UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
FORM 10-K
| /X/ | ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 |
For the fiscal year ended December 31, 20062009
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, zip code telephone number | I.R.S. Employer Identification Number |
| 1-16305 | PUGET ENERGY, INC. A Washington Corporation 10885 NE 4thth Street, Suite 1200 Bellevue, Washington 98004-5591 (425) 454-6363 | 91-1969407 |
| 1-4393 | PUGET SOUND ENERGY, INC. A Washington Corporation 10885 NE 4thth Street, Suite 1200 Bellevue, Washington 98004-5591 (425) 454-6363 | 91-0374630 |
Securities registered pursuant to Section 12(b) of the Act: None
| | Title Of Each Class | Name Of Each Exchange
On Which Listed
|
Puget Energy, Inc.
| Common Stock, $0.01 par value | NYSE |
| | Preferred Share Purchase Rights | NYSE | |
| | | |
| | | |
Securities registered pursuant to Section 12(g) of the Act:
None
| | Title Of Each Class | |
Puget Sound Energy, Inc.
| Preferred Stock (cumulative, $100 par value) | |
| | | | |
| | | |
Puget Sound Energy, Inc. meets the conditions set forth in General Instructions I (1)(a) and (b) of Form 10-K and is therefore filing this Form 10-K with the reduced disclosure format.
Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act.
| | Puget Energy, Inc. | Yes | /X/ / | No | / /X/ | | Puget Sound Energy, Inc. | Yes | /X/ | No | / / |
Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Act.
| | Puget Energy, Inc. | Yes | / /X/ | No | /X/ / | | Puget Sound Energy, Inc. | Yes | / / | No | /X/ |
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 | / / | No | /X/ | | Puget Sound Energy, Inc. | Yes | /X/ | No | / / |
Indicate by check mark whether the registrants have submitted electronically and posted on its corporate websites, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T during the preceding 12 months (or for such shorter period that the registrant was required to post such files).
| Puget Energy, Inc. | Yes | / / | No | / / | | Puget Sound Energy, Inc. | Yes | /X/ / | No | / / |
Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K is not contained herein, and will not be contained, to the best of registrant’s knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K. / //X/
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 | /X/ | Smaller reporting company | / / |
| Puget Sound Energy, Inc. | Large accelerated filer | / / | Accelerated filer | / / | Non-accelerated filer | /X/ | Smaller reporting company | / / |
Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Act).
| | Puget Energy, Inc. | Yes | / / | No | /X/ | | Puget Sound Energy, Inc. | Yes | / / | No | /X/ |
The aggregate market valueAs of February 6, 2009, all of the outstanding shares of voting stock held by non-affiliates of Puget Energy, Inc., computed are held by reference to the price at which the common stock was last sold, as of the last business dayPuget Equico LLC, an indirect wholly owned subsidiary of Puget Energy’s most recently completed second fiscal quarter was approximately $2,411,121,000. The number of shares of Puget Energy, Inc.’s common stock outstanding at February 21, 2007 was 116,723,205 shares.Holdings LLC.
All of the outstanding shares of voting stock of Puget Sound Energy, Inc. are held by Puget Energy, Inc.
Documents Incorporated by Reference
Portions of the Puget Energy, Inc. proxy statement for its 2007 Annual Meeting of Shareholders to be filed with the Commission pursuant to Regulation 14A not later than 120 days after December 31, 2006 are incorporated by reference in Part III hereof.
This Annual Report on Form 10-K is a combined report being filed separately by two different registrants:by: Puget Energy, Inc. and Puget Sound Energy, Inc. Puget Sound Energy, Inc. makes no representation as to the information contained in this report relating to Puget Energy, Inc. and the subsidiaries of Puget Energy, Inc. other than Puget Sound Energy, Inc. and its subsidiaries.
INDEX
| AFUDC | Allowance for Funds Used During Construction |
| aMW | Average Megawatt |
| ASC | Accounting Standards Codification |
| ASU | Accounting Standards Update |
| BPA | Bonneville Power Administration |
CAISOColstrip | California Independent System OperatorColstrip, Montana coal-fired steam electric generation facility |
| Consortium | Infrastructure investors including Macquarie Infrastructure Partners I, Macquarie Infrastructure Partners II, Macquarie Capital Group Limited, Macquarie-FSS Infrastructure Trust, the Canada Pension Plan Investment Board, the British Columbia Investment Management Corporation and the Alberta Investment Management Corporation |
| Dth | Dekatherm (one Dth is equal to one MMBtu) |
EcologyEBITDA | Washington State Department of EcologyEarnings Before Interest, Tax, Depreciation and Amortization |
| EPA | United States Environmental Protection Agency |
| FASB | Financial Accounting Standards Board |
| FERC | Federal Energy Regulatory Commission |
FINGAAP | FinancialGenerally Accepted Accounting Standards Board InterpretationPrinciples |
FPAGHG | Federal Power ActGreenhouse gases |
| Goldendale | Goldendale electric generating facility |
| IRP | Integrated Resource Plan |
InfrastruXIRS | InfrastruX Group, Inc.Internal Revenue Service |
| kWh | Kilowatt Hour (one kWh equals one thousand watt hours) |
| LIBOR | London Interbank Offered Rate |
| LNG | Liquefied Natural Gas |
| LTI Plan | Long-Term Incentive Plan |
| Mint Farm | Mint Farm Electric Generation Facility |
| MMBtu | One Million British Thermal Units |
MMSMoody’s | Minerals Management Service of the United StatesMoody’s Investor Services |
| MW | Megawatt (one MW equals one thousand kW) |
| MWh | Megawatt Hour (one MWh equals one thousand kWh) |
| NERC | North American Electric Reliability Corporation |
| Ninth Circuit | United States Court of Appeals for the Ninth Circuit |
| NOAA | National Oceanic and Atmospheric Administration |
| NPNS | Normal Purchase Normal Sale |
| NWP | Northwest Pipeline GP |
| NYSE | New York Stock Exchange |
| OCI | Other Comprehensive Income |
| PCA | Power Cost Adjustment |
| PCORC | Power Cost Only Rate Case |
| PGA | Purchased Gas Adjustment |
PG&E | Pacific Gas & Electric Company |
| PSE | Puget Sound Energy, Inc. |
| PTC | Production Tax Credit |
| PUDs | Washington Public Utility Districts |
| Puget Energy | Puget Energy, Inc. |
| Puget Equico | Puget Equico LLC |
| Puget Holdings | Puget Holdings LLC |
| PURPA | Public Utility Regulatory Policies Act |
RFPREP | Request for ProposalResidential Exchange Program |
RTOS&P | Regional Transmission OrganizationStandard & Poor’s |
| SEC | United States Securities and Exchange Commission |
SFAS | Statement of Financial Accounting Standards |
| Tenaska | Tenaska Power Fund, L.P. |
| VIE | Variable Interest Entity |
| Washington Commission | Washington Utilities and Transportation Commission |
WECOWild Horse | Western Energy CompanyWild Horse wind project |
Puget Energy, Inc. (Puget Energy) and Puget Sound Energy, Inc. (PSE) are including the following cautionary statements in this Form 10-K 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; butparties. 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, financings, 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, maintenance and construction of natural gas and electric distribution and transmission facilities, (gas and electric), licensing of hydroelectric operations and natural gas storage facilities, recovery of other capital investments, recovery of power and natural gas costs, recovery of regulatory assets and present or prospective wholesale and retail competition; |
| · | Failure of PSE to comply with FERC or Washington Commission standards and/or rules, which could result in penalties based on the discretion of either commission; |
| · | Findings of noncompliance with electric reliability standards developed by the North American Electric Reliability Corporation (NERC) or the Western Electricity Coordinating Council for users, owners and operators of the power system, which could result in penalties; |
| · | Changes in, adoption of and compliance with laws and regulations, including decisions and policies concerning the environment, climate change, greenhouse gas or other emissions or byproducts of electric generation (including coal ash or other substances), natural resources, and fish and wildlife (including the Endangered Species Act); as well as the risk of litigation arising from such matters, whether involving public or private claimants or regulatory investigative or enforcement measures; |
| · | The ability to recover costs arising from changes in enacted federal, state or local tax laws through revenue in a timely manner; |
| · | NaturalChanges in tax law, related regulations or differing interpretation or enforcement of applicable law by the Internal Revenue Service (IRS) or other taxing jurisdiction; |
| · | Inability to realize deferred tax assets and use production tax credits due to insufficient future taxable income; |
· | Accidents or natural disasters, such as hurricanes, windstorms, earthquakes, floods, fires and landslides, which can interrupt service and lead to lost revenues, cause temporary supply disruptions and/or price spikes in the cost of fuel and raw materials;materials and impose extraordinary costs; |
| · | Commodity price risks associated with procuring natural gas and power in wholesale markets that impact customer loads;markets; |
| · | Wholesale market disruption, which may result in a deterioration of market liquidity, increase the risk of counterparty default, affect the regulatory and legislative process in unpredictable ways, negatively affect wholesale energy prices and/or impede PSE’s ability to manage its energy portfolio risks and procure energy supply, affect the availability and access to capital and credit markets and/or impact delivery of energy to PSE from its suppliers; |
| · | Financial difficulties of other energy companies and related events, which may affect the regulatory and legislative process in unpredictable ways, and also adversely affect the availability of and access to capital and credit markets and/or impact delivery of energy to PSE from itits suppliers; |
| · | The effect of wholesale market structures (including, but not limited to, regional market designs or transmission organizations) or other related federal initiatives; |
| · | PSE electric or natural gas distribution system failure, which may impact PSE’s ability to deliver energy supply to its customers; |
| · | Changes in climate or weather conditions in the Pacific Northwest, which could have effects on customer usage and PSE’s revenues, thus impacting net income;revenues; |
| · | Weather,Regional or national weather, which can have a potentially serious impact on PSE’s ability to procure adequate supplies of natural gas, fuel or purchased power to serve its customers and on the cost of procuring such supplies; |
| · | Variable hydrohydrologic conditions, which can impact streamflow and PSE’s ability to generate electricity from hydroelectric facilities; |
| · | PlantElectric plant generation and transmission system 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 generation resource; |
| · | The ability of a natural gas or electric plant to operate as intended; |
| · | The ability to renew contracts for electric and natural gas supply and the price of renewal; |
| · | Blackouts or large curtailments of transmission systems, whether PSE’s or others’, which can affect PSE’s ability to deliver power or natural gas to its customers;customers and generating facilities; |
| · | The ability to restart generation following a regional transmission disruption; |
| · | FailureThe failure of the interstate natural gas pipeline delivering to PSE’s system, which may impact PSE’s ability to adequately deliver natural gas supply or electric power to its customers; |
| · | The amount of collection, if any, of PSE’s receivables from the California Independent System Operator (CAISO) and other parties and the amount of refunds found to be due from PSE to the CAISO or other parties; |
| ·
| Industrial, commercial and residential growth and demographic patterns in the service territories of PSE; |
| · | General economic conditions in the Pacific Northwest, which mightmay impact customer consumption or affect PSE’s accounts receivable; |
| · | The loss of significant customers, or changes in the business of significant customers or the condemnation of PSE’s facilities, which may result in changes in demand for PSE’s services; |
| · | The failure of information systems or the failure to secure information system data, which may impact the operations and cost of PSE’s customer service, generation, distribution and transmission; |
· | The impact of acts of God, terrorism, flu pandemic or similar significant events; |
| · | Capital market conditions, including changes in the availability of capital orand 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 adequate 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; and |
| ·
| The ability to maintain effective internal controls over financial reporting.reporting and operational processes; |
| · | Changes in Puget Energy’s or PSE’s credit ratings, which may have an adverse impact on the availability and cost of capital for PSE or Puget Energy generally, or the failure to comply with the covenants in Puget Energy’s or PSE’s credit facilities, which would limit the Companies’ ability to utilize such facilities for capital; and |
| · | Deteriorating values of the equity, fixed income and other markets which could significantly impact the value of investments of PSE’s retirement plan, post-retirement medical benefit plan trusts and the funding of obligations thereunder. |
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 the quarterly reports on Form 10-Q and current reports on Form 8-K, as well as Item 1A-“Risk Factors” on this Form 10-K.
PART I
Puget Energy, Inc. (Puget Energy) is an energy services holding company incorporated in the state of Washington in 1999. All of its operations are conducted through its subsidiary, Puget Sound Energy, Inc. (PSE), a utility company. Puget Energy has no significant assets other than the stock of PSE.
On May 7, 2006,February 6, 2009, Puget Holdings LLC (Puget Holdings) completed its merger with Puget Energy. Puget Holdings is a consortium of long-term infrastructure investors including Macquarie Infrastructure Partners I, Macquarie Infrastructure Partners II, Macquarie Capital Group Limited, Macquarie-FSS Infrastructure Trust, the Canada Pension Plan Investment Board, the British Columbia Investment Management Corporation and the Alberta Investment Management Corporation (collectively, the Consortium). As a result of the merger, Puget Energy sold its 90.9% interest in InfrastruX Group, Inc. (InfrastruX) and thereforeis the financial position and resultsdirect wholly owned subsidiary of operations for InfrastruX are presented as discontinued operations.Puget Equico LLC (Puget Equico), which is an indirect wholly owned subsidiary of Puget Holdings. Puget Energy and PSE are collectively referred to herein as “the Company.” The following table provides the percentages of Puget Energy’s consolidated continuing operating revenues and net income generated and assets held by the operating segments:
Segment | Percent of Revenue | Percent of Net Income | Percent of Assets |
| | 2006 | 2005 | 2004 | 2006 | 2005 | 2004 | 2006 | 2005 | 2004 |
| Puget Sound Energy | 99.7% | 99.7% | 99.7% | 103.3% | 91.7% | 224.2% | 99.0% | 94.8% | 94.2% |
InfrastruX1,2 | 0% | 0% | 0% | 0% | 6.1% | (127.8)% | 0% | 4.2% | 4.6% |
Other3 | 0.3% | 0.3% | 0.3% | (3.3)% | 2.2% | 3.6% | 1.0% | 1.0% | 1.2% |
_______________
1
| InfrastruX is presented on a discontinued operations basis beginning in 2005 and therefore does not present operating revenue. Operating revenue in 2004 has been reclassified as discontinued operations.
|
2
| In 2004, Puget Energy recorded Goodwill impairment of $76.6 million after-tax which resulted in a loss at InfrastruX.
|
3
| Includes subsidiaries of PSE and Puget Energy holding company operations. 2006 includes the impact of the establishment and funding of a charitable foundation.
|
Puget EnergyCorporate Strategy
Puget Energy is the direct parent company of PSE, the oldest and largest electric and natural gas utility headquartered in the state of Washington, primarily engaged in the business of electric transmission, distribution, generation and natural gas transmission and distribution. Puget Energy’s business strategy is to generate stable earnings and cash flow by offering reliable electric and natural gas service in a cost effectivecost-effective manner through PSE.
Puget Sound Energy, Inc.
PSE is a public utility incorporated in the state of Washington in 1960. PSE furnishes electric and natural gas service in a territory covering approximately 6,000 square miles, principally in the Puget Sound region of the state of Washington.
At December 31, 2006,2009, PSE had approximately 1,039,4001,075,400 electric customers, consisting of 918,200949,900 residential, 114,600118,400 commercial, 3,8003,700 industrial and 2,8003,400 other customers;customers, and approximately 713,000748,900 natural gas customers, consisting of 658,100691,900 residential, 52,10054,300 commercial, 2,7002,500 industrial and 100200 transportation customers. At December 31, 2006,2009, approximately 342,200375,000 customers purchased both electricity and natural gas from PSE. In 2006,2009, PSE added approximately 21,3006,000 electric customers and 19,4005,000 natural gas customers, representing annualized customer growth rates of 2.1%0.6% and 2.8%0.7%, respectively. During 2006,2009, PSE’s billed retail and transportation revenues from electric utility operations were derived 49.3%52.7% from residential customers, 42.8%41.4% from commercial customers, 6.3%4.9% from industrial customers and 1.6%1.0% from other customers. PSE’s retail revenues from natural gas utility operations were derived 63.2%66.0% from residential customers, 30.4%29.6% from commercial customers, 5.2%3.3% from industrial customers and 1.2%1.1% from transportation customers in 2006.2009. During this period, the largest customer accounted for approximately 1.2%1.5% of PSE’s operating revenues.
PSE is affected by various seasonal weather patterns and therefore, utility revenues and associated expenses are not generated evenly during the year. Energy usage varies seasonally and monthly, primarily as a result of weather conditions. PSE experiences its highest retail energy sales in the first and fourth quarters of the year. Sales of electricity to wholesale customers also vary by quarter and year depending principally upon fundamental market factors and weather conditions. PSE has a purchased gas adjustmentPurchased Gas Adjustment (PGA) mechanism in retail natural gas rates to recover variations in natural gas supply and transportation costs. PSE also has a power cost adjustmentPower Cost Adjustment (PCA) mechanism in retail electric rates to recover variations in electricity costs on a shared basis with customers.
In the five-year period ended December 31, 2006,2009, PSE’s gross electric utility plant additions were $1.5$3.1 billion and retirements were $300.6$342.2 million. In the same five-year period, PSE’s gross gas utility plant additions were $686.7$871.9 million and retirements were $92.1 million. In the same five-year period,$120.0 million and PSE’s gross common utility plant additions were $273.6$253.9 million and retirements were $50.3$127.1 million. Gross electric utility plant at December 31, 20062009 was approximately $5.3$7.0 billion, which consisted of 54.2%46.9% distribution, 31.6%33.8% generation, 6.2%5.7% transmission and 8.0%13.6% general plant and other. Gross gas utility plant at December 31, 20062009 was approximately $2.1$2.6 billion, which consisted of 93.0% distribution and 7.0% general plant and other. Gross common utility general and intangible plant at December 31, 20062009 was approximately $458.3$539.3 million.
InfrastruX Group, Inc.
InfrastruX, a non-regulated construction services business, was incorporated in the state of Washington in 2000. On May 7, 2006, Puget Energy sold its 90.9% interest in InfrastruX to an affiliate of Tenaska Power Fund, L.P. (Tenaska). Puget Energy accounted for InfrastruX as a discontinued operation.
Employees
At February 21, 2007,December 31, 2009, Puget Energy had no employees and PSE had approximately 2,4003,000 full-time employees. Approximately 1,1421,325 PSE employees are represented by the International Brotherhood of Electrical Workers Union (IBEW) orand the United Association of Plumbers and Pipefitters (UA). The current labor contracts with the IBEW and UA run through March 31, 2007 and September 30, 2010, respectively. The Company is currently in contract discussionsnegotiations with the IBEW.IBEW regarding the contract expiring on March 31, 2010 and will enter into negotiations with the UA later in 2010 for the contract expiring October 1, 2010.
Corporate Location
Puget Energy’s and PSE’s principal executive offices are located at 10885 NE 4thth Street, Suite 1200, Bellevue, Washington 98004 and the telephone number is (425) 454-6363.
Available Information
The Company’s reports on Form 10-K, quarterly reports on Form 10-Q, current reports on Form 8-K and amendments to those reports filed or furnished pursuant to Section 13(a) or 15(d) of the Securities Exchange Act of 1934 are available or may be accessed free of charge through the Investors section of the Company’s website at www.pugetenergy.com after the reports are electronically filed with, or furnished to, the United States Securities and Exchange Commission (SEC). Information may also be obtained via the SEC Internet website at www.sec.gov.
In addition, the following corporate governance materials of the Company are available in the Investors section of the Company’s website and a copy will be mailed upon request. Requests should be made to Puget Energy, Inc., Investor Services, P.O. Box 97034, PSE-08N, Bellevue, Washington 98009-9734.
| ·
| Corporate Governance Guidelines; |
| ·
| Corporate Ethics and Compliance Code; |
| ·
| Charters of Board Committees; and |
| ·
| Code of Ethics for the Company’s Chief Executive Officer and senior financial officers. |
If the Company waives any material provision of its Code of Ethics for its Chief Executive Officer (CEO) and senior financial officers or its Corporate Ethics and Compliance Code, or substantively changes the codes for any specific officer, the Company will disclose that waiver on its website within four business days.
New York Stock Exchange Certification
On May 24, 2006, the CEO of Puget Energy and PSE filed a Section 303A.12(a) CEO Certification with the New York Stock Exchange (NYSE). The CEO Certification attests that the CEO is not aware of any violations by the Company of the NYSE’s Corporate Governance Listing Standards.
PSE is subject to the regulatory authority of: (1) the Federal Energy Regulatory Commission (FERC) with respect to the transmission of electric energy, the resalesale of electric energy at wholesale, accounting and certain other matters; and (2) the Washington Utilities and Transportation Commission (Washington Commission) as to retail rates, accounting, the issuance of securities and certain other matters.
Federal Regulation
FERC Order No. 2000, issued on December 20, 1999, required all utilities subject to its jurisdiction that own, operate or control transmission facilities to either voluntarily form or participate in a Regional Transmission Organization (RTO) or Independent System Operator (ISO); or, alternatively, to describe its efforts to participate in an RTO/ISO or the obstacles to such participation. PSE had been an active participant in regional efforts to form an RTO/ISO in the Pacific Northwest since the issuance of Order No. 2000. PSE has continued to workalso must comply with BPA and other regional transmission owners to address the transmission related issues in the region via a new organization known as ColumbiaGrid.
The Energy Policy Act of 2005 (EPAct 2005) added a requirement for FERC to certify an Electric Reliability Organization (ERO) to develop mandatory and enforceable electric system reliability standards. FERC has certifiedstandards developed by the North American Electric Reliability Corporation (NERC) as, the ERO to develop theseElectric Reliability Organization certified by FERC, which standards subject to FERC review and approval. Once approved, the reliability standards will apply to PSE and will beare enforced by the ERO subject to FERC oversight. PSE expects the standards to become mandatoryWestern Electricity Coordinating Council in June 2007. Failure to comply with these reliability standards once they become mandatory could result in a financial penalty.PSE’s operating territory.
State Regulation
PSE’s retail electric service is fully regulated by the Washington Commission. PSE is not aware of any proposals or prospects for retail deregulation in the state of Washington.
PSE’s retail gas service is also regulated by the Washington Commission. Since 1986, PSE has been offering gas transportation as a separate service to industrial and commercial customers who choose to purchase their gas supply directly from producers and gas marketers. The shifting of customers between sales and transportation service does not materially impact utility margin, as PSE earns similar margins on transportation service and large-volume, interruptible gas sales.
Electric Regulation and Rates
Power Cost Adjustment Mechanism.Electric Rate Case. On June 20, 2002,May 8, 2009, PSE filed a general rate case with the Washington Commission which proposed an increase in electric rates of $148.1 million or 7.4% annually, effective April 2010. On February 19, 2010, PSE filed a brief, which lowered the requested electric rate increase to $110.3 million or 5.5% annually. This rate request includes an equity component of PSE’s capital structure of 48.0% and a requested rate of return on equity of 10.8%. A final order from the Washington Commission is expected in April 2010.
On October 8, 2008, the Washington Commission issued its order in PSE’s electric general rate case filed in December 2007, approving a general rate increase for electric customers of $130.2 million or 7.1% annually. The rate increase for electric customers was effective November 1, 2008. In its order, the Washington Commission approved a PCA mechanismweighted cost of capital of 8.25%, or 7.0% after-tax, and a capital structure that triggers if PSE’s costs to provide 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 1.0%included 46.0% common equity with a return on equity of the excess. In October 2005, the Washington Commission approved a shift to an annual PCA measurement period from January through December starting in 2007. 10.15%.
On January 5,August 2, 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 (hydroelectricPower Cost Only Rate Case (PCORC) settlement agreement 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 includedauthorized an increase in PSE’s electric rates of $64.7 million or an average increase of 3.7% annually, effective September 1, 2007. PSE’s investment in the PCA mechanism.Goldendale electric generating facility (Goldendale) acquired in February 2007 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.
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 | July-December 2006 Power Cost Variability1 | Customers’ Share | Company’s Share2 |
| +/- | $20 million | +/- | $10 million | 0 | % | 100 | % |
| +/- | $20 - $40 million | +/- | $10 - $20 million | 50 | % | 50 | % |
| +/- | $40 - $120 million | +/- | $20 - $60 million | 90 | % | 10 | % |
| +/- | $120 million | +/- | $60 million | 95 | % | 5 | % |
_____________
1
| In October 2005, the Washington Commission in its Power Cost Only Rate Case order allowed for a reduction to the power cost variability amounts to half the annual power cost variability for the period July 1, 2006 through December 31, 2006.
|
2
| Over the four-year period July 1, 2002 through June 30, 2006, the Company’s share of pre-tax power cost variations is capped at a cumulative $40.0 million plus 1.0% of the excess. Power cost variation after December 31, 2006 will be apportioned on a calendar year basis, without a cumulative cap.
|
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)
Gas Regulation and Rates
Gas Rate Case. On May 8, 2009, PSE filed a power cost onlygeneral rate case (PCORC) increase of $96.1 million annually effective July 1, 2006.
Power Cost Only Rate Case. A limited-scope proceeding called a PCORC was created in 2002 bywith the Washington Commission which proposed an increase in natural gas rates of $27.2 million or 2.2% annually, effective April 2010. On August 3, 2009, PSE filed an addendum to periodically reset power cost rates. The main objectivethe natural gas rate request which changed the rate increase to $30.4 million or 2.5%. On December 17, 2009, PSE filed rebuttal testimony, which lowered the requested natural gas rate increase to $28.4 million or 2.3% annually. This rate request includes a capital structure with an equity component of the PCORC proceeding is to provide for timely review48.0% and a requested rate of new resource acquisitions costs and inclusionreturn on equity of such costs in rates at the time the new resource goes into service. To achieve this objective,10.8%. A final order from the Washington Commission agreed to an expedited five-month PCORC decision timeline rather thanis expected in April 2010.
On October 8, 2008, the statutory 11-month timeline for aWashington Commission issued its order in PSE’s natural gas general rate case.
On October 20, 2005,case filed in December 2007, approving a natural gas rate increase of $49.2 million or 4.6% annually. In its order, the Washington Commission approved a PCORC filing that increased electric rates 3.7% or $55.6 million annually. Included in the increase is the recoveryweighted cost of capital of 8.25%, or 7.00% after-tax, and operating costsa capital structure that included 46.0% common equity with a return on equity of the Hopkins Ridge wind generating facility. The Hopkins Ridge wind generating facility was completed on November 27, 2005. As a wind generating facility, Hopkins Ridge is eligible for Federal Production Tax Credits (PTCs) that will ultimately offset some of the costs associated with generating power from Hopkins Ridge. The PTC is a tax credit provided by the federal government for generating electricity from certain renewable resources. The current amount of the tax credit is $0.019 per kilowatt hour (kWh) for wind generation and may be subject to inflation adjustments over time. The tax credit can be claimed for 10 years for a new wind project put into service prior to January 1, 2008. The use of the credit is restricted to offset only 25.0% of current taxes payable. Unused credits can be carried forward for up to 20 years. In the Washington Commission’s October 2005 order, a new tariff schedule was approved which provides for the pass through to ratepayers of all benefits of the PTCs of the Hopkins Ridge project. This mechanism (a PTC Tracker) will pass through to the customer the actual PTCs of the Hopkins Ridge project as they are generated. The PTC Tracker would not be subject to the sharing bands in the PCA. The credits passed through to the customer will be adjusted by the carrying costs of unused PTCs. Since the customer is receiving the benefit of the tax credits as they are generated and the Company does not receive a credit from the IRS until the tax credits are utilized, the Company is reimbursed its carrying costs for funds through this calculation.
Gas Regulation and Rates10.15%.
Gas General Rate Case.On January 5, 2007, the Washington Commission issued its order in PSE’s natural gas general rate case, granting an increase in natural gas rates of $29.5 million or 2.8% annually, effective January 13, 2007.annually. In its order, the Washington Commission approved the samea weighted cost of capital of 8.4%, or 7.06% after-tax, and capital structure that included 44.0% common equity with a return on equity of 10.4%, as allowed for the Company’s electric operations..
Purchased Gas Adjustment. PSE has a purchased gas adjustment (PGA)PGA mechanism in retail natural gas rates to recover variations in natural gas supply and transportation costs. Variations in natural gas rates are passed through to customers,customers; therefore, PSE’s gas margin and net income areis not affected by such variations. On September 27, 2006, the Washington Commission approved a revision ofA change in PGA rates increases or decreases PSE’s PGA tariff schedule that went into effect on October 1, 2006. The tariff changes will increase gas revenue approximately $95.1 million, or 10.2%, on an annual basis. The rate increase authorized PSE to recover higher projected future gas and gas transportation costs, as well as to collect an accumulated deficit (receivable) balance in its PGA balancing account over a 24-month period (beginning October 1, 2006). The PGA rate change will increase PSE’s gas revenue, but willdoes not impact the Company’s net income as the increased or decreased revenue will beis offset by increased or decreased purchased gas and gas transportation costs.
The following PGA rate adjustments were approved by the Washington Commission in relation to the PGA mechanism during 2006, 20052009, 2008 and 2004:2007:
| Effective Date | Percentage Increase in Rates | Annual Increase in Revenues (Dollars In Millions) |
| October 1, 2006 | 10.2% | $ 95.1 |
| October 1, 2005 | 14.7% | 121.6 |
| October 1, 2004 | 17.6% | 121.7 |
| Effective Date | Percentage Increase (Decrease) in Rates | Annual Increase (Decrease) in Revenues (Dollars In Millions) |
| October 1, 2009 | (17.1)% | $ (198.1) |
| June 1, 2009 | (1.7)% | $ (21.2) |
| October 1, 2008 | 11.1 % | $ 108.8 |
| October 1, 2007 | (13.0)% | $ (148.1) |
| Twelve Months ended December 31 | | 2006 | | 2005 | | 2004 | | | 2009 | | | 2008 | | | 2007 | |
| Generation and purchased power, MWh | | | | | | | | | | | | | | | | |
| Company-controlled resources | | | 6,845,323 | | | 6,902,040 | | | 7,048,270 | | | | 10,748,523 | | | | 9,419,375 | | | | 8,623,094 | |
| Contracted resources | | | 9,625,381 | | | 9,606,880 | | | 9,421,546 | | | | 8,285,761 | | | | 8,711,075 | | | | 9,353,824 | |
| Non-firm energy purchased | | | 8,185,198 | | | 7,299,139 | | | 6,164,457 | | | | 6,935,600 | | | | 7,106,320 | | | | 7,473,458 | |
| Total generation and purchased power | | | 24,655,902 | | | 23,808,059 | | | 22,634,273 | | | | 25,969,884 | | | | 25,236,770 | | | | 25,450,376 | |
| Less: losses and Company use | | | (1,489,008 | ) | | (1,448,214 | ) | | (1,432,686 | ) | | | (1,568,372 | ) | | | (1,549,277 | ) | | | (1,562,975 | ) |
| Total energy sales, MWh | | | 23,166,894 | | | 22,359,845 | | | 21,201,587 | | | | 24,401,512 | | | | 23,687,493 | | | | 23,887,401 | |
| Twelve Months ended December 31 | | 2006 | | 2005 | | 2004 | | | 2009 | | | 2008 | | | 2007 | |
| Electric energy sales, MWh | | | | | | | | | | | | | | | | |
| Residential | | | 10,593,340 | | | 10,321,984 | | | 10,028,150 | | | | 11,163,371 | | | | 11,082,670 | | | | 10,869,347 | |
| Commercial | | | 8,939,155 | | | 8,647,478 | | | 8,449,566 | | | | 9,488,763 | | | | 9,453,940 | | | | 9,226,215 | |
| Industrial | | | 1,368,672 | | | 1,357,973 | | | 1,352,660 | | | | 1,148,060 | | | | 1,304,662 | | | | 1,364,264 | |
| Other customers | | | 78,078 | | | 105,388 | | | 94,034 | | | | 103,537 | | | | 100,948 | | | | 96,217 | |
| Total energy billed to customers | | | 20,979,245 | | | 20,432,823 | | | 19,924,410 | | | | 21,903,731 | | | | 21,942,220 | | | | 21,556,043 | |
| Unbilled energy sales - net increase (decrease) | | | 119,800 | | | 40,015 | | | (40,217 | ) | |
| Unbilled energy sales – net (decrease) increase | | | | (29,652 | ) | | | 80,375 | | | | 78,303 | |
| Total energy sales to customers | | | 21,099,045 | | | 20,472,838 | | | 19,884,193 | | | | 21,874,079 | | | | 22,022,595 | | | | 21,634,346 | |
| Sales to other utilities and marketers | | | 2,067,849 | | | 1,887,007 | | | 1,317,394 | | | | 2,527,433 | | | | 1,664,898 | | | | 2,253,055 | |
| Total energy sales, MWh | | | 23,166,894 | | | 22,359,845 | | | 21,201,587 | | | | 24,401,512 | | | | 23,687,493 | | | | 23,887,401 | |
| Transportation, including unbilled | | | 2,091,981 | | | 2,030,457 | | | 1,988,965 | | | | 2,030,110 | | | | 2,045,161 | | | | 2,131,970 | |
| Electric energy sales and transportation, MWh | | | 25,258,875 | | | 24,390,302 | | | 23,190,552 | | | | 26,431,622 | | | | 25,732,654 | | | | 26,019,371 | |
| Twelve Months ended December 31 | | 2006 | | 2005 | | 2004 | | | 2009 | | | 2008 | | | 2007 | |
| Electric operating revenues by classes (thousands): | | | | | | | | |
| Electric operating revenues by classes (dollars in thousands): | | | | | | | | | | |
| Residential | | $ | 788,237 | | $ | 690,184 | | $ | 628,869 | | | $ | 1,067,274 | | | $ | 1,046,897 | | | $ | 951,101 | |
| Commercial | | | 702,754 | | | 629,008 | | | 580,973 | | | | 838,275 | | | | 800,879 | | | | 748,824 | |
| Industrial | | | 103,043 | | | 93,922 | | | 88,779 | | | | 99,552 | | | | 106,092 | | | | 105,227 | |
| Other customers | | | 66,470 | | | 76,153 | | | 58,007 | | | | 6,509 | | | | 72,250 | | | | 57,482 | |
Operating revenues billed to customers1 | | | 1,660,504 | | | 1,489,267 | | | 1,356,628 | | |
| Unbilled revenues - net increase (decrease) | | | 20,749 | | | 9,548 | | | (813 | ) | |
| Operating revenues billed to customers | | | | 2,011,610 | | | | 2,026,118 | | | | 1,862,634 | |
| Unbilled revenues – net (decrease) increase | | | | (1,968 | ) | | | 10,789 | | | | 16,103 | |
| Total operating revenues from customers | | | 1,681,253 | | | 1,498,815 | | | 1,355,815 | | | | 2,009,642 | | | | 2,036,907 | | | | 1,878,737 | |
| Transportation, including unbilled | | | 11,488 | | | 9,027 | | | 10,707 | | | | 10,623 | | | | 7,840 | | | | 9,356 | |
| Sales to other utilities and marketers | | | 85,004 | | | 105,027 | | | 56,512 | | | | 78,471 | | | | 84,716 | | | | 109,736 | |
| Total electric operating revenues | | $ | 1,777,745 | | $ | 1,612,869 | | $ | 1,423,034 | | | $ | 2,098,736 | | | $ | 2,129,463 | | | $ | 1,997,829 | |
| Twelve Months ended December 31 | | 2006 | | 2005 | | 2004 | |
| Number of customers served (average): | | | | | | | |
| Residential | | | 909,876 | | | 893,576 | | | 877,711 | |
| Commercial | | | 111,672 | | | 111,587 | | | 109,238 | |
| Industrial | | | 3,696 | | | 3,877 | | | 3,980 | |
| Other | | | 2,637 | | | 2,426 | | | 2,197 | |
| Transportation | | | 18 | | | 17 | | | 17 | |
| Total customers (average) | | | 1,027,899 | | | 1,011,483 | | | 993,143 | |
| Twelve Months ended December 31 | | 2006 | | 2005 | | 2004 | | | 2009 | | | 2008 | | | 2007 | |
| Average kWh used per customer: | | | | | | | | |
| Number of customers served (average): | | | | | | | | | | |
| Residential | | | 11,643 | | | 11,551 | | | 11,425 | | | | 947,299 | | | | 939,440 | | | | 926,080 | |
| Commercial | | | 80,048 | | | 77,495 | | | 77,350 | | | | 118,423 | | | | 117,521 | | | | 115,577 | |
| Industrial | | | 370,312 | | | 350,264 | | | 339,864 | | | | 3,695 | | | | 3,744 | | | | 3,771 | |
| Other | | | 29,609 | | | 43,441 | | | 42,801 | | | | 3,403 | | | | 3,231 | | | | 2,965 | |
| Average revenue billed per customer: | | | | | | | | | | | |
| Residential | | $ | 866 | | $ | 772 | | $ | 716 | | |
| Commercial | | | 6,293 | | | 5,637 | | | 5,318 | | |
| Industrial | | | 27,880 | | | 24,225 | | | 22,306 | | |
| Other | | | 25,207 | | | 31,390 | | | 26,403 | | |
| Average retail revenues per kWh sold: | | | | | | | | | | | |
| Residential | | $ | 0.0744 | | $ | 0.0669 | | $ | 0.0627 | | |
| Commercial | | | 0.0786 | | | 0.0727 | | | 0.0688 | | |
| Industrial | | | 0.0753 | | | 0.0692 | | | 0.0656 | | |
| Average retail revenue per kWh sold | | | 0.0763 | | | 0.0695 | | | 0.0655 | | |
| Heating degree days | | | 4,476 | | | 4,489 | | | 4,421 | | |
Percent of normal - NOAA 30-year average | | | 93.3 | % | | 93.6 | % | | 91.8 | % | |
Load factor2 | | | 52.4 | % | | 57.4 | % | | 53.5 | % | |
| Transportation | | | | 17 | | | | 18 | | | | 18 | |
| Total customers | | | | 1,072,837 | | | | 1,063,954 | | | | 1,048,411 | |
| Twelve Months ended December 31 | | 2009 | | | 2008 | | | 2007 | |
| Average kWh used per customer: | | | | | | | | | |
| Residential | | | 11,784 | | | | 11,797 | | | | 11,737 | |
| Commercial | | | 80,126 | | | | 80,445 | | | | 79,827 | |
| Industrial | | | 310,706 | | | | 348,468 | | | | 361,778 | |
| Other | | | 30,425 | | | | 31,243 | | | | 32,451 | |
| Average revenue billed per customer: | | | | | | | | | | | | |
| Residential | | $ | 1,127 | | | $ | 1,114 | | | $ | 1,027 | |
| Commercial | | | 7,079 | | | | 6,815 | | | | 6,479 | |
| Industrial | | | 26,942 | | | | 28,337 | | | | 27,904 | |
| Other | | | 1,913 | | | | 22,362 | | | | 19,366 | |
| Average retail revenues per kWh sold: | | | | | | | | | | | | |
| Residential | | $ | 0.0956 | | | $ | 0.0944 | | | $ | 0.0875 | |
| Commercial | | | 0.0883 | | | | 0.0847 | | | | 0.0812 | |
| Industrial | | | 0.0867 | | | | 0.0813 | | | | 0.0771 | |
| Average retail revenue per kWh sold | | | 0.0902 | | | | 0.0868 | | | | 0.0819 | |
| Heating degree days | | | 4,897 | | | | 5,062 | | | | 4,823 | |
Percent of normal - NOAA1 30-year average | | | 102.1 | % | | | 105.1 | % | | | 100.5 | % |
Load factor 2 | | | 54.5 | % | | | 58.6 | % | | | 58.9 | % |
_______________1 | Operating revenues in 2004 were reduced by $0.8 million as a result of the Company’s sale of $237.7 million of its investment in customer-owned conservation measures in 1995National Oceanic and 1997. As of October 2004, the bond was paid and any excess collections were recorded as a reduction in revenues.
Atmospheric Administration (NOAA). |
2 | Average usage by customers divided by their maximum usage. |
At December 31, 2006,2009, PSE’s electric power resources, which include company-owned or controlled resources as well as those under long-term contract, had a total capacity of approximately 4,4565,044 megawatts (MW). PSE’s historical peak load of approximately 4,8474,912 MW occurred on December 21, 1998.10, 2009 and broke the previous record of 4,906 MW which occurred on December 15, 2008. In order to meet an extreme winter peak load, PSE may supplement its electric power resources with winter-peaking call options and other instruments that may include, but are not limited to, weather-related hedges and exchange agreements.hedges. When it is more economical to purchase power than to run the Company’soperate PSE’s generation, PSE will purchase in the short-term markets.spot market energy.
The following table shows PSE’s electric energy supply resources at December 31, 2006 and 2005 and energy production duringfor the year:years ended December 31, 2009 and 2008:
| | Peak Power Resources At December 31 | Energy Production |
| | 2006 | 2005 | 2006 | 2005 |
| | MW | % | MW | % | MWh | % | MWh | % |
| Purchased resources: | | | | | | | | |
| Columbia River PUD contracts | 1,164 | 26.1% | 1,212 | 28.3% | 5,692,366 | 23.1% | 5,397,825 | 22.7% |
Other hydroelectric1 | 168 | 3.8% | 164 | 3.8% | 653,362 | 2.6% | 590,263 | 2.5% |
Other producers1 | 932 | 20.9% | 944 | 22.1% | 3,279,575 | 13.3% | 3,618,792 | 15.2% |
Short-term wholesale energy purchases2 | N/A | N/A | N/A | N/A | 8,185,276 | 33.2% | 7,299,139 | 30.7% |
| Total purchased | 2,264 | 50.8% | 2,320 | 54.2% | 17,810,579 | 72.2% | 16,906,019 | 71.1% |
| Company-controlled resources: | | | | | | | | |
| Hydroelectric | 234 | 5.3% | 234 | 5.5% | 949,276 | 3.9% | 879,493 | 3.7% |
| Coal | 677 | 15.2% | 677 | 15.8% | 4,800,028 | 19.5% | 5,175,799 | 21.7% |
| Natural gas/oil | 902 | 20.2% | 902 | 21.0% | 723,190 | 2.9% | 813,078 | 3.4% |
Wind3 | 379 | 8.5% | 150 | 3.5% | 372,829 | 1.5% | 33,670 | 0.1% |
| Total Company-controlled | 2,192 | 49.2% | 1,963 | 45.8% | 6,845,323 | 27.8% | 6,902,040 | 28.9% |
| Total | 4,456 | 100.0% | 4,283 | 100.0% | 24,655,902 | 100.0% | 23,808,059 | 100.0% |
_______________| | Peak Power Resources At December 31 | Energy Production At December 31 |
| | 2009 | 2008 | 2009 | 2008 |
| | MW | % | MW | % | MWh | % | MWh | % |
| Purchased resources: | | | | | | | | |
Columbia River PUD contracts 1 | 1,057 | 21.0% | 1,135 | 22.4% | 4,861,462 | 20.7% | 5,438,195 | 21.5% |
Other hydroelectric 2 | 145 | 2.8 | 145 | 2.8 | 606,534 | 2.6 | 592,535 | 2.3 |
Other producers 2 | 822 | 16.3 | 821 | 16.2 | 3,098,197 | 13.2 | 2,532,033 | 10.0 |
| Wind | 50 | 1.0 | 50 | 1.0 | 132,569 | 0.6 | 148,311 | 0.6 |
Short-term wholesale energy purchases 3 | N/A | N/A | N/A | N/A | 3,995,196 | 17.0 | 7,106,322 | 28.2 |
| Total purchased | 2,074 | 41.1% | 2,151 | 42.4% | 12,693,958 | 54.1% | 15,817,396 | 62.6% |
| Company-controlled resources: | | | | | | | | |
| Hydroelectric | 236 | 4.7% | 236 | 4.6% | 987,779 | 4.2% | 974,924 | 3.9% |
| Coal | 677 | 13.4 | 677 | 13.3 | 4,451,104 | 19.0 | 5,067,445 | 20.1 |
Natural gas/oil 4 | 1,627 | 32.3 | 1,627 | 32.1 | 4,363,147 | 18.6 | 2,269,586 | 9.0 |
| Wind | 430 | 8.5 | 386 | 7.6 | 946,494 | 4.1 | 1,107,419 | 4.4 |
| Total company-controlled | 2,970 | 58.9% | 2,926 | 57.6% | 10,748,524 | 45.9% | 9,419,374 | 37.4% |
| Total | 5,044 | 100.0% | 5,077 | 100.0% | 23,442,482 | 100.0% | 25,236,770 | 100.0% |
| 1 | Net of 59 MW of capacity delivered to Canada pursuant to the provisions of a treaty between Canada and the United States and Canadian Entitlement Allocation agreements. |
| 2 | Power received from other utilities is classified between hydroelectric and other producers based on the character of the utility system used to supply the power or, if the power is supplied from a particular resource, the character of that resource. |
2
3 | Short-term wholesale purchases net of resale of 2,067,8492,527,433 MWh and 1,887,0071,664,898 MWh account for 27.1%7.0% and 24.7%23.1% of energy production, net of resale for 20062009 and 2005,2008, respectively. |
3
4 | 2006 represents Hopkins RidgeSumas is included beginning August 2008 and Wild Horse wind projects. Wild Horse began commercial operations onMint Farm is included beginning December 22, 2006. 2005 represents Hopkins Ridge, which began commercial operations on November 27, 2005.
2008. |
Integrated Resource PlansPSE is required by the Washington Commission to file electric and gas Integrated Resource Plans (IRP) every two years. The next plan will be filed in May 2007. PSE filed its electric IRP in May 2005 that supports a strategy of diverse electric power and demand resource acquisitions including resources fueled by natural gas and coal, renewable resources (e.g., wind and biomass) and the implementation of energy efficiency strategies. The electric IRP was followed by an all-source request for proposal (RFP) issued on November 1, 2005. The Washington Commission approved the all-source RFP on October 28, 2005. Based on PSE’s projected customer usage for electricity and its current electric generation resources, PSE expects that future energy needs will exceed current purchased and Company-controlled power resources. The expected average MW shortfall for the period 2007 through 2011 is as follows:
| | 2007 | 2008 | 2009 | 2010 |
Projected average MW shortfall1 | 283 | 305 | 362 | 457 |
______________ | Estimated using all resources under long-term contracts and Company-controlled facilities.
|
PSE expects to address this shortfall position with the use of a combination of new long-term power contracts and the purchase or construction of new generating resources.
Company - Controlled– Owned Electric Generation Resources
At December 31, 2006,2009, PSE hasowns or controls the following plants with an aggregate net generating capacity of 2,1922,962 MW:
| Plant Name | Plant Type | Net Capacity (MW) | Year Installed |
| Colstrip Units 1 & 2 (50% interest) | Coal | 307 | 1975 & 1976 |
| Colstrip Units 3 & 4 (25% interest) | Coal | 370 | 1984 & 1986 |
| Fredonia Units 1 & 2 | Dual-fuel combustion turbines | 207 | 1984 |
| Fredonia Units 3 & 4 | Dual-fuel combustion turbines | 107 | 2001 |
| Frederickson Units 1 & 2 | Dual-fuel combustion turbines | 147 | 1981 |
| Whitehorn Units 2 & 3 | Dual-fuel combustion turbines | 147 | 1981 |
| Frederickson Unit 1 (49.85% interest) | Natural gas combined cycle | 137 | 2002; added duct firing in 2005 |
| Goldendale | Natural gas combined cycle | 277 | 2004 |
| Mint Farm | Natural gas combined cycle | 302 | 2007 |
| Sumas | Natural gas cogeneration | 125 | 1993 |
| Encogen | Natural gas cogeneration | 167 | 1993 |
| Crystal Mountain | Internal combustion | 3 | 1969 |
Upper Baker River 1 | Hydroelectric | 91 | 1959 |
Lower Baker River 1 | Hydroelectric | 79 | 1925; reconstructed 1960; upgraded 2001 |
Snoqualmie Falls 2 | Hydroelectric | 44 | 1898 to 1911 & 1957 |
| Electron | Hydroelectric | 22 | 1904 to 1929 |
| Wild Horse | Wind | 273 | 2006; added 22 turbines in 2009 |
| Hopkins Ridge | Wind | 157 | 2005; added 4 turbines in 2008 |
| Total net capacity | | 2,962 | |
_______________
| 1 | FERC jurisdictional facility, operated pursuant to 50-year license granted by FERC in October 2008, which will require net present value funds of between $305.0 million to $325.0 million for capital expenditures and operations and maintenance costs over 50 years in order to implement the license conditions. The license provides protection and enhancements for fish and wildlife, water quality, recreation and cultural and historic resources. |
| 2 | FERC jurisdictional facility, operated pursuant to 40-year license granted by FERC in June 2004, which will require net present value funds in the amount of $240.0 million to $260.0 million over the 40-year term in order to implement the license conditions. |
| Plant Name | Plant Type | Net Capacity (MW) | Year Installed |
| Colstrip Units 1 & 2 (50% interest) | Coal | 307 | 1975 & 1976 |
| Colstrip Units 3 & 4 (25% interest) | Coal | 370 | 1984 & 1986 |
| Fredonia Units 1 & 2 | Dual-fuel combustion turbines | 207 | 1984 |
| Frederickson Units 1 & 2 | Dual-fuel combustion turbines | 147 | 1981 |
| Whitehorn Units 2 & 3 | Dual-fuel combustion turbines | 147 | 1981 |
| Fredonia Units 3 & 4 | Dual-fuel combustion turbines | 107 | 2001 |
| Frederickson Unit 1 (49.85% interest) | Natural gas combined cycle | 124 | 2002 |
| Encogen | Natural gas cogeneration | 167 | 1993 |
| Crystal Mountain | Internal combustion | 3 | 1969 |
| Upper Baker River | Hydroelectric | 91 | 1959 |
| Lower Baker River | Hydroelectric | 79 | 1925; reconstructed 1960; upgraded 2001 |
| Snoqualmie Falls | Hydroelectric | 44 | 1898 to 1911 & 1957 |
| Electron | Hydroelectric | 22 | 1904 to 1929 |
| Wild Horse | Wind | 229 | 2006 |
| Hopkins Ridge | Wind | 150 | 2005 |
| Total Net Capacity | | 2,194 | |
Goldendale Generating StationOn February 21, 2007, PSE acquired the Goldendale Generating Station, a 277 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 the generating facility.
FERC Hydroelectric Projects And Licenses
As part of its hydroelectric operations, PSE is required to obtain operating licenses from FERC. A typical license contains mandatory conditions of operation, such as flow rate requirements, adherence to certain ramping protocols for outages, maintenance of reservoir levels, equipment upgrade projects and fish and wildlife mitigation projects for a 30 to 50 year period. The licensing and relicensing processes involve harmonizing conflicting rights and obligations of numerous governmental, non-governmental and private parties, and dealing with issues that may include environmental compliance, fish protection and mitigation, water quality, Native American rights, title claims, operational and capital improvements and flood control. As a result, a number of political, compliance and financial risks can arise from the licensing and relicensing processes. FERC regulates dam safety and administers proceedings under the Federal Power Act (FPA) to license jurisdictional hydropower projects.
PSE owns three operating hydroelectric projects: the Baker River project, the Snoqualmie Falls project and the Electron project. PSE’s White River project ceased operations as a hydroelectric generating resource in January 2004. The Baker River and Snoqualmie Falls projects are operating under the jurisdiction of FERC.
Baker River project. The Baker River project’s current annual license expires on April 30, 2007, and PSE submitted an application for a new license to FERC on April 30, 2004. On November 30, 2004, PSE and 23 parties, (federal, state and local governmental organizations, Native American Indian tribes, environmental and other non-governmental entities) filed a proposed comprehensive settlement agreement on all issues relating to the relicensing of the Baker River project. The proposed settlement includes a set of proposed license articles and, if approved by FERC without material modification, would allow for a new license of 45 years or more. The proposed settlement would require an investment of approximately $360.0 million over the next 30 years (capital expenditures and operations and maintenance cost) in order to implement the conditions of the new license. The proposed settlement is subject to additional regulatory approvals yet to be attained from various agencies and other contingencies that have yet to be resolved. A Final Environmental Impact Statement was issued by FERC on September 8, 2006. However, FERC has not yet ruled on the proposed settlement and its ultimate outcome remains uncertain.
