ) | (29.1 | ) | (3.8 | ) | (13.1 | ) | ||||||||
| Net electric revenue for margin | 416.9 | 385.4 | 31.5 | 8.2 | ||||||||||||
| Minus power costs: | ||||||||||||||||
Purchased electricity1 | (198.9 | ) | (172.8 | ) | (26.1 | ) | (15.1 | ) | ||||||||
Electric generation fuel1 | (32.7 | ) | (23.7 | ) | (9.0 | ) | (38.0 | ) | ||||||||
Residential exchange1 | 20.3 | 17.6 | 2.7 | 15.3 | ||||||||||||
| Total electric power costs | (211.3 | ) | (178.9 | ) | (32.4 | ) | (18.1 | ) | ||||||||
Electric margin2 | $ | 205.6 | $ | 206.5 | $ | (0.9 | ) | (0.4 | ) % | |||||||
____________________________
| 1 | As reported on PSE’s Consolidated Statement of Income. |
| 2 | Electric margin does not include any allocation for amortization/depreciation expense or electric generation operation and maintenance expense. |
Electric margin decreased $0.9 million for the three months ended June 30, 2008 as compared to the same period in 2007. Contributing to higher power costs was a 6.8% decline in hydroelectric energy production from both Company-owned facilities and sources under long-term contract as well as higher purchased power costs. As a result, electric margin decreased $9.6 million due to lower over collection of net power costs during the period. The over collection for the three months ended June 30, 2008 totaled $26.9 compared to the same period in 2007 of $36.5 million. Offsetting the decrease was an $8.8 million increase in electric margin due to a 4.9% increase in retail sales. Power cost recovery is seasonal with under recovery in the first and fourth quarters and over recovery in the second and third quarters.
The following table displays the details of electric margin changes for the six months ended June 30, 2008 compared to the same period in 2007. Electric margin is electric sales to retail and transportation customers less pass-through tariff items and revenue-sensitive taxes, and the cost of generating and purchasing electric energy sold to customers, including transmission costs to bring electric energy to PSE’s service territory.
| Electric Margin | ||||||||||||||||
(Dollars in Millions) Six Months Ended June 30, | 2008 | 2007 | Change | Percent Change | ||||||||||||
Electric operating revenue1 | $ | 1,084.2 | $ | 962.9 | $ | 121.3 | 12.6 | % | ||||||||
| Less: Other electric operating revenue | (32.5 | ) | (26.7 | ) | (5.8 | ) | (21.7 | ) | ||||||||
| Add: Other electric revenue-gas supply resale | 11.0 | 6.4 | 4.6 | 71.9 | ||||||||||||
| Total electric revenue for margin | 1,062.7 | 942.6 | 120.1 | 12.7 | ||||||||||||
| Adjustments for amounts included in revenue: | ||||||||||||||||
| Pass-through tariff items | (29.1 | ) | (20.9 | ) | (8.2 | ) | (39.2 | ) | ||||||||
| Pass-through revenue-sensitive taxes | (74.6 | ) | (65.7 | ) | (8.9 | ) | (13.5 | ) | ||||||||
| Net electric revenue for margin | 959.0 | 856.0 | 103.0 | 12.0 | ||||||||||||
| Minus power costs: | ||||||||||||||||
Purchased electricity1 | (471.7 | ) | (454.8 | ) | (16.9 | ) | (3.7 | ) | ||||||||
Electric generation fuel1 | (79.7 | ) | (49.8 | ) | (29.9 | ) | (60.0 | ) | ||||||||
Residential exchange1 | 20.3 | 52.0 | (31.7 | ) | (61.0 | ) | ||||||||||
| Total electric power costs | (531.1 | ) | (452.6 | ) | (78.5 | ) | (17.3 | ) | ||||||||
Electric margin2 | $ | 427.9 | $ | 403.4 | $ | 24.5 | 6.1 | % | ||||||||
| 1 | As reported on PSE’s Consolidated Statement of Income. |
| 2 | Electric margin does not include any allocation for amortization/depreciation expense or electric generation operation and maintenance expense. |
Electric margin increased $24.5 million for the six months ended June 30, 2008 compared to the same period in 2007. This is primarily due to a Power Cost Only Rate Case (PCORC) rate increase of 3.7% effective September 1, 2007, net of a 1.3% general rate decrease effective January 13, 2007 which increased electric margin by $5.3 million due in part to the recovery of Goldendale and Wild Horse facilities. In addition, a 4.4% increase in retail sales volumes increased electric margin by $17.0 million. Additionally, electric margin is positively impacted by $1.4 million due to an increase in overrecovery of power costs, $24.4 million for the six months ended June 30, 2008 compared to $23.0 million for the same period in 2007.
The following table displays the details of gas margin changes for the three months ended June 30, 2008 as compared to the same period in 2007. Gas margin is natural gas sales to retail and transportation customers less pass-through tariff items and revenue-sensitive taxes, and the cost of natural gas purchased, including transportation costs to bring natural gas to PSE’s service territory.
| Gas Margin | ||||||||||||||||
(Dollars in Millions) Three Months Ended June 30, | 2008 | 2007 | Change | Percent Change | ||||||||||||
Gas operating revenue1 | $ | 233.8 | $ | 225.2 | $ | 8.6 | 3.8 | % | ||||||||
| Less: Other gas operating revenue | (4.2 | ) | (4.4 | ) | 0.2 | 4.5 | ||||||||||
| Total gas revenue for margin | 229.6 | 220.8 | 8.8 | 4.0 | ||||||||||||
| Adjustments for amounts included in revenue: | ||||||||||||||||
| Pass-through tariff items | (2.3 | ) | (1.7 | ) | (0.6 | ) | (35.3 | ) | ||||||||
| Pass-through revenue-sensitive taxes | (20.3 | ) | (19.1 | ) | (1.2 | ) | (6.3 | ) | ||||||||
| Net gas revenue for margin | 207.0 | 200.0 | 7.0 | 3.5 | ||||||||||||
Minus purchased gas costs1 | (137.7 | ) | (139.1 | ) | 1.4 | 1.0 | ||||||||||
Gas margin2 | $ | 69.3 | $ | 60.9 | $ | 8.4 | 13.8 | % | ||||||||
| 1 | As reported on PSE’s Consolidated Statement of Income. |
| 2 | Gas margin does not include any allocation for amortization/depreciation expense or electric generation operations and maintenance expense. |
Gas margin increased $8.4 million for the three months ended June 30, 2008 as compared to the same period in 2007 primarily due to a 16.9% gas therm volume sales increase resulting in $10.3 million increase to gas margin. This increase was partially offset by a $1.9 million decrease in margin due to a change in customer mix and other pricing variances.
The following table displays the details of gas margin changes for the six months ended June 30, 2008 compared to the same period in 2007. Gas margin is natural gas sales to retail and transportation customers less pass-through tariff items and revenue-sensitive taxes, and the cost of natural gas purchased, including transportation costs to bring natural gas to PSE’s service territory.
| Gas Margin | ||||||||||||||||
(Dollars in Millions) Six Months Ended June 30, | 2008 | 2007 | Change | Percent Change | ||||||||||||
Gas operating revenue1 | $ | 677.1 | $ | 692.2 | $ | (15.1 | ) | (2.2 | ) % | |||||||
| Less: Other gas operating revenue | (8.9 | ) | (9.2 | ) | 0.3 | 3.3 | ||||||||||
| Total gas revenue for margin | 668.2 | 683.0 | (14.8 | ) | (2.2 | ) | ||||||||||
| Adjustments for amounts included in revenue: | ||||||||||||||||
| Pass-through tariff items | (6.7 | ) | (4.9 | ) | (1.8 | ) | (36.7 | ) | ||||||||
| Pass-through revenue-sensitive taxes | (55.4 | ) | (57.1 | ) | 1.7 | 3.0 | ||||||||||
| Net gas revenue for margin | 606.1 | 621.0 | (14.9 | ) | (2.4 | ) | ||||||||||
Less: Purchased gas costs1 | (413.9 | ) | (449.7 | ) | 35.8 | 8.0 | ||||||||||
Gas margin2 | $ | 192.2 | $ | 171.3 | $ | 20.9 | 12.2 | % | ||||||||
| 1 | As reported on PSE’s Consolidated Statement of Income. |
| 2 | Gas margin does not include any allocation for amortization/depreciation expense or electric generation operations and maintenance expense. |
Gas margin increased $20.9 million for the six months ended June 30, 2008 compared to the same period in 2007 primarily due to a 2.8% general rate increase effective January 13, 2007 which increased gas margin $5.4 million and a 11.0% gas therm volume sales increase which increased gas margin $18.9 million. This increase was offset by a $3.4 million decrease in margin due to a change in customer mix and other pricing variances.
Electric Operating Revenues
The table below sets forth changes in electric operating revenues for PSE for the three months ended June 30, 2008 as compared to the same period in 2007.
(Dollars in Millions) Three Months Ended June 30, | 2008 | 2007 | Change | Percent Change | ||||||||||||
| Electric operating revenues: | ||||||||||||||||
| Residential sales | $ | 237.1 | $ | 199.4 | $ | 37.7 | 18.9 | % | ||||||||
| Commercial sales | 189.4 | 173.5 | 15.9 | 9.2 | ||||||||||||
| Industrial sales | 26.1 | 25.1 | 1.0 | 4.0 | ||||||||||||
| Other retail sales, including unbilled revenue | (20.7 | ) | (7.9 | ) | (12.8 | ) | (162.0 | ) | ||||||||
| Total retail sales | 431.9 | 390.1 | 41.8 | 10.7 | ||||||||||||
| Transportation sales | 1.4 | 2.4 | (1.0 | ) | (41.7 | ) | ||||||||||
| Sales to other utilities and marketers | 24.4 | 27.1 | (2.7 | ) | (10.0 | ) | ||||||||||
| Other | 20.3 | 15.7 | 4.6 | 29.3 | ||||||||||||
| Total electric operating revenues | $ | 478.0 | $ | 435.3 | $ | 42.7 | 9.8 | % | ||||||||
Electric retail sales increased $41.8 million for the three months ended June 30, 2008 as compared to the same period in 2007. The increase in electricity usage was primarily related to customer growth and colder average temperatures in the Pacific Northwest. Second quarter 2008 heating degree days were 17% above historic averages for the Pacific Northwest while 2007 heating degrees were 5.9% below normal. Retail electricity usage increased 236,349 Megawatt Hours (MWh) or 4.9% compared to the same period in 2007, which resulted in an increase of approximately $20.1 million in electric operating revenue. The PCORC rate increase effective September 1, 2007 increased operating revenues $16.3 million for the three months ended June 30, 2008 as compared to the same period in 2007.
