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 September 30, 2007 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, or a non-accelerated filer. See definition of “accelerated filer and large accelerated filer” in Rule 12b-2 of the Exchange Act.
| Puget Energy, Inc. | Large accelerated filer | /X/ | Accelerated filer | / / | Non-accelerated filer | / / |
| Puget Sound Energy, Inc. | Large accelerated filer | / / | Accelerated filer | / / | Non-accelerated filer | /X/ |
Indicate by check mark whether the registrant is a shell company (as defined in Exchange Act Rule 12b-2)
| Puget Energy, Inc. | Yes | / / | No | /X/ | Puget Sound Energy, Inc. | Yes | / / | No | /X/ |
As of October 25, 2007, (i) the number of shares of Puget Energy, Inc. common stock outstanding was 117,176,878 ($.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. | ||
| AFUDC | Allowance for Funds Used During Construction |
| aMW | Average Megawatt |
| BART | Best Available Retrofit Technology |
| BPA | Bonneville Power Administration |
| CAISO | California Independent System Operator |
| EITF | Emerging Issues Task Force |
| EPA | U. S. Environmental Protection Agency |
| FASB | Financial Accounting Standards Board |
| FERC | Federal Energy Regulatory Commission |
| FIN | Financial Accounting Standards Board Interpretation |
| GAAP | Generally Accepted Accounting Principles |
| IBEW | International Brotherhood of Electrical Workers |
| InfrastruX | InfrastruX Group, Inc. |
| IRP | Integrated Resource Plan |
| IRS | Internal Revenue Service |
| kW | Kilowatt |
| kWh | Kilowatt Hour |
| LIBOR | London Interbank Offered Rate |
| MMS | Minerals 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 |
| 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. |
| PTC | Production Tax Credit |
| Puget Energy | Puget Energy, Inc. |
| RFP | Request For Proposal |
| SFAS | Statement of Financial Accounting Standards |
| Sumas | Sumas Cogeneration Company, L.P. |
| TBtu | Trillion British Thermal Unit |
| Tenaska | Tenaska Power Fund, L.P. |
| Washington Commission | Washington Utilities and Transportation Commission |
| WECC | Western Electricity Coordinating Council |
| WECO | Western Energy Company |
This Quarterly 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 (gas and electric), licensing of hydroelectric operations and gas storage facilities, recovery of other capital investments, recovery of power and gas costs, recovery of regulatory assets and present or prospective wholesale and retail competition; | |
| · | Failure to comply with standards and/or rules governed by FERC or the Washington Commission, which could result in penalties based on the discretion of either commission; | |
| · | Failure to comply with new 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 Company’s 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 that impact customer loads; | |
| · | 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 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 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 gas or electric plant to operate as intended; | |
| · | The ability to renew contracts for electric and 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 gas pipeline delivering to PSE’s system, which may impact PSE’s ability to adequately deliver gas supply 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, 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; | |
| · | Future losses related to corporate guarantees provided by Puget Energy as a part of the sale of its InfrastruX subsidiary | |
| · | The ability to maintain effective internal controls over financial reporting and operational processes; and | |
| · | The risk that the stock purchase will not close or will be delayed, including as a result of the failure to obtain on a timely basis clearance under the Hart Scott Rodino Antitrust Improvements Act of 1976, as amended (HSR Act), which could adversely impact PSE’s liquidity and capital resources; | |
| · | 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 shareholder approval or 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 million, plus out-of-pocket expenses of the acquiring entity and its members of up to $10 million; | |
| § | Risks related to diverting management's attention from ongoing business operations; | |
| § | The effect of the announcement of the merger on our business relationships, operating results and business generally, including our ability to retain key employees; and | |
| § | Potential litigation regarding the merger. | |
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 our most recent annual report on Form 10-K and this quarterly report for updates.
CONSOLIDATED STATEMENTS OF INCOME
(Dollars in thousands except per share amounts)
(Unaudited)
Three Months Ended September 30, | Nine Months Ended September 30, | |||||||||||||||
| 2007 | 2006 | 2007 | 2006 | |||||||||||||
| Operating revenues: | ||||||||||||||||
| Electric | $ | 456,100 | $ | 399,246 | $ | 1,418,980 | $ | 1,247,650 | ||||||||
| Gas | 142,120 | 119,610 | 834,304 | 718,655 | ||||||||||||
| Non-utility operating revenues | 3,460 | 685 | 13,439 | 5,776 | ||||||||||||
| Total operating revenues | 601,680 | 519,541 | 2,266,723 | 1,972,081 | ||||||||||||
| Operating expenses: | ||||||||||||||||
| Energy costs: | ||||||||||||||||
| Purchased electricity | 185,778 | 183,723 | 640,627 | 623,793 | ||||||||||||
| Electric generation fuel | 43,528 | 36,282 | 93,312 | 72,158 | ||||||||||||
| Residential exchange | (384 | ) | (35,923 | ) | (52,424 | ) | (131,226 | ) | ||||||||
| Purchased gas | 80,914 | 68,294 | 530,616 | 453,335 | ||||||||||||
| Net unrealized (gain) loss on derivative instruments | 5,276 | (611 | ) | 1,031 | 214 | |||||||||||
| Utility operations and maintenance | 94,433 | 87,687 | 291,539 | 258,653 | ||||||||||||
| Non–utility expense and other | 3,301 | 958 | 8,199 | 2,665 | ||||||||||||
| Depreciation and amortization | 68,909 | 65,530 | 204,351 | 193,959 | ||||||||||||
| Conservation amortization | 8,530 | 7,127 | 27,608 | 22,638 | ||||||||||||
| Taxes other than income taxes | 56,907 | 46,360 | 207,269 | 180,299 | ||||||||||||
| Total operating expenses | 547,192 | 459,427 | 1,952,128 | 1,676,488 | ||||||||||||
| Operating income | 54,488 | 60,114 | 314,595 | 295,593 | ||||||||||||
| Other income (deductions): | ||||||||||||||||
| Other income | 6,725 | 7,298 | 17,710 | 17,425 | ||||||||||||
| Charitable foundation funding | -- | -- | -- | (15,000 | ) | |||||||||||
| Other expense | (686 | ) | (1,685 | ) | (4,546 | ) | (3,943 | ) | ||||||||
| Interest charges: | ||||||||||||||||
| AFUDC | 3,554 | 5,189 | 8,915 | 10,238 | ||||||||||||
| Interest expense | (54,681 | ) | (45,923 | ) | (158,133 | ) | (134,197 | ) | ||||||||
| Income from continuing operations before income taxes | 9,400 | 24,993 | 178,541 | 170,116 | ||||||||||||
| Income tax (benefit) expense | (2,218 | ) | 9,072 | 49,262 | 60,048 | |||||||||||
| Income from continuing operations | 11,618 | 15,921 | 129,279 | 110,068 | ||||||||||||
| Income from discontinued segment (net of tax) | (224 | ) | 1 | (212 | ) | 51,903 | ||||||||||
| Net income before cumulative effect of accounting change | 11,394 | 15,922 | 129,067 | 161,971 | ||||||||||||
| Cumulative effect of implementation of accounting change (net of tax) | -- | -- | -- | 89 | ||||||||||||
| Net income | $ | 11,394 | $ | 15,922 | $ | 129,067 | $ | 162,060 | ||||||||
| Common shares outstanding weighted average (in thousands) | 116,821 | 116,101 | 116,650 | 115,910 | ||||||||||||
| Diluted shares outstanding weighted average (in thousands) | 117,365 | 116,568 | 117,225 | 116,311 | ||||||||||||
| Basic earnings per common share before cumulative effect of accounting change | $ | 0.10 | $ | 0.14 | $ | 1.11 | $ | 0.95 | ||||||||
| Basic earnings per common share from discontinued operations | -- | -- | -- | 0.45 | ||||||||||||
| Cumulative effect from accounting change | -- | -- | -- | -- | ||||||||||||
| Basic earnings per common share | $ | 0.10 | $ | 0.14 | $ | 1.11 | $ | 1.40 | ||||||||
| Diluted earnings per common share before cumulative effect of accounting change | $ | 0.10 | $ | 0.14 | $ | 1.10 | $ | 0.95 | ||||||||
| Diluted earnings per common share from discontinued operations | -- | -- | -- | 0.44 | ||||||||||||
| Cumulative effect from accounting change | -- | -- | -- | -- | ||||||||||||
| Diluted earnings per common share | $ | 0.10 | $ | 0.14 | $ | 1.10 | $ | 1.39 | ||||||||
The accompanying notes are an integral part of the financial statements.
CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME
(Dollars in thousands)
(Unaudited)
Three Months Ended September 30, | Nine Months Ended September 30, | |||||||||||||||
| 2007 | 2006 | 2007 | 2006 | |||||||||||||
| Net income | $ | 11,394 | $ | 15,922 | $ | 129,067 | $ | 162,060 | ||||||||
| Other comprehensive income, net of tax at 35%: | ||||||||||||||||
| Foreign currency translation adjustment, net of tax of $0, $0, $0 and $(176), respectively | -- | -- | -- | (327 | ) | |||||||||||
| Unrealized gain from pension and postretirement plans, net of tax of $943, $0, $2,228 and $78, respectively | 1,752 | -- | 4,138 | 145 | ||||||||||||
| Net unrealized losses on derivative instruments during the period, net of tax of $(5,752), $(6,042), $(11,303) and $(15,687), respectively | (10,683 | ) | (11,220 | ) | (20,992 | ) | (29,133 | ) | ||||||||
| Reversal of net unrealized gains (losses) on derivative instruments settled during the period, net of tax of $2,488, $690, $3,556 and $(4,632), respectively | 4,620 | 1,281 | 6,604 | (8,603 | ) | |||||||||||
| Amortization of cash flow hedge contracts to earnings, net of tax of $43, $41, $128 and $246, respectively | 79 | 76 | 238 | 457 | ||||||||||||
| Settlement of cash flow hedge contracts net of tax of $0, $(224), $0 and $7,239, respectively | -- | (416 | ) | -- | 13,444 | |||||||||||
| Deferral of cash flow hedges related to the power cost adjustment mechanism, net of tax of $0, $0, $0 and $3,366, respectively | -- | -- | -- | 6,252 | ||||||||||||
| Comprehensive loss | (4,232 | ) | (10,279 | ) | (10,012 | ) | (17,765 | ) | ||||||||
| Comprehensive income | $ | 7,162 | $ | 5,643 | $ | 119,055 | $ | 144,295 | ||||||||
The accompanying notes are an integral part of the financial statements.
CONSOLIDATED BALANCE SHEETS
(Dollars in thousands)
ASSETS
September 30, 2007 (Unaudited) | December 31, 2006 | |||||||
| Utility plant: (at original cost, including construction work in progress of $303,538 and $ 206,459, respectively) | ||||||||
| Electric | $ | 5,841,288 | $ | 5,334,368 | ||||
| Gas | 2,270,518 | 2,146,048 | ||||||
| Common plant | 482,374 | 458,262 | ||||||
| Less: Accumulated depreciation and amortization | (3,072,245 | ) | (2,757,632 | ) | ||||
| Net utility plant | 5,521,935 | 5,181,046 | ||||||
| Other property and investments | 153,874 | 151,462 | ||||||
| Current assets: | ||||||||
| Cash | 29,769 | 28,117 | ||||||
| Restricted cash | 4,792 | 839 | ||||||
| Accounts receivable, net of allowance for doubtful accounts | 119,554 | 253,613 | ||||||
| Secured pledged accounts receivable | 126,000 | 110,000 | ||||||
| Unbilled revenues | 115,238 | 202,492 | ||||||
| Purchased gas adjustment receivable | -- | 39,822 | ||||||
| Materials and supplies, at average cost | 61,199 | 43,501 | ||||||
| Fuel and gas inventory, at average cost | 116,797 | 115,752 | ||||||
| Unrealized gain on derivative instruments | 12,523 | 16,826 | ||||||
| Prepaid income tax | 35,859 | -- | ||||||
| Prepaid expenses | 8,883 | 9,228 | ||||||
| Other | 16,303 | -- | ||||||
| Deferred income taxes | 6,049 | 1,175 | ||||||
| Total current assets | 652,966 | 821,365 | ||||||
| Other long-term assets: | ||||||||
| Restricted cash | -- | 3,814 | ||||||
| Regulatory asset for deferred income taxes | 106,068 | 115,304 | ||||||
| Regulatory asset for PURPA contract buyout costs | 147,375 | 167,941 | ||||||
| Unrealized gain on derivative instruments | 32 | 6,934 | ||||||
| Power cost adjustment mechanism | -- | 6,357 | ||||||
| Other | 660,410 | 611,816 | ||||||
| Total other long-term assets | 913,885 | 912,166 | ||||||
| Total assets | $ | 7,242,660 | $ | 7,066,039 | ||||
The accompanying notes are an integral part of the financial statements.
PUGET ENERGY, INC.
CONSOLIDATED BALANCE SHEETS
(Dollars in thousands)
CAPITALIZATION AND LIABILITIES
September 30, 2007 (Unaudited) | December 31, 2006 | |||||||
| Capitalization: | ||||||||
| Common shareholders’ investment: | ||||||||
| Common stock $0.01 par value, 250,000,000 shares authorized, 117,170,298 and 116,576,636 shares outstanding, respectively | $ | 1,170 | $ | 1,166 | ||||
| Additional paid-in capital | 1,983,018 | 1,969,032 | ||||||
| Earnings reinvested in the business | 213,976 | 172,529 | ||||||
| Accumulated other comprehensive loss, net of tax at 35% | (36,710 | ) | (26,698 | ) | ||||
| Total shareholders’ equity | 2,161,454 | 2,116,029 | ||||||
| Redeemable securities and long-term debt: | ||||||||
| Preferred stock subject to mandatory redemption | 1,889 | 1,889 | ||||||
| Junior subordinated notes | 250,000 | -- | ||||||
| Junior subordinated debentures of the corporation payable to a subsidiary trust holding mandatorily redeemable preferred securities | -- | 37,750 | ||||||
| Long-term debt | 2,428,860 | 2,608,360 | ||||||
| Total redeemable securities and long-term debt | 2,680,749 | 2,647,999 | ||||||
| Total capitalization | 4,842,203 | 4,764,028 | ||||||
| Current liabilities: | ||||||||
| Accounts payable | 238,922 | 379,579 | ||||||
| Short-term debt | 378,039 | 328,055 | ||||||
| Current maturities of long-term debt | 179,500 | 125,000 | ||||||
| Accrued expenses: | ||||||||
| Purchased gas liability | 61,158 | -- | ||||||
| Taxes | 60,743 | 54,977 | ||||||
| Salaries and wages | 19,597 | 32,122 | ||||||
| Interest | 57,161 | 36,915 | ||||||
| Unrealized loss on derivative instruments | 56,668 | 70,596 | ||||||
| Other | 52,480 | 43,889 | ||||||
| Total current liabilities | 1,104,268 | 1,071,133 | ||||||
| Long-term liabilities: | ||||||||
| Deferred income taxes | 773,872 | 745,095 | ||||||
| Unrealized loss on derivative instruments | 9,065 | 415 | ||||||
| Power cost adjustment mechanism | 4,841 | -- | ||||||
| Other deferred credits | 508,411 | 485,368 | ||||||
| Total long-term liabilities | 1,296,189 | 1,230,878 | ||||||
| Total capitalization and liabilities | $ | 7,242,660 | $ | 7,066,039 | ||||
The accompanying notes are an integral part of the financial statements.
CONSOLIDATED STATEMENTS OF CASH FLOWS
(Dollars in thousands, Unaudited)
Nine Months Ended September 30, | ||||||||
| 2007 | 2006 | |||||||
| Operating activities: | ||||||||
| Net income | $ | 129,067 | $ | 162,060 | ||||
| Adjustments to reconcile net income to net cash provided by operating activities: | ||||||||
| Depreciation and amortization | 204,351 | 193,959 | ||||||
| Deferred income taxes and tax credits, net | 38,567 | (11,309 | ) | |||||
| Net unrealized loss on derivative instruments | 1,031 | 214 | ||||||
| Amortization of gas pipeline capacity assignment | (8,169 | ) | (7,951 | ) | ||||
| Impairment on InfrastruX investment | -- | (7,269 | ) | |||||
| Gain on sale of InfrastruX | -- | (29,765 | ) | |||||
| Cash collateral paid from energy suppliers | -- | (22,020 | ) | |||||
| Change in residential exchange program | (27,205 | ) | 434 | |||||
| Cash receipt from lease purchase option settlement | 18,898 | -- | ||||||
| Chelan PUD contract initiation prepayment | -- | (89,000 | ) | |||||
| Power cost adjustment mechanism | 11,198 | 15,696 | ||||||
| Goldendale deferred costs | (11,211 | ) | -- | |||||
| Storm damage deferred costs | (16,460 | ) | (7,545 | ) | ||||
| Other | 27,767 | 10,214 | ||||||
| Change in certain current assets and liabilities: | ||||||||
| Accounts receivable and unbilled revenue | 215,363 | 198,243 | ||||||
| Materials and supplies | (17,698 | ) | (4,408 | ) | ||||
| Fuel and gas inventory | (1,045 | ) | (39,105 | ) | ||||
| Prepayments and other | (51,816 | ) | (16,696 | ) | ||||
| Purchased gas adjustment receivable/payable | 100,980 | (16,318 | ) | |||||
| Accounts payable | (134,002 | ) | (119,308 | ) | ||||
| Taxes payable | 5,766 | (78,357 | ) | |||||
| Accrued expenses and other | 6,248 | 20,718 | ||||||
| Net cash provided by operating activities | 491,630 | 152,487 | ||||||
| Investing activities: | ||||||||
| Construction and capital expenditures - excluding equity AFUDC | (548,043 | ) | (579,384 | ) | ||||
| Energy efficiency expenditures | (30,054 | ) | (21,859 | ) | ||||
| Cash proceeds from property sales | 5,747 | 196 | ||||||
| Refundable cash received for customer construction projects | 16,950 | 12,004 | ||||||
| Restricted cash | (139 | ) | (3,529 | ) | ||||
| Gross proceeds from sale of InfrastruX, net of cash disposed | -- | 263,575 | ||||||
| Other | (340 | ) | 5,835 | |||||
| Net cash used by investing activities | (555,879 | ) | (323,162 | ) | ||||
| Financing activities: | ||||||||
| Change in short-term debt and leases, net | 49,984 | 65,323 | ||||||
| Dividends paid | (79,135 | ) | (78,123 | ) | ||||
| Payments to minority shareholders of InfrastruX | -- | (10,451 | ) | |||||
| Issuance of common stock | 4,379 | 4,241 | ||||||
| Issuance of bonds and notes | 250,000 | 550,000 | ||||||
| Redemption of trust preferred stock | (37,750 | ) | (200,000 | ) | ||||
| Redemption of bonds, notes and leases | (125,000 | ) | (190,096 | ) | ||||
| Settlement of cash flow hedge of interest rate derivative | -- | 20,682 | ||||||
| Issuance and redemption costs of bonds and other | 3,423 | (3,760 | ) | |||||
| Net cash provided by financing activities | 65,901 | 157,816 | ||||||
| Net increase (decrease) in cash | 1,652 | (12,859 | ) | |||||
| Cash at beginning of year | 28,117 | 22,897 | ||||||
| Cash at end of period | $ | 29,769 | $ | 10,038 | ||||
| Supplemental cash flow information: | ||||||||
| Cash paid for interest (net of capitalized interest) | $ | 128,755 | $ | 118,848 | ||||
| Income taxes paid | 23,000 | 97,725 | ||||||
The accompanying notes are an integral part of the financial statements.