Snoqualmie Falls project. The Snoqualmie Falls project was granted a new 40-year operating license by FERC on June 29, 2004. PSE estimates that the investment required to implement the conditions of the new license will cost approximately $44.0 million. On July 29, 2004, the Snoqualmie Tribe filed a request for rehearing of the new license and a request to stay the FERC license. On March 1, 2005, FERC issued an Order on Rehearing and Dismissing Stay Request. Appeals to the U.S. Court of Appeals by the Snoqualmie Tribe and by PSE have been consolidated. Oral arguments were held on February 8, 2007. An adverse ruling from the Court or adverse action by FERC if the license issuance is remanded could impact PSE’s future use of this generating asset.
White River project. The White River project was operated as a hydropower facility until 2004. PSE is actively seeking to sell the project and the municipal water rights associated with the project to one or more entities. In June 2003, Ecology approved an application for new municipal water rights related to the White River project reservoir. After an appeal in July 2004, this decision was remanded back to Ecology for further analysis of non-hydropower operations. On December 21, 2006, PSE entered into a Purchase and Sale Agreement with the Cascade Land Conservancy to sell certain rights and interests in a portion of former project properties, although the closing of the sale is subject to contingencies that have yet to be resolved.
On April 7, 2004, the Washington Commission approved PSE’s recovery on the unamortized White River plant investment. At December 31, 2006, the White River project net book value totaled $69.1 million, which included $43.4 million of net utility plant, $17.1 million of capitalized FERC licensing costs, $4.3 million of costs related to construction work in progress and $1.8 million related to dam operations and safety. On February 18, 2005, the Washington Commission approved the recovery of the White River net utility plant costs but did not allow current recovery of FERC licensing costs and other related costs until all costs associated with selling the White River plant and any sales proceeds are known. Any proceeds from the sale of the White River assets and water rights will reduce the balance of the deferred regulatory asset. Neither the outcome of this matter nor any potential associated financial impacts can be predicted at this time.
Columbia River Electric Energy Supply Contracts
During 2006,2009, approximately 23.1%21.4% of PSE’s energy outputrequirement was obtained at an average cost of approximately $0.014 per kWh through long-term contracts with several of thethree Washington PUDsPublic Utility Districts (PUDs) that own and operate hydroelectric projects on the Columbia River. PSE agrees to pay a proportionate share of the annual debt service, operating and maintenance costs and other expenses associated with each project.project in proportion to its share of projected output. PSE’s payments are not contingent upon the projects being operable.
As of December 31, 2006, the Company2009, PSE was entitled to purchase portions of the power output of the PUDs’ projects as set forth:forth below:
| | | Company’s Annual Amount Purchasable (Approximate) | | Company’s Annual Purchasable Amount (Approximate) |
| Project | Contract Exp. Date | License Exp. Date | % of Output | | Megawatt Capacity | Contract Expiration Year | License Expiration Year | Percent of Output | | Megawatt Capacity |
Chelan County PUD:1 | | | | | | |
| Rock Island Project | | | | 2012 | 2029 | 50.0% | | 312 |
| Original units | 2012 | 2029 | 50.0 | } | 330 | |
| Additional units | 2012 | 2029 | 50.0 | |
| Rocky Reach Project | 2011 | 2006 | 38.9 | | 501 | 2011 | 2052 | 38.9% | | 498 |
| Douglas County PUD: | | | | | | | |
| Wells Project | 2018 | 2012 | 29.9 | | 251 | 2018 | 2012 | 29.9% | | 251 |
Grant County PUD:2,3 | | | | | |
| Grant County PUD: | | | | |
| Priest Rapids Development | TBD | 4.3 | | 39 | 2052 | 2.8% | | 26 |
| Wanapum Development | 2009 | TBD | 10.8 | | 106 | 2052 | 2.8% | | 29 |
| Total | | | 1,227 | | | 1,116 |
1 | On February 3, 2006, PSE and Chelan entered into a new Power Sales Agreement and a related Transmission Agreement for 25.0% of the output of Chelan’s Rocky Reach and Rock Island hydro electrichydroelectric generating facilities located on the mid-Columbia River in exchange for PSE paying 25.0% of the operating costs of the facilities. PSE’s share of the output represents approximately 487 MW of capacity and 243 average MW of energy. The agreements terminate in 2031 and provide that PSE will begin to receive power upon expiration of PSE’s existing long-term contracts with Chelan for the Rocky Reach and Rock Island output (expiring in 2011 and 2012, respectively). PSE made a non-refundable capacity reservation payment of $89.0 million as required by the agreements. The Washington Commission determined the prudence of PSE entering into the new Chelan contract and confirmed the treatment of the $89.0 million as a regulatory asset as part of its order in PSE’s General Rate Casegeneral rate case on January 5, 2007. |
2
| Under terms of the 2001 Grant contract extensions, PSE will continue to obtain capacity and energy for the term of any new FERC license to be obtained by Grant County PUD. The new contracts’ terms began in November of 2005 for the Priest Rapids Development and will beginin November of 2009 for the Wanapum Development.
|
3
| PSE’s share of power from the 2001 contract declines over time as Grant County PUD’s load increases. PSE’s share of the Wanapum Development will remain at 10.8% until November 2009 and will be adjusted annually thereafter for the remaining term of the new contracts. PSE’s share of the Priest Rapids Development declined to approximately 4.3% in 2006 and will be adjusted annually for the remaining term of the new contract.
|
Other Electric Energy Supply, Exchange and Transmission Contracts and Agreements With Other Utilities
PSE has entered into long-term firm purchased power contracts with other utilities in the WestWestern region. PSE generally is generally not obligated to make payments under these contracts unless power is delivered.
Under a 1985 settlement agreement These include seasonal energy and capacity exchange agreements with the Bonneville Power AssociationAdministration (BPA), PSE is entitled to receive exchange energy from BPA during the months of November through April, which amounts to 36.5 (for 42 average MW of energymegawatts (aMW)) and 82 MW of capacity for contract year 2006-2007. BPA has an option to request that PSE deliver up to 31.2 average MW of exchange energy to BPA in all months except May, July and August for contract year 2006-2007. The contract terminates June 30, 2017, but may be terminated earlier under certain circumstances.
On October 1, 1989, PSE signed a contract with The Montana Power Company for 71 average MW of energy (97 MW of peak capacity) through December 2010. The contract deliveries are contingent on the combined availability of Colstrip Units 3 & 4. The contract payments consist of a fixed monthly payment and an energy payment based on commodity and transportation costs for coal. The fixed payment may be reduced if the delivered energy is less than the adjusted energy entitlement (equal to an equivalent availability of approximately 73.0%) for the contract year.
In January 1992, PSE executed an agreement with Pacific Gas & Electric Company (PG&E) to exchange(for 300 MW of capacity togethercapacity) and an energy purchase contract with upNorthWestern Energy (for 71 aMW).
Pursuant to 413,000 megawatt hours (MWh)the provisions of energy seasonally each year. No payments are made under this agreement. PG&E provides power during the months of November through February and PSE provides power during the months of June through September. Each party may terminate the contract upon five year prior notice.
Under an agreement with Powerex expiring in February 2006, Powerex pays PSE for the right to deliver up to 1,200,000 MWh annually to PSE at the Canadian border in exchange for PSE delivering power to Powerex at various locations in the United States. The agreement also allows Powerex to make up any exchange volumes not used up to two years after the end of the annual period.
Electric Energy Supply Contracts and Agreements With Non-Utility Generators
As required by the federal Public Utility Regulatory Policies Act (PURPA), and Washington state regulations, PSE also has entered into long-term firm purchased power contracts with non-utility generators. The most significant contracts are described below. PSE purchases the net electrical output of these three projects at fixed and annually escalating prices, intended to approximate PSE’s avoided cost of new generation projected at the time these agreements were made.
As of December 31, 2006,2009, the Company purchased the following significant power output from the following:entities:
| | | | | Average |
| | Plant | Contract | Megawatt | Megawatts |
| Contract | Type | Expiration | Capacity | of Energy |
| March Point Cogeneration Company: | | | | |
| March Point Phase I | Natural gas cogeneration | December 2011 | 80 | 70 |
| March Point Phase II | Natural gas cogeneration | December 2011 | 60 | 53 |
| Tenaska Washington Partners, L.P. | Natural gas cogeneration | December 2011 | 245 | 216 |
| Total | | | 385 | 339 |
| Contract | Plant Type | Contract Exp. Date | Megawatt Capacity | Average Megawatts of Energy |
| Sumas Cogeneration Company | Natural gas cogeneration | 2013 | 135 | 108 |
| March Point Cogeneration Company: | | | | |
| March Point Phase I | Natural gas cogeneration | 2011 | 80 | 70 |
| March Point Phase II | Natural gas cogeneration | 2011 | 60 | 53 |
| Tenaska Washington Partners, LP | Natural gas cogeneration | 2011 | 245 | 216 |
| Total | | | 520 | 447 |
Electric Transmission Contracts With Other Utilities
Further, PSE has entered into numerousmultiple various-term transmission contracts with BPAother utilities to integrate electric generation and contracted resources into PSE’s system. These transmission contracts require PSE to pay for transmission service based on the contracted MW level of demand, regardless of actual use. AnyThese costs incurred are recovered through the PCA mechanism.
Other transmission agreements provide actual capacity ownership or capacity ownership rights. PSE’s annual charges under these agreements are also based on contracted MW volumes. Capacity on these agreements that is not committed to serve PSE load is available for sale to third parties on PSE’s Open Access Same Time Information System (OASIS).parties. PSE also purchases short term transmission services from a variety of providers, including BPA.
TheIn 2009, PSE had 4,030 MW and 620 MW of total transmission agreementsdemand contracted with BPA have various terms collectively and have an aggregate demand limit in excess of 2,600 MW.
In 2006, BPAother utilities (Avista, Klickitat PUD, Grant PUD and PSE signed agreements for a total of 650 MW from the Mid-Columbia area into PSE’s system. Service under these agreements commenced November 1, 2006 and will continue until November 30, 2007 and contain rights to continue service beyond the termination date.Snohomish PUD), respectively.
Natural Gas Supply for Electric Customers
| Twelve Months ended December 31 | | 2006 | | 2005 | | 2004 | |
| Gas operating revenues by classes (thousands): | | | | | | | |
| Residential | | $ | 697,631 | | $ | 592,361 | | $ | 478,969 | |
| Commercial firm | | | 279,977 | | | 234,342 | | | 187,262 | |
| Industrial firm | | | 43,994 | | | 38,380 | | | 30,472 | |
| Interruptible | | | 68,753 | | | 56,928 | | | 46,900 | |
| Total retail gas sales | | | 1,090,355 | | | 922,011 | | | 743,603 | |
| Transportation services | | | 13,269 | | | 13,277 | | | 12,968 | |
| Other | | | 16,494 | | | 17,227 | | | 12,735 | |
| Total gas operating revenues | | $ | 1,120,118 | | $ | 952,515 | | $ | 769,306 | |
| Twelve Months ended December 31 | | 2006 | | 2005 | | 2004 | |
| Number of customers served (average): | | | | | | | |
| Residential | | | 649,373 | | | 629,563 | | | 610,181 | |
| Commercial firm | | | 51,007 | | | 50,148 | | | 49,050 | |
| Industrial firm | | | 2,618 | | | 2,651 | | | 2,688 | |
| Interruptible | | | 470 | | | 528 | | | 574 | |
| Transportation | | | 122 | | | 129 | | | 129 | |
| Total customers | | | 703,590 | | | 683,019 | | | 662,622 | |
| Twelve Months ended December 31 | | 2006 | | 2005 | | 2004 | |
| Gas volumes, therms (thousands): | | | | | | | |
| Residential | | | 533,370 | | | 510,026 | | | 489,036 | |
| Commercial firm | | | 236,753 | | | 225,389 | | | 217,346 | |
| Industrial firm | | | 41,185 | | | 38,576 | | | 36,751 | |
| Interruptible | | | 65,016 | | | 61,769 | | | 65,425 | |
| Total retail gas volumes, therms | | | 876,324 | | | 835,760 | | | 808,558 | |
| Transportation volumes | | | 206,367 | | | 198,504 | | | 201,642 | |
| Total volumes | | | 1,082,691 | | | 1,034,264 | | | 1,010,200 | |
| Twelve Months ended December 31 | | 2006 | | 2005 | | 2004 | |
| Working gas volumes in storage at year end, therms (thousands): | | | | | | | |
| Jackson Prairie | | | 68,141 | | | 70,303 | | | 70,986 | |
| AECO hub - Canada | | | 14,810 | | | 14,820 | | | -- | |
| Clay Basin | | | 91,090 | | | 38,857 | | | 55,044 | |
| Average therms used per customer: | | | | | | | | | | |
| Residential | | | 821 | | | 810 | | | 801 | |
| Commercial firm | | | 4,642 | | | 4,494 | | | 4,431 | |
| Industrial firm | | | 15,731 | | | 14,551 | | | 13,672 | |
| Interruptible | | | 138,332 | | | 116,987 | | | 113,981 | |
| Transportation | | | 1,691,533 | | | 1,538,791 | | | 1,563,116 | |
| Average revenue per customer: | | | | | | | | | | |
| Residential | | $ | 1,074 | | $ | 941 | | $ | 785 | |
| Commercial firm | | | 5,489 | | | 4,673 | | | 3,818 | |
| Industrial firm | | | 16,804 | | | 14,478 | | | 11,336 | |
| Interruptible | | | 146,283 | | | 107,818 | | | 81,707 | |
| Transportation | | | 108,762 | | | 102,922 | | | 100,527 | |
| Average revenue per therm sold: | | | | | | | | | | |
| Residential | | $ | 1.308 | | $ | 1.161 | | $ | 0.979 | |
| Commercial firm | | | 1.183 | | | 1.040 | | | 0.862 | |
| Industrial firm | | | 1.068 | | | 0.995 | | | 0.829 | |
| Interruptible | | | 1.057 | | | 0.922 | | | 0.717 | |
| Average retail revenue per therm sold | | | 1.244 | | | 1.103 | | | 0.920 | |
| Transportation | | | 0.064 | | | 0.067 | | | 0.064 | |
| Heating degree days | | | 4,476 | | | 4,489 | | | 4,421 | |
Percent of normal - NOAA 30-year average | | | 93.3 | % | | 93.6 | % | | 91.8 | % |
PSE currently purchases a blended portfolio ofnatural gas supplies rangingfor its power portfolio to meet demand for its combustion turbine generators. Supplies range from long-term firm to daily agreements as the demand for the turbines varies depending on market heat rates. Purchases are made from a diverse group of major and independent natural gas producers and marketers in the United States and Canada. PSE also enters into short-term physical and financial fixed price derivative instruments to hedge the cost of natural gas. PSE utilizes natural gas storage capacity to facilitate increased natural gas supply reliability and intra-day dispatch of PSE’s gas-fired generation resources. During 2009, approximately 70.0% of natural gas for power purchased by PSE for power customers originated in British Columbia and 30.0% originated in the United States. Natural gas is either marketed outside PSE’s service territory (off-system sales) or injected into the power portfolio’s natural gas storage when the natural gas is not needed for the combustion turbines.
Integrated Resource Plans, Resource Acquisition and Development
PSE is required by Washington Commission regulations to file electric and natural gas Integrated Resource Plans (IRP) every two years. PSE filed its most recent IRP with the Washington Commission on July 30, 2009 and an addendum to the 2009 IRP was filed on January 29, 2010. The IRP demonstrated PSE’s continuing need to acquire significant amounts of new generating resources, driven primarily by expiration of existing purchase power contracts. The IRP, as amended, identifies the following capacity needs:
| | 2011 | 2012 | 2013 | 2014 |
| Projected MW shortfall | 281 | 934 | 1,036 | 1,128 |
To meet these expected shortfalls, the IRP demonstrates the potential value of increasing energy efficiency programs and acquiring additional renewable resources (primarily wind) and natural gas-fired generation to meet the growing needs of customers. Any actual mix of resources acquired will be determined through the Company’s resource acquisition program that examines specific acquisition and development opportunities.
As part of its actions to meet these identified shortfalls in electric generating resources in 2008, PSE added an additional 44 MW of wind generating capacity to its existing 229 MW Wild Horse wind project (Wild Horse). The expansion was completed in November 2009. In 2009, PSE also purchased from RES America, Inc., all of the undivided interest in four development-stage wind projects, collectively known as the Lower Snake River wind project, totaling 1,400 MW in the Columbia and Garfield counties in Washington state. PSE is currently evaluating development of the first stage of this project.
| Twelve Months ended December 31 | | 2009 | | | 2008 | | | 2007 | |
| Gas operating revenues by classes (dollars in thousands): | | | | | | | | | |
| Residential | | $ | 795,756 | | | $ | 766,799 | | | $ | 756,188 | |
| Commercial firm | | | 303,989 | | | | 321,829 | | | | 306,357 | |
| Industrial firm | | | 36,141 | | | | 42,530 | | | | 46,805 | |
| Interruptible | | | 56,511 | | | | 53,317 | | | | 67,560 | |
| Total retail gas sales | | | 1,192,397 | | | | 1,184,475 | | | | 1,176,910 | |
| Transportation services | | | 13,014 | | | | 14,700 | | | | 13,706 | |
| Other | | | 19,334 | | | | 17,694 | | | | 17,413 | |
| Total gas operating revenues | | $ | 1,224,745 | | | $ | 1,216,869 | | | $ | 1,208,029 | |
| Twelve Months ended December 31 | | 2009 | | | 2008 | | | 2007 | |
| Number of customers served (average): | | | | | | | | | |
| Residential | | | 689,438 | | | | 681,267 | | | | 666,756 | |
| Commercial firm | | | 54,022 | | | | 53,441 | | | | 52,067 | |
| Industrial firm | | | 2,534 | | | | 2,596 | | | | 2,611 | |
| Interruptible | | | 398 | | | | 419 | | | | 445 | |
| Transportation | | | 140 | | | | 128 | | | | 124 | |
| Total customers | | | 746,532 | | | | 737,851 | | | | 722,003 | |
| Twelve Months ended December 31 | | 2009 | | | 2008 | | | 2007 | |
| Gas volumes, therms (thousands): | | | | | | | | | |
| Residential | | | 585,626 | | | | 589,405 | | | | 556,837 | |
| Commercial firm | | | 248,321 | | | | 275,631 | | | | 248,497 | |
| Industrial firm | | | 31,535 | | | | 38,956 | | | | 40,472 | |
| Interruptible | | | 59,222 | | | | 56,329 | | | | 64,944 | |
| Total retail gas volumes, therms | | | 924,704 | | | | 960,321 | | | | 910,750 | |
| Transportation volumes | | | 210,243 | | | | 217,774 | | | | 213,542 | |
| Total volumes | | | 1,134,947 | | | | 1,178,095 | | | | 1,124,292 | |
| Twelve Months ended December 31 | | 2009 | | | 2008 | | | 2007 | |
| Working gas volumes in storage at year end, therms (thousands): | | | | | | | | | |
| Jackson Prairie | | | 66,948 | | | | 60,301 | | | | 64,982 | |
| AECO hub Canada | | | -- | | | | -- | | | | 15,093 | |
| Clay Basin | | | 93,023 | | | | 92,203 | | | | 87,454 | |
| Average therms used per customer: | | | | | | | | | | | | |
| Residential | | | 849 | | | | 865 | | | | 835 | |
| Commercial firm | | | 4,597 | | | | 5,158 | | | | 4,773 | |
| Industrial firm | | | 12,445 | | | | 15,006 | | | | 15,501 | |
| Interruptible | | | 148,799 | | | | 134,436 | | | | 145,942 | |
| Transportation | | | 1,501,739 | | | | 1,701,359 | | | | 1,722,113 | |
| Average revenue per customer: | | | | | | | | | | | | |
| Residential | | $ | 1,154 | | | $ | 1,126 | | | $ | 1,134 | |
| Commercial firm | | | 5,627 | | | | 6,022 | | | | 5,884 | |
| Industrial firm | | | 14,262 | | | | 16,383 | | | | 17,926 | |
| Interruptible | | | 141,986 | | | | 127,247 | | | | 151,819 | |
| Transportation | | | 92,959 | | | | 114,846 | | | | 110,533 | |
| Average revenue per therm sold: | | | | | | | | | | | | |
| Residential | | $ | 1.359 | | | $ | 1.302 | | | $ | 1.358 | |
| Commercial firm | | | 1.224 | | | | 1.168 | | | | 1.233 | |
| Industrial firm | | | 1.146 | | | | 1.092 | | | | 1.156 | |
| Interruptible | | | 0.954 | | | | 0.947 | | | | 1.040 | |
| Average retail revenue per therm sold | | | 1.289 | | | | 1.233 | | | | 1.292 | |
| Transportation | | | 0.062 | | | | 0.068 | | | | 0.064 | |
| Heating degree days | | | 4,897 | | | | 5,062 | | | | 4,823 | |
Percent of normal - NOAA 30-year average | | | 102.1 | % | | | 105.1 | % | | | 100.5 | % |
PSE purchases a portfolio of natural gas supplies ranging from long-term firm to daily from a diverse group of major and independent natural gas producers and marketers in the United States and Canada. PSE also enters into short-term physical and financial fixed-price derivative instruments to hedge the cost of natural gas to serve its customers. All of PSE’s natural gas supply is ultimately transported through the facilities of Williams Northwest Pipeline CorporationGP (NWP), the sole interstate pipeline delivering directly into western Washington. DeliveryPSE’s service territory. Accordingly, delivery of gas supply to PSE’s natural gas system is therefore dependent upon the reliable operations of NWP.
| | 2006 | | 2005 | |
| Peak Firm Gas Supply at December 31 | Dth per Day | | % | | Dth per Day | | % | |
| Purchased gas supply: | | | | | | | | |
| British Columbia | | 235,000 | | | 24.3 | % | | 205,400 | | | 22.1 | % |
| Alberta | | 60,000 | | | 6.2 | % | | 60,000 | | | 6.5 | % |
| United States | | 145,700 | | | 15.1 | % | | 167,800 | | | 18.1 | % |
| Total purchased gas supply | | 440,700 | | | 45.6 | % | | 433,200 | | | 46.7 | % |
| Purchased storage capacity: | | | | | | | | | | | | |
| Clay Basin | | 76,000 | | | 7.9 | % | | 45,200 | | | 4.9 | % |
| Jackson Prairie | | 55,100 | | | 5.7 | % | | 55,100 | | | 5.9 | % |
| AECO hub - Canada | | 16,700 | | | 1.7 | % | | 16,700 | | | 1.8 | % |
| Liquefied natural gas | | 70,500 | | | 7.3 | % | | 70,500 | | | 7.6 | % |
| Total purchased storage capacity | | 218,300 | | | 22.6 | % | | 187,500 | | | 20.2 | % |
| Owned storage capacity: | | | | | | | | | | | | |
| Jackson Prairie | | 294,700 | | | 30.5 | % | | 294,700 | | | 31.8 | % |
| Propane-air and other | | 12,500 | | | 1.3 | % | | 12,500 | | | 1.3 | % |
| Total owned storage capacity | | 307,200 | | | 31.8 | % | | 307,200 | | | 33.1 | % |
| Total peak firm gas supply | | 966,200 | | | 100 | % | | 927,900 | | | 100.0 | % |
| Other and commitments with third parties | | (44,400 | ) | | | | | (41,400 | ) | | | |
| Total net peak firm gas supply | | 921,800 | | | | | | 886,500 | | | | |
| | | 2009 | | | 2008 | |
| Peak Firm Natural Gas Supply at December 31 | | Dth per Day | | | % | | | Dth per Day | | | % | |
| Purchased gas supply: | | | | | | | | | | | | |
| British Columbia | | | 203,400 | | | | 21.3 | | | | 180,000 | | | | 19.7 | |
| Alberta | | | 78,400 | | | | 8.2 | | | | 75,000 | | | | 8.2 | |
| United States | | | 139,200 | | | | 14.6 | | | | 153,100 | | | | 16.8 | |
| Total purchased natural gas supply | | | 421,000 | | | | 44.1 | % | | | 408,100 | | | | 44.7 | % |
| Purchased storage capacity: | | | | | | | | | | | | | | | | |
| Clay Basin | | | 37,800 | | | | 3.9 | | | | 24,000 | | | | 2.6 | |
| Jackson Prairie | | | 64,700 | | | | 6.8 | | | | 48,400 | | | | 5.3 | |
| Plymouth liquefied natural gas | | | 70,500 | | | | 7.4 | | | | 70,500 | | | | 7.8 | |
| Total purchased storage capacity | | | 173,000 | | | | 18.1 | % | | | 142,900 | | | | 15.7 | % |
| Owned storage capacity: | | | | | | | | | | | | | | | | |
| Jackson Prairie | | | 348,700 | | | | 36.5 | | | | 348,700 | | | | 38.2 | |
| Propane-air and other | | | 12,500 | | | | 1.3 | | | | 12,500 | | | | 1.4 | |
| Total owned storage capacity | | | 361,200 | | | | 37.8 | % | | | 361,200 | | | | 39.6 | % |
| Total peak firm natural gas supply | | | 955,200 | | | | 100.0 | % | | | 912,200 | | | | 100.0 | % |
| Other and commitments with third parties | | | (15,400 | ) | | | | | | | (16,900 | ) | | | | |
| Total net peak firm natural gas supply | | | 939,800 | | | | | | | | 895,300 | | | | | |
All peak firm gas supplies and storage are connected to PSE’s market with firm transportation capacity.
For baseload and peak-shavingpeak management purposes, PSE supplements its firm gas supply portfolio by purchasing natural gas in off-peak periods, injecting it into underground storage facilities and withdrawing it during the peak winter heating season. Storage facilities at Jackson Prairie in western Washington and at Clay Basin in Utah are used for this purpose. Jackson Prairie is also used for daily balancing of load requirements on PSE’s gas system. Peaking needs are also metmet: by using PSE-owned natural gas held in NWP’s liquefied natural gas (LNG) facility atin Plymouth, Washington,Washington; by using PSE-owned natural gas held in PSE’s LNG peaking facility located within its distribution system in Gig Harbor, Washington; by producing propane-air gas at a plant owned by PSE and located on its distribution system,system; and by interrupting service to customers on interruptible service rates.
PSE expects to meet its firm peak-day requirements for residential, commercial and industrial markets through its firm natural gas purchase contracts, firm transportation capacity, firm storage capacity and other firm peaking resources. PSE believes it will be able to acquire incremental firm natural gas supply and capacity to meet anticipated growth in the requirements of its firm customers for the foreseeable future.
Gas Supply Portfolio
For the 2006-2007 winter heating season, PSE contractedDuring 2009, approximately 24.3% of its expected peak-day gas supply requirements from sources originating in British Columbia, Canada under a combination of long-term, medium-term and seasonal purchase agreements. Long-term gas supplies from Alberta represent approximately 6.2% of the peak-day requirements. Long-term and winter peaking arrangements with U.S. suppliers make up approximately 15.1% of the peak-day portfolio. The balance of the peak-day requirements is expected to be met with gas stored at Jackson Prairie, Clay Basin and AECO hub (AECO), LNG held at NWP’s Plymouth facility and propane-air and other resources, which represent approximately 36.2%, 7.9%, 1.7%, 7.3% and 1.3%, respectively, of expected peak-day requirements. PSE also has the ability to curtail service to industrial and commercial customers on interruptible service rates during a peak-day event. The December 2006 firm gas supply portfolio consisted of arrangements with 20 producers and gas marketers, with no single supplier representing more than 6.0% of expected peak-day requirements. Contracts have remaining terms ranging from less than 1 year to 8 years.
During 2006, approximately 37.9%36.0% of gas supplies purchased by PSE for its gas customers originated in British Columbia, while 18.4%18.0% originated in Alberta and 43.7%46.0% originated in the United States. PSE’s firm gas supply portfolio has adequate flexibility in its transportation arrangements so that someto enable it to achieve savings can be achieved when there are regional price differentials between gas supply basins. The geographic mix of suppliers and daily, monthly and annual take requirements permit some degree of flexibility in managing gas supplies during off-peak periods to minimize costs. Gas is marketed outside PSE’s service territory (off-system sales) whenever on-system customer demand requirements permit.
Natural Gas Storage Capacity
PSE holds storage capacity in the Jackson Prairie and Clay Basin underground natural gas storage facilities adjacent to NWP’s pipeline and at AECO in Alberta, Canada adjacent to Nova Gas Transmission, Ltd. (TransCanada-Alberta).serve PSE’s natural gas customers. These facilities represent 45.8%approximately 44.0% of the expected near-term peak-day portfolio.requirement. The Jackson Prairie facility is operated and one-third owned by PSE,PSE. The facility is used primarily for intermediate peaking purposes since it is able to deliver a large volume of natural gas over a relatively short time period. Combined with capacity contracted from NWP’s one-third stake in Jackson Prairie, PSE has peak firm deliverywithdrawal capacity in excess of over 349,000400,000 Dekatherms (one(a Dekatherm, or Dth, is equal to one million British thermal units or MMBtu) per day andday. PSE’s total firm storage capacity of over 8,600,000 Dth at the facility.facility is in excess of 9,000,000 Dth. The location of the Jackson Prairie facility in PSE’s market area increases supply reliability and provides significant pipeline demand cost savings by reducing the amount of annual pipeline capacity required to meet peak-day gas requirements. PSE has been in the process of expanding the storage capacity at Jackson Prairie since March 2003 and plans toits withdrawal capacity since June 2007. The most recent withdrawal capacity expansion was placed in service in November 2008 and the reservoir expansion activities will continue through 2008. At the end of this project, PSE will have added approximately 2,000,000 Dth of additional working storage capacity. In order to meet the growing peaking requirements in the region, PSE and other owners of Jackson Prairie obtained FERC authorization on February 5, 2007 to increase deliverability of the project from 884,000 Dth per day to 1,196,000 Dth per day. PSE’s share of this expansion, 104,000 Dth per day, is expected to cost $15.0 million and be in-service by November 2008.2012. The Clay Basin storage facility is a supply area storage facility that is used primarily to reduce portfolio costs through injections and withdrawalssupply management efforts that take advantage of market price volatility, and is also used for system reliability. PSE holds 13,400,000over 12,800,000 Dth of Clay Basin storage capacity and approximately 107,000 Dth per day of firm withdrawal capacity under two long-term contracts with remaining terms of 6three years and 13ten years. PSE has exchanged 2,000,000 DthNet of this Clay Basin capacity for 2,000,000 Dth of AECO storage capacity, which includes withdrawal capacity of 16,700 Dth per day and terminates March 31, 2008. After this exchange,releases, PSE’s maximum firm withdrawal capacity and total storage capacity at Clay Basin is over 76,00090,600 Dth per day and exceeds 11,000,00010,800,000 Dth, respectively. During 2009, PSE was able to permanently exchange certain of its firm Clay Basin withdrawal capacity and storage capacity for a comparable amount of more desirable firm Jackson Prairie withdrawal capacity and storage capacity with a third party.
Due to the recent expansion of Jackson Prairie storage withdrawal capacity and storage capacity, PSE’s natural gas storage resources are expected to exceed gas customer requirements for the next two or three years. Therefore, beginning in 2009, 50,000 Dth per day of natural gas storage withdrawal capacity and 500,000 Dth of natural gas storage capacity have been temporarily assigned to support PSE’s power portfolio, increasing natural gas supply reliability and facilitating intra-day dispatch of PSE’s natural gas-fired generation resources.
LNG and Propane-Air Resources
LNG and propane-air resources provide firm natural gas supply on short notice for short periods of time. Due to their typically high cost and slow cycle times, these resources are normally utilized as the supply of last resort in extreme peak-demand periods, typically lasting a fewduring the coldest hours or days. PSE has a long-term contractcontracts for LNG storage services of 241,700 Dth of PSE-owned gas as LNG at NWP’s Plymouth facility, which is approximately three and one-half day’s supply at a maximum daily deliverability of 70,500 Dth. At the Swarr vaporized propane-air station located in Renton, Washington, PSE owns storage capacity for approximately 1.5 million gallons of propane. TheThis propane-air injection facilities arefacility is capable of delivering the equivalent of 10,000 Dth of natural gas per day for up to twelve12 days directly into PSE’s distribution system.
In 2004, a 6,000 Dth capacity PSE owns and operates an LNG storagepeaking facility was completed in Gig Harbor. In 2006, PSE expandedHarbor, Washington, with total capacity of 10,600 Dth, which is capable of delivering the capacity to 10,600 Dth. The purposeequivalent of the facility is to provide a supplemental supply2,500 Dth of natural gas during periods of high demand, improve overall system reliability and eliminate the need for portable LNG operations in the Gig Harbor area.per day.
Natural Gas Transportation Capacity
PSE currently holds firm transportation capacity on pipelines owned by NWP, Gas Transmission Northwest (a(GTN), Nova Gas Transmission (NOVA), Foothills Pipe Lines (Foothills) and Westcoast Energy (Westcoast). GTN, NOVA, and Foothills are all TransCanada company, “GTN”), TransCanada Pipelines, Ltd. (TransCanada) and Westcoast.companies. Accordingly, PSE pays fixed monthly demand charges for the right, but not the obligation, to transport specified quantities of natural gas from receipt points to delivery points on such pipelines each day for the term or terms of the applicable agreements.
PSE and WNG CAP I, a wholly-owned subsidiary of PSE, holdholds firm year-round capacity on NWP through various contracts. PSE and WNG CAP I participateparticipates in the secondary pipeline capacity market to achieve savings for PSE’s customers. PSE and WNG CAP I holdholds approximately 520,000 Dth per day of capacity for its natural gas customers on NWP that provides firm delivery to PSE’s service territory. In addition, PSE holds approximately 413,000524,000 Dth per day of seasonal firm capacity on NWP to provide for delivery of natural gas stored in Jackson Prairie and the Plymouth LNG facility during the heating season. PSE has firm transportation capacity on NWP through various contracts that supplies the Frederickson 1supply electric generating facilityfacilities with approximately 22,000112,000 Dth per day, with a remaining term of 12 years.day. PSE has released certain segments of its firm capacity withto third parties to effectively lower transportation costs. PSE’s firm transportation capacity contracts with NWP have remaining terms ranging from 1less than one year to 1035 years. However, PSE has either the unilateral right to extend the contracts under theirthe contracts’ current terms or the right of first refusal to extend such contracts under current FERC orders.rules. PSE’s firm transportation capacity on GTN’s pipeline, totaling approximately 90,000 Dth per day, has a remaining term of 1714 years.
PSE’s firm transportation capacity for its gas customers on Westcoast’s pipeline is approximately 97,000127,000 Dth per day until October 31, 2012, then approximately 86,000 Dth per day until October 31, 2014, then approximately 41,000 Dth per day until October 31, 2017 and thereafter approximately 15,000 Dth per day until October 31, 2018.under various contracts, with remaining terms of three to nine years. PSE has other firm transportation capacity on Westcoast’s pipeline, which supplies the Frederickson 1electric generating facility,facilities, totaling approximately 22,00047,000 Dth per day, with a remaining termterms of 8five to nine years. PSE has firm capacity on TransCanada’s Alberta and British Columbia transportation systems, totaling approximately 80,000 Dth per day. PSE has annual rollover rights for this capacity. In addition, PSE has firm transportation capacity on TransCanada’sNOVA and Foothills pipelines, commencing in 2008 withtotaling approximately 80,000 Dth per day, a portion of which has a remaining term of 15 years, totaling approximately 8,000 Dth per day.14 years. PSE has annual renewal rights on the remainder of this capacity.
Capacity Release
FERC provided a capacityregulates the release mechanism as the means for holders of firm pipeline and storage entitlementscapacity for facilities which fall under its jurisdiction. Capacity releases allow shippers to temporarily or permanently relinquish unutilized capacity to others in order to recouprecover all or a portion of the cost of such capacity. Capacity mayFERC allows capacity to be released through several methods including open bidding and by pre-arrangement. PSE continueshas acquired some firm pipeline and storage service through capacity release provisions to successfully mitigateserve its growing service territory and electric generation portfolio. PSE also mitigates a portion of the demand charges related to bothunutilized storage and pipeline capacity not utilized during off-peak periods through capacity release. PSE also utilizes capacity release mechanisms to acquire additional assets to serve its growing service territory. WNG CAP I, a PSE subsidiary, provides additional flexibility and benefits from capacity release transactions. Capacity release benefits derived from the gas customer portfolio are passed on to PSE’s natural gas customers through the PGA mechanism.
PSE is required under Washington state law to pursue cost-effective reductions in electric power consumption. PSE offers programs designed to help new and existing residential, commercial and industrial customers use energy efficiently. PSE uses a variety of mechanisms including cost-effective financial incentives, information and technical services to enable customers to make energy-efficientenergy efficient choices with respect to building design, equipment and building systems, appliance purchases and operating practices. EnergyAs described below, PSE recovers the actual costs of electric and gas energy efficiency programs reduce customerthrough a tracker mechanism (for gas) and a tariff rider mechanism (for electric) so that these expenditures have no impact on earnings. However, the tariff mechanism does not provide for the cost recovery of lost sales margin associated with reduced energy sales.
PSE’s rates are designed to capture most of the approved revenue requirements for fixed costs through volumetric rates. PSE fully recovers these costs only if its customers consume a certain level of gas and electricity. This level of consumption is typically established in the utility’s most recently completed rate case based upon historical gas and electric volumes. When customers use less gas or electricity, whether due to conservation, weather or economic conditions, PSE’s financial performance suffers because recovery of energy thus reducing energy margins. The impactfixed costs is reduced in proportion to the reduction in gas or electric sales.
As part of load reductions is adjusted in rates at eachPSE’s 2006 general rate case.
PSE's two-yearcase, the Washington Commission authorized a three-year pilot program, allowing PSE to earn an incentive on electric conservation savings goalsif PSE exceeds annual baseline savings. These targets are set based onreached through a collaborative process between PSE and the Integrated Resource Plan and in conjunction with the Conservation Resource Advisory Group per(CRAG). This pilot program expired on December 31, 2009. As required by the termsCommission’s order approving the incentive, PSE, in consultation with the CRAG, is currently evaluating the pilot incentive program.
Since 1995, PSE has been authorized by the Washington Commission to defer natural gas energy efficiency (or conservation) expenditures and recover them through a tariff tracker mechanism. The tracker mechanism allows PSE to defer efficiency expenditures and recover them in rates over the subsequent year. The tracker mechanism also allows PSE to recover an allowance for funds used to conserve energy on any outstanding balance that is not currently being recovered in rates. As a result of the 2002 Conservation Stipulation Agreement. For 2004-2005, the minimum savings goals for the two-year period to avoid a “penalty”tracker mechanism, were set at 23.2 average MW and 3.5 million therms while the “stretch” goals were set at 39.2 average MW and 5 million therms. PSE achieved 39.34 average MW and 6 million therms of cost-effectivenatural gas energy savings during the two-year timeframe, exceeding its goals.
For 2006-2007, the sum of the annual savings goals for the two-year period is set at 33 average MW and 3.4 million therms. If conservation savings are less than 75.0% of the minimum goal, PSE will be subject to a penalty of $0.8 million. If savings are between 75.0% and 89.0% of the minimum, the penalty is $0.5 million, and between 90.0% and 99.0% of the minimum, the penalty is $0.2 million. Actual results through December 31, 2006 for the 2006-2007 period are 18.98 average MWs and 2.4 million therms.efficiency expenditures have no impact on earnings.
Since May 1997, PSE has recovered direct electric energy efficiency (or conservation) expenditures through a tariff rider mechanism. The rider mechanism allows PSE to defer the efficiency expenditures and amortize them to expense as PSE concurrently collects the efficiency expenditures in rates over a one-year period. As a result of the rider mechanism, direct electric energy efficiency expenditures have no effect on earnings.are recovered.
Since 1995, PSE has been authorized by the Washington Commission to defer gas energy efficiency (or conservation) expenditures and recover them through a tariff tracker mechanism. The tracker allows PSE to defer efficiency expenditures and recover them in rates over the subsequent year. The tracker also allows PSE to recover an allowance for funds used to conserve energy on any outstanding balance that is not being recovered in rates. As a result of the tracker mechanism, gas energy efficiency expenditures have no impact on earnings.
The Company’sPSE’s operations are subject to environmental laws and regulation by federal, state and local authorities. Due to the inherent uncertainties surrounding the development of federal and state environmental and energy laws and regulations, the Company cannotPSE may not determine the impact, if any, that changes in such laws may have on its existing and future facilities.facilities and operations.
Greenhouse Gas Policy
PSE recognizes the growing concern that increased atmospheric concentrations of greenhouse gases (GHG) contribute to climate change. PSE believes that climate change is a veryan important issue that requires careful analysis and considered responses. PSE’s policy is to takeencourage the use of cost-effective measuresmarket mechanisms to mitigate and/or offset greenhouse gasGHG emissions from ourits energy activities while maintainingactivities. PSE advocates for market and regulatory mechanisms that will ensure price discovery and facilitate planning in a way that will help maintain a dependable, cost-effective and diverse energy portfolio mix that will sustain our customers’ needs now and into the future. However, PSE is takingbelieves market mechanisms are not enough and governments must formulate active strategies to invent and demonstrate new large-scale, low-emissions technologies and energy systems. Properly designed market mechanisms can be useful in leveraging ways that will continueaccelerate the adoption of new technologies through research, development and deployment, preferential treatment and appropriate price signaling, but they cannot be the only mechanisms. PSE also believes the United States cannot do this alone. Industrialized nations must find ways to engage emerging countries in carbon reduction. In the meantime, PSE continues to take appropriate steps to meet the goal of providing cost-effective and reliable energy while decreasing the impact on climate change through the implementation of these measures.energy. The fullcomplete PSE Greenhouse Gas Policy is available at www.pse.com.
Regulation Of Emissions
PSE facilities, including PSE’s interest in a coal-fired, steam-electric generating plant at Colstrip, Montana and its gas-fired combustion turbine units, are subject to regulation of emissions, including PSE’s interest in coal-fired, steam-electric generating plants at Colstrip, Montana and its combustion turbine units. There is no assurance that futureemissions. Future environmental laws and regulations affecting emissions, including sulfur dioxide, carbon monoxide, particulate matter, mercury or nitrogen oxide emissions, will notmay be more restrictive, or thatand new restrictions on greenhouse gasGHG emissions, such as carbon dioxide, or otherand coal combustion byproducts, such as mercury,wastes, may not be imposed at the federal or state level. Future legislation and regulation may have a significant impact on the cost of carbon-intensive coal generation, in particular.
In June 2008, the Washington Department of Ecology adopted regulations implementing an Emissions Performance Standard of 1,100 lbs/MWh. Under these regulations, utility companies that enter into long-term financial commitments to purchase all, or an interest in, new facilities or enter into power purchase agreements, among other things, must comply with this standard. Facilities owned by PSE on or before July 1, 2008 are not subject to this standard. A PSE evaluation of facilities that were acquired after July 1, 2008, including Mint Farm, showed that it was compliant with the standard in its current operating configurations and no additional modifications are required. Future resource planning and resource acquisition decisions will take this regulation into account.
Climate policy continues to evolve at the state and federal levels. PSE remains involved in state, regional and federal policymaking activities that involve emissions and climate change. PSE is also monitoring the development of the commercial marketplace for the exchange of carbon attributes. PSE anticipates that additional proposals will come from state and federal legislators in 2010 and beyond. In 2009, PSE made multiple submittals to the Western Climate Initiative (WCI) to provide its recommendations on the WCI design proposals, and it has participated in stakeholder committee groups and will continue this effort. PSE will also factor the impact of any future legislation on the cost of generation through its Integrated Resource Plan process.
On June 26, 2009, the House of Representatives passed H.R. 2454, the American Clean Energy and Security Act (ACES), a bill that would implement a cap-and-trade system of allowances to reduce GHG emissions 17.0% below 2005 levels by 2020, reaching an eventual target of 83.0% below 2005 levels by 2050. The Senate may also take climate change legislation back up in the first half of 2010.
The EPA issued two key “endangerment findings” under the Clean Air Act in December 2009. These two findings are: 1) the current and projected atmospheric concentrations of six GHGs endanger the public health and welfare of current and future generations; and 2) the combined emissions of these GHGs from new motor vehicles in the United States contribute to global climate change. These findings appear to set the agency on course for regulating GHG emissions throughout 2010.
Establishing GHGs as a pollutant means the six gases will become subject to regulation that triggers the Prevention of Significant Deterioration (PSD) program, under which new or modified “major emitting facilities” must obtain certain permits and install “Best Available Control Technology.” The impacts of this development are still unclear. Under current Clean Air Act protocols, new and modified sources of emissions must be fitted with air emission controls that are commercially (and readily) available however such controls for GHGs do not exist today.
In December 2009, signatories of the Kyoto Protocol met in Copenhagen to discuss next steps after that treaty expires at the end of 2012. The results from those negotiations include first-time emission reduction commitments from major developing countries, terms for financial assistance for least-developed countries and significant progress to develop policies to reduce emissions from deforestation and degradation. However, these terms are not binding, and it remains to be seen how they may be implemented in United States law.
There is significant uncertainty about when and how GHG emissions will ultimately be regulated at the federal, state or regional level. Nevertheless, it appears possible that some form of regulation will be adopted in the future, and such regulation is likely to make carbon-intensive electric generation, such as coal-fired generation, more expensive. Until more is known about future regulation, it is impossible to predict how it will affect PSE's future cost of doing business.
Emissions Inventory
During 2006,2009, PSE’s total electric retail load of 21,099,045 MWh21.9 million megawatt hours (MWh) was served from a supply portfolio of owned and purchased resources. Since 2002, PSE has voluntarily undertaken an inventory of its greenhouse gas (GHG)GHG emissions associated with this portfolio. Such inventory follows the protocol established by the World Resource Institute GHG Protocol (GHG Protocol).Protocol. The most recent data indicate that PSE’s total GHG emissions (direct and indirect) from its electric supply portfolio in 20052008 were 12,999,05112.3 million tons (CO2e).of carbon dioxide equivalent. Since 2008, new generation facilities have resulted in combined GHG emissions of 88,216 tons of carbon dioxide equivalent. Approximately 54.3%52.0% of thesePSE’s total GHG emissions (approximately 7,058,3136.4 million tons) are associated with PSE’s ownership and contractual interests in Colstrip.
New rules enacted by the 2,200 MWWashington State Department of Ecology (Ecology) and by the EPA will require PSE to report its GHG emissions. The Ecology rule obligates PSE to report certain emissions that were produced in 2009 by October 31, 2010. The EPA rule requires reporting beginning with emissions from 2010 by March 31, 2011. Equipment modifications will not be required at this time at Colstrip Montana coal-fired steam electric generation facility (the “Facility”).or at any of PSE’s combustion turbines as a result of these reporting rules.
Colstrip is a significant part of the diversified portfolio PSE owns and/or operates for its customers. Consequently, while Colstrip remains a significant portion of our overallits GHG emissions, PSE’s overall emissions strategy demonstrates a concerted effort to manage our customers’ needs with an appropriate balance of new renewable generation, existing generation owned and/or operated by PSE and significant energy efficiency efforts.
With ongoing development of state and federal initiatives intended to address climate change, the challenge to develop strategic solutions is more complicated than ever. However, PSE believes that now is the time to act. Consequently it is PSE’s intent to incorporate into the IRP a long-term strategic goal that will adhere to the objectives of our recently published Greenhouse Gas Policy.
On May 18, 2005, the Environmental Protection Agency (EPA) enacted the Clean Air Mercury Rule (CAMR) that will permanently cap and reduce mercury emissions from coal-fired power plants. Colstrip Emission Controls
The Montana Board of Environmental Review approved a more stringentMontana mercury control rule to limit mercury emissions from coal-fired plants on October 16, 2006 (0.9(with limits of 0.9 lbs/TBtu, instead of the federal 1.4 lbs/TBtu). The Colstrip owners are still evaluating the potential impact of the new rule and it is still unknown whether the new rule will be appealed. Preliminary treatment technology studies undertaken bytrillion British thermal units for plants burning coal like that used at Colstrip) which became effective on January 1, 2010. In 2008, the Colstrip owners, estimatebased on testing performed in 2006, 2007 and 2008, ordered mercury control equipment intended to achieve the new limit. Installation of this equipment has been completed and is in operation. Depending on actual long-term performance, an evaluation will be conducted to determine whether additional controls, if any, are necessary.
On June 15, 2005, 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 PSE’s portionColstrip Units 1 & 2 were determined to be subject to EPA’s BART requirements. PSE submitted a BART engineering analysis for Colstrip Units 1 & 2 in August 2007 and responded to an EPA request for additional analyses with an addendum in June 2008. PSE cannot yet determine the need for or costs of the costsadditional controls to comply with the new rule could be as much as $75.0 million in construction expenditures; this number could change as new information becomes available.
In December 2003, the EPA issued an Administrative Consent Order (ACO) which alleged violation of the Clean Air Act permit requirement to submit, for review and approval by the EPA, an analysis and proposal for reducing emissions of nitrogen oxide to address visibility concerns upon the occurrence of certain triggering events which EPA asserts occurred in 1980. Although Colstrip owners believe that the ACO is unfounded, the Colstrip owners signed a settlement agreement in December 2006 that is now awaiting signature by EPA, and then will be entered by the court. The agreement includes installation of low nitrogen oxide equipment installation on Colstrip Units 3 & 4 which will cost PSE approximately $2.65 million.rule.
Federal Endangered Species Act
Since 1991, a total of thirteen17 species of Northwest and Columbia River Basin salmon and steelhead have been listed as threatened or endangered species under the Endangered Species Act, which influences hydroelectric operations. While the most significant impacts have affected the Mid-Columbia PUDs, certain ESAEndangered Species Act impacts may affect PSE operations, potentially representing cost exposure and operational constraints. PSE is actively engaging theengaged with federal agencies to address Endangered Species Act issues for PSE’s generating facilities.
The executive officers of Puget Energy as of December 31, 20062009 are listed below. Forbelow along with their business experience during the past five years, please refer to the table below regarding Puget Sound Energy’s executive officers.years. Officers of Puget Energy are elected for one-year terms.
Name | Age | Offices |
| S. P. Reynolds | 5861 | President and Chief Executive Officer since February 2009; Chairman, President and Chief Executive Officer since May 2005;2005 – 2009; President and Chief Executive Officer, 2002 -– 2005. Director since January 2002. |
| J. W. Eldredge | 5659 | Vice President, Controller and Chief Accounting Officer since May 2007; Vice President, Corporate Secretary and Chief Accounting Officer since May 2005;2005 – 2007; Corporate Secretary and Chief Accounting Officer 1999 -– 2005. |
| D. E. Gaines | 4952 | Vice President Finance and Treasurer since March 2002. |
| E. M. Markell | 58 | Executive Vice President and Chief Financial Officer since May 2007; Senior Vice President Energy Resources 2003 – 2007. |
| J. L. O’Connor | 5053 | Senior Vice President, General Counsel, Corporate Secretary and Chief Ethics and Compliance Officer since May 2007; Senior Vice President, General Counsel, Chief Ethics and Compliance Officer since October 2005;2005 - 2007; Vice President and General Counsel, 2003 - 2005. |
B. A. Valdman | 43 | Senior Vice President Finance and Chief Financial Officer since January 2004. |
The executive officers of Puget Sound EnergyPSE as of December 31, 20062009 are listed below along with their business experience during the past five years. Officers of Puget Sound EnergyPSE are elected for one-year terms.