Sales to other utilities and marketers decreased $2.7 million for the three months ended June 30, 2008 as compared to the same period in 2007 primarily due to a decrease in sales volume of 2,915 MWh or 0.5% as a result of decreased surplus energy, which resulted in a decrease of $0.2 million. This decrease was also caused by lower wholesale prices in the second quarter 2008 as compared to the same period in 2007, which decreased sales by $2.5 million.
Other electric operating revenues increased $4.6 million for the three months ended June 30, 2008 as compared to the same period in 2007 primarily due to an increase of $3.7 million in gas sales to third parties and an increase of $1.5 million in transmission revenues.
The table below sets forth changes in electric operating revenues for PSE for the six months ended June 30, 2008 compared to the same period in 2007.
(Dollars in Millions) Six Months Ended June 30, | 2008 | 2007 | Change | Percent Change | ||||||||||||
| Electric operating revenues: | ||||||||||||||||
| Residential sales | $ | 583.7 | $ | 491.4 | $ | 92.3 | 18.8 | % | ||||||||
| Commercial sales | 401.5 | 373.0 | 28.5 | 7.6 | ||||||||||||
| Industrial sales | 53.5 | 52.3 | 1.2 | 2.3 | ||||||||||||
| Other retail sales, including unbilled revenue | (32.3 | ) | (31.6 | ) | (0.7 | ) | (2.2 | ) | ||||||||
| Total retail sales | 1,006.4 | 885.1 | 121.3 | 13.7 | ||||||||||||
| Transportation sales | 2.9 | 4.8 | (1.9 | ) | (39.6 | ) | ||||||||||
| Sales to other utilities and marketers | 42.4 | 46.3 | (3.9 | ) | (8.4 | ) | ||||||||||
| Other | 32.5 | 26.7 | 5.8 | 21.7 | ||||||||||||
| Total electric operating revenues | $ | 1,084.2 | $ | 962.9 | $ | 121.3 | 12.6 | % | ||||||||
Electric retail sales increased $121.3 million for the six months ended June 30, 2008 compared to the same period in 2007 due primarily to an increase in customer growth and colder average temperatures in the Pacific Northwest during the first half of 2008. Retail electricity usage increased 482,842 MWh or 4.4% for the six months ended June 30, 2008 compared to the same period in 2007, which resulted in an increase of approximately $43.0 million in electric operating revenue. The increase was also related to the PCORC rate increase of September 1, 2007 offset by the electric general rate decrease of January 13, 2007 which resulted in an increase of $51.4 million. During the six month period ended June 30, 2008, the benefits of the Residential and Farm Energy Exchange Benefit credited to customers reduced electric operating revenues by $21.2 million compared to $54.5 million for the same period in 2007. This credit also reduced power costs by a corresponding amount with no impact on earnings.
The following electric rate changes were approved by the Washington Commission in 2007:
Type of Rate Adjustment | Effective Date | Average Percentage Increase (Decrease) in Rates | Annual Increase (Decrease) in Revenues (Dollars in Millions) | |
| Electric General Rate Case | January 13, 2007 | (1.3 | ) % | $ (22.8) |
| Power Cost Only Rate Case | September 1, 2007 | 3.7 | 64.7 | |
Gas Operating Revenues
The table below sets forth changes in gas operating revenues for PSE for the three months ended June 30, 2008 as compared to the same period in 2007.
(Dollars in Millions) Three Months Ended June 30, | 2008 | 2007 | Change | Percent Change | ||||||||||||
| Gas operating revenues: | ||||||||||||||||
| Residential sales | $ | 144.3 | $ | 135.0 | $ | 9.3 | 6.9 | % | ||||||||
| Commercial sales | 72.1 | 72.4 | (0.3 | ) | (0.4 | ) | ||||||||||
| Industrial sales | 9.7 | 10.2 | (0.5 | ) | (4.9 | ) | ||||||||||
| Total retail sales | 226.1 | 217.6 | 8.5 | 3.9 | ||||||||||||
| Transportation sales | 3.4 | 3.2 | 0.2 | 6.3 | ||||||||||||
| Other | 4.3 | 4.4 | (0.1 | ) | (2.3 | ) | ||||||||||
| Total gas operating revenues | $ | 233.8 | $ | 225.2 | $ | 8.6 | 3.8 | % | ||||||||
Gas retail sales increased $8.5 million for the three months ended June 30, 2008 as compared to the same period in 2007 due to an increase in gas therm sales of 34.9 million or 16.9% reflecting customer growth and colder average temperatures in the Pacific Northwest which contributed $39.2 million. The increase was negatively impacted by the $31.5 million reduction in gas operating revenues as a result of a 13.0% Purchased Gas Adjustment (PGA) mechanism rate decrease for retail customers effective October 1, 2007. The PGA mechanism passes through to customers increases or decreases in the natural gas supply portion of the natural gas service rates based upon changes in the price of natural gas purchased from producers and wholesale marketers or changes in natural gas pipeline transportation costs. PSE’s gas margin and net income are not affected by changes under the PGA mechanism.
The table below sets forth changes in gas operating revenues for PSE for the six months ended June 30, 2008 compared to the same period in 2007.
(Dollars in Millions) Six Months Ended June 30, | 2008 | 2007 | Change | Percent Change | ||||||||||||
| Gas operating revenues: | ||||||||||||||||
| Residential sales | $ | 438.5 | $ | 435.8 | $ | 2.7 | 0.6 | % | ||||||||
| Commercial sales | 200.0 | 207.9 | (7.9 | ) | (3.8 | ) | ||||||||||
| Industrial sales | 22.5 | 32.5 | (10.0 | ) | (30.8 | ) | ||||||||||
| Total retail sales | 661.0 | 676.2 | (15.2 | ) | (2.2 | ) | ||||||||||
| Transportation sales | 7.2 | 6.8 | 0.4 | 5.9 | ||||||||||||
| Other | 8.9 | 9.2 | (0.3 | ) | (3.3 | ) | ||||||||||
| Total gas operating revenues | $ | 677.1 | $ | 692.2 | $ | (15.1 | ) | (2.2 | )% | |||||||
Gas retail sales decreased $15.2 million for the six months ended June 30, 2008 compared to the same period in 2007 due to lower PGA mechanism rates and increased customer natural gas usage. The Washington Commission approved a PGA mechanism rate decrease effective October 1, 2007. PSE’s gas margin and net income are not affected by changes under the PGA mechanism. The effects of the PGA mechanism rate decrease of 13.0% were offset by a 2.8% natural gas general rate increase effective January 13, 2007 provided a decrease of $87.0 million in natural gas operating revenues. The decrease was offset by higher gas sales of 67.8 million therms or 11.0% which increased gas operating revenue by $71.6 million. A 2.3% increase in natural gas customers and colder than average temperatures contributed to the higher natural gas sales.
The following natural gas rate adjustments were approved by the Washington Commission in 2007:
Type of Rate Adjustment | Effective Date | Average Percentage Increase (Decrease) in Rates | Annual Increase (Decrease) in Revenues (Dollars in Millions) | ||
| Gas General Rate Case | January 13, 2007 | 2.8 | % | $ 29.5 | |
| Purchased Gas Adjustment | October 1, 2007 | (13.0 | ) | (148.1 | ) |
Non-Utility Operating Revenues
The table below sets forth changes in non-utility operating revenues for PSE for the six months ended June 30, 2008 as compared to the same period in 2007.
(Dollars in Millions) Six Months Ended June 30, | 2008 | 2007 | Change | Percent Change | ||||||||||||
| Non-utility operating revenue | $ | 2.1 | $ | 10.0 | $ | (7.9 | ) | (79.0 | ) % | |||||||
Non-utility operating revenues decreased $7.9 million for the six months ended June 30, 2008 as compared to the same period in 2007 due to higher property sales during 2007 by PSE’s real estate subsidiary.
Operating Expenses
The table below sets forth significant changes in operating expenses for PSE and its subsidiaries for the three months ended June 30, 2008 as compared to the same period in 2007.
(Dollars in Millions) Three Months Ended June 30, | 2008 | 2007 | Change | Percent Change | ||||||||||||
| Purchased electricity | $ | 198.9 | $ | 172.8 | $ | 26.1 | 15.1 | % | ||||||||
| Electric generation fuel | 32.7 | 23.7 | 9.0 | 38.0 | ||||||||||||
| Residential exchange | (20.3 | ) | (17.6 | ) | (2.7 | ) | (15.3 | ) | ||||||||
| Purchased gas | 137.7 | 139.1 | (1.4 | ) | (1.0 | ) | ||||||||||
| Unrealized (gain) loss on derivative instruments | (2.4 | ) | 1.5 | (3.9 | ) | * | ||||||||||
| Utility operations and maintenance | 116.5 | 98.9 | 17.6 | 17.8 | ||||||||||||
| Depreciation and amortization | 76.3 | 65.7 | 10.6 | 16.1 | ||||||||||||
| Conservation amortization | 15.5 | 8.8 | 6.8 | 76.1 | ||||||||||||
| Taxes other than income taxes | 63.7 | 63.3 | 0.4 | 0.6 | ||||||||||||
| * | Percent change not applicable or meaningful |
The table below sets forth significant changes in operating expenses for PSE and its subsidiaries for the six months ended June 30, 2008 compared to the same period in 2007.