CONSOLIDATED STATEMENTS OF INCOME
(Dollars in thousands)
(Unaudited)
Three Months Ended September 30, | Nine Months Ended September 30, | |||||||||||||||
| 2007 | 2006 | 2007 | 2006 | |||||||||||||
| Operating revenues: | ||||||||||||||||
| Electric | $ | 456,100 | $ | 399,246 | $ | 1,418,980 | $ | 1,247,650 | ||||||||
| Gas | 142,120 | 119,610 | 834,304 | 718,655 | ||||||||||||
| Non-utility operating revenues | 3,460 | 685 | 13,439 | 5,776 | ||||||||||||
| Total operating revenues | 601,680 | 519,541 | 2,266,723 | 1,972,081 | ||||||||||||
| Operating expenses: | ||||||||||||||||
| Energy costs: | ||||||||||||||||
| Purchased electricity | 185,778 | 183,723 | 640,627 | 623,793 | ||||||||||||
| Electric generation fuel | 43,528 | 36,282 | 93,312 | 72,158 | ||||||||||||
| Residential exchange | (384 | ) | (35,923 | ) | (52,424 | ) | (131,226 | ) | ||||||||
| Purchased gas | 80,914 | 68,294 | 530,616 | 453,335 | ||||||||||||
| Unrealized (gain) loss on derivative instruments | 5,276 | (611 | ) | 1,031 | 214 | |||||||||||
| Utility operations and maintenance | 94,433 | 87,687 | 291,539 | 258,653 | ||||||||||||
| Non-utility expense and other | 2,178 | 707 | 6,755 | 1,432 | ||||||||||||
| Depreciation and amortization | 68,909 | 65,530 | 204,351 | 193,959 | ||||||||||||
| Conservation amortization | 8,530 | 7,127 | 27,608 | 22,638 | ||||||||||||
| Taxes other than income taxes | 56,907 | 46,360 | 207,269 | 180,299 | ||||||||||||
| Total operating expenses | 546,069 | 459,176 | 1,950,684 | 1,675,255 | ||||||||||||
| Operating income | 55,611 | 60,365 | 316,039 | 296,826 | ||||||||||||
| Other income (deductions): | ||||||||||||||||
| Other income | 6,725 | 7,298 | 17,710 | 17,069 | ||||||||||||
| Other expense | (686 | ) | (1,685 | ) | (4,546 | ) | (3,943 | ) | ||||||||
| Interest charges: | ||||||||||||||||
| AFUDC | 3,554 | 5,189 | 8,915 | 10,238 | ||||||||||||
| Interest expense | (54,681 | ) | (45,923 | ) | (158,133 | ) | (134,197 | ) | ||||||||
| Interest expense on Puget Energy note | (352 | ) | (382 | ) | (1,027 | ) | (503 | ) | ||||||||
| Income before income taxes | 10,171 | 24,862 | 178,958 | 185,490 | ||||||||||||
| Income tax (benefit) expense | (1,875 | ) | 9,230 | 49,777 | 66,008 | |||||||||||
| Net income before cumulative effect of accounting change | 12,046 | 15,632 | 129,181 | 119,482 | ||||||||||||
| Cumulative effect of implementation of accounting change (net of tax) | -- | -- | -- | 89 | ||||||||||||
| Net income | $ | 12,046 | $ | 15,632 | $ | 129,181 | $ | 119,571 | ||||||||
The accompanying notes are an integral part of the financial statements.
CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME
(Dollars in thousands)
(Unaudited)
Three Months Ended September 30, | Nine Months Ended September 30, | |||||||||||||||
| 2007 | 2006 | 2007 | 2006 | |||||||||||||
| Net income | $ | 12,046 | $ | 15,632 | $ | 129,181 | $ | 119,571 | ||||||||
| Other comprehensive income, net of tax at 35%: | ||||||||||||||||
| Unrealized gain from pension and postretirement plans, net of tax of $943, $0, $2,228 and $78, respectively | 1,752 | -- | 4,138 | 145 | ||||||||||||
| Net unrealized losses on derivative instruments during the period, net of tax of $(5,752), $(6,042), $(11,303) and $(15,687), respectively | (10,683 | ) | (11,220 | ) | (20,992 | ) | (29,133 | ) | ||||||||
| Reversal of net unrealized gains (losses) on derivative instruments settled during the period, net of tax of $2,488, $690, $3,556 and $(4,632), respectively | 4,620 | 1,281 | 6,604 | (8,603 | ) | |||||||||||
| Amortization of cash flow hedge contracts to earnings, net of tax of $43, $41, $128 and $246, respectively | 79 | 76 | 238 | 457 | ||||||||||||
| Settlement of cash flow hedge contracts net of tax of $0, $(224), $0 and $7,239, respectively | -- | (416 | ) | -- | 13,444 | |||||||||||
| Deferral of cash flow hedges related to the power cost adjustment mechanism, net of tax of $0, $0, $0 and $3,366, respectively | -- | -- | -- | 6,252 | ||||||||||||
| Comprehensive loss | (4,232 | ) | (10,279 | ) | (10,012 | ) | (17,438 | ) | ||||||||
| Comprehensive income | $ | 7,814 | $ | 5,353 | $ | 119,169 | $ | 102,133 | ||||||||
The accompanying notes are an integral part of the financial statements.
CONSOLIDATED BALANCE SHEETS
(Dollars in thousands)
ASSETS
September 30, 2007 (Unaudited) | December 31, 2006 | |||||||
| Utility plant: (at original cost, including construction work in progress of $303,538 and $206,459, respectively) | ||||||||
| Electric | $ | 5,841,288 | $ | 5,334,368 | ||||
| Gas | 2,270,518 | 2,146,048 | ||||||
| Common plant | 482,374 | 458,262 | ||||||
| Less: Accumulated depreciation and amortization | (3,072,245 | ) | (2,757,632 | ) | ||||
| Net utility plant | 5,521,935 | 5,181,046 | ||||||
| Other property and investments | 153,874 | 151,462 | ||||||
| Current assets: | ||||||||
| Cash | 29,677 | 28,092 | ||||||
| Restricted cash | 841 | 839 | ||||||
| Accounts receivable, net of allowance for doubtful accounts | 119,775 | 253,613 | ||||||
| Secured pledged accounts receivable | 126,000 | 110,000 | ||||||
| Unbilled revenues | 115,238 | 202,492 | ||||||
| Purchased gas adjustment receivable | -- | 39,822 | ||||||
| Materials and supplies, at average cost | 61,199 | 43,501 | ||||||
| Fuel and gas inventory, at average cost | 116,797 | 115,752 | ||||||
| Unrealized gain on derivative instruments | 12,523 | 16,826 | ||||||
| Prepaid income taxes | 34,821 | -- | ||||||
| Prepaid expenses | 8,309 | 8,659 | ||||||
| Other | 16,303 | -- | ||||||
| Deferred income taxes | 6,049 | 1,175 | ||||||
| Total current assets | 647,532 | 820,771 | ||||||
| Other long-term assets: | ||||||||
| Regulatory asset for deferred income taxes | 106,068 | 115,304 | ||||||
| Regulatory asset for PURPA contract buyout costs | 147,375 | 167,941 | ||||||
| Unrealized gain on derivative instruments | 32 | 6,934 | ||||||
| Power cost adjustment mechanism | -- | 6,357 | ||||||
| Other | 660,329 | 611,598 | ||||||
| Total other long-term assets | 913,804 | 908,134 | ||||||
| Total assets | $ | 7,237,145 | $ | 7,061,413 | ||||
The accompanying notes are an integral part of the financial statements.
PUGET SOUND ENERGY, INC.
CONSOLIDATED BALANCE SHEETS
(Dollars in thousands)
CAPITALIZATION AND LIABILITIES
September 30, 2007 (Unaudited) | December 31, 2006 | |||||||
| 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 | 1,001,534 | 996,737 | ||||||
| Earnings reinvested in the business | 313,251 | 263,206 | ||||||
| Accumulated other comprehensive loss, net of tax at 35% | (36,710 | ) | (26,698 | ) | ||||
| Total shareholder’s equity | 2,137,113 | 2,092,283 | ||||||
| Redeemable securities and long-term debt: | ||||||||
| Preferred stock subject to mandatory redemption | 1,889 | 1,889 | ||||||
| Junior subordinated notes | 250,000 | -- | ||||||
| Junior subordinated debentures of the corporation payable to a subsidiary trust holding mandatorily redeemable preferred securities | -- | 37,750 | ||||||
| Long-term debt | 2,428,860 | 2,608,360 | ||||||
| Total redeemable securities and long-term debt | 2,680,749 | 2,647,999 | ||||||
| Total capitalization | 4,817,862 | 4,740,282 | ||||||
| Current liabilities: | ||||||||
| Accounts payable | 238,337 | 379,494 | ||||||
| Short-term debt | 378,039 | 328,055 | ||||||
| Short-term note owed to Puget Energy | 24,282 | 24,303 | ||||||
| Current maturities of long-term debt | 179,500 | 125,000 | ||||||
| Accrued expenses: | ||||||||
| Purchased gas liability | 61,158 | -- | ||||||
| Taxes | 60,743 | 55,365 | ||||||
| Salaries and wages | 19,597 | 31,591 | ||||||
| Interest | 57,280 | 37,031 | ||||||
| Unrealized loss on derivative instruments | 56,668 | 70,596 | ||||||
| Other | 52,480 | 43,889 | ||||||
| Total current liabilities | 1,128,084 | 1,095,324 | ||||||
| Long-term liabilities: | ||||||||
| Deferred income taxes | 777,459 | 749,033 | ||||||
| Unrealized loss on derivative instruments | 9,065 | 415 | ||||||
| Power cost adjustment mechanism | 4,841 | -- | ||||||
| Other deferred credits | 499,834 | 476,359 | ||||||
| Total long-term liabilities | 1,291,199 | 1,225,807 | ||||||
| Total capitalization and liabilities | $ | 7,237,145 | $ | 7,061,413 | ||||
The accompanying notes are an integral part of the financial statements.
CONSOLIDATED STATEMENTS OF CASH FLOWS
(Dollars in thousands)
(Unaudited)
Nine Months Ended September 30, | ||||||||
| 2007 | 2006 | |||||||
| Operating activities: | ||||||||
| Net income | $ | 129,181 | $ | 119,571 | ||||
| Adjustments to reconcile net income to net cash provided by operating activities: | ||||||||
| Depreciation and amortization | 204,351 | 193,959 | ||||||
| Deferred income taxes and tax credits, net | 38,216 | 2,276 | ||||||
| Net unrealized loss on derivative instruments | 1,031 | 214 | ||||||
| Amortization of gas pipeline capacity assignment | (8,169 | ) | (7,951 | ) | ||||
| Cash collateral paid from energy suppliers | -- | (22,020 | ) | |||||
| Change in residential exchange program | (27,205 | ) | 434 | |||||
| Cash receipt from lease purchase option settlement | 18,898 | -- | ||||||
| Chelan PUD contract initiation payment | -- | (89,000 | ) | |||||
| Power cost adjustment mechanism | 11,198 | 15,969 | ||||||
| Goldendale deferred costs | (11,211 | ) | -- | |||||
| Storm damage deferred costs | (16,460 | ) | (7,545 | ) | ||||
| Other | 28,050 | 13,839 | ||||||
| Change in certain current assets and liabilities: | ||||||||
| Accounts receivable and unbilled revenue | 215,142 | 210,578 | ||||||
| Materials and supplies | (17,698 | ) | (5,324 | ) | ||||
| Fuel and gas inventory | (1,045 | ) | (39,105 | ) | ||||
| Prepayments and other | (50,774 | ) | (14,012 | ) | ||||
| Purchased gas adjustment receivable/payable | 100,980 | (16,318 | ) | |||||
| Accounts payable | (134,503 | ) | (122,257 | ) | ||||
| Taxes payable | 5,378 | (80,119 | ) | |||||
| Accrued expenses and other | 6,782 | 26,393 | ||||||
| Net cash provided by operating activities | 492,142 | 179,582 | ||||||
| Investing activities: | ||||||||
| Construction expenditures - excluding equity AFUDC | (548,043 | ) | (575,108 | ) | ||||
| Energy efficiency expenditures | (30,054 | ) | (21,859 | ) | ||||
| Cash proceeds from property sales | 5,747 | 196 | ||||||
| Refundable cash received for customer construction projects | 16,950 | 12,004 | ||||||
| Restricted cash | (3 | ) | 209 | |||||
| Other | (340 | ) | 5,939 | |||||
| Net cash used by investing activities | (555,743 | ) | (578,619 | ) | ||||
| Financing activities: | ||||||||
| Change in short-term debt, net | 49,984 | 62,154 | ||||||
| Loan from Puget Energy | (21 | ) | 24,211 | |||||
| Dividends paid | (79,136 | ) | (83,550 | ) | ||||
| Investment from Puget Energy | 3,684 | 68,635 | ||||||
| Issuance of bonds and notes | 250,000 | 550,000 | ||||||
| Redemption of trust preferred stock | (37,750 | ) | (200,000 | ) | ||||
| Redemption of bonds and notes | (125,000 | ) | (46,000 | ) | ||||
| Settlement of cash flow hedge interest rate derivative | -- | 20,682 | ||||||
| Issuance and redemption cost of bonds and other | 3,425 | (3,809 | ) | |||||
| Net cash provided by financing activities | 65,186 | 392,323 | ||||||
| Net increase (decrease) in cash | 1,585 | (6,714 | ) | |||||
| Cash at beginning of year | 28,092 | 16,709 | ||||||
| Cash at end of period | $ | 29,677 | $ | 9,995 | ||||
| Supplemental cash flow information: | ||||||||
| Cash paid for interest (net of capitalized interest) | $ | 128,755 | $ | 115,951 | ||||
| Income taxes paid | 23,000 | 91,621 | ||||||
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) and until May 7, 2006, InfrastruX Group, Inc. (InfrastruX). PSE is a public utility incorporated in the state of Washington that furnishes electric and gas services in a territory covering 6,000 square miles, primarily in the Puget Sound region.
The 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. Certain amounts previously reported have been reclassified to conform to current year presentations with no effect on total equity or net income. The reclassification relates to the income statements of Puget Energy and PSE, which have been changed from a utility presentation format based on Federal Energy Regulatory Commission (FERC) guidelines to a presentation based on generally accepted accounting principles (GAAP).
The 2006 consolidated financial statements of Puget Energy reflect the accounts of Puget Energy and its subsidiaries, PSE and InfrastruX. Puget Energy holds all the common shares of PSE and until May 7, 2006, a 90.9% interest in InfrastruX. The results of PSE and InfrastruX are presented on a consolidated basis. The financial position and results of operations for InfrastruX are presented as discontinued operations. At the time that it was owned by Puget Energy, InfrastruX was a non-regulated utility construction service company incorporated in the state of Washington, which provides construction services to the electric and gas utility industries primarily in the Midwest, Texas, south-central and eastern United States regions.
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, 2006.