Name | Age | Offices |
| S. P. Reynolds | 5861 | President and Chief Executive Officer since February 2009; Chairman, President and Chief Executive Officer since May 2005;2005 – 2009; Director since January 2002; President and Chief Executive Officer 2002 - 2005; President and Chief Executive Officer of Reynolds Energy International, 1998 - 2002. |
D. P. Brady | 42 | Senior Vice President Customer Service, Information Technology and Chief Information Officer since October 2005; Vice President Customer Services 2003 - 2005; Director and Assistant to Chief Operating Officer, 2002 - 2003. Prior to joining PSE, he was Managing Director of Irvine Associates Merchant Banking Group, 2001 - 2002. |
P. K. Bussey | 50 | Senior Vice President Corporate Affairs since October 2005; Vice President Regional and Public Affairs, 2003 -– 2005. Prior to joining PSE, he was President of the Washington Round Table, 1996 - 2003. |
| J. W. Eldredge | 5659 | Vice President, Controller and Chief Accounting Officer since May 2007; Vice President, Corporate Secretary, Controller and Chief Accounting Officer since May 2001.2001 – 2007. |
| D. E. Gaines | 4952 | Vice President Finance and Treasurer since March 2002; Vice President and Treasurer, 2001 - 2002. |
| K. J. Harris | 4245 | Executive Vice President and Chief Resource Officer since May 2007; Senior Vice President Regulatory Policy and Energy Efficiency since October 2005;2005 – 2007; Vice President Regulatory and Government Affairs 2003 -– 2005; Vice President Regulatory Affairs 2002 - 2003; Director Load Resource Strategies and Associate General Counsel, 2001 - 2002.– 2003. |
| E. M. Markell | 5558 | Executive Vice President and Chief Financial Officer since May 2007; Senior Vice President Energy Resources since February 2003; Vice President Corporate Development, 2002 - 2003. Prior to joining PSE, he was Chief Financial Officer, Club One, Inc., 2000 - 2002. |
S. McLain | 50 | Senior Vice President Operations since February 2003; Vice President Operations - Delivery, 1999 - 2003. |
M. D. Mellies | 46 | Vice President Human Resources since October 2005. Prior to joining PSE, she was General Manager of Human Resources at Microsoft, 2002 - 2005.2003 – 2007. |
| J. L. O’Connor | 5053 | Senior Vice President, General Counsel, Corporate Secretary and Chief Ethics and Compliance Officer since May 2007; Senior Vice President, General Counsel, Chief Ethics and Compliance Officer since October 2005;2005 – 2007; Vice President and General Counsel 2003 -– 2005. Prior to joining PSE, she was interim General Counsel, Starbucks Corporation, 2002; Senior Vice President and Deputy General Counsel, Starbucks Corporation, 2001 - 2002. |
C. E. Shirley | 53 | Vice President Energy Efficiency Services since October 2005; Director Energy Efficiency Services, 2002 - 2005. Prior to joining PSE, he was Senior Manager of Energy Services for Snohomish County Public Utility District, 1995 - 2002. |
| B. A. Valdman | 4346 | Executive Vice President and Chief Operating Officer since May 2007; Senior Vice President Finance and Chief Financial Officer since December 2003. Prior to joining PSE, he was Managing Director with JP Morgan Securities, Inc., 2000 - 2003. |
P. M. Wiegand | 54 | Vice President Project Development and Contract Management since July 2003; Vice President Corporate Planning, 2003; Vice President Corporate Planning and Performance, 2002 - 2003; Vice President Risk Management and Strategic Planning, 2000 - 2002.2003 – 2007. |
The following risk factors, in addition to other factors and matters discussed elsewhere in this report, should be carefully considered. The risks and uncertainties described below are not the only risks and uncertainties that Puget Energy and PSE may face. Additional risks and uncertainties not presently known or currently deemed immaterial also may impair PSE’s business operations. If any of the following risks actually occur, Puget Energy’s and PSE’s business, results of operations and financial conditions would suffer.
RISKS RELATING TO THE UTILITYPSE's BUSINESS
The actions of regulators can significantly affect PSE’s earnings, liquidity and business activities.
The rates that PSE is allowed to charge for its services is the single most important item influencing its financial position, results of operations and liquidity. PSE is highly regulated and the rates that it charges its wholesale and retail customers are determined by both the Washington Commission.Commission and FERC.
PSE is also subject to the regulatory authority of the Washington Commission with respect to accounting, operations, the issuance of securities and certain other matters, and the regulatory authority of FERC with respect to the transmission of electric energy, the resalesale of electric energy at wholesale, accounting and certain other matters. Policies and regulatory actions by these regulators could have a material impact on PSE’s financial position, results of operations and liquidity.
PSE’s recovery of costs is subject to regulatory review and its operating income may be adversely affected if its costs are disallowed or recovery is delayed. disallowed.
The Washington Commission determines the rates PSE may charge to its electric retail customers based in part on ahistoric test year costs plus weather normalized cost of producing power.assumptions about rate year hydro conditions and power costs. Non-energy costs for natural gas retail customers are based on historic test year costs. If in a specific year PSE’s costs are higher than normal,what is allowed to be recovered in rates, willrevenues may not be sufficient to permit PSE to earn theits allowed return or to cover its costs and recovery of energy costs will be deferred until subsequent ratemaking proceedings.costs. In addition, the Washington Commission decides what level of expense and investment is reasonable and prudent in providing electric and natural gas service. If the Washington Commission decides that part of PSE’s costs do not meet the standard, those costs may be disallowed partially or entirely and not recovered in rates. For these reasons, the rates authorized by the Washington Commission may not be sufficient to earn the allowed return or recover the costs incurred by PSE in a given period.
The PCA mechanism, by which variations in PSE’s power costs are apportioned between itPSE and its customers pursuant to a graduated scale, could experienceresult in significant increaseincreases in expenses. PSE’s expenses if power costs are significantly higher than the baseline rate.
PSE has a PCAPower Cost Adjustment (PCA) mechanism that provides for recovery of power costs from customers or refunding of power cost savings to customers, as those costs vary from the “power cost baseline” level of power costs which are set, in part, based on normalized assumptions about weather and hydro conditions. Excess power costs or power cost savings will be apportioned between PSE and its customers pursuant to the graduated scale set forth in the PCA mechanism without operation of any cap. mechanism. As a result, if power costs are significantly higher than the baseline rate, PSE’s expenses could significantly increase.
PSE may be unable to acquire energy supply resources to meet projected customer needs or may fail to successfully integrate such acquisitions.
PSE projects that future energy needs will exceed current purchased and Company-controlled power resources. As part of PSE’s business strategy, it plans to acquire additional electric generation and delivery infrastructure to meet customer needs. If PSE cannot acquire further additional energy supply resources at a reasonable cost, it may be required to purchase additional power in the open market at a cost that could significantly increase its expenses and reduce earnings and cash flows. Additionally, PSE may not be able to timely recover some or all of those increased expenses through ratemaking.
While PSE expects to identify the benefits of new energy supply resources prior to their acquisition and integration, it may not be able to achieve the expected benefits of such energy supply sources.
The Company’sPSE’s cash flow and earnings could be adversely affected by potential high prices and volatile markets for purchased power, increased customer demand for energy, recurrence of low availability of hydroelectric resources, outages of its generating facilities or a failure to deliver on the part of its suppliers.
The utility business involves many operating risks. If PSE’s operating expenses, including the cost of purchased power and natural gas, significantly exceed the levels recovered from retail customers, for an extended period of time, its cash flow and earnings would be negatively affected. Factors which could cause purchased power and natural gas costs to be higher than anticipated include, but are not limited to, high prices in western wholesale markets during periods when PSE has insufficient energy resources to meet its load requirements and/or high volumes of energy purchased in wholesale markets at prices above the amount recovered in retail rates due to:
| | · | Increases in demand due, for example, either to weather or customer growth; |
| | · | Below normal energy generated by PSE-owned hydroelectric resources due to low streamflow conditions;conditions or precipitation; |
| | · | Extended outages of any of PSE-owned generating facilities or the transmission lines that deliver energy to load centers; |
| | · | Failure to perform on the part of any party from which PSE purchases capacity or energy; and |
| | · | The effects of large-scale natural disasters such as the hurricanes recently experienced in the southern United States.on a substantial portion of distribution infrastructure. |
PSE’s electric generating facilities are subject to operational risks that could result in unscheduled plant outages, unanticipated operation and maintenance expenses and increased power purchase costs.
PSE owns and operates coal, natural gas-fired, hydro,hydroelectric, wind-powered and oil-fired generating facilities. Operation of electric generating facilities involves risks that can adversely affect energy output and efficiency levels. Included among these risks are:
| | · | Increased prices for fuel and fuel transportation as existing contracts expire; |
| | · | Facility shutdowns due to a breakdown or failure of equipment or processes or interruptions in fuel supply; |
| | · | Disruptions in the delivery of fuel and lack of adequate inventories; |
| | · | Labor disputes; |
| | · | Inability to comply with regulatory or permit requirements; |
| | · | Disruptions in the delivery of electricity; |
| | · | Operator error;error or safety related stoppages; |
| | · | Terrorist attacks; and |
| | · | Catastrophic events such as fires, explosions, floods or other similar occurrences. |
PSE is subject to the commodity price, delivery and credit risks associated with the energy markets.
In connection with matching loads and resources, PSE engages in wholesale sales and purchases of electric capacity and energy, and, accordingly, is subject to commodity price risk, delivery risk, credit risk and other risks associated with these activities. Credit risk includes the risk that counterparties owing PSE money or energy will breach their obligations. Should the counterparties to these arrangements fail to perform, PSE may be forced to enter into alternative arrangements. In that event, PSE’s financial results could be adversely affected. Although PSE’s models takePSE takes into account the expected probability of default by counterparties, the actual exposure to a default by a particular counterparty could be greater than the models predict.predicted.
To lower its financial exposure related to commodity price fluctuations, PSE may use forward delivery agreements, swaps and option contracts to hedge commodity price risk with a diverse group of counterparties. However, PSE does not always cover the entire exposure of its assets or positions to market price volatility, and the coverage will vary over time. To the extent PSE has unhedged positions or its hedging procedures do not work as planned, fluctuating commodity prices could adversely impact its results of operations.
Conditions that may be imposed in connection with hydroelectric license renewals may require large capital expenditures and reduce earnings and cash flows.
PSE is in the process of renewing the federal licenses for its Baker River hydroelectric project and implementing the federal licensing requirements for the Snoqualmie Falls hydroelectric project. The relicensing process is a political and public regulatory process that involves sensitive resource issues. PSE cannot predict with certainty the conditions that may be imposed during the relicensing process, the economic impact of those requirements, whether new licenses will ultimately be issued, modified, or whether PSE will be willing to meet the relicensing requirements to continue operating these hydroelectric projects.
Costs of compliance with environmental, climate change and endangered species laws are significant and the cost of compliance with new environmental or endangered speciesand emerging laws and regulations and the incurrence of environmentalassociated liabilities could adversely affect PSE’s results of operations.
PSE’s operations are subject to extensive federal, state and local regulationlaws and regulations relating to environmental, climate change and endangered species protection. To comply with these legal requirements, PSE must spend significant sums on environmental and endangered speciesmeasures including resource planning, remediation, monitoring, analysis, mitigation measures, pollution control equipment and emissionemissions related abatement and fees. New environmental, climate change, emissions and endangered species laws and regulations affecting PSE’s operations may be adopted, and new interpretations of existing laws and regulations could be adopted or become applicable to PSE or its facilities which may substantially increase environmental, climate change, emissions and endangered species expenditures made by itPSE in the future. Compliance with these or other future regulations could require significant capital expenditures by PSE and adversely affect PSE’s financial position, results of operations, cash flows and liquidity. In addition, PSE may not be able to recover all of its costs for environmentalsuch expenditures through electric and natural gas rates at current levels in the future.
With respect to endangered species laws, the listing or proposed listing of several species of salmon in the Pacific Northwest is causing a number of changes to the operations of hydroelectric generating facilities on Pacific Northwest rivers, including the Columbia River. These changes could reduce the amount, and increase the cost, of power generated by hydroelectric plants owned by PSE or in which PSE has an interest and increase the cost of the permitting process for these facilities.
Under current law, PSE is also generally responsible for any on-site liabilities associated with the environmental condition of the facilities that it currently owns or operates or has previously owned or operated, regardless of whether the liabilities arose before, during or after the time the facility was owned or operated. The incurrence of a material environmental liability or the new regulations governing such liability could result in substantial future costs and have a material adverse effect on PSE’s results of operations and financial condition.
Specific to climate change, Washington State has adopted both a renewable portfolio standard and greenhouse gas legislation, including an emission performance standard provision. PSE cannot yet determine the costs of compliance with the recently enacted legislation. Recent decisions related to climate change by the United States Supreme Court and EPA, together with efforts by Congress have drawn greater attention to this issue at the federal, state and local level. While PSE cannot yet determine costs associated with these or future decisions or potential future legislation, there may be a significant impact on the cost of carbon-intensive coal generation, in particular.
The Company’s
PSE’s business is dependent on its ability to successfully access capital markets. capital.
The CompanyPSE relies on access to bothbank borrowings and short-term money markets as a sourcesources of liquidity and longer-term capitaldebt markets to fund its utility construction program and other capital expenditure requirements not satisfied by cash flow from its operations.operations or equity investment from its parent, Puget Energy. If the CompanyPSE is unable to access capital at competitive rates,on reasonable terms, its ability to pursue improvements or acquisitions, including generating capacity, which may be relied on for future growth and to otherwise implement its strategy, could be adversely affected.
Certain Capital and credit market disruptions, or a downgrade of the Company’sPSE’s credit rating or the imposition of restrictions on borrowings under its credit facility in the event of a deterioration of financial ratios, may increase the Company’sPSE’s cost of borrowing or adversely affect the ability to access one or more financial markets.
PSE’s operating results fluctuate on a seasonal and quarterly basis.
PSE’s business is seasonal and weather patterns can have a material impact on its revenues, expenses and operating results. Because natural gas is heavily used for residential and commercial heating, demand depends heavily on weather patterns in PSE’s service territory, and a significant amount of natural gas revenues are recognized in the first and fourth quarters related to the heating season. However, conservation efforts may result in decreased customer demand, despite normal or lower than normal temperatures. Demand for electricity is also greater in the winter months associated with heating. Accordingly, PSE’s operations have historically generated less revenues and income when weather conditions are milder in the winter. In the event that the Company experiences unusually mild winters, results of operations and financial condition could be adversely affected.
PSE may be adversely affected by extreme events in which PSE is not able to promptly respond and repair the electric and gas infrastructure system.
PSE must maintain an emergency planning and training program to allow PSE to quickly respond to extreme events. Without emergency planning, PSE is subject to availability of outside contractors during an extreme event which may impact the quality of service provided to PSE’s customers. In addition, a slow response to extreme events may have an adverse affect on earnings as customers may be without electricity and natural gas for an extended period of time.
PSE may be negatively affected by its inability to attract and retain professional and technical employees.
PSE’s ability to implement a workforce succession plan is dependent upon PSE’s ability to employ and retain skilled professional and technical workers in an aging workforce. Without a skilled workforce, PSE’s ability to provide quality service to PSE’s customers and meet regulatory requirements will be challenged and could affect earnings.
PSE depends on an aging work force and third party vendors to perform certain important services.
PSE continues to be concerned about the availability and aging of skilled workers for special complex utility functions. PSE also hires third parties to perform a variety of normal business functions, such as power plant maintenance, data warehousing and management, electric transmission, electric and gas distribution construction and maintenance and certain billing and metering processes. The unavailability of skilled workers or unavailability of such vendors could adversely affect the quality and cost of PSE’s gas and electric service and accordingly PSE’s results of operations.
Poor performance of pension and postretirement benefit plan investments and other factors impacting plan costs could unfavorably impact PSE’s cash flow and liquidity.
PSE provides a defined benefit pension plan to PSE employees and postretirement benefits to certain PSE employees and former employees. Costs of providing these benefits are based in part on the value of the plan’s assets and therefore, continued adverse market performance could result in lower rates of return for the investments that fund PSE’s pension and postretirement benefits plans and could increase PSE’s funding requirements related to the pension plans. Any contributions to PSE’s plans in 2009 and beyond and the timing of the recovery of such contributions in general rate cases could impact PSE’s cash flow and liquidity.
RISKS RELATING TO PUGET ENERGY AND PSE OPERATIONS
A downgrade in the Company’sPuget Energy’s or PSE’s credit rating could negatively affect itstheir ability to access capital and the ability to hedge in wholesale markets.
Standard and& Poor’s (S&P) and Moody’s Investor Services (Moody’s) rate PSE’s senior secured debt at “BBB”“A-” with a stable outlook and “Baa2”“Baa1” with a stable outlook, respectively. Although the Company is not aware of any current plans of S&P or Moody’s to lower their respective ratings on PSE’s debt, the Company cannot be assured that such credit ratings will not be downgraded.
Although neither Puget Energy nor PSE has any rating downgrade provisions in its credit facilities that would accelerate the maturity dates of outstanding debt, a downgrade in the Companies’ credit ratings could adversely affect their ability to renew existing or obtain access to new credit facilities and could increase the cost of such facilities. For example, under Puget Energy’s and PSE’s revolving credit facility,facilities, the borrowing spreads over the indexLondon Interbank Offered Rate (LIBOR) and commitment feefees increase as PSE’sif their respective corporate credit ratings decline. A downgrade in commercial paper ratings could increase the cost of commercial paper and limit or preclude PSE’s ability to issue commercial paper under its current programs.
Any downgrade below investment grade of PSE’s senior secured debt could allowcause counterparties in the wholesale electric, wholesale natural gas and financial derivative markets to require PSE to post a letter of credit or other collateral, make cash prepayments, obtain a guarantee agreement or provide other mutually agreeable security, all of which would expose PSE to additional costs.
The Company’s operating results fluctuate on a seasonal and quarterly basis.
PSE’s business is seasonal and weather patterns can have a material impact on its operating performance. Because natural gas is heavily used for residential and commercial heating, demand depends heavily on weather patterns in PSE’s service territory, and a significant amount of natural gas revenues are recognized in the first and fourth quarters related to the heating season. However, the recent increase in the price of natural gas may result in decreased customer demand, despite normal or lower than normal temperatures. Demand for electricity is also greater in the winter months associated with heating. Accordingly, PSE’s operations have historically generated less revenues and income when weather conditions are milder in the winter. In the event that the Company experiences unusually mild winters, results of operations and financial condition could be adversely affected.
The Company may be adversely affected by legal proceedings arising out of the electricity supply situation in the western power markets, which could result in refunds or other liabilities.
The Company is involved in a number of legal proceedings and complaints with respect to power markets in the western United States. Most of these proceedings relate to the significant increase in the spot market price of energy in western power markets in 2000 and 2001, which allegedly contributed to or caused unjust and unreasonable prices and allegedly may have been the result of manipulations by certain other parties. These proceedings include, but are not limited to, refund proceedings and hearings in California and the Pacific Northwest and complaints and cross-complaints filed by various parties with respect to alleged misconduct by other parties in western power markets. 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, individually or in the aggregate, will not materially and adversely affect PSE’s financial condition, results of operations or liquidity.
The Company may be negatively affected by its inability to attract and retain professional and technical employees.
The Company’s ability to implement a workforce succession plan is dependent upon the Company’s ability to employ and retain skilled professional and technical workers in an aging workforce. Without a skilled workforce, the Company’s ability to provide quality service to PSE’s customers and meet regulatory requirements will be challenged and could affect earnings.
The Company may be adversely affected by extreme events in which the Company is not able to promptly respond and repair the electric and gas infrastructure system.
The Company must maintain an emergency planning and training program to allow the Company to quickly respond to extreme events. Without emergency planning, the Company is subject to availability of outside contractors during an extreme event which may impact the quality of service provided to PSE’s customers. In addition, a slow response to extreme events may have an adverse affect on earnings as customers may be without electricity and gas for an extended period of time.
The Company may be negatively affected by unfavorable changes in the tax laws or their interpretation.
Changes in tax law, related regulations or differing interpretation or enforcement of applicable law by the Internal Revenue Service or other taxing jurisdiction could have a material adverse impact on the Company’s financial statements. The tax law, related regulations and case law are inherently complex. The Company must make judgments and interpretations about the application of the law when determining the provision for taxes. Disputes over interpretations of tax laws may be settled with the taxing authority in examination, upon examinationappeal or audit.through litigation. The Company’s tax obligations include income, real estate, public utility, municipal, sales and use, business and occupation and employment-related taxes and ongoing appeals issues related to these taxes. These judgments may include reserves for potential adverse outcomes regarding tax positions that have been taken that may be subject to challenge by the taxing authorities.
RISKS RELATING TO PUGET ENERGY’S CORPORATE STRUCTURE
As a holding company, Puget Energy is subject to restrictionsdepends on itsPSE’s ability to pay dividends.
As a holding company with no significant operations of its own, the primary source of funds for the repayment of debt and other expenses, as well as payment of dividends to its shareholdersshareholder, is cash dividends PSE pays to Puget Energy. PSE is a separate and distinct legal entity and has no obligation to pay any amounts to Puget Energy, whether by dividends, loans or other payments. The ability of PSE to pay dividends or make distributions to Puget Energy, and accordingly, Puget Energy’s ability to pay dividends on its common stock,or repay debt or other expenses, will depend on itsPSE’s earnings, capital requirements and general financial condition. If Puget Energy does not receive adequate distributions from PSE, it may not be able to makemeet its obligations or may have to reduce dividend payments on its common stock.pay dividends.
PSE’sThe payment of common stock dividends by PSE to Puget Energy is restricted by provisions of certain covenants applicable to its preferred stock and long-term debt contained in its restated articles of incorporation and electric and gasPSE’s mortgage indentures. Puget Energy’s Board of Directors reviews the dividend policy periodically in light of the factors referred to above and cannot assure shareholders of the amount of dividends, if any, that may be paidIn addition, beginning February 6, 2009, as approved in the future.
Future sales of Puget Energy’sWashington Commission merger order, PSE dividends may not be declared or paid if its common stockequity ratio is 44.0% or below except to the extent a lower equity ratio is ordered by the Washington Commission. In addition, pursuant to the merger order, PSE may not declare or make any distribution on the public market could lowerdate of distribution unless: (a) the stock price.
ratio of PSE’s Earnings Before Interest, Tax, Depreciation and Amortization (EBITDA) to PSE interest for the most recently ended four fiscal quarter periods prior to such date is equal to or greater than three to one; and (b) PSE’s corporate credit/issuer rating is equal to or greater than BBB- with S&P’s and Baa3 with Moody’s. Further, pursuant to the merger order, Puget Energy may sell additional sharesnot declare or make a distribution unless on such date Puget Energy’s ratio of common stock in public offerings, throughconsolidated EBITDA to consolidated interest expense for the stock purchase and dividend reinvestment planmost recently ended four fiscal quarter periods prior to such date is equal to or through common stock offering programs which it has entered into withgreater than two financial institutions. Puget Energy cannot predictto one. PSE’s ability to pay dividends is also limited by the size of future issuances of common stock, or the effect, if any, that future issuances and sales of shares of common stock will have on the market price of common stock. Sales of substantial amounts of common stock, or the perception that such sales could occur, may adversely affect the prevailing market price of common stock.
The market price for common stock is uncertain and may fluctuate significantly.
Puget Energy cannot predict whether the market priceterms of its common stock will rise or fall. Numerous factors influence the trading pricecredit facilities, pursuant to which PSE is not permitted to pay dividends during any Event of its common stock. These factors may include changes in financial condition, results of operations and prospects, legal and administrative proceedings and political, economic, financial and other factors that can affect the capital markets generally, the stock exchanges on which Puget Energy’s common stock is traded and its business segments.
Certain provisions of law, as well as provisionsDefault (as defined in the restated articles of incorporation, bylaws and shareholders rights plan, may make it more difficult for othersfacilities), such as failure to obtain control of Puget Energy. comply with certain financial covenants.
Puget Energy is a Washington corporation and certain anti-takeover provisions of Washington laws apply and create various impediments to the acquisition of control of Puget Energy or to the consummation of certain business combinations. In addition, Puget Energy’s restated articles of incorporation, bylaws and shareholders rights plan contain provisions which may make it more difficult to remove incumbent directors or effect certain business combinations with Puget Energy without the approval of the Board of Directors. These provisions of law and of Puget Energy’s corporate documents, individually or in the aggregate, could discourage a future takeover attempt which individual shareholders might deem to be in their best interests or in which shareholders would receive a premium for their shares over current prices.
None.
The principal electric generating plants and underground natural gas storage facilities owned by PSE are described under Item 1, Business - Electric Supply and Gas Supply. PSE owns its transmission and distribution facilities and various other properties. Substantially all properties of PSE are subject to the liens of PSE’s mortgage indentures. PSE’sThe Company’s corporate headquarters is housed in a leased building located in Bellevue, Washington.
See the section under Item 7, Management’s Discussion and Analysis of Financial Condition and Results of Operations-Proceedings Relating to the Western Power Market.
None.
PART II
Upon the completion of the merger on February 6, 2009, Puget Energy’s common stock was delisted from trading on the New York Stock Exchange (NYSE). As a result of the merger, all of the outstanding shares of Puget Energy’s common stock, the only class of common equity of Puget Energy, are held by its direct parent Puget Equico, which is traded on the New York Stock Exchange under the symbol “PSD.” At February 21, 2007, there were approximately 36,800 holders of recordan indirect wholly owned subsidiary of Puget Energy’s common stock.Holdings. The outstanding shares of PSE’s common stock, the only class of common equity of PSE, are held by Puget Energy and are not publicly traded.
The following table showsIn 2008 and the market price rangefirst quarter of and2009, prior to the merger, Puget Energy declared quarterly dividends paidin the amount of $0.25 per share on Puget Energy’seach share of common stock duringoutstanding and, in connection with the periods indicated in 2006 and 2005.February 6, 2009 merger, Puget Energy and its predecessor companies have paid dividends on common stock each year since 1943 when such stock first became publicly held.
| | 2006 | 2005 |
| | Price Range | Dividends | Price Range | Dividends |
| Quarter Ended | High | Low | Paid | High | Low | Paid |
| March 31 | $21.68 | $20.26 | $0.25 | $24.60 | $21.30 | $0.25 |
| June 30 | 21.62 | 20.13 | 0.25 | 23.56 | 20.73 | 0.25 |
| September 30 | 22.86 | 21.20 | 0.25 | 24.36 | 22.05 | 0.25 |
| December 31 | 25.91 | 22.72 | 0.25 | 23.70 | 20.21 | 0.25 |
The amount and paymentalso declared a special pro rata dividend of future dividends will depend on Puget Energy’s financial condition, results of operations, capital requirements and other factors deemed relevant by Puget Energy’s Board of Directors.$0.04448 per share. The Board of Directors’ current policy is to pay out approximately 60.0% of normalized utility earnings in dividends.
Puget Energy’s primary source of funds for the payment of dividends to its shareholders is dividends received from PSE. PSE’s payment ofon Puget Energy common stock dividends to Puget Energy is restricted by provisions of certain covenants applicable to preferred stock and long-term debt contained in PSE’s Restated Articles of Incorporation and electric and gas mortgage indentures. UnderIn addition, on February 6, 2009, the most restrictive covenantsCompany became subject to certain dividend restrictions. See Item 1A, Risk Factors, Risks relating to Puget Energy’s Corporate Structure or Item 7, Management’s Discussion and Analysis of PSE, earnings reinvested in the business unrestricted as to paymentFinancial Condition and Results of cash dividends were approximately $398.9 million at December 31, 2006.Operations.
The following tables show selected financial data. This information should be read in conjunction with the Management Discussion and Analysis (Item 7) and the audited consolidated financial statements and the related notes (Item 8) included elsewhere in this document.
Puget Sound Energy Summary of Operations (Dollars in Thousands) | | | | | | | | | | |
| For Years Ended December 31 | 2009 | | 2008 | | 2007 | | 2006 | | 2005 | |
| Operating revenue | $ | 3,328,501 | | $ | 3,357,773 | | $ | 3,220,147 | | $ | 2,907,063 | | $ | 2,578,008 | |
| Operating income | | 383,135 | | | 392,386 | | | 450,384 | | | 422,682 | | | 391,650 | |
| Net income | | 159,252 | | | 162,736 | | | 191,127 | | | 176,740 | | | 146,769 | |
| Total assets at year end | $ | 8,816,571 | | $ | 8,435,855 | | $ | 7,592,210 | | $ | 7,061,413 | | $ | 6,339,800 | |
| Long-term debt | | 2,638,860 | | | 2,270,860 | | | 2,428,860 | | | 2,608,360 | | | 2,183,360 | |
Preferred stock subject to mandatory redemption 1 | | -- | | | 1,889 | | | 1,889 | | | 1,889 | | | 1,889 | |
| Junior subordinated notes | | 250,000 | | | 250,000 | | | 250,000 | | | -- | | | -- | |
| Junior subordinated debentures of the corporation payable to a subsidiary trust holding mandatorily redeemable preferred securities | | -- | | | -- | | | -- | | | 37,750 | | | 237,750 | |
| Capital lease obligations | | 54,196 | | | 68,586 | | | 22,910 | | | 23,043 | | | -- | |
| | Successor 2 | | Predecessor 2 | |
Puget Energy Summary of Operations (Dollars in Thousands) For Years Ended December 31 | February 6, 2009 to December 31, 2009 | | January 1, 2009 to February 5, 2009 | | 2008 | | 2007 | | 2006 | | 2005 | |
| Operating revenue | $ | 2,925,148 | | $ | 403,713 | | $ | 3,357,773 | | $ | 3,220,147 | | $ | 2,907,063 | | $ | 2,578,008 | |
| Operating income | | 474,863 | | | 35,410 | | | 382,748 | | | 441,034 | | | 420,851 | | | 390,297 | |
| Income from continuing operations | | 174,015 | | | 12,756 | | | 154,929 | | | 184,676 | | | 167,224 | | | 146,283 | |
| Net income | | 174,015 | | | 12,756 | | | 154,929 | | | 184,464 | | | 219,216 | | | 155,726 | |
| Basic earnings per common share from continuing operations | | N/A | | | N/A | | | 1.20 | | | 1.57 | | | 1.44 | | | 1.43 | |
| Basic earnings per common share | | N/A | | | N/A | | | 1.20 | | | 1.57 | | | 1.89 | | | 1.52 | |
| Diluted earnings per common share from continuing operations | | N/A | | | N/A | | | 1.19 | | | 1.56 | | | 1.44 | | | 1.42 | |
| Diluted earnings per common share | | N/A | | | N/A | | | 1.19 | | | 1.56 | | | 1.88 | | | 1.51 | |
| Dividends per common share | | N/A | | | N/A | | $ | 1.00 | | $ | 1.00 | | $ | 1.00 | | $ | 1.00 | |
| Book value per common share | | N/A | | | N/A | | | 17.53 | | | 19.45 | | | 18.15 | | | 17.52 | |
| Total assets at year end | $ | 11,900,140 | | $ | 8,594,836 | | $ | 8,434,102 | | $ | 7,598,736 | | $ | 7,066,039 | | $ | 6,609,951 | |
| Long-term debt | | 3,790,698 | | | 2,520,860 | | | 2,270,860 | | | 2,428,860 | | | 2,608,360 | | | 2,183,360 | |
Preferred stock subject to mandatory redemption 1 | | -- | | | -- | | | 1,889 | | | 1,889 | | | 1,889 | | | 1,889 | |
| Junior subordinated notes | | 250,000 | | | 250,000 | | | 250,000 | | | 250,000 | | | -- | | | -- | |
| Junior subordinated debentures of the corporation payable to a subsidiary trust holding mandatorily redeemable preferred securities | | -- | | | -- | | | -- | | | -- | | | 37,750 | | | 237,750 | |
| Capital lease obligations | | 134,229 | | | 68,293 | | | 68,586 | | | 22,910 | | | 23,043 | | | -- | |
Puget Energy Summary of Operations (Dollars in Thousands, Except per share data) |
| Years Ended December 31 | 2006 | 2005 | 2004 | 2003 1 | 2002 |
Operating revenue 2 | $ | 2,905,693 | $ | 2,573,210 | $ | 2,198,877 | $ | 2,041,016 | $ | 1,995,652 |
| Operating income | | 326,616 | | 303,163 | | 287,678 | | 297,723 | | 294,074 |
| Net income from continuing operations | | 167,224 | | 146,283 | | 125,410 | | 114,600 | | 100,597 |
| Net income | | 219,216 | | 155,726 | | 55,022 | | 116,197 | | 110,052 |
| Basic earnings per common share from continuing operations | | 1.44 | | 1.43 | | 1.26 | | 1.21 | | 1.13 |
| Basic earnings per common share | | 1.89 | | 1.52 | | 0.55 | | 1.23 | | 1.24 |
| Diluted earnings per common share from continuing operations | | 1.44 | | 1.42 | | 1.26 | | 1.20 | | 1.13 |
| Diluted earnings per common share | | 1.88 | | 1.51 | | 0.55 | | 1.22 | | 1.24 |
| Dividends per common share | $ | 1.00 | $ | 1.00 | $ | 1.00 | $ | 1.00 | $ | 1.21 |
| Book value per common share | | 18.29 | | 17.52 | | 16.24 | | 16.71 | | 16.27 |
| Total assets at year end | $ | 7,066,039 | $ | 6,609,951 | $ | 5,851,219 | $ | 5,708,724 | $ | 5,772,132 |
| Long-term debt | | 2,608,360 | | 2,183,360 | | 2,069,360 | | 1,955,347 | | 2,021,832 |
| Preferred stock subject to mandatory redemption | | 1,889 | | 1,889 | | 1,889 | | 1,889 | | 43,162 |
| Corporation obligated, mandatorily redeemable preferred securities of subsidiary trust holding solely junior subordinated debentures of the corporation | | -- | | -- | | -- | | -- | | 300,000 |
| Junior subordinated debentures of the corporation payable to a subsidiary trust holding mandatorily redeemable preferred securities | | 37,750 | | 237,750 | | 280,250 | | 280,250 | | -- |
_______________
1 | All outstanding shares of preferred stock of PSE were defeased on February 5, 2009, and redeemed on March 13, 2009. In 2003, FASB issued Interpretation No. 46 (FIN 46) which requiredconnection with the consolidation of PSE’s 1995 Conservation Trust Transaction. As a result, revenues and expenses increased $5.7 million with no effect on net income, and assets and liabilities increased $4.2 million in 2003. FIN 46 also required deconsolidation of PSE’s trust preferred securities that are now classified as junior subordinated debt. This deconsolidation has no impact on assets, liabilities, receivables or earnings for 2003. |
2
| Operating Electric Revenues and Purchased Electricity expenses in 2003 and 2002 were revised as a result of implementing Emerging Issues Task Force Issue No. 03-11, “Reporting Realized Gains and Losses on Derivative Instruments That Are Subject to FASB No. 133 and Not ‘Held for Trading Purposes’ as Defined in Issue No. 02-03” (EITF No. 03-11), which became effective on January 1, 2004. Operating Electric Revenues and Purchased Electricity expense formerger, Puget Energy and Puget Sound Energy were reduced by $108.7 millionPSE amended in their entirety their respective Articles of Incorporation and $77.1 million in 2003 and 2002, respectively, withpreferred stock is no effect on net income.
|
Puget Sound Energy Summary of Operations (Dollars in Thousands) |
| Years Ended December 31 | 2006 | 2005 | 2004 | 20031 | 2002 |
Operating revenue 2 | $ | 2,905,693 | $ | 2,573,210 | $ | 2,198,877 | $ | 2,041,016 | $ | 1,995,652 |
| Operating income | | 327,490 | | 303,496 | | 288,241 | | 297,904 | | 294,593 |
| Net income for common stock | | 176,740 | | 146,769 | | 126,192 | | 114,735 | | 101,117 |
| Total assets at year end | $ | 7,061,413 | $ | 6,339,800 | $ | 5,579,756 | $ | 5,359,104 | $ | 5,453,390 |
| Long-term debt | | 2,608,360 | | 2,183,360 | | 2,064,360 | | 1,950,347 | | 2,021,832 |
| Preferred stock subject to mandatory redemption | | 1,889 | | 1,889 | | 1,889 | | 1,889 | | 43,162 |
| Corporation obligated, mandatorily redeemable preferred securities of subsidiary trust holding solely junior subordinated debentures of the corporation | | -- | | -- | | -- | | -- | | 300,000 |
| Junior subordinated debentures of the corporation payable to a subsidiary trust holding mandatorily redeemable preferred securities | | 37,750 | | 237,750 | | 280,250 | | 280,250 | | -- |
_______________
1
| See note 1 above.
longer authorized. |
2 | All of the operations of Puget Energy are conducted through its subsidiary PSE. “Predecessor” refers to the operations of Puget Energy and PSE prior to the consummation of the merger. “Successor” refers to the operations of Puget Energy and PSE subsequent to the merger. The merger was accounted for in accordance with Financial Accounting Standards Board (FASB) ASC 805. See note 2 above. Note 3 of the notes to the consolidated financial statements for a description of this transaction. |
The following discussion and analysis should be read in conjunction with the financial statements and related notes thereto included elsewhere in this annual report on Form 10-K. The discussion contains forward-looking statements that involve risks and uncertainties, such as Puget Energy’sEnergy, Inc.’s (Puget Energy) and Puget Sound Energy’sEnergy, Inc.’s (PSE) objectives, expectations and intentions. Words or phrases such as “anticipates,” “believes,” “estimates,” “expects,” “ plans,” “predicts,” “projects,” “will likely result,” “will continue” and similar expressions are intended to identify certain of these 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. Readers are cautioned not to place undue reliance on these forward-looking statements, which speak only as of the date of this report. Puget Energy’s and PSE’s actual results could differ materially from results that may be anticipated by such forward-looking statements. Factors that could cause or contribute to such differences include, but are not limited to, those discussed in the section entitled “Forward-Looking Statements” and “Risk Factors” included elsewhere in this report. Except as required by law, neither Puget Energy nor PSE undertakes an obligation to revise any forward-looking statements in order to reflect events or circumstances that may subsequently arise. Readers are urged to carefully review and consider the various disclosures made in this report and in Puget Energy’s and PSE’s other reports filed with the United States Securities and Exchange Commission that attempt to advise interested parties of the risks and factors that may affect Puget Energy’s and PSE’s business, prospects and results of operations.
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 (PSE),PSE, a regulated electric and natural gas utility company.company. 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 cash flows by offering reliable electric and natural gas service in a cost-effective manner through PSE. On February 6, 2009, Puget Holdings LLC (Puget Holdings) completed its merger with Puget Energy. Puget Holdings is a consortium of long-term infrastructure investors including Macquarie Infrastructure Partners I, Macquarie Infrastructure Partners II, Macquarie Capital Group Limited, Macquarie-FSS Infrastructure Trust, the Canada Pension Plan Investment Board, the British Columbia Investment Management Corporation, and the Alberta Investment Management Corporation (collectively, the Consortium). As a result of the merger, Puget Energy is a direct wholly owned a 90.9% interest in InfrastruX, a utility construction and services company, until it was sold tosubsidiary of Puget Equico LLC (Puget Equico), which is an affiliateindirect wholly owned subsidiary of Tenaska Power Fund, L.P. (Tenaska) on May 7, 2006. After repayment of debt, adjustments for working capital,Puget Holdings. In connection with the merger transaction, costs and distributions to minority interests, Puget Energy received $95.9 million for its 90.9% interest in InfrastruX in the second quarter 2006. The sale resulted in an after-tax gainapplied Accounting Standards Codification No. 805, “Business Combinations” (ASC 805). PSE’s basis of $29.8 million for the twelve months ended December 31, 2006. The $95.9 million net proceeds Puget Energy received from the sale of InfrastruX were usedaccounting will continue to support PSE through an equity contribution of $65.0 millionbe on a historical basis and a loan of $24.3 million. In addition, Puget Energy established a charitable foundation, Puget Sound Energy Foundation, in the second quarter 2006 with a contribution of $15.0 million from the net proceeds from the sale of InfrastruX along with investment income of $0.4 million on the cash proceeds and a federal income tax benefit of $5.3 million from funding the Puget Sound Energy Foundation.PSE’s financial statements will not include any purchase accounting adjustments.
Puget Sound Energy
PSE generates revenues and cash flow primarily from the sale of electric and natural gas services mainly to residential and commercial customers within a service territory covering approximately 6,000 square miles, principally in the Puget Sound region of the state of Washington. To meet customer growth and to replace expiring power contracts, PSE is implementing energy efficiency programs to reduce the need for additional energy generation, and pursuing additional renewable energy production resources (primarily wind) and base load natural gas-fired generation to meet its needs. As PSE acquires new long-term energy resources, it will require access to capital markets to meet its financing needs.
The number of PSE’s electric and natural gas customers continued to increase in 2009 but at a slower rate, as compared to 2008; approximately 0.6% and 0.7% annually for each, respectively. Electric retail kilowatt sales and gas therm sales for the year ended December 31, 2009 declined 0.7% and 3.7%, respectively, as compared to the same period in 2008. The decline in sales volumes in 2009 is due to warmer temperatures in the fourth quarter of 2009 as compared to 2008, the impact of PSE’s residential and commercial customer conservation programs and weaker economic conditions. The average temperature in PSE’s service territory for the year ended December 31, 2009 was warmer than the same period in 2008. The winter forecast provided by the National Oceanic and Atmospheric Administration’s Climate Prediction Center was for an El Nino weather pattern, which may cause the Pacific Northwest to be drier and warmer than normal. As a result of drier weather conditions during 2009, PSE hydroelectric generation and hydroelectric generation obtained under take or pay contracts declined by 8.8% as compared to the same period in 2008, causing an increase in overall power supply costs.
Factors and Trends Affecting PSE’s Performance.
The implementation of PSE’s strategy requires the investment of substantial capital over both the near-term and long-term, which presents PSE with several challenges. Because PSE intends to seek recovery of such investments through the regulatory process, it is substantially dependent upon positive outcomes from that process, as further discussed below. Further, PSE’s performance is heavily influenced by general economic conditions in its service territory, which effect customer growth and thus utility sales, as well as by the effects of its customers’ conservation investments, which tend to reduce energy sales.The principal business, economic and other factors that affect PSE’s operations and financial performance include:
| · | The rates PSE is allowed to charge for its services; |
| · | Demand for electricity and natural gas among customers in PSE’s service territory; |
| · | Regulatory decisions allowing PSE to recover costs, including purchased power and fuel costs, on a timely basis; |
| · | PSE’s ability to supply electricity and natural gas, either through company-owned generation, purchase power contracts or by procuring natural gas or electricity in wholesale markets; |
| · | Availability and access to capital and the cost of capital; |
| · | Regulatory compliance costs, including those related to new and developing federal regulations of electric system reliability, state regulations of natural gas pipelines and federal and state environmental standards; and |
| · | The impact of energy efficiency programs on sales and margins. |
Regulation of PSE Rates and Recovery of PSE Costs. The rates that PSE is allowed to charge for its services is the single most important item influencing its financial position, results of operations and liquidity. PSE is highly regulated and the rates that it charges its retail customers are determined by the Washington State.Utilities and Transportation Commission (Washington Commission). The Washington Commission determines these rates based, to a large extent, on historic test year costs plus weather normalized assumptions about hydro conditions and power costs in the relevant rate year. If in a particular rate year PSE’s costs are higher than what is allowed to be recovered in rates, revenues may not be sufficient to permit PSE to earn its allowed return or to cover its costs. In addition, the Washington Commission determines whether expenses and investments are reasonable and prudent in providing electric and natural gas service. If the Washington Commission determines that part of PSE’s costs do not meet the standard, those costs may be disallowed partially or entirely and not recovered in rates.
Electric Rates
On May 8, 2009, PSE filed a general rate case requesting recovery of increased electric revenue requirements. Based on its February 19, 2010 brief, PSE is requesting an increase in retail general rates of approximately $110.3 million or 5.5% annually for electric. This rate request includes a capital structure that includes 48.0% common equity and a requested return on equity of 10.8%. A final order from the Washington Commission is expected in April 2010.
Currently, PSE has a Power Cost Adjustment (PCA) mechanism that provides for recovery of power costs from customers or refunding of power cost savings to customers, as those costs vary from the “power cost baseline” level of power costs which are set, in part, based on normalized assumptions about weather and hydro conditions. Excess power costs or power cost savings are apportioned between PSE and its customers pursuant to the graduated scale set forth in the PCA mechanism. As a result, if power costs are significantly higher than the baseline rate, PSE’s expenses could significantly increase.
The graduated scale is as follows:
| Annual Power Cost Variability | Customers’ Share | Company’s Share |
| +/- $20 million | 0% | 100% |
| +/- $20 million - $40 million | 50% | 50% |
| +/- $40 million - $120 million | 90% | 10% |
| +/- $120 + million | 95% | 5% |
The following table sets forth electric rate changes that were approved by the Washington Commission and the corresponding impact to PSE’s annual revenues based on the effective dates:
| Type of Rate Adjustment | Effective Date | Average Percentage Increase (Decrease) in Rates | Annual Increase (Decrease) in Revenues (Dollars in Millions) |
| Merger Rate Credit | February 13, 2009 | (0.4)% | $ (6.7) |
| Electric General Rate Case | November 1, 2008 | 7.1 | 130.2 |
| Power Cost Only Rate Case | September 1, 2007 | 3.7 | 64.7 |
| Electric General Rate Case | January 13, 2007 | (1.3) | (22.8) |
Gas Rates
On May 28, 2009, the Washington Commission approved a Purchased Gas Adjustment (PGA) rate decrease of $21.2 million or 1.7% annually effective June 1, 2009. On September 24, 2009, the Washington Commission approved a PGA rate decrease of $198.1 million or 17.1% annually effective October 1, 2009. PSE has a PGA mechanism in retail natural gas rates to recover variations in natural gas supply and transportation costs. Variations in natural gas rates are passed through to customers; therefore PSE’s net income is not affected by such variations.
On May 8, 2009 PSE filed a general rate case with the Washington Commission which proposed an increase in natural gas rates of $27.2 million or 2.2% annually, effective April 2010. On August 3, 2009, PSE filed an addendum to the natural gas rate request which changed the rate increase to $30.4 million or 2.5%. On December 17, 2009, PSE filed rebuttal testimony, which lowered the requested natural gas rate increase to $28.4 million or 2.3% annually. This rate request includes a capital structure with an equity component of 48.0% and a requested rate of return on equity of 10.8%. A final order from the Washington Commission is expected in April 2010.
The following table sets forth gas rate changes that were approved by the Washington Commission and the corresponding impact to PSE’s annual revenues based on the effective dates:
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, 2009 | (17.1)% | $ (198.1) |
| Purchased Gas Adjustment | June 1, 2009 | (1.7) | (21.2) |
| Merger Rate Credit | February 13, 2009 | (0.4) | (3.6) |
| Gas General Rate Case | November 1, 2008 | 4.6 | 49.2 |
| Purchased Gas Adjustment | October 1, 2008 | 11.1 | 108.8 |
| Purchased Gas Adjustment | October 1, 2007 | (13.0) | (148.1) |
| Gas General Rate Case | January 13, 2007 | 2.8 | 29.5 |
Weather Conditions. Weather conditions in PSE’s service territory can have a significant impact on customer energy usage, affecting PSE’s revenues and energy supply expenses. PSE’s operating revenues and associated energy supply expenses are not generated evenly duringthroughout the year. VariationsWhile both PSE’s electric and natural gas sales are generally greatest during winter months, 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. PSE is experiencing lower customer usage due in part to warmer temperatures beginning with the second quarter of 2009 as compared to 2008, although winter months of both 2009 and 2008 were colder than historical averages in the Puget Sound region.
AsCustomer Demand. Although in the long term PSE expects the number of natural gas customers to grow at rates slightly above electric customers, both residential electric and natural gas customers are expected to continue a regulatedlong-term trend of slow decline of energy usage based on continued energy efficiency improvements and higher retail rates. Because the Washington Commission has not approved any “decoupling” (i.e., severing the link between recovery of fixed costs from commodity sales) or similar regulatory adjustment mechanism for PSE, energy efficiency or conservation programs lead to a direct reduction in net income. In addition, the effects of the current recession on Washington’s economy have caused a decline in customer usage in 2009 as compared to 2008.
Access to Debt Capital. PSE relies on access to bank borrowings and short-term money markets as sources of liquidity and longer-term debt markets to fund its utility company,construction program and other capital expenditure requirements not satisfied by cash flow from its operations or equity investment from its parent, Puget Energy. Neither Puget Energy nor PSE has any debt outstanding that would accelerate debt maturity upon a credit rating downgrade. However, 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 Puget Energy’s and PSE’s credit facilities, both of which expire in 2014, the borrowing costs and commitment fees increase as their respective credit ratings decline. If PSE is unable to access debt capital on reasonable terms, its ability to pursue improvements or acquisitions, including generating capacity, which may be relied on for future growth and to otherwise implement its strategy, could be adversely affected. PSE monitors the credit environment and expects to continue to be able to access the capital markets to meet its short-term and long-term borrowing needs.
Regulatory Compliance Costs and Expenditures. PSE’s operations are subject to Federal Energy Regulatory Commission (FERC)extensive federal, state and Washington Utilitieslocal laws and Transportation Commission (Washington Commission)regulations. Such regulations cover electric system reliability, gas pipeline system safety and energy market transparency, among other areas. Environmental regulations of air and water quality, hazardous waste disposal and endangered species protection also impact the Company’s operations, as would possible climate change legislation or the regulation which may impact a large array of business activities,generation by-products such as coal ash. PSE must spend significant sums on measures including limitation of future rate increases; directed accounting requirements that may negatively impact earnings; licensing of PSE-owned generation facilities;resource planning, remediation, monitoring, pollution control equipment and other FERCemissions-related abatement and Washington Commission directives that may impact PSE’s long-term goals. In addition, PSE is subjectfees in order to risks inherent to the utility industry as a whole, including weather changes affecting purchases and sales of energy; outages at owned and non-owned generation plants where energy is obtained; stormscomply with these regulatory requirements.
Compliance with these or other events which can damage gasfuture regulations, such as those pertaining to climate change and electric distributionhazardous waste could require significant capital expenditures by PSE and transmission lines;may adversely affect PSE’s financial position, results of operations, cash flows and wholesale market stability over timeliquidity.
Other Challenges and significant evolving environmental legislation.Strategies
Energy Supply. As noted in PSE’s main operational objective is to provide reliable, safe and cost-effective energy to its customers. To help accomplish this objective, PSE is implementing a strategy to be more self-sufficient in energy generation resources. PSE is continually exploring new electric-power resource generation and long-term purchase power agreements to meet this goal. The completion of the Hopkins Ridge wind project in 2005 and the Wild Horse wind project in December 2006 are two steps in reaching this goal. The Hopkins Ridge wind project provides a rated capacity of 150 megawatts (MW) or 52 average MW. The Wild Horse wind project provides a rated capacity of 229 MW or 73 average MW. These projects are considered to be non-firm energy due to the reliance on wind to produce the energy.
The Hopkins Ridge wind project and the Wild Horse wind project were included as part of PSE’s energy resource portfolio in its long-term electric IRP that wasIntegrated Resource Plan (IRP) filed May 2, 2005 with the Washington Commission. The plan supports a strategy of diverse resource acquisitions includingCommission, PSE projects that future energy needs will exceed current resources fueled by natural gasfrom long-term power purchase agreements and coal, renewable resources and sharedCompany-controlled power resources. The IRP was followed by issuing an all-source request for proposal (RFP) on November 1, 2005.
In addition, on February 21, 2007,identifies reductions in contractual supplies of energy and capacity available under certain long-term power purchase agreements, requiring replacement of supplies to meet projected demands. Therefore, PSE’s IRP sets forth a multi-part strategy of implementing energy efficiency programs and pursuing additional renewable resources (primarily wind) and additional base load natural gas-fired generation to meet the growing needs of its customers. If PSE acquired the Goldendale Generating Station,cannot acquire further additional energy supply resources at a 277 MW capacity natural gas generating facilityreasonable cost, it may be required to purchase additional power in the stateopen market at a cost that could, in the absence of Washington, fromregulatory relief, significantly increase its expenses and reduce earnings and cash flows.