(Dollars in Millions) Six Months Ended June 30, | 2008 | 2007 | Change | Percent Change | ||||||||||||
| Purchased electricity | $ | 471.7 | $ | 454.8 | $ | 16.9 | 3.7 | % | ||||||||
| Electric generation fuel | 79.7 | 49.8 | 29.9 | 60.0 | ||||||||||||
| Residential exchange credit | (20.3 | ) | (52.0 | ) | 31.7 | 61.0 | ||||||||||
| Purchased gas | 413.9 | 449.7 | (35.8 | ) | (8.0 | ) | ||||||||||
| Unrealized (gain) loss on derivative instruments | (2.3 | ) | (4.3 | ) | 2.0 | 46.5 | ||||||||||
| Utility operations and maintenance | 228.6 | 197.1 | 31.5 | 16.0 | ||||||||||||
| Non-utility expense and other | 1.7 | 4.6 | (2.9 | ) | (63.0 | ) | ||||||||||
| Depreciation and amortization | 151.7 | 135.4 | 16.3 | 12.0 | ||||||||||||
| Conservation amortization | 28.9 | 19.1 | 9.8 | 51.3 | ||||||||||||
| Taxes other than income taxes | 158.0 | 150.4 | 7.6 | 5.1 | ||||||||||||
Purchased electricity expenses increased $26.1 million and $16.9 million for the three and six months ended June 30, 2008, respectively, as compared to the same period in 2007. This increase for the three months ended June 30, 2008 was primarily due to an increase in the amount of purchased power, 229,324 MWh or 5.7%. The increase in purchased power was caused by increased load due to cooler temperatures during the three months ended June 30, 2008 and from lower hydroelectric energy supplies from both company-owned facilities and long term power supply contracts, as well as higher market prices for purchased power. The lower hydroelectric and Colstrip generation was offset by increased generation from PSE’s wind generation facilities, and combustion turbines (primarily Goldendale and Frederickson). The additional purchased power resulted in an increase of $8.6 million in purchased electricity expenses. This increase was also impacted by higher wholesale market prices which caused an increase of $15.7 million and transmission and other power supply expenses of $2.2 million due in part to increased kilowatt hour (kWh) sales to customers. The increase for the six months ended June 30, 2008 was primarily the result of higher wholesale market prices which contributed $18.6 million offset by a decrease in purchased power of 106,122 MWh or 1.2%, resulting in a decrease of $4.9 million. The decrease in purchased power is related to increased production from company-owned combustion turbines, wind facilities and thermal generating facilities. Also contributing to the increase were increased transmission costs and other expenses, which contributed $3.2 million due in part to increased kWh sales to customers.
The July 8, 2008 Columbia Basin Runoff Forecast published by the National Weather Service Northwest River Forecast Center indicated that the total forecasted runoff above Grand Coulee Reservoir for the period January through July 2008 is 97% of normal, which compares to 102% of normal runoff observed for the same period in 2007.
To meet customer demand, PSE economically dispatches resources in its power supply portfolio such as fossil-fuel generation, owned and contracted hydroelectric capacity and energy and long-term contracted power. However, depending principally upon availability of hydroelectric energy, plant availability, fuel prices and/or changing load as a result of weather, PSE may sell surplus power or purchase deficit power in the wholesale market. PSE manages its regulated power portfolio through short-term and intermediate-term off-system physical purchases and sales and through other risk management techniques.
Electric generation fuel expense increased $9.0 million and $29.9 million for the three and six months ended June 30, 2008, respectively, as compared to the same period in 2007. The increase for the three months ended June 30, 2008 was due in part to increased generation from Goldendale and Frederickson combustion turbines which contributed $5.3 million and $4.1 million. The increase for the six months ended June 30, 2008 was primarily due to the operations of Goldendale and Frederickson combustion turbines which contributed $22.1 million and $10.0 million in 2008 compared to 2007.
Residential exchange credits associated with the Bonneville Power Administration (BPA) Residential Exchange Program (REP) decreased $2.7 million and increased $31.7 million for the three and six months ended June 30, 2008, respectively, as compared to the same period in 2007 as a result of the suspension of the residential and small farm customer electric credit in rates effective June 7, 2007. The suspension was due to an adverse ruling from the U.S. Court of Appeals for the Ninth Circuit (Ninth Circuit) which states that BPA actions in entering into residential exchange settlement agreements with investor owned utilities were not in accordance with the law. In April 2008, PSE signed an agreement pursuant to which BPA would pay PSE $53.7 million for fiscal year 2008 REP benefits. Of this amount PSE received approval to pass-through to customers approximately $20.0 million over a one-month period. The remaining $33.7 million was used to offset PSE’s regulatory asset. The REP credit is a pass-through tariff item with a corresponding credit in electric operating revenue; thus, it has no impact on electric margin or net income.
Purchased gas expenses decreased $1.4 million and $35.8 million for the three and six months ended June 30, 2008, respectively, as compared to the same period in 2007 primarily due to a decrease in PGA rates, partially offset by higher customer therm sales. The PGA mechanism allows PSE to recover expected natural gas supply and transportation costs, and defer, as a receivable or liability, any natural gas supply and transportation costs that exceed or fall short of this expected gas cost amount in PGA mechanism rates, including accrued interest. The PGA mechanism payable balance at June 30, 2008 was $26.8 million as compared to $77.9 million at December 31, 2007. PSE is authorized by the Washington Commission to accrue carrying costs on PGA receivable and payable balances. A receivable balance in the PGA mechanism reflects an under recovery of market natural gas cost through rates. A payable balance reflects over recovery of market natural gas cost through rates.
Unrealized gain on derivative instruments increased $3.9 million and decreased $2.0 million for the three and six months ended June 30, 2008, respectively, as compared to the same period in 2007. The increase for the three months ended June 30, 2008 as compared to the same period in 2007 was primarily related to the ineffective portion of a cash flow hedge due to an increase in future wholesale market electric prices as compared to the contract price. The increase was partially offset by an unrealized loss on a locational exchange power contract. The decrease for the six months ended June 30, 2008 as compared to the same period in 2007 was primarily due to the reversal in 2007 of the loss reserve and settlement of a physically delivered natural gas supply contract for PSE’s electric generating facilities along with an increase in the loss of a locational exchange power contract. The decrease was offset by an unrealized gain on the ineffective portion of a cash flow hedge due to increase in future wholesale market electric prices as compared to the contract price.
Utility operations and maintenance expense increased $17.6 million and $31.5 million for the three and six months ended June 30, 2008, respectively, as compared to the same period in 2007. The increase for the three months ended June 30, 2008 was primarily due to an increase of $5.5 million in production operations and maintenance at PSE’s generating facilities, $3.8 million increase in electric transmission and distribution expenses, $3.6 million increase in administrative and general costs, $3.5 million higher gas operations and distribution costs and a $1.3 million increase in customer service costs. The increase for the six months ended June 30, 2008 was primarily due to $18.5 million in production operations and maintenance at PSE’s generating facilities, $5.8 million increases in gas operations and distribution costs, $3.6 million increase in administrative and general costs, and $2.9 million increase in customer service costs.
Non-utility expense and other decreased $2.9 million for the six months ended June 30, 2008, as compared to the same period in 2007 primarily due to a decrease in PSE’s long-term incentive plan costs.
Depreciation and amortization expense increased $10.5 million and $16.3 million for the three and six months ended June 30, 2008, respectively, as compared to the same period in 2007. These increases include the benefit of the 2007 deferral of Goldendale ownership and operating costs of $5.9 million and $6.9 million for the three and six months ended June 30, 2007, respectively, which, had it not been included, would have resulted in an increase to depreciation and amortization expense of $4.6 million and $9.3 million for the three and six months ended June 30 2008, respectively, as compared to the same periods in 2007. The Goldendale deferral of ownership and operating costs ceased to be effective September 1, 2007, when PSE was authorized to begin recovering the costs in rates. The increase, excluding Goldendale deferral, was primarily due to placing additional utility plants into service during the last 12 months.
Conservation amortization increased $6.8 million and $9.8 million for the three and six months ended June 30, 2008, respectively, as compared to the same period in 2007 due to higher authorized recovery of electric conservation expenditures. Conservation amortization is a pass-through tariff item with no impact on earnings.
Taxes other than income taxes increased $0.4 million and $7.6 million for the three and six months ended June 30, 2008, respectively, as compared to the same period in 2007. The increase for the three months ended June 30, 2008 was due to increases in revenue-based Washington State excise tax and municipal tax due to increased operating revenue. Revenue sensitive Washington State excise and municipal taxes have no impact on earnings. Excluding the impact of revenue sensitive taxes, taxes other than income taxes decreased $5.0 million primarily as a result of truing up 2007 levy rates based on property tax billings. The increase for the six months ended June 30, 2008 was due to increases in revenue-based Washington State excise tax and municipal tax as a result of increased operating revenues.
Other Income, Other Expenses, Interest Expense and Income Tax Expense
The table below sets forth significant changes in other income, other expenses, interest expense and income tax expense for PSE and its subsidiaries for the three months ended June 30, 2008 as compared to the same period in 2007.
(Dollars in Millions) Three Months Ended June 30, | 2008 | 2007 | Change | Percent Change | ||||||||||||
| Other income | $ | 8.1 | $ | 6.2 | $ | 1.9 | 30.6 | % | ||||||||
| Other expense | (0.8 | ) | (2.8 | ) | 2.0 | 71.4 | ||||||||||
| Interest charge | (47.0 | ) | (49.6 | ) | 2.6 | 5.2 | ||||||||||
| Income tax expense | (13.3 | ) | (17.7 | ) | 4.4 | 24.9 | ||||||||||
Other income increased $1.9 million for the three months ended June 30, 2008 as compared to the same period in 2007 primarily due a $0.9 million increase related to Washington Commission Allowance for Funds Used During Construction (AFUDC) and $0.6 million increase due to Washington Commission AFUDC equity.