The preparation of financial statements in conformity with 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 $40.5 million and $163.4 million for the three and nine months ended September 30, 2007, respectively, and $35.9 million and $141.2 million for the three and nine months ended September 30, 2006, 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 116,821,000 and 116,650,000 for the three and nine months ended September 30, 2007, respectively, and 116,101,000 and 115,910,000 for the three and nine months ended September 30, 2006, 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 117,365,000 and 117,225,000 for the three and nine months ended September 30, 2007, respectively, and 116,568,000 and 116,311,000 for the three and nine months ended September 30, 2006, 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,” as amended, requires that all contracts considered to be derivative instruments be recorded on the balance sheet at 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: 1) deems the counterparty creditworthy; 2) if the counterparty owns or controls energy resources within the western region to allow for physical delivery of the energy; and 3) if the transaction is within PSE’s forecasted load requirements as adjusted from time to time. Contracts that do not meet 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,” 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 wholesale 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 tables present the impact of changes in the market value of derivative instruments not meeting NPNS or cash flow hedge criteria to the Company’s earnings during the three and nine months ended September 30, 2007 and September 30, 2006:
(Dollars in Millions) Three Months Ended September 30, | 2007 | 2006 | Change |
| Unrealized (gain) loss on derivative instruments | $ 5.3 | $ (0.6) | $ 5.9 |
(Dollars in Millions) Nine Months Ended September 30, | 2007 | 2006 | Change |
| Unrealized (gain) loss on derivative instruments | $ 1.0 | $ 0.2 | $ 0.8 |
During the three and nine months ended September 30, 2007, the Company recorded a decrease in earnings for the change in the market value of derivative instruments not meeting NPNS or cash flow hedge criteria of $5.3 million and $1.0 million, respectively. The increase in expense is primarily due to the change in the mark-to-market valuation of a physically delivered gas supply contract for electric generation that did not meet NPNS or cash flow hedge criteria and the ineffective portion of two long-term power purchase agreements designated as cash flow hedges. During the three months ended September 30, 2007, in order to replace the energy that was lost due to the early termination of a contract by the counterparty in the second quarter 2007, the Company entered into two long-term power purchase contracts that met cash flow hedge criteria. The ineffective portion relates to periods in which the Company has enough projected energy resources to meet the expected customer usage without the two contracts. In addition, a decline in the unrealized gain on a physical gas supply contract recorded in the second quarter 2007 contributed to the unrealized loss in the three months ended September 30, 2007 due to the lower market value of natural gas and settlement of contracts during the third quarter 2007. During the three and nine months ended September 30, 2006, the Company recorded an increase in earnings for the change in the market value of derivative instruments not meeting NPNS or cash flow hedge criteria of $0.6 million and a decrease in earnings of $0.2 million, respectively.
The following table presents electric derivatives that are designated as cash flow hedges or contracts that do not meet NPNS at September 30, 2007 and December 31, 2006:
Electric Derivatives | ||||||||
(Dollars in Millions) | September 30, 2007 | December 31, 2006 | ||||||
| Short-term asset | $ | 10.1 | $ | 10.1 | ||||
| Long-term asset | -- | 6.8 | ||||||
| Total assets | $ | 10.1 | $ | 16.9 | ||||
| �� | ||||||||
| Short-term liability | $ | 17.1 | $ | 9.0 | ||||
| Long-term liability | 8.7 | 0.4 | ||||||
| Total liabilities | $ | 25.8 | $ | 9.4 | ||||
If it is determined that it is uneconomical to operate PSE’s controlled electric generating facilities in future periods, 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 September 30, 2007, the Company had net unrealized day one loss deferral of $9.6 million primarily related to a locational power exchange contract which was modeled and therefore the day one loss was deferred under Emerging Issues Task Force (EITF) 02-3, “Issues Involved in Accounting for Derivative Contracts Held for Trading Purposes and Involved in Energy Trading and Risk Management Activities.” The deferred loss is being amortized over the term of the contract through December 31, 2010. Any future changes in the mark-to-market value will be recorded through the income statement. The contract throughout its term has economic benefit to the Company. The locational exchange will help ease electric transmission congestion across the Cascade Mountains during 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 same quantities of power at the Mid-Columbia trading hub location.
The amount of net unrealized gain (loss), net of tax, related to the Company’s energy-related cash flow hedges under SFAS No. 133 consisted of the following at September 30, 2007 and December 31, 2006:
(Dollars in Millions, net of tax) | September 30, 2007 | December 31, 2006 |
| Other comprehensive income – unrealized (gain) loss | $ 9.5 | $ (4.9) |
The following table presents derivative hedges of natural gas contracts to serve natural gas customers at September 30, 2007 and December 31, 2006:
| Gas Derivatives | ||||||||
| (Dollars in Millions) | September 30, 2007 | December 31, 2006 | ||||||
| Short-term asset | $ | 2.5 | $ | 6.7 | ||||
| Long-term asset | -- | 0.1 | ||||||
| Total assets | $ | 2.5 | $ | 6.8 | ||||
| Short-term liability | $ | 39.6 | $ | 61.6 | ||||
| Long-term liability | 0.4 | -- | ||||||
| Total liabilities | $ | 40.0 | $ | 61.6 | ||||
Due to the PGA mechanism, mark-to-market adjustments relating to the natural gas business have been reclassified to a deferred account in accordance with SFAS No. 71. The PGA mechanism passes increases and decreases in the cost of natural gas supply to customers. As the gains and losses on the hedges are realized in future periods, they will be recorded as gas costs under the PGA mechanism.
At September 30, 2007, a portion of the ending balance in other comprehensive income relates to previously settled treasury interest rate swap contracts resulting in a net loss of $8.3 million after-tax and accumulated amortization. At December 31, 2006, the ending balance in other comprehensive income was a loss of $8.5 million.
(4) | Discontinued Operations and Corporate Guarantees (Puget Energy Only) |
On May 7, 2006, Puget Energy sold InfrastruX to an affiliate of Tenaska Power Fund, L.P. (Tenaska). Puget Energy accounted for InfrastruX as a discontinued operation under SFAS No. 144, “Accounting for the Impairment or Disposal of Long-Lived Assets” in 2006.
As part of the transaction, Puget Energy made certain representations and warranties concerning InfrastruX. Puget Energy obtained a representation and warranty insurance policy and deposited $3.7 million into an escrow account to serve as retention under the policy. At September 30, 2007, restricted cash in the escrow account was $4.0 million, which is included in Puget Energy’s balance sheets, representing management’s estimate of the aggregate fair value of Puget Energy’s maximum risk of loss related to those representations and warranties. Should Tenaska make any such claims against Puget Energy, payment for the claims would be made from the escrow account. The representation and warranty obligation expires May 7, 2008.
Puget Energy also agreed to indemnify Tenaska for certain costs and expenses incurred after closing related to an investigation of one of InfrastruX’s subsidiary companies. Under the indemnity agreement, Puget Energy is also liable for refunding a portion of the purchase price paid by Tenaska for InfrastruX if the subsidiary does not achieve certain operating results during the measurement year. The maximum obligation of Puget Energy for defense costs and a refund of a portion of the purchase price is capped at $15.0 million. Tenaska has notified Puget Energy that 2008 will be the measurement year for purposes of calculating the potential purchase price refund obligation. At September 30, 2007, a liability in the amount of $4.5 million is included in the accompanying balance sheets after payment of $0.5 million related to the guarantee. During the fourth quarter 2007, Puget Energy will pay InfrastruX $1.3 million to resolve a claim under this guarantee. The obligation expires May 7, 2011.
Puget Energy’s accounting policy for its representations and warranties loss reserve and the indemnity agreement is to reduce the loss reserve only when the guarantee expires or is settled. Any increase to the loss reserves subsequent to the initial recognition would be determined if it is probable that a future event will occur confirming the additional loss and the amount of the additional loss can be reasonably estimated in accordance with SFAS No. 5, “Accounting for Contingencies.”
Puget Energy also provided an environmental guarantee as part of the sale agreement. Under the terms of the agreement, Tenaska will be responsible for the first $0.1 million of environmental claims, Tenaska and Puget Energy will share the next $6.4 million equally and Puget Energy will be responsible for the next $3.5 million. Puget Energy believes it will not have a future loss in connection with the environmental guarantee.
The following table summarizes Puget Energy’s income from discontinued operations:
Three Months Ended September 30, | Nine Months Ended September 30, | |||||||||||||||
| (Dollars in Thousands) | 2007 | 2006 | 2007 | 2006 | ||||||||||||
| Revenues | $ | -- | $ | -- | $ | -- | $ | 138,573 | ||||||||
| Goodwill impairment | -- | -- | -- | |||||||||||||
| Operating expenses (including interest expense) | -- | -- | -- | (128,605 | ) | |||||||||||
| Pre-tax income | -- | -- | -- | 9,968 | ||||||||||||
| Income tax expense | (224 | ) | -- | (224 | ) | (3,544 | ) | |||||||||
| Puget Energy carrying value adjustment of InfrastruX | -- | -- | -- | 7,269 | ||||||||||||
| Puget Energy cost of sale related to InfrastruX, net of tax | -- | -- | -- | (937 | ) | |||||||||||
| Puget Energy deferred tax basis adjustment of InfrastruX | -- | -- | -- | 9,966 | ||||||||||||
| Gain on sale, net of tax | -- | 1 | 12 | 29,765 | ||||||||||||
| Minority interest in income of discontinued operations | -- | -- | -- | (584 | ) | |||||||||||
| Income from discontinued operations | $ | (224 | ) | $ | 1 | $ | (212 | ) | $ | 51,903 | ||||||
In accordance with SFAS No. 144, InfrastruX discontinued depreciation and amortization of its assets effective February 8, 2005. This discontinuation of depreciation and amortization resulted in $6.7 million ($4.3 million after-tax) lower depreciation and amortization expense than otherwise would have been recorded as continuing operations for the nine months ended September 30, 2006. Puget Energy did not record any amortization expense related to the intangible assets of InfrastruX in 2006.
(5) | Retirement Benefits |
The Company has a defined benefit pension plan with a cash balance feature covering substantially all PSE 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 September 30:
| Pension Benefits | Other Benefits | |||||||||||||||
| (Dollars in Thousands) | 2007 | 2006 | 2007 | 2006 | ||||||||||||
| Service cost | $ | 3,328 | $ | 3,293 | $ | 33 | $ | 99 | ||||||||
| Interest cost | 6,628 | 6,171 | 204 | 426 | ||||||||||||
| Expected return on plan assets | (9,715 | ) | (9,310 | ) | (210 | ) | (290 | ) | ||||||||
| Amortization of prior service cost | 510 | 585 | 43 | 134 | ||||||||||||
| Recognized net actuarial (gain) loss | 1,297 | 1,423 | (493 | ) | 49 | |||||||||||
| Amortization of transition obligation | -- | -- | 12 | 104 | ||||||||||||
| Net periodic benefit cost | $ | 2,048 | $ | 2,162 | $ | (411 | ) | $ | 522 | |||||||
| Curtailment/settlement cost | $ | -- | $ | -- | $ | 708 | $ | -- | ||||||||
The following table summarizes the net periodic benefit cost for the nine months ended September 30:
| Pension Benefits | Other Benefits | |||||||||||||||
| (Dollars in Thousands) | 2007 | 2006 | 2007 | 2006 | ||||||||||||
| Service cost | $ | 9,983 | $ | 9,415 | $ | 216 | $ | 270 | ||||||||
| Interest cost | 19,884 | 18,501 | 962 | 1,142 | ||||||||||||
| Expected return on plan assets | (29,144 | ) | (28,179 | ) | (620 | ) | (653 | ) | ||||||||
| Amortization of prior service cost | 1,532 | 1,756 | 310 | 401 | ||||||||||||
| Recognized net actuarial (gain) loss | 3,890 | 3,922 | (605 | ) | (205 | ) | ||||||||||
| Amortization of transition obligation | -- | -- | 222 | 314 | ||||||||||||
| Net periodic benefit cost | $ | 6,145 | $ | 5,415 | $ | 485 | $ | 1,269 | ||||||||
| Curtailment/settlement cost | $ | -- | $ | -- | $ | 708 | $ | -- | ||||||||
The Company previously disclosed in its financial statements for the year ended December 31, 2006 that it expected contributions by the Company to fund the pension and other benefits plans for the year ending December 31, 2007 to be $4.5 million and $0.3 million, respectively. During the three and nine months ended September 30, 2007, the actual cash contributions to the Company’s non-qualified pension plans were $0.4 million and $1.2 million, respectively. Based on this activity, the Company anticipates contributing an additional $1.0 million to the Company’s non-qualified pension plan in 2007. The full amount of the pension plan funding for 2007 is for the Company’s non-qualified supplemental retirement plan.
During the three and nine months ended September 30, 2007, actual other post-retirement medical benefit plan contributions were less than $0.1 million and $0.8 million, respectively, and the Company does not expect to make additional contributions for the remaining period of 2007.
On June 20, 2007, the International Brotherhood of Electrical Workers (IBEW) ratified a collective bargaining agreement with PSE. The collective bargaining agreement included changes to the Company’s subsidy for retiree medical insurance. Effective June 20, 2007, no new IBEW employees will receive a retiree medical subsidy at retirement.
Current IBEW-represented employees with less than five years of service will no longer receive a medical subsidy at retirement and those employees with more that one year of service but less than five years of service received a one-time cash payment. Current IBEW-represented employees with five or more years of service had a one-time opportunity to elect a cash payment that varied depending on the years of employment with PSE in lieu of continuing eligibility for the retiree medical subsidy. As a result of the termination, the curtailment loss was $0.7 million.
(6) | Income Taxes |
During the three and nine months ended September 30, 2007, PSE recorded an income tax benefit of $1.9 million and an expense of $49.2 million, respectively, compared to an expense of $9.1 million and $60.0 million for the three and nine months ended September 30, 2006, respectively. Lower income tax expense in 2007 was primarily related to lower net income in 2007 and a true-up of the 2006 federal tax provision which resulted in an adjustment to the 2007 effective tax rate. The effective tax rate was also lower due to higher tax credits associated with the production of wind-powered energy. The true-up of the 2006 tax provision was a benefit of $1.9 million for the three months ended September 30, 2007 as compared to an expense of $0.5 million in 2006 for the 2005 tax provision true-up. The production tax credits for the three and nine months ended September 30, 2007 were $1.1 million and $13.9 million, respectively, compared to $0.3 million and $4.9 million for the three and nine months ended September 30, 2006, respectively.
The additional credits were made available due to the addition of the Wild Horse wind project, which was placed in service in December 2006. In July 2006, Financial Accounting Standards Board (FASB) issued Interpretation No. 48 (FIN 48), “Accounting for Uncertainty in Income Taxes, an Interpretation of FASB Statement No. 109,” which clarifies the accounting for uncertainty in income taxes recognized in the financial statements in accordance with FASB Statement No. 109, “Accounting for Income Taxes.” FIN 48 requires the use of a two-step approach for recognizing and measuring tax positions taken or expected to be taken in a tax return. First, a tax position should only be recognized when it is more likely than not, based on technical merits, that the position will be sustained upon examination by the taxing authority. Second, a tax position that meets the recognition threshold should be measured at the largest amount that has a greater than 50% likelihood of being sustained.
FIN 48 was effective for the Company as of January 1, 2007. As of the date of adoption, the Company had no material unrecognized tax benefits but accrued $6.6 million in interest expense related to tax deductions for certain capitalized internal labor and related overhead costs previously deducted before repayment in 2005 and 2006. Additionally, the Company has reversed $1.9 million and $1.2 million in interest expense for the three and nine months ended September 30, 2007, respectively, related to the tax deductions for the capitalized internal labor and overheads due to a change in estimate related to settlement guidelines established by the Internal Revenue Service (IRS) national office. The balance at September 30, 2007 was $5.4 million.
In its 2001 tax return, PSE claimed a deduction when it changed its tax accounting method with respect to capitalized internal labor and overheads. Under the new method, the Company could immediately deduct certain costs that it had previously capitalized. In the IRS audit of the Company’s 2001, 2002 and 2003 federal income tax returns, the IRS disallowed the deduction, citing Revenue Ruling 2005-53. The Company believes the original deductions were valid as filed and has formally appealed the IRS adjustment. The Company repaid the tax benefits in 2005 and 2006 as provided in the new Regulations, issued on August 2, 2005 (Regulation 1.263(a)-1). At December 31, 2006, the full tax benefit had been repaid. The IRS national office established settlement guidelines which will apply to its settlement offers on this issue. It is possible that this issue could be resolved in the next 12 months.
Based on prior Washington Utilities and Transportation Commission (Washington Commission) orders on this issue, it is management’s expectation that if the IRS is ultimately successful in challenging some portion of the deduction the Company could request rate recovery of the regulatory asset for the interest accrued.
For federal income tax purposes, the Company has open tax years from 2001 through 2007. The Company continues its policy of classifying interest as interest expense and penalties as other expense in the financial statements.
(7) | Regulation and Rates |
On September 26, 2007, the Washington Commission approved PSE’s requested revisions to its purchased gas adjustment (PGA) tariff schedules resulting in a decrease of $148.1 million or 13% on an annual basis in gas sales revenues effective October 1, 2007. The rate decrease was the result of lower costs of natural gas in the forward market and a refund of the accumulated PGA payable balance over a 12-month period beginning October 1, 2007. The PGA rate change will decrease PSE’s revenue but will not impact the Company’s net income as the decreased revenue will be offset by decreased purchased gas costs and revenue sensitive taxes.
On March 20, 2007, PSE submitted a Power Cost Only Rate Case (PCORC) filing to request approval of an updated power cost baseline rate beginning September 2007. The PCORC filing also requested recovery of the Goldendale generating facility (Goldendale) ownership and operating costs through retail electric rates. On May 23, 2007, PSE filed updated power costs due to changes in market conditions of natural gas and other costs which resulted in a revised proposed increase of $77.8 million or 4.4% annually. On July 5, 2007, a settlement agreement in this PCORC signed by PSE and certain other parties to the proceeding was filed with the Washington Commission, the terms of which included an electric rate increase of $64.7 million. On August 2, 2007, the Washington Commission approved the settlement agreement and authorized an increase in PSE’s electric rates of $64.7 million or an average increase of 3.7% annually effective September 1, 2007. The investment in Goldendale was found prudent, thus allowing for recovery of certain ownership and operating costs through electric retail rates effective September 1, 2007 along with updating other power costs.
In accordance with the August 2, 2007 Washington Commission order approving the PCORC settlement, PSE and other parties have agreed to conduct a collaborate stakeholder review of the PCORC process to consider the scope and timing of the PCORC mechanism and whether the mechanism should continue. The collaborative review will include but is not limited to: 1) the number of PCORCs that a company will be allowed to file in any given year; 2) the number and timing of updates that a company my submit in the PCORC process; 3) the items directly associated with power costs that may be included and considered in a PCORC filing; and 4) whether the number and timing of updates may vary depending on if other parties can easily verify. Any agreements reached by the parties in the collaborative will be presented to the Washington Commission for approval during PSE’s next general rate case and any issues on which agreement has not been reached may be raised in the same general rate case.