Infrastructure Investment. PSE is investing in its utility infrastructure and customer service functions in order to meet regulatory requirements, serve customer energy needs and replace aging infrastructure. These investments and operating requirements give rise to significant growth in depreciation expense and operating expense, which are not recovered through the Calpine Corporation through its bankruptcy proceeding. PSE paid $120.0 millionratemaking process in a timely manner. This “regulatory lag” is expected to continue for the foreseeable future.
Operational Risks Associated With Generating Facilities. PSE owns and operates coal, natural gas-fired, hydroelectric, wind-powered and oil-fired generating facility.
In August 2006, PSE announcedfacilities. Operation of electric generating facilities involves risks that can adversely affect energy output and efficiency levels, including facility shutdowns due to equipment and process failures or fuel supply interruptions. For example, Colstrip Unit 4 was out of service from March 2009 to the selectionend of seven projects for further discussion and possible negotiation asOctober 2009 due to significant repair work required to the unit which was discovered during its routine overhaul. As a result of this outage, PSE incurred higher power costs of approximately $16.9 million from July through October 2009. PSE does not have business interruption insurance coverage to cover replacement power costs.
Energy Efficiency Related Lost Sales Margin. PSE’s sales, margins, earnings and cash flow are adversely affected by its energy efficiency programs, many of which are mandated by law. The Company is evaluating strategies and other means to reduce or eliminate these adverse financial effects.
Markets for Intangible Power Attributes. The Company is actively engaged in monitoring the 2005 RFP process. In aggregate, these outside sources, if completed, would generate approximately 1,100 MWdevelopment of long-termthe commercial markets for such intangible power supplyattributes as Renewable Energy Credits (RECs) and Carbon Financial Instruments. The Company supports the development of regional and national markets for such products that are free, open, transparent and liquid.
RESULTS OF OPERATIONS
The following discussion should be read in total. The outcomeconjunction with the audited consolidated financial statements and the related notes included elsewhere in this document. Set forth below is the consolidated financial results of such discussionPSE for the years ended December 31, 2009, 2008 and negotiation are not known at this time.2007:
Puget Sound Energy (Dollars in Thousands) For Years Ended December 31 | | 2009 | | | 2008 | | | 2009-2008 Percent Change | | | 2007 | | | 2008-2007 Percent Change | |
| Operating revenues: | | | | | | | | | | | | | | | |
| Electric | | | | | | | | | | | | | | | |
| Residential sales | | $ | 1,067,274 | | | $ | 1,046,897 | | | | 1.9 | % | | $ | 951,101 | | | | 10.1 | % |
| Commercial sales | | | 838,275 | | | | 800,878 | | | | 4.7 | | | | 748,824 | | | | 7.0 | |
| Industrial sales | | | 99,552 | | | | 106,092 | | | | (6.2 | ) | | | 105,227 | | | | 0.8 | |
| Other retail sales, including unbilled revenue | | | 16,424 | | | | 27,607 | | | | (40.5 | ) | | | 31,693 | | | | (12.9 | ) |
| Total retail sales | | | 2,021,525 | | | | 1,981,474 | | | | 2.0 | | | | 1,836,845 | | | | 7.9 | |
| Transportation sales | | | 10,623 | | | | 7,840 | | | | 35.5 | | | | 9,356 | | | | (16.2 | ) |
| Sales to other utilities and marketers | | | 78,471 | | | | 84,716 | | | | (7.4 | ) | | | 109,736 | | | | (22.8 | ) |
| Other | | | (11,883 | ) | | | 55,433 | | | | * | | | | 41,892 | | | | 32.3 | |
| Total electric operating revenue | | | 2,098,736 | | | | 2,129,463 | | | | (1.4 | ) | | | 1,997,829 | | | | 6.6 | |
| Gas | | | | | | | | | | | | | | | | | | | | |
| Residential sales | | | 795,756 | | | | 766,799 | | | | 3.8 | | | | 756,188 | | | | 1.4 | |
| Commercial sales | | | 357,110 | | | | 373,701 | | | | (4.4 | ) | | | 363,006 | | | | 2.9 | |
| Industrial sales | | | 39,531 | | | | 43,974 | | | | (10.1 | ) | | | 57,716 | | | | (23.8 | ) |
| Total retail sales | | | 1,192,397 | | | | 1,184,474 | | | | 0.7 | | | | 1,176,910 | | | | 0.6 | |
| Transportation sales | | | 13,014 | | | | 14,700 | | | | (11.5 | ) | | | 13,706 | | | | 7.3 | |
| Other | | | 19,334 | | | | 17,694 | | | | 9.3 | | | | 17,413 | | | | 1.6 | |
| Total gas operating revenues | | | 1,224,745 | | | | 1,216,868 | | | | 0.6 | | | | 1,208,029 | | | | 0.7 | |
| Non-utility operating revenue | | | 5,020 | | | | 11,442 | | | | (56.1 | ) | | | 14,289 | | | | (19.9 | ) |
| Total operating revenues | | | 3,328,501 | | | | 3,357,773 | | | | (0.9 | ) | | | 3,220,147 | | | | 4.3 | |
| Operating expenses: | | | | | | | | | | | | | | | | | | | | |
| Energy costs: | | | | | | | | | | | | | | | | | | | | |
| Purchased electricity | | | 887,306 | | | | 903,317 | | | | 1.8 | | | | 895,592 | | | | (0.9 | ) |
| Electric generation fuel | | | 208,444 | | | | 212,333 | | | | 1.8 | | | | 143,406 | | | | (48.1 | ) |
| Residential exchange | | | (96,504 | ) | | | (40,664 | ) | | | * | | | | (52,439 | ) | | | (22.5 | ) |
| Purchased gas | | | 718,860 | | | | 737,851 | | | | 2.6 | | | | 762,112 | | | | 3.2 | |
| Net unrealized (gain)loss on derivative instruments | | | (1,254 | ) | | | 7,538 | | | | * | | | | (2,687 | ) | | | * | |
| Utility operations and maintenance | | | 487,396 | | | | 461,632 | | | | (5.6 | ) | | | 403,681 | | | | (14.4 | ) |
| Non-utility expense and other | | | 14,532 | | | | 12,399 | | | | (17.2 | ) | | | 12,429 | | | | 0.2 | |
| Merger and related costs | | | 23,908 | | | | -- | | | | * | | | | -- | | | | * | |
| Depreciation and amortization | | | 332,852 | | | | 312,128 | | | | (6.6 | ) | | | 279,222 | | | | (11.8 | ) |
| Conservation amortization | | | 66,466 | | | | 61,650 | | | | (7.8 | ) | | | 39,955 | | | | (54.3 | ) |
| Taxes other than income taxes | | | 303,360 | | | | 297,203 | | | | (2.1 | ) | | | 288,492 | | | | (3.0 | ) |
| Total operating expenses | | | 2,945,366 | | | | 2,965,387 | | | | 0.7 | | | | 2,769,763 | | | | (7.1 | ) |
| Operating income | | | 383,135 | | | | 392,386 | | | | (2.4 | ) | | | 450,384 | | | | (12.9 | ) |
| Other income (deductions): | | | | | | | | | | | | | | | | | | | | |
| Other income and expense, net | | | 46,288 | | | | 26,024 | | | | 77.9 | | | | 21,429 | | | | 21.4 | |
| Interest expense | | | (202,527 | ) | | | (194,792 | ) | | | (4.0 | ) | | | (206,505 | ) | | | 5.7 | |
| Income before income taxes | | | 226,896 | | | | 223,618 | | | | 1.5 | | | | 265,308 | | | | (15.7 | ) |
| Income tax expense | | | 67,644 | | | | 60,882 | | | | (11.1 | ) | | | 74,181 | | | | 17.9 | |
| Net income | | $ | 159,252 | | | $ | 162,736 | | | | (2.1 | )% | | $ | 191,127 | | | | (14.9 | )% |
Puget Sound Energy
NON-GAAP FINANCIAL MEASURES2009 compared to 2008
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 measureSummary Results 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. Our 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.Operations
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
Puget Energy
All the operations of Puget Energy are conducted through its subsidiary PSE. NetPSE’s net income in 20062009 was $219.2$159.3 million on operating revenues from continuing operations of $2.9$3.3 billion as compared to $155.7$162.7 million on operating revenues from continuing operations of $2.6$3.4 billion in 2005 and $55.02008. Subsequent to the merger on February 6, 2009, PSE’s basis of accounting continued to be on a historical basis as PSE’s financial statements do not include any ASC 805 purchase accounting adjustments. The following are significant factors impacting PSE’s net income:
| · | Decrease in electric operating revenues of $30.7 million mainly as a result of losses incurred from the sale of natural gas originally purchased for electric generation, as well as certain related financial hedge contracts, increase residential exchange credit and production tax credits pass through to PSE’s customers and a decline in customer usage due to warmer temperature and the impact of the recession on Washington’s economy. The decrease was partially offset by an increase in PSE’s retail sales as a result of an electric general tariff rate increase effective November 1, 2008 offset by PGA rate decreases of June 1, 2009 and October 1, 2009. |
| · | Increase in gas operating revenues of $7.8 million mainly due to a higher gas general tariff rate increase effective November 1, 2008, and a PGA rate increase effective October 1, 2008. This was offset by PGA rate decreases effective June 1, 2009 and October 1, 2009. |
| · | Decrease in purchased electricity and electric generation fuel of $16.0 million and $3.9 million, respectively, as a result of lower customer usage and lower wholesale market prices. The decrease was offset by higher generation from natural gas turbines due to the Colstrip 4 outage and lower hydroelectric and wind generation. |
| · | Decrease in purchased gas of $19.0 million due to lower customer usage and changes in PGA rates. The rate decrease was the result of declining natural gas wholesale costs and a reduction of the credit for accumulated PGA payable balance. |
| · | Increase in residential exchange credits for power costs of $55.8 million from the Bonneville Power Administration (BPA), which was a pass-through to PSE customers, reflected as a reduction in PSE electric operating revenues. |
| · | Increase in other income and expenses of $20.3 million primarily due to an increase in regulatory interest income from the Mint Farm Generation Station (Mint Farm) deferral. |
| · | Increase in net unrealized gain on derivative instruments of $8.8 million primarily due to a favorable marked-to-market accounting impact that resulted from the de-designation of cash flow hedges related to PSE’s energy contracts starting on July 1, 2009. |
The above changes were partially offset by the following unfavorable impacts to net income:
| · | Decrease in non-utility operating revenues of $6.4 million as a result of lower property sales of PSE’s real estate subsidiary and lower revenues related to non-tariff customer support. |
| · | Increase from one time merger costs of $23.9 million related to the merger of Puget Energy with Puget Holdings. These costs were primarily related to PSE employee compensation triggered by Puget Energy’s change of control, credit agreement related expenses and the impact of increases in the deferred compensation related liability. |
| · | Increase in utility operations and maintenance of $25.8 million mainly due to increases in customer service expense and bad debts expense. |
| · | Increase in depreciation and amortization of $20.7 million and an increase in taxes other than income taxes by $6.2 million. |
| · | Increase in conservation amortization of $4.8 million as a result of higher authorized recovery of electric and natural gas conservation expenditures. |
| · | Increase in interest expense of $7.7 million as a result of higher rate long-term debt and an increase in the costs of credit facilities. |
2008 compared to 2007
Summary Results of Operations
PSE’s net income in 2008 was $162.7 million on operating revenues from continuing operations of $2.2$3.4 billion in 2004. Income from continuing operations in 2006 was $167.2 millionas compared to $146.3$191.1 million in 2005 and $125.4 million in 2004.
Basic earnings per share in 2006 was $1.89 on 116.0 million weighted average common shares outstanding compared to $1.52 on 102.6 million weighted average common shares outstanding in 2005 and $0.55 on 99.5 million weighted average common shares outstanding in 2004. Diluted earnings per share in 2006 was $1.88 on 116.5 million weighted average common shares outstanding compared to $1.51 on 103.1 million weighted average common shares outstanding in 2005 and $0.55 on 99.9 million weighted average common shares outstanding in 2004. Included in basic earnings per share for 2006 was $0.45 compared to $0.09 and $(0.71) for 2005 and 2004, respectively, related to discontinued operations. Included in diluted earnings per share for 2006 was $0.45 compared to $0.09 and $(0.71) for 2005 and 2004, respectively, related to discontinued operations.
Income from continuing operations excluding the impact of the charitable contribution to the Puget Sound Energy Foundation was $177.0 million for 2006. Management of the Company believes it is useful to present income from continuing operations and diluted earnings excluding the impact of the charitable contribution because it represents a more accurate measure of operating performance and facilitates period-to-period comparisons. Basic and diluted earnings per share from continuing operations were $1.52 for the twelve months ended December 31, 2006, excluding the impact of the charitable contribution to the Puget Sound Energy Foundation. A reconciliation to amounts under GAAP is as follows:
(Dollars in millions, except per share amounts) | | Twelve Months Ended December 31, 2006 |
| Income from continuing operations, as reported | | $ | 167.2 |
| Add: Impact of charitable contribution to Foundation, net of tax | | | 9.8 |
| Income from continuing operations, excluding charitable contribution | | $ | 177.0 |
| Earnings per share: | | | |
| Basic and diluted earnings per share before cumulative effect of accounting change from continuing operations, as reported | | $ | 1.44 |
| Add: Impact of charitable contribution to Foundation | | | 0.08 |
| Basic and diluted earnings per share before cumulative effect of accounting change from continuing operations, excluding charitable contribution | | $ | 1.52 |
Net income in 2006 benefited from income from discontinued operations of InfrastruX of $51.9 million (after-tax) compared to $9.5 million (after-tax) for 2005. Puget Energy’s income from discontinued operations for 2006 includes $7.3 million related to the reversal of a carrying value adjustment recorded in 2005 as well as $10.0 million related to the anticipated realization of a deferred tax asset associated with the sale of the business. Natural gas and electric margins increased by $22.6 million and $46.0 million, respectively, for 2006 compared to 2005, which positively impacted net income. The increase in natural gas margins resulted from increased natural gas general tariff rates and increased sales volumes. The increase in electric margins was the result of increased sales volumes, overrecovery of power costs under the power cost adjustment (PCA) mechanism and two power cost only rate case (PCORC) rate increases effective November 1, 2005 and July 1, 2006. Net income in 2005 was positively impacted by an increase in incomerevenues from continuing operations of $20.6$3.2 billion in 2007. The following are significant factors impacting PSE net income:
| · | Increase in electric operating revenues of $131.7 million due to an increase in retail sales as a result of electric general tariff rate increase, customer growth and higher electricity usage due to colder average temperature. The increase was partially offset by a decrease in sales to other utilities and marketers. |
| · | Increase in gas operating revenue of $8.8 million due to higher gas therm sales from customer growth and higher usage from the colder average temperatures in the Pacific Northwest. |
| · | Increase in purchased electricity and electric generation fuel of $7.7 million and $68.9 million, respectively, as a result of higher wholesale market prices and an increase in combustion turbine generation. |
| · | Decrease in purchased gas of $24.2 million as a result of lower PGA rates. The decrease was slightly offset by higher customer therm sales. |
| · | Decrease in interest expense of $11.7 million as a result of lower debt outstanding and lower average interest rates. |
The above changes were partially offset by the following unfavorable impact to net income:
| · | Decrease in residential exchange pass-through credits of $11.7 million from the BPA. |
| · | Increase in utility operations and maintenance cost of $57.9 million due to increases in planned maintenance costs, administrative and general expenses, electric transmission and distribution expenses, gas operations and distribution expenses and a settlement related to Colstrip. |
| · | Increase in net unrealized loss on derivative instruments of $10.2 million due to declining market prices in both electric and gas sectors and an unrealized loss related to PSE’s cash flow hedges of power contracts. |
| · | Increase in depreciation and amortization of $32.9 million due to additions in depreciable assets and an increase in amortization related to a benefit recognized in 2007 from deferring certain operating costs related to Goldendale. |
| · | Increase in conservation amortization of $21.7 million as a result of higher authorized recovery of electric and natural gas conservation expenditures and taxes other than income taxes of $8.7 million. |
Puget Sound Energy
The following discussion provides the significant items that impact PSE’s results of operations for the years ended December 31, 2009 and 2008.
2009 compared to 2008
Regulated Utility Operating Revenues
Electric Operating Revenues. Electric retail sales increased $40.0 million, or 2.0%, to $2.02 billion from $2.0 billion. The increase was mainly due to increasedan electric and gas marginsgeneral rate increase of $73.47.1% effective November 1, 2008, that was partially offset by a merger rate credit, which contributed to an increase in electric retail sales of $109.3 million. This increase was partially offset by the benefits of the Residential and Farm Energy Exchange Benefit credited to customers which reduced electric operating revenues by $58.4 million. The credit also reduced power costs by a corresponding amount with no impact on earnings. In addition, a decrease in retail electricity usage of 148,516 megawatt hours (MWhs) or 0.7% related to lower customer usage resulted in a decrease of approximately $13.7 million to electric operating revenue.
Sales to other utilities and marketers decreased $6.2 million, or 7.4%, to $78.5 million from $84.7 million. The decrease was due primarily to a higher Tenaska disallowancedecline in 2004PSE’s average wholesale electric sales price which decreased revenues by $33.3 million which was offset by $26.7 million due to an increase in volume. The sales volume increased by 862,535 MWh or 51.8%.
Other electric operating revenues decreased $67.3 million, to $(11.9) million from $55.4 million. The decrease was primarily due to $54.7 million related losses from natural gas hedging contracts and $7.6 million decrease in non-core gas sales. Such gains or losses on the sale of $43.4natural gas, which was intended to be used for electric generation, are included as a component of PSE’s PCA mechanism. Also contributing to this decrease are a reduction in transmission revenue and other miscellaneous operating revenues.
Gas Operating Revenues. Gas retail sales increased $7.9 million, comparedor 0.7%, to $4.1$1.192 billion from $1.184 billion. The increase was primarily due to a $50.5 million increase in 2005. Increased electricity and gas sales volumes increased margin by $24.5 million as compared to 2004. Gas margin also increased $17.3 millionoperating revenues as a result of the 2005a gas general rate case. Offsettingincrease of 4.6% effective November 1, 2008 and PGA rate increase effective October 1, 2008, offset by PGA rate decreases of June 1, 2009 and October 1, 2009. The PGA mechanism passes through to customer increases or decreases in the increases were higher operationsnatural gas supply portion of the natural gas service rates based upon changes in the price of natural gas purchased from producers and maintenance costs of $42.1wholesale marketers or changes in natural gas pipeline transportation costs. PSE’s net income is not affected by changes under the PGA mechanism. Partially offsetting the increase is a $35.6 million or 3.7% decrease in gas therm sales which decreased revenue by $44.4 million.
Non-Utility Operating Revenues
Non-utility operating revenues decreased $6.4 million, or 56.0%, to $5.0 million from $11.4 million. The decrease was due to lower property sales by PSE’s real estate subsidiary, which reduced revenue by $3.6 million, and depreciation and amortization of $13.0lower revenues related to non-tariff customer support work performed by PSE, which reduced revenue by $3.0 million. In addition, income
Operating Expenses
Purchased electricity expenses decreased $16.0 million, or 1.8%, to $887.3 million from discontinued operations increased $79.9 million in 2005 compared to 2004$903.3 million. This decrease was primarily due to lower non-cash impairmentscustomer usage related to weak economic conditions and favorable industry conditionshigher generation from natural gas combustion turbines as a result of Colstrip Unit 4 outage, lower hydroelectric and wind generation.
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 purchase or sell power in the utility construction services sector.
wholesale market. PSE manages its regulated power portfolio through short-term and intermediate-term off-system physical purchases and sales as well as through other risk management techniques.
Puget Sound EnergyElectric generation fuel
2006 compared expense decreased $3.9 million, or 1.8%, to 2005
Energy Margins
The following table displays the details of electric margin changes$208.4 million from 2005$212.3 million. This decrease was due to 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) Twelve Months Ended December 31 | | 2006 | | 2005 | | Change | | Percent Change | |
Electric operating revenue1 | | $ | 1,777.7 | | $ | 1,612.9 | | $ | 164.8 | | | 10.2 | % |
| Less: Other electric operating revenue | | | (51.8 | ) | | (62.5 | ) | | 10.7 | | | 17.1 | |
| Add: Other electric operating revenue - gas supply resale | | | 16.4 | | | 26.1 | | | (9.7 | ) | | (37.2 | ) |
| Total electric revenue for margin | | | 1,742.3 | | | 1,576.5 | | | 165.8 | | | 10.5 | |
| Adjustments for amounts included in revenue: | | | | | | | | | | | | | |
| Pass-through tariff items | | | (35.9 | ) | | (26.9 | ) | | (9.0 | ) | | (33.5 | ) |
| Pass-through revenue-sensitive taxes | | | (117.4 | ) | | (104.9 | ) | | (12.5 | ) | | (11.9 | ) |
| Net electric revenue for margin | | | 1,589.0 | | | 1,444.7 | | | 144.3 | | | 10.0 | |
| Minus power costs: | | | | | | | | | | | | | |
Purchased electricity1 | | | (917.8 | ) | | (860.4 | ) | | (57.4 | ) | | (6.7 | ) |
Electric generation fuel1 | | | (97.3 | ) | | (73.3 | ) | | (24.0 | ) | | (32.7 | ) |
Residential exchange1 | | | 163.6 | | | 180.5 | | | (16.9 | ) | | (9.4 | ) |
| Total electric power costs | | | (851.5 | ) | | (753.2 | ) | | (98.3 | ) | | (13.1 | ) |
Electric margin2 | | $ | 737.5 | | $ | 691.5 | | $ | 46.0 | | | 6.7 | % |
_______________
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 $46.0an $8.6 million decrease in 2006 compared to 2005 primarilycoal-burned fuel due to the effectsoutage of the general rate case rate increase effectiveColstrip Unit 4. The unit was taken offline in March 4, 20052009 to conduct maintenance and the PCORC rate increases effective November 1, 2005repair and July 1, 2006 which increased margin by $27.5 million. Retail customer kilowatt hour (kWh) sales (residential, commercial and industrial customers) increased 3.1%was returned to service in 2006 compared to 2005, which provided $21.8 million to electric margin. Electric margin also increased by $12.9 million due to overrecovery of excess power cost under the PCA mechanism. Electric margin increased by $1.2 million due to the reduction of the Tenaska disallowance in the PCA mechanism. These increases wereOctober 2009. The decrease was partially offset by a $11.2$4.8 million decrease relatedincrease in combustion turbine generation costs due to production tax credits (PTCs) provided to customers through tariff rates, which are trued-up to actual PTCs taken in an annual true-up processlower hydroelectric and the non-recurring benefit of a February 23, 2005 Washington Commission order allowing recovery of power costs that lowered electric margin by $6.0 million.wind generation.
The following table displaysResidential exchange credits increased $55.8 million or 137.1%, to $(96.5) million from $(40.7) million. Associated with the details of gas margin changes from 2005 to 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) Twelve Months Ended December 31 | | 2006 | | 2005 | | Change | | Percent Change | |
Gas operating revenue1 | | $ | 1,120.1 | | $ | 952.5 | | $ | 167.6 | | | 17.6 | % |
| Less: Other gas operating revenue | | | (16.5 | ) | | (17.2 | ) | | 0.7 | | | 4.1 | |
| Total gas revenue for margin | | | 1,103.6 | | | 935.3 | | | 168.3 | | | 18.0 | |
| Adjustments for amounts included in revenue: | | | | | | | | | | | | | |
| Pass-through tariff items | | | (7.1 | ) | | (5.7 | ) | | (1.4 | ) | | (24.6 | ) |
| Pass-through revenue-sensitive taxes | | | (86.3 | ) | | (73.1 | ) | | (13.2 | ) | | (18.1 | ) |
| Net gas revenue for margin | | | 1,010.2 | | | 856.5 | | | 153.7 | | | 17.9 | |
Minus purchased gas costs1 | | | (723.2 | ) | | (592.1 | ) | | (131.1 | ) | | (22.1 | ) |
Gas margin2 | | $ | 287.0 | | $ | 264.4 | | $ | 22.6 | | | 8.5 | % |
_______________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 $22.6 million in 2006 compared to 2005. Gas margin increased $12.6 million due to a 4.7% increase in gas therm volume sales; $7.0 million ofBPA Residential Exchange Program (REP), the increase was a result of an agreement with BPA to continue to pass on REP benefits to PSE’s customers. REP credit is a pass-through tariff item with a corresponding credit in electric operating revenue; thus, it has no impact on net income.
Purchased gas expenses decreased $19.0 million, or 2.6%, to $718.9 million from $737.9 million. The decrease was primarily due to a 3.7% decrease in customer usage and changes to PGA rates. The PGA mechanism provides the rates used to determine gas general tariffcosts based on customer usage. The rate casedecrease was the result of declining costs of natural gas wholesale. The PGA mechanism allows PSE to recover expected natural gas supply and transportation costs and defer, as a receivable or liability, any natural gas supply and transportation costs that exceed or fall short of this expected gas cost amount in PGA mechanism rates, including accrued interest. The PGA mechanism payable balance at December 31, 2009 was $49.6 million as compared to $8.9 million at December 31, 2008. PSE is authorized by the Washington Commission to accrue carrying costs on PGA receivable and payable balances. A receivable balance in the PGA mechanism reflects an under recovery of market natural gas cost through rates. A payable balance reflects over recovery of market natural gas cost through rates.
Net unrealized (gain) loss on derivative instruments changed by $8.8 million, to a gain of $(1.3) million in 2009, as compared to a loss of $7.5 million in 2008. The gain was mainly due to mark-to-market accounting for PSE’s energy derivative contracts. On July 1, 2009, PSE elected to de-designate its energy derivative contracts previously designated as cash flow hedges. The contracts that were de-designated are physical electric supply contracts and natural gas swap contracts which were used to fix the price of natural gas for electric generation. For these contracts, all future mark-to-market accounting impacts will be recognized through earnings. The amount in Accumulated Other Comprehensive Income (OCI) is transferred to earnings when the contracts settle or sooner, if management determines that the forecasted transaction is probable of not occurring. As a result, PSE will likely continue to experience earnings volatility in future periods. For the year ended December 31, 2009, PSE recognized $135.5 million gain from the transfer in OCI when contracts settled, which was effective March 4, 2005. These increases were partially offset by a $1.5$126.6 million decreaseloss from unfavorable mark-to-market adjustments.
Utility operations and maintenance expense increased $25.8 million, or 5.6%, to $487.4 million from $461.6 million. The increase was driven by an $18.6 million increase in margincustomer service expenses, which included a $4.9 million increase in bad debt expense, administrative costs and electric transmission and distribution costs. Also contributing to the increase is a $2.1 million increase in gas operations costs.
Merger and related costs associated with the merger with Puget Holdings increased $23.9 million. These costs were primarily related to customer mixPSE employee compensation triggered by Puget Energy’s change of control, credit agreement related expenses, legal fees and pricing.
Electric Operating Revenuesdeferred compensation related liability increases triggered by the merger. Pursuant to the Washington Commission merger order commitments, PSE will not seek recovery of these costs in retail rates.
Depreciation and amortization expense increased $20.7 million, or 6.6%, to $332.9 million from $312.1 million. This increase was due to additional capital expenditures that were placed into service and an increase in storm amortization costs as approved in PSE’s general rate case effective November 1, 2008. Amortization expense included a benefit related to the deferral of Mint Farm fixed cost of $14.1 million which, had it not been included as a reduction to amortization expense, depreciation and amortization expense would have increased by $34.9 million.
Conservation amortization increased $4.8 million, or 7.8%, to $66.5 million from $61.7 million. The table below sets forth changes inincrease was due to a higher authorized recovery of electric operating revenues for PSEand natural gas conservation expenditures. Conservation amortization is a pass-through tariff item with no impact on earnings.
Taxes other than income taxes increased $6.2 million, or 2.1%, to $303.4 million from 2005$297.2 million. The increase was due to 2006.revenue sensitive taxes from increased revenue.
(Dollars in Millions) Twelve Months Ended December 31 | | 2006 | | 2005 | | Change | | Percent Change | |
| Electric operating revenues: | | | | | | | | | |
| Residential sales | | $ | 788.2 | | $ | 690.2 | | $ | 98.0 | | | 14.2 | % |
| Commercial sales | | | 702.8 | | | 629.0 | | | 73.8 | | | 11.7 | |
| Industrial sales | | | 103.0 | | | 93.9 | | | 9.1 | | | 9.7 | |
| Other retail sales, including unbilled revenue | | | 35.4 | | | 23.3 | | | 12.1 | | | 51.9 | |
| Total retail sales | | | 1,629.4 | | | 1,436.4 | | | 193.0 | | | 13.4 | |
| Transportation sales | | | 11.5 | | | 9.0 | | | 2.5 | | | 27.8 | |
| Sales to other utilities and marketers | | | 85.0 | | | 105.0 | | | (20.0 | ) | | (19.0 | ) |
| Other | | | 51.8 | | | 62.5 | | | (10.7 | ) | | (17.1 | ) |
| Total electric operating revenues | | $ | 1,777.7 | | $ | 1,612.9 | | $ | 164.8 | | | 10.2 | % |
Other income and expense increased $20.3 million, or 77.9%, to $46.3 million from $26.0 million. The increase was primarily due to an increase in regulatory interest income from Mint Farm which contributed $14.7 million, Allowance for Funds Used During Construction (AFUDC) of $2.6 million and $2.2 million gain on PSE trust owned life insurance.
Interest expense increased $7.8 million, or 4.0%, to $202.6 million from $194.8 million. The increase was primarily due to issuance of higher rate long-term debt and an increase in the amortization of costs of credit facilities.
Income tax expense increased $6.7 million, or 11.11%, to $67.6 million from $60.9 million. The increase was primarily due to an increase in the effective tax rate to 29.8% from 27.2%. The increase in effective tax rate was mainly due to lower wind generation in 2009 as compared to 2008, which resulted in lower production tax credits.
2008 compared to 2007
Regulated Utility Operating Revenues
Electric Operating Revenues.Electric retail sales increased $193.0$144.6 million for 2006 compared2008, or 7.9%, to 2005$1.981 billion from $1.836 billion. The increase was primarily due primarily to rate increases related tocolder average temperatures in the PCORCPacific Northwest during the first half of 2008 and during the electric general rate casemonth of December 2008 which saw record energy peak loads and increased retailan increase in customer usage. The PCORC and electric general rate case provided a combined additional $68.7 million to electric operating revenues for 2006 compared to 2005.growth. Retail electricity usage increased 626,207388,249 MWh or 3.1%1.8% for 20062008 as compared to 2005.the same period in 2007, which resulted in an increase of approximately $34.9 million in electric operating revenue. The increase in electricity usage was mainly the result of a 1.6%related in part to 1.5% higher average number of customers served in 20062008 as compared to 2005.
During 2006,2007. The electric general rate decrease of January 13, 2007, the Power Cost Only Rate Case (PCORC) rate increase of September 1, 2007 coupled with the electric general rate increase of November 1, 2008 increased electric retail sales by $104.6 million. The benefits of the Residential and Small Farm Energy Exchange Benefit credited to customers reduced electric operating revenues by $171.3 million compared to $189.0 million for 2005.$42.5 million. This credit also reduced power costs by a corresponding amount with no impact on earnings.
Transportation sales increased $2.5 million for 2006 compared to 2005 due to an increase in sales volume of 61,524 MWh or 3.0%.
Sales to other utilities and marketers decreased $20.0$25.0 million, comparedor 22.8%, to 2005$84.7 million from $109.7 million. The decrease was due primarily to a decrease in the wholesale market pricesales volume of electricity588,157 MWh or 26.1%, which resulted in 2006 as compared to 2005a decrease of $28.6 million. This decrease was partially offset by an increase in PSE’s average wholesale sales price to other utilities and marketers as compared to 2007 which resulted in an increase of 180,842 MWh in 2006 from 2005.approximately $3.6 million.
Other electric revenues decreased $10.7increased $13.6 million, in 2006 comparedor 32.3%, to 2005, primarily associated with natural gas purchased for electric generation needs that was subsequently sold rather than used by PSE or gains$55.5 million from electric generation financial derivatives on gas sold.$41.9 million. The following electric rate changes were approved by the Washington Commission in 2007, 2006 and 2005:
Type of Rate Adjustment | Effective Date | Average Percentage Increase in Rates | Annual Increase in Revenues (Dollars in Millions) |
| Electric General Rate Case | March 4, 2005 | 4.1 | % | $ 57.7 |
| Power Cost Only Rate Case | November 1, 2005 | 3.7 | % | 55.6 |
| Power Cost Only Rate Case | July 1, 2006 | 5.9 | % | 45.3 1 |
| Electric General Rate Case | January 13, 2007 | (1.3 | )% | (22.8) |
_______________
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 from 2005 to 2006.
(Dollars in Millions) Twelve Months Ended December 31 | | 2006 | | 2005 | | Change | | Percent Change | |
| Gas operating revenues: | | | | | | | | | |
| Residential sales | | $ | 697.6 | | $ | 592.4 | | $ | 105.2 | | | 17.8 | % |
| Commercial sales | | | 335.7 | | | 281.3 | | | 54.4 | | | 19.3 | |
| Industrial sales | | | 57.1 | | | 48.3 | | | 8.8 | | | 18.2 | |
| Total retail sales | | | 1,090.4 | | | 922.0 | | | 168.4 | | | 18.3 | |
| Transportation sales | | | 13.3 | | | 13.3 | | | -- | | | 0.0 | |
| Other | | | 16.4 | | | 17.2 | | | (0.8 | ) | | (4.7 | ) |
| Total gas operating revenues | | $ | 1,120.1 | | $ | 952.5 | | $ | 167.6 | | | 17.6 | % |
Gas retail sales increased $168.4 million for 2006 compared to 2005 due to higher purchased gas adjustment (PGA) mechanism rates in 2006, approval of a 3.5% gas general rate increase effective March 4, 2005 and higher retail customer gas usage. The Washington Commission approved a PGA mechanism rate increase effective October 1, 2005 that provided $113.2 million in gas revenues for 2006 compared to 2005. In addition, the gas general rate case increase provided an additional $7.0 million in gas operating revenues for 2006 compared to in 2005. The remaining increase in gas retail revenues was primarily due to an increase of $14.3 million in customers of 3.0% and highernoncore gas sales.
Gas Operating Revenues. Gas retail sales increased $7.6 million, or 0.7%, to $1.184 billion from $1.176 billion. The increase was due to an increase in gas therm sales of 48.453.8 million, therms or $43.8 million for 2006 compared to 2005.
The following gas rate changes were approved by the Washington Commission in 2007, 20064.8%, reflecting customer growth and 2005:
Type of Rate Adjustment | Effective Date | Average Percentage Increase in Rates | Annual Increase in Revenues (Dollars in Millions) |
| Gas General Rate Case | March 4, 2005 | 3.5 | % | $ 26.3 |
| Purchased Gas Adjustment | October 1, 2005 | 14.7 | % | 121.6 |
| Purchased Gas Adjustment | October 1, 2006 | 10.2 | % | 95.1 |
| Gas General Rate Case | January 13, 2007 | 2.8 | % | 29.5 |
Operating Expenses
The table below sets forth significant changes in operating expenses for PSE from 2005 to 2006.
(Dollars in Millions) Twelve Months Ended December 31 | | 2006 | | 2005 | | Change | | Percent Change | |
| Purchased electricity | | $ | 917.8 | | $ | 860.4 | | $ | 57.4 | | | 6.7 | % |
| Electric generation fuel | | | 97.3 | | | 73.3 | | | 24.0 | | | 32.7 | |
| Residential exchange | | | (163.6 | ) | | (180.5 | ) | | 16.9 | | | 9.4 | |
| Purchased gas | | | 723.2 | | | 592.1 | | | 131.1 | | | 22.1 | |
| Utility operations and maintenance | | | 354.6 | | | 333.3 | | | 21.3 | | | 6.4 | |
| Depreciation and amortization | | | 262.3 | | | 241.6 | | | 20.7 | | | 8.6 | |
| Conservation amortization | | | 32.3 | | | 24.3 | | | 8.0 | | | 32.9 | |
| Taxes other than income taxes | | | 255.7 | | | 233.7 | | | 22.0 | | | 9.4 | |
| Income taxes | | | 97.2 | | | 89.6 | | | 7.6 | | | 8.5 | |
Purchased electricity expenses increased $57.4 million in 2006 compared to 2005 primarily due to a 3.1% increase in retail customer sales volumes and a 9.6% increase in wholesale sales volumes. Total purchased power for 2006 increased 904,560 MWh, or a 5.4% increase over 2005. Increase in the purchased power volumes offset by slightly lower wholesale prices caused an increase of $19.2 million in 2006. The increase in costs also reflected the recovery of previously deferred excess power costs of $12.7 million due to lower power costs in 2006 than the baseline PCA mechanism rate as compared to a deferral of excess power costs of $15.7 million in 2005. Also contributing to the increase in costs was a Washington Commission order that allowed PSE to reflect additional power costs totaling $6.0 million during the PCA 2 period of July 1, 2003 through December 31, 2003, in 2005. In addition, transmission and other expenses increased $5.0 million due in part to increased kWh sales to customers.
PSE’s hydroelectric production and related power costs in 2006 were positively impacted by above-normal precipitation and snow packcolder average temperatures in the Pacific Northwest region,during the first half 2008 and during December 2008, which resultedcontributed $61.2 million. The increase was primarily offset by lower PGA mechanism rates that were effective October 1, 2007. PSE’s gas margin and net income are not affected by changes under the PGA mechanism. The effects of the PGA mechanism rate decrease of 13.0% were offset by a 2.8% natural gas general rate increase effective January 13, 2007, a 11.1% PGA rate increase effective October 1, 2008 and a 4.6% natural gas general rate increase effective November 1, 2008, resulting in a decrease of $53.5 million in natural gas operating revenues. The PGA mechanism passes through to customers increases or decreases in the runoff above Grand Coulee Reservoirnatural gas supply portion of the natural gas service rates based upon changes in the price of natural gas purchased from producers and wholesale marketers or changes in natural gas pipeline transportation costs.
Gas transportation sales increased $1.0 million, or 7.3%, to be 106.0%$14.7 million from $13.7 million. The increase was due to an increase in natural gas general rates effective January 13, 2007 and November 1, 2008 which contributed $0.8 million and an increase in gas transportation volume of normal as compared4.2 million or 2.0% which contributed $0.2 million.
Operating Expenses
Purchased electricity expenses increased $7.7 million, or 0.9%, to $903.3 million from $895.6 million. The increase primarily was a below normal runoffresult of 88.0%higher wholesale market prices during the first half of 2008 which contributed $57.4 million offset by a decrease in 2005.purchased power of 1,009.9 MWh or 6.0%, resulting in a decrease of $48.9 million. The January Early Bird Columbia Basin Runoff Forecast published bydecrease in purchased power is related to increased production from company-owned combustion turbines, wind facilities and thermal generating facilities. Also offsetting the National Weather Service Northwest River Forecast Center indicated that the total forecasted runoff above Grand Coulee Reservoir for the period January through July 2007 would be near historical averages.increase were decreased transmission costs and other expenses, which contributed $0.9 million.
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 $24.0$68.9 million, in 2006 comparedor 48.1%, to 2005$212.3 million from $143.4 million. The increase was primarily due to an increase of $17.4in generation from company-owned combustion turbine plants which contributed $66.6 million into the cost of fuel at PSE-controlled combustion turbine generating facilitiesand an increase of $2.3 million due to higher costs of natural gas offset by slightly lower volumes of electricity generated and anat the Colstrip, Montana coal-fired steam electric generation facility (Colstrip), which increased coal costs in 2008 as compared to 2007. The increase in the costcombustion turbine generation was due to lower hydroelectric generation and higher wholesale market price of coal at Colstrip generating facilities of $6.6 million compared to 2005.electricity.
Residential exchange credits associated with the Residential Purchase and Sale Agreement with the Bonneville Power Association (BPA)REP decreased $16.9$11.7 million, in 2006 comparedor 22.5%, to 2005$(40.7) million from $(52.4) million, as a result of lowerthe suspension of the residential and small farm customer electric rates.credit in rates effective June 7, 2007. The suspension was due to an adverse ruling from the United States Court of Appeals for the Ninth Circuit (Ninth Circuit) which states that BPA actions in entering into residential exchange settlement agreements with investor owned utilities were not in accordance with the law. In April 2008, PSE signed an agreement pursuant to which BPA would pay PSE $53.7 million for fiscal year 2008 REP benefits. Of this amount PSE received approval to pass-through to customers approximately $20.0 million over a one-month period. The remaining $33.7 million was used to offset PSE’s regulatory asset. The REP credit is a pass-through tariff item with a corresponding credit in electric operating revenue; thus, it has no impact on electric margin or net income. Effective October 1, 2006, the annual paymentBased upon a new REP agreement, PSE receives from BPA decreased to $105.5 million for the periodresumed passing through September 30, 2007. This will have no impact on PSE’s earnings as this payment is passed throughREP credits to customers through a lower residential exchange tariff credit.on November 1, 2008.
Purchased gas expenses increased $131.1decreased $24.2 million, in 2006 comparedor 3.2%, to 2005$737.9 million from $762.1 million. The decrease was primarily due to an increasea decrease in PGA rates as approved by the Washington Commission effective October 1, 2007 and partially offset by higher customer therm sales. The PGA mechanism allows PSE to recover expected natural gas costs, and defer, as a receivable or liability, any natural gas costs that exceed or fall short of this expected natural gas cost amount in PGA mechanism rates, including accrued interest. The PGA mechanism receivablepayable balance at December 31, 2006 and2008 was $8.9 million as compared to a payable balance at December 31, 20052007 of $77.9 million.
Net unrealized (gain) loss on derivative instruments changed by $10.2 million to $7.5 million loss from $(2.7) million gain. The increase was $39.8 millionprimarily a result of decreasing market prices in both electric and $67.3 million, respectively. PSE is authorized by the Washington Commission to accrue carrying costs on PGA receivable balances. A receivable balancegas sectors in the PGA mechanism reflects a current underrecoverythird and fourth quarters of market2008 which included Mid-Columbia and gas cost through rates. For further discussion on PGA rates see Item 1 - Business - Gas Regulation and Rates.derivative contracts. In addition, $6.1 million of this unrealized loss is associated with the ineffective portion of cash flow hedges for certain power purchase agreements.
Utility operations and maintenance expense increased $21.3$57.9 million, in 2006 comparedor 14.4%, to 2005$461.6 million from $403.7 million. The increase was primarily due to higher productiona $23.1 million increase in planned maintenance costs of $11.9 millionPSE’s generating facilities and a settlement related to Colstrip, a major overhauls$10.0 million increase in administrative and general expenses which included increases in maintenance of Colstrip Units 1electric general plant, company facility leases, insurance and 4, the Hopkins Ridge wind project which became operational on November 26, 2005, soil remediation costs at PSE’s Crystal Mountainliability claims, a $10.0 million increase in electric generation station sitetransmission and costs to repairdistribution expenses, a failure of PSE’s Whitehorn Unit 2 combustion turbine generator. $7.2$9.9 million of the increase was due to higher electric distribution system restoration costs as a result of a series of severe winter storms. In addition, customer service and call center costs increased $3.8 million andin gas operations and distribution costs increased $2.0 million. These increases were slightly offset byexpenses and a decrease of $3.6$5.5 million in other expenses. PSE anticipates operation and maintenance expense to increase in future years as investmentscustomer service expenses including bad debt expense.
Depreciation and amortization expense increased $32.9 million, or 11.8%, to $312.1 million from $279.2 million. Costs in new2007 included the benefit of the deferral of Goldendale electric generating resourcesfacility (Goldendale) ownership and energy delivery infrastructure are completed. The timing and amountsoperating costs of increases will vary depending on when new generating resources come into service.
A series of severe wind storms occurred during 2006 for$10.8 million which, PSE incurred significant costs, including a wind storm that occurred in December 2006 thathad it not been included, would have resulted in a lossan increase of electric service$43.7 million for 2008 as compared to over 700,0002007. The Goldendale deferral of PSE’s customers.ownership and operating costs ceased to be effective September 1, 2007, when PSE incurred over $72.0 million in estimated costs relatedwas authorized to this wind storm,begin recovering the majority of which were deferred in accordance with the Washington Commission’s orders. In total, PSE deferred $92.3 million of storm costs in 2006 as a result of a Washington Commission order that allowed deferral of qualified storm costs in excess of $7.0rates.
Conservation amortization increased $21.7 million, or 54.3%, to $61.7 million from $40.0 million. Qualifying storm costs are those that exceed the Institute of Electrical and Electronics Engineers (IEEE) standard for determining system average interruption duration index.
Conservation amortization increased $8.0 million in 2006 compared to 2005The increase was due to higher authorized recovery of electric and natural gas conservation expenditures. Conservation amortization is a pass-through tariff item with no impact on earnings.
Depreciation
Interest Expense and amortizationIncome Tax Expense
Interest expense increased $20.7decreased $11.7 million, in 2006 comparedor 5.7%, to 2005$194.8 million from $206.5 million. The decrease is due primarily to the effects of new generating and electric and gas distribution system plant placeddecrease in service, of which $8.1 million is from placing the Hopkins Ridge wind project in service on November 26, 2005.
Taxes other than income taxes increased $22.0 million in 2006 compared to 2005 primarily due to increases in revenue-based Washington State excise tax and municipal tax due to increased operating revenues. Revenue sensitive excise and municipal taxes have no impact on earnings. Excluding the impact of revenue sensitive taxes, taxes other than income taxes decreased $3.8 million primarilyaverage debt outstanding as a result of 2006 propertyan equity issuance in December 2007 and lower average interest rates on outstanding debt.
Income tax reduction settled with the Washington State Department of Revenueexpense decreased $13.3 million in August 2006 which resulted in a lower valuation for tax purposes in 20062008 as compared to 2005.
Income taxes increased $7.6 million in 2006 compared to 2005 was the result of higher taxable income slightly offset by a lower2007. The effective tax rate influenced bywas lower primarily due to higher production tax credits associated with the production of wind-powered energy (PTCs). The PTCs and the true-up of the prior year federal income tax provision which resultedfor 2008 were $23.0 million as compared to $20.2 million in an expense in 2006 versus a benefit in 2005.2007.
Other Income, Other Expenses, Other Income Taxes and Interest Charges
The table below sets forth significant changes in other income and interest charges for PSE from 2005 to 2006.Puget Energy
2009 compared to 2008
(Dollars in Millions) Twelve Months Ended December 31 | | 2006 | | 2005 | | Change | | Percent Change | |
| Other income | | $ | 29.6 | | $ | 16.8 | | | 12.8 | | | 76.2 | % |
| Other expenses | | | (10.0 | ) | | (11.1 | ) | | 1.1 | | | 9.9 | |
| Income taxes | | | (1.4 | ) | | 2.6 | | | (4.0 | ) | | * | |
| Interest charges | | | 169.0 | | | 165.0 | | | 4.0 | | | 2.4 | |
_______________All the operations of Puget Energy are conducted through its subsidiary PSE. “Predecessor” refers to the operations of Puget Energy and PSE prior to the consummation of the merger on February 6, 2009. “Successor” refers to the operations of Puget Energy and PSE subsequent to the merger. The merger was accounted for in accordance with ASC 805. The purchase price was allocated to the related assets and liabilities based on their respective fair values on the merger date with the remaining consideration recorded as goodwill. The fair values of assets are being amortized over their estimated useful lives in a manner that best reflects the economic benefits derived from such assets. Goodwill is not amortized, but is subject to impairment testing on an annual basis. Such adjustments to fair value and the allocation of purchase price between identifiable intangibles and goodwill will have an impact on Puget Energy’s expenses and profitability.
Puget Energy’s net income for the years ended December 31 was as follows:
| Puget Energy Consolidated Statements of Income | |
| (Dollars in Thousands) | Successor | | Predecessor | |
| Benefit/(Expense) | February 6, 2009 - December 31, 2009 | | January 1, 2009 – February 5, 2009 | | 2009 Combined | | Twelve Months Ended December 31, 2008 | | 2009-2008 Percent Change | | | Twelve Months Ended December 31, 2007 | | 2008-2007 Percent Change | |
PSE reported net income | $ | 127,641 | | $ | 31,611 | | $ | 159,252 | | $ | 162,736 | | | (2.1 | )% | | $ | 191,127 | | | (14.9 | )% |
Other operating revenue | | 361 | | | -- | | | 361 | | | -- | | | * | | | | -- | | | * | |
Purchased electricity | | 529 | | | -- | | | 529 | | | -- | | | * | | | | -- | | | * | |
Net unrealized gain on derivative instruments | | 151,481 | | | -- | | | 151,481 | | | -- | | | * | | | | -- | | | * | |
Non-utility expense and other | | (2,249 | ) | | (4 | ) | | (2,253 | ) | | (380 | ) | | * | | | | (1,206 | ) | | 68.5 | |
Merger and related costs | | (2,731 | ) | | (20,416 | ) | | (23,147 | ) | | (9,252 | ) | | * | | | | (8,143 | ) | | (13.6 | ) |
Depreciation and amortization | | 167 | | | -- | | | 167 | | | -- | | | * | | | | -- | | | * | |
Charitable contribution expense | | (5,000 | ) | | -- | | | (5,000 | ) | | -- | | | * | | | | -- | | | * | |
Interest expense 1 | | (71,250 | ) | | 25 | | | (71,225 | ) | | 851 | | | * | | | | 1,088 | | | * | |
Income tax expense | | (24,934 | ) | | 1,540 | | | (23,394 | ) | | 974 | | | * | | | | 1,598 | | | * | |
Puget Energy net income | $ | 174,015 | | $ | 12,756 | | $ | 186,771 | | $ | 154,929 | | | 20.6 | % | | $ | 184,464 | | | (16.0 | )% |
| * | Not meaningful |
| 1 | Puget Energy’s interest expense includes elimination adjustments of intercompany interest on short-term debt. |
Puget Energy’s net income for 2009 was $186.8 million on operating revenues of $3.3 billion as compared to net income of $154.9 million on operating revenues of $3.4 billion for the same period in 2008. The following are significant factors impacting Puget Energy’s net income:
Percent | · | Puget Energy’s net income was positively impacted by $151.5 million representing a change not applicable or meaningful.in net unrealized gain on derivative instruments as a result of the required recognition of all contracts at fair value as part of purchase accounting, including derivative contracts previously designated as Normal Purchase Normal Sale (NPNS). Certain of these contracts were subsequently redesignated as NPNS. The unrealized gain represents amortization of the fair values recorded. |
| · | These increases were partially offset by one-time merger costs of $23.1 million related to the merger of Puget Energy with Puget Holdings. These costs were primarily related to real estate excise tax, legal fees, transaction advisory services and stock options. |
| · | Net income was impacted by increases in interest expense of $72.1 million primarily related to the issuance of debt at the time of the merger and a $5.0 million charitable contribution to the PSE Foundation. Also impacting net income is a $6.8 million increase in expense due to pension and postretirement plan costs as a result of purchase accounting related to the merger, which was included in non-utility expense and other. |
Other income 2008 increased $12.8 million in 2006 compared to 20052007
Summary Results of Operations
All the operations of Puget Energy are conducted through its subsidiary PSE. There were no significant items under Puget Energy exclusive of PSE. For summary of results of operations, refer to PSE’s 2008 compared to 2007 summary of results of operations.
The following discussion provides the significant items that impact Puget Energy’s results of operations for the year ended December 31, 2009. For the year ended December 31, 2008, there were no significant items at Puget Energy.
2009 compared to 2008
Operating Expenses
Net unrealized gain on derivative instruments changed by a $151.5 million gain, which included $128.6 million gains from a favorable mark-to-market accounting of derivative contracts.