Other expense decreased $2.0 million for the three months ended June 30, 2008 as compared to the same period in 2007 primarily due to the accrual in 2007 of a recordkeeping violation penalty assessed by the Washington Commission, which is not tax-deductible.
Interest expense decreased $2.6 million due primarily to the decrease in average debt outstanding as a result of the equity issuance in December 2007 and lower average interest rates on outstanding debt.
Income tax expense decreased $4.4 million for the three months ended June 30, 2008 as compared to the same period in 2007 due primarily to a lower effective tax rate as a result of an increased amount of production tax credits.
The table below sets forth significant changes in other income, interest charges and income taxes for PSE and its subsidiaries for the six months ended June 30, 2008 compared to the same period in 2007.
(Dollars in Millions) Six Months Ended June 30, | 2008 | 2007 | Change | Percent Change | ||||||||||||
| Other income | $ | 14.9 | $ | 11.0 | $ | 3.9 | 35.5 | % | ||||||||
| Other expense | (1.8 | ) | (3.9 | ) | 2.1 | 53.8 | ||||||||||
| Interest charge | (95.8 | ) | (98.8 | ) | 3.0 | 3.0 | ||||||||||
| Income tax expense | (49.0 | ) | (51.7 | ) | 2.7 | 5.2 | ||||||||||
Other income increased $3.9 million for the six months ended June 30, 2008 compared to the same period in 2007 primarily due to an increase in Washington Commission AFUDC and an increase in regulatory interest on the Residential Exchange Regulatory Asset.
Other expenses decreased $2.1 million for the six months ended June 30, 2008 compared to the same period in 2007 primarily due to a decrease in non-tax deductible penalties of $2.3 million. The decrease is primarily related to the 2007 recordkeeping violation penalty assessed by the Washington Commission, which is not tax-deductible.
Interest expense decreased $3.0 million due primarily to lower average debt outstanding as a result of the equity issuance in December 2007 and lower average interest rate on outstanding debt.
Income tax expense decreased $2.7 million for the six months ended June 30, 2008 compared to the same period in 2007 due primarily to higher tax credits associated with the production of wind-powered energy. The production tax credits for the six months ended June 30, 2008 increased $3.7 million compared to the same period in 2007.
Capital Requirements
Contractual Obligations and Commercial Commitments
Puget Energy. The following are Puget Energy’s aggregate consolidated (including PSE) contractual obligations and commercial commitments as of June 30, 2008:
| Puget Energy | Payments Due Per Period | |||||||||
Contractual Obligations (Dollars in Millions) | Total | 2008 | 2009- 2010 | 2011- 2012 | 2013 & Thereafter | |||||
| Long-term debt including interest | $ | 6,283.1 | $ | 209.2 | $ | 712.8 | $ | 520.9 | $ | 4,840.2 |
| Short-term debt including interest | 286.6 | 286.6 | -- | -- | -- | |||||
| Mandatorily redeemable preferred stock | 1.9 | -- | -- | -- | 1.9 | |||||
| Service contract obligations | 398.0 | 36.8 | 128.4 | 94.5 | 138.3 | |||||
| Non-cancelable operating leases | 162.7 | 8.3 | 50.9 | 25.7 | 77.8 | |||||
Fredonia combustion turbines lease 1 | 49.5 | 2.3 | 7.7 | 39.5 | -- | |||||
| Energy purchase obligations | 6,962.0 | 910.1 | 2,307.8 | 1,220.6 | 2,523.5 | |||||
| Contract initiation payment/collateral requirement | 18.5 | -- | -- | 18.5 | -- | |||||
| Financial hedge obligations | (154.0 | ) | (64.6 | ) | (89.4 | ) | -- | -- | ||
| Purchase obligations | 66.1 | 27.3 | 22.7 | -- | 16.1 | |||||
| Pension and other benefits funding and payments | 40.3 | 4.5 | 8.1 | 8.0 | 19.7 | |||||
| Other obligations | 6.7 | 6.7 | -- | -- | -- | |||||
| Total contractual cash obligations | $ | 14,121.4 | $ | 1,427.2 | $ | 3,149.0 | $ | 1,927.7 | $ | 7,617.5 |
Puget Energy | Amount of Commitment Expiration Per Period | |||||||||
Commercial Commitments (Dollars in Millions) | Total | 2008 | 2009- 2010 | 2011- 2012 | 2013 & Thereafter | |||||
Credit agreement - available 2 | $ | 671.0 | $ | -- | $ | -- | $ | 671.0 | $ | -- |
Receivable securitization facility 3 | 85.0 | -- | 85.0 | -- | -- | |||||
| Energy operations letter of credit | 7.4 | 7.4 | -- | -- | -- | |||||
| Total commercial commitments | $ | 763.4 | $ | 7.4 | $ | 85.0 | $ | 671.0 | $ | -- |
________________
| 1 | See “Fredonia 3 and 4 Operating Lease” under “Off-Balance Sheet Arrangements” below. |
| 2 | At June 30, 2008, PSE had available a $500.0 million and a $350.0 million unsecured credit agreements expiring in April 2012. The credit agreements provide credit support for letters of credit and commercial paper. At June 30, 2008, PSE had $7.4 million outstanding under four letters of credit and $171.6 million commercial paper outstanding, effectively reducing the available borrowing capacity to $671 million. |
| 3 | At June 30, 2008, PSE had available a $200.0 million receivables securitization facility that expires in December 2010. $115.0 million was outstanding under the receivables securitization facility at June 30, 2008 thus leaving $85.0 million available. The facility allows receivables to be used as collateral to secure short-term loans, not exceeding the lesser of $200.0 million or the borrowing base of eligible receivables, which fluctuate with the seasonality of energy sales to customers. See “Receivables Securitization Facility” below for further discussion. |
Puget Sound Energy. The following are PSE’s aggregate contractual obligations and commercial commitments as of June 30, 2008:
| Puget Sound Energy | Payments Due Per Period | |||||||||
Contractual Obligations (Dollars in Millions) | Total | 2008 | 2009- 2010 | 2011- 2012 | 2013 & Thereafter | |||||
| Long-term debt including interest | $ | 6,283.1 | $ | 209.2 | $ | 712.8 | $ | 520.9 | $ | 4,840.2 |
| Short-term debt including interest | 311.7 | 311.7 | -- | -- | -- | |||||
| Mandatorily redeemable preferred stock | 1.9 | -- | -- | -- | 1.9 | |||||
| Service contract obligations | 398.0 | 36.8 | 128.4 | 94.5 | 138.3 | |||||
| Non-cancelable operating leases | 162.7 | 8.3 | 50.9 | 25.7 | 77.8 | |||||
Fredonia combustion turbines lease 1 | 49.5 | 2.3 | 7.7 | 39.5 | -- | |||||
| Energy purchase obligations | 6,962.0 | 910.1 | 2,307.8 | 1,220.6 | 2,523.5 | |||||
| Contract initiation payment/collateral requirement | 18.5 | -- | -- | 18.5 | -- | |||||
| Financial hedge obligations | (154.0 | ) | (64.6 | ) | (89.4 | ) | -- | -- | ||
| Purchase obligations | 66.1 | 27.3 | 22.7 | -- | 16.1 | |||||
| Pension and other benefits funding and payments | 40.3 | 4.5 | 8.1 | 8.0 | 19.7 | |||||
| Other obligations | 6.7 | 6.7 | -- | -- | -- | |||||
| Total contractual cash obligations | $ | 14,146.5 | $ | 1,452.3 | $ | 3,149.0 | $ | 1,927.7 | $ | 7,617.5 |
| Puget Sound Energy | Amount of Commitment Expiration Per Period | |||||||||
Commercial Commitments (Dollars in Millions) | Total | 2008 | 2009- 2010 | 2011- 2012 | 2013 & Thereafter | |||||
Credit agreement - available 2 | $ | 671.0 | $ | -- | $ | -- | $ | 671.0 | $ | -- |
Receivable securitization facility 3 | 85.0 | -- | 85.0 | -- | -- | |||||
| Energy operations letter of credit | 7.4 | 7.4 | -- | -- | -- | |||||
| Total commercial commitments | $ | 763.4 | $ | 7.4 | $ | 85.0 | $ | 671.0 | $ | -- |
________________
| 1 | See note 1 under Puget Energy above. |
| 2 | See note 2 under Puget Energy above. |
| 3 | See note 3 under Puget Energy above. |
Off-Balance Sheet Arrangements
Fredonia 3 and 4 Operating Lease. PSE leases two combustion turbines for its Fredonia 3 and 4 electric generating facility pursuant to a master operating lease that was amended for this purpose in April 2001. The lease has a term expiring in 2011, but can be canceled by PSE at any time. Payments under the lease vary with changes in the London Interbank Offered Rate (LIBOR). At June 30, 2008, PSE’s outstanding balance under the lease was $46.9 million. The expected residual value under the lease is the lesser of $37.4 million or 60.0% of the cost of the equipment. In the event the equipment is sold to a third party upon termination of the lease and the aggregate sales proceeds are less than the unamortized value of the equipment, PSE would be required to pay the lessor contingent rent in an amount equal to the deficiency up to a maximum of 87.0% of the unamortized value of the equipment.
Utility Construction Program
PSE’s construction programs for generating facilities, the electric transmission system and the natural gas and electric distribution systems are designed to meet continuing customer growth and to support reliable energy delivery. The cash flow construction expenditures, excluding equity AFUDC and customer refundable contributions was $251.3 million for the three months ended June 30, 2008. The anticipated utility construction expenditures, excluding AFUDC, for 2008, 2009 and 2010 are:
Capital Expenditure Estimates (Dollars in Millions) | 2008 | 2009 | 2010 | |||||||||
| Energy delivery, technology and facilities | $ | 595.0 | $ | 568.0 | $ | 743.0 | ||||||
| New supply resources | 72.0 | 220.0 | 514.0 | |||||||||
| Total expenditures | $ | 667.0 | $ | 788.0 | $ | 1,257.0 | ||||||
The proposed utility construction expenditures and any new generation resource expenditures that may be incurred are anticipated to be funded with a combination of cash from operations, short-term debt, long-term debt and equity. Construction expenditure estimates, including any new generation resources, are subject to periodic review and adjustment in light of changing economic, regulatory, environmental and efficiency factors.