PSE’s storm accounting, which allows deferral of certain storm damage costs, is subject to review by the Washington Commission at the end of the current three year period, which is December 31, 2007. During the fourth quarter 2007, PSE intends to seek approval from the Washington Commission to continue its storm deferral accounting treatment at current levels beyond December 31, 2007.
On April 11, 2007, the Washington Commission approved PSE’s petition for issuance of an accounting order that authorizes PSE to defer certain ownership and operating costs (and associated carrying costs) the Company incurred related to its purchase of Goldendale during the period prior to inclusion in PSE’s retail electric rates in the PCORC. The deferral is for the time period from March 15, 2007 through September 1, 2007. As of September 30, 2007, PSE had established a regulatory asset of $11.2 million. PSE anticipates amortization of the costs will begin no later than January 1, 2009 as determined in PSE’s next general rate case.
On May 21, 2007, the Bonneville Power Administration (BPA) notified PSE and other investor-owned utilities that BPA was suspending payments related to its residential exchange program due to an adverse Ninth Circuit Court of Appeals (Ninth Circuit) decision of May 3, 2007. The Ninth Circuit concluded in its decision that certain BPA actions in entering into residential exchange settlements in 2000 were not in accordance with the law. BPA suspended payments under the residential exchange program until final decisions by the Ninth Circuit are determined. As a result of the BPA suspension of payment, PSE filed revisions to the tariffs which pass through the benefits of the Residential Exchange to all residential and small farm customers. The Washington Commission approved the termination of the Residential Exchange Credit effective June 7, 2007. Under Federal law, investor-owned utilities receiving residential exchange benefits must pass-through the benefits to their residential and small farm electric customers.
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. The accounting petition sought approval to record carrying costs on the deferred balance until the deferred balance is recovered from customers. As of September 30, 2007, PSE has recorded a regulatory asset of $34.8 million.
In May 2007, the Washington Commission Staff alleged that PSE’s gas system service provider had violated certain Washington Commission recordkeeping rules. The Washington Commission has since filed a complaint against PSE that includes Washington Commission Staff’s recommendation that PSE be assessed a $2.0 million regulatory penalty. As of June 30, 2007, PSE management determined the penalty met the SFAS No. 5, “Accounting for Contingencies” criteria for recording a loss contingency and thus recorded a $2.0 million loss reserve. The Washington Commission investigation is ongoing.
On January 5, 2007, the Washington Commission issued its order in PSE’s electric general rate case filed in February 2006, approving a general rate decrease for electric customers of $22.8 million or 1.3% annually. The rates for electric customers became effective beginning January 13, 2007. In its order, the Washington Commission approved a weighted cost of capital of 8.4%, or 7.06% after-tax and a capital structure that included 44.0% common equity with a return on equity of 10.4%. The Washington Commission had earlier approved (on June 28, 2006) a PCORC increase of $96.1 million annually effective July 1, 2006.
On June 20, 2002, the Washington Commission approved a PCA mechanism that becomes operative if PSE’s costs to provide customers electricity fall outside certain bands established in an electric rate case. The cumulative maximum pre-tax earnings exposure due to power cost variations over the four-year period ended June 30, 2006 was limited to $40.0 million plus 1.0% of the excess. In October 2005, the Washington Commission approved a shift to an annual PCA mechanism measurement period from January through December starting in 2007. On January 5, 2007, the Washington Commission approved the PCA mechanism for continuation under the same annual graduated scale without a cumulative cap for excess power costs. All significant variable power supply cost variables (i.e. hydroelectric and wind generation, market price for purchased power and surplus power, natural gas and coal fuel price, generation unit forced outage risk and transmission cost) are included in the PCA mechanism.
On January 5, 2007, the Washington Commission also issued its order in PSE’s natural gas general rate case, granting an increase for gas customers of $29.5 million or 2.8% annually, effective January 13, 2007.
(8) | Litigation |
Residential Exchange. 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 BPA Residential Exchange Program. 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 have been 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. The parties to these various actions presented oral arguments to the Ninth Circuit in November 2005. 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 June 2007, BPA requested FERC to continue a stay of FERC’s review of such rates in light of uncertainties created by 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 Residential Exchange Program 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.
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. As of September 30, 2007, PSE has a regulatory asset of $34.8 million. 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. It is not clear what impact, if any, development or review of such rates, review of such agreements and the above described Ninth Circuit litigation may ultimately have on PSE.
Colstrip Matters. In May 2003, approximately 50 plaintiffs brought an action against the owners of Colstrip which has since been amended to add additional claims. The lawsuit alleges that certain domestic water wells, groundwater and the Colstrip water supply pond were contaminated by seepage from a Colstrip Units 1 & 2 effluent holding pond, that seepage from Colstrip Units 1 & 2 have decreased property values and that seepage from the Colstrip water supply pond caused structural damage to buildings and toxic mold. Discovery is ongoing. The trial date has been postponed until June 2008. The Company has established a reserve for the expected liability.
On March 29, 2007, a second complaint related to pond seepage was filed on behalf of two ranch owners alleging damage due to the Colstrip Units 3 & 4 effluent holding pond.
On June 15, 2005, the U. S. Environmental Protection Agency (EPA) issued the Clean Air Visibility Rule to address regional haze or regionally-impaired visibility caused by multiple sources over a wide area. The rule defines Best Available Retrofit Technology (BART) requirements for electric generating units, including presumptive limits for sulfur dioxide, particulate matter and nitrogen oxide controls for large units. In February 2007, Colstrip was notified by EPA that Colstrip Units 1 & 2 were determined to be subject to the BART requirements, PSE submitted a BART engineering analysis for Colstrip Units 1 & 2 in August 2007. PSE cannot yet determine the need for or costs of additional controls to comply with this rule.
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.
CPUC Decision. Proceedings, including filings of requests for rehearing or further review, before the Ninth Circuit and/or FERC, have been stayed upon the Court’s own motion until November 16, 2007 to allow for possible settlement discussions to proceed.
Lockyer Case. On June 18, 2007, the U.S. Supreme Court denied the petition that PSE and other energy sellers had submitted that sought Supreme Court review of the Ninth Circuit decision. As such, this matter will be remanded to FERC for further proceedings, but not before November 16, 2007, when the stay of the mandate back to FERC expires.
Pacific Northwest Refund 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. The court remanded the matter to FERC for further proceedings but subsequently issued an order staying further deadlines, including the remand, to November 16, 2007 to allow parties to engage in court-sponsored mediation. PSE intends to vigorously defend its position in this proceeding, but it is unable to predict the outcome of this matter.
Proceeding Relating to the Proposed Merger. On October 26, 2007, a lawsuit was filed in King County Superior Court, Seattle, Washington, naming Puget Energy and its directors as defendants. The lawsuit is a purported class action filed by Edward Tansey on behalf of an alleged class of Puget Energy's shareholders. Plaintiff alleges, among other things, that the director defendants breached their fiduciary duties in approving the proposed acquisition of Puget Energy 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 that was publicly announced on October 26, 2007 (see Note 13 for more information regarding the proposed acquisition). The suit seeks to enjoin the defendants from consummating the proposed acquisition and other relief.
(9) | Related Party Transaction |
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 September 30, 2007, the outstanding balance of the Note was $24.3 million and the interest rate was 5.9%. The outstanding balance and the related interest under the Note are eliminated by Puget Energy upon consolidation of PSE’s financial statements.
(10) | Financings |
On June 1, 2007, PSE redeemed all remaining $37.8 million of its 8.231% Capital Trust Preferred Securities (classified as Junior Subordinated Debentures of the Corporation Payable to a Subsidiary Trust Holding Mandatorily Redeemable Preferred Securities on the balance sheet and referred to herein as “Securities”). The purpose of the redemption was to reduce interest costs by retiring higher cost debt. The Securities were redeemed at a 4.12% premium, or $39.3 million, plus accrued interest on the redemption date.
On June 4, 2007, PSE issued $250 million of Junior Subordinated Notes (Notes) due June 2067. The Notes bear a fixed rate of interest for the first 10.5 years with interest payable semiannually in May and November of each year, after which the Notes will bear a variable rate of interest (3-month LIBOR plus 2.35%). Proceeds were used to repay short-term debt, incurred in part to redeem the Securities. The Notes are structured to be treated as debt by the IRS, yet they are considered to have equity-like characteristics by the credit rating agencies. In addition, the Notes contain a call option feature and are callable in whole or in part by PSE on or after June 1, 2017. The Notes are not derivatives and the call option is not required to be bifurcated. They are presented on the balance sheet as a separate line item in the redeemable securities and long-term debt.
In March 2007, PSE entered into a five-year, $350 million credit agreement with a group of banks. The agreement supports the Company’s energy hedging activities. Pursuant to the Washington Commission order in PSE’s electric and gas general rate cases issued on January 5, 2007, the costs of this hedging credit facility will be recovered through the PCA and PGA mechanisms. Under the terms of the credit agreement, PSE pays a floating interest rate on outstanding borrowings based either on the agent bank’s prime rate or on LIBOR plus a marginal rate based on PSE’s long-term credit rating at the time of borrowing. The facility can also be used to provide letters of credit. PSE pays a commitment fee on any unused portion of the credit agreement based on long-term credit ratings of PSE.
In March 2005, PSE entered into a five-year, $500 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 million facility.
(11) | Other |
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 three counterparties during the nine months ended September 30, 2007 may be considered variable interest entities. Consistent with FIN 46R, PSE submitted requests for information to those three 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.
One of these counterparties, Sumas Cogeneration Company, L.P. (Sumas), delivered a letter to PSE on May 7, 2007, stating that it had sold its dedicated 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 and Sumas have initiated discussion relating to Sumas’ actions under the contract, but PSE cannot yet determine what may result from such discussions.
For the two remaining power purchase agreements that may be considered variable interest entities under FIN 46R as of the third quarter 2007, 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 September 30, 2007 was $60.0 million for the two entities and for the three months ended September 30, 2006 was $78.8 million for the three entities. PSE’s purchased electricity expense for the nine months ended September 30, 2007 and 2006 for these three entities was $157.2 million and $174.7 million, respectively.
The EPA required states to produce regulations by November 15, 2006 to bring their mercury emissions in line with those mandated by the Clean Air Mercury Rule. The Montana Board of Environmental Review approved the state of Montana’s regulation to limit mercury emissions from coal-fired plants on October 16, 2006. The new rule takes a two-tiered approach to reducing mercury emissions, allowing power plants burning lower-quality lignite coal to release more emissions than plants such as Colstrip that burn cleaner sub-bituminous coal. The new rule has a more stringent limit than the federal rule (0.9 lbs/Trillion British thermal unit (TBtu), instead of the federal 1.4 lbs/TBtu), but includes a cap-and-trade provision as well as alternative emission limits for plants that have tried to meet the new standards but have demonstrated that they cannot. PSE and the Colstrip owners are still evaluating the potential impact of the new rule and have not determined whether to appeal the new rule.
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 EPA. The Notice stated that PSE had met the requirements of the Order and the accompanying scope of work. Total removal costs as of September 30, 2007 were approximately $13.0 million. PSE estimates the total remediation cost to be approximately $15.0 million, which has been accrued or paid. At September 30, 2007, PSE had an insurance receivable recorded in the amount of $12.6 million associated with this fuel release. PSE has also responded to a request for information under the Clean Water Act from the EPA. PSE has filed a petition with the Washington Commission to defer costs associated with the remediation effort. The Washington Commission has not yet ruled on this matter.
On May 30, 2007, PSE agreed to extend the terms of the existing leases of its Bellevue corporate office complex from 10 years to 15 years. PSE’s lease agreement included a one-time right to purchase the office complex. PSE elected to monetize the value of this purchase option and negotiated for a cash payment of $18.9 million, net of transaction fees, in exchange for the termination of the purchase option. PSE has filed an accounting petition with the Washington Commission seeking deferred accounting treatment of the net proceeds and amortization of the net proceeds to match the near-term contractual lease payment increases. The Washington Commission has not yet ruled on this matter.
In a recent decision, Washington State Supreme Court ruled that certain job reporting practices involving the use of company vehicles are compensable time under Washington State’s wage and hour laws. One union representing a portion of PSE's workforce claims its members should now be compensated for PSE job site reporting practices as a result of this decision. The extent of the claims and financial impact on PSE currently is unknown.
(12) | New Accounting Pronouncements |
In September 2006, FASB issued SFAS No, 157, “Fair Value Measurements.” SFAS No. 157 establishes a common definition for fair value to be applied to GAAP, a framework for measuring fair value, and expands disclosure about such fair value measurements. SFAS No. 157 is effective for fiscal years beginning after November 15, 2007 which will be the calendar year beginning January 1, 2008 for the Company. The Company is currently assessing the impact of SFAS No. 157 on its financial statements.
(13) | Subsequent Event |
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 also includes Alberta Investment Management, Macquarie-FSS Infrastructure Trust and Macquarie Bank Limited (together 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 approval of the transaction by the affirmative vote of two-thirds of the votes entitled to be cast thereon by Puget Energy’s shareholders, the termination or expiration of the waiting period under the Hart-Scott-Rodino Antitrust Improvements Act of 1976, as amended (the "HSR Act"), and the receipt of required regulatory approvals. The transaction is expected to close during the second half of 2008.
The merger agreement contains termination rights for both Puget Energy and the Consortium under certain circumstances. In the event Puget Energy elects to terminate the merger agreement under specified circumstances, it would be required to pay to the acquiring entity either $30 million if the termination is based on the submission of an alternative proposal meeting certain requirements by a party with whom Puget Energy had been in discussions prior to December 10, 2007, or $40 million if such fee becomes payable in all other circumstances, plus, in each case, documented out-of-pocket expenses of the Consortium of up to $10 million. In addition, Puget Energy may be required to pay the Consortium documented out-of-pocket expenses incurred by the Consortium not in excess of $15 million if the merger agreement is terminated due to a breach of the terms of the Merger Agreement by Puget Energy and such breach is incurable or has not been cured within a specified time. The acquiring entity may be required to pay Puget Energy an amount equal to $130 million if the merger agreement is terminated due to a breach of the terms of the merger agreement by the acquiring entity and such breach is incurable or has not been cured within a specified time.
Further information regarding the terms of the merger, including a copy of the Agreement and Plan of Merger, is included in Puget Energy's Current Report on Form 8-K relating to the merger, filed with the Securities and Exchange Commission on October 29, 2007.
On the same day, Puget Energy announced that it had entered into a separate transaction pursuant to a Stock Purchase Agreement, dated as of October 25, 2007, with certain members of the Consortium (collectively, the “Purchasers”). Under the Stock Purchase Agreement, the Purchasers will severally acquire, and Puget Energy will issue to the Purchasers, 12,500,000 shares of Puget Energy common stock at a purchase price of $23.67 per share. Puget Energy intends to use the proceeds from this issuance to invest in its wholly owned subsidiary, Puget Sound Energy, Inc., for capital expenditures, debt redemption and working capital. The consummation of the sale of securities to the Purchasers pursuant to the Agreement is subject to the satisfaction of customary closing conditions, including termination or expiration of the waiting period under the HSR Act. Puget Energy anticipates that the stock purchase will close before then end of 2007. Further information regarding the terms of the Stock Purchase Agreement, including a copy of the agreement, is included in Puget Energy's Current Report on Form 8-K relating to the Stock Purchase Agreement, filed with the Securities and Exchange Commission on October 29, 2007.
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 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. You 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 gas utility company. Until May 7, 2006, Puget Energy owned a 90.9% interest in InfrastruX Group, Inc. (InfrastruX), a utility construction and services company that was sold to an affiliate of Tenaska Power Fund, L.P. (Tenaska). Puget Energy is substantially 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 gas service in a cost effective manner through PSE.
Recent Developments
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 also includes Alberta Investment Management, Macquarie-FSS Infrastructure Trust and Macquarie Bank Limited (together 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 approval of the transaction by the affirmative vote of two-thirds of the votes entitled to be cast thereon by Puget Energy’s shareholders, the termination or expiration of the waiting period under the Hart-Scott-Rodino Antitrust Improvements Act of 1976, as amended (the "HSR Act"), and the receipt of required regulatory approvals. The transaction is expected to close during the second half of 2008.
The merger agreement contains termination rights for both Puget Energy and the Consortium under certain circumstances. In the event Puget Energy elects to terminate the merger agreement under specified circumstances, it would be required to pay to the acquiring entity either $30 million if the termination is based on the submission of an alternative proposal meeting certain requirements by a party with whom Puget Energy had been in discussions prior to December 10, 2007, or $40 million if such fee becomes payable in all other circumstances, plus, in each case, documented out-of-pocket expenses of the Consortium of up to $10 million. In addition, Puget Energy may be required to pay the Consortium documented out-of-pocket expenses incurred by the Consortium not in excess of $15 million if the merger agreement is terminated due to a breach of the terms of the Merger Agreement by Puget Energy and such breach is incurable or has not been cured within a specified time. The acquiring entity may be required to pay Puget Energy an amount equal to $130 million if the merger agreement is terminated due to a breach of the terms of the merger agreement by the acquiring entity and such breach is incurable or has not been cured within a specified time.
Further information regarding the terms of the merger, including a copy of the Agreement and Plan of Merger, is included in Puget Energy's Current Report on Form 8-K relating to the merger, filed with the Securities and Exchange Commission on October 29, 2007.
On the same day, Puget Energy announced that it had entered into a separate transaction pursuant to a Stock Purchase Agreement, dated as of October 25, 2007, with certain members of the Consortium (collectively, the “Purchasers”). Under the Stock Purchase Agreement, the Purchasers will severally acquire, and Puget Energy will issue to the Purchasers, 12,500,000 shares of Puget Energy common stock at a purchase price of $23.67 per share. Puget Energy intends to use the proceeds from this issuance to invest in its wholly owned subsidiary, Puget Sound Energy, Inc., for capital expenditures, debt redemption and working capital. The consummation of the sale of securities to the Purchasers pursuant to the Agreement is subject to the satisfaction of customary closing conditions, including termination or expiration of the waiting period under the HSR Act. Puget Energy anticipates that the stock purchase will close before then end of 2007. Further information regarding the terms of the Stock Purchase Agreement, including a copy of the agreement, is included in Puget Energy's Current Report on Form 8-K relating to the Stock Purchase Agreement, filed with the Securities and Exchange Commission on October 29, 2007.