Merger and related costs increased $13.8 million at Puget Energy for 2009 related to compensation triggered by Puget Energy’s change of control, excise taxes associated with the transaction and financial advisor fees.
Other Income and Expense, Interest Expense and Income Tax Expense
Charitable contribution expense increased $5.0 million at Puget Energy for 2009, due to a charitable contribution to the PSE Foundation.
Interest expense at Puget Energy increased $72.1 million for 2009, primarily due to the term loan and credit facility fees related to the merger on February 6, 2009, which contributed $80.2 million. Offsetting this increase were the business combination fair value amortization of PSE’s fair value debt, PSE’s deferred debt costs, and PSE Treasury Locks, which contributed $8.6 million.
Income tax expense at Puget Energy increased $24.3 million for 2009. The increase for 2009 as compared to the same period in 2008 is due to an increase in the accrual of carrying costs on regulatory assets andpre-tax income combined with an increase in the equity portion of allowance for funds used during construction (AFUDC).
Other expenses decreased by $1.1 million due to a decrease in long-term share based incentive plan costs offset by certain regulatory penalty expenses incurred in 2006.
Income taxes on other income and expenses increased $4.0 million in 2006 as compared to 2005effective tax rate. The effective tax rate increase is a result of the increase in other income.
Interest charges increased $4.0 million in 2006 compared to 2005 dueattributable primarily to interest expense of $6.4 million related to an increase in debt due to construction projects offset by an increase in the debt AFUDC credit. .
InfrastruX
On May 7, 2006, Puget Energy sold its 90.9% interest in InfrastruX to an affiliate of Tenaska, resulting in after-tax cash proceeds of approximately $95.9 million, an after-tax gain of $29.8 million for 2006. Puget Energy accounted for InfrastruX as a discontinued operation under SFAS No. 144, “Accounting for the Impairment or Disposal of Long-Lived Assets” in 2005 and 2006.
Under the terms of the sale agreement, Puget Energy remains obligated for certain representations and warranties made by InfrastruX concerning its business through May 7, 2008. Puget Energy obtained a representation and warranty insurance policy and deposited $3.7 million into an escrow account as retention under the policy. As of December 31, 2006, long-term restricted cash in the amount of $3.8 million is included in the accompanying balance sheets and represents Puget Energy’s maximum exposure related to those commitments. Puget Energy also agreed to indemnify the purchaser for certain potential future losses related to one of InfrastruX’s subsidiaries through May 7, 2011, with the maximum amount of loss not to exceed $15.0 million. A liability in the amount of $5.0 million is included in the accompanying balance sheets as of December 31, 2006, which represents Puget Energy’s estimate of the fair value of the amount potentially payable using a probability-weighted approach to a range of future cash flows. Puget Energy also provided an environmental guarantee as part of the sale agreement. Puget Energy believes it will not have a future loss in connection with the environmental guarantee.
For 2006, Puget Energy reported InfrastruX related income from discontinued operations, including gain on sale, of $51.9 million compared to $9.5 million for 2005 (in each case, net of taxes and minority interest). Puget Energy’s income from discontinued operations for 2006 includes $7.3 million related to the reversal of a carrying value adjustment recorded in 2005 as well as $10.0 million related to the anticipated realization of a deferred tax asset associated with the sale of the business.
InfrastruX's operating revenue through May 7, 2006 was $138.6 million compared to $393.3 million for the twelve months ended December 31, 2005. Pre-tax income for the twelve months ended December 31, 2006 was $9.9 million compared to $36.4 million for the same period in 2005.
Puget Sound Energy
2005 compared to 2004
Energy Margins
The following table displays the details of electric margin changes from 2004 to 2005. 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) Twelve Months Ended December 31 | | 2005 | | 2004 | | Change | | Percent Change | |
Electric operating revenue1 | | $ | 1,612.9 | | $ | 1,423.0 | | $ | 189.9 | | | 13.3 | % |
| Less: Other electric operating revenue | | | (62.5 | ) | | (44.8 | ) | | (17.7 | ) | | (39.5 | ) |
| Add: Other electric revenue-gas supply resale | | | 26.1 | | | 11.4 | | | 14.7 | | | 128.9 | |
| Total electric revenue for margin | | | 1,576.5 | | | 1,389.6 | | | 186.9 | | | 13.4 | |
| Adjustments for amounts included in revenue: | | | | | | | | | | | | | |
| Pass-through tariff items | | | (26.9 | ) | | (25.4 | ) | | (1.5 | ) | | (5.9 | ) |
| Pass-through revenue-sensitive taxes | | | (104.9 | ) | | (94.2 | ) | | (10.7 | ) | | (11.4 | ) |
| Net electric revenue for margin | | | 1,444.7 | | | 1,270.0 | | | 174.7 | | | 13.8 | |
| Minus power costs: | | | | | | | | | | | | | |
Purchased electricity1 | | | (860.4 | ) | | (723.6 | ) | | (136.8 | ) | | (18.9 | ) |
Electric generation fuel1 | | | (73.3 | ) | | (80.8 | ) | | 7.5 | | | 9.3 | |
Residential exchange1 | | | 180.5 | | | 174.5 | | | 6.0 | | | 3.4 | |
| Total electric power costs | | | (753.2 | ) | | (629.9 | ) | | (123.3 | ) | | (19.6 | ) |
Electric margin2 | | $ | 691.5 | | $ | 640.1 | | $ | 51.4 | | | 8.0 | % |
_______________
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 $51.4 million in 2005 compared to 2004 primarily as a result of the Tenaska disallowance recorded in May 2004, and ongoing Tenaska disallowances, which reduced margin by $43.4 million for 2004 compared to $4.1 million in 2005. Other items that increased margin include a 3.0% increase in retail customer usage which contributed $18.7 million to margin. These increases were partially offset by a reduction in transmission and transportation revenues in 2005 compared to 2004 which reduced electric margin by $2.7 million. Customers also received a reduction in revenue of $2.6 million related to production tax credits for the Hopkins Ridge wind generating facility which lowered electric revenue and margin. These credits vary quarter to quarter and over time the amounts credited to customers through lower electric rates will equal the amount used for federal income taxes. A lower authorized return on electric generating facilities that became effective on March 4, 2005 also lowered electric margin by $2.3 million.
The following table displays the details of gas margin changes from 2004 to 2005. 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.non-deductible merger transaction costs.
| | | Gas Margin | |
(Dollars in Millions) Twelve Months Ended December 31 | | 2005 | | 2004 | | Change | | Percent Change | |
| Gas operating revenue | | $ | 952.5 | | $ | 769.3 | | $ | 183.2 | | | 23.8 | % |
| Less: Other gas operating revenue | | | (17.2 | ) | | (12.7 | ) | | (4.5 | ) | | (35.4 | ) |
Total gas revenue for margin1 | | | 935.3 | | | 756.6 | | | 178.7 | | | 23.6 | |
| Adjustments for amounts included in revenue: | | | | | | | | | | | | | |
| Pass-through tariff items | | | (5.7 | ) | | (3.6 | ) | | (2.1 | ) | | (58.3 | ) |
| Pass-through revenue-sensitive taxes | | | (73.1 | ) | | (59.3 | ) | | (13.8 | ) | | (23.3 | ) |
| Net gas revenue for margin | | | 856.5 | | | 693.7 | | | 162.8 | | | 23.5 | |
Minus purchased gas costs1 | | | (592.1 | ) | | (451.3 | ) | | (140.8 | ) | | (31.2 | ) |
Gas margin2 | | $ | 264.4 | | $ | 242.4 | | $ | 22.0 | | | 9.1 | % |
_______________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.
|
CAPITAL RESOURCES AND LIQUIDITY
Gas margin increased $22.0 million for 2005 compared to 2004. Gas margin increased $17.3 million as a result of the gas general tariff rate increase of 3.5% effective March 4, 2005. In addition, therm sales increased 2.4% for 2005 compared to 2004, which provided $5.8 million to gas margin and changes in customer class usage provided $3.9 million to gas margin.
Electric Operating Revenues
The table below sets forth changes in electric operating revenues for PSE from 2004 to 2005.
(Dollars in Millions) Twelve Months Ended December 31 | | 2005 | | 2004 | | Change | | Percent Change | |
| Electric operating revenues: | | | | | | | | | |
| Residential sales | | $ | 690.2 | | $ | 628.9 | | $ | 61.3 | | | 9.7 | % |
| Commercial sales | | | 629.0 | | | 581.0 | | | 48.0 | | | 8.3 | |
| Industrial sales | | | 93.9 | | | 88.8 | | | 5.1 | | | 5.7 | |
| Other retail sales, including unbilled revenue | | | 23.3 | | | 12.2 | | | 11.1 | | | 91.0 | |
| Total retail sales | | | 1,436.4 | | | 1,310.9 | | | 125.5 | | | 9.6 | |
| Transportation sales | | | 9.0 | | | 10.7 | | | (1.7 | ) | | (15.9 | ) |
| Sales to other utilities and marketers | | | 105.0 | | | 56.5 | | | 48.5 | | | 85.8 | |
| Other | | | 62.5 | | | 44.9 | | | 17.6 | | | 39.2 | |
| Total electric operating revenues | | $ | 1,612.9 | | $ | 1,423.0 | | $ | 189.9 | | | 13.3 | % |
Electric retail sales increased $125.5 million for 2005 compared to 2004 due primarily to rate increases related to the PCORC and the electric general rate case and increased retail customer usage. The PCORC and electric general rate case provided a combined additional $66.5 million to electric operating revenues for 2005 compared to 2004, which provided approximately $24.5 million in electric operating revenues. Retail electricity usage increased 588,645 MWh or 3.0% for 2005 compared to 2004. The increase in electricity usage was mainly the result of a 1.8% higher average number of customers served in 2005 compared to 2004.
During 2005, the benefits of the Residential and Small Farm Energy Exchange Benefit credited to customers reduced electric operating revenues by $189.0 million compared to $182.6 million for 2004. This credit also reduced power costs by a corresponding amount with no impact on earnings.
Sales to other utilities and marketers increased $48.5 million compared to 2004 primarily due to an increase of 569,613 MWh sold related to excess generation and energy available for sale on the wholesale market. This resulted primarily from normal streamflows for hydroelectric generation in the third quarter as compared to below normal streamflows that were expected. The increase in MWh sold was due to differences in timing of the need for power to serve base load and actual weather conditions.
Other electric revenues increased $17.6 million for 2005 compared to 2004, primarily from the sale of excess non-core gas purchased for intended electric generation. Non-core gas sales are included in the PCA mechanism calculation as a reduction in determining costs.
The following electric rate changes were approved by the Washington Commission in 2005 and 2004:
Type of Rate Adjustment | Effective Date | Average Percentage Increase in Rates | Annual Increase in Revenues (Dollars in Millions) |
| Power Cost Only Rate Case | May 24, 2004 | 3.2 | % | $ 44.1 |
| Electric General Rate Case | March 4, 2005 | 4.1 | % | 57.7 |
| Power Cost Only Rate Case | November 1, 2005 | 3.7 | % | 55.6 |
Gas Operating Revenues
The table below sets forth changes in gas operating revenues for PSE from 2004 to 2005.
(Dollars in Millions) Twelve Months Ended December 31 | | 2005 | | 2004 | | Change | | Percent Change | |
| Gas operating revenues: | | | | | | | | | |
| Residential sales | | $ | 592.4 | | $ | 479.0 | | $ | 113.4 | | | 23.7 | % |
| Commercial sales | | | 281.3 | | | 225.8 | | | 55.5 | | | 24.6 | |
| Industrial sales | | | 48.3 | | | 38.8 | | | 9.5 | | | 24.5 | |
| Total retail sales | | | 922.0 | | | 743.6 | | | 178.4 | | | 24.0 | |
| Transportation sales | | | 13.3 | | | 13.0 | | | 0.3 | | | 2.3 | |
| Other | | | 17.2 | | | 12.7 | | | 4.5 | | | 35.4 | |
| Total gas operating revenues | | $ | 952.5 | | $ | 769.3 | | $ | 183.2 | | | 23.8 | % |
Gas retail sales increased $178.4 million for 2005 compared to 2004 due to higher PGA mechanism rates in 2005, approval of a 3.5% general gas rate increase in the gas general rate case effective March 4, 2005 and higher customer gas usage. The Washington Commission approved PGA mechanism rate increases effective October 1, 2004 that increased rates 17.6% 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 2005, the effects of the PGA mechanism rate increases provided an increase of $123.8 million in gas operating revenues. In addition, the gas general rate increase provided an additional $17.3 million in gas operating revenue for 2005 compared to 2004. An increase of 3.1% in the average number of customers and lower temperatures in 2005 increased retail customer usage by 27.2 million therms or approximately $25.0 million in retail gas operating revenues.
The following gas rate adjustments were approved by the Washington Commission in 2005 and 2004:
Type of Rate Adjustment | Effective Date | Average Percentage Increase in Rates | Annual Increase in Revenues (Dollars in Millions) |
| PGA | October 1, 2004 | 17.6 | % | $ 121.7 |
| Gas General Rate Case | March 4, 2005 | 3.5 | % | 26.3 |
| PGA | October 1, 2005 | 14.7 | % | 121.6 |
Operating Expenses
The table below sets forth significant changes in operating expenses for PSE from 2004 to 2005.
(Dollars in Millions) Twelve Months Ended December 31 | | 2005 | | 2004 | | Change | | Percent Change | |
| Purchased electricity | | $ | 860.4 | | $ | 723.6 | | $ | 136.8 | | | 18.9 | % |
| Electric generation fuel | | | 73.3 | | | 80.8 | | | (7.5 | ) | | (9.3 | ) |
| Residential exchange | | | (180.5 | ) | | (174.5 | ) | | (6.0 | ) | | (3.4 | ) |
| Purchased gas | | | 592.1 | | | 451.3 | | | 140.8 | | | 31.2 | |
| Utility operations and maintenance | | | 333.3 | | | 291.2 | | | 42.1 | | | 14.5 | |
| Depreciation and amortization | | | 241.6 | | | 228.6 | | | 13.0 | | | 5.7 | |
| Taxes other than income taxes | | | 233.7 | | | 209.0 | | | 24.7 | | | 11.8 | |
| Income taxes | | | 89.6 | | | 77.1 | | | 12.5 | | | 16.2 | |
Purchased electricity expenses increased $136.8 million in 2005 compared to 2004 as a result of increased power purchases from higher customer usage and higher wholesale market prices offset by a reduction in the Tenaska disallowance related to the return on the Tenaska gas supply regulatory asset. The reduction of $39.3 million related to the Tenaska disallowance from 2004 included a February 23, 2005 Washington Commission order concerning PSE’s compliance filing related to the PCA 2 period of July 1, 2003 through June 30, 2004. In its order, the Washington Commission determined that PSE was allowed to reflect additional power costs totaling $6.0 million during the PCA 2 period of July 1, 2003 through December 31, 2003. These costs were reflected in the PCA mechanism, which resulted in a reduction in purchased electricity expense for 2005. Total purchased power for 2005 increased 1,336,501 MWh, or an 8.6% increase over 2004.
PSE’s hydroelectric production and related power costs in 2005 and 2004 were negatively impacted by below-normal precipitation and reduced snow pack in the Pacific Northwest region. The January 4, 2006 Columbia Basin Runoff Summary published by the National Weather Service Northwest River Forecast Center indicated that the total observed runoff above Grand Coulee Reservoir for 2005 was 88.0% of normal, which approximates the total observed runoff for 2004.
Electric generation fuel expense decreased $7.5 million in 2005 compared to 2004 primarily due to a $6.9 million charge recorded in 2004 related to a binding arbitration settlement between Western Energy Company and PSE. Excluding this settlement, electric generation fuel costs decreased $0.6 million related to overall lower cost of gas for combustion turbine units and cost of gas at those facilities totaling $5.6 million. The decrease in lower cost of gas was partially offset by an increase of the cost of coal of $5.0 million in 2005 compared to 2004 due to higher generation at Colstrip generating facilities of 56,797 MWh. Costs associated with electric generation fuel are reflected in the PCA mechanism.
The reduction in electric generation fuel was also the result of the Hopkins Ridge wind generation facility beginning operations on November 27, 2005. Generation from the Hopkins Ridge generation facility does not include fuel expenses in its operation.
Residential exchange credits associated with the Residential Purchase and Sale Agreement with BPA increased $6.0 million in 2005 compared to 2004 as a result of increased residential and small farm customer electric load. 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.
Purchased gas expenses increased $140.8 million in 2005 compared to 2004 primarily due to an increase in PGA rates as approved by the Washington Commission. 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 receivable balance at December 31, 2005 and 2004 was $67.3 million and $19.1 million, respectively. A receivable balance in the PGA mechanism reflects a current underrecovery of market gas cost through rates.
Utility operations and maintenance expense increased $42.1 million in 2005 compared to 2004 which includes an increase of $4.3 million related to low-income program costs that are passed-through in retail rates with no impact on earnings. As a result, the impact on net income from utility operations and maintenance for 2005 was an increase of $37.7 million. The increase for 2005 includes increases of $26.2 million related to higher gas distribution system expenses, planned maintenance costs for PSE-owned energy production facilities, electric distribution system costs, regulatory commission expense for rate cases and administrative costs. The production operation and maintenance increase for 2005 also includes a $1.5 million loss reserve associated with an arbitration panel’s ruling in favor of the Muckleshoot Indian Tribe relating to the operation of a fish hatchery on the White River recorded in the second quarter 2005. These increases were partially offset by lower storm damage repair costs of $5.5 million for 2005 due to less severe weather and outages. Total storm damage costs for 2005 totaled $3.6 million compared to $9.1 million in 2004.
Depreciation and amortization expense increased $13.0 million in 2005 compared to 2004 due primarily to the effects of new generating and electric and gas distribution system plant placed in service in 2005. New plant placed in service in 2005 includes $170.9 million for the Hopkins Ridge wind project in November 2005.
Taxes other than income taxes increased $24.7 million in 2005 compared to 2004 primarily due to increases in revenue-based Washington State excise tax and municipal tax due to increased operating revenues. Revenue sensitive excise and municipal taxes have no impact on earnings.
Income taxes increased $12.5 million in 2005 compared to 2004 as a result of higher taxable income and the non-recurrence of the one-time income tax benefit of $1.4 million in 2004 related to a 2001 tax audit.
Other Income and Interest Charges
The table below sets forth significant changes in other income and interest charges for PSE from 2005 to 2004.
(Dollars in Millions) Twelve Months Ended December 31 | | 2005 | | 2004 | | Change | | Percent Change | |
| Other income | | $ | 16.8 | | $ | 11.0 | | $ | 5.8 | | | 52.7 | % |
| Other expenses | | | (11.1 | ) | | (9.5 | ) | | (1.6 | ) | | (16.8 | ) |
| Interest charges | | | 165.0 | | | 166.4 | | | (1.4 | ) | | (0.8 | ) |
Other income increased $5.8 million in 2005 compared to 2004 primarily due to increases in the equity portion of allowance for funds used during construction and an increase in revenue from PSE’s basic ordering agreement for energy management projects with the U.S. Navy.
Other expenses decreased by $1.6 million primarily due to a decrease in long-term incentive plan costs due to not meeting the performance condition.
Interest charges decreased $1.4 million in 2005 compared to 2004 due to the redemption of $231.0 million of long-term debt with rates ranging from 3.40% to 6.93% in 2005. Also, in May 2005, PSE redeemed $42.5 million of PSE's 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). These redemptions and resulting decreases in interest expense were partially offset by the issuance of $250.0 million and $150.0 million of long-term senior notes in May 2005 and October 2005, respectively. In addition, debt AFUDC credited to interest expense increased $4.1 million due to increased construction activity in 2005.
InfrastruX
2005 compared to 2004
The following table summarizes Puget Energy’s income from discontinued operations for 2005 and 2004:
| (Dollars in Millions) | | 2005 | | 2004 | |
| Income from operations reported by InfrastruX | | $ | 11.4 | | $ | 6.8 | |
| Goodwill impairment | | | (13.9 | ) | | (91.2 | ) |
| Tax provision on goodwill impairment | | | -- | | | 24.9 | |
| Net (loss) at InfrastruX | | | (2.5 | ) | | (59.5 | ) |
| Goodwill impairment not recognized at Puget Energy | | | 13.9 | | | -- | |
| InfrastruX depreciation and amortization not recorded by Puget Energy, net of tax | | | 10.8 | | | -- | |
| Puget Energy tax benefit (valuation allowance) from goodwill impairment | | | 1.9 | | | (18.0 | ) |
| Carrying value adjustment to estimated fair value and transaction costs | | | (12.4 | ) | | -- | |
| Minority interest in income from discontinued operations | | | (2.2 | ) | | 7.1 | |
| Income (loss) from discontinued operations | | $ | 9.5 | | $ | (70.4 | ) |
In accordance with Statement of Financial Accounting Standards (SFAS) No. 144, Puget Energy adjusted the carrying value of its investment in InfrastruX to the estimate of fair value, less cost to sell, at December 31, 2005. After reflecting a $12.4 million carrying value adjustment and charge for transaction costs in 2005, Puget Energy’s equity investment in InfrastruX was $43.5 million at December 31, 2005 compared to $33.8 million at December 31, 2004. Puget Energy’s carrying value under SFAS No. 144 as compared to the estimated fair value of its InfrastruX investment was not impacted by the non-cash goodwill impairment recorded by InfrastruX under SFAS No. 142 due to discontinued operations of InfrastruX. As a result, Puget Energy did not record the effects of the goodwill impairment under SFAS No. 142 in 2005.
Capital Resources and Liquidity
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 December 31:
| Puget Energy | | Payments Due Per Period |
Contractual Obligations (Dollars in Millions) | | | Total | | | 2007 | | | 2008- 2009 | | | 2010- 2011 | | | 2012 & Thereafter |
| Long-term debt including interest | | $ | 5,444.4 | | $ | 294.9 | | $ | 654.8 | | $ | 741.0 | | $ | 3,753.7 |
| Short-term debt including interest | | | 328.1 | | | 328.1 | | | -- | | | -- | | | -- |
Junior subordinated debentures payable to a subsidiary trust including interest1 | | | 101.2 | | | 3.1 | | | 6.2 | | | 6.2 | | | 85.7 |
| Mandatorily redeemable preferred stock | | | 1.9 | | | -- | | | -- | | | -- | | | 1.9 |
| Service contract obligations | | | 159.8 | | | 30.7 | | | 69.0 | | | 45.6 | | | 14.5 |
| Non-cancelable operating leases | | | 120.3 | | | 15.5 | | | 50.3 | | | 21.4 | | | 33.1 |
Fredonia combustion turbines lease 2 | | | 65.4 | | | 6.1 | | | 12.5 | | | 46.8 | | | -- |
| Energy purchase obligations | | | 6,176.3 | | | 1,001.1 | | | 1,666.3 | | | 992.3 | | | 2,516.6 |
| Contract initiation payment/collateral requirement | | | 18.5 | | | -- | | | -- | | | 18.5 | | | -- |
| Financial hedge obligations | | | 3.6 | | | 2.2 | | | 1.4 | | | -- | | | -- |
| Purchase obligations | | | 44.6 | | | 10.5 | | | 34.1 | | | -- | | | -- |
| Non-qualified pension and other benefits funding and payments | | | 47.2 | | | 6.6 | | | 7.4 | | | 9.1 | | | 24.1 |
| Total contractual cash obligations | | $ | 12,511.3 | | $ | 1,698.8 | | $ | 2,502.0 | | $ | 1,880.9 | | $ | 6,429.6 |
| Puget Energy | | Amount of Commitment Expiration Per Period |
Commercial Commitments (Dollars in Millions) | | | Total | | | 2007 | | | 2008- 2009 | | | 2010- 2011 | | | 2012 & Thereafter |
Indemnity agreements 3 | | $ | 8.8 | | $ | -- | | $ | 3.8 | | $ | -- | | $ | 5.0 |
Credit agreement - available 4 | | | 281.5 | | | -- | | | -- | | | 281.5 | | | -- |
Receivable securitization facility5 | | | 90.0 | | | -- | | | -- | | | 90.0 | | | -- |
| Energy operations letter of credit | | | 0.5 | | | 0.5 | | | -- | | | -- | | | -- |
| Total commercial commitments | | $ | 380.8 | | $ | 0.5 | | $ | 3.8 | | $ | 371.5 | | $ | 5.0 |
_______________
1
| In 1997, PSE formed Puget Sound Energy Capital Trust I for the sole purpose of issuing and selling preferred securities (Trust Securities) to investors and issuing common securities to PSE. The proceeds from the sale of Trust Securities were used by the Trust to purchase Junior Subordinated Debentures (Debentures) from PSE. The Debentures are the sole assets of the Trusts and PSE owns all common securities of the Trusts.
|
2
| See “Fredonia 3 and 4 Operating Lease” under “Off-Balance Sheet Arrangements” below.
|
3
| 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 $3.8 million at December 31, 2006 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 $5.0 million at December 31, 2006. See “InfrastruX” above for further discussion.
|
4
| At December 31, 2006, PSE had available a $500.0 million unsecured credit agreement expiring in April 2011. The credit agreement provides credit support for letters of credit and commercial paper. At December 31, 2006, PSE had $0.5 million for an outstanding letter of credit and $218.0 million commercial paper outstanding, effectively reducing the available borrowing capacity to $281.5 million.
|
5
| At December 31, 2006, PSE had available a $200.0 million receivables securitization facility that expires in December 2010. $110.0 million was outstanding under the receivables securitization facility at December 31, 2006 thus leaving $90.0 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 and Puget Energy’s aggregate contractual obligations and commercial commitments as of December 31:
| | | | | Payments Due Per Period | |
Contractual Obligations (Dollars in Millions) | Total | | | 2010 | | | | 2011 – 2012 | | | | 2013 - 2014 | | | 2015 & Thereafter | |
Energy purchase obligations 1 | $ | 6,187.5 | | | $ | 1,232.7 | | | $ | 1,643.5 | | | $ | 1,174.3 | | | $ | 2,137.0 | |
Long-term debt including interest 2 | | 4,141.0 | | | | 421.5 | | | | 595.0 | | | | 345.1 | | | | 2,779.4 | |
| Short-term debt including interest | | 127.9 | | | | 127.9 | | | | -- | | | | -- | | | | -- | |
Service contract obligations 3 | | 474.1 | | | | 73.5 | | | | 135.8 | | | | 118.7 | | | | 146.1 | |
Non-cancelable operating leases 4 | | 142.4 | | | | 9.8 | | | | 24.3 | | | | 25.3 | | | | 83.0 | |
Capital leases 4 | | 54.3 | | | | 54.3 | | | | -- | | | | -- | | | | -- | |
Pension and other benefits funding and payments 5 | | 61.2 | | | | 16.5 | | | | 8.2 | | | | 9.8 | | | | 26.7 | |
| Total PSE contractual cash obligations | $ | 11,188.4 | | | $ | 1,936.2 | | | $ | 2,406.8 | | | $ | 1,673.2 | | | $ | 5,172.2 | |
Long-term debt, including interest 6 | | 1,778.4 | | | | 71.6 | | | | 143.4 | | | | 1,563.4 | | | | -- | |
Puget Energy capital leases 4 | | 80.0 | | | | 37.4 | | | | 42.6 | | | | -- | | | | -- | |
Less: Inter-company short-term debt and interest elimination 8 | | (22.9 | ) | | | (22.9 | ) | | | -- | | | | -- | | | | -- | |
| Total Puget Energy contractual cash obligations | $ | 13,023.9 | | | $ | 2,022.3 | | | $ | 2,592.8 | | | $ | 3,236.6 | | | $ | 5,172.2 | |
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 | | $ | 5,444.4 | | $ | 294.9 | | $ | 654.8 | | $ | 741.0 | | $ | 3,753.7 |
| Short-term debt including interest | | | 352.5 | | | 352.5 | | | -- | | | -- | | | -- |
Junior subordinated debentures payable to a subsidiary trust including interest1 | | | 101.2 | | | 3.1 | | | 6.2 | | | 6.2 | | | 85.7 |
| Mandatorily redeemable preferred stock | | | 1.9 | | | -- | | | -- | | | -- | | | 1.9 |
| Service contract obligations | | | 159.8 | | | 30.7 | | | 69.0 | | | 45.6 | | | 14.5 |
| Non-cancelable operating leases | | | 120.3 | | | 15.5 | | | 50.3 | | | 21.4 | | | 33.1 |
Fredonia combustion turbines lease 2 | | | 65.4 | | | 6.1 | | | 12.5 | | | 46.8 | | | -- |
| Energy purchase obligations | | | 6,176.3 | | | 1,001.1 | | | 1,666.3 | | | 992.3 | | | 2,516.6 |
| Contract initiation payment/collateral requirement | | | 18.5 | | | -- | | | -- | | | 18.5 | | | -- |
| Financial hedge obligations | | | 3.6 | | | 2.2 | | | 1.4 | | | -- | | | -- |
| Purchase obligations | | | 44.6 | | | 10.5 | | | 34.1 | | | -- | | | -- |
| Non-qualified pension and other benefits funding and payments | | | 47.2 | | | 6.6 | | | 7.4 | | | 9.1 | | | 24.1 |
| Total contractual cash obligations | | $ | 12,535.7 | | $ | 1,723.2 | | $ | 2,502.0 | | $ | 1,880.9 | | $ | 6,429.6 |
Puget Sound Energy. The following are PSE’s and Puget Energy’s aggregate availability under commercial commitments as of December 31, 2006:31:
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 3 | | $ | 281.5 | | $ | -- | | $ | -- | | $ | 281.5 | | $ | -- |
Receivable securitization facility4 | | | 90.0 | | | -- | | | -- | | | 90.0 | | | -- |
| Energy operations letter of credit | | | 0.5 | | | 0.5 | | | -- | | | -- | | | -- |
| Total commercial commitments | | $ | 372.0 | | $ | 0.5 | | $ | -- | | $ | 371.5 | | $ | -- |
| | Amount of Available Commitments Expiration Per Period | |
Commercial Commitments (Dollars in Millions) | Total | | | 2010 | | | | 2011 – 2012 | | | | 2013 – 2014 | | | 2015 & Thereafter | |
PSE working capital facility 7 | $ | 400.0 | | | $ | -- | | | $ | -- | | | $ | 400.0 | | | $ | -- | |
PSE capital expenditures facility 7 | | 295.0 | | | | -- | | | | -- | | | | 295.0 | | | | -- | |
PSE energy hedging facility 7 | | 343.0 | | | | -- | | | | -- | | | | 343.0 | | | | -- | |
Inter-company short term interest and debt 8 | | 7.1 | | | | 7.1 | | | | -- | | | | -- | | | | -- | |
| Total PSE commercial commitments | $ | 1,045.1 | | | $ | 7.1 | | | $ | -- | | | $ | 1,038.0 | | | $ | -- | |
Puget Energy capital expenditures facility 6 | | 742.0 | | | | -- | | | | -- | | | | 742.0 | | | | -- | |
Less: Inter-company short term interest and debt elimination 8 | | (7.1 | ) | | | (7.1 | ) | | | -- | | | | -- | | | | -- | |
| Total Puget Energy commercial commitments | $ | 1,780.0 | | | $ | -- | | | $ | -- | | | $ | 1,780.0 | | | $ | -- | |
____________________________
1 | See note 1 above.
Energy purchase contracts were entered into as part of PSE’s obligation to serve retail electric and natural gas customers’ energy requirements. As a result, costs are generally recovered either through base retail rates or adjustments to retail rates as part of the power and natural gas cost adjustment mechanisms. |
2 | See note 2 above. Note 9 “Long-Term Debt,” of the notes to the consolidated financial statements for individual long-term debt maturities. For Puget Energy the amount above excludes the fair value adjustments related to the merger. |
3 | See note 4 above.
Represents operational agreements, settlements and other contractual obligations with respect to generation, transmission and distribution facilities. These costs are generally recovered through base retail rates. |
4 | See Note 13 “Leases,” of the notes to the consolidated financial statements for additional information. |
| 5 | Pension and other benefit expected contributions represent PSE’s estimated cash contributions to the pension plan through 2015. |
| 6 | As of December 31, 2009, Puget Energy had fully drawn on a five-year term loan of $1.2 billion and incurred a $258.0 million draw under its $1.0 billion Puget Energy capital expenditure facility. This balance excludes a purchase price adjustment from the merger. |
| 7 | As of December 31, 2009, PSE had credit facilities totaling $1.15 billion of which $105.0 million had been drawn. These consisted of $400.0 million to fund operating expenses, $400.0 million to fund capital expenditures and $350.0 million to support energy and natural gas hedging. In addition, a $7.0 million letter of credit was outstanding under the $350.0 million hedging facility. |
| 8 | As of December 31, 2009, PSE has a revolving credit facility with Puget Energy in the form of a promissory note 5 above.to borrow up to $30.0 million of which $22.9 million was drawn. |
Off-Balance Sheet Arrangements
Fredonia 3 and 4 Operating Lease. PSE leases two combustion turbinesUtility Construction Program
PSE’s construction programs for its Fredonia 3 and 4generating facilities, the electric generating facility pursuant to a master operating lease that was amended for this purpose in April 2001. The lease has a term expiring in 2011, but can be canceled by PSE at any time. Payments under the lease vary with changes in the London Interbank Offered Rate (LIBOR). At December 31, 2006, PSE’s outstanding balance under the lease was $51.1 million. The expected residual value under the lease is the lesser of $37.4 million or 60.0% of the cost of the equipment. In the event the equipment is sold to a third party upon termination of the leasetransmission system and the aggregate sales proceeds are less than the unamortized value of the equipment, PSE would be required to pay the lessor contingent rent in an amount equal to the deficiency up to a maximum of 87.0% of the unamortized value of the equipment.
Utility construction Program
Utility construction expenditures for generation, transmissionnatural gas and electric distribution systems are designed to meet continuingregulatory requirements, customer growth and to support reliability of PSE’sreliable energy delivery systems. Constructiondelivery. The cash flow from construction expenditures, excluding equity AFUDC and customer refundable contributions were $575.1was $775.3 million for 2006. Utilityin 2009. Presently planned utility construction expenditures, excluding AFUDC, for 2010, 2011 and excluding new generation resources other than the Wild Horse project (which will be determined as the company proceeds through the integrated resource planning process) are anticipated to be the following in 2007, 2008 and 2009:2012 are:
Capital Expenditure Projections (Dollars in Millions) | | 2007 | | 2008 | | 2009 | | 2010 | | 2011 | | 2012 | |
| Energy delivery, technology and facilities | | $ | 530 | | $ | 555 | | $ | 640 | | $ | 657 | | $ | 596 | | $ | 591 | |
| New resources | | | 120 | | | 70 | | | 210 | | | 369 | | | 524 | | | 513 | |
| Total expenditures | | $ | 650 | | $ | 625 | | $ | 850 | | $ | 1,026 | | $ | 1,120 | | $ | 1,104 | |
The proposed utilityprogram is subject to change to respond to general business, economic and regulatory conditions. Utility construction expenditures and any new generation resource expenditures that may be incurred are anticipated to be funded with a combination of sources that may include cash from operations, short-term debt, long-term debt andand/or equity. Construction expenditure estimates, includingPSE’s planned capital expenditures result in a level of spending that will likely exceed its cash flow from operations. As a result, execution of PSE’s strategy is dependent in part on continued access to the new generation resources, are subject to periodic review and adjustment in light of changing economic, regulatory, environmental and efficiency factors.capital markets.
New Generation Resources
On December 22, 2006, PSE placed into service the Wild Horse wind project. Wild Horse is located in central Washington State. The Wild Horse wind project features 127 turbines providing up to 229 MW, generating enough wind-fueled electricity on average to serve 76,000 of the Company’s electric customers in Western Washington and Kittitas County.
Capital Resources
Cash From Operations
Puget Sound Energy
Cash generated from operations for 2006the year ended December 31, 2009 was $185.5$720.7 million, which is 23.7%an increase of $174.3 million from the $546.4 million generated during the year ended December 31, 2008. The increase was primarily the result of the $783.4 million used for utility construction expenditures and other capital expenditures. For 2005,following factors:
| · | An overrecovery of natural gas costs through the PGA mechanism during 2009 of $40.7 million compared to a reduction in the overcollection of $69.0 million to customers in 2008 which increased cash flow from operating activities by $109.7 million. |
| · | Accounts receivable and unbilled revenue decreased $64.3 million in 2009 compared to an increase of $33.1 million in 2008 due to increased collections from customers, causing an operating cash flow increase of $97.4 million. |
| · | PSE recognized $116.4 million greater net deferred income taxes and tax credits during 2009 as compared to 2008. |
| · | Fuel and gas inventory decreased by $24.4 million during 2009 compared to an increase of $20.4 during 2008, which resulted in an increase of $44.8 million. |
| · | Accrued expenses and other current liabilities increased $7.7 million in 2009 compared to a decrease of $2.8 million in 2008, resulting in an increase of $10.5 million to operating cash flows. |
The increase in cash generated from operating activities in 2009 was partially offset by the following:
| · | Net payments of $35.2 million on accounts payable during 2009 compared to net purchases of $20.7 million in 2008 due to the timing of payments, which resulted in a decrease of $55.9 million. |
| · | An increase in prepaid income taxes for 2009 by $107.1 million compared to the same period in 2008. |
| · | Increased net payments made for the residential exchange program by $38.6 million over 2008. |
| · | PSE also incurred $21.8 million of deferred regulatory costs related to Mint Farm and Wild Horse expansion during 2009. |
Puget Energy
Cash generated from operations for the year ended December 31, 2009 was $255.8$1.1 billion, an increase of $531.8 million which is 42.1%from the $536.6 million generated in 2008. The increase included $174.3 million from the cash provided by the operating activities of PSE, discussed above. In addition, the increase was primarily the result of the $608.0 million used for utility construction expenditures and other capital expenditures.following:
| · | $524.4 million in derivative settlement payments reclassified to financing activities as a result of the merger. These contracts represent proceeds received from derivative instruments that included financing elements at the merger date. |
| · | Puget Energy recognized $45.8 million greater net deferred income taxes and tax credits during 2009 as compared to 2008 than PSE over the same period. |
The overallincrease in cash generated from operating activities for 2006 decreased $70.3 million compared to 2005. The decrease was primarily attributable to deferred storm damage costs of $92.3 million and to a non-refundable capacity reservation payment of $89.0 million in April 2006 for the Chelan PUD power sales agreement which will begin providing power to PSE at the end of 2011. In addition, $37.7 million of cash collateral related to natural gas supply contracts was returned in 2006 and $55.0 million was received in 2005 for funds received from a gas pipeline capacity contract obligation of Duke Energy Marketing and Trading. Further, there was an increase of $83.4 million in payments made for accounts payable related to energy purchases which contributed to the decrease. Partially offsetting the decrease was an increase in accounts receivable balances of $139.7 million2009 as compared to 2005 which2008 was primarily attributable to the changepartially offset by a net increase of $54.5 million in the accounts receivable securitization program. In addition, there was an increase in cash received for the purchasednatural gas receivable adjustmentpayments and payment of $75.8 million, a beneficial increase in the change of thegas financial hedge contracts, power cost adjustment of $30.4 million, an increase inand other payable and accrued expenses of $15.9 million and a decrease in BPA prepaid transmission of $10.8 million in 2005 that further offset the decrease in cash generated from operating activities.
expense balances as compared to PSE’s net payments.
Financing Program
Financing utility construction requirements and operational needs are largely dependent upon the amount of cash available and the cost and availability of external funds throughfrom the capital markets and from financial institutions.markets. PSE anticipates refinancing the redemption of bonds with its liquidity facilities and/or the issuance of new bonds. Access to funds depends upon factors such as general economic conditions, regulatory authorizationsclimate and policies, and Puget Energy’s and PSE’s credit ratings.ratings and investor receptivity to investing in the utility industry and PSE.
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, restated articles of incorporation and certain loan agreements. Under the most restrictive tests, at December 31, 2006, PSE could issue:
· | approximately $262.0 million of additional first mortgage bonds under PSE’s electric mortgage indenture based on approximately $437.0 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 December 31, 2006; |
· | approximately $365.0 million of additional first mortgage bonds under PSE’s gas mortgage indenture based on approximately $608.0 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 December 31, 2006; |
· | approximately $802.8 million of additional preferred stock at an assumed dividend rate of 6.5%; and |
· | approximately $688.8 million of unsecured long-term debt. |
At December 31, 2006, PSE had approximately $4.0 billion in electric and gas ratebase to support the interest coverage ratio limitation test for net earnings available for interest. SFAS No. 158 will not have an impact on PSE’s ratebase.
Credit Ratings
The ratings of Puget Energy and PSE, as of February 21, 2007, were:
| 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 |
Trust preferred securities | 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 PSE’s credit facilities.
|
Neither Puget Energy nor PSE has any debt outstanding that would accelerate debt maturity upon a credit rating downgrade. However, 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 any or a combination of PSE’s debt ratings may prompt counterparties on a contract by contract basis in the wholesale electric, wholesale gas and financial derivative markets to require PSE to post a letter of credit or other collateral, make cash prepayments, obtain a guarantee agreement or provide other mutually agreeable security.
Shelf Registrations, Long-Term Debt and Common Stock Activity
On March 16, 2006, Puget Energy and PSE filed a shelf registration statement with the Securities and Exchange Commission for the offering of:
· | common stock of Puget Energy; |
· | senior notes of PSE, secured by first mortgage bonds; |
· | preferred stock of PSE; and |
· | trust preferred securities of Puget Sound Energy Capital Trust III. |
The registration statement is valid for three years and does not specify the amount of securities that the Company may offer. The Company is subject to restrictions under PSE’s indentures and articles of incorporation on the amount of first mortgage bonds, unsecured debt and preferred stock that the Company may issue.
On September 18, 2006, PSE completed the issuance of $300.0 million of senior secured notes at a rate of 6.274%, which are due on March 15, 2037. The net proceeds from the issuance of the senior notes of approximately $297.4 million will be used to repay PSE’s outstanding short-term debt which was incurred primarily to fund construction programs. The yield to maturity of the $300.0 million senior secured notes was 6.29% after the settlement of two forward starting swap contracts.
On June 30, 2006, PSE redeemed for $200.0 million all of the outstanding shares of 8.40% Trust Originated Preferred Securities of The Puget Sound Energy Capital Trust II (classified as Junior Subordinated Debentures of the Corporation Payable to a Subsidiary Trust Holding Mandatorily Redeemable Preferred Securities on the balance sheet) at $25.0 par value per share plus accrued interest to the redemption date.
On June 30, 2006, PSE completed the issuance of $250.0 million of senior secured notes at a rate of 6.724% which are due on June 15, 2036. The net proceeds from the issuance of the senior notes of approximately $247.8 million were used to redeem $200.0 million of 8.40% Trust Originated Preferred Securities of the Puget Sound Energy Capital Trust II, which were redeemed at par on June 30, 2006, and to repay a portion of PSE’s short-term debt. The short-term debt was incurred to repay $46.0 million of 8.06% senior notes that matured June 19, 2006. The yield to maturity of the $250.0 million senior secured notes was 6.17% after the settlement of two forward starting swap contracts.
Based on PSE's goal to become a more vertically integrated utility, it is expected that further issuances of debt, equity or a combination of the two will be necessary in the future. The structure, timing and amount of such financings depend on market conditions and financing needed.
Liquidity Facilities and Commercial Paper
PSE’s short-term borrowings and sales of commercial paper are used to provide working capital and funding of utility construction programs. Puget Energy and PSE have not been significantly impacted by the recent disruption in the credit environment.
As of December 31, 2009 and 2008, PSE Credit Facilities
The Company has twohad $105.0 million and $964.7 million in short-term debt outstanding, exclusive of the demand promissory note with Puget Energy, with a weighted average interest rate of 3.59% and 3.84%, respectively. As of December 31, 2008, PSE had four committed credit facilities that provide,provided, in aggregate, $700.0 million$1.425 billion in short-term borrowing capability. These includeThose included a $500.0 million unsecured revolving credit agreement, and a $200.0 million accounts receivable securitization facility. Thefacility, a $375.0 million unsecured short-term credit facility and a $350.0 million unsecured credit agreement can be terminated by either party upon written notice.to support hedging activity. Effective with the merger on February 6, 2009, the existing credit agreements were replaced with three new credit facilities as described below.
Puget Sound Energy Credit Facilities
Effective with the merger of Puget Energy and Puget Holdings on February 6, 2009, PSE payshas three committed unsecured revolving credit facilities that provide, in the aggregate, $1.150 billion in short-term borrowing capability. These new facilities include a varying$400.0 million credit agreement for working capital needs, a $400.0 million credit facility for funding capital expenditures and a $350.0 million facility to support energy hedging activities.
PSE's credit agreements contain usual and customary affirmative and negative covenants that, among other things, place limitations on its ability to incur additional indebtedness and liens, issue equity, pay dividends, transact with affiliates and make dispositions and investments. The credit agreements also contain financial covenants, whose measurement periods began with the third quarter 2009 financial statements, based on the following three ratios: cash flow interest coverage; cash flow debt leverage and debt service coverage. PSE certifies its compliance with such covenants each quarter with the lending banks. As of December 31, 2009, PSE exceeded each of the ratio minimums.
These facilities mature in 2014, contain similar terms and conditions, and are syndicated among numerous committed lenders and financial institutions. The agreements provide PSE with the ability to borrow at different interest rate on outstanding borrowings based on terms entered intooptions and include variable fee levels. The bank credit agreements allow PSE to borrow at the timebank’s prime rate or to make floating rate advances at the London Interbank Offered Rate (LIBOR) plus a spread that is based upon PSE’s credit rating. The $400.0 million working capital facility and $350.0 million credit agreement to support energy hedging allow for issuing standby letters of credit up to the entire amount of the borrowings.credit agreements. The $400.0 million working capital facility also serves as a backstop for PSE’s commercial paper program.
As of December 31, 2009, PSE had $105.0 million outstanding on the $400.0 million capital expenditures facility, a $7.0 million letter of credit outstanding under the $350.0 million facility supporting energy hedging and no outstanding balance on the $400.0 million working capital facility.
Demand Promissory Note. 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 averageweighted-average interest rate ofof: (a) PSE’s outstanding commercial paper interest rate;rate or (b) PSE’s senior unsecured revolving credit facility; or (c) thefacility. Absent such borrowings, interest rate available under the receivable securitization facility of PSE Funding, Inc., a PSE subsidiary, which is thecharged at one-month LIBOR rate plus a marginal rate.0.25%. At December 31, 2006,2009, the outstanding balance of the Note was $24.3$22.9 million. The outstanding balance and the related interest under the Note are eliminated by Puget Energy upon consolidation of PSE’s financial statements.
Puget Energy Credit Agreement. In March 2005, PSE entered intoFacilities
As of December 31, 2009, Puget Energy has a $1.225 billion five-year $500.0 million unsecuredterm loan and a $1.0 billion credit agreementfacility for funding capital expenditures. Puget Energy’s credit agreements contain usual and customary affirmative and negative covenants similar to PSE's credit facilities. Puget Energy's financial covenants include cash flow interest coverage and cash flow debt leverage ratios whose measurement periods began with a groupthe third quarter 2009 financial statements. Puget Energy certifies its compliance with such covenants each quarter with the lending banks. As of banks. In April 2006, PSE amended this credit agreement to extend the expiration date from April 2010 to April 2011. The agreement is primarily used to provide credit support for commercial paper and letters of credit. Under the termsDecember 31, 2009, Puget Energy exceeded each of the credit agreement, PSE pays a floatingratio minimums.
These facilities mature in 2014, contain similar terms and conditions, and are syndicated among numerous committed lenders and financial institutions. The agreements provide Puget Energy with the ability to borrow at different interest rate on outstanding borrowings based either onoptions and include variable fee levels. Borrowings may be at the agent bank’s prime rate or at floating rates based on LIBOR plus a marginal ratespread that is based on PSE’s long-termupon Puget Energy’s credit rating at the time of borrowing. PSE paysrating. Puget Energy must also pay a commitment fee on anythe unused portion of the credit agreement which is also based$1.0 billion facility. The spreads and the commitment fee depend on long-termPuget Energy’s credit ratings as determined by Standard & Poor’s (S&P) and Moody’s Investment Services (Moody’s). Based on Puget Energy’s credit ratings as of PSE.the date of this report, the spread over prime rate is 1.25%, the spread to the LIBOR is 2.25% and the commitment fee is 0.84%. As of December 31, 2009, the term loan was fully drawn and $258.0 million was outstanding under the $1.0 billion facility.
Long-term Funding and Restrictive Covenants
Bond Issuances. On January 23, 2009, PSE issued $250.0 million of senior notes, secured by first mortgage bonds. The bonds, were placed with approximately 35 institutional investors, have a term of seven years and carry a 6.75% interest rate. Net proceeds from the issue were used to repay short-term debt incurred to fund in part the utility’s capital expenditures.
On September 11, 2009, PSE issued $350.0 million of senior notes, secured by first mortgage bonds. The bonds, were placed with approximately 80 institutional investors, have a term of 30 years and carry a 5.757% interest rate. Net proceeds from the issue were used to repay short-term debt which had been incurred primarily for earlier retirement of maturing long-term debt and to fund in part the utility’s capital expenditures.
Dividend Payment Restrictions. The payment of dividends by PSE to Puget Energy is restricted by provisions of certain covenants applicable to long-term debt contained in PSE’s electric and natural gas mortgage indentures. At December 31, 2006, there2009, approximately $468.0 million of unrestricted retained earnings was $0.5available for the payment of dividends under the most restrictive mortgage indenture covenant.
In addition, beginning February 6, 2009, as approved in the Washington Commission merger order, dividends may not be declared or paid if PSE’s common equity ratio, calculated on a regulatory basis, is 44.0% or below except to the extent a lower equity ratio is ordered by the Washington Commission. In addition, pursuant to the merger order, PSE may not declare or make any distribution unless on the date of distribution PSE’s corporate credit/issuer rating is investment grade (equal to or greater than BBB- with S&P and Baa3 with Moody’s), or, if its credit rating is below investment grade, PSE’s ratio of Earnings Before Interest, Tax, Depreciation and Amortization (EBITDA) to interest for the most recently ended four fiscal quarter periods prior to such date is equal to or greater than three to one.
PSE’s ability to pay dividends is also limited by the terms of its credit facilities. Under the credit facilities, PSE is not permitted to pay dividends during any Event of Default (as defined in the facilities), such as failure to comply with certain financial covenants.
Puget Energy’s ability to pay dividends to its shareholder is also limited by the merger order as well as by the terms of its credit facilities, beginning February 6, 2009. Pursuant to the merger order, Puget Energy may not declare or make a distribution unless on such date Puget Energy’s ratio of consolidated EBITDA to consolidated interest expense for the four most recently ended fiscal quarters prior to such date is equal to or greater than two to one. In accordance with terms of the Puget Energy credit facilities, Puget Energy is not permitted to pay dividends during any Event of Default (as defined in the facilities), such as failure to comply with certain financial covenants. In addition, in order to declare or pay unrestricted dividends, Puget Energy’s FFO to Interest Coverage Ratio (as defined in the facility) may not be less than 1.5 to one and its FFO to Debt Ratio (as defined in the facility) may not be less than 8.25% for the 12 months ending each quarter-end. Puget Energy is also subject to other restrictions, such as a "lock up" provision that, in certain circumstances, such as failure to meet certain cash flow tests, may further restrict Puget Energy's ability to pay dividends.
At December 31, 2009, the Company met or exceeded all restrictive test minimums required for the payment of dividends.