Capital Resources
Cash From Operations
Cash generated from operations for the six months ended June 30, 2008 was $507.8 million, which is 179.6% of the $282.8 million cash used for utility construction expenditures and other capital expenditures. For the six months ended June 30, 2007, cash from operations was $345.9 million, which was 87.7% of the $394.2 million cash used for utility construction expenditures and other capital expenditures.
The overall cash generated from operating activities for the six months ended June 30, 2008 increased $161.9 million compared to the same period in 2007. The increase was primarily the result of lower cash payments of $122.5 million related to accounts payable, cash received in 2008 compared to payments in 2007 related to the REP which contributed $58.1 million and income tax refunds of $42.4 million. Further, cash from operations increased due to lower cash payments for prepaid expenses of $27.3 million, lower cash payments of $16.2 million related to deferred storm damage costs and $16.0 million recovery in materials and supplies for the six months ended June 30, 2008. Cash from operations also increased due to $9.8 million collection of energy conservation expenditures. The increase was partially offset by a reduction of the purchased gas liability in 2008 of $51.1 million as compared to under collection of $81.4 million in 2007, which resulted in a decrease in cash of $132.5 million. In addition, the increase was offset by a cash receipt of $18.9 million in 2007 from the lease purchase option settlement for the Bellevue offices.
Financing Program
Financing utility construction requirements and operational needs are dependent upon the cost and availability of external funds through capital markets and from financial institutions. Access to funds depends upon factors such as general economic conditions, regulatory authorizations and policies and Puget Energy’s and PSE’s credit ratings.
Restrictive Covenants
In determining the type and amount of future financing, PSE may be limited by restrictions contained in its electric and natural gas mortgage indentures, restated articles of incorporation and certain loan agreements. Under the most restrictive tests, at June 30, 2008, PSE could issue:
| · | approximately $742.0 million of additional first mortgage bonds under PSE’s electric mortgage indenture based on approximately $1.2 billion of electric bondable property available for issuance, subject to an interest coverage ratio limitation of 2.0 times net earnings available for interest (as defined in the electric utility mortgage), which PSE exceeded at June 30, 2008; |
| · | approximately $507.0 million of additional first mortgage bonds under PSE’s natural gas mortgage indenture based on approximately $845.0 million of gas bondable property available for issuance, subject to interest coverage ratio limitations of 1.75 times and 2.0 times net earnings available for interest (as defined in the natural gas utility mortgage), which PSE exceeded at June 30, 2008; |
| · | approximately $1.3 billion of additional preferred stock at an assumed dividend rate of 8.5%; and |
| · | approximately $771.9 million of unsecured long-term debt. |
At June 30, 2008, PSE had approximately $4.8 billion in electric and natural gas ratebase to support the interest coverage ratio limitation test for net earnings available for interest.
Credit Ratings
Neither Puget Energy nor PSE has any debt outstanding that would accelerate debt maturity upon a credit rating downgrade. A ratings downgrade could adversely affect the ability to renew existing, or obtain access to new credit facilities and could increase the cost of such facilities. For example, under PSE’s revolving credit facility, the borrowing costs and commitment fee increase as PSE’s secured long-term debt ratings decline. A downgrade in commercial paper ratings could preclude PSE’s ability to issue commercial paper under its current programs. The marketability of PSE commercial paper is currently limited by the A-3/P-2 ratings by Standard & Poor’s and Moody’s Investors Service. In addition, downgrades in PSE’s debt ratings may prompt counterparties to require PSE to post a letter of credit or other collateral, make cash prepayments, obtain a guarantee or provide other security.
The ratings of Puget Energy and PSE, as of July 25, 2008, were as follows:
| Ratings | ||
Standard & Poor’s1,2 | Moody’s3 | |
| Puget Sound Energy | ||
| Corporate credit/issuer rating | BBB- | Baa3 |
| Senior secured debt | BBB+ | Baa2 |
| Junior subordinated notes | BB | Ba1 |
| Preferred stock | BB | Ba2 |
| Commercial paper | A-3 | P-2 |
| Revolving credit facility | Note 1 | Baa3 |
| Ratings outlook | Note 2 | Note 3 |
| Puget Energy | ||
| Corporate credit/issuer rating | BBB- | Ba1 |
| Ratings outlook | Note 2 | Note 3 |
_______________
| 1 | Standard & Poor’s does not rate PSE’s credit facilities. |
| 2 | On October 26, 2007, Standard & Poor’s placed the ratings of Puget Energy (BBB-) and PSE (BBB-/A-3) on CreditWatch with negative implications. The CreditWatch listing reflects the possibility that debt ratings for Puget Energy could be lowered dependent on the final outcome of regulatory approval proceedings. |
| 3 | On October 29, 2007, Moody’s placed the Ba1 Issuer rating of Puget Energy on review for possible downgrade. Moody’s also affirmed the long-term ratings of PSE and changed its rating outlook to stable from positive. On this same date, Moody’s placed PSE’s P-2 short-term rating for commercial paper under review for possible downgrade. |
Shelf Registrations, Long-Term Debt and Common Stock Activity
Liquidity Facilities and Commercial Paper
PSE’s short-term borrowings and sales of commercial paper are used to provide working capital to fund utility construction programs. PSE has not been significantly impacted by the current credit environment.
PSE Credit Facilities
The Company has three committed credit facilities that provide, in aggregate, $1.05 billion in short-term borrowing capability. These include a $500.0 million credit agreement, a $200.0 million accounts receivable securitization facility and a $350.0 million credit agreement to support hedging activity.
Credit Agreements. In March 2007, PSE entered into a five-year, $350.0 million credit agreement with a group of banks. The agreement is used to support the Company’s energy hedging activities and may also be used to provide letters of credit. The interest rate on outstanding borrowings is based either on the agent bank’s prime rate or on LIBOR plus a marginal rate related to PSE’s long-term credit rating at the time of borrowing. PSE pays a commitment fee on any unused portion of the credit agreement also related to long-term credit ratings of PSE. At June 30, 2008, there were no borrowings or letters of credit outstanding under the credit facility.
In March 2005, PSE entered into a five-year $500.0 million unsecured credit agreement with a group of banks. In March 2007, PSE restated this credit agreement to extend the expiration date to April 2012. The agreement is primarily used to provide credit support for commercial paper and letters of credit. The terms of this agreement, as restated, are essentially identical to those contained in the $350.0 million facility described above.
At June 30, 2008, there was $7.4 million outstanding under four letters of credit and $171.6 million commercial paper outstanding, effectively reducing the available borrowing capacity under the two credit agreements to $671.0 million.
Receivables Securitization Facility. PSE entered into a five-year Receivable Sales Agreement with PSE Funding, Inc. (PSE Funding), a wholly owned subsidiary, on December 20, 2005. Pursuant to the Receivables Sales Agreement, PSE sells all of its utility customer accounts receivable and unbilled utility revenues to PSE Funding. In addition, PSE Funding entered into a Loan and Servicing Agreement with PSE and two banks. The Loan and Servicing Agreement allows PSE Funding to use the receivables as collateral to secure short-term loans, not exceeding the lesser of $200.0 million or the borrowing base of eligible receivables which fluctuate with the seasonality of energy sales to customers. All loans from this facility are reported as short-term debt in the financial statements. The PSE Funding facility expires in December 2010, and is terminable by PSE and PSE Funding upon notice to the banks. There were $115.0 million in loans that were secured by accounts receivable pledged at June 30, 2008. The remaining borrowing base of eligible receivables at June 30, 2008 was $85.0 million.
Demand Promissory Note. On June 1, 2006, PSE entered into an uncommitted revolving credit facility with its parent, Puget Energy, pursuant to a Demand Promissory Note (Note) under which PSE may borrow up to $30.0 million from Puget Energy. Under the terms of the Note, PSE pays interest on the outstanding borrowings based on the lowest of the weighted-average interest rate of (a) PSE’s outstanding commercial paper interest rate; (b) PSE’s senior unsecured revolving credit facility; or (c) the interest rate available under the receivable securitization facility of PSE Funding, a PSE subsidiary. At June 30, 2008, the outstanding balance of the Note was $25.0 million. The outstanding balance and the related interest under the Note are eliminated by Puget Energy upon consolidation of PSE’s financial statements.
Stock Purchase and Dividend Reinvestment Plan
Puget Energy has a Stock Purchase and Dividend Reinvestment Plan pursuant to which shareholders and other interested investors may invest cash and cash dividends in shares of Puget Energy common stock. Since new shares of common stock may be purchased directly from Puget Energy, funds received may be used for general corporate purposes. Puget Energy did not issue common stock under the Stock Purchase and Dividend Reinvestment Plan for the three and six months ended June 30, 2008, as compared to $3.2 million (124,995 shares) and $6.5 million (255,891 shares) for the three and months ended June 30, 2007, respectively. The proceeds from sales of stock under the Stock Purchase and Dividend Reinvestment Plan are used for general corporate needs. Pending the outcome of the merger, Puget Energy intends to fund the Stock Purchase and Dividend Reimbursement Plan with shares acquired in the public markets.
Common Stock Offering Programs
To provide additional financing options, Puget Energy entered into agreements in July 2003 with two financial institutions under which Puget Energy may offer and sell shares of its common stock from time to time through these institutions as sales agents, or as principals. Sales of the common stock, if any, may be made by means of negotiated transactions or in transactions that may be deemed to be “at-the-market” offerings as defined in Rule 415 promulgated under the Securities Act of 1933, including in ordinary brokers’ transactions on the New York Stock Exchange at market prices.