Puget Sound Energy
PSE generates revenues from the sale of electric and gas services, mainly to residential and commercial customers within Washington State. PSE’s operating revenues and associated expenses are not generated evenly during 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 Federal Energy Regulatory Commission (FERC) and Washington Utilities and Transportation Commission (Washington Commission) regulation which may impact a large array of business activities, including limitation of future rate increases related to retail rates, transmission rates and wholesale power sales; directed accounting requirements that could 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 gas and electric distribution and transmission lines; 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. PSE is continually exploring new electric-power resource generation and long-term power purchase agreements to meet this goal on an ongoing basis. On February 21, 2007, PSE acquired the Goldendale generating facility (Goldendale), a 277 megawatt (MW) capacity natural gas generating facility in the state of Washington, from the Calpine Corporation through its bankruptcy proceeding. PSE paid $120.0 million for this generating facility plus transaction costs totaling $2.4 million. On March 20, 2007, PSE filed a Power Cost Only Rate Case (PCORC) seeking recovery of related ownership and operating costs with the Washington Commission. PSE filed a settlement agreement in the PCORC on July 5, 2007 which approved the Goldendale acquisition. On August 2, 2007, the Washington Commission adopted the settlement agreement thus finding PSE’s acquisition of Goldendale prudent. Recovery of the costs began effective September 1, 2007 with the new electric rates. Certain ownership and operating costs incurred for the time period March 15, 2007 through September 1, 2007 were deferred pursuant to an approved petition for accounting order.
On May 31, 2007, PSE filed its 2007 Integrated Resource Plan (IRP) with the Washington Commission. The plan supports a strategy of diverse acquisitions to cost-effectively meet growing demand for energy and reduce carbon emissions. According to the IRP, PSE can secure additional power supplies through heightened energy-efficiency efforts and expanded wind-power generation. PSE believes that a cost-effective and environmentally responsible way to source generation will likely include additional natural gas-fired resources.
In August 2006, PSE announced the selection of seven projects for further discussion and possible negotiation as a result of the 2005 Request For Proposal (RFP) process. Of the seven, PSE has completed three, which include the purchase of Goldendale, a four-year power purchase agreement for 150 MW of winter on-peak energy commencing in 2008 and a power purchase agreement executed on July 12, 2007, for a portion of the output of Klondike Wind Power III, LLC, a wind-powered electric generating facility in north-central Oregon scheduled to be completed in the fourth quarter 2007. Of the remaining four, PSE remains in discussion on one project and has discontinued discussions on the other three. In October 2007, PSE filed two draft RFPs with the Washington Commission to continue expansion of its energy-efficiency programs and power supplies. PSE plans to release the final RFPs in January 2008. The first RFP seeks to broaden and expand PSE’s program for helping customers conserve energy. The second RFP will ask outside power producers, markets and power-plant developers to help PSE procure up to 1,340 average megawatts (aMW) of new electricity resources by 2015.
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. PSE’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 PSE and until May 7, 2006, InfrastruX. Net income for the three months ended September 30, 2007 was $11.4 million on operating revenues of $601.7 million compared to net income of $15.9 million on operating revenues from continuing operations of $519.5 million for the same period in 2006. Net income for 2007 and 2006 includes the results of discontinued operations for InfrastruX.
Basic and diluted earnings per share for the three months ended September 30, 2007 were $0.10 compared to basic and diluted earnings per share for the three months ended September 30, 2006 of $0.14. The discontinued operations of InfrastruX had no impact on the basic and diluted earnings per share for the three months ended September 30, 2006. Electric margin increased $6.3 million and gas margin increased $7.5 million for the three months ended September 30, 2007, compared to the same period in 2006. Offsetting the increases in margin were an increase of $6.7 million in utility operation and maintenance expense, a $2.3 million increase in non-utility operation and maintenance and other expenses, a $3.4 million increase in depreciation and amortization, an increase of $6.0 million in taxes other than income taxes, net of revenue sensitive taxes, a $10.4 million increase in interest expense due to higher debt levels and higher interest rates and a decrease of $5.9 million in the unrealized gain on derivative instruments.
For the nine months ended September 30, 2007, Puget Energy’s net income was $129.1 million on operating revenues from continuing operations of $2.3 billion compared to net income of $162.1 million on operating revenues from continuing operations of $2.0 billion for the same period in 2006. Basic and diluted earnings per share for the nine months ended September 30, 2007 were $1.11 and $1.10, respectively, compared to basic and diluted earnings per share of $1.40 and $1.39, respectively, for the same period in 2006.
Net income for the nine months ended September 30, 2007 was positively impacted by increased electric and gas margins of $33.7 million and $25.7 million, respectively, compared to the same period in 2006. Net income was negatively impacted by an increase of $32.9 million related to utility operation and maintenance, a $5.3 million increase in non-utility operation and maintenance, an increase in depreciation and amortization of $10.4 million, a $4.8 million increase in taxes other than income taxes, net of revenue sensitive taxes and a $25.7 million increase in interest expense due to increased debt levels and higher short-term interest rates. Net income for the nine months ended September 30, 2006 was positively impacted by income from discontinued operations of InfrastruX of $51.9 million (after-tax). The income from discontinued operations for the nine months ended September 30, 2006 included a gain on disposal of $29.8 million (after-tax) resulting from the sale of InfrastruX. The increase was partially offset by the charitable contribution of $15.0 million ($9.75 million after-tax) by Puget Energy.
Puget Sound Energy
PSE’s operating revenues and associated expenses are not generated evenly during 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 overrecovery 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 September 30, 2007 compared to the same period in 2006. 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 September 30, | 2007 | 2006 | Change | Percent Change | ||||||||||||
Electric operating revenue1 | $ | 456.1 | $ | 399.2 | $ | 56.9 | 14.3 | % | ||||||||
| Less: Other electric operating revenue | (3.2 | ) | (8.2 | ) | 5.0 | 61.0 | ||||||||||
| Add: Other electric revenue-gas supply resale | (6.6 | ) | (0.1 | ) | (6.5 | ) | * | |||||||||
| Total electric revenue for margin | 446.3 | 390.9 | 55.4 | 14.2 | ||||||||||||
| Adjustments for amounts included in revenue: | ||||||||||||||||
| Pass-through tariff items | (9.8 | ) | (8.3 | ) | (1.5 | ) | (18.1 | ) | ||||||||
| Pass-through revenue-sensitive taxes | (29.5 | ) | (26.7 | ) | (2.8 | ) | (10.5 | ) | ||||||||
| Net electric revenue for margin | 407.0 | 355.9 | 51.1 | 14.4 | ||||||||||||
| Minus power costs: | ||||||||||||||||
Purchased electricity1 | (185.8 | ) | (183.7 | ) | (2.1 | ) | (1.1 | ) | ||||||||
Electric generation fuel1 | (43.5 | ) | (36.3 | ) | (7.2 | ) | (19.8 | ) | ||||||||
Residential exchange1 | 0.4 | 35.9 | (35.5 | ) | (98.9 | ) | ||||||||||
| Total electric power costs | (228.9 | ) | (184.1 | ) | (44.8 | ) | (24.3 | ) | ||||||||
Electric margin2 | $ | 178.1 | $ | 171.8 | $ | 6.3 | 3.7 | % | ||||||||
____________________________
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 $6.3 million for the three months ended September 30, 2007 compared to the same period in 2006 due to an increase in customer pricing due to the January 13, 2007 general rate case which resulted in an increase to margin of $13.2 million and a 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 $1.3 million due in part to recovery of ownership and operating costs of new generation facilities. In addition, a 1.2% increase in retail-sales volumes increased electric margin $2.1 million. These increases were partially offset by a decrease in electric margin of $3.6 million due to an increase of production tax credits (PTCs) provided to customers. PTCs provided to customers through lower rates are recovered through a lower effective tax rate. Such favorable changes in the allocation of power costs between PSE and the customer may not be repeated in the future and should not be considered a recurring element in operating income for the quarter.
The Power Cost Adjustment (PCA) mechanism allows PSE to recover power costs according to certain terms. The PCA mechanism was revised effective July 1, 2006 resulting in a shift in PSE’s power cost recovery between quarters and within the calendar year. The increase in the third quarter 2007 electric margin reflects a decrease of $6.7 million related to the PCA mechanism. PSE overrecovered power costs under the PCA mechanism by $7.2 million in the third quarter 2007 compared to $13.9 million in the third quarter 2006 due to revisions in the PCA sharing bands during 2006.
The following table displays the details of electric margin changes for the nine months ended September 30, 2007 compared to the same period in 2006. 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) Nine Months Ended September 30, | 2007 | 2006 | Change | Percent Change | ||||||||||||
Electric operating revenue1 | $ | 1,419.0 | $ | 1,247.6 | $ | 171.4 | 13.7 | % | ||||||||
| Less: Other electric operating revenue | (29.9 | ) | (38.2 | ) | 8.3 | 21.7 | ||||||||||
| Add: Other electric revenue-gas supply resale | (0.2 | ) | 11.9 | (12.1 | ) | (101.7 | ) | |||||||||
| Total electric revenue for margin | 1,388.9 | 1,221.3 | 167.6 | 13.7 | ||||||||||||
| Adjustments for amounts included in revenue: | ||||||||||||||||
| Pass-through tariff items | (30.7 | ) | (25.4 | ) | (5.3 | ) | (20.9 | ) | ||||||||
| Pass-through revenue-sensitive taxes | (95.3 | ) | (83.4 | ) | (11.9 | ) | (14.3 | ) | ||||||||
| Net electric revenue for margin | 1,262.9 | 1,112.5 | 150.4 | 13.5 | ||||||||||||
| Minus power costs: | ||||||||||||||||
Purchased electricity1 | (640.6 | ) | (623.7 | ) | (16.9 | ) | (2.7 | ) | ||||||||
Electric generation fuel1 | (93.3 | ) | (72.2 | ) | (21.1 | ) | (29.2 | ) | ||||||||
Residential exchange1 | 52.4 | 131.2 | (78.8 | ) | (60.1 | ) | ||||||||||
| Total electric power costs | (681.5 | ) | (564.7 | ) | (116.8 | ) | (20.7 | ) | ||||||||
Electric margin2 | $ | 581.4 | $ | 547.8 | $ | 33.6 | 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 $33.6 million for the nine months ended September 30, 2007 compared to the same period in 2006 due to lower power costs related to increased production of low cost hydroelectric power and company-owned generating facilities. The increase was also due to a PCORC rate increase of 5.9% effective July 1, 2006 and 3.7% effective September 1, 2007 net of a 1.3% general rate decrease effective January 13, 2007 which increased electric margin by $31.9 million for recovery of ownership and operating costs of new generating facilities. In addition, a 2.1% increase in retail sales volumes increased electric margin by $9.5 million. These increases were partially offset by a decrease in electric margin of $12.1 million due to an increase of PTCs provided to customers. PTCs provided to customers through lower rates are recovered through a lower effective tax rate.
The increase in 2007 electric margin for the nine months ended September 30, 2007 reflects $3.3 million related to the PCA mechanism. PSE overrecovered power costs under the PCA mechanism by $30.1 million during 2007 compared to $26.8 million during 2006. Such favorable changes in the allocation of power costs between PSE and the customer may not be repeated in the future and should not be considered a recurring element in operating income.
The following table displays the details of gas margin changes for the three months ended September 30, 2007 compared to the same period in 2006. Gas margin is gas sales to retail and transportation customers less pass-through tariff items and revenue-sensitive taxes, and the cost of gas purchased, including gas transportation costs to bring gas to PSE’s service territory.
| Gas Margin | ||||||||||||||||
(Dollars in Millions) Three Months Ended September 30, | 2007 | 2006 | Change | Percent Change | ||||||||||||
Gas operating revenue1 | $ | 142.1 | $ | 119.6 | $ | 22.5 | 18.8 | % | ||||||||
| Less: Other gas operating revenue | (4.1 | ) | (3.8 | ) | (0.3 | ) | (7.9 | ) | ||||||||
| Total gas revenue for margin | 138.0 | 115.8 | 22.2 | 19.2 | ||||||||||||
| Adjustments for amounts included in revenue: | ||||||||||||||||
| Pass-through tariff items | (1.1 | ) | (0.7 | ) | (0.4 | ) | (57.1 | ) | ||||||||
| Pass-through revenue-sensitive taxes | (11.0 | ) | (9.3 | ) | (1.7 | ) | (18.3 | ) | ||||||||
| Net gas revenue for margin | 125.9 | 105.8 | 20.1 | 19.0 | ||||||||||||
Less: Purchased gas costs1 | (80.9 | ) | (68.3 | ) | (12.6 | ) | (18.4 | ) | ||||||||
Gas margin2 | $ | 45.0 | $ | 37.5 | $ | 7.5 | 20.0 | % | ||||||||
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 $7.5 million for the three months ended September 30, 2007 compared to the same period in 2006 primarily due to a 2.8% general rate increase effective January 13, 2007 which increased gas margin $3.0 million, increased usage by residential and commercial customers and a change in pricing which increased margin $2.7 million and a 4.8% increase in gas therm volume sales which contributed $1.8 million to gas margin.
The following table displays the details of gas margin changes for the nine months ended September 30, 2007 compared to the same period in 2006. Gas margin is gas sales to retail and transportation customers less pass-through tariff items and revenue-sensitive taxes, and the cost of gas purchased, including gas transportation costs to bring gas to PSE’s service territory.
| Gas Margin | ||||||||||||||||
(Dollars in Millions) Nine months Ended September 30, | 2007 | 2006 | Change | Percent Change | ||||||||||||
Gas operating revenue1 | $ | 834.3 | $ | 718.6 | $ | 115.7 | 16.1 | % | ||||||||
| Less: Other gas operating revenue | (13.3 | ) | (12.4 | ) | (0.9 | ) | (7.3 | ) | ||||||||
| Total gas revenue for margin | 821.0 | 706.2 | 114.8 | 16.3 | ||||||||||||
| Adjustments for amounts included in revenue: | ||||||||||||||||
| Pass-through tariff items | (6.0 | ) | (4.5 | ) | (1.5 | ) | (33.3 | ) | ||||||||
| Pass-through revenue-sensitive taxes | (68.1 | ) | (57.7 | ) | (10.4 | ) | (18.0 | ) | ||||||||
| Net gas revenue for margin | 746.9 | 644.0 | 102.9 | 16.0 | ||||||||||||
Less: Purchased gas costs1 | (530.6 | ) | (453.4 | ) | (77.2 | ) | (17.0 | ) | ||||||||
Gas margin2 | $ | 216.3 | $ | 190.6 | $ | 25.7 | 13.5 | % | ||||||||
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 $25.7 million for the nine months ended September 30, 2007 compared to the same period in 2006 primarily due to a 2.8% general rate increase effective January 13, 2007 which increased gas margin $15.6 million, a 3.8% gas therm volume sales increase which increased gas margin $7.3 million and a change in customer usage and pricing which increased margin $2.8 million.
Electric Operating Revenues
The table below sets forth changes in electric operating revenues for PSE for the three months ended September 30, 2007 compared to the same period in 2006.
(Dollars in Millions) Three Months Ended September 30, | 2007 | 2006 | Change | Percent Change | ||||
| Electric operating revenues: | ||||||||
| Residential sales | $ 184.2 | $ 150.2 | $ 34.0 | 22.6 | % | |||
| Commercial sales | 177.6 | 174.7 | 2.9 | 1.7 | ||||
| Industrial sales | 25.5 | 26.0 | (0.5 | ) | (1.9 | ) | ||
| Other retail sales, including unbilled revenue | 17.6 | 12.4 | 5.2 | 41.9 | ||||
| Total retail sales | 404.9 | 363.3 | 41.6 | 11.5 | ||||
| Transportation sales | 2.8 | 3.4 | (0.6 | ) | (17.6 | ) | ||
| Sales to other utilities and marketers | 45.3 | 24.3 | 21.0 | 86.4 | ||||
| Other | 3.1 | 8.2 | (5.1 | ) | (62.2 | ) | ||
| Total electric operating revenues | $ 456.1 | $ 399.2 | $ 56.9 | 14.3 | % | |||
Electric retail sales increased $41.6 million for the three months ended September 30, 2007 compared to the same period in 2006 due primarily to a decrease in the benefits of the Residential and Farm Energy Exchange Benefit credited to customers during the three month period ended September 30, 2007 which reduced electric operating revenues by $0.4 million compared to $37.6 million for the same period in 2006. This credit also reduced power costs by a corresponding amount with no impact on earnings. The Residential and Farm Energy Exchange Benefit was suspended to residential and small farm customers effective June 7, 2007 due to adverse rulings from the Ninth Circuit Court of Appeals (Ninth Circuit) which states that Bonneville Power Administration (BPA) actions in entering into residential exchange settlement agreements with investor owned utilities were not in accordance with the law. The increase was also related to the PCORC rate increase of September 1, 2007 and retail sales volumes offset by the electric general rate decrease of January 13, 2007. The electric tariff changes provided $1.3 million to electric operating revenues for the three months ended September 30, 2007 compared to the same period in 2006. Retail electricity usage increased 54,917 megawatt hours (MWh) or 1.2% for the three months ended September 30, 2007 compared to the same period in 2006, which resulted in an increase of approximately $4.2 million in electric operating revenue. The increase in electricity usage was primarily related to 1.8% higher average number of customers served in 2007 compared to 2006.
Sales to other utilities and marketers increased $21.0 million for the three months ended September 30, 2007 compared to the same period in 2006 primarily due to an increase in sales volume of 429,099 MWh or 96.8%, which resulted in an increase of $22.3 million, partially offset by lower wholesale market prices for the third quarter 2007 compared to the same period in 2006 resulting in a decrease of $1.3 million.