Debt Restrictive Covenants. The type and amount of future long-term financing for Puget Energy and PSE are limited by provisions in their credit agreements and restated articles of incorporation as well as PSE’s mortgage indentures. Under its credit agreements, Puget Energy is generally limited to permitted refinancings and borrowings under its credit facilities and by restrictions placed upon its subsidiaries. One such restriction limits PSE’s long-term debt issuances to not exceed $500.0 million per year, plus any amount needed to refinance maturing bonds. Unused amounts under this limitation may be carried forward into future years. Puget Energy’s facilities contain a provision whereby additional capital expenditure loans up to $750.0 million may, under certain conditions, be made available after the $1.0 billion capital expenditure commitment has been fully borrowed.
PSE may be limited by certain restrictions contained in its credit facilities, its electric and natural gas mortgage indentures and certain loan agreements. Under the most restrictive tests, at December 31, 2009, PSE could issue:
| · | approximately $1.0 billion of additional first mortgage bonds under PSE’s electric mortgage indenture based on approximately $1.7 billion of electric bondable property available for issuance, subject to an interest coverage ratio limitation of 2.0 times net earnings available for interest (as defined in the electric utility mortgage), which PSE exceeded at December 31, 2009; and |
| · | approximately $644.0 million of additional first mortgage bonds under PSE’s natural gas mortgage indenture based on approximately $1.1 billion of gas bondable property available for issuance, subject to interest coverage ratio limitations of 1.75 times and 2.0 times net earnings available for interest (as defined in the natural gas utility mortgage), which PSE exceeded at December 31, 2009. |
At December 31, 2009, PSE had approximately $5.5 billion in electric and natural gas ratebase to support the interest coverage ratio limitation test for net earnings available for interest.
Credit Ratings
Neither Puget Energy nor PSE have 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 Puget Energy’s and PSE’s credit facilities, the borrowing costs and commitment fee increase as their respective credit 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-2/P-3 ratings by S&P and Moody’s, respectively. In addition, downgrades in any or a combination of PSE’s debt ratings may prompt counterparties on a contract by contract basis in the wholesale electric, wholesale natural gas and financial derivative markets to require PSE to post a letter of credit or other collateral, make cash prepayments, obtain a guarantee or provide other mutually agreeable security.
On January 16, 2009, S&P raised its corporate credit rating on PSE to BBB from BBB- while it also lowered its corporate credit rating on Puget Energy to BB+ from BBB-. The rating actions reflected the anticipated completion of the acquisition of Puget Energy and $218.0PSE by Puget Holdings, which occurred on February 6, 2009. In taking this action, S&P noted that the acquisition was expected to increase total net debt by $850.0 million commercial paper outstanding, effectivelyon a consolidated basis while reducing debt at PSE. At the available borrowing capacity undersame time, S&P removed both companies’ ratings from credit watch with negative implications and revised its ratings outlook to stable.
On February 2, 2009, Moody’s downgraded the issuer rating of Puget Energy to Ba2 from Ba1 and affirmed the long-term ratings of PSE. The ratings downgrade at Puget Energy reflected Moody’s concern about the increase in financial risk resulting from the additional debt being introduced from the acquisition by Puget Holdings. The ratings outlook for both companies is stable.
On August 3, 2009, Moody’s upgraded the Senior Secured Debt rating of PSE to Baa1 from Baa2.
On February 1, 2010, Moody’s reaffirmed the issuer rating on PSE at Baa3 and the issuer rating on Puget Energy at Ba2.
On February 18, 2010, S&P reaffirmed the corporate credit facility to $281.5 million.rating on PSE at BBB and corporate credit rating on Puget Energy at BB+.
Receivables Securitization Facility.The ratings of Puget Energy and PSE, entered intoas of February 25, 2010 were as follows:
| Ratings |
| S&P | Moody’s |
| Puget Sound Energy, Inc. | | |
| Corporate credit/issuer rating | BBB | Baa3 |
| Senior secured debt | A- | Baa1 |
| Junior subordinated notes | BB+ | Ba1 |
| Commercial paper | A-2 | P-3 |
| Bank facilities | BBB | Baa3 |
| Ratings outlook | Stable | Stable |
| Puget Energy, Inc. | | |
| Corporate credit/issuer rating | BB+ | Ba2 |
| Bank facilities | BB+ | Ba2 |
| Ratings outlook | Stable | Stable |
Shelf Registrations, Long-Term Debt and Common Stock Activity
In connection with the closing of the merger, all shelf registration statements of Puget Energy were terminated. On March 13, 2009, PSE filed with the SEC a five-year Receivable Sales Agreement withnew shelf registration statement to provide for the offering of senior notes of PSE, Funding, Inc. (PSE Funding), a wholly owned subsidiary,secured by first mortgage bonds, and unsecured debentures of PSE. This shelf registration statement, which did not specify the amount of securities that PSE may offer, was amended on December 20, 2005. PursuantJanuary 26, 2010 and will remain valid until March 13, 2012. Under the shelf registration, as amended, PSE may offer senior notes secured by first mortgage bonds in an aggregate amount of up to $800.0 million. The Company also remains subject to the Receivables Sales Agreement,restrictions of PSE’s indentures on the amount of first mortgage bonds that PSE sells allmay issue.
On January 23, 2009, PSE completed a $250.0 million issuance of its utility customer accounts receivablesenior secured notes. The notes have a term of seven years and unbilled utility revenuesan interest rate of 6.75%. Net proceeds from the issue were used 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 will be reported asrepay short-term debt incurred to fund in part the financial statements.utility’s capital expenditures.
On September 11, 2009, PSE completed a $350.0 million issuance of senior secured notes. The PSE Funding facility expires in December 2010,notes have a term of 30 years and is terminable by PSE and PSE Funding upon notice to the banks. During 2006, PSE Funding borrowed a cumulative amountan interest rate of $441.0 million secured by accounts receivable. There was $110.0 million in loans that were secured by accounts receivable pledged at December 31, 2006. The borrowing available under the receivables securitization at December 31, 2006 was $90.0 million.
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’s 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 stock5.757%. Net proceeds from the Stock Purchaseissue were used to repay short-term debt which had been incurred primarily for earlier retirement of maturing long-term debt and Dividend Reinvestment Plan of $13.5 million (615,648 shares)to fund in 2006 compared to $14.5 million (656,267 shares) in 2005. The proceeds from sales of stock under these plans are used for general corporate needs.part the utility’s capital expenditures.
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 (NYSE) at market prices.
Other
Other
IRS Audit. As a matter of course, the Company’s tax returns are routinely audited by federal, state and city tax authorities. In May of 2006, the IRS completed its examination of the company’s 2001, 2002 and 2003 federal income tax returns. The Company is formally appealing two IRS audit adjustments. The first adjustment relates to the receivable balance due from the California Independent System Operator (CAISO). The IRS claims that the deduction was not valid for the 2003 tax year and would require repayment of approximately $14.5 million in tax. The Company believes the deduction is valid and intends to vigorously defend the deduction. Any potential tax payment (excluding interest) would have no impact on earnings, as it would be recognized as a deferred tax asset. If the Company is unsuccessful, a charge for interest expense would apply.
The second IRS audit adjustment relates to the company’s accounting method with respect to capitalized internal labor and overheads. 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 audit, the IRS disallowed the deduction. On August 2, 2005, the Internal Revenue Service and the Treasury Department issued Revenue Ruling 2005-53 and related Regulations. The Revenue Ruling and the Regulations required utility companies, including PSE, to adopt a less advantageous method of accounting and to repay the accumulated tax benefits. Through September 30, 2005, the Company claimed $66.3 million in accumulated tax benefits. PSE accounted for the accumulated tax benefits as temporary differences in determining its deferred income tax balances. Consequently, the repayment of the tax benefits did not impact earnings but did have a cash flow impact of $33.2 million in the fourth quarter 2005 and $33.1 million in 2006. As of December 31, 2006, the full tax benefit had been repaid. There is some uncertainty in the new guidance. PSE believes that the new Regulations required the Company to repay the accumulated tax benefits over the 2005 and 2006 tax years and that the tax deductions claimed on the Company’s tax returns were appropriate based on the applicable statutes, Regulations and case law in effect at the time. However, there is no assurance that PSE’s appeal will prevail. If the Company is unsuccessful, a charge for interest expense would apply.
On October 19, 2005, PSE filed an accounting petition with the Washington Commission to defer the capital costs associated with repayment of the deferred tax. The Washington Commission had reduced PSE’s ratebase by $72.0 million in its order of February 18, 2005. The accounting petition was approved by the Washington Commission on October 26, 2005, for deferral of additional capital costs beginning November 1, 2005 using PSE’s allowed net of tax rate of return. The Washington Commission granted cost recovery of these deferred carrying costs over two years, beginning January 13, 2007.
Tenaska Disallowance.The Washington Commission issued an order on May 13, 2004 determining that PSE did not prudently manage natural gas costs for the Tenaska electric generating plant and ordered PSE to adjust its PCA deferral account to reflect a disallowance of accumulated costs under the PCA mechanism for these excess costs. The increase in purchased electricity expense resulting from the disallowance totaled $9.0$1.0 million, $4.1$6.4 million and $43.4$7.8 million in 2006, 20052009, 2008 and 2004,2007, respectively. The order also established guidelines and a benchmark to determine PSE’s recovery on the Tenaska regulatory asset starting with the PCA 3 period (July 1, 2004) through the expiration of the Tenaska contract in the yearDecember 2011. The benchmark is defined as the original cost of the Tenaska contract adjusted to reflect the 1.2% disallowance from a 1994 Prudence Order.
In August 2004 PSE filed the PCA 2 period compliance and received an order from the Washington Commission on February 23, 2005. In the PCA 2 compliance order, the Washington Commission approved the Washington Commission staff’s recommendation for an additional return related to the Tenaska regulatory asset in the amount of $6.0 million related to the period July 1, 2003 through December 31, 2003.
The Washington Commission confirmed that if the Tenaska natural gas costs are deemed prudent, PSE will recover the full amount of actual natural gas costs and the recovery of the Tenaska regulatory asset even if the benchmark is exceeded. Due to fluctuations in forward market prices of natural gas, the amount and timing of any potential disallowance related to Tenaska can change significantly day to day.change. The projected costs and projected benchmark costs for Tenaska as of December 31, 20062009 based on current forward market natural gas prices are as follows:
(Dollars in Millions) | | 2007 | | 2008 | | 2009 | | 2010 | | 2011 | | | 2010 | | | 2011 | |
| Projected Tenaska costs * | | $ | 208.6 | | $ | 225.8 | | $ | 218.8 | | $ | 211.5 | | $ | 201.7 | | | $ | 206.5 | | | $ | 203.2 | |
| Projected Tenaska benchmark costs | | | 174.8 | | | 182.9 | | | 189.9 | | | 197.4 | | | 205.6 | | | | 197.4 | | | | 205.6 | |
| Over (under) benchmark costs | | $ | 33.8 | | $ | 42.9 | | $ | 28.9 | | $ | 14.1 | | $ | (3.9 | ) | | $ | 9.1 | | | $ | (2.4 | ) |
| | | | | | | | | | | | | | | | | | | | | | | | | |
| Projected 50% disallowance based on Washington Commission methodology | | $ | 7.8 | | $ | 6.4 | | $ | 4.9 | | $ | 3.1 | | $ | -- | | | $ | 3.0 | | | $ | -- | |
* | Projection will change based on market conditions of natural gas and replacement power costs. |
California Regulatory Asset
PSE has held a receivable relating to unpaid bills for power sold into the markets maintained by the CAISO. At December 31, 2009, the net receivable for such sales was $21.2 million, which was reclassified to a regulatory asset. The collectability is subject to the outcome of the Washington Commission ruling on the accounting petition. On October 7, 2009, PSE filed an amended accounting petition requesting that the Washington Commission authorize PSE to defer the net revenues from the sale of renewable energy credits (RECs) and carbon financial instruments (collectively, REC Proceeds) and use the revenues to: (1) provide funding for low income energy efficiency and renewable energy services, (2) credit a portion of the REC Proceeds to the California Receivable (see Litigation footnote for further discussion) and (3) provide a credit to customers by offsetting the REC Proceeds against a regulatory asset. The accounting petition is an amended petition to the accounting petition originally filed in April 2007 that requested deferred accounting treatment for renewable energy credits. The petition is scheduled for hearing in March 2010 and a Washington Commission order is anticipated in the first half of 2010.
Proceedings Relating to the Western Power Market
The following discussion summarizes the status as of the date of this report of ongoing proceedings relating to the western power markets to which PSE is a party. PSE is vigorously defending each of these cases.the remaining claims. 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 adversely affect PSE’s financial condition, results of operations or liquidity.
PSE Settlement of California ReceivableMatters. On May 8, 2009, PSE and California Refund Proceeding. Since 2001, PSE has held a receivable relating to unpaid bills for power that PSE sold in 2000 into the markets maintained by the CAISO. At December 31, 2006, the net receivable for such sales was approximately $21.2 million. PSE’s ability to recover all or a portion of this amount is uncertain. At this time there is no reasonable basis under applicable financial accounting rules to adjust PSE’s net receivable because the outcome of further court and FERC actions is uncertain and any likely financial impact cannot be quantified.
In 2001, FERC ordered an evidentiary hearing (Docket No. EL00-95) to determine the amount of refunds due to California energy buyers for purchases made in the spot markets operated by the CAISO and the California PX during the period October 2, 2000 through June 20, 2001 (refund period). FERC also ordered that if the refunds required by the formula it adopted would cause a seller to recover less than its actual costs for the refund period, the seller is allowed to document its costs and limit its refund liability commensurately. Consistent with those orders, PSE filed a fuel cost adjustment claim and a portfolio cost claim. Recovery of those amounts is uncertain, but the amount owed to PSE under all FERC orders to date is included in the PSE net receivable amount. FERC has not issued a final order determining “who owes how much to whom” in the California Refund Proceeding, and it is not clear when such an order will be issued.
In the course of the California Refund Proceeding, FERC has issued dozens of orders. Most have been taken up on appeal before the United States Court of Appeals for the Ninth Circuit (Ninth Circuit), which has issued opinions on some issues in the last several years. These cases are described below in the section, “California Litigation.”
California Litigation. Lockyer v. FERC. On September 9, 2004, the Ninth Circuit issued a decision on the California Attorney General’s challenge to the validity of FERC’s market-based rate system. This case was originally presented to FERC upon complaint that the adoption and implementation of market rate authority was flawed. FERC dismissed the complaint after all sellers refiled summaries of transactions with California entities during 2000 and 2001. The Ninth Circuit upheld FERC’s authority to authorize sales of electric energy at market-based rates, but found the requirement that all sales at market-based rates be contained in quarterly reports filed with FERC to be integral to a market-based rate tariff. Thecertain California parties among others, have interpreted the decision as providing authority to FERC to order refunds for different time frames and based on different rationales than are currently pending in the California Refund Proceedings, discussed above in “California Refund Proceeding.” The decision itself remands to FERC the question of whether to allow refunds. On December 28, 2006, PSE and several other energy sellers filed a petition for a writ of certiorari to the U.S. Supreme Court. The U.S. Supreme Court has not yet acted on that petition. PSE cannot predict the scope, nature or ultimate resolution of this case. That additional uncertainty may make the outcomes of certain other western energy market cases less predictable than previously anticipated.
CPUC v. FERC. On August 2, 2006, the Ninth Circuit decided that FERC erred in excluding potential relief for tariff violations for periods that pre-dated October 2, 2000 and additionally ruled that FERC should consider remedies for transactions previously considered outside the scope of the proceedings. The August 2, 2006 decision may adversely impact PSE’s ability to recover the full amount of its CAISO receivable. The decision may also expose PSE to claims or liabilities for transactions outside the previously defined “refund period.” At this time the ultimate financial outcome for PSE is unclear. The deadline for seeking rehearing of the August 2, 2006 decision is April 29, 2007, and it is likely that some parties will seek rehearing. In addition, parties have been engaged in court-sponsored settlement discussions, and those discussions may result in some settlements. PSE is studying the court’s decision, but is unable to predict either the outcome of the proceedings or the ultimate financial effect on PSE.
California Class Actions. In 2002, Reliant Energy Services (Reliant) and Duke Energy Trading & Marketing (Duke) cross-complained against PSE in several class actions filed in California arising from the California energy crisis. Duke and Reliant settled the underlying cases and subsequently dismissed the cross-complaints against the cross-defendants, including PSE.
Orders to Show Cause. On June 25, 2003, FERC issued two show cause orders pertaining to its western market investigations that commenced individual proceedings against many sellers. One show cause order investigated 26 entities that allegedly had potential “partnerships” with Enron. PSE was not named in that show cause order. On January 22, 2004, FERC stated that it did not intend to proceed further against other parties.
The second show cause order named PSE (Docket No. EL03-169) and approximately 54 other entities that alleg-edly had engaged in potential “gaming” practices in the CAISO and California PX markets. PSE and FERC staff filed a proposed settlement with the Federal Energy Regulatory Commission (FERC), seeking FERC’s approval to resolve all the matters and disputes pending between PSE and California parties relating to the western energy crisis. On July 1, 2009, FERC approved that settlement.
Under the settlement, PSE releases all claims to amounts held in, or presumed payable into, certain escrow accounts. In particular, the California Power Exchange and Pacific Gas & Electric delivered $59.9 million, plus up to $36.8 million in interest, from escrows they maintain to the California parties. The release of those funds fully satisfies all issues pendingclaims by the California parties against PSE, and the California parties assume the risk of any shortfalls or adjustments that occur in those accounts.
The settlement resolves all claims by the California parties against PSE in thoseall proceedings and resolves all claims by PSE against California energy purchasers in all proceedings, except that PSE retains any claims or defenses that pertain to the Pacific Northwest Refund Proceedings at FERC.
In addition to the FERC approval obtained on August 28, 2003. The proposedJuly 1, 2009, PSE’s settlement which admits no wrongdoing onwith the partCalifornia parties was expressly conditioned upon two other actions: (1) the California Energy Commission’s approval as qualifying facilities under California renewable energy rules of PSE, would result in a paymentPSE’s Wild Horse and Hopkins Ridge wind farms; and (2) the approval by the California Public Utility Commission of a nominal amountrenewable power agreement between PSE and Southern California Edison (SCE), under which PSE will sell qualifying renewable power to settleSCE in 2009 and 2010. PSE entered into the SCE contract in January 2009, and all claims. FERC approvedrequired approvals for that contract were obtained by June 18, 2009.
Use of the proceeds from the renewable power transaction, for ratemaking and accounting purposes, will be determined by the Washington Commission. PSE anticipates recovery of the net California receivable through this proceeding.
The settlement on January 22, 2004. The California parties filed for rehearing ofmeans that order. On March 17, 2004, PSE movedPSE’s exposure to dismisswestern energy crisis claims is now limited to the California parties’ rehearing requestPacific Northwest Refund Proceeding, described previously and awaits FERC action on that motion.
updated below.
Pacific Northwest Refund Proceeding.In October 2000, PSE filed a complaint at FERC (Docket No. EL01-10) against “all jurisdictional sellers” in the Pacific Northwest seeking prospective price caps consistent with any result FERC ordered for the California markets. In April 2009, the Ninth Circuit rejected the requests for rehearing filed in this matter and remanded the proceeding to FERC. FERC dismissedis now considering what response to take to the Court remand order, as petitions for review by the Supreme Court were denied on January 11, 2010. PSE intends to vigorously defend its position but is unable to predict the outcome of this matter.
Colstrip Matters
In May 2003, approximately 50 plaintiffs initiated an action against the owners of Colstrip alleging that: (1) seepage from two different wastewater pond areas caused groundwater contamination and threatened to contaminate domestic water wells and the Colstrip water supply pond; and (2) seepage from the Colstrip water supply pond caused structural damage to buildings and toxic mold. The defendants reached agreement on a global settlement with all plaintiffs on April 29, 2008 and PSE paid its share of the settlement in the amount of $10.7 million, net of insurance proceeds, in July 2008. PSE had previously expensed the settlement in the first quarter 2008. PSE has also filed an accounting petition with the Washington Commission to recover such costs over five years in its current electric rate proceeding. This matter is included in PSE’s pending general rate case and an order is expected in April 2010.
On March 29, 2007, a second complaint but PSE challengedrelated to pond seepage was filed on behalf of two ranch owners alleging damage due to the Colstrip Units 3 & 4 effluent holding pond. Discovery is ongoing and trial is scheduled to begin on May 16, 2011.
The federal Clean Air Mercury Rule, enacted by the Environmental Protection Agency (EPA) in May 2005, was vacated by the D.C. Circuit Court in February 2008. Final resolution of this matter is still pending. However the Montana Board of Environmental Review approved a Montana mercury control rule to limit mercury emissions from coal-fired plants on October 16, 2006 (with a limit of 0.9 lbs/Trillion British thermal units (TBtu) for plants burning coal like that dismissal. used at Colstrip) which remains in effect. In 2008, the Colstrip owners, based on testing performed in 2006, 2007 and 2008, ordered mercury control equipment intended to achieve the new limit. The equipment has been fully installed and is in regular operation. The Colstrip mercury control equipment is operating at a level that meets the current Montana limit, which is based on a rolling 12 month average so compliance cannot be fully confirmed until January 1, 2011. Optimization of the feed rates of calcium bromide and activated carbon is underway. Depending on actual long-term performance, an evaluation will be conducted to determine whether additional controls, if any, are necessary.
On June 19, 2001, FERC ordered price caps on energy sales throughout15, 2005, EPA issued the West. Various parties,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 larger units.
In February 2007, Colstrip was notified by EPA that Colstrip Units 1 & 2 were determined to be subject to EPA’s BART requirements. PSE submitted a BART engineering analysis for Colstrip Units 1 & 2 in August 2007 and responded to an EPA request for additional analyses with an addendum in June 2008. PSE cannot yet determine the outcome.
A lawsuit was filed in the United States District Court for the District of Montana in February 2009 against the Colstrip operator related to a fatality that occurred at the plant in June 2008. Discovery ends April 1, 2010 and trial is scheduled for July 12, 2010. PSE’s level of exposure in this matter is currently unknown.
Proceedings Related to Bonneville Power Administration
Petitioners in several actions in the Ninth Circuit against BPA asserted that BPA acted contrary to law in entering into or performing or implementing a number of agreements, including the Port of Seattleamended settlement agreement (and the May 2004 agreement) between BPA and PSE regarding the cities of Seattle and Tacoma, then moved to interveneREP. Petitioners in several actions in the proceeding seeking retroactive refunds for numerous transactions. The proceeding became known as the “Pacific Northwest Refund Proceeding,” though refund claims were outside the scope of the original complaint. On June 25, 2003, FERC terminated the proceeding on procedural, jurisdictional and equitable grounds and on November 10, 2003, FERC on rehearing, confirmed the order terminating the proceeding. Petitions for review, including PSE’s, are now pending before the Ninth Circuit. The Ninth Circuit held argument onagainst BPA also asserted that BPA acted contrary to law in adopting or implementing the petitions on January 8, 2007,rates upon which the benefits received or to be received from BPA during the October 1, 2001 through September 30, 2006 period were based. A number of parties 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 the matter now awaits that court's decision.BPA acted contrary to law or without authority in deciding to enter into, or in entering into or performing or implementing such agreements.
Port of Seattle Suit.On May 21, 2003, the Port of Seattle commenced suit in federal court in Seattle against 22 energy sellers, including PSE, alleging that their conduct during 2000 and 2001 constituted market manipulation, violated antitrust laws and damaged the Port of Seattle. On May 12, 2004, the district court dismissed the lawsuit. The Port of Seattle filed an appeal to the Ninth Circuit. After briefing and oral argument on March 30, 2006,3, 2007, the Ninth Circuit issued an order dismissingopinion in Portland Gen. Elec. v. BPA, Case No. 01-70003, in which proceeding the case.actions of BPA in entering into settlement agreements regarding the REP with PSE and with other investor-owned utilities were challenged. In this opinion, the Ninth Circuit granted petitions for review and held the settlement agreements entered into between BPA and the investor-owned utilities being challenged in that proceeding to be inconsistent with statute. On May 3, 2007, the Ninth Circuit also issued an opinion in Golden Northwest Aluminum v. BPA, Case No. 03-73426, in which proceeding the petitioners sought review of BPA’s 2002-2006 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 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.
In March 2008, BPA and PSE signed an agreement pursuant to which BPA made a payment to PSE related to the REP benefits for the fiscal year ended September 30, 2008, which payment is subject to true-up depending upon the amount of any REP benefits ultimately determined to be payable to PSE.
In September 2008, BPA issued its record of decision in its reopened WP-07 rate proceeding to respond to the various Ninth Circuit opinions. In this record of decision, BPA adjusted its fiscal year 2009 rates, determined the amounts of REP benefits it considered to have been improperly paid after fiscal year 2001 to PSE and the other regional investor-owned utilities, and determined that such amounts are to be recovered through reductions in REP benefit payments to be made over a number of years. The amount determined by BPA to be recovered through reductions commencing October 2007 in REP payments for PSE’s residential and small farm customers was approximately $207.2 million plus interest on unrecovered amounts to the extent that PSE receives any REP benefits for its customers in the future. However, these BPA determinations are subject to subsequent administrative and judicial review, which may alter or reverse such determinations. PSE and others, including a number of preference agency and investor-owned utility customers of BPA, in December 2008 filed petitions for review in the Ninth Circuit of various of these BPA determinations.
In September 2008, BPA and PSE signed a short-term Residential Purchase and Sale Agreement (RPSA) under which BPA is to pay REP benefits to PSE for fiscal years ending September 30, 2009–2011. In December 2008, BPA and PSE signed another, long-term RPSA under which BPA is to pay REP benefits to PSE for the period October 2011 through September 2028. PSE and other customers of BPA in December 2008 filed petitions for review in the Ninth Circuit of the short-term and long-term RPSAs signed by PSE (and similar RPSAs signed by other investor-owned utility customers of BPA) and BPA’s record of decision regarding such RPSAs. Generally, REP benefit payments under a RPSA are based on the amount, if any, by which a utility's average system cost (ASC) exceeds BPA’s Priority Firm (PF) Exchange rate for such utility. The ASC for a utility is determined using an ASC methodology adopted by BPA. The ASC methodology adopted by BPA and the ASC determinations, REP overpayment determinations, and the PF Exchange rate determinations by BPA are all subject to FERC review or judicial review or both and are subject to adjustment, which may affect the amount of REP benefits paid or to be paid by BPA to PSE. As discussed above, BPA has determined to reduce such payments based on its determination of REP benefit overpayments after fiscal year 2001.
It is not clear what impact, if any, such development or review of such BPA rates, ASC, ASC methodology, and BPA determination of REP overpayments, review of such agreements, and the above described Ninth Circuit litigation may ultimately have on PSE.
Potential for Flooding in the Green River Valley
Wah Chang Suit. The Howard Hanson Dam (Dam), located on the upper reach of the Green-Duwamish River, provides flood risk reduction for the benefit of the Green River Valley of south King County. Formerly an agricultural area, the Green River Valley now is home to substantial residential, commercial and industrial development in such communities as Auburn, Kent, Renton, South Seattle and Tukwila, all of which are within PSE’s gas and electric service territories. In June 2004, Wah Chang,addition to many gas and electric customers, the area is home to critical PSE infrastructure, including transmission substations, distribution systems, and key operational facilities housing. In January 2009, heavy rains damaged a section of the Dam and resulted in the Army Corps of Engineers (Corps) deciding in July 2009 to reduce the Dam’s flood storage capacity, pending the completion of improvements. Due to this reduced capacity, there is an Oregon company, filed suit in federal court against Puget Energyincreased risk to downstream communities for higher flood levels during this and PSE, among others. The complaint is similarfuture storm seasons, according to the allegations made byCorps. PSE is working closely with the PortCorps, King County, the many affected jurisdictions, and other agencies in preparing for the possibility of Seattle described above. The case was dismissed onflooding, potentially multiple times, that could disrupt service to tens of thousands of electric and gas customers and damage substantial PSE infrastructure. Should a flood or floods in the grounds that FERC has the exclusive jurisdiction over plaintiff’s claims. On March 10, 2005, Wah Chang filed a notice of appealGreen River Valley occur, PSE could incur both significant costs responding to the Ninth Circuit. Oral argumentevent and repairing any damage it creates, as well as the loss of revenue from affected customers.
On January 28, 2010, the Washington Commission approved PSE’s request for authorization to defer the costs associated with restoring the Company’s infrastructure, facilitating public safety, and repairing the Company’s electric and natural gas system in the Green River Valley flood plain in the event evacuation is scheduledrequired or flooding occurs due to take placeoperations associated with the Dam. This authorization is conditioned on April 10, 2007.PSE incurring incremental operation and maintenance costs in excess of $5.0 million per year associated with repair or restoration of the Company’s systems around the Green River. The Washington Commission’s Order will be effective until the date the Corps confirms that the Dam has been permanently repaired and that Corps’ operations will return to normal.
Critical Accounting Policies And Estimates
The preparation of financial statements in conformity with generally accepted accounting principles (GAAP) requires that management apply accounting policies and make estimates and assumptions that affect results of operations and the reported amounts of assets and liabilities in the financial statements. The following accounting policies represent those that management believes are particularly important to the financial statements and that require the use of estimates, assumptions and judgment to describe matters that are inherently uncertain.
Revenue Recognition.Utility revenues are recognized when the basis of service is rendered, which includes estimates to determine amounts relating to services rendered but not billed. Unbilled electricity revenue is determined by taking MWh generated and purchased less estimated system losses and billed MWh plus unbilled MWh balance at the last true-up date. The estimated system loss percentage for electricity is determined by reviewing historical billed MWh to generated and purchased MWh. The estimated unbilled MWh balance is then multiplied by the estimated average revenue per MWh. Unbilled gas revenue is determined by taking therms delivered to PSE less estimated system losses, prior month unbilled therms and billed therms. The estimated system loss percentage for natural gas is determined by reviewing historical billed therms to therms delivered to customers, which vary little from year to year. The estimated current month unbilled therms is then multiplied by estimated average rate schedule revenue per therm. Non-utility revenue is recognized when services are performed or upon the sale of assets. The recognition of revenue is in conformity with generally accepted accounting principles, which require the use of estimates and assumptions that affect the reported amounts of revenue.
Regulatory Accounting. As a regulated entity of the Washington Commission and FERC, PSE prepares its financial statements in accordance with the provisions of SFAS No. 71, “Accounting for the Effects of Certain Types of Regulation.”ASC 980, “Regulated Operations” (ASC 980). The application of SFAS No. 71ASC 980 results in differences in the timing and recognition of certain revenues and expenses in comparison with businesses in other industries. The rates that are charged by PSE to its customers are based on cost base regulation reviewed and approved by the Washington Commission and FERC. Under the authority of these commissions, PSE has recorded certain regulatory assets and liabilities at December 31, 20062009 in the amount of $838.5$867.8 million and $191.6$300.2 million, respectively, and regulatory assets and liabilities of $674.3 million$1.01 billion and $241.9$228.1 million, respectively, at December 31, 2005.2008. In conjunction with the merger, Puget Energy recognized additional regulatory assets of $297.1 million and liabilities of $1.05 billion, which are amortized through a corresponding liability or asset account, respectively, with no impact to earnings with the exception of NPNS fair value amounts, which will amortize through the statements of income. PSE expects to fully recover theseits regulatory assets and liabilities through its rates. If future recovery of costs ceases to be probable, PSE would be required to write off these regulatory assets and liabilities. In addition, if at some point in the future PSE determines that it no longer meets the criteria for continued application of SFAS No. 71, PSEASC 980, Puget Energy could be required to write off its regulatory assets and liabilities.liabilities associated with acquisition adjustment.
Also encompassed by regulatory accounting and subject to SFAS No. 71ASC 980 are the PCA and PGA mechanisms. The PCA and PGA mechanisms mitigate the impact of commodity price volatility upon the Company and are approved by the Washington Commission. The PCA mechanism provides for a sharing of costs that vary from baseline rates over a graduated scale. See Item 1 -– Business -– Regulation and Rates -– Electric Regulation and Rates for further discussion regarding the PCA mechanism. The PGA mechanism passes through to customers increases and decreases in the cost of natural gas supply. PSE expects to fully recover these regulatory assets through its rates. However, both mechanisms are subject to regulatory review and approval by the Washington Commission on a periodic basis.
Derivatives. Goodwill. On February 6, 2009, Puget Holdings completed its merger with Puget Energy. Puget Energy usesremeasured the carrying amount of all its assets and liabilities to fair value, which resulted in recognition of approximately $1.7 billion in goodwill. ASC 350, “Intangibles- Goodwill and Other,” (ASC 350) requires that goodwill be tested for impairment at the reporting unit level on an annual basis and between annual tests if an event occurs or circumstances change that would more likely than not reduce the fair value of a reporting unit below its carrying value. These events or circumstances could include a significant change in the business climate, legal factors, operating performance indicators, competition or sale or disposition of a significant portion of a reporting unit. Application of the goodwill impairment test requires judgment, including the identification of reporting unit, assignment of assets and liabilities to reporting unit, assignment of goodwill to reporting unit, and determination of the fair value of the reporting unit.
The goodwill represents the potential long-term return of Puget Energy to their investors. Goodwill is tested for impairment annually using a two-step process. The first step compares the carrying amount of the reporting unit with its fair value, with a carrying value higher than fair value indicating potential impairment. If the first step test fails, the second step is performed. This entails a full valuation of Puget Energy’s assets and liabilities and comparing the valuation to the carrying amount, with the difference indicating the amount of impairment. Goodwill of a reporting unit will be tested for impairment on an interim basis if an event occurs or circumstances change that would cause the fair value of a reporting unit to fall below its carrying amount.
Puget Energy conducted its annual impairment tests as of October 1, 2009. The fair value of Puget Energy’s reporting unit is estimated using both discounted cash flow and market approach. Such approaches are considered methodology that market participants would use. This analysis requires significant judgments, including estimation of future cash flows, which is dependent on internal forecasts, estimation of the long-term rate of growth for Puget Energy business, estimation of the useful life over which cash flows will occur and determination of our weighted average cost of capital. The market approach estimates the fair value of the business based on market prices of stocks of companies engaged in the same or similar lines of business. In addition, indications of market value are estimated by deriving multiples of equity or invested capital to various measures of revenue, earnings or cash flow. Changes in these estimates and or assumptions could materially affect the determination of fair value and goodwill impairment of the reporting unit. Based on the test performed, Management has determined that there is no impairment as of October 1, 2009. There were no events or circumstances from the date of the assessment through December 31, 2009 that would impact this conclusion.
Derivatives. The Company enters into derivative financial instruments primarilycontracts to manage its energy commodity price risksresource portfolio and interest rate exposure including forward physical and financial contracts and swaps unless the contracts qualify for an exception. ASC 815 requires that all contracts considered to be derivative instruments be recorded on the balance sheet at their fair value. The majority of PSE’s physical contracts qualify for the NPNS exception to derivative accounting rules. Generally, NPNS applies to contracts with creditworthy counterparties, for which physical delivery is probable and in quantities that will be used in the normal course of business. Power purchases designated as NPNS must meet additional criteria to determine if the transaction is within PSE’s forecasted load requirements and if the counterparty owns or controls energy resources within the western region to allow for physical delivery of the energy. PSE may enter into certainthe financial derivatives to manage interest rate risk. Derivative financial instruments are accounted for under SFAS No. 133, “Accounting for Derivative Instruments and Hedging Activities,” as amended by SFAS No. 138 and SFAS No. 149. Accounting for derivatives continues to evolve through guidance issued by the Derivatives Implementation Group (DIG) of the Financial Accounting Standards Board (FASB). To the extent that changes by the DIG modify current guidance, including the normal purchases and normal sales determination, the accounting treatment for derivatives may change.
To manage its electric and gas portfolios, Puget Energy enters intofixed contracts to purchase or sell electricity and gas. Thesehedge the variability of certain NPNS contracts. Those contracts that do not meet the NPNS exception are considered derivatives under SFAS No. 133 unless a determination is made that they qualify for the normal purchases and normal sales exception. If the exception applies, those contracts are not marked-to-market and are not reflectedto current earnings in the financial statements until delivery occurs.
The availability of income, subject to deferral under ASC 980, for energy related derivatives due to the normal purchasePCA mechanism and normal sale exception to specific contracts is based on a determination that a resource is available for a forward sale and similarly a determination that at certain times existing resources will be insufficient to serve load. This determination is based on internal models that forecast customer demand and generation supply. The models include assumptions regarding customer load growth rates, which are influenced by the economy, weather and the impact of customer choice and resource availability. The critical assumptions used in the determination of the normal purchases and normal sales exception are consistent with assumptions used in the energy portfolio management process.PGA mechanism.
Energy and financial contracts that are considered derivatives may be eligible for designation as cash flow hedges. If a contract is designated as a cash flow hedge, the change in its market value of the effective portion of the hedge is generally deferred as a component of other comprehensive income until the transaction it is hedging is completed. Conversely, the change in the market value of derivatives not designated as cash flow hedges is recorded in current period earnings.
On July 1, 2009, PSE elected to de-designate all energy related derivative contracts that previously had been recorded as cash flow hedges for the purpose of simplifying its financial reporting. The contracts that were de-designated related to physical electric supply contracts and natural gas swap contracts to fix the price of natural gas for electric generation. For these contracts, all future mark-to-market accounting will be recognized through earnings. The amount in accumulated OCI is transferred to earnings in the same period or periods during which the hedged transaction affected earnings or sooner if management determines that the forecasted transaction is probable of not occurring. As a result, the Company will likely continue to experience earnings volatility in future periods.
PSE values derivative instruments based on daily quoted prices from numerousan independent energy brokerage services.external pricing service. The Company regularly confirms the validity of pricing service quoted prices (e.g. Level 2 in the fair value hierarchy) used to value commodity contracts to the actual prices of commodity contracts entered into during the most recent quarter. When external quoted market prices are not available for derivative contracts, PSE uses a valuation model that uses volatility assumptions relating to future energy prices based on specific energy markets and utilizes externally available forward market price curves. All derivative instruments are sensitive to market price fluctuations that can occur on a daily basis. The Company is focused on commodity price exposure and risks associated with volumetric variability in the natural gas and electric portfolios. It is not engaged in the business of assuming risk for the purpose of speculative trading. The Company economically hedges open natural gas and electric positions to reduce both the portfolio risk and the volatility risk in prices. The exposure position is determined by using a probabilistic risk system that models 250 simulations of how the Company’s natural gas and power portfolios will perform under various weather, hydro and unit performance conditions.
The Company may enter into swap instruments on other financial derivative instruments to manage the interest rate risk associated with its long-term debt financing and debt instruments. As of December 31, 2009, Puget Energy has interest rate swap contracts outstanding related to its long-term debt. See Note 9 of the notes to the consolidated financial statements.
Fair Value. As defined in ASC 820, “Fair Value Measurements” (ASC 820), fair value is the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date (exit price). However, as permitted under ASC 820, the Company utilizes a mid-market pricing convention (the mid-point price between bid and ask prices) as a practical expedient for valuing the majority of its assets and liabilities measured and reported at fair value. The Company utilizes market data or assumptions that market participants would use in pricing the asset or liability, including assumptions about risk and the risks inherent in the inputs to the valuation technique. These inputs can be readily observable, market corroborated or generally unobservable. The Company primarily applies the market approach for recurring fair value measurements and endeavors to utilize the best available information. Accordingly, the Company utilizes valuation techniques that maximize the use of observable inputs and minimize the use of unobservable inputs.
On February 6, 2009, Puget Holdings completed its merger with Puget Energy. Puget Energy remeasured the carrying amount of all its assets and liabilities to fair value, which resulted in a recognition of approximately $1.7 billion in goodwill. See Note 3 of the notes to the consolidated financial statements for the discussion of purchase accounting adjustments.
Pension and Other Postretirement Benefits. Puget EnergyPSE has a qualified defined benefit pension plan covering substantially all employees of PSE. Qualified pension expense of $1.0$3.3 million, was recorded in 2006 and income of $2.6$0.4 million and $8.0expense of $2.8 million waswere recorded infor the financial statements for 2005years ended December 31, 2009, 2008 and 2004,2007, respectively. Of these amounts, approximately 56.6%61.2%, 63.0%60.0% and 63.3% offset58.6% were included in utility operations and maintenance expense in 2006, 20052009, 2008 and 2004,2007, respectively, and the remaining amounts were capitalized. QualifiedDue to the merger, the pension plan was remeasured in accordance with ASC 805. See Note 3 of the notes to the consolidated financial statements. For the year ending December 31, 2009, Puget Energy recognized incremental qualified pension expense of $7.5 million. In 2010, it is expected to be $1.7that PSE and Puget Energy will recognize pension expense of $7.9 million in 2007.and $3.6 million, respectively.
PSE’sPSE has a Supplemental Retirement Plan (SERP). For the years ended December 31, 2009, 2008 and 2007, PSE recognized $4.9 million, $4.5 million and $5.4 million of pension and other postretirement benefit expenses, respectively. Due to the merger, the SERP plan was remeasured in accordance with ASC 805. See Note 3 of the notes to the consolidated financial statements for further information on the business combination. For the year ended December 31, 2009, Puget Energy recognized incremental income of $1.8 million. In 2010, it is expected PSE and Puget Energy will recognize $4.5 million of pension expense and $1.3 million of pension income.
PSE has other limited postretirement benefit plans. For the years ended December 31, 2009, 2008 and 2007, PSE recognized expense of $0.3 million, income of $0.2 million and expense of $0.4 million, respectively. Due to the merger, the other postretirement benefit plans were remeasured in accordance with ASC 805. For the year ended December 31, 2009, Puget Energy recognized incremental expense of $0.3 million. See Note 3 of the notes to the consolidated financial statements for further information on the business combination. In 2010, it is expected that PSE and Puget Energy will recognize expense of $0.2 million and $0.3 million, respectively.
The Company’s pension and other postretirement benefits income or costs depend on several factors and assumptions, including plan design, timing and amount of cash contributions to the plan, earnings on plan assets, discount rate, expected long-term rate of return, mortality and health care cost trends. Changes in any of these factors or assumptions will affect the amount of income or expense that Puget Energythe Company records in its financial statements in future years and its projected benefit obligation. The Company has selected an expected return on plan assets based on a historical analysis of rates of return and the Company’s investment mix, market conditions, inflation and other factors. The Company’sPSE’s accounting policy for calculating the market-related value of assets is based on a five-year smoothing of asset gains/losses measured from the expected return on market-related assets. This is a calculated value that recognizes changes in fair value in a systematic and rational manner over five years. The same manner of calculating market-related value is used for all classes of assets, and is applied consistently from year to year. Puget Energy has selected an expected return on plan assets based on a historical analysis of rates of return and Puget Energy’s investment mix, market conditions, inflation and other factors. As required by merger accounting rules, market-related value was reset to market value effective with the merger. During 2006, PSE2009, the Company made noa cash contributionscontribution of $18.4 million to the qualified defined benefit plan. Management is closely monitoring the funding status of its qualified pension plan given the recent volatility of the financial markets. The aggregate expected contributions by the Company to fund the retirement plan, SERP and expects to make no contributions in 2007.other postretirement plans for the year ending December 31, 2010 are $12.0 million, $3.0 million and $1.5 million, respectively.
The following table reflectstables reflect the estimated sensitivity associated with a change in certain significant actuarial assumptions (each assumption change is presented mutually exclusive of other assumption changes):
| Puget Sound Energy | Change in Assumption | Impact on Projected Benefit Obligation (increase) decrease | |
(Dollars in Thousands) | | Pension Benefits | | SERP | | Other Benefits | |
| Increase in discount rate | 50 basis points | $ | (25,867 | ) | $ | (1,731 | ) | $ | (673 | ) |
| Decrease in discount rate | 50 basis points | | 28,436 | | | 1,868 | | | 728 | |
| | | Change in Assumption | | Impact on Projected Benefit Obligation Increase (Decrease) | | Impact on 2006 Pension Income Increase (Decrease) | | |
| Puget Sound Energy | | Change in Assumption | Impact on 2009 Pension Expense (increase) decrease | |
(Dollars in Thousands) | | | | Pension Benefits | | Other Benefits | | Pension Benefits | | Other Benefits | | | Pension Benefits | | SERP | | Other Benefits | |
| Increase in discount rate | | 50 basis points | | $ | (23,144 | ) | $ | (3,291 | ) | $ | 2,014 | | $ | 296 | | 50 basis points | $ | (2,540 | ) | $ | (146 | ) | $ | (55 | ) |
| Decrease in discount rate | | 50 basis points | | | 24,458 | | | 3,537 | | | (2,188 | ) | | 299 | | 50 basis points | | 2,777 | | | 154 | | | 56 | |
| Increase in return of plan assets | | 50 basis points | | | * | | | * | | | 2,277 | | | 73 | | |
| Increase in return on plan assets | | 50 basis points | | (2,749 | ) | | * | | | (39 | ) |
| Decrease in return on plan assets | | 50 basis points | | | * | | | * | | | (2,277 | ) | | (73 | ) | 50 basis points | | 2,749 | | | * | | | 39 | |
_________________________| * | Calculation not applicable. |
California Receivable. PSE operates within the western wholesale market and has made sales into the California energy market. At December 31, 2000, PSE’s receivables from the CAISO and other counterparties was $41.8 million. PSE received the majority of the partial payments for sales made in the fourth quarter 2000 in the first quarter 2001 and has since received a small amount of payments. At December 31, 2006, such remaining receivables were approximately $21.2 million.
Based on the calculation of existing FERC orders issued to date, PSE has determined that the receivable balance at December 31, 2006 is collectible from the CAISO. However, PSE’s ability to collect all or a portion of this amount may be impaired by future FERC orders or decisions by the Ninth Circuit.| Puget Energy | Change in Assumption | Impact on Projected Benefit Obligation (increase) decrease | |
(Dollars in Thousands) | | Pension Benefits | | SERP | | Other Benefits | |
| Increase in discount rate | 50 basis points | $ | (25,867 | ) | $ | (1,731 | ) | $ | (673 | ) |
| Decrease in discount rate | 50 basis points | | 28,436 | | | 1,868 | | | 728 | |
Stock Compensation. Effective January 1, 2006, the Company adopted the fair value recognition provisions of SFAS No. 123R, “Share-Based Payment,” using the modified-prospective transition method. Results for prior periods have not been restated, as provided for under the modified-prospective method. Prior to 2006, stock-based compensation plans were accounted for according to Accounting Principles Board (APB) No. 25, “Accounting for Stock Issued to Employees,” and related interpretations as allowed by SFAS No. 123, “Accounting for Stock-Based Compensation.” In 2003, the Company adopted the fair value based accounting of SFAS No. 123 using the prospective method under the guidance of SFAS No. 148, “Accounting for Stock-Based Compensation - Transition and Disclosure.” The Company applied SFAS No. 123 accounting to stock compensation awards granted subsequent to January 1, 2003, while grants prior to 2003 continued to be accounted for using the intrinsic value method of APB No. 25.
The adoption of SFAS 123R resulted in a cumulative benefit from an accounting change of $0.1 million, after tax, for the quarter ended March 31, 2006. The cumulative effect adjustment is the result of the inclusion of estimated forfeitures occurring before award vesting dates in the computation of compensation expense for unvested awards. As a result of adopting SFAS No. 123R on January 1, 2006, the Company’s income before income taxes and net income from continuing operations for the twelve months ended December 31, 2006 is $0.1 million and $0.1 million higher, respectively, than if it had continued to account for share-based compensation under SFAS No. 123 due to the inclusion of estimated forfeitures in compensation cost. There is no difference between basic and diluted earnings per share for income from continuing operations for the twelve months ended December 31, 2006, under SFAS No. 123R as compared to earlier methods.
The fair value of the stock-based grants is based on the closing price of the Company’s common stock on the date of measurement and historical performance of the certain share grants and prospective analysis using the Capital Asset Pricing Model and expected EPS growth rates. Based on this analysis, the Company’s total shareholder returns would need to significantly increase as compared to other companies to have a material impact on the Company’s financial statements. Shares granted prior to 2006 were valued using the Black-Scholes option pricing model.
| Puget Energy | Change in Assumption | Impact on 2009 Pension Expense (increase) decrease | |
(Dollars in Thousands) | | Pension Benefits | | SERP | | Other Benefits | |
| Increase in discount rate | 50 basis points | $ | (218 | ) | $ | 36 | | $ | (42 | ) |
| Decrease in discount rate | 50 basis points | | 1,830 | | | 95 | | | (22 | ) |
| Increase in return on plan assets | 50 basis points | | (2,052 | ) | | * | | | (39 | ) |
| Decrease in return on plan assets | 50 basis points | | 2,052 | | | * | | | 39 | |
New Accounting Pronouncements__________At its June 15, 2006 meeting, FASB’s EITF approved the issuance of EITF Issue No. 06-3, “How Taxes Collected from Customers and Remitted to Governmental Authorities Should Be Presented in the Income Statement (That Is, Gross versus Net Presentation).” The Company’s policy is to report state utility taxes and municipal taxes on a gross basis. The EITF concluded that these requirements should be applied to financial reports for interim and annual periods beginning after December 15, 2006, which will be the quarter ended March 31, 2007, for the Company. The adoption of EITF Issue No. 06-3 is not expected to have a material impact on the Company’s 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 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, the 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 50.0% likelihood of being sustained.
FIN 48 was effective for the Company as of January 1, 2007. The change in net assets as a result of adopting FIN 48 will be treated as a change in accounting method. The cumulative effect of the change will be recorded to retained earnings. Adjustments to regulatory accounts, if any, will be based on other applicable accounting standards. The Company is currently in the process of evaluating the provisions of FIN 48 to determine the potential impact, if any, the adoption will have on the Company’s financial statements. The adoption of FIN 48 is not expected to have a material impact on the Company’s retained earnings. Management’s estimated impact of adoption is subject to change due to potential changes in interpretation of FIN 48 by the FASB or other regulatory bodies and the finalization of the Company’s adoption efforts.
On September 15, 2006, FASB issued SFAS No. 157, “Fair Value Measurements.” SFAS No. 157 standardizes the measurement of fair value when it is required under GAAP. SFAS No. 157 is effective for fiscal years beginning after November 15, 2007, which will be the year beginning January 1, 2008, for the Company. The adoption of SFAS No. 157 is not expected to have a material impact on the Company’s financial statements.
| * | QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISKCalculation not applicable. |
Recently Adopted Accounting Pronouncements
For the discussion of recently adopted accounting pronouncements, see Note 2 of the notes to the consolidated financial statements (Item 8).
Energy Portfolio Management
The Company hasPSE maintains energy risk policies and procedures to manage commodity and volatility risks. The Company’s Energyrisks and the related effects on credit, tax, accounting, financing and liquidity. PSE’s Asset Management Committee establishes the Company’s energyPSE’s risk management policies and procedures and monitors compliance. The EnergyAsset Management Committee is comprised of certain CompanyPSE officers and is overseen by the Audit Committee of the Company’sPSE Board of Directors.
The CompanyPSE is focused on commodity price exposure and risks associated with volumetric variability in the gas and electric portfolios.portfolios and the related effects noted above. It is not engaged in the business of assuming risk for the purpose of speculative trading. The CompanyPSE hedges open gas and electric positions to reduce both the portfolio risk and the volatility risk in prices. The exposure position is determined by using a probabilistic risk system that models 100 scenarios250 simulations of how the Company’sPSE’s gas and power portfolios will perform under various weather, hydro and unit performance conditions. The objectiveobjectives of the hedging strategy is:are to:
| | · | ensureEnsure physical energy supplies are available to reliably and cost-effectively serve retail load; |
| | · | prudent management ofManage the energy portfolio risksprudently to serve retail load at overall least cost and limit undesired impacts on PSE’s customers and shareholders; and |
| | · | reduceReduce power costs by extracting the value of PSE’s assets; and |
| ·Meet the Company’s assets.credit, liquidity, financing, tax and accounting requirements of PSE. |
At December 31, 2006,ASC 815, “Derivatives and Hedging” (ASC 815) requires a significant amount of new disclosure regarding PSE’s derivative activities and the nature of such derivatives impact on PSE’s financial position, financial performance and cash flows. Such detail should serve as an accompaniment to Management’s Discussion and Analysis (MD&A), which is located under Item 8, Note 14 of the notes to the audited consolidated financial statements.