Other
Regulation and Rates
On December 3, 2007, PSE filed a general rate case with the Washington Commission which proposed an increase in electric rates of $174.5 million, and in an increase in natural gas rates of $56.8 million, effective November 3, 2008. PSE requested a weighted cost of capital of 8.6%, or 7.29% after-tax, and a capital structure that included 45.0% common equity with a return on equity of 10.8%. In July 2008, PSE filed rebuttal testimony and revised its proposed increase in electric rates to $165.2 million and natural gas rates to $55.5 million. PSE expects an order to be issued by the Washington Commission no later than October 31, 2008.
In November 2007, the Western Electricity Coordinating Council (WECC) audited PSE’s compliance with electric reliability standards adopted by FERC, the North American Electric Reliability Corporation (NERC) and/or WECC. Compliance with these standards includes periodic self-certifications of compliance, self-reports of violations after discovery of the violation, spot checks to review self-certifications and external audits that review compliance with designated standards in detail. The WECC audit team identified four potential violations of the standards that PSE had not previously self-reported. Several months after the audit, WECC issued a “Notice of Alleged Violations” to PSE, adding details and proposed penalties to the proposed findings. Under the rules for the process, PSE met with WECC representatives in July to discuss settlement. PSE is hopeful that all issues concerning the four potential violations will be resolved. Resolution of reliability standards issues will be an ongoing concern, however, PSE self-reports violations when they are discovered. Such self-reports could result in settlement of issues or issuances of penalties in the future.
In May 2007, the Washington Commission Staff alleged that PSE’s natural gas system service provider had violated certain Washington Commission recordkeeping rules. On April 3, 2008, the Washington Commission issued an order approving a settlement agreement that requires PSE to pay a regulatory penalty of $1.25 million, to establish a quality assurance program to better monitor its subcontractors and to complete an independent audit of natural gas system recordkeeping procedures.
Accounting Petition. On August 29, 2007, the Washington Commission approved PSE’s accounting petition to defer as a regulatory asset the excess BPA REP benefit provided to customers and accrue monthly carrying charges on the deferred balance from June 7, 2007 until the deferral is recovered from customers or BPA.
On December 17, 2007, BPA released a proposal for public comment which would provide temporary, interim relief to the region’s investor-owned utilities until final REP contracts are reached and executed which are planned to go into effect October 1, 2008. These interim agreements are offered in exchange for suspension of certain litigation activities and will be trued-up to the actual final REP benefits for each individual company as established in BPA’s upcoming administrative proceedings. In March 2008, BPA and PSE signed an agreement pursuant to which BPA (on April 2, 2008) paid PSE $53.7 million in REP benefits for fiscal year 2008, which payment is subject to true-up depending upon the amount of any REP benefits ultimately determined to be payable to PSE.
On April 10, 2008, the Washington Commission approved PSE’s tariff filing seeking to pass-through the net amount of the benefits under the interim agreements to residential and small farm customers. The Washington Commission also approved PSE’s request to credit the regulatory asset amount of $33.7 million against the $53.7 million payment and pass-through to customers the remaining amount of approximately $20.0 million. The accrued carrying charges on the regulatory asset totaling $3.1 million at June 30, 2008 will be addressed in PSE’s pending general rate case (Docket No. UE-072300).
Colstrip Matters
In May 2003, approximately 50 plaintiffs initiated an action against the owners of Colstrip alleging that (1) seepage from two different wastewater pond areas caused groundwater contamination and threatened to contaminate domestic water wells and the Colstrip water supply pond, and (2) seepage from the Colstrip water supply pond caused structural damage to buildings and toxic mold. The defendants reached agreement on a global settlement with all plaintiffs on April 29, 2008 and PSE paid its share of the settlement in the amount of $10.7 million in July 2008. PSE had previously expensed the settlement in the first quarter 2008. PSE has also filed an accounting petition with the Washington Commission to recover such costs in the future.
The Minerals Management Service of the United States Department of Interior (MMS) has issued a series of orders to Western Energy Company (WECO) to pay additional taxes and royalties concerning coal WECO sold to the owners of Colstrip 3 & 4, and similar orders have been issued in the administrative appellate process. The orders assert that additional royalties are owed in connection with payments received by WECO from Colstrip 3 & 4 owners (including PSE) for the construction and operation of a conveyor system that runs several miles from the mine to Colstrip 3 & 4. The state of Montana has also issued a demand to WECO consistent with the MMS position. WECO has challenged these orders, and the issue has been on appeal for several years. WECO has won some points during the appellate process that have reduced the claims; however under applicable law, to pursue the appeals, the principal in dispute cannot be paid, which causes interest to accrue. Moreover, because the conveyor system continues to be used, the amount in dispute grows. In the aggregate, the accrued interest plus unasserted claims to bring the amount current could make the total claim (principal plus interest) pertaining to PSE’s 25.0% project share as high as $10.0 million. PSE and the other Colstrip 3 & 4 owners authorized WECO to make a settlement offer to the Montana Department of Revenue (DOR) and the MMS in Connection with these claims. PSE recorded a $1.2 million pre-tax loss reserve in the second quarter of 2008 in that regard.
Proceedings Relating to the Western Power Market
Puget Energy’s and PSE’s Annual Report on Form 10-K for the year ended December 31, 2007 includes a summary relating to the western power market proceedings. The following discussion provides a summary of material developments in these proceedings that occurred during and subsequent to the period covered by that report. PSE is vigorously defending each of these cases. Litigation is subject to numerous uncertainties and PSE is unable to predict the ultimate outcome of these matters. Accordingly, there can be no guarantee that these proceedings, either individually or in the aggregate, will not materially and/or adversely affect PSE’s financial condition, results of operations or liquidity.
Lockyer Case. In March and April 2008, FERC issued orders establishing procedures for the Lockyer remand. The orders commence a seller-by-seller inquiry into the transaction reports filed by entities that sold power in California during 2000. The inquiry is to determine if the transaction reports as filed masked the gathering of more than 20% of the market during the period, by that seller. PSE is confident that it will not be found to have possessed 20% of any relevant market during any relevant time. The order also mandates a settlement process before an Administrative Law Judge (ALJ). FERC staff and the ALJ requested data concerning energy sellers’ transactions, and PSE provided such data to FERC staff. Settlement talks among various parties continue but PSE cannot predict the ultimate outcome of any negotiations or subsequent process before FERC or the ALJ.
California Receivable and California Refund Proceeding. The California Independent System Operator (CAISO) filed status reports in this matter from time to time, but has yet to report its “who owes what to whom” calculation.
Proceeding Relating to the Bonneville Power Administration
Petitioners in several actions in the Ninth Circuit against BPA asserted that BPA acted contrary to law in entering into or performing or implementing a number of agreements, including the amended settlement agreement (and the May 2004 agreement) between BPA and PSE regarding the REP. BPA rates used in such agreements between BPA and PSE for determining the amounts of money to be paid to PSE by BPA under such agreements during the period October 1, 2001 through September 30, 2006 were confirmed, approved and allowed to go into effect by the FERC. Petitioners in several actions in the Ninth Circuit against BPA also asserted that BPA acted contrary to law in adopting or implementing the rates upon which the benefits received or to be received from BPA during the October 1, 2001 through September 30, 2006 period were based. A number of parties have claimed that the BPA rates proposed or adopted in the BPA rate proceeding to develop BPA rates to be used in the agreements for determining the amounts of money to be paid to PSE by BPA during the period October 1, 2006 through September 30, 2009 are contrary to law and that BPA acted contrary to law or without authority in deciding to enter into, or in entering into or performing or implementing such agreements. In March 2008, BPA requested FERC to continue a stay of FERC’s review of such rates in light of the reopened rate proceeding described below arising out of the Ninth Circuit litigation.
On May 3, 2007, the Ninth Circuit issued an opinion in Portland Gen. Elec. v. BPA, No. 01-70003, in which proceeding the actions of BPA in entering into settlement agreements regarding the BPA REP with PSE and with other investor-owned utilities were challenged. In this opinion, the Ninth Circuit granted petitions for review and held the settlement agreements entered into between BPA and the investor-owned utilities being challenged in that proceeding to be inconsistent with statute. On May 3, 2007, the Ninth Circuit also issued an opinion in Golden Northwest Aluminum v. BPA, No. 03-73426, in which proceeding the petitioners sought review of BPA’s 2002-06 power rates. In this opinion, the Ninth Circuit granted petitions for review and held that BPA unlawfully shifted onto its preference customers the costs of its settlements with the investor-owned utilities. On October 5, 2007, petitions for rehearing of these two opinions were denied. On February 1, 2008, PSE and other utilities filed in the Supreme Court of the United States a petition for a writ of certiorari to review the decisions of the Ninth Circuit, which petition was denied in June 2008.
In May 2007, following the Ninth Circuit’s issuance of these two opinions, BPA suspended payments to PSE under the amended settlement agreement (and the May 2004 agreement). On August 29, 2007, the Washington Commission approved PSE’s accounting petition to defer as a regulatory asset the excess BPA Residential Exchange benefit provided to customers and accrue monthly carrying charges on the deferred balance from June 7, 2007 until the deferral is recovered from customers or BPA. On October 11, 2007, the Ninth Circuit remanded the May 2004 agreement to BPA in light of the Portland Gen. Elec. V. BPA opinion and dismissed the remaining three pending cases regarding settlement agreements.
On February 8, 2008, BPA issued a notice reopening its WP-07 rate proceeding to respond to the various Ninth Circuit opinions. In the notice, BPA proposed to adjust its fiscal year 2009 rates and to determine the amounts of Residential Exchange benefits paid since 2002 that may be recovered. BPA is proposing to determine an amount that was improperly passed through to residential and small farm customers of PSE and the other regional investor-owned utilities during the 2002 to 2008 rate periods and to recover this amount over time by reducing future benefits under the REP. The amount to be recovered over future periods from PSE’s residential and small farm customers in BPA’s initial proposal is approximately $150.0 million. However, this is an initial proposal and is subject to BPA’s rate case process resulting in a final decision in approximately August 2008, and is also subject to subsequent administrative and judicial review.