Other electric revenues decreased $5.1 million for the three months ended September 30, 2007 compared to the same period in 2006 primarily due to higher losses from non-core gas financial hedges and physical sales of surplus natural gas purchased for electric generating use in 2007 compared to the same period in 2006.
The table below sets forth changes in electric operating revenues for PSE for the nine months ended September 30, 2007 compared to the same period in 2006.
(Dollars in Millions) Nine months Ended September 30, | 2007 | 2006 | Change | Percent Change | ||||
| Electric operating revenues: | ||||||||
| Residential sales | $ 675.7 | $ 559.3 | $ 116.4 | 20.8 | % | |||
| Commercial sales | 550.6 | 516.9 | 33.7 | 6.5 | ||||
| Industrial sales | 77.8 | 76.4 | 1.4 | 1.8 | ||||
| Other retail sales, including unbilled revenue | (14.0 | ) | (8.9 | ) | (5.1 | ) | (57.3 | ) |
| Total retail sales | 1,290.1 | 1,143.7 | 146.4 | 12.8 | ||||
| Transportation sales | 7.6 | 8.8 | (1.2 | ) | (13.6 | ) | ||
| Sales to other utilities and marketers | 91.5 | 56.9 | 34.6 | 60.8 | ||||
| Other | 29.8 | 38.3 | (8.5 | ) | (22.2 | ) | ||
| Total electric operating revenues | $ 1,419.0 | $ 1,247.7 | $ 171.3 | 13.7 | % | |||
Electric retail sales increased $146.4 million for the nine months ended September 30, 2007 compared to the same period in 2006 due primarily to a decrease in the benefits of the Residential and Farm Energy Exchange Benefit credited to customers during the nine months ended September 30, 2007 which reduced electric operating revenues by $54.9 million compared to $137.4 million for the same period in 2006. This credit also reduced power costs by a corresponding amount with no impact on earnings. The PCORC rate increases of July 1, 2006 and September 1, 2007 offset by the electric general rate decrease of January 13, 2007 increased electric retail sales along with an increase in retail sales volumes. The electric tariff changes provided $37.9 million to electric operating revenues for the nine months ended September 30, 2007 compared to the same period in 2006. Retail electricity usage increased 313,554 MWh or 2.1% for the nine months ended September 30, 2007 compared to the same period in 2006, which resulted in an increase of approximately $23.5 million in electric operating revenue. The increase in electricity usage was related to 2.1% higher average number of customers served in 2007 compared to 2006.
Transportation sales decreased $1.2 million for the nine months ended September 30, 2007 compared to the same period in 2006 as a result of transportation customers balancing their scheduled load. For the nine months ended September 2006, transportation customers purchased power in excess of their scheduled load whereas for the same period in 2007, the scheduled load was less than actual usage. This decrease was offset by an increase in sales volume of 22,976 MWh or 1.4%.
Sales to other utilities and marketers increased $34.6 million for the nine months ended September 30, 2007 compared to the same period in 2006 due to an increase in sales volume of 378,141 MWh or 24.4%, which resulted in a $18.0 million increase and an increase in wholesale market prices during 2007 compared to 2006 which resulted in an increase of $15.6 million.
Other electric revenues decreased $8.5 million for the nine months ended September 30, 2007 compared to the same period in 2006, primarily due to gains from gas financial hedges on natural gas sold to third parties in 2006 that did not recur in 2007.
The following electric rate changes were approved by the Washington Commission in 2007 and 2006:
Type of Rate Adjustment | Effective Date | Average Percentage Increase (Decrease) in Rates | Annual Increase (Decrease) in Revenues (Dollars in Millions) | |
| Power Cost Only Rate Case | September 1, 2007 | 3.7 | % | $ 64.7 |
| Power Cost Only Rate Case | July 1, 2006 | 5.9 | 45.3 1 | |
| Electric General Rate Case | January 13, 2007 | (1.3 | ) | (22.8) |
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1 | The rate increase is for the period July 1, 2006 through December 31, 2006. The annualized basis of the PCORC rate increase is $96.1 million. |
Gas Operating Revenues
The table below sets forth changes in gas operating revenues for PSE for the three months ended September 30, 2007 compared to the same period in 2006.
(Dollars in Millions) Three Months Ended September 30, | 2007 | 2006 | Change | Percent Change | ||||
| Gas operating revenues: | ||||||||
| Residential sales | $ 74.7 | $ 60.9 | $ 13.8 | 22.7 | % | |||
| Commercial sales | 49.3 | 41.8 | 7.5 | 17.9 | ||||
| Industrial sales | 10.6 | 10.0 | 0.6 | 6.0 | ||||
| Total retail sales | 134.6 | 112.7 | 21.9 | 19.4 | ||||
| Transportation sales | 3.4 | 3.1 | 0.3 | 9.7 | ||||
| Other | 4.1 | 3.8 | 0.3 | 7.9 | ||||
| Total gas operating revenues | $ 142.1 | $ 119.6 | $ 22.5 | 18.8 | % | |||
Gas retail sales increased $21.9 million for the three months ended September 30, 2007 compared to the same period in 2006 due to higher Purchased Gas Adjustment (PGA) mechanism rates, the approval of a 2.8% general gas rate increase effective January 13, 2007 and increased customer gas usage. The Washington Commission approved a PGA mechanism rate increase effective October 1, 2006 that increased rates 10.2% annually. The PGA mechanism passes through to customers increases or decreases in the 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 gas pipeline transportation costs. PSE’s gas margin and net income are not affected by changes under the PGA mechanism. For the three months ended September 30, 2007, the effects of the PGA mechanism rate increases provided an increase of $9.4 million in gas operating revenues. The gas general rate case provided an additional $3.0 million in gas revenues for the three months ended September 30, 2007 as compared to the same period in 2006. The remaining increase in gas retail revenues was primarily due to higher gas sales of 6.5 million therms or $5.6 million for the three months ended September 30, 2007 compared to the same period in 2006, which was related to a 2.7% increase in customers.
The table below sets forth changes in gas operating revenues for PSE for the nine months ended September 30, 2007 compared to the same period in 2006.
(Dollars in Millions) Nine Months Ended September 30, | 2007 | 2006 | Change | Percent Change | ||||
| Gas operating revenues: | ||||||||
| Residential sales | $ 510.5 | $ 436.0 | $ 74.5 | 17.1 | % | |||
| Commercial sales | 257.2 | 221.0 | 36.2 | 16.4 | ||||
| Industrial sales | 43.1 | 39.4 | 3.7 | 9.4 | ||||
| Total retail sales | 810.8 | 696.4 | 114.4 | 16.4 | ||||
| Transportation sales | 10.2 | 9.8 | 0.4 | 4.1 | ||||
| Other | 13.3 | 12.4 | 0.9 | 7.3 | ||||
| Total gas operating revenues | $ 834.3 | $ 718.6 | $ 115.7 | 16.1 | % | |||
Gas retail sales increased $114.4 million for the nine months ended September 30, 2007 compared to the same period in 2006 due to higher PGA mechanism rates, the approval of a 2.8% general gas rate increase effective January 13, 2007 and increased customer gas usage. The Washington Commission approved a PGA mechanism rate increase effective October 1, 2006 that increased rates 10.2% annually. The PGA mechanism passes through to customers increases or decreases in the 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 gas pipeline transportation costs. PSE’s gas margin and net income are not affected by changes under the PGA mechanism. For the nine months ended September 30, 2007, the effects of the PGA mechanism rate increases provided an increase of $62.3 million in gas operating revenues. The gas general rate case provided an additional $15.6 million in gas revenues for the nine months ended September 30, 2007 as compared to the same period in 2006. The remaining increase in gas retail revenues was primarily due to higher gas sales of 27.9 million therms or $27.2 million for the nine months ended September 30, 2007 compared to the same period in 2006, which was related to a 2.7% increase in customers.
The following gas rate adjustments were approved by the Washington Commission in 2007 and 2006:
Type of Rate Adjustment | Effective Date | Average Percentage Increase (Decrease) in Rates | Annual Increase (Decrease) in Revenues (Dollars in Millions) | ||
| Purchased Gas Adjustment | October 1, 2007 | (13.0 | ) % | $(148.1 | ) |
| Purchased Gas Adjustment | October 1, 2006 | 10.2 | 95.1 | ||
| Gas General Rate Case | January 13, 2007 | 2.8 | 29.5 | ||
Non-Utility Operating Revenues
The table below sets forth changes in non-utility operating revenues for PSE for the three months ended September 30, 2007 compared to the same period in 2006.
(Dollars in Millions) Three Months Ended September 30, | 2007 | 2006 | Change | Percent Change | ||||
| Non-Utility Operating Revenue | $3.5 | $0.7 | $2.8 | * | ||||
| * | Percent change not applicable or meaningful |
The table below sets forth changes in non-utility operating revenues for PSE for the nine months ended September 30, 2007 compared to the same period in 2006.
(Dollars in Millions) Nine Months Ended September 30, | 2007 | 2006 | Change | Percent Change | ||||
| Non-Utility Operating Revenue | $13.4 | $5.8 | $7.6 | 131.0 | % | |||
Non-utility operating revenues increased $2.8 million and $7.6 million for the three and nine months ended September 30, 2007, respectively, compared to the same periods in 2006 due to additional 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 September 30, 2007 compared to the same period in 2006.
(Dollars in Millions) Three Months Ended September 30, | 2007 | 2006 | Change | Percent Change | ||||
| Purchased electricity | $ 185.8 | $ 183.7 | $ 2.1 | 1.1 | % | |||
| Electric generation fuel | 43.5 | 36.3 | 7.2 | 19.8 | ||||
| Residential exchange credit | (0.4 | ) | (35.9 | ) | (35.5 | ) | (98.9 | ) |
| Purchased gas | 80.9 | 68.3 | 12.6 | 18.4 | ||||
| Unrealized (gain) loss on derivative instruments | 5.3 | (0.6 | ) | 5.9 | * | |||
| Utility operations and maintenance | 94.4 | 87.7 | 6.7 | 7.6 | ||||
| Non-utility expense and other | 2.2 | 0.7 | 1.5 | * | ||||
| Depreciation and amortization | 68.9 | 65.5 | 3.4 | 5.2 | ||||
| Conservation amortization | 8.5 | 7.1 | 1.4 | 19.7 | ||||
| Taxes other than income taxes | 56.9 | 46.3 | 10.6 | 22.9 | ||||
| * | Percent change not applicable or meaningful |
The table below sets forth significant changes in operating expenses for PSE and its subsidiaries for the nine months ended September 30, 2007 compared to the same period in 2006.
(Dollars in Millions) Nine Months Ended September 30, | 2007 | 2006 | Change | Percent Change | ||||
| Purchased electricity | $ 640.6 | $ 623.8 | $ 16.8 | 2.7 | % | |||
| Electric generation fuel | 93.3 | 72.2 | 21.1 | 29.2 | ||||
| Residential exchange credit | (52.4 | ) | (131.2 | ) | (78.8 | ) | (60.1 | ) |
| Purchased gas | 530.6 | 453.3 | 77.3 | 17.1 | ||||
| Unrealized loss on derivative instruments | 1.0 | 0.2 | 0.8 | * | ||||
| Utility operations and maintenance | 291.5 | 258.7 | 32.8 | 12.7 | ||||
| Non-utility expense and other | 6.8 | 1.4 | 5.4 | * | ||||
| Depreciation and amortization | 204.4 | 194.0 | 10.4 | 5.4 | ||||
| Conservation amortization | 27.6 | 22.6 | 5.0 | 22.1 | ||||
| Taxes other than income taxes | 207.3 | 180.3 | 27.0 | 15.0 | ||||
| * | Percent change not applicable or meaningful |
Purchased electricity expenses increased $2.1 million and $16.8 million for the three and nine months ended September 30, 2007, respectively, compared to the same periods in 2006. The increase for the three months ended September 30, 2007 was primarily the result of an increase in transmission and other expenses of $5.4 million and a deferral of $4.5 million owed to customers related to the PCA mechanism, which reflected an increase in the overrecovery of allowable power costs shared with customers due to lower wholesale market prices during the three months ended September 30, 2007 as compared to the same period in 2006. A change in the PCA mechanism sharing bands effective January 2007 resulted in sharing more overrecovered power costs with customers in the three months ended September 30, 2007 as compared to the same period in 2006. In addition, total purchased power for the three months ended September 30, 2007 increased $3.8 million due to an increase in purchases (88,443 MWh or 2.5%) compared to the same period in 2006. This increase was offset by a decrease in wholesale market prices, which resulted in a net decrease in purchased power of $11.6 million. The increase for the nine months ended September 30, 2007 was primarily the result of higher wholesale market prices which resulted in an increase of $21.2 million offset to purchased electricity expense by a decrease in purchased power of 297,669 MWh or 2.3%, resulting in a decrease of $13.0 million. Increases in transmission and other expenses contributed $13.8 million due in part to increased kilowatt hour (kWh) sales to customers. The PCA mechanism reflected a $5.2 million decrease in the deferral of power costs for the nine months ended September 30, 2007 as compared to the same period in 2006.
The July 9, 2007 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 April through September 2007 is 99% of normal, which compares to 106% of normal runoff observed for the same period in 2006. PSE’s hydroelectric production and related power costs in 2006 for the January to September period were positively impacted by above-normal precipitation and snow pack in the Pacific Northwest region. The 2008 Columbia Basin Runoff Forecast will be available in December 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 $7.2 million and $21.1 million for the three and nine months ended September 30, 2007, respectively, compared to the same periods in 2006. The increase for the three months ended September 30, 2007 was due in part to the operations of Goldendale, acquired on February 21, 2007, which increased costs by $4.6 million. In addition, higher volumes of electricity generated at Colstrip combined with an increase in the cost of coal increased costs by $1.8 million compared to the same period in 2006. The increase for the nine months ended September 30, 2007 was the result of an increase of $11.4 million primarily due to the operations of Goldendale and an increase of $7.1 million due to higher volumes of electricity generated at Colstrip combined with an increase in the cost of coal in 2007 compared to 2006. In addition, higher volumes of electricity generation and natural gas fuel costs at PSE’s combustion turbine contributed $2.6 million for the nine months ended September 30, 2007 as compared to the same period in 2006.
Residential exchange credits associated with the Residential Exchange Program with BPA decreased $35.5 million and $78.8 million for the three and nine months ended September 30, 2007, respectively, compared to the same periods in 2006 as a result of lower residential and small farm customer electric credit in rates effective October 1, 2006. The residential exchange 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. The residential exchange credit provided to residential and small farm customers was suspended effective June 7, 2007.
Purchased gas expenses increased $12.6 million and $77.3 million for the three and nine months ended September 30, 2007, respectively, compared to the same periods in 2006 primarily due to an increase in PGA rates as approved by the Washington Commission and higher customer therm sales. The PGA mechanism allows PSE to recover expected gas costs, and defer, as a receivable or liability, any gas 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 September 30, 2007 was $61.2 million compared to a receivable balance at December 31, 2006 of $39.8 million. 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 underrecovery of market gas cost through rates. A payable balance reflects overrecovery of market gas cost through rates.
Unrealized gain on derivative instruments decreased $5.9 million and $0.8 million for the three and nine months ended September 30, 2007, respectively, compared to the same periods in 2006. The decrease for the three months ended September 30, 2007 was primarily the result of a loss incurred during the third quarter 2007 related to the ineffective portion of cash flow hedge contracts for physical power beginning January 2009 and the decrease in the fair value of the unrealized gain related to a physical gas supply contract for PSE’s electric generating facilities. The cash flow hedge contracts replace the energy that was lost due to the early termination of a contract by the counterparty in the second quarter 2007. The ineffective portion relates to periods in which PSE has enough projected energy resources to meet the expected customer usage without the two contracts. The mark-to-market gain or loss on the physical gas supply contracts is the difference between the forward market price of natural gas and the contract price for natural gas based on volumes purchased. As the contracts near termination, the gain or loss will continue to reverse due to settlement of the contract on a monthly basis and the mark-to-market value will decrease as long as the price for natural gas is at or near the current forward market price.
Utility operations and maintenance expense increased $6.7 million and $32.8 million for the three and nine months ended September 30, 2007, respectively, compared to the same periods in 2006. The increases were the result of higher operating and maintenance costs of $3.0 million and $14.1 million at PSE’s generating facilities primarily due to the addition of Wild Horse which began operations on December 22, 2006 and Goldendale, which was acquired during February 2007. Wild Horse operations and maintenance expense is fully recovered in rates and beginning September 1, 2007, Goldendale is fully recovered in rates. The balance of the increases was the result of higher expenses of operating and maintaining PSE’s energy delivery systems, support services and increased customer service costs.
Non-utility expense and other increased $1.5 million and $5.4 million for the three and nine months ended September 30, 2007, respectively, compared to the same periods in 2006 primarily due to an increase in PSE’s long-term share-based incentive plan costs.
Depreciation and amortization expense increased $3.4 million and $10.4 million for the three and nine months ended September 30, 2007, respectively, compared to the same periods in 2006. These increases include the benefit of the deferral of Goldendale ownership and operating costs of $3.9 million and $10.8 million for the three and nine months ended September 30, 2007, respectively, which, had it not been included, would have resulted in an increase to depreciation and amortization expense of $7.3 million and $21.2 million for the three and nine months ended September 30, 2007, respectively, as compared to the same periods in 2006. The increase in depreciation and amortization for the three months ended September 30, 2007 includes $3.3 million from placing Wild Horse into service on December 16, 2006, $1.2 million from placing Goldendale into service on February 22, 2007 and $2.8 million from other depreciable property placed into service during 2007. The increase in depreciation and expense for the nine months ended September 30, 2007 includes $9.9 million due to Wild Horse, $4.0 million from additions of computer software and leasehold improvements, $2.9 million due to Goldendale and $4.4 million from other depreciable property placed into service during 2007. On August 2, 2007, the Washington Commission approved a PCORC settlement agreement filed July 5, 2007 finding the acquisition of Goldendale to be prudent. 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.