PSE pursues various portfolio optimization strategies but is not in the business of assuming risk for the purpose of realizing speculative trading revenues. PSE’s portfolio of owned and contracted electric generation resources exposes PSE and its retail electric customers to some volumetric and commodity price risks within the sharing mechanism of the Power Cost Adjustment (PCA). PSE’s natural gas retail customers are served by natural gas purchase contracts which expose PSE’s customers to commodity price risks through the Purchased Gas Adjustment (PGA) mechanism. All purchased natural gas costs are recovered through customer rates with no direct impact on PSE. Therefore, wholesale market transactions are focused on balancing PSE’s energy portfolio, reducing costs and risks where feasible and reducing volatility. PSE’s energy risk portfolio management function monitors and manages these risks. In order to manage risks effectively, PSE enters into forward physical electricity and gas purchase and sale agreements, and floating for fixed swap contracts that are related to its regulated electric and gas portfolios. The forward physical electricity contacts are both fixed and variable (at index) while the physical natural gas contracts are variable with investment grade counterparties that do not require collateral calls on the contracts. To fix the price of natural gas, PSE may enter into natural gas floating for fixed swap (financial) contracts with various counterparties.
On July 1, 2009, PSE elected to de-designate all energy related derivative contracts that previously had been recorded as cash flow hedges for the purpose of simplifying its financial reporting. The contracts that were de-designated related to physical electric supply contracts and natural gas swap contracts to fix the price of natural gas for electric generation. For these contracts, all future mark-to-market accounting will be recognized through earnings. The amount in accumulated OCI is transferred to earnings in the same period or periods during which the hedged transaction affected earnings or sooner if management determines that the forecasted transaction is probable of not occurring. As a result, the Company had a short-term asset of $0.9 million and a short-term liability of $0.9 million, primarily as a result of de-designating gas financial contracts. These contracts were relatedwill likely continue to electric generationexperience earnings volatility in future periods.
The following tables present the Company’s energy derivatives instruments that was no longer probable. During 2006, the Company recorded a decrease in earnings for the change in the market value of derivative instrumentsdo not meetingmeet the normal purchase normal sale (NPNS) exception orat December 31, 2009 and December 31, 2008, excluding derivatives designated as cash flow hedge criteria under SFAS No. 133 of $0.1 million compared to a decrease in earnings of $0.5 million for 2005 and an increase of $0.5 million for 2004.
Athedges (at December 31, 2006,2009 PSE had a short-term asset of $9.2 million and a long-term asset of $6.8 million as well as a short-term liability of $8.0 million and a long-term liability of $0.4 million related to energyno contracts designated as cash flow hedges that represent forward financial purchaseshedges):
| | | Energy Derivatives | |
Puget Sound Energy Derivative Portfolio (Dollars in Millions) | | December 31, 2009 | | | December 31, 2008 | |
| | | Assets | | | Liabilities | | | Assets | | Liabilities | |
| Electric portfolio | | | | | | | | | | | |
| Current | | $ | 4.1 | | | $ | 75.3 | | | $ | 0.4 | | $ | 90.6 | |
| Long-term | | | 1.0 | | | | 70.4 | | | | 0.5 | | | 96.1 | |
| Total electric derivatives | | | 5.1 | | | | 145.7 | | | | 0.9 | | | 186.7 | |
| Gas portfolio | | | | | | | | | | | | | | | |
| Current | | | 10.8 | | | | 62.2 | | | | 15.2 | | | 146.3 | |
| Long-term | | | 3.6 | | | | 19.3 | | | | 6.2 | | | 62.3 | |
| Total gas derivatives | | | 14.4 | | | | 81.5 | | | | 21.4 | | | 208.6 | |
| Total derivatives | | $ | 19.5 | | | $ | 227.2 | | | $ | 22.3 | | $ | 395.3 | |
| | | Energy Derivatives | |
Puget Energy Derivative Portfolio (Dollars in Millions) | | Successor December 31, 2009 | | Predecessor December 31, 2008 | |
| | | Assets | | | Liabilities | | Assets | | Liabilities | |
| Electric Portfolio | | | | | | | | | | |
| Current | | $ | 4.1 | | | $ | 79.7 | | $ | 0.4 | | $ | 90.6 | |
| Long-term | | | 1.0 | | | | 70.4 | | | 0.5 | | | 96.1 | |
| Total electric derivatives | | | 5.1 | | | | 150.1 | | | 0.9 | | | 186.7 | |
| Gas portfolio | | | | | | | | | | | | | | |
| Current | | | 10.8 | | | | 62.2 | | | 15.2 | | | 146.3 | |
| Long-term | | | 3.6 | | | | 19.3 | | | 6.2 | | | 62.3 | |
| Total gas derivatives | | | 14.4 | | | | 81.5 | | | 21.4 | | | 208.6 | |
| Total derivatives | | $ | 19.5 | | | $ | 231.6 | | $ | 22.3 | | $ | 395.3 | |
For further details regarding both the fair value of gas supply for electric generation from PSE-owned electric plants in future periods. These contracts were designated as qualifyingderivative instruments and the impacts such instruments have on current period earnings and OCI (for cash flow hedgeshedges), please see Notes 14 and a corresponding unrealized gain of $4.9 million, net of tax, was recorded in other comprehensive income. If it is determined that it is uneconomical to run the plants in the future period, the hedging relationship is ended and the cash flow hedge is de-designated and any unrealized gains and losses are recorded in the income statement. Gains and losses, when these de-designated cash flow hedges are settled, are recognized in energy costs and are included as part15 of the PCA mechanism. At December 31, 2005,notes to the Company had an unrealized gain recorded in other comprehensive income of $43.2 million (net of tax), before SFAS No.71 deferrals of $6.3 million, related to energy contracts which met the criteria for designation as cash flow hedges under SFAS No. 133. This was mainly the result of higher forward market prices for natural gas and electricity at December 31, 2005 compared to December 31, 2006.consolidated financial statements.
At December 31, 2006,2009, the Company had a short-term assettotal assets of $6.8$14.4 million and a short-term liabilitytotal liabilities of $61.6 million as well as a long-term asset of $0.1$81.6 million related to financial contracts used to economically hedge the hedgescost of physical natural gas contractspurchased to serve natural gas customers. All mark-to-marketfair value adjustments on derivatives relating to the natural gas business have been reclassified to a deferred account in accordance with SFAS No. 71ASC 980 due to the PGA mechanism. All increases and decreases in the cost of natural gas supply are passed on to customers with the PGA mechanism. As the gains and losses on the hedges are realized in future periods, they will be recorded as gas costs under the PGA mechanism. At December 31, 2005, the Company had a net asset of $25.7 million related to the hedge of gas contracts to serve natural gas customers.
A hypothetical 10.0% increase/decrease in the market prices of natural gas and electricity would decreasechange the fair value of qualifying cash flow hedgesPuget Energy and PSE derivative contracts by $5.0$118.9 million and $118.2 million, respectively, and would have no effect forimpact the fair value of those contracts marked-to-market in earnings.earnings by $25.1 million and $14.3 million, respectively, after-tax related to derivatives not designated as hedges.
The change in fair value of the Company’s outstanding energy derivative instruments from December 31, 2008 through December 31, 2009 is summarized in the table below:
| | | Puget Sound Energy | | | Puget Energy Successor | | | Predecessor 2 | |
| Energy Derivative Contracts Gain/(Loss) (Dollars in Millions ) | | December 31, 2009 | | | December 31, 2009 | | | December 31, 2008 | |
| Fair value of contracts outstanding at December 31, 2008 | | $ | (373.0 | ) | | $ | (373.0 | ) | | $ | 2.0 | |
| Contracts realized or otherwise settled during 2009 | | | 334.5 | | | | 148.0 | | | | 4.0 | |
ASC 820 transition adjustment 1 | | | -- | | | | -- | | | | (9.0 | ) |
| Change in fair value of derivatives | | | (169.2 | ) | | | 12.9 | | | | (370.0 | ) |
| Fair value of contracts outstanding at December 31, 2009 | | $ | (207.7 | ) | | $ | (212.1 | ) | | $ | (373.0 | ) |
| 1 | ASC 820,”Fair Value Measurement,” transition adjustment related to day one loss deferral of a three-year Locational Power Exchange contract. |
| 2 | Prior to the merger, energy derivative contracts were the same for Puget Sound Energy and Puget Energy. |
The fair value of the Company’s outstanding derivative instruments at December 31, 2009, based on price source and the period during which the instrument will mature, is summarized below:
| Puget Sound Energy | | Fair Value of Contracts By Settlement Year | |
Source of Fair Value (Dollars in Millions) | | 2010 | | | | 2011-2012 | | | | 2013-2014 | | | 2015 & Thereafter | | | Total Fair Value | |
Prices provided by external sources 1 | | $ | (95.6 | ) | | $ | (11.8 | ) | | $ | -- | | | $ | -- | | | $ | (107.4 | ) |
Prices based on internal models and valuation methods 2 | | | (27.0 | ) | | | (62.1 | ) | | | (9.3 | ) | | | (1.9 | ) | | | (100.3 | ) |
| Total fair value | | $ | (122.6 | ) | | $ | (73.9 | ) | | $ | (9.3 | ) | | $ | (1.9 | ) | | $ | (207.7 | ) |
| Puget Energy | | Fair Value of Contracts By Settlement Year | |
Source of Fair Value (Dollars in Millions) | | 2010 | | | | 2011-2012 | | | | 2013-2014 | | | 2015 & Thereafter | | | Total Fair Value | |
Prices provided by external sources 1 | | $ | (100.0 | ) | | $ | (11.8 | ) | | $ | -- | | | $ | -- | | | $ | (111.8 | ) |
Prices based on internal models and valuation methods 2 | | | (27.0 | ) | | | (62.1 | ) | | | (9.3 | ) | | | (1.9 | ) | | | (100.3 | ) |
| Total fair value | | $ | (127.0 | ) | | $ | (73.9 | ) | | $ | (9.3 | ) | | $ | (1.9 | ) | | $ | (212.1 | ) |
______________Energy Derivative Contracts
Gain(Loss) (Dollars in Millions)
1 | Amounts
| Prices provided by external pricing service, which utilizes broker quotes and pricing models. Pricing inputs are based on observable market data. |
Fair value of contracts outstanding at December 31, 20052 | | $ | 93.6 | |
Contracts realized or otherwise settled during 2006 | | | (34.1 | ) |
Changes in fair values of derivatives | | | (106.7 | ) |
Fair value of contracts outstanding at December 31, 2006 | | $ | (47.2 | )Pricing derived from inputs with internally developed methodologies. Pricing inputs are generally less observable than objective sources. |
| | Fair Value of Contracts with Settlement During Year |
Source of Fair Value (Dollars in Millions) | 2007 | 2008- 2009 | 2010- 2011 | 2012 and Thereafter | Total Fair Value |
| Prices actively quoted | $(53.7) | $6.5 | -- | -- | $(47.2) |
| Prices provided by other external sources | -- | -- | -- | -- | -- |
| Prices based on models and other valuation methods | $(53.7) | $6.5 | -- | -- | $(47.2) |
Contingent Features and Counterparty Credit Risk
The CompanyPSE is exposed to credit risk primarily through buying and selling electricity and natural gas to serve customers. Credit risk is the potential loss resulting from a counterparty’s non-performance under an agreement. The CompanyPSE manages credit risk with policies and procedures for, among other things, counterparty analysis exposureand measurement, exposure monitoring and exposure mitigation.mitigation of exposure.
Where deemed appropriate, PSE may request collateral or other security from its counterparties to mitigate the potential credit default losses. Criteria employed in this decision include, among other things, the perceived creditworthiness of the counterparty and the expected credit exposure. As of December 31, 2009, PSE held approximately $2.6 million worth of standby letters of credit in support of various electricity and renewable energy credit transactions.
It is possible that extreme volatility in energy commodity prices could cause the CompanyPSE to have material credit risk exposures with one or more counterparties. If such counterparties fail to perform their obligations under one or more agreements, the CompanyPSE could suffer a material financial loss. However, as of December 31, 2006,2009, approximately 99.0%95.7% of thePSE’s energy and gas portfolio exposure, including NPNS transactions, is with counterparties comprising the sources of our energy portfoliothat are rated at least investment grade by the major rating agencies and 1.0%4.3% of PSE’s portfolio are either rated below investment grade or are not rated by rating agencies. The CompanyPSE assesses credit risk internally for counterparties that are not rated.
PSE has entered into commodity master arrangements with its counterparties to mitigate credit exposure to those counterparties. PSE generally enters into the following master arrangements: (1) Western Systems Power Pool agreements (WSPP) - standardized power sales contracts in the electric industry; (2) International Swaps and Derivatives Association agreements (ISDA) - standardized financial gas and electric contracts; and (3) North American Energy Standards Board agreements (NAESB) - standardized physical gas contracts. PSE believes that entering into such agreements reduces the risk of default by allowing a counterparty the ability to make only one net payment.
PSE monitors counterparties that are experiencing financial problems, have significant swings in credit default swap rates, have credit rating changes by external rating agencies or have changes in ownership. Counterparty credit risk impacts PSE’s decisions on derivative accounting treatment. A counterparty may have a deterioration of credit below investment grade, potentially indicating that it is no longer probable that it will fulfill its obligations under a contract (e.g., make a physical delivery upon the contract’s maturity). ASC 815 specifies the requirements for derivative contracts to qualify for the NPNS scope exception. When performance is no longer probable, based on the deterioration of counterparty’s credit, PSE records the fair value of the contract on the balance sheet with the corresponding amount recorded in the statements of income.
The locked accumulated OCI of the cash flow hedge is impacted by a counterparty’s deterioration of credit under ASC 815 guidelines. If a forecasted transaction associated with the transaction is no longer probable of occurring, based on deterioration of credit, PSE will record in earnings the locked accumulated OCI.
Should a counterparty file for bankruptcy, which could be considered a default under master arrangements, PSE may terminate related contracts. Derivative accounting entries previously recorded would be reversed in the financial statements. PSE would compute any termination receivable or payables based on the terms of existing master arrangements.
PSE computes credit reserves at a master agreement level (i.e. WSPP, ISDA or NAESB) by counterparty. PSE considers external credit ratings and market factors, such as credit default swaps and bond spreads, in determination of reserves. PSE recognizes that external ratings may not always reflect how a market participant perceives a counterparty’s risk of default. PSE uses both default factors published by S&P and factors derived through analysis of market risk, which reflect the application of an industry standard recovery rate. PSE selects a default factor by counterparty at an aggregate master agreement level based on a weighted average default tenor for that counterparty’s deals. The default tenor is used by weighting fair values and contract tenors for all deals for each counterparty and coming up with an average value. The default factor used is dependent upon whether the counterparty is in a net asset or a net liability position after applying the master agreement levels.
PSE applies the counterparty’s default factor to compute credit reserves for counterparties that are in a net asset position. Moreover, PSE calculates a non-performance risk on its derivative liabilities by using its estimated incremental borrowing rate over the risk-free rate. The fair value of derivatives includes the impact of taking into account credit and non-performance reserves. As of December 31, 2009, PSE was in a net liability position with the majority of their counterparties; as a result, the default factors of counterparties did not have a significant impact on reserves for the year.
Interest Rate Risk
The Company believes its interest rate risk primarily relates to the use of short-term debt instruments variable-rate notes and leases and anticipated long-term debt financing needed to fund capital requirements. The Company manages its interest rate risk through the issuance of mostly fixed-rate debt of various maturities. The Company utilizes bank borrowings, commercial paper, and 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 CompanyAs of December 31, 2009, Puget Energy had seven interest rate swap contracts outstanding whereas PSE did not have any outstanding swap instruments outstanding on fixedinstruments.
In February 2009, Puget Energy entered into interest rate debt asswap transactions to hedge the risk associated with one-month LIBOR floating rate debt. As of December 31, 2006 or 2005, however2009, the fair value of the interest rate swaps designated as cash flow hedges was a $5.9 million loss. This fair value considers the risk of Puget Energy’s non-performance by using Puget Energy’s incremental borrowing rate on unsecured debt over the risk-free rate in the valuation estimate. The ending balance in OCI includes a loss of $3.9 million after tax related to the interest rate swaps designated as cash flow hedges during the current reporting period.
A hypothetical 10% increase in three-month LIBOR would increase the fair value of interest rate swaps by $17.7 million, with a corresponding after-tax increase in unrealized gains recorded in accumulated OCI by $11.5 million. A hypothetical 10% decrease in interest rates would decrease the fair value of interest rate swaps by $13.0 million, with a corresponding after-tax decrease in unrealized losses recorded in accumulated OCI by $8.5 million.
The following table presents Puget Energy’s interest rate derivative instruments designated as cash flow hedges at December 31, 2009 (no interest rate derivatives existed in 2008):
Derivative Portfolio (Dollars in Millions) | | Puget Energy December 31, 2009 | |
| Interest Rate Swaps | | Assets | | | Liabilities | |
| Current | | $ | -- | | | $ | 26.8 | |
| Long-term | | | 20.9 | | | | -- | |
| Total | | $ | 20.9 | | | $ | 26.8 | |
The change in fair value of Puget Energy’s outstanding interest rate swaps from February 6, 2009 through December 31, 2009 is summarized in the table below:
Interest Rate Derivative Contracts Gain/(Loss) (Dollars in Millions) | | Puget Energy Successor February 6, 2009 - December 31, 2009 | |
| Fair value of contracts outstanding at December 31, 2008 | | $ | -- | |
| Contracts realized or otherwise settled during 2009 | | | (29.1 | ) |
| Change in fair value of derivatives | | | 23.2 | |
| Fair value of contracts outstanding at December 31, 2009 | | $ | (5.9 | ) |
The fair value of Puget Energy’s outstanding interest rate swaps at December 31, 2009, based on price source and the period during which the instrument will mature, is summarized below:
| | | Fair Value of Contracts By Settlement Year | |
Source of Fair Value (Dollars in Millions) | | 2010 | | | | 2011-2012 | | | | 2013-2014 | | | 2015 & Thereafter | | | Total fair value | |
Prices provided by external sources 1 | | $ | (26.8 | ) | | $ | 0.4 | | | $ | 20.5 | | | $ | -- | | | $ | (5.9 | ) |
| Total fair value | | $ | (26.8 | ) | | $ | 0.4 | | | $ | 20.5 | | | $ | -- | | | $ | (5.9 | ) |
______________| 1 | Prices provided by external pricing service, which utilizes broker quotes and pricing models. Pricing inputs are based on observable market data. |
From time to time the CompanyPSE may enter into treasury locklocks or forward starting swap contracts to hedge interest rate exposure related to an anticipated debt issuance. The ending balance in OCI related to the forward starting swaps and previously settled treasury lock contracts at December 31, 2009 is a net loss of $7.6 million after tax and accumulated amortization. This compares to a loss of $7.9 million in OCI after tax as of December 31, 2008. All financial hedge contracts of this type are reviewed by an officer, presented to the Asset Management Committee or the Board of Directors, as applicable and are approved prior to execution. PSE had no treasury locks or forward starting swap contracts outstanding at December 31, 2009.
The carrying amounts and the fair values of the Company’s debt instruments are:were:
| | | 2006 | | 2005 | | | December 31, 2009 | | December 31, 2008 | |
(Dollars in Millions) | | Carrying Amount | | Fair Value | | Carrying Amount | | Fair Value | | | Carrying Amount | | | Fair Value | | Carrying Amount | | | Fair Value | |
| Financial liabilities: | | | | | | | | | | | | | | | | | | | | |
| Short-term debt | | $ | 328.0 | | $ | 328.0 | | $ | 41.0 | | $ | 41.0 | | | $ | 105.0 | | | $ | 105.0 | | $ | 964.7 | | | $ | 964.7 | |
| Short-term debt owed by PSE to Puget Energy | | | 24.3 | | | 24.3 | | | -- | | | -- | | |
Long-term debt - fixed-rate1 | | | 2,733.4 | | | 2,823.3 | | | 2,264.4 | | | 2,416.6 | | |
Short-term debt owed by PSE to Puget Energy 1 | | | | 22.9 | | | | 22.9 | | | 26.1 | | | | 26.1 | |
Long-term debt - fixed-rate | | | | 3,120.9 | | | | 3,282.4 | | | 2,678.9 | | | | 2,221.5 | |
| Long-term debt – variable rate | | | | 1,483.0 | | | | 1,478.6 | | | -- | | | | -- | |
_____________________________1 | PSE’s carrying value and fair valueShort-term debt owed by PSE to Puget Energy is eliminated upon consolidation of fixed-rate long-term debt was the same as Puget Energy’s debt in 2006 and 2005.
Energy. |
In the second quarter 2006, the Company settled two forward starting swap contracts which originated in May 2005. The purpose of the forward starting swap contracts was to hedge a debt offering of $200.0 million that was completed on June 30, 2006. PSE received $21.3 million from the counterparties when the contracts were settled. The forward starting swap contracts were designated and documented under SFAS No. 133 criteria as cash flow hedges, with all changes in market value for each reporting period presented net of tax in other comprehensive income. In the second quarter 2006, the settlement of these instruments resulted in a gain of $13.9 million after-tax, which was recorded in other comprehensive income.
In the third quarter 2006, the Company entered into and settled two forward starting swap contracts. The purpose of the forward starting swap contracts was to hedge a debt offering of $300.0 million that was priced on September 13, 2006. PSE paid $0.6 million to the counterparties when the contracts were settled. The forward starting swap contracts were designated and documented under SFAS No. 133 criteria as cash flow hedges, with all changes in market value being presented net of tax in other comprehensive income. In the third quarter 2006, the settlement of these instruments resulted in a loss of $0.4 million after tax, which was recorded in other comprehensive income. In accordance with SFAS No. 133, the loss will be amortized out of other comprehensive income to current earnings as an increase to interest expense over the life of the new debt issued.
The ending balance in other comprehensive income related to settled swaps contracts at December 31, 2006 was a net loss of $8.5 million after-tax and accumulated amortization. This compares to a loss of $22.4 million in other comprehensive income after-tax and accumulated amortization at December 31, 2005. 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.
| FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA |
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CONSOLIDATED FINANCIAL STATEMENTS: |
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NOTES To The Consolidated Financial Statements of Puget Energy and Puget Sound Energy: |
| Note 1. | |
| Note 2. | |
| Note 3. | |
| Note 4. | |
Note 4. | |
| Note 5. | |
| Note 6. | |
| Note 7. | |
| Note 8. | |
Note 9.9 | |
| Note 10. | |
| Note 11 | |
| Note 12. | |
Note 11. | |
Note 12. | |
| Note 13. | |
| Note 14. | |
Note 15. | |
Note 16. | |
Note 17. | |
| Note 15. | |
| Note 16. | |
| Note 17. | |
| Note 18. | |
| Note 19. | |
| Note 20. | |
| Note 21. | |
| Note 22. | |
| Note 23. | |
| Note 24. | |
| Note 25. | |
| Note 26. | |
|
| |
SCHEDULE: |
|
|
| |
| All other schedules have been omitted because of the absence of the conditions under which they are required, or because the information required is included in the consolidated financial statements or the notes thereto. |
| |
Financial statements of PSE’s subsidiaries are not filed herewith inasmuch as the assets, revenues, earnings and earnings reinvested in the business of the subsidiaries are not material in relation to those of PSE.the Company. |
REPORT OF MANAGEMENT AND STATEMENT OF RESPONSIBILITY Puget Energy, Inc.
and
Puget Sound Energy, Inc.
Puget Energy, Inc. and Puget Sound Energy, Inc. (the Company) management assumes accountability for maintaining compliance with our established financial accounting policies and for reporting our results with objectivity and integrity. The Company believes it is essential for investors and other users of the consolidated financial statements to have confidence that the financial information we provide is timely, complete, relevant and accurate. Management is also responsible to present fairly Puget Energy’s and Puget Sound Energy’s consolidated financial statements, prepared in accordance with generally accepted accounting principles.
Management, with oversight of the Board of Directors, established and maintains a strong ethical climate under the guidance of our Corporate Ethics and Compliance Program so that our affairs are conducted to high standards of proper personal and corporate conduct. Management also established an internal control system that provides reasonable assurance as to the integrity and accuracy of the consolidated financial statements. These policies and practices reflect corporate governance initiatives that are compliant with the corporate governance requirements of the Sarbanes-Oxley Act of 2002, including:
| · | Our Board has adopted clear corporate governance guidelines. |
| · | With the exception of the Chairman of the Board,President and Chief Executive Officer, the Board members are independent of the Company and its management. |
| · | All members of our key Board committees -– the Audit Committee, the Compensation and Leadership Development Committee and the Governance and Public Affairs Committee -– are independent of the Company and its management. |
| · | The independentnon-management members of our Board meet regularly without the presence of Puget Energy and Puget Sound Energy management. |
| · | The Charters of our Board committees clearly establish their respective roles and responsibilities. |
| · | The Company has adopted a Corporate Ethics and Compliance Code with a hotline (through an independent third party) available to all employees, and our Audit Committee has procedures in place for the anonymous submission of employee complaints on accounting, internal accounting controls or auditing matters. The Compliance Program is led by the Chief Ethics and Compliance Officer of the Company. |
| · | Our internal audit control function maintains critical oversight over the key areas of our business and financial processes and controls, and reports directly to our Board Audit Committee. |
Management is confident that the internal control structure is operating effectively and will allow the Company to meet the requirements under Section 404 of the Sarbanes-Oxley Act of 2002.
PricewaterhouseCoopers LLP, our independent registered public accounting firm, reports directly to the Audit Committee of the Board of Directors. PricewaterhouseCoopers LLP’s accompanying report on our consolidated financial statements is based on its audit conducted in accordance with auditing standards prescribed by the Public Company Accounting Oversight Board, including a review of our internal control structure for purposes of designing their audit procedures. Our independent registered accounting firm has reported on the effectiveness of our internal control over financial reporting as required under Section 404 of the Sarbanes-Oxley Act of 2002.
We are committed to improving shareholder value and accept our fiduciary oversight responsibilities. We are dedicated to ensuring that our high standards of financial accounting and reporting as well as our underlying system of internal controls are maintained. Our culture demands integrity and we have confidence in our processes, our internal controls and our people, who are objective in their responsibilities and who operate under a high level of ethical standards.
| /s/ Stephen P. Reynolds | | /s/ Bertrand A. ValdmanEric M. Markell | | /s/ James W. Eldredge |
| Stephen P. Reynolds | | Bertrand A. ValdmanEric M. Markell | | James W. Eldredge |
Chairman, President and Chief Executive Officer
| | SeniorExecutive Vice President Finance
and Chief Financial Officer | | Vice President, Corporate Secretary Controller and
Chief Accounting Officer |
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
To the Board of Directors and Shareholders of Puget Energy, Inc.:
We have completed integrated audits of Puget Energy Inc.’s consolidated financial statements and of its internal control over financial reporting as of December 31, 2006, in accordance with the standards of the Public Company Accounting Oversight Board (United States). Our opinions, based on our audits, are presented below.
Consolidated financial statements and financial statement schedules
In our opinion, the consolidated financial statements listed in the accompanying index present fairly, in all material respects, the financial position of Puget Energy, Inc. and its subsidiaries at December 31, 2006 and December 31, 2005,2009 (Successor Company), and the results of their operations and their cash flows for each of the three years in the period endedfrom February 6, 2009 to December 31, 20062009 in conformity with accounting principles generally accepted in the United States of America. In addition, in our opinion, the financial statement schedules listed in the accompanying index present fairly, in all material respects, the information set forth therein when read in conjunction with the related consolidated financial statements. TheseAlso in our opinion, the Company maintained, in all material respects, effective internal control over financial statements and financial statement schedules arereporting as of December 31, 2009, based on criteria established in Internal Control - Integrated Framework issued by the responsibilityCommittee of Sponsoring Organizations of the Company’s management. Our responsibilityTreadway Commission (COSO). The Company's management is to express an opinion onresponsible for these financial statements and financial statement schedules, for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting, included in Management's Report on Internal Control over Financial Reporting. Our responsibility is to express opinions on these financial statements, on the financial statement schedules, and on the Company's internal control over financial reporting based on our integrated audits. We conducted our audits of these statements in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the auditaudits to obtain reasonable assurance about whether the financial statements are free of material misstatement. Anmisstatement and whether effective internal control over financial reporting was maintained in all material respects. Our audit of the financial statements includesincluded examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, and evaluating the overall financial statement presentation. Our audit of internal control over financial reporting included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, and testing and evaluating the design and operating effectiveness of internal control based on the assessed risk. Our audits also included performing such other procedures as we considered necessary in the circumstances. We believe that our audits provide a reasonable basis for our opinion.
As discussed in Note 4 to the consolidated financial statements, the Company changed the manner in which it accounts for conditional asset retirement obligations in 2005.
As discussed in Note 16 to the consolidated financial statements, the Company changed the manner in which it accounts for share-based compensation in 2006.
As discussed in Note 14 to the consolidated financial statements, the Company changed the manner in which it accounts for defined pension and other postretirement plans in 2006.opinions.
Internal control over financial reporting
Also, in our opinion, management’s assessment, included in Management's Report on Internal Control Over Financial Reporting appearing under Item 9A, that the Company maintained effective internal control over financial reporting as of December 31, 2006 based on criteria established in Internal Control - Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO), is fairly stated, in all material respects, based on those criteria. Furthermore, in our opinion, the Company maintained, in all material respects, effective internal control over financial reporting as of December 31, 2006, based on criteria established in Internal Control - Integrated Framework issued by the COSO. The Company’s management is responsible for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting. Our responsibility is to express opinions on management’s assessment and on the effectiveness of the Company’s internal control over financial reporting based on our audit. We conducted our audit of internal control over financial reporting in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether effective internal control over financial reporting was maintained in all material respects. An audit of internal control over financial reporting includes obtaining an understanding of internal control over financial reporting, evaluating management’s assessment, testing and evaluating the design and operating effectiveness of internal control, and performing such other procedures as we consider necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinions.
A company’s internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company’s internal control over financial reporting includes those policies and procedures that (i) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (ii) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (iii) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s assets that could have a material effect on the financial statements.
Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.
/s/ PricewaterhouseCoopers LLP
PricewaterhouseCoopers LLP
Seattle, WAWashington
March 1, 2007February 25, 2010
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
To the Board of Directors and Shareholder of Puget Sound Energy, Inc.:
We have completed integrated audits of Puget Sound Energy Inc.’s consolidated financial statements and of its internal control over financial reporting as of December 31, 2006, in accordance with the standards of the Public Company Accounting Oversight Board (United States). Our opinions, based on our audits, are presented below.
Consolidated financial statements and financial statement schedule
In our opinion, the consolidated financial statements listed in the accompanying index present fairly, in all material respects, the financial position of Puget Sound Energy, Inc. and its subsidiaries at December 31, 2006 and December 31, 2005,2008 (Predecessor Company), and the results of their operations and their cash flows for the period from January 1, 2009 to February 5, 2009 and for each of the threetwo years in the period ended December 31, 20062008 in conformity with accounting principles generally accepted in the United States of America. In addition, in our opinion, the financial statement scheduleschedules listed in the accompanying indexpresents present fairly, in all material respects, the information set forth therein when read in conjunction with the related consolidated financial statements. These financial statements and financial statement scheduleschedules are the responsibility of the Company’sCompany's management. Our responsibility is to express an opinion on these financial statements and financial statement scheduleschedules based on our audits. We conducted our audits of these statements in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit of financial statements includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, and evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.
As discussed in Note 42 to the consolidated financial statements, the Company changed the manner in which it accounts for conditional asset retirement obligationsbusiness combinations in 2005.
As discussed in Note 16 to the consolidated financial statements, the Company changed2009 and the manner in which it accounts for share-based compensationfair value measurements in 2006.2008.
As discussed in Note 14 to
/s/ PricewaterhouseCoopers LLP
PricewaterhouseCoopers LLP
Seattle, Washington
February 25, 2010
To the Board of Directors and Shareholder of Puget Sound Energy, Inc.
In our opinion, the consolidated financial statements listed in the Company changed the manner in which it accounts for defined pension and other postretirement plans in 2006.
Internal control over financial reporting
Also, in our opinion, management’s assessment, included in Management's Report on Internal Control Over Financial Reporting appearing under Item 9A, that the Company maintained effective internal control over financial reporting as of December 31, 2006 based on criteria established in Internal Control - Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO), isaccompanying index present fairly, stated, in all material respects, based on those criteria. Furthermore,the financial position of Puget Sound Energy, Inc. and its subsidiaries at December 31, 2009 and 2008, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2009 in conformity with accounting principles generally accepted in the United States of America. In addition, in our opinion, the financial statement schedule listed in the accompanying index presents fairly, in all material respects, the information set forth therein when read in conjunction with the related consolidated financial statements. Also in our opinion, the Company maintained, in all material respects, effective internal control over financial reporting as of December 31, 2006,2009, based on criteria established in Internal Control - Integrated Framework issued by the COSO.Committee of Sponsoring Organizations of the Treadway Commission (COSO). The Company’sCompany's management is responsible for these financial statements and financial statement schedule, for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting.reporting, included in Management's Report on Internal Control over Financial Reporting. Our responsibility is to express opinions on management’s assessmentthese financial statements, on the financial statement schedule, and on the effectiveness of the Company’sCompany's internal control over financial reporting based on our audit.integrated audits. We conducted our audit of internal control over financial reportingaudits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the auditaudits to obtain reasonable assurance about whether the financial statements are free of material misstatement and whether effective internal control over financial reporting was maintained in all material respects. AnOur audits of the financial statements included examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, and evaluating the overall financial statement presentation. Our audit of internal control over financial reporting includesincluded obtaining an understanding of internal control over financial reporting, evaluating management’s assessment,assessing the risk that a material weakness exists, and testing and evaluating the design and operating effectiveness of internal control andbased on the assessed risk. Our audits also included performing such other procedures as we considerconsidered necessary in the circumstances. We believe that our audit providesaudits provide a reasonable basis for our opinions.
As discussed in Note 2 to the consolidated financial statements, the Company changed the manner in which it accounts for fair value measurements in 2008.
A company’s internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company’s internal control over financial reporting includes those policies and procedures that (i) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (ii) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (iii) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s assets that could have a material effect on the financial statements.
Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.
/s/ PricewaterhouseCoopers LLP
PricewaterhouseCoopers LLP
Seattle, WA
March 1, 2007February 25, 2010
PugetPuget Energy Consolidated Statements ofINCOME
(Dollars in Thousands, except per share amounts) For Years Ended December 31 | | 2006 | | 2005 | | 2004 | | |
| | | | Successor | | | Predecessor | | | | | | |
(Dollars in Thousands) For Years Ended December 31 | | | February 6, 2009 – December 31, 2009 | | | January 1, 2009 – February 5, 2009 | | | 2008 | | | 2007 | |
| Operating revenues: | | | | | | | | | | | | | | | | | | | |
| Electric | | $ | 1,777,745 | | $ | 1,612,869 | | $ | 1,423,034 | | | $ | 1,885,118 | | | $ | 213,618 | | | $ | 2,129,463 | | | $ | 1,997,829 | |
| Gas | | | 1,120,118 | | | 952,515 | | | 769,306 | | | | 1,034,744 | | | | 190,001 | | | | 1,216,868 | | | | 1,208,029 | |
| Other | | | 7,830 | | | 7,826 | | | 6,537 | | | | 5,286 | | | | 94 | | | | 11,442 | | | | 14,289 | |
| Total operating revenues | | | 2,905,693 | | | 2,573,210 | | | 2,198,877 | | | | 2,925,148 | | | | 403,713 | | | | 3,357,773 | | | | 3,220,147 | |
| Operating expenses: | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Energy costs: | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Purchased electricity | | | 917,801 | | | 860,422 | | | 723,567 | | | | 796,040 | | | | 90,737 | | | | 903,317 | | | | 895,592 | |
| Electric generation fuel | | | 97,320 | | | 73,318 | | | 80,772 | | | | 196,483 | | | | 11,961 | | | | 212,333 | | | | 143,406 | |
| Residential exchange | | | (163,622 | ) | | (180,491 | ) | | (174,473 | ) | | | (83,962 | ) | | | (12,542 | ) | | | (40,664 | ) | | | (52,439 | ) |
| Purchased gas | | | 723,232 | | | 592,120 | | | 451,302 | | | | 597,935 | | | | 120,925 | | | | 737,851 | | | | 762,112 | |
| Unrealized (gain) loss on derivative instruments | | | 71 | | | 472 | | | (526 | ) | |
| Net unrealized (gain) loss on derivative instruments | | | | (156,601 | ) | | | 3,867 | | | | 7,538 | | | | (2,687 | ) |
| Utility operations and maintenance | | | 354,590 | | | 333,256 | | | 291,232 | | | | 449,745 | | | | 37,650 | | | | 461,632 | | | | 403,681 | |
| Other operations and maintenance | | | 3,041 | | | 2,657 | | | 2,326 | | |
| Non-utility expense and other | | | | 16,672 | | | | 112 | | | | 12,785 | | | | 13,636 | |
| Merger and related costs | | | | 2,731 | | | | 44,324 | | | | 9,252 | | | | 8,143 | |
| Depreciation and amortization | | | 262,341 | | | 241,634 | | | 228,566 | | | | 305,943 | | | | 26,742 | | | | 312,128 | | | | 279,222 | |
| Conservation amortization | | | 32,320 | | | 24,308 | | | 22,688 | | | | 58,875 | | | | 7,592 | | | | 61,650 | | | | 39,955 | |
| Taxes other than income taxes | | | 255,712 | | | 233,742 | | | 208,989 | | | | 266,424 | | | | 36,935 | | | | 297,203 | | | | 288,492 | |
| Income taxes | | | 96,271 | | | 88,609 | | | 76,756 | | |
| Total operating expenses | | | 2,579,077 | | | 2,270,047 | | | 1,911,199 | | | | 2,450,285 | | | | 368,303 | | | | 2,975,025 | | | | 2,779,113 | |
| Operating income | | | 326,616 | | | 303,163 | | | 287,678 | | | | 474,863 | | | | 35,410 | | | | 382,748 | | | | 441,034 | |
| Other income (deductions): | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Other income | | | 29,962 | | | 16,803 | | | 11,044 | | | | 49,158 | | | | 3,653 | | | | 33,274 | | | | 28,942 | |
| Other expense | | | | (6,154 | ) | | | (369 | ) | | | (7,215 | ) | | | (7,509 | ) |
| Charitable contributions | | | (15,000 | ) | | -- | | | -- | | | | (5,000 | ) | | | -- | | | | -- | | | | -- | |
| Other expense | | | (9,999 | ) | | (11,063 | ) | | (9,517 | ) | |
| Income taxes | | | 3,784 | | | 2,569 | | | 2,835 | | |
| Interest charges: | | | | | | | | | | | | | | | | | | | | | | | | | | |
| AFUDC | | | 15,874 | | | 9,493 | | | 5,420 | | | | 8,864 | | | | 350 | | | | 8,610 | | | | 12,614 | |
| Interest expense | | | (183,922 | ) | | (174,591 | ) | | (171,959 | ) | | | (265,675 | ) | | | (17,291 | ) | | | (202,582 | ) | | | (217,823 | ) |
| Mandatorily redeemable securities interest expense | | | (91 | ) | | (91 | ) | | (91 | ) | |
| Net income from continuing operations | | | 167,224 | | | 146,283 | | | 125,410 | | |
| Income (loss) from discontinued segment (net of tax) | | | 51,903 | | | 9,514 | | | (70,388 | ) | |
| Net income before cumulative effect of accounting change | | | 219,127 | | | 155,797 | | | 55,022 | | |
| Cumulative effect of implementation of accounting change (net of tax) | | | 89 | | | (71 | ) | | -- | | |
| Income from continuing operations before income taxes | | | | 256,056 | | | | 21,753 | | | | 214,835 | | | | 257,258 | |
| Income tax expense | | | | 82,041 | | | | 8,997 | | | | 59,906 | | | | 72,582 | |
| Income from continuing operations | | | | 174,015 | | | | 12,756 | | | | 154,929 | | | | 184,676 | |
| Loss from discontinued segment (net of tax) | | | | -- | | | | -- | | | | -- | | | | (212 | ) |
| Net income | | $ | 219,216 | | $ | 155,726 | | $ | 55,022 | | | $ | 174,015 | | | $ | 12,756 | | | $ | 154,929 | | | $ | 184,464 | |
| Common shares outstanding weighted average (in thousands) | | | 115,999 | | | 102,570 | | | 99,470 | | |
| Diluted shares outstanding weighted average (in thousands) | | | 116,457 | | | 103,111 | | | 99,911 | | |
| Basic earnings per common share before cumulative effect from accounting change | | $ | 1.44 | | $ | 1.43 | | $ | 1.26 | | |
| Basic earnings per common share from discontinued operations | | | 0.45 | | | 0.09 | | | (0.71 | ) | |
| Cumulative effect from accounting change | | | -- | | | -- | | | -- | | |
| Basic earnings per common share | | $ | 1.89 | | $ | 1.52 | | $ | 0.55 | | |
| Diluted earnings per common share before cumulative effect from accounting change | | $ | 1.44 | | $ | 1.42 | | $ | 1.26 | | |
| Diluted earnings per common share from discontinued operations | | | 0.44 | | | 0.09 | | | (0.71 | ) | |
| Cumulative effect from accounting change | | | -- | | | -- | | | -- | | |
| Diluted earnings per common share | | $ | 1.88 | | $ | 1.51 | | $ | 0.55 | | |
The accompanying notes are an integral part of the consolidated financial statements.
Puget Energy Consolidated Balance Sheets ASSETS
| | | | Successor | | | Predecessor | |
(Dollars in Thousands) At December 31 | | 2006 | | 2005 | | | 2009 | | | 2008 | |
| Utility plant: | | | | | | | | | | | |
| Electric plant | | $ | 5,334,368 | | $ | 4,802,363 | | | $ | 4,705,900 | | | $ | 6,596,359 | |
| Gas plant | | | 2,146,048 | | | 1,991,456 | | | | 1,995,219 | | | | 2,500,236 | |
| Common plant | | | 458,262 | | | 439,599 | | | | 284,758 | | | | 550,368 | |
| Less: Accumulated depreciation and amortization | | | (2,757,632 | ) | | (2,602,500 | ) | | | (185,474 | ) | | | (3,358,816 | ) |
| Net utility plant | | | 5,181,046 | | | 4,630,918 | | | | 6,800,403 | | | | 6,288,147 | |
| Other property and investments: | | | | | | | | | |
| Goodwill | | | | 1,656,513 | | | | -- | |
| Investment in Bonneville Exchange Power contract | | | | 26,450 | | | | 29,976 | |
| Other property and investments | | | 151,462 | | | 157,321 | | | | 127,073 | | | | 118,039 | |
| Total other property and investments | | | | 1,810,036 | | | | 148,015 | |
| Current assets: | | | | | | | | | | | | | | | |
| Cash | | | 28,117 | | | 16,710 | | |
| Cash and cash equivalents | | | | 78,527 | | | | 38,526 | |
| Restricted cash | | | 839 | | | 1,047 | | | | 19,844 | | | | 18,889 | |
| Accounts receivable, net of allowance for doubtful accounts | | | 253,613 | | | 294,509 | | | | 320,016 | | | | 203,563 | |
| Secured pledged accounts receivable | | | 110,000 | | | 41,000 | | | | -- | | | | 158,000 | |
| Unbilled revenues | | | 202,492 | | | 160,207 | | | | 208,948 | | | | 248,649 | |
| Purchased gas adjustment receivable | | | 39,822 | | | 67,335 | | |
| Materials and supplies, at average cost | | | 43,501 | | | 36,491 | | | | 75,035 | | | | 62,024 | |
| Fuel and gas inventory, at average cost | | | 115,752 | | | 91,058 | | | | 96,483 | | | | 120,205 | |
| Unrealized gain on derivative instruments | | | 16,826 | | | 75,037 | | | | 14,948 | | | | 15,618 | |
| Prepayments and other | | | 9,228 | | | 7,596 | | |
| Income taxes | | | | 134,617 | | | | 19,121 | |
| Prepaid expense and other | | | | 13,117 | | | | 14,964 | |
| Power contract acquisition adjustment gain | | | | 169,171 | | | | -- | |
| Deferred income taxes | | | 1,175 | | | -- | | | | 39,977 | | | | 75,135 | |
| Current assets of discontinued operations | | | -- | | | 107,434 | | |
| Total current assets | | | 821,365 | | | 898,424 | | | | 1,170,683 | | | | 974,694 | |
| Other long-term assets: | | | | | | | | |
| Restricted cash | | | 3,814 | | | -- | | |
| Other long-term and regulatory assets: | | | | | | | | | |
| Regulatory asset for deferred income taxes | | | 115,304 | | | 129,693 | | | | 89,303 | | | | 95,417 | |
| Regulatory asset for PURPA buyout costs | | | 167,941 | | | 191,170 | | | | 78,162 | | | | 110,838 | |
| Power cost adjustment mechanism | | | | 8,529 | | | | 3,126 | |
| Regulatory assets related to power contracts | | | | 210,340 | | | | -- | |
| Other regulatory assets | | | | 751,999 | | | | 766,732 | |
| Unrealized gain on derivative instruments | | | 6,934 | | | 28,464 | | | | 25,459 | | | | 6,712 | |
| Power cost adjustment mechanism | | | 6,357 | | | 18,380 | | |
| Power contract acquisition adjustment gain | | | | 865,020 | | | | -- | |
| Other | | | 611,816 | | | 388,468 | | | | 90,206 | | | | 40,421 | |
| Long-term assets of discontinued operations | | | -- | | | 167,113 | | |
| Total other long-term assets | | | 912,166 | | | 923,288 | | |
| Total other long-term and regulatory assets | | | | 2,119,018 | | | | 1,023,246 | |
| Total assets | | $ | 7,066,039 | | $ | 6,609,951 | | | $ | 11,900,140 | | | $ | 8,434,102 | |
The accompanying notes are an integral part of the consolidated financial statements.
Puget Energy Consolidated Balance Sheets CAPITALIZATION AND LIABILITIES
| | | | Successor | | | Predecessor | |
(Dollars in Thousands) At December 31 | | 2006 | | 2005 | | | 2009 | | | 2008 | |
| Capitalization: | | | | | | | | | | | |
(See Consolidated Statements of Capitalization ) | | | | | | |
| Common equity | | $ | 2,116,029 | | $ | 2,027,047 | | |
| Total shareholders’ equity | | | 2,116,029 | | | 2,027,047 | | |
| Common shareholders’ equity: | | | | | | | | | |
| Common stock $0.01 par value, 250,000,000 shares authorized, 129,678,489 shares outstanding | | | $ | -- | | | $ | 1,297 | |
| Common stock $0.01 par value, 1,000 share authorized, 200 shares outstanding | | | | -- | | | | -- | |
| Additional paid-in capital | | | | 3,308,957 | | | | 2,275,225 | |
| Earnings reinvested in the business | | | | 91,024 | | | | 259,483 | |
Accumulated other comprehensive income (loss) - net of tax | | | | 23,487 | | | | (262,804 | ) |
| Total common shareholders’ equity | | | | 3,423,468 | | | | 2,273,201 | |
| Redeemable securities and long-term debt: | | | | | | | | | | | | | | | |
| Preferred stock subject to mandatory redemption | | | 1,889 | | | 1,889 | | |
| Junior subordinated debentures of the corporation payable to a subsidiary trust holding mandatorily redeemable preferred securities | | | 37,750 | | | 237,750 | | |
| Long-term debt | | | 2,608,360 | | | 2,183,360 | | |
Preferred stock subject to mandatory redemption - cumulative - $100 par value: | | | | | | | | | |
4.84% series -150,000 shares authorized, 14,583 shares outstanding | | | | -- | | | | 1,458 | |
4.70% series -150,000 shares authorized, 4,311 shares outstanding | | | | -- | | | | 431 | |
| Total preferred stock subject to mandatory redemption | | | | -- | | | | 1,889 | |
| Long-term debt: | | | | | | | | | |
| PSE first mortgage bonds and senior notes | | | | 2,709,000 | | | | 2,267,000 | |
| PSE pollution control revenue bonds: | | | | | | | | | |
| Revenue refunding 2003 series, due 2031 | | | | 161,860 | | | | 161,860 | |
| PSE junior subordinated notes | | | | 250,000 | | | | 250,000 | |
| Puget Energy long-term debt | | | | 1,483,000 | | | | -- | |
| PSE long-term debt due within one year | | | | (232,000 | ) | | | (158,000 | ) |
| Debt discount and other | | | | (331,162 | ) | | | -- | |
| Total redeemable securities and long-term debt | | | 2,647,999 | | | 2,422,999 | | | | 4,040,698 | | | | 2,522,749 | |
| Total capitalization | | | 4,764,028 | | | 4,450,046 | | | | 7,464,166 | | | | 4,795,950 | |
| Minority interest in discontinued operations | | | -- | | | 6,816 | | |
| Current liabilities: | | | | | | | | | | | | | | | |
| Accounts payable | | | 379,579 | | | 346,490 | | | | 321,287 | | | | 342,254 | |
| Short-term debt | | | 328,055 | | | 41,000 | | | | 105,000 | | | | 964,700 | |
| Current maturities of long-term debt | | | 125,000 | | | 81,000 | | | | 232,000 | | | | 158,000 | |
| Accrued expenses: | | | | | | | | | | | | | | | |
| Purchased gas liability | | | | 49,587 | | | | 8,892 | |
| Taxes | | | 54,977 | | | 112,860 | | | | 77,302 | | | | 85,068 | |
| Salaries and wages | | | 32,122 | | | 15,034 | | | | 30,654 | | | | 35,280 | |
| Interest | | | 36,915 | | | 31,004 | | | | 52,540 | | | | 36,074 | |
| Unrealized loss on derivative instruments | | | 70,596 | | | 9,772 | | | | 168,783 | | | | 236,866 | |
| Deferred income tax | | | -- | | | 10,968 | | |
| Power contract acquisition adjustment loss | | | | 94,223 | | | | -- | |
| Other | | | 43,889 | | | 35,694 | | | | 194,786 | | | | 117,222 | |
| Current liabilities of discontinued operations | | | -- | | | 55,791 | | |
| Total current liabilities | | | 1,071,133 | | | 739,613 | | | | 1,326,162 | | | | 1,984,356 | |
| Long-term liabilities: | | | | | | | | |
| Long-term and regulatory liabilities: | | | | | | | | | |
| Deferred income taxes | | | 745,095 | | | 738,809 | | | | 1,147,667 | | | | 815,462 | |
| Unrealized loss on derivative instruments | | | 415 | | | -- | | | | 89,717 | | | | 158,423 | |
| Regulatory liabilities | | | | 261,990 | | | | 219,221 | |
| Regulatory liabilities related to power contracts | | | | 1,034,192 | | | | -- | |
| Power contract acquisition adjustment loss | | | | 117,272 | | | | -- | |
| Other deferred credits | | | 485,368 | | | 513,023 | | | | 458,974 | | | | 460,690 | |
| Long-term liabilities of discontinued operations | | | -- | | | 161,644 | | |
| Total long-term liabilities | | | 1,230,878 | | | 1,413,476 | | |
| Commitments and contingencies (Note 22) | | | | | | | | |
| Total long-term and regulatory liabilities | | | | 3,109,812 | | | | 1,653,796 | |
| Commitments and contingencies (Note 23) | | | | | | | | | |
| Total capitalization and liabilities | | $ | 7,066,039 | | $ | 6,609,951 | | | $ | 11,900,140 | | | $ | 8,434,102 | |
The accompanying notes are an integral part of the consolidated financial statements.
CAPITALIZATIONCOMMON SHAREHOLDERS’ EQUITY
(Dollars in Thousands) At December 31 | | 2006 | | 2005 | |
| Common equity: | | | | | |
| Common stock $0.01 par value, 250,000,000 shares authorized, 116,576,636 and 115,695,463 shares outstanding at December 31, 2006 and 2005 | | $ | 1,166 | | $ | 1,157 | |
| Additional paid-in capital | | | 1,969,032 | | | 1,948,975 | |
| Earnings reinvested in the business | | | 172,529 | | | 69,407 | |
Accumulated other comprehensive income (loss) - net of tax | | | (26,698 | ) | | 7,508 | |
| Total common equity | | | 2,116,029 | | | 2,027,047 | |
Preferred stock subject to mandatory redemption - cumulative - $100 par value: * | | | | | | | |
4.84% series -150,000 shares authorized, 14,583 shares outstanding at December 31, 2006 and 2005 | | | 1,458 | | | 1,458 | |
4.70% series -150,000 shares authorized, 4,311 shares outstanding at December 31, 2006 and 2005 | | | 431 | | | 431 | |
| Total preferred stock subject to mandatory redemption | | | 1,889 | | | 1,889 | |
| Junior subordinated debentures of the corporation payable to a subsidiary trust holding mandatorily redeemable preferred securities | | | 37,750 | | | 237,750 | |
| Long-term debt: | | | | | | | |
| First mortgage bonds and senior notes | | | 2,571,500 | | | 2,102,500 | |
| Pollution control revenue bonds: | | | | | | | |
| Revenue refunding 2003 series, due 2031 | | | 161,860 | | | 161,860 | |
| Other notes | | | -- | | | -- | |
| Long-term debt due within one year | | | (125,000 | ) | | (81,000 | ) |
| Total long-term debt excluding current maturities | | | 2,608,360 | | | 2,183,360 | |
| Total capitalization | | $ | 4,764,028 | | $ | 4,450,046 | |
| | | Common Stock | | | | | | | | | | | | | |
(Dollars in Thousands) For Years Ended December 31, 2009, 2008 & 2007 | | Shares | | | Amount | | | Additional Paid-in Capital | | | Earnings Reinvested in the Business | | | Accumulated Other Comprehensive Income (Loss) | | | Total Amount | |
| Predecessor | | | | | | | | | | | | | | | | | | |
| Balance at December 31, 2006 | | | 116,576,636 | | | $ | 1,166 | | | $ | 1,969,032 | | | $ | 172,529 | | | $ | (26,698 | ) | | $ | 2,116,029 | |
| Net income | | | -- | | | | -- | | | | -- | | | | 184,464 | | | | -- | | | | 184,464 | |
| Common stock dividend declared | | | -- | | | | -- | | | | -- | | | | (116,914 | ) | | | -- | | | | (116,914 | ) |
| Common stock issued: | | | | | | | | | | | | | | | | | | | | | | | | |
| New issuance | | | 12,500,000 | | | | 125 | | | | 293,070 | | | | -- | | | | -- | | | | 293,195 | |
| Dividend reinvestment plan | | | 399,993 | | | | 4 | | | | 9,777 | | | | -- | | | | -- | | | | 9,781 | |
| Employee plans | | | 201,860 | | | | 2 | | | | 6,621 | | | | -- | | | | -- | | | | 6,623 | |
| Other comprehensive income | | | -- | | | | -- | | | | -- | | | | -- | | | | 28,776 | | | | 28,776 | |
| Balance at December 31, 2007 | | | 129,678,489 | | | $ | 1,297 | | | $ | 2,278,500 | | | $ | 240,079 | | | $ | 2,078 | | | $ | 2,521,954 | |
| Net income | | | -- | | | | -- | | | | -- | | | | 154,929 | | | | -- | | | | 154,929 | |
| Common stock dividend declared | | | -- | | | | -- | | | | -- | | | | (129,677 | ) | | | -- | | | | (129,677 | ) |
| Adjustment to initially apply ASC 820, Fair Value Measurements | | | -- | | | | -- | | | | -- | | | | (5,848 | ) | | | -- | | | | (5,848 | ) |
| Common stock issued: | | | | | | | | | | | | | | | | | | | | | | | | |
| Employee plans | | | -- | | | | -- | | | | (3,275 | ) | | | -- | | | | -- | | | | (3,275 | ) |
| Other comprehensive loss | | | -- | | | | -- | | | | -- | | | | -- | | | | (264,882 | ) | | | (264,882 | ) |
| Balance at December 31, 2008 | | | 129,678,489 | | | $ | 1,297 | | | $ | 2,275,225 | | | $ | 259,483 | | | $ | (262,804 | ) | | $ | 2,273,201 | |
| Net income | | | -- | | | | -- | | | | -- | | | | 12,756 | | | | -- | | | | 12,756 | |
| Common stock dividend declared | | | -- | | | | -- | | | | -- | | | | (38,188 | ) | | | -- | | | | (38,188 | ) |
| Common stock expense | | | -- | | | | -- | | | | (455 | ) | | | -- | | | | -- | | | | (455 | ) |
| Vesting of employee common stock | | | -- | | | | -- | | | | 1,531 | | | | -- | | | | -- | | | | 1,531 | |
| Other comprehensive loss | | | -- | | | | -- | | | | -- | | | | -- | | | | (19,312 | ) | | | (19,312 | ) |
| Balance at February 5, 2009 | | | 129,678,489 | | | $ | 1,297 | | | $ | 2,276,301 | | | $ | 234,051 | | | $ | (282,116 | ) | | $ | 2,229,533 | |
| Successor | | | | | | | | | | | | | | | | | | | | | | | | |
| Capitalization at merger | | | 200 | | | $ | -- | | | $ | 3,308,529 | | | $ | -- | | | $ | -- | | | $ | 3,308,529 | |
| Net income | | | -- | | | | -- | | | | -- | | | | 174,015 | | | | -- | | | | 174,015 | |
| Common stock dividend declared | | | -- | | | | -- | | | | -- | | | | (82,991 | ) | | | -- | | | | (82,991 | ) |
| Employee stock plan tax windfall | | | -- | | | | -- | | | | 428 | | | | -- | | | | -- | | | | 428 | |
| Other comprehensive income | | | -- | | | | -- | | | | -- | | | | -- | | | | 23,487 | | | | 23,487 | |
| Balance at December 31, 2009 | | | 200 | | | $ | -- | | | $ | 3,308,957 | | | $ | 91,024 | | | $ | 23,487 | | | $ | 3,423,468 | |
* Puget Energy has 50,000,000 shares authorized for $0.01 par value preferred stock. Puget Sound Energy has 13,000,000 shares authorized for $25 par value preferred stock and 3,000,000 shares authorized for $100 par value preferred stock. The preferred stock is available for issuance under mandatory and non-mandatory redemption provisions.
The accompanying notes are an integral part of the consolidated financial statements.
Puget Energy Consolidated Statements of COMMON SHAREHOLDERS’ EQUITYCOMPREHENSIVE INCOME
| (Dollars in Thousands) | | Common Stock | Additional | | | | Accumulated Other | | | |
For Years Ended December 31, 2006, 2005 & 2004 | | Shares | | Amount | | Paid-in Capital | | Retained Earnings | | Comprehensive Income | | Total Amount | |
| Balance at December 31, 2003 | | | 99,074,070 | | $ | 991 | | $ | 1,603,901 | | $ | 58,217 | | $ | (8,063 | ) | $ | 1,655,046 | |
| Net income | | | -- | | | -- | | | -- | | | 55,022 | | | -- | | | 55,022 | |
| Common stock dividend declared | | | -- | | | -- | | | -- | | | (99,386 | ) | | -- | | | (99,386 | ) |
| Common stock issued: | | | | | | | | | | | | | | | | | | | |
| New issuance | | | 5,195 | | | -- | | | 68 | | | -- | | | -- | | | 68 | |
| Dividend reinvestment plan | | | 681,491 | | | 7 | | | 15,170 | | | -- | | | -- | | | 15,177 | |
| Employee plans | | | 107,612 | | | 1 | | | 2,617 | | | -- | | | -- | | | 2,618 | |
| Other comprehensive loss | | | -- | | | -- | | | -- | | | -- | | | (6,269 | ) | | (6,269 | ) |
| Balance at December 31, 2004 | | | 99,868,368 | | $ | 999 | | $ | 1,621,756 | | $ | 13,853 | | $ | (14,332 | ) | $ | 1,622,276 | |
| Net income | | | -- | | | -- | | | -- | | | 155,726 | | | -- | | | 155,726 | |
| Common stock dividend declared | | | -- | | | -- | | | -- | | | (100,172 | ) | | -- | | | (100,172 | ) |
| Common stock issued: | | | | | | | | | | | | | | | | | | | |
| New issuance | | | 15,009,991 | | | 150 | | | 309,744 | | | -- | | | -- | | | 309,894 | |
| Dividend reinvestment plan | | | 656,267 | | | 6 | | | 14,545 | | | -- | | | -- | | | 14,551 | |
| Employee plans | | | 160,837 | | | 2 | | | 2,930 | | | -- | | | -- | | | 2,932 | |
| Other comprehensive loss | | | -- | | | -- | | | -- | | | -- | | | 21,840 | | | 21,840 | |
| Balance at December 31, 2005 | | | 115,695,463 | | $ | 1,157 | | $ | 1,948,975 | | $ | 69,407 | | $ | 7,508 | | $ | 2,027,047 | |
| Net income | | | -- | | | -- | | | -- | | | 219,216 | | | -- | | | 219,216 | |
| Common stock dividend declared | | | -- | | | -- | | | -- | | | (116,094 | ) | | -- | | | (116,094 | ) |
| Common stock issued: | | | | | | | | | | | | | | | | | | | |
| Dividend reinvestment plan | | | 614,548 | | | 6 | | | 13,481 | | | -- | | | -- | | | 13,487 | |
| Employee plans | | | 266,625 | | | 3 | | | 6,576 | | | -- | | | -- | | | 6,579 | |
| Other comprehensive loss | | | -- | | | -- | | | -- | | | -- | | | (15,553 | ) | | (15,553 | ) |
| Adjustment to initially apply SFAS No. 158, net of tax of $(12,420) | | | -- | | | -- | | | -- | | | -- | | | (18,653 | ) | | (18,653 | ) |
| Balance at December 31, 2006 | | | 116,576,636 | | $ | 1,166 | | $ | 1,969,032 | | $ | 172,529 | | $ | (26,698 | ) | $ | 2,116,029 | |
| | | Successor | | | Predecessor | |
(Dollars in Thousands) For Years Ended December 31 | | February 6, 2009 – December 31, 2009 | | | January 1, 2009 – February 5, 2009 | | | 2008 | | | 2007 | |
| Net income | | $ | 174,015 | | | $ | 12,756 | | | $ | 154,929 | | | $ | 184,464 | |
| Other comprehensive income (loss): | | | | | | | | | | | | | | | | |
| Net unrealized loss on interest rate swaps during the period, net of tax of $(12,264), $0, $0 and $0, respectively | | | (22,777 | ) | | | -- | | | | -- | | | | -- | |
| Reclassification of net unrealized loss on interest rate swaps during the period, net of tax of $10,168, $0, $0 and $0, respectively | | | 18,884 | | | | -- | | | | -- | | | | -- | |
| Net unrealized gain (loss) from pension and postretirement plans, net of tax of $18,554, $ 170, $(80,769) and $16,083, respectively | | | 34,458 | | | | 315 | | | | (149,999 | ) | | | 29,869 | |
| Net unrealized loss on energy derivative instruments during the period, net of tax of $(14,120), $(13,010), $(73,621) and $(6,776), respectively | | | (26,222 | ) | | | (24,162 | ) | | | (136,725 | ) | | | (12,584 | ) |
| Reclassification of net unrealized loss on energy derivative instruments settled during the period, net of tax of $10,309, $2,428, $11,590 and $6,017, respectively | | | 19,144 | | | | 4,509 | | | | 21,525 | | | | 11,174 | |
| Amortization of financing cash flow hedge contracts to earnings, net of tax of $0, $15, $171 and $171, respectively | | | -- | | | | 26 | | | | 317 | | | | 317 | |
| Other comprehensive income (loss) | | | 23,487 | | | | (19,312 | ) | | | (264,882 | ) | | | 28,776 | |
| Comprehensive income (loss) | | $ | 197,502 | | | $ | (6,556 | ) | | $ | (109,953 | ) | | $ | 213,240 | |
The accompanying notes are an integral part of the consolidated financial statements.
Puget Energy Consolidated Statements of COMPREHENSIVE INCOME
(Dollars in Thousands) For Years Ended December 31 | | 2006 | 2005 | 2004 |
| Net income | | $ | 219,216 | | $ | 155,726 | | $ | 55,022 | |
| Other comprehensive income (loss): | | | | | | | | | | |
| Foreign currency translation adjustment, net of tax of $(176), $(49) and $148, respectively | | | (327 | ) | | (91 | ) | | 275 | |
| Minimum pension liability adjustment, net of tax of $2,376, $0 and $0, respectively | | | 2,873 | | | 925 | | | 157 | |
| Net unrealized gain (loss) on energy derivative instruments during the period, net of tax of $(17,669), $26,799 and $3,672, respectively | | | (32,813 | ) | | 49,770 | | | 6,820 | |
| Reversal of net unrealized (gains) losses on energy derivative instruments settled during the period, net of tax of $(2,972), $(10,319) and $(5,610), respectively | | | (5,519 | ) | | (19,164 | ) | | (10,418 | ) |
| Gain (loss) from settlement of financing cash flow hedge contracts, net of tax of $7,239, $(12,363) and $0, respectively | | | 13,443 | | | (22,960 | ) | | -- | |
| Amortization of financing cash flow hedge contracts to earnings, net of tax of $289, $245 and $0, respectively | | | 537 | | | 455 | | | -- | |
| Deferral of energy cash flow hedges related to power cost adjustment mechanism, net of tax of $3,367, $6,949 and $(1,671), respectively | | | 6,253 | | | 12,905 | | | (3,103 | ) |
| Other comprehensive income (loss) | | | (15,553 | ) | | 21,840 | | | (6,269 | ) |
| Comprehensive income | | $ | 203,663 | | $ | 177,566 | | $ | 48,753 | |
| | | Successor | | | Predecessor | |
(Dollars in Thousands) For Years Ended December 31 | | February 6, 2009 – December 31, 2009 | | | January 1, 2009 – February 5, 2009 | | | 2008 | | | 2007 | |
| Operating activities: | | | | | | | | | | | | |
| Net income | | $ | 174,015 | | | $ | 12,756 | | | $ | 154, 929 | | | $ | 184,464 | |
| Adjustments to reconcile net income to net cash provided by operating activities: | | | | | | | | | | | | | | | | |
| Depreciation and amortization | | | 305,943 | | | | 26,742 | | | | 312,128 | | | | 279,222 | |
| Conservation amortization | | | 58,875 | | | | 7,592 | | | | 61,650 | | | | 39,955 | |
| Deferred income taxes and tax credits, net | | | 243,381 | | | | (512 | ) | | | 80,596 | | | | 66,820 | |
| Power cost adjustment mechanism | | | -- | | | | -- | | | | (12 | ) | | | 3,243 | |
| Amortization of gas pipeline capacity assignment | | | (8,620 | ) | | | (791 | ) | | | (9,346 | ) | | | (10,943 | ) |
| Non cash return on regulatory assets | | | (8,786 | ) | | | (800 | ) | | | (9,860 | ) | | | (10,194 | ) |
| Net unrealized loss (gain) on derivative instruments | | | (156,601 | ) | | | 3,867 | | | | 7,538 | | | | (2,687 | ) |
| Deferred regulatory costs for generation facilities | | | (18,369 | ) | | | (3,443 | ) | | | (288 | ) | | | (11,505 | ) |
| Pension funding | | | (18,400 | ) | | | -- | | | | (24,900 | ) | | | -- | |
| Change in residential exchange program | | | (2,667 | ) | | | 1,927 | | | | 37,811 | | | | (28,133 | ) |
| Derivative contracts classified as financing activities due to merger | | | 524,397 | | | | -- | | | | -- | | | | -- | |
| Cash receipt from lease purchase option settlement | | | -- | | | | -- | | | | -- | | | | 18,859 | |
| Storm damage deferred costs | | | -- | | | | -- | | | | -- | | | | (29,274 | ) |
| Other | | | 26,618 | | | | 5,230 | | | | 3,999 | | | | 16,117 | |
| Change in certain current assets and liabilities: | | | | | | | | | | | | | | | | |
| Accounts receivable and unbilled revenue | | | 91,515 | | | | (31,332 | ) | | | (29,405 | ) | | | (4,652 | ) |
| Materials and supplies | | | 4,077 | | | | (3,388 | ) | | | 89 | | | | (18,613 | ) |
| Fuel and gas inventory | | | (11,444 | ) | | | 7,605 | | | | (20,433 | ) | | | 15,981 | |
| Income taxes | | | (133,773 | ) | | | 18,277 | | | | 25,182 | | | | (44,303 | ) |
| Prepayments and other | | | 5,744 | | | | (3,295 | ) | | | (3,055 | ) | | | (2,681 | ) |
| Purchased gas receivable/payable | | | 38,984 | | | | 1,711 | | | | (68,972 | ) | | | 117,685 | |
| Accounts payable | | | (85,073 | ) | | | (40,203 | ) | | | 21,420 | | | | (52,678 | ) |
| Taxes payable | | | 12,227 | | | | (3,340 | ) | | | 313 | | | | 29,779 | |
| Accrued expenses and other | | | (31,473 | ) | | | 59,172 | | | | (2,802 | ) | | | 7,539 | |
| Net cash provided by operating activities | | | 1,010,570 | | | | 57,775 | | | | 536,582 | | | | 564,001 | |
| Investing activities: | | | | | | | | | | | | | | | | |
Construction expenditures - excluding equity AFUDC | | | (726,157 | ) | | | (49,531 | ) | | | (846,001 | ) | | | (737,258 | ) |
| Energy efficiency expenditures | | | (82,258 | ) | | | (4,918 | ) | | | (66,126 | ) | | | (43,398 | ) |
| Restricted cash | | | (945 | ) | | | (10 | ) | | | (14,096 | ) | | | (141 | ) |
| Cash proceeds from property sales | | | 28,152 | | | | -- | | | | 2,248 | | | | 6,468 | |
| Other | | | (1,868 | ) | | | 959 | | | | (7,880 | ) | | | 17,330 | |
| Net cash used in investing activities | | | (783,076 | ) | | | (53,500 | ) | | | (931,855 | ) | | | (756,999 | ) |
| Financing activities: | | | | | | | | | | | | | | | | |
| Change in short-term debt and leases, net | | | 38,807 | | | | (151,800 | ) | | | 704,214 | | | | (67,569 | ) |
| Dividends paid | | | (121,179 | ) | | | -- | | | | (129,677 | ) | | | (108,434 | ) |
| Issuance of common stock | | | -- | | | | -- | | | | -- | | | | 300,544 | |
| Long-term notes and bonds issued | | | 400,211 | | | | 250,000 | | | | -- | | | | 250,000 | |
| Redemption of preferred stock | | | -- | | | | (1,889 | ) | | | -- | | | | (37,750 | ) |
| Redemption of bonds and notes | | | (158,000 | ) | | | -- | | | | (179,500 | ) | | | (125,000 | ) |
| Derivative contracts classified as financing activities due to merger | | | (524,397 | ) | | | -- | | | | -- | | | | -- | |
| Issuance costs of bonds and other | | | (16,372 | ) | | | 7,133 | | | | (2,035 | ) | | | (6,113 | ) |
| Net cash (used in) provided by financing activities | | | (380,930 | ) | | | 103,444 | | | | 393,002 | | | | 205,678 | |
| Net increase (decrease) in cash and cash equivalents | | | (153,436 | ) | | | 107,719 | | | | (2,271 | ) | | | 12,680 | |
| Cash and cash equivalents at beginning of year | | | 231,963 | | | | 38,526 | | | | 40,797 | | | | 28,117 | |
| Cash and cash equivalents at end of year | | $ | 78,527 | | | $ | 146,245 | | | $ | 38,526 | | | $ | 40,797 | |
| Supplemental cash flow information: | | | | | | | | | | | | | | | | |
| Cash payments for interest (net of capitalized interest) | | $ | 247,247 | | | $ | 1,239 | | | $ | 204,837 | | | $ | 196,180 | |
| Cash payments (refunds) for income taxes | | | (47,740 | ) | | | -- | | | | (42,338 | ) | | | 26,897 | |
The accompanying notes are an integral part of the consolidated financial statements.
Puget Sound Energy Consolidated Statements of CASH FLOWSINCOME
(Dollars in Thousands) For Years Ended December 31 | | 2006 | | 2005 | | 2004 | |
| Operating activities: | | | | | | | |
| Net income | | $ | 219,216 | | $ | 155,726 | | $ | 55,022 | |
| Adjustments to reconcile net income to net cash provided by operating activities: | | | | | | | | | | |
| Depreciation and amortization | | | 262,341 | | | 241,634 | | | 246,842 | |
Deferred income taxes and tax credits - net | | | 20,613 | | | (56,852 | ) | | 72,702 | |
| Power cost adjustment mechanism | | | 12,023 | | | (18,380 | ) | | 3,605 | |
| Non cash return on regulatory assets | | | (12,438 | ) | | -- | | | -- | |
| Amortization of gas pipeline capacity assignment | | | (10,632 | ) | | -- | | | -- | |
| Gain on sale of InfrastruX | | | (29,765 | ) | | -- | | | -- | |
| InfrastruX carrying value impairment adjustment | | | (7,269 | ) | | 7,269 | | | -- | |
| InfrastruX goodwill impairment | | | -- | | | -- | | | 91,196 | |
| Net unrealized (gain) loss on derivative instruments | | | 71 | | | 472 | | | (526 | ) |
| Other (including conservation amortization) | | | 13,600 | | | 1,131 | | | 8,166 | |
| Cash collateral received from (returned to) energy suppliers | | | (22,020 | ) | | 15,700 | | | 6,320 | |
| Gas pipeline capacity assignment | | | -- | | | 55,000 | | | -- | |
| BPA prepaid transmission | | | -- | | | (10,750 | ) | | -- | |
| Chelan PUD contract initiation | | | (89,000 | ) | | -- | | | -- | |
| Storm damage deferred costs | | | (92,331 | ) | | -- | | | -- | |
| Change in certain current assets and liabilities: | | | | | | | | | | |
| Accounts receivable and unbilled revenue | | | (78,179 | ) | | (217,861 | ) | | 2,218 | |
| Materials and supplies | | | (6,093 | ) | | (4,945 | ) | | (39,740 | ) |
| Fuel and gas inventory | | | (24,694 | ) | | (25,163 | ) | | 17,512 | |
| Prepayments and other | | | (4,319 | ) | | 273 | | | (8,159 | ) |
| Purchased gas receivable / liability | | | 27,513 | | | (48,246 | ) | | (31,073 | ) |
| Accounts payable | | | 36,038 | | | 119,416 | | | 25,163 | |
| Taxes payable | | | (53,826 | ) | | 38,047 | | | 247 | |
| Tenaska disallowance reserve | | | -- | | | (3,156 | ) | | 3,156 | |
| Accrued expenses and other | | | 24,658 | | | 6,496 | | | 3,709 | |
| Net cash provided by operating activities | | | 185,507 | | | 255,811 | | | 456,360 | |
| Investing activities: | | | | | | | | | | |
Construction and capital expenditures - excluding equity AFUDC | | | (749,516 | ) | | (583,594 | ) | | (409,403 | ) |
| Energy efficiency expenditures | | | (33,865 | ) | | (24,428 | ) | | (24,852 | ) |
| Restricted cash | | | (3,605 | ) | | 586 | | | 905 | |
| Cash proceeds from property sales | | | 936 | | | 24,291 | | | 1,315 | |
| Refundable cash received for customer construction projects | | | 12,253 | | | 9,869 | | | 13,424 | |
| Cash proceeds from sale of InfrastruX, net of cash disposed | | | 263,575 | | | -- | | | -- | |
| Other | | | 5,500 | | | 5,906 | | | 432 | |
| Net cash used by investing activities | | | (504,722 | ) | | (567,370 | ) | | (418,179 | ) |
| Financing activities: | | | | | | | | | | |
Change in short-term debt and leases - net | | | 290,224 | | | 36,512 | | | (5,596 | ) |
| Dividends paid | | | (104,332 | ) | | (88,071 | ) | | (86,873 | ) |
| Issuance of common stock | | | 5,878 | | | 317,607 | | | 5,413 | |
| Issuance of bonds and notes | | | 550,000 | | | 400,000 | | | 343,841 | |
| Net payments made to minority shareholders of InfrastruX | | | (10,451 | ) | | -- | | | -- | |
| InfrastruX debt redeemed | | | (141,221 | ) | | -- | | | -- | |
| Redemption of trust preferred stock | | | (200,000 | ) | | (42,500 | ) | | -- | |
| Redemption of bonds, notes and leases | | | (83,875 | ) | | (260,615 | ) | | (308,708 | ) |
| Settlement of derivatives | | | 20,682 | | | (35,323 | ) | | -- | |
| Issuance costs and other | | | (2,467 | ) | | (12,928 | ) | | 6,032 | |
| Net cash provided (used) by financing activities | | | 324,438 | | | 314,682 | | | (45,891 | ) |
| Increase (decrease) in cash from net income | | | 5,223 | | | 3,123 | | | (7,710 | ) |
| Cash at beginning of year | | | 22,894 | | | 19,771 | | | 27,481 | |
| Cash at end of year | | $ | 28,117 | | $ | 22,894 | | $ | 19,771 | |
Supplemental cash flow information: | | | | | | | | | | |
| Cash payments for: | | | | | | | | | | |
| Interest (net of debt AFUDC) | | $ | 167,789 | | $ | 182,054 | | $ | 182,419 | |
| Income taxes (net of refunds) | | | 129,100 | | | 126,807 | | | (1,232 | ) |
(Dollars in Thousands) For Years Ended December 31 | | 2009 | | | 2008 | | | 2007 | |
| Operating revenues: | | | | | | | | | |
| Electric | | $ | 2,098,736 | | | $ | 2,129,463 | | | $ | 1,997,829 | |
| Gas | | | 1,224,745 | | | | 1,216,868 | | | | 1,208,029 | |
| Other | | | 5,020 | | | | 11,442 | | | | 14,289 | |
| Total operating revenues | | | 3,328,501 | | | | 3,357,773 | | | | 3,220,147 | |
| Operating expenses: | | | | | | | | | | | | |
| Energy costs: | | | | | | | | | | | | |
| Purchased electricity | | | 887,306 | | | | 903,317 | | | | 895,592 | |
| Electric generation fuel | | | 208,444 | | | | 212,333 | | | | 143,406 | |
| Residential exchange | | | (96,504 | ) | | | (40,664 | ) | | | (52,439 | ) |
| Purchased gas | | | 718,860 | | | | 737,851 | | | | 762,112 | |
| Net unrealized (gain) loss on derivative instruments | | | (1,254 | ) | | | 7,538 | | | | (2,687 | ) |
| Utility operations and maintenance | | | 487,396 | | | | 461,632 | | | | 403,681 | |
| Non-utility expense and other | | | 14,532 | | | | 12,399 | | | | 12,429 | |
| Merger and related costs | | | 23,908 | | | | -- | | | | -- | |
| Depreciation and amortization | | | 332,852 | | | | 312,128 | | | | 279,222 | |
| Conservation amortization | | | 66,466 | | | | 61,650 | | | | 39,955 | |
| Taxes other than income taxes | | | 303,360 | | | | 297,203 | | | | 288,492 | |
| Total operating expenses | | | 2,945,366 | | | | 2,965,387 | | | | 2,769,763 | |
| Operating income | | | 383,135 | | | | 392,386 | | | | 450,384 | |
| Other income (deductions): | | | | | | | | | | | | |
| Other income | | | 52,812 | | | | 33,239 | | | | 28,938 | |
| Other expense | | | (6,524 | ) | | | (7,215 | ) | | | (7,509 | ) |
| Interest charges: | | | | | | | | | | | | |
| AFUDC | | | 9,215 | | | | 8,610 | | | | 12,614 | |
| Interest expense | | | (211,478 | ) | | | (202,588 | ) | | | (217,823 | ) |
| Interest expense on Puget Energy note | | | (264 | ) | | | (814 | ) | | | (1,296 | ) |
| Income before income taxes | | | 226,896 | | | | 223,618 | | | | 265,308 | |
| Income tax expense | | | 67,644 | | | | 60,882 | | | | 74,181 | |
| Net income | | $ | 159,252 | | | $ | 162,736 | | | $ | 191,127 | |
The accompanying notes are an integral part of the consolidated financial statements.
Puget Sound Energy Consolidated Statements ofBalance Sheets INCOMEASSETS
(Dollars in Thousands) For Years Ended December 31 | | 2006 | | 2005 | | 2004 | |
| Operating revenues: | | | | | | | |
| Electric | | $ | 1,777,745 | | $ | 1,612,869 | | $ | 1,423,034 | |
| Gas | | | 1,120,118 | | | 952,515 | | | 769,306 | |
| Other | | | 7,830 | | | 7,826 | | | 6,537 | |
| Total operating revenues | | | 2,905,693 | | | 2,573,210 | | | 2,198,877 | |
| Operating expenses: | | | | | | | | | | |
| Energy costs: | | | | | | | | | | |
| Purchased electricity | | | 917,801 | | | 860,422 | | | 723,567 | |
| Electric generation fuel | | | 97,320 | | | 73,318 | | | 80,772 | |
| Residential exchange | | | (163,622 | ) | | (180,491 | ) | | (174,473 | ) |
| Purchased gas | | | 723,232 | | | 592,120 | | | 451,302 | |
| Unrealized (gain) loss on derivative instruments | | | 71 | | | 472 | | | (526 | ) |
| Utility operations and maintenance | | | 354,590 | | | 333,256 | | | 291,232 | |
| Other operations and maintenance | | | 1,211 | | | 1,304 | | | 1,342 | |
| Depreciation and amortization | | | 262,341 | | | 241,634 | | | 228,566 | |
| Conservation amortization | | | 32,320 | | | 24,308 | | | 22,688 | |
| Taxes other than income taxes | | | 255,712 | | | 233,742 | | | 208,989 | |
| Income taxes | | | 97,227 | | | 89,629 | | | 77,177 | |
| Total operating expenses | | | 2,578,203 | | | 2,269,714 | | | 1,910,636 | |
| Operating income | | | 327,490 | | | 303,496 | | | 288,241 | |
| Other income (deductions): | | | | | | | | | | |
| Other income | | | 29,606 | | | 16,803 | | | 11,044 | |
| Other expense | | | (9,999 | ) | | (11,063 | ) | | (9,517 | ) |
| Income taxes | | | (1,462 | ) | | 2,569 | | | 2,835 | |
| Interest charges: | | | | | | | | | | |
| AFUDC | | | 15,874 | | | 9,493 | | | 5,420 | |
| Interest expense | | | (183,922 | ) | | (174,367 | ) | | (171,740 | ) |
| Interest expense on Puget Energy note | | | (845 | ) | | -- | | | -- | |
| Mandatorily redeemable securities interest expense | | | (91 | ) | | (91 | ) | | (91 | ) |
| Net income before cumulative effect of accounting change | | | 176,651 | | | 146,840 | | | 126,192 | |
| Cumulative effect of implementation of accounting change (net of tax) | | | 89 | | | (71 | ) | | -- | |
| Net income for common stock | | $ | 176,740 | | $ | 146,769 | | $ | 126,192 | |
(Dollars in Thousands) At December 31 | | 2009 | | | 2008 | |
| Utility plant: | | | | | | |
| Electric plant | | $ | 7,046,379 | | | $ | 6,596,359 | |
| Gas plant | | | 2,637,003 | | | | 2,500,236 | |
| Common plant | | | 539,296 | | | | 550,368 | |
| Less: Accumulated depreciation and amortization | | | (3,453,165 | ) | | | (3,358,816 | ) |
| Net utility plant | | | 6,769,513 | | | | 6,288,147 | |
| Other property and investments: | | | | | | | | |
| Investment in Bonneville Exchange Power contract | | | 26,450 | | | | 29,976 | |
| Other property and investments | | | 116,267 | | | | 118,039 | |
| Total other property and investments | | | 142,717 | | | | 148,015 | |
| Current assets: | | | | | | | | |
| Cash and cash equivalents | | | 78,407 | | | | 38,470 | |
| Restricted cash | | | 19,844 | | | | 18,889 | |
| Accounts receivable, net of allowance for doubtful accounts | | | 320,065 | | | | 207,776 | |
| Secured pledged accounts receivable | | | -- | | | | 158,000 | |
| Unbilled revenues | | | 208,948 | | | | 248,649 | |
| Materials and supplies, at average cost | | | 64,604 | | | | 62,024 | |
| Fuel and gas inventory, at average cost | | | 95,813 | | | | 120,205 | |
| Unrealized gain on derivative instruments | | | 14,948 | | | | 15,618 | |
| Income taxes | | | 99,948 | | | | 17,317 | |
| Prepaid expenses and other | | | 12,067 | | | | 14,420 | |
| Deferred income taxes | | | 38,781 | | | | 75,135 | |
| Total current assets | | | 953,425 | | | | 976,503 | |
| Other long-term and regulatory assets: | | | | | | | | |
| Regulatory asset for deferred income taxes | | | 89,303 | | | | 95,417 | |
| Regulatory asset for PURPA buyout costs | | | 78,162 | | | | 110,838 | |
| Power cost adjustment mechanism | | | 8,529 | | | | 3,126 | |
| Other regulatory assets | | | 665,272 | | | | 766,732 | |
| Unrealized gain on derivative instruments | | | 4,605 | | | | 6,712 | |
| Other | | | 105,045 | | | | 40,365 | |
| Total other long-term and regulatory assets | | | 950,916 | | | | 1,023,190 | |
| Total assets | | $ | 8,816,571 | | | $ | 8,435,855 | |
The accompanying notes are an integral part of the consolidated financial statements.
Puget Sound Energy Consolidated Balance Sheets CAPITALIZATION AND LIABILITIES
ASSETS
(Dollars in Thousands) At December 31 | | 2006 | | 2005 | |
| Utility plant: | | | | | |
| Electric plant | | $ | 5,334,368 | | $ | 4,802,363 | |
| Gas plant | | | 2,146,048 | | | 1,991,456 | |
| Common plant | | | 458,262 | | | 439,599 | |
| Less: Accumulated depreciation and amortization | | | (2,757,632 | ) | | (2,602,500 | ) |
| Net utility plant | | | 5,181,046 | | | 4,630,918 | |
| Other property and investments | | | 151,462 | | | 157,321 | |
| Current assets: | | | | | | | |
| Cash | | | 28,092 | | | 16,709 | |
| Restricted cash | | | 839 | | | 1,047 | |
| Accounts receivable, net of allowance for doubtful accounts | | | 253,613 | | | 299,938 | |
| Secured pledged accounts receivable | | | 110,000 | | | 41,000 | |
| Unbilled revenues | | | 202,492 | | | 160,207 | |
| Purchased gas adjustment receivable | | | 39,822 | | | 67,335 | |
| Materials and supplies, at average cost | | | 43,501 | | | 36,491 | |
| Fuel and gas inventory, at average cost | | | 115,752 | | | 91,058 | |
| Unrealized gain on derivative instruments | | | 16,826 | | | 75,037 | |
| Prepayments and other | | | 8,659 | | | 7,023 | |
| Deferred income taxes | | | 1,175 | | | -- | |
| Total current assets | | | 820,771 | | | 795,845 | |
| Other long-term assets: | | | | | | | |
| Regulatory asset for deferred income taxes | | | 115,304 | | | 129,693 | |
| Regulatory asset for PURPA buyout costs | | | 167,941 | | | 191,170 | |
| Unrealized gain on derivative instruments | | | 6,934 | | | 28,464 | |
| Power cost adjustment mechanism | | | 6,357 | | | 18,380 | |
| Other | | | 611,598 | | | 388,009 | |
| Total other long-term assets | | | 908,134 | | | 755,716 | |
| Total assets | | $ | 7,061,413 | | $ | 6,339,800 | |
(Dollars in Thousands) At December 31 | | 2009 | | | 2008 | |
| Capitalization: | | | | | | |
Common shareholders’ equity: | | | | | | |
Common stock ($10 stated value) - 150,000,000 shares authorized, 85,903,791 shares outstanding | | $ | -- | | | $ | 859,038 | |
| Common stock ($0.01 par value) – 150,000,000 shares authorized, 85,903,791 shares outstanding | | | 859 | | | | -- | |
| Additional paid-in capital | | | 2,959,205 | | | | 1,296,005 | |
| Earnings reinvested in the business | | | 333,128 | | | | 356,947 | |
| Accumulated other comprehensive income (loss) – net of tax | | | (210,120 | ) | | | (262,804 | ) |
| Total common shareholders’ equity | | | 3,083,072 | | | | 2,249,186 | |
| Redeemable securities and long-term debt: | | | | | | | | |
Preferred stock subject to mandatory redemption – cumulative - $100 par value: | | | | | | | | |
4.84% series - 150,000 shares authorized, 14,583 shares outstanding | | | -- | | | | 1,458 | |
4.70% series - 150,000 shares authorized, 4,311 shares outstanding | | | -- | | | | 431 | |
| Total preferred stock subject to mandatory redemption | | | -- | | | | 1,889 | |
| Long-term debt: | | | | | | | | |
| First mortgage bonds and senior notes | | | 2,709,000 | | | | 2,267,000 | |
| Pollution control revenue bonds: | | | | | | | | |
| Revenue refunding 2003 series, due 2031 | | | 161,860 | | | | 161,860 | |
| Junior subordinated notes | | | 250,000 | | | | 250,000 | |
| Long-term debt due within one year | | | (232,000 | ) | | | (158,000 | ) |
| Total redeemable securities and long-term debt | | | 2,888,860 | | | | 2,522,749 | |
| Total capitalization | | | 5,971,932 | | | | 4,771,935 | |
| Current liabilities: | | | | | | | | |
| Accounts payable | | | 321,287 | | | | 341,255 | |
| Short-term debt | | | 105,000 | | | | 964,700 | |
| Short-term note owed to Puget Energy | | | 22,898 | | | | 26,053 | |
| Current maturities of long-term debt | | | 232,000 | | | | 158,000 | |
| Accrued expenses: | | | | | | | | |
| Purchased gas liability | | | 49,587 | | | | 8,892 | |
| Taxes | | | 77,302 | | | | 85,068 | |
| Salaries and wages | | | 30,654 | | | | 35,280 | |
| Interest | | | 47,154 | | | | 36,112 | |
| Unrealized loss on derivative instruments | | | 137,530 | | | | 236,866 | |
| Other | | | 104,148 | | | | 117,223 | |
| Total current liabilities | | | 1,127,560 | | | | 2,009,449 | |
| Long-term liabilities and regulatory liabilities: | | | | | | | | |
| Deferred income taxes | | | 996,576 | | | | 816,136 | |
| Unrealized loss on derivative instruments | | | 89,717 | | | | 158,423 | |
| Regulatory liabilities | | | 250,586 | | | | 219,221 | |
| Other deferred credits | | | 380,200 | | | | 460,691 | |
| Total long-term liabilities and regulatory liabilities | | | 1,717,079 | | | | 1,654,471 | |
| Commitments and contingencies (Note 23) | | | | | | | | |
| Total capitalization and liabilities | | $ | 8,816,571 | | | $ | 8,435,855 | |
The accompanying notes are an integral part of the consolidated financial statements.
Puget Sound Energy Consolidated Balance SheetsStatement of CAPITALIZATION AND LIABILITIESCOMMON SHAREHOLDERS’ EQUITY
(Dollars in Thousands) At December 31 | | 2006 | | 2005 | |
| Capitalization: | | | | | |
(See Consolidated Statements of Capitalization): | | | | �� | |
| Common equity | | $ | 2,092,283 | | $ | 1,986,621 | |
| Total shareholder’s equity | | | 2,092,283 | | | 1,986,621 | |
| Redeemable securities and long-term debt: | | | | | | | |
| Preferred stock subject to mandatory redemption | | | 1,889 | | | 1,889 | |
| Junior subordinated debentures of the corporation payable to a subsidiary trust holding mandatorily redeemable preferred securities | | | 37,750 | | | 237,750 | |
| Long-term debt | | | 2,608,360 | | | 2,183,360 | |
| Total redeemable securities and long-term debt | | | 2,647,999 | | | 2,422,999 | |
| Total capitalization | | | 4,740,282 | | | 4,409,620 | |
| Current liabilities: | | | | | | | |
| Accounts payable | | | 379,494 | | | 346,490 | |
| Short-term debt | | | 328,055 | | | 41,000 | |
| Short-term debt owed to Puget Energy | | | 24,303 | | | -- | |
| Current maturities of long-term debt | | | 125,000 | | | 81,000 | |
| Accrued expenses: | | | | | | | |
| Taxes | | | 55,365 | | | 111,900 | |
| Salaries and wages | | | 31,591 | | | 15,034 | |
| Interest | | | 37,031 | | | 31,004 | |
| Unrealized loss on derivative instruments | | | 70,596 | | | 9,772 | |
| Deferred income taxes | | | -- | | | 10,968 | |
| Other | | | 43,889 | | | 30,932 | |
| Total current liabilities | | | 1,095,324 | | | 678,100 | |
| Long-term liabilities: | | | | | | | |
| Deferred income taxes | | | 749,033 | | | 739,162 | |
| Unrealized loss on derivative instruments | | | 415 | | | -- | |
| Other deferred credits | | | 476,359 | | | 512,918 | |
| Total long-term liabilities | | | 1,225,807 | | | 1,252,080 | |
| Commitments and contingencies (Note 22) | | | | | | | |
| Total capitalization and liabilities | | $ | 7,061,413 | | $ | 6,339,800 | |
(Dollars in Thousands) | | Common Stock | | | | | | | | | | | | | |
For Years Ended December 31, 2009, 2008 & 2007 | | Shares | | | Amount | | | Additional Paid-in Capital | | | Earnings Reinvested in the business | | | Accumulated Other Comprehensive Income (loss) | | | Total Amount | |
| Balance at December 31, 2006 | | | 85,903,791 | | | $ | 859,038 | | | $ | 996,737 | | | $ | 263,206 | | | $ | (26,698 | ) | | $ | 2,092,283 | |
| Net income | | | -- | | | | -- | | | | -- | | | | 191,127 | | | | -- | | | | 191,127 | |
| Common stock dividend declared | | | -- | | | | -- | | | | -- | | | | (108,434 | ) | | | -- | | | | (108,434 | ) |
| Investment received from parent | | | -- | | | | -- | | | | 300,339 | | | | -- | | | | -- | | | | 300,339 | |
| Other comprehensive income | | | -- | | | | -- | | | | -- | | | | -- | | | | 28,776 | | | | 28,776 | |
| Balance at December 13, 2007 | | | 85,903,791 | | | $ | 859,038 | | | $ | 1,297,076 | | | $ | 345,899 | | | $ | 2,078 | | | $ | 2,504,091 | |
| Net income | | | -- | | | | -- | | | | -- | | | | 162,736 | | | | -- | | | | 162,736 | |
| Common stock dividend declared | | | -- | | | | -- | | | | -- | | | | (145,840 | ) | | | -- | | | | (145,840 | ) |
| Adjustment to initially apply ASC 820, Fair Value Measurements | | | -- | | | | -- | | | | -- | | | | (5,848 | ) | | | -- | | | | (5,848 | ) |
| Investment returned to parent | | | -- | | | | -- | | | | (1,071 | ) | | | -- | | | | -- | | | | (1,071 | ) |
| Other comprehensive loss | | | -- | | | | -- | | | | -- | | | | -- | | | | (264,882 | ) | | | (264,882 | ) |
| Balance at December 31, 2008 | | | 85,903,791 | | | $ | 859,038 | | | $ | 1,296,005 | | | $ | 356,947 | | | $ | (262,804 | ) | | $ | 2,249,186 | |
| Change in par value | | | -- | | | | (858,179 | ) | | | 858,179 | | | | -- | | | | -- | | | | -- | |
| Net income | | | -- | | | | -- | | | | -- | | | | 159,252 | | | | -- | | | | 159,252 | |
| Common stock dividend declared | | | -- | | | | -- | | | | -- | | | | (183,071 | ) | | | -- | | | | (183,071 | ) |
| Investment from parent | | | -- | | | | -- | | | | 805,283 | | | | -- | | | | -- | | | | 805,283 | |
| Employee common stock award transferred to liability award | | | -- | | | | -- | | | | (690 | ) | | | -- | | | | -- | | | | (690 | ) |
| Employee stock plan tax windfall | | | -- | | | | -- | | | | 428 | | | | -- | | | | -- | | | | 428 | |
| Other comprehensive income | | | -- | | | | -- | | | | -- | | | | -- | | | | 52,684 | | | | 52,684 | |
| Balance at December 31, 2009 | | | 85,903,791 | | | $ | 859 | | | $ | 2,959,205 | | | $ | 333,128 | | | $ | (210,120 | ) | | $ | 3,083,072 | |
COMPREHENSIVE INCOME
(Dollars in Thousands) For Years Ended December 31 | | 2009 | | | 2008 | | | 2007 | |
| Net income | | $ | 159,252 | | | $ | 162,736 | | | $ | 191,127 | |
| Other comprehensive income (loss): | | | | | | | | | | | | |
| Net unrealized gain (loss) from pension and postretirement plans, net of tax of $12,819, $(80,769) and $16,083, respectively | | | 23,807 | | | | (149,999 | ) | | | 29,869 | |
| Net unrealized loss on energy derivative instruments during the period, net of tax of $(32,996), $(73,621) and $(6,776), respectively | | | (61,277 | ) | | | (136,725 | ) | | | (12,584 | ) |
| Reclassification of net unrealized loss on energy derivative instruments settled during the period, net of tax of $48,373, $11,590 and $6,017, respectively | | | 89,837 | | | | 21,525 | | | | 11,174 | |
| Amortization of financing cash flow hedge contracts to earnings, net of tax of $171, $171 and $171, respectively | | | 317 | | | | 317 | | | | 317 | |
| Other comprehensive income (loss) | | | 52,684 | | | | (264,882 | ) | | | 28,776 | |
| Comprehensive income (loss) | | $ | 211,936 | | | $ | (102,146 | ) | | $ | 219,903 | |
The accompanying notes are an integral part of the consolidated financial statements.
CAPITALIZATION
(Dollars in Thousands) At December 31 | | 2006 | | 2005 | |
| Common equity: | | | | | |
Common stock ($10 stated value) - 150,000,000 shares authorized, 85,903,791 shares outstanding | | $ | 859,038 | | $ | 859,038 | |
| Additional paid-in capital | | | 996,737 | | | 924,154 | |
| Earnings reinvested in the business | | | 263,206 | | | 196,248 | |
| Accumulated other comprehensive income (loss) - net of tax | | | (26,698 | ) | | 7,181 | |
| Total common equity | | | 2,092,283 | | | 1,986,621 | |
| Preferred stock subject to mandatory redemption - cumulative - $100 par value:* | | | | | | | |
4.84% series - 150,000 shares authorized, 14,583 shares outstanding at December 31, 2006 and 2005 | | | 1,458 | | | 1,458 | |
4.70% series - 150,000 shares authorized, 4,311 shares outstanding at December 31, 2006 and 2005 | | | 431 | | | 431 | |
| Total preferred stock subject to mandatory redemption | | | 1,889 | | | 1,889 | |
| Junior subordinated debentures of the corporation payable to a subsidiary trust holding mandatorily redeemable preferred securities | | | 37,750 | | | 237,750 | |
| Long-term debt: | | | | | | | |
| First mortgage bonds and senior notes | | | 2,571,500 | | | 2,102,500 | |
| Pollution control revenue bonds: | | | | | | | |
| Revenue refunding 2003 series, due 2031 | | | 161,860 | | | 161,860 | |
| Long-term debt due within one year | | | (125,000 | ) | | (81,000 | ) |
| Total long-term debt excluding current maturities | | | 2,608,360 | | | 2,183,360 | |
| Total capitalization | | $ | 4,740,282 | | $ | 4,409,620 | |
*13,000,000 shares authorized for $25 par value preferred stock and 3,000,000 shares authorized for $100 par value preferred stock, both of which are available for issuance under mandatory and non-mandatory redemption provisions.
The accompanying notes are an integral part of the consolidated financial statements.
Puget Sound Energy Consolidated Statements ofCOMMON SHAREHOLDER’S EQUITY
| (Dollars in Thousands) | | Common Stock | | Additional | | | | | | | |
For Years Ended December 31, 2006, 2005 & 2004 | | Shares | | Amount | | Paid-in Capital | | Retained Earnings | | Income | | Total Amount | |
| Balance at December 31, 2003 | | | 85,903,791 | | $ | 859,038 | | $ | 604,451 | | $ | 100,186 | | $ | (8,206 | ) | $ | 1,555,469 | |
| Net income | | | -- | | | -- | | | -- | | | 126,192 | | | -- | | | 126,192 | |
| Common stock dividend declared | | | -- | | | -- | | | -- | | | (87,700 | ) | | -- | | | (87,700 | ) |
| Investment received from Puget Energy | | | -- | | | -- | | | 5,016 | | | -- | | | -- | | | 5,016 | |
| Other comprehensive loss | | | -- | | | -- | | | -- | | | -- | | | (6,544 | ) | | (6,544 | ) |
| Balance at December 31, 2004 | | | 85,903,791 | | $ | 859,038 | | $ | 609,467 | | $ | 138,678 | | $ | (14,750 | ) | $ | 1,592,433 | |
| Net income | | | -- | | | -- | | | -- | | | 146,769 | | | -- | | | 146,769 | |
| Common stock dividend declared | | | -- | | | -- | | | -- | | | (89,199 | ) | | -- | | | (89,199 | ) |
| Investment received from Puget Energy | | | -- | | | -- | | | 314,687 | | | -- | | | -- | | | 314,687 | |
| Other comprehensive loss | | | -- | | | -- | | | -- | | | -- | | | 21,931 | | | 21,931 | |
| Balance at December 31, 2005 | | | 85,903,791 | | $ | 859,038 | | $ | 924,154 | | $ | 196,248 | | $ | 7,181 | | $ | 1,986,621 | |
| Net income | | | -- | | | -- | | | -- | | | 176,740 | | | -- | | | 176,740 | |
| Common stock dividend declared | | | -- | | | -- | | | -- | | | (109,782 | ) | | -- | | | (109,782 | ) |
| Investment received from Puget Energy | | | -- | | | -- | | | 72,583 | | | -- | | | -- | | | 72,583 | |
| Other comprehensive income | | | -- | | | -- | | | -- | | | -- | | | (15,226 | ) | | (15,226 | ) |
| Adjustment to initially apply SFAS No. 158, net of tax of $(12,420) | | | -- | | | -- | | | -- | | | -- | | | (18,653 | ) | | (18,653 | ) |
| Balance at December 31, 2006 | | | 85,903,791 | | $ | 859,038 | | $ | 996,737 | | $ | 263,206 | | $ | (26,698 | ) | $ | 2,092,283 | |
The accompanying notes are an integral part of the consolidated financial statements.
Puget Sound Energy Consolidated Statements ofCOMPREHENSIVE INCOME
(Dollars in Thousands) For Years Ended December 31 | | 2006 | | 2005 | | 2004 | |
| Net income | | $ | 176,740 | | $ | 146,769 | | $ | 126,192 | |
| Other comprehensive income (loss): | | | | | | | | | | |
| Minimum pension liability adjustment, net of tax of $2,376, $0 and $0, respectively | | | 2,873 | | | 925 | | | 157 | |
| Net unrealized gains (losses) on energy derivative instruments during the period, net of tax of $(17,669), $26,799, and $3,672, respectively | | | (32,813 | ) | | 49,770 | | | 6,820 | |
| Reversal of net unrealized (gains) losses on