In March 2008, BPA and PSE signed an agreement pursuant to which BPA made a payment to PSE related to the REP benefits for the fiscal year ending September 30, 2008, which payment is under such agreement subject to true-up depending upon the amount of any REP benefits ultimately determined to be payable to PSE. In March and April 2008, Clatskanie People’s Utility District filed petitions in the Ninth Circuit for review of BPA actions in connection with offering or entering into such agreement with PSE and similar agreements with other investor-owned utilities.
It is not clear what impact, if any, such reopened rate proceeding, development or review of such rates, review of such agreements and the above described Ninth Circuit litigation may ultimately have on PSE.
Proceeding Relating to the Proposed Merger
On February 6, 2008, the Company entered into a memorandum of understanding providing for the settlement of the consolidated shareholder lawsuit, subject to customary conditions including completion of appropriate settlement documentation, confirmatory discovery and court approval. Pursuant to the memorandum of understanding, the Company agreed to include certain additional disclosures in its proxy statement relating to the merger. The Company does not admit, however, that its prior disclosures were in any way materially misleading or inadequate. In addition, the Company and the other defendants in the consolidated lawsuit deny the plaintiffs’ allegations of wrongdoing and violation of law in connection with the merger. The settlement, if completed and approved by the court, will result in dismissal with prejudice and release of all claims of the plaintiffs and settlement class of the Company’s shareholders that were or could have been brought on behalf of the plaintiffs and the settlement class. In connection with such settlement, the plaintiffs intend to seek a court-approved award of attorneys’ fees and expenses in an amount up to $290,000, which the Company has agreed to pay. As of June 30, 2008, the Company has a loss reserve of $290,000.
New Accounting Pronouncements
On September 15, 2006, Financial Accounting Standards Board (FASB) issued Statement of Financial Accounting Standards (SFAS) No. 157, “Fair Value Measurements” (SFAS No. 157), which clarifies how companies should use fair value measurements in accordance with GAAP for recognition and disclosure purposes. SFAS No. 157 establishes a common definition of fair value and a framework for measuring fair value under GAAP, along with expanding disclosures about fair value to eliminate differences in current practice that exist in measuring fair value under the existing accounting standards. The definition of fair value in SFAS No. 157 retains the notion of exchange price; however, it focuses on the price that would be received to sell the asset or paid to transfer a liability (i.e. an exit price), rather than the price that would be paid to acquire the asset or received to assume the liability (i.e. an entrance price). Under SFAS No. 157, a fair value measure should reflect all of the assumptions that market participants would use in pricing the asset or liability, including assumptions about the risk inherent in a particular valuation technique, the effect of a restriction on the sale or use of an asset, and the risk of nonperformance. To increase consistency and comparability in fair value measures, SFAS No. 157 establishes a three-level fair value hierarchy to prioritize the inputs used in valuation techniques between observable inputs that reflect quoted market prices in active markets, inputs other than quoted prices with observable market data, and unobservable data (e.g. a company’s own data).
SFAS No. 157 is effective for fiscal years beginning after November 15, 2007, which was January 1, 2008, for the Company. On February 28, 2008, the FASB issued a final FASB Staff Position (FSP) that partially deferred the effective date of SFAS No. 157 for one year for non-financial assets and non-financial liabilities that are recognized or disclosed at fair value, except for those that are recognized or disclosed at fair value on an annual or more frequent basis. The Company adopted SFAS No. 157 on January 1, 2008, prospectively, as required by the Statement, with certain exceptions, including the initial impact of changes in fair value measurements of existing derivative financial instruments measured initially using the transaction price under Emerging Issues Task Force (EITF) 02-3. On January 1, 2008, the difference between the carrying amounts and the fair values of those instruments originally recorded under guidance in EITF 02-3 was recognized as a cumulative-effect adjustment to the opening balance of retained earnings. SFAS No. 157 nullified a portion of EITF 02-3. Under EITF 02-3, the transaction price presumption prohibited recognition of a trading profit at inception of a derivative unless the positive fair value of that derivative was substantially based on quoted prices or a valuation process incorporating observable inputs. For transactions that did not meet this criterion at inception, trading profits that had been deferred were recognized in the period that inputs to value the derivative became observable or when the contract performed.
In December 2007, the FASB issued SFAS No. 141(R), “Business Combinations” (SFAS No. 141 (R)). This Statement replaces FASB Statement No. 141, “Business Combinations” and addresses the accounting for all transactions or other events in which an entity obtains control of one or more businesses. The objective of this Statement is to improve the relevance, representational faithfulness and comparability of the information that a reporting entity provides in its financial reports about a business combination and its effects. To accomplish that, this Statement establishes principles and requirements for how the acquirer: 1) Recognizes and measures in its financial statements the identifiable assets acquired, the liabilities assumed and any noncontrolling interest in the acquiree; 2) Recognizes and measures the goodwill acquired in the business combination or a gain from a bargain purchase; and 3) Determines what information to disclose to enable users of the financial statements to evaluate the nature and financial effects of the business combination. This Statement shall be applied prospectively to business combinations for which the acquisition date is on or after the beginning of the first annual reporting period beginning on or after December 15, 2008. The Company does not expect any impact from SFAS No. 141 (R).
On March 19, 2008, FASB issued SFAS No. 161, “Disclosures about Derivative Instruments and Hedging Activities – An Amendment of FASB Statement No. 133” (SFAS No. 161). SFAS No. 161 is effective for the fiscal years and interim years beginning after November 15, 2008, which will be the quarter ended March 31, 2009 for the Company. SFAS No. 161 requires companies with derivative instruments to disclose information that should enable financial statement users to understand how and why a company uses derivative instruments, how derivative instruments and related hedged items are accounted for under SFAS No. 133 and how derivative instruments and related hedged items affect a company’s financial position, financial performance and cash flows. SFAS No. 161 requirements will impact the following derivative and hedging disclosures: objectives and strategies, balance sheet, financial performance, contingent features and counterparty credit risk. The Company is currently assessing the impact of SFAS No. 161.
In May 2008, FASB issued SFAS No. 162, “The Hierarchy of Generally Accepted Accounting Principles” (SFAS No. 163), which identifies the sources of accounting principles and the framework for selecting the principles to be used in the preparation of financial statements of nongovernmental entities that are presented in conformity with generally accepted accounting principles. The FASB Board is responsible for identifying the sources of accounting principles and providing entities with a framework for selecting the principles used in the preparation of financial. The current GAAP hierarchy, as set forth in the American Institute of Certified Public Accountants Statement on Auditing Standards No. 69, “The Meaning of Present Fairly in Conformity With Generally Accepted Accounting Principles”, has been criticized because it is directed to the auditor rather than the entity, it is complex and it ranks FASB Statements of Financial Accounting Concepts, which are subject to the same level of due process as FASB Statements of Financial Accounting Standards, below industry practices that are widely recognized as generally accepted but that are not subject to due process. The Board believes that the GAAP hierarchy should be directed to entities because it is the entity that is responsible for selecting accounting principles for financial statements that are presented in conformity with GAAP. The Company has reviewed the statement and has assessed there will be no significant impact to the financial statements.
On June 16, 2008, FSP No. EITF 03-6-1, “Determining Whether Instruments Granted in Share-Based Payment Transactions Are Participating Securities”, was issued. This FSP addresses whether instruments granted in share-based payment transactions are participating securities prior to vesting and, therefore, need to be included in the earnings allocation in computing earnings per share under the two-class method. Unvested share-based payment awards that contain nonforfeitable rights to dividends or dividend equivalents (whether paid or unpaid) are participating securities and shall be included in the computation of EPS pursuant to the two-class method. The Company is currently assessing the financial statement presentation impact of FSP EITF No. 03-6-1.
Energy Portfolio Management
The Company has energy risk policies and procedures to manage commodity and volatility risks. The Company’s Energy Management Committee establishes the Company’s energy risk management policies and procedures, and monitors compliance. The Energy Management Committee is comprised of certain Company officers and is overseen by the Audit Committee of the Company’s Board of Directors.
The Company is focused on commodity price exposure and risks associated with volumetric variability in the natural gas and electric portfolios. It is not engaged in the business of assuming risk for the purpose of speculative trading. The Company hedges open natural gas and electric positions to reduce both the portfolio risk and the volatility risk in prices. The exposure position is determined by using a probabilistic risk system that models 100 scenarios of how the Company’s natural gas and power portfolios will perform under various weather, hydro and unit performance conditions. The objectives of the hedging strategy are to:
| · | Ensure physical energy supplies are available to reliably and cost-effectively serve retail load; | |
| · | Manage energy portfolio risks prudently to serve retail load at overall least cost and limit undesired impacts on PSE’s customers and shareholders; and | |
| · | Reduce power costs by extracting the value of the Company’s assets. |
The following table presents electric derivatives that are designated as cash flow hedges or contracts that do not meet Normal Purchase Normal Sale (NPNS) at June 30, 2008 and December 31, 2007:
Electric Derivatives |
(Dollars in Millions) | June 30, 2008 | December 31, 2007 | ||||||
| Short-term asset | $ | 115.5 | $ | 11.1 | ||||
| Long-term asset | 143.1 | 6.6 | ||||||
| Total assets | $ | 258.6 | $ | 17.7 | ||||
| Short-term liability | $ | 7.2 | $ | 9.8 | ||||
| Long-term liability | 6.6 | -- | ||||||
| Total liabilities | $ | 13.8 | $ | 9.8 | ||||
If it is determined that it is uneconomical to operate PSE’s controlled electric generating facilities in the future period, the fuel supply cash flow hedge relationship is terminated and the hedge is de-designated which results in the unrealized gains and losses associated with the contracts being recorded in the income statement. As these contracts are settled, the costs are recognized as energy costs and are included as part of the Power Cost Adjustment (PCA) mechanism.