Conservation amortization increased $1.4 million and $5.0 million for the three and nine months ended September 30, 2007, respectively, compared to the same periods in 2006 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 $10.6 million and $27.0 million for the three and nine months ended September 30, 2007, respectively, compared to the same periods in 2006 due primarily to a property tax reduction settlement in 2006 with the Washington State Department of Revenue which resulted in lower property valuations in 2006. The increases also reflect additional plant placed in service as well as revenue sensitive taxes due to increased revenue.
Other Income, Expense, Interest Charges and Income Tax Expense
The table below sets forth significant changes in other income, interest charges and income taxes for PSE and its subsidiaries for the three months ended September 30, 2007 compared to the same period in 2006.
(Dollars in Millions) Three Months Ended September 30, | 2007 | 2006 | Change | Percent Change | ||||||||||||
| Other expense | $ | 0.7 | $ | 1.7 | $ | (1.0 | ) | (58.8 | )% | |||||||
| Interest charge | 51.5 | 41.1 | 10.4 | 25.3 | ||||||||||||
| Income tax (benefit) expense | (1.9 | ) | 9.2 | (11.1 | ) | * | ||||||||||
| * | Percent change not applicable or meaningful |
The table below sets forth significant changes in other income, interest charges and income taxes for PSE and its subsidiaries for the nine months ended September 30, 2007 compared to the same period in 2006.
(Dollars in Millions) Nine Months Ended September 30, | 2007 | 2006 | Change | Percent Change | ||||||||||||
| Interest charge | $ | 150.2 | $ | 124.5 | $ | 25.7 | 20.6 | % | ||||||||
| Income tax expense | 49.8 | 66.0 | (16.2 | ) | (24.5 | ) | ||||||||||
Other expenses decreased $1.0 million for the three months ended September 30, 2007 compared to the same period in 2006 primarily due to a penalty that was assessed by the Washington Commission in the third quarter 2006, which is not tax-deductible.
Interest expense increased $10.4 million and $25.7 million for the three and nine months ended September 30, 2007, respectively, as compared to the same period in 2006. The increase for the three months ended September 30, 2007 was primarily due to additional debt financing in 2007 during which average balances were higher than 2006 levels. The increase was also driven by more favorable pricing on gas purchases in 2007 which resulted in the interest-bearing PGA transferring from a receivable balance in 2006 to a payable balance in 2007. The remainder of the increase was related to additional construction projects in 2007. The increase for the nine months ended September 30, 2007 as compared to the same period in 2006 was due primarily to additional debt financing in 2007 during which average balances were higher than 2006 levels. The increase was also driven by more favorable pricing on gas purchases in 2007 which resulted in the interest-bearing PGA transferring from a receivable balance in 2006 to a payable balance in 2007. The remainder of the increase was related to additional construction projects in 2007.
Income tax expense decreased $11.1 million and $16.2 million for the three and nine months ended September 30, 2007, respectively compared to the same period in 2006. The increase for the three months ended September 30, 2007 was primarily due to lower net income in 2007 and a true-up of the 2006 federal tax provision which resulted in an adjustment to the 2007 effective tax rate. The effective tax rate was also lower due to higher tax credits associated with the production of wind-powered energy. The true-up of the 2006 tax provision was a benefit of $1.9 million for the three months ended September 30, 2007 as compared to an expense of $0.5 million in 2006 for the 2005 tax provision true-up. The PTCs for the three months ended September 30, 2007 were $1.1 million compared to $0.3 million for the same period in 2006. These additional credits were made available due to the addition of Wild Horse, which was placed in service in December 2006. The decrease for the nine months ended September 30, 2007 compared to the same period in 2006 was primarily due to a true-up of the 2006 federal tax provision as a result of filing the federal income tax return which adjusted the 2007 effective tax rate. The effective tax rate was also lower due to higher tax credits associated with the production of wind-powered energy. The PTCs for the nine months ended September 30, 2007 were $13.9 million compared to $4.9 million for the same period in 2006. These additional credits were made available due to the addition of Wild Horse, which was placed in service in December 2006.
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 September 30, 2007:
| Puget Energy | Payments Due Per Period | |||||||||
Contractual Obligations (Dollars in Millions) | Total | 2007 | 2008- 2009 | 2010- 2011 | 2012 & Thereafter | |||||
| Long-term debt including interest | $ | 6,613.3 | $ | 178.1 | $ | 689.6 | $ | 775.8 | $ | 4,969.8 |
| Short-term debt including interest | 378.0 | 378.0 | -- | -- | -- | |||||
| Mandatorily redeemable preferred stock | 1.9 | -- | -- | -- | 1.9 | |||||
| Service contract obligations | 444.5 | 35.7 | 126.5 | 118.5 | 163.8 | |||||
| Non-cancelable operating leases | 175.0 | 7.9 | 53.8 | 25.4 | 87.9 | |||||
Fredonia combustion turbines lease 1 | 61.4 | 1.5 | 12.9 | 47.0 | -- | |||||
| Energy purchase obligations | 6,561.8 | 333.2 | 2,036.1 | 1,324.2 | 2,868.3 | |||||
| Contract initiation payment/collateral requirement | 18.5 | -- | -- | 18.5 | -- | |||||
| Financial hedge obligations | 10.6 | 6.6 | 4.0 | -- | -- | |||||
| Purchase obligations | 34.7 | 9.9 | 24.8 | -- | -- | |||||
| Non-qualified pension and other benefits funding | 46.7 | 6.1 | 7.4 | 5.1 | 28.1 | |||||
| Interest liability on uncertain tax positions | 5.4 | -- | 5.4 | -- | -- | |||||
| Total contractual obligations | $ | 14,351.8 | $ | 957.0 | $ | 2,960.5 | $ | 2,314.5 | $ | 8,119.8 |
| Puget Energy | Amount of Commitment Expiration Per Period | |||||||||
Commercial Commitments (Dollars in Millions) | Total | 2007 | 2008- 2009 | 2010- 2011 | 2012 & Thereafter | |||||
Indemnity agreements 2 | $ | 8.5 | $ | -- | $ | 4.0 | $ | -- | $ | 4.5 |
Credit agreement - available 3 | 590.6 | -- | -- | -- | 590.6 | |||||
Receivable securitization facility 4 | 74.0 | -- | -- | 74.0 | -- | |||||
| Energy operations letter of credit | 7.4 | 7.4 | -- | -- | -- | |||||
| Total commercial commitments | $ | 680.5 | $ | 7.4 | $ | 4.0 | $ | 74.0 | $ | 595.1 |
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1 | See “Fredonia 3 and 4 Operating Lease” under “Off-Balance Sheet Arrangements” below. |
2 | Under the InfrastruX sale agreement, Puget Energy is obligated for certain representations and warranties concerning InfrastruX’s business and anti-trust inquiries. The fair value of the business warranty is $4.0 million at September 30, 2007 and the obligation expires on May 7, 2008. Puget Energy also agreed to indemnify the buyer relating to an inquiry of an InfrastruX subsidiary and the fair value of the warranty was $4.5 million at September 30, 2007. |
3 | At September 30, 2007, PSE had available a $500.0 million and a $350.0 million unsecured credit agreement expiring in April 2012. The credit agreements provide credit support for letters of credit and commercial paper. At September 30, 2007, PSE had $7.4 million outstanding under four letters of credit, $90.0 million in loans outstanding under the $500 million agreement and $162.0 million commercial paper outstanding, effectively reducing the available borrowing capacity to $590.6 million. |
4 | At September 30, 2007, PSE had available a $200.0 million receivables securitization facility that expires in December 2010. $126.0 million was outstanding under the receivables securitization facility at September 30, 2007 thus leaving $74.0 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 September 30, 2007:
| Puget Sound Energy | Payments Due Per Period | |||||||||
Contractual Obligations (Dollars in Millions) | Total | 2007 | 2008- 2009 | 2010- 2011 | 2012 & Thereafter | |||||
| Long-term debt including interest | $ | 6,613.3 | $ | 178.1 | $ | 689.6 | $ | 775.8 | $ | 4,969.8 |
| Short-term debt including interest | 402.4 | 402.4 | -- | -- | -- | |||||
| Mandatorily redeemable preferred stock | 1.9 | -- | -- | -- | 1.9 | |||||
| Service contract obligations | 444.5 | 35.7 | 126.5 | 118.5 | 163.8 | |||||
| Non-cancelable operating leases | 175.0 | 7.9 | 53.8 | 25.4 | 87.9 | |||||
Fredonia combustion turbines lease 1 | 61.4 | 1.5 | 12.9 | 47.0 | -- | |||||
| Energy purchase obligations | 6,561.8 | 333.2 | 2,036.1 | 1,324.2 | 2,868.3 | |||||
| Contract initiation payment/collateral requirement | 18.5 | -- | -- | 18.5 | -- | |||||
| Financial hedge obligations | 10.6 | 6.6 | 4.0 | -- | -- | |||||
| Purchase obligations | 34.7 | 9.9 | 24.8 | -- | -- | |||||
| Non-qualified pension and other benefits funding | 46.7 | 6.1 | 7.4 | 5.1 | 28.1 | |||||
| Interest liability on uncertain tax positions | 5.4 | -- | 5.4 | -- | -- | |||||
| Total contractual obligations | $ | 14,376.2 | $ | 981.4 | $ | 2,960.5 | $ | 2,314.5 | $ | 8,119.8 |
| Puget Sound Energy | Amount of Commitment Expiration Per Period | |||||||||
Commercial Commitments (Dollars in Millions) | Total | 2007 | 2008- 2009 | 2010- 2011 | 2012 & Thereafter | |||||
Credit agreement - available 2 | $ | 590.6 | $ | -- | $ | -- | $ | -- | $ | 590.6 |
Receivable securitization facility 3 | 74.0 | -- | -- | 74.0 | -- | |||||
| Energy operations letter of credit | 7.4 | 7.4 | -- | -- | -- | |||||
| Total commercial commitments | $ | 672.0 | $ | 7.4 | $ | -- | $ | 74.0 | $ | 590.6 |
_________________
1 | See note 1 under Puget Energy above. |
2 | See note 3 under Puget Energy above. |
3 | See note 4 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 lease in April 2001. The term of the lease expires 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 September 30, 2007, PSE’s outstanding balance under the lease was $49.0 million. The expected residual value under the lease is the lesser of $37.4 million or 60% 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% of the unamortized value of the equipment.
Utility Construction Program
Utility construction expenditures for generation, transmission and distribution are designed to meet continuing customer growth and to improve efficiencies of PSE’s energy delivery systems. Construction expenditures, excluding equity Allowance for Funds Used During Construction (AFUDC) and customer refundable contributions, were $548.0 million for the nine months ended September 30, 2007. Utility construction expenditures, excluding AFUDC and excluding new generation resources other than Wild Horse (which will be determined as the Company proceeds through the integrated resource planning process) are anticipated to be as follows in 2007, 2008 and 2009:
Capital Expenditure Estimates (Dollars in Millions) | 2007 | 2008 | 2009 | |||||||||
| Energy delivery, technology and facilities | $ | 565 | $ | 600 | $ | 570 | ||||||
| New supply resources | 145 | 70 | 220 | |||||||||
| Total expenditures | $ | 710 | $ | 670 | $ | 790 | ||||||
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 year ended September 30, 2007 was $491.6 million which is 85.0% of the $578.1 million used for utility construction expenditures and other capital expenditures. For the nine months ended September 30, 2006, cash generated from operations was $152.5 million which is 25.4% of the $601.2 million used for utility construction expenditures and other capital expenditures.
The overall cash generated from operating activities for the nine months ended September 30, 2007 increased $339.1 million compared to the same period in 2006. The increase was primarily the result of collection of the purchased gas receivable of $117.3 million and transactions that occurred in 2006 which did not recur in 2007. These transactions included the Chelan PUD contract initiation payment of $89.0 million, cash collateral re-payment to energy suppliers of $22.0 million and a gain on the sale of InfrastruX of $29.8 million. Also contributing to the increase was $97.7 million in income taxes paid in the first nine months of 2006 compared to $23.0 million paid in the same period in 2006 and a decrease in fuel and gas inventory costs of $38.1 million. These increases were partially offset by a $27.7 million increase in payments to customers related to the Residential Exchange program.
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 is dependent 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 gas mortgage indentures, articles of incorporation and certain loan agreements. Under the most restrictive tests, at September 30, 2007, PSE could issue:
| · | approximately $608.0 million of additional first mortgage bonds under PSE’s electric mortgage indenture based on approximately $1,013.3 million 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 September 30, 2007; |
| · | approximately $447.0 million of additional first mortgage bonds under PSE’s gas mortgage indenture based on approximately $745.0 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 gas utility mortgage), which PSE exceeded at September 30, 2007; |
| · | approximately $859.4 million of additional preferred stock at an assumed dividend rate of 7.0%; and |
| · | approximately $712.1 million of unsecured long-term debt. |
At September 30, 2007, PSE had approximately $4.3 billion in electric and 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 October 29, 2007, were as follows:
| Ratings | ||
| Standard & Poor’s | Moody’s | |
Puget Sound Energy | ||
| Corporate credit/issuer rating | BBB- | Baa3 |
| Senior secured debt | BBB+ | Baa2 |
| Shelf debt senior secured | BBB+ | (P)Baa2 |
| Junior Subordinated Notes | BB | Ba1 |
| Preferred stock | BB | Ba2 |
| Commercial paper | A-3 | P-2 |
| Revolving credit facility | * | Baa3 |
| Ratings outlook | Stable | Stable |
Puget Energy | ||
| Corporate credit/issuer rating | BBB- | Ba1 |
____________
* Standard & Poor’s does not rate credit facilities.
Shelf Registrations, Long-Term Debt and Common Stock Activity
On June 1, 2007, PSE redeemed the remaining 8.231% Capital Trust Preferred Securities (classified on the balance sheet as Junior Subordinated Debentures of the Corporation Payable to a Subsidiary Trust Holding Mandatorily Redeemable Preferred Securities and referred to herein as “Securities”). The purpose of the redemption was to help reduce interest costs by retiring higher cost debt. The remaining $37.8 million of the Securities outstanding were redeemed on June 1, 2007 at a 4.12% premium, or $39.3 million, plus accrued interest on the redemption date.
On June 4, 2007, PSE issued $250.0 million of Junior Subordinated Notes (Notes) due June 2067. The Notes bear a fixed rate of interest for the first ten and a half years with interest payable semiannually in May and November of each year, after which the notes will bear a variable rate of interest (3-month LIBOR plus 2.35%). Proceeds were used to fund the redemption of the remaining $37.8 million 8.231% Securities and to repay short-term debt. The Notes are structured to be treated as debt by the IRS, yet they are considered to be similar to equity by the credit rating agencies. In addition, the Notes contain a call option feature and are callable in whole or in part by PSE on or after June 1, 2017. They are presented on the balance sheet as a separate line item in the redeemable securities and long-term debt.
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 and support the Company’s energy hedging activities.
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 September 30, 2007, 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 September 30, 2007, there was $7.4 million outstanding under four letters of credit, $90.0 million in loans outstanding under this agreement and $162.0 million commercial paper outstanding, effectively reducing the available borrowing capacity under the two credit agreements to $590.6 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 $126.0 million in loans that were secured by accounts receivable pledged at September 30, 2007. The remaining borrowing base of eligible receivables at September 30, 2007 was $74.0 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 September 30, 2007, the outstanding balance of the Note was $24.3 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 issued common stock under the Stock Purchase and Dividend Reinvestment Plan of $3.2 million (140,079 shares) and $9.7 million (395,970 shares) for the three and nine months ended September 30, 2007, respectively, compared to $3.3 million (150,295 shares) and $10.2 million (481,930 shares) for the three and nine months ended September 30, 2006, respectively.
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
Electric Regulation and Rates
Integrated Resource Plan. PSE filed its IRP on May 31, 2007 with the Washington Commission. The plan supports a strategy of diverse acquisitions to cost-effectively meet growing demand for energy and reduce carbon emissions. According to the IRP, PSE can secure additional power supplies through heightened energy-efficiency efforts and expanded wind-power generation. PSE believes that a cost-effective and environmentally responsible way to source generation will likely include additional natural gas-fired resources. PSE’s analysis targets a need to acquire 1,600 aMW of additional power supply in the next decade and 2,600 aMW by 2025.
Mandatory Electric Reliability Standards. On March 16, 2007, FERC issued Order 693, “Mandatory Reliability Standards for the Bulk-Power System,” which imposes penalties of up to $1.0 million per day per violation for failure to comply with new electric reliability standards. FERC approved 83 reliability standards developed by the North American Electric Reliability Corporation (NERC). The 83 standards comprise 586 requirements and sub-requirements that PSE must comply with. On June 18, 2007, the standards became mandatory and enforceable under federal law. PSE expects that the existing standards will often change as a result of modifications, guidance and clarification following industry implementation and ongoing audits and enforcement.
Per NERC and Western Electricity Coordinating Council (WECC) guidelines, users, owners and operators of the bulk power system that self-report non-compliance with any of the NERC standards and that submit mitigation plans to address the non-compliance will not be subject to sanctions if the mitigation plans were submitted on or before June 18, 2007 and approved by WECC. In June 2007, PSE submitted self reports and mitigation plans to WECC for review and approval. Neither the outcome of this submission nor the financial impact to PSE of complying with Order 693, if any, can be predicted at this time. PSE’s compliance with these standards will be audited at least every three years. The first such audit will be conducted during the fourth quarter 2007.
Power Cost Only Rate Case. On March 20, 2007, PSE submitted a PCORC filing to request approval of an updated power cost baseline rate beginning September 2007. The PCORC filing also requested recovery of Goldendale ownership and operating costs through retail electric rates. The requested electric rate increase was $64.7 million or 3.7% annually. On May 23, 2007, PSE filed updated power costs due to changes in market conditions of natural gas and other costs which resulted in a revised proposed increase of $77.8 million or 4.4% annually. On July 5, 2007, a settlement agreement in this PCORC signed by PSE and other parties to the proceeding was filed with the Washington Commission. The terms of the settlement agreement include an increase in electric rates and a finding that Goldendale ownership and operating costs are agreed upon as prudent, thus allowing for recovery of the costs through electric retail rates. On August 2, 2007, the Washington Commission approved and adopted the settlement agreement which provides for an electric rate increase of $64.7 million or 3.7% effective September 1, 2007.
In accordance with the August 2, 2007 Washington Commission order approving the PCORC settlement, PSE and other parties have agreed to conduct a collaborate stakeholder review of the PCORC process to consider the scope and timing of the PCORC mechanism and whether the mechanism should continue. The collaborative review will include but is not limited to: 1) the number of PCORCs that a company will be allowed to file in any given year; 2) the number and timing of updates that a company my submit in the PCORC process; 3) the items directly associated with power costs that may be included and considered in a PCORC filing; and 4) whether the number and timing of updates may vary depending on if other parties can easily verify. Any agreements reached by the parties in the collaborative will be presented to the Washington Commission for approval during PSE’s next general rate case and any issues on which agreement has not been reached may be raised in the same general rate case.
Storm Accounting Mechanism. PSE’s storm accounting, which allows deferral of certain storm damage costs, is subject to review by the Washington Commission at the end of the current three year period, which is December 31, 2007. During the fourth quarter 2007, PSE intends to seek approval from the Washington Commission to continue its storm deferral accounting treatment at current levels beyond December 31, 2007.
Accounting Petition. 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 to accrue monthly carrying charges on the deferred balance from June 7, 2007 until the deferral is recovered from customers or from BPA. As of September 30, 2007, PSE has a regulatory asset recorded for the benefit provided to customers and related carrying charges of $34.8 million.
Electric General Rate Case. On January 5, 2007, the Washington Commission issued its order in PSE’s electric general rate case filed in February 2006, approving a general rate decrease for electric customers of $22.8 million or 1.3% annually. The rates for electric customers were effective beginning January 13, 2007. In its order, the Washington Commission approved a weighted cost of capital of 8.4%, or 7.06% after-tax, and a capital structure that included 44.0% common equity with a return on equity of 10.4%. The Washington Commission had earlier approved (on June 28, 2006) a PCORC increase of $96.1 million annually effective July 1, 2006.
Production Tax Credit. On October 30, 2006, PSE revised its PTC electric tariff to increase the revenue credit to customers from $13.1 million to $28.8 million, effective January 1, 2007. The credit is based on expected wind generation and reflects the true-up of prior years’ credits provided to customers versus credits for actual wind generation taken for federal income taxes and the addition of Wild Horse to the wind portfolio. PSE will be revising its tariff effective January 1, 2008 based on actual PTC results for 2007 and project 2008 PTCs based on a filing to be made in the fourth quarter 2007.
PCA Mechanism. On June 20, 2002, the Washington Commission approved a PCA mechanism that triggers if PSE’s costs to provide customers’ electricity falls outside certain bands established in an electric rate case. The cumulative maximum pre-tax earnings exposure due to power cost variations over the four-year period ending June 30, 2006 was limited to $40.0 million plus 1% of the excess. On January 5, 2007, the Washington Commission approved the PCA mechanism for continuation under the same annual graduated scale without a cumulative cap for excess power costs. All significant variable power supply cost variables (hydroelectric and wind generation, market price for purchased power and surplus power, natural gas and coal fuel price, generation unit forced outage risk and transmission cost) are included in the PCA mechanism. The PCA mechanism apportions increases or decreases in power costs, on a calendar year basis, between PSE and its customers on a graduated scale:
Annual Power Cost Variability | Customers’ Share | Company’s Share1 |
| +/- $20 million | 0% | 100% |
| +/- $20 - $40 million | 50% | 50% |
| +/- $40 - $120 million | 90% | 10% |
| +/- $120 million | 95% | 5% |
_________________
1 | Over the four-year period July 1, 2002 through June 30, 2006, the Company’s share of pre-tax power cost variations was capped at a cumulative $40 million plus 1% of the excess. Power cost variations after June 30, 2006 are apportioned on an annual basis, on the graduated scale without a cumulative cap. |
Gas Regulation and Rates
Purchased Gas Adjustment Mechanism. On September 26, 2007, the Washington Commission approved PSE’s requested revisions to its PGA tariffs resulting in a rate decrease for gas customers of $148.1 million or 13.0% annually effective October 1, 2007. The rate decrease was the result of lower costs of natural gas in the forward market and a refund of the accumulated PGA payable balance over a 12-month period beginning October 1, 2007. The PGA rate change will decrease PSE’s revenue but will not impact the Company’s net income as the decreased revenue will be offset by decreased purchased gas costs and decreased revenue sensitive taxes.
Gas General Rate Case. On January 5, 2007, the Washington Commission issued its order in PSE’s gas general rate case, granting a rate increase for gas customers of $29.5 million or 2.8% annually, effective January 13, 2007. In its order the Washington Commission approved the same weighted cost of capital of 8.4%, or 7.06% after-tax and a capital structure that included 44.0% common equity with a return on equity of 10.4%, consistent with the Company’s electric operations.
Proceedings Relating to the Western Power Market
Puget Energy’s and PSE’s Report on Form 10-K for the year ended December 31, 2006 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 this 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.
CPUC Decision. Proceedings, including filings of requests for rehearing or further review, before the Ninth Circuit and/or FERC, have been stayed upon the Court’s own motion until November 16, 2007 to allow for possible settlement discussions to proceed.
Lockyer Case. On June 18, 2007, the U.S. Supreme Court denied the petition for a writ of certiorari that PSE and other energy sellers had submitted. As such, this matter will be remanded to FERC for further proceedings, but not before November 16, 2007, when the stay of the mandate back to FERC expires.
Pacific Northwest Refund 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. The court remanded the matter to FERC for further proceedings but subsequently issued an order staying further deadlines, including the remand, to November 16, 2007 to allow parties to engage in court-sponsored mediation. PSE intends to vigorously defend its position in this proceeding, but it is unable to predict the outcome of this matter.
Colstrip Matters
Colstrip Matters. In May 2003, approximately 50 plaintiffs brought an action against the owners of Colstrip which has since been amended to add additional claims. The lawsuit alleges that certain domestic water wells, groundwater and the Colstrip water supply pond were contaminated by seepage from a Colstrip Units 1 & 2 effluent holding pond, that seepage from Colstrip Units 1 & 2 have decreased property values and that seepage from the Colstrip water supply pond caused structural damage to buildings and toxic mold. Discovery is ongoing. The trial date has been postponed until May 21, 2008.
On March 29, 2007, a second complaint related to pond seepage was filed on behalf of two ranch owners alleging damage due to the Colstrip Units 3 & 4 effluent holding pond.
On June 15, 2005, the U.S. Environmental Protection Agency (EPA) issued the Clean Air Visibility Rule to address regional haze or regionally-impaired visibility caused by multiple sources over a wide area. The rule defines Best Available Retrofit Technology (BART) requirements for electric generating units, including presumptive limits for sulfur dioxide, particulate matter and nitrogen oxide controls for large units. In February 2007, Colstrip was notified by EPA that Colstrip Units 1 & 2 were determined to be subject to the BART requirements. PSE submitted a BART engineering analysis for Colstrip Units 1 & 2 in August 2007. PSE cannot yet determine the need for or costs of additional controls to comply with this rule, though any such costs could be significant and would most likely be capitalized to plant.
Sumas Cogeneration Company Contract
Sumas Cogeneration Company, L.P. (Sumas), owner of a 135 MW gas-fired co-generation facility in the state of Washington and the counterparty to a power purchase agreement with PSE, delivered a letter to PSE on May 7, 2007, stating that it had sold its dedicated 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 and Sumas have initiated discussion relating to Sumas’ actions under the contract, but PSE cannot yet determine what may result from such discussions.
Washington State Supreme Court Ruling
In a recent decision, Washington State Supreme Court ruled that certain job reporting practices involving the use of company vehicles are compensable time under Washington State’s wage and hour laws. One union representing a portion of PSE's workforce claims its members should now be compensated for PSE job site reporting practices as a result of this decision. The extent of the claims and financial impact on PSE currently is unknown.
New Accounting Pronouncements
In September 2006, Financial Accounting Standards Board (FASB) issued SFAS No, 157, “Fair Value Measurements.” SFAS No. 157 establishes a common definition for fair value to be applied to GAAP, establishes a framework for measuring fair value, and expands disclosure about such fair value measurements. SFAS No. 157 is effective for fiscal years beginning after November 15, 2007 which will be the calendar year beginning January 1, 2008 for the Company. The Company is currently assessing the impact of SFAS No. 157 on its financial statements.
In July 2006, FASB issued Interpretation No. 48 (FIN 48), “Accounting for Uncertainty in Income Taxes, an Interpretation of FASB Statement No. 109,” which clarifies the accounting for uncertainty in income taxes recognized in the financial statements in accordance with FASB Statement No. 109, “Accounting for Income Taxes.” FIN 48 provides guidance on recognition threshold and measurement attributed to a tax position taken or expected to be taken in a tax return. The tax positions should only be recognized when it is more likely than not, based on technical merits, that the position will be sustained upon examination by the taxing authority. FIN 48 was effective for the Company as of January 1, 2007. The Company has performed a review of all open tax years (2001 through 2007) and identified one tax position that must be reported under the provisions of FIN 48. The Company has determined that the proper amount of interest to accrue under FIN 48 is $5.4 million as of September 30, 2007. See discussion at Note 6, “Income Taxes.”
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 gas and electric portfolios. It is not engaged in the business of assuming risk for the purpose of speculative trading. The Company hedges open gas and electric positions to reduce both portfolio risk and volatility risk in prices. The exposure position is determined by using a probabilistic risk system that models 100 scenarios of how the Company’s 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; |
| · | prudently manage energy portfolio risks 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 September 30, 2007 and December 31, 2006:
Electric Derivatives | ||||||||
(Dollars in Millions) | September 30, 2007 | December 31, 2006 | ||||||
| Short-term asset | $ | 10.1 | $ | 10.1 | ||||
| Long-term asset | -- | 6.8 | ||||||
| Total assets | $ | 10.1 | $ | 16.9 | ||||
| Short-term liability | $ | 17.1 | $ | 9.0 | ||||
| Long-term liability | 8.7 | 0.4 | ||||||
| Total liabilities | $ | 25.8 | $ | 9.4 | ||||
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 PCA mechanism.
At September 30, 2007, the Company had net unrealized day one loss deferral of $9.6 million primarily related to a three year locational power exchange contract which was modeled and therefore the day one loss was deferred under Emerging Issues Task Force (EITF) 02-3, “Issues Involved in Accounting for Derivative Contracts Held for Trading Purposes and Involved in Energy Trading and Risk Management Activities.” The deferred loss is being amortized over the term of the contract through December 31, 2010. Any future changes in the mark-to-market value will be recorded through the income statement. The contract throughout its term has economic benefit to the Company. The locational exchange will help ease electric transmission congestion across the Cascade Mountains during 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 same quantities of power at the Mid-Columbia trading hub location.
The following tables present the impact of changes in the market value of derivative instruments not meeting NPNS or cash flow hedge criteria to the Company’s earnings during the three and nine months ended September 30, 2007 and September 30, 2006:
(Dollars in Millions) Three Months Ended September 30, | 2007 | 2006 | Change |
| Unrealized (gain) loss on derivative instruments | $ 5.3 | $ (0.6) | $ 5.9 |
(Dollars in Millions) Nine Months Ended September 30, | 2007 | 2006 | Change |
| Unrealized (gain) loss on derivative instruments | $ 1.0 | $ 0.2 | $ 0.8 |
During the three and nine months ended September 30. 2007, the Company recorded a decrease in earnings for the change in the market value of derivative instruments not meeting NPNS or cash flow hedge criteria of $5.3 million and $1.0 million, respectively. The increase in expense is primarily due to the change in the mark-to-market valuation of a physically delivered gas supply contract for electric generation that did not meet NPNS or cash flow hedge criteria and due to the ineffective portion of two long-term power purchase agreements designated as cash flow hedges. During the three months ended September 30, 2007, in order to replace the energy that was lost due to the early termination of a contract by the counterparty in the second quarter 2007, the Company entered into two long-term power purchase contracts that met cash flow hedge criteria. The ineffective portion relates to periods in which the Company has enough projected energy resources to meet the expected customer usage without the two contracts. In addition, a decline in the unrealized gain on a physical gas supply contract recorded in the second quarter 2007 contributed to the unrealized loss in the three months ended September 30, 2007 due to the lower market value of natural gas and settlement of contracts during the third quarter 2007. During the three and nine months ended September 30, 2006, the Company recorded an increase in earnings for the change in the market value of derivative instruments not meeting NPNS or cash flow hedge criteria of $0.6 million and a decrease in earnings of $0.2 million, respectively.
The amount of net unrealized gain (loss), net of tax, related to the Company’s energy-related cash flow hedges under SFAS No. 133 consisted of the following at September 30, 2007 and December 31, 2006:
(Dollars in Millions, net of tax) | September 30, 2007 | December 31, 2006 |
| Other comprehensive income – unrealized (gain) loss | $ 9.5 | $ (4.9) |
The following table presents derivative hedges of natural gas contracts to serve natural gas customers at September 30, 2007 and December 31, 2006:
| Gas Derivatives | ||||||||
| (Dollars in Millions) | September 30, 2007 | December 31, 2006 | ||||||
| Short-term asset | $ | 2.5 | $ | 6.7 | ||||
| Long-term asset | -- | 0.1 | ||||||
| Total assets | $ | 2.5 | $ | 6.8 | ||||
| Short-term liability | $ | 39.6 | $ | 61.6 | ||||
| Long-term liability | 0.4 | -- | ||||||
| Total liabilities | $ | 40.0 | $ | 61.6 | ||||
Due to the PGA mechanism, mark-to-market adjustments relating to the natural gas business have been reclassified to a deferred account in accordance with SFAS No. 71. The PGA mechanism passes increases and decreases in the cost of natural gas supply to customers. As the gains and losses on the hedges are realized in future periods, they will be recorded as 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 and comprehensive income by $24.1 million after-tax and would decrease the fair value of those contracts marked-to-market in earnings by $1.0 million after-tax.
Credit Risk
The Company is exposed to credit risk primarily through buying and selling electricity and gas to serve its customers. Credit risk is the potential loss resulting from 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.
It is possible that extreme volatility in energy commodity prices could cause the Company to have sub-optimal 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 September 30, 2007, approximately 99% of the Company’s energy portfolio was rated investment grade or higher by Standard & Poor's Ratings Services and/or Moody's Investor Services, Inc.
Interest Rate Risk
The Company believes its interest rate risk primarily relates to the use of short-term debt instruments, variable-rate 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 September 30, 2007 was a net loss of $8.3 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.
PugetEnergy
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 September 30, 2007, 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 period ended September 30, 2007 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 September 30, 2007, 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 period ended September 30, 2007, 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 September 30, 2007. 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.
The following risk factor is an update to previously disclosed risk factors by Puget Energy and PSE in their Form 10-K, Item 1A for the period ending December 31, 2006 and the Company’s Quarterly Report on Form 10-Q for the quarter ended June 30, 2007.
There are risks if we do not complete the proposed merger with the Consortium.
If the merger we announced on October 26, 2007 is not completed for any reason, Puget Energy will remain an independent public company and the common stock will continue to be listed and traded on the New York Stock Exchange. While we expect that management will operate the business in a manner similar to that in which it is being operated today, if the merger is not completed, Puget Energy may suffer negative financial ramifications, including the following:
| · | The current market price of Puget Energy’s common stock may reflect a market assumption that the merger will occur, and a failure to complete the merger could result in a negative perception by investors in Puget Energy generally and could cause a decline in the market price of Puget Energy’s common stock. This could affect Puget Energy’s ability to access the equity markets to fund PSE’s construction program and working capital needs. |
| · | Puget Energy might be required to pay an up to $40 million termination fee, and up to $10 million of expenses, to the Consortium, which could adversely impact liquidity. |
The Company’s business may be adversely affected if the closing of the proposed stock purchase transaction with certain members of the Consortium does not occur or is delayed.
The stock purchase transaction we announced on October 26, 2007, pursuant to which certain members of the Consortium of long-term infrastructure investors led by Macquarie Infrastructure Partners, The Canada Pension Plan Investment Board and British Columbia Investment Management Corporation will severally purchase shares of Puget Energy’s common stock is subject to customary closing conditions, including receipt of all applicable regulatory approvals. If this transaction is not completed or if the closing is significantly delayed for any reason, the Company’s liquidity and capital resources may be adversely effected. In that case, the Company may be required to obtain alternative financing, which may not be available on acceptable terms, if at all. Moreover, the Company’s ability to secure any such alternative financing could be limited by covenants in the merger agreement with the Consortium that restrict the Company's ability to issue equity or incur indebtedness without first obtaining the consent of the Consortium. The Company’s inability to complete an equity financing may also adversely impact the equity ratio that is likely to be requested in Puget Sound Energy's general rate case filing.
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: November 1, 2007 | ||
| Chief accounting officer and officer duly authorized to sign this report on behalf of each registrant | ||
The following exhibits are filed herewith:
| 3(i).1 | Articles of Amendment of Puget Energy, Inc., as filed with the Washington Secretary of State on May 10, 2007. |
| 3(ii).1 | Amended and Restated Bylaws of Puget Energy effective May 4, 2007. |
| 12.1 | Statement setting forth computation of ratios of earnings to fixed charges (2002 through 2006 and 12 months ended September 30, 2007) for Puget Energy. |
| 12.2 | Statement setting forth computation of ratios of earnings to fixed charges (2002 through 2006 and 12 months ended September 30, 2007) 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. |