At December 31, 2007, the Company had an unrealized day one loss deferral of $9.0 million related to a three-year locational power exchange contract which was modeled and therefore the day one gain was deferred under EITF No. 02-3. The contract has economic benefit to the Company over its terms. The locational exchange will help ease electric transmission congestion across the Cascade Mountains during the winter months as PSE will take delivery of energy at a location that interconnects with PSE’s transmission system in western Washington. At the same time, PSE will make available the quantities of power at the Mid-Columbia trading hub location. The day one loss deferral was transferred to retained earnings on January 1, 2008 as required by SFAS No. 157, “Fair Value Measurements” and any future day one loss on contracts will be recorded in the income statement beginning January 1, 2008 in accordance with the statement.
The following tables present the impact of changes in the market value of derivative instruments not meeting NPNS or cash flow hedge criteria, and ineffectiveness related to highly effective cash flow hedges, to the Company’s earnings during the three and six months ended June 30, 2008 and June 30, 2007:
(Dollars in Millions) Three Months Ended June 30, | 2008 | 2007 | Change |
| Increase (decrease) in earnings | $ 2.4 | $ (1.5) | $ 3.9 |
(Dollars in Millions) Six Months Ended June 30, | 2008 | 2007 | Change |
| Increase (decrease) in earnings | $ 2.3 | $ 4.2 | $ (1.9) |
In the first quarter 2007, the Company reversed a loss reserve due to credit worthiness related to a physically delivered natural gas supply contract for electric generation. The counterparty’s financial outlook had changed and delivery was now probable through the life of the contract which expired June 30, 2008.
The amount of net unrealized gain (loss), net of tax, related to the Company’s cash flow hedges under SFAS No. 133 consisted of the following at June 30, 2008 and December 31, 2007:
(Dollars in Millions, net of tax) | June 30, 2008 | December 31, 2007 |
| Other comprehensive income – unrealized gain (loss) | $ 161.9 | $ (3.4) |
The following table presents derivative hedges of natural gas contracts to serve natural gas customers at June 30, 2008 and December 31, 2007:
Gas Derivatives | ||||||||
| (Dollars in Millions) | June 30, 2008 | December 31, 2007 | ||||||
| Short-term asset | $ | 132.2 | $ | 6.0 | ||||
| Long-term asset | 56.3 | 5.3 | ||||||
| Total assets | $ | 188.5 | $ | 11.3 | ||||
| Short-term liability | $ | 1.4 | $ | 17.3 | ||||
| Long-term liability | 3.2 | -- | ||||||
| Total liabilities | $ | 4.6 | $ | 17.3 | ||||
At June 30, 2008, the Company had total assets of $188.6 million and total liabilities of $4.6 million related to hedges of natural gas contracts to serve natural gas customers. All mark-to-market adjustments relating to the natural gas business have been reclassified to a deferred account in accordance with SFAS No. 71 due to the PGA mechanism. All increases and decreases in the cost of natural gas supply are passed on to customers with the PGA mechanism. As the gains and losses on the hedges are realized in future periods, they will be recorded as natural gas costs under the PGA mechanism.
A hypothetical 10.0% decrease in the market prices of natural gas and electricity would decrease the fair value of qualifying cash flow hedges by $59.4 million after-tax, with a corresponding impact in comprehensive income and earnings (due to ineffectiveness) of $57.9 million and $1.5 million, respectively, after-tax, and would increase the fair value of those contracts marked-to-market in earnings by $1.2 million after-tax.
Credit Risk
The Company is exposed to credit risk primarily through buying and selling electricity and natural gas to serve customers. Credit risk is the potential loss resulting from a counterparty’s non-performance under an agreement. The Company manages credit risk with policies and procedures for, among other things, counterparty analysis, exposure measurement, exposure monitoring and exposure mitigation. The Company has entered into master netting arrangements with counterparties when available to mitigate credit exposure to those counterparties. The Company believes that entering into such agreements reduces risk of settlement default for the ability to make only one net payment.
It is possible that extreme volatility in energy commodity prices could cause the Company to have credit risk exposures with one or more counterparties. If such counterparties fail to perform their obligations under one or more agreements, the Company could suffer a material financial loss. However, as of June 30, 2008, approximately 92.0% of the counterparties with transaction amounts outstanding in the Company’s energy portfolio are rated at least investment grade by the major rating agencies. The Company assesses credit risk internally for counterparties that are not rated.
Interest Rate Risk
The Company believes its interest rate risk primarily relates to the use of short-term debt instruments, variable-rate notes and leases and anticipated long-term debt financing needed to fund capital requirements. The Company manages its interest rate risk through the issuance of mostly fixed-rate debt of various maturities. The Company utilizes commercial paper, line of credit facilities and accounts receivable securitization to meet short-term cash requirements. These short-term obligations are commonly refinanced with fixed-rate bonds or notes when needed and when interest rates are considered favorable. The Company may enter into swap instruments or other financial hedge instruments to manage the interest rate risk associated with these debts.
The ending balance in other comprehensive income related to the forward starting swaps and previously settled treasury lock contracts at June 30, 2008 was a net loss of $8.0 million after-tax and accumulated amortization. All financial hedge contracts of this type are reviewed by senior management and presented to the Securities Pricing Committee of the Board of Directors and are approved prior to execution.
Puget Energy
Evaluation of Disclosure Controls and Procedures
Under the supervision and with the participation of Puget Energy’s management, including the Chairman, President and Chief Executive Officer and the Executive Vice President and Chief Financial Officer, Puget Energy has evaluated the effectiveness of its disclosure controls and procedures (as defined in Rule 13a-15(e) under the Securities Exchange Act of 1934) as of June 30, 2008, the end of the period covered by this report. Based upon that evaluation, the Chairman, President and Chief Executive Officer and the Executive Vice President and Chief Financial Officer of Puget Energy concluded that these disclosure controls and procedures are effective.
Changes in Internal Control Over Financial Reporting
There have been no changes in Puget Energy’s internal control over financial reporting during the quarter ended June 30, 2008 that have materially affected, or are reasonably likely to materially affect, Puget Energy’s internal control over financial reporting.
Puget Sound Energy
Evaluation of Disclosure Controls and Procedures
Under the supervision and with the participation of PSE’s management, including the Chairman, President and Chief Executive Officer and the Executive Vice President and Chief Financial Officer, PSE has evaluated the effectiveness of its disclosure controls and procedures (as defined in Rule 13a-15(e) under the Securities Exchange Act of 1934) as of June 30, 2008, the end of the period covered by this report. Based upon that evaluation, the Chairman, President and Chief Executive Officer and the Executive Vice President and Chief Financial Officer of PSE concluded that these disclosure controls and procedures are effective.
Changes in Internal Control Over Financial Reporting
There have been no changes in PSE’s internal control over financial reporting during the quarter ended June 30, 2008, that have materially affected, or are reasonably likely to materially affect, PSE’s internal control over financial reporting.
See the section titled “Proceedings Relating to the Western Power Market” under Item 2 “Management’s Discussion and Analysis of Financial Conditions and Results of Operations” of this Report on Form 10-Q. Contingencies arising out of the normal course of the Company’s business exist at June 30, 2008. The ultimate resolution of these issues in part or in the aggregate is not expected to have a material adverse impact on the financial condition, results of operations or liquidity of the Company.
There have been no material changes from the risk factors set forth in Part I, Item 1A in the Company’s Annual Report on Form 10-K for the year ended December 31, 2007.
Puget Energy’s special meeting of shareholders was held on April 16, 2008. At the special meeting, the shareholders approved by more than two-thirds required vote a merger with the Consortium of North American infrastructure investors. The vote on the proposals were as follows:
Proposal 1: Approval of the Plan of Merger dated as of October 26, 2007 between Puget Energy, Puget Holdings LLC, Puget Intermediate Holdings Inc. and Puget Merger Sub, Inc.
| For | Against | Abstain | Broker Non-Vote |
| 101,640,757 | 2,362,394 | 1,408,869 | -- |
Proposal 2: Approval to adjourn the special meeting to a later date, if necessary, to permit solicitation of proxies.
| For | Against | Abstain | Broker Non-Vote |
| 96,584,206 | 7,196,655 | 1,631,159 | -- |
See Exhibit Index for list of exhibits.
Pursuant to the requirements of the Securities Exchange Act of 1934, each registrant has duly caused this report to be signed on their behalf by the undersigned thereunto duly authorized.
| PUGET ENERGY, INC. | ||
| PUGET SOUND ENERGY, INC. | ||
| /s/ James W. Eldredge | ||
| James W. Eldredge | ||
| Vice President, Controller and Chief Accounting Officer | ||
| Date: August 4, 2008 | ||
| Chief accounting officer and officer duly authorized to sign this report on behalf of each registrant | ||
The following exhibits are filed herewith:
| 12.1 | Statement setting forth computation of ratios of earnings to fixed charges (2003 through 2007 and 12 months ended June 30, 2008) for Puget Energy. |
| 12.2 | Statement setting forth computation of ratios of earnings to fixed charges (2003 through 2007 and 12 months ended June 30, 2008) for PSE. |
| 31.1 | Chief Executive Officer certification of Puget Energy pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 302 of the Sarbanes-Oxley Act of 2002. |
| 31.2 | Chief Financial Officer certification of Puget Energy pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 302 of the Sarbanes-Oxley Act of 2002. |
| 31.3 | Chief Executive Officer certification of Puget Sound Energy pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 302 of the Sarbanes-Oxley Act of 2002. |
| 31.4 | Chief Financial Officer certification of Puget Sound Energy pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 302 of the Sarbanes-Oxley Act of 2002. |
| 32.1 | Chief Executive Officer certification pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002. |
| 32.2 | Chief Financial Officer certification pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002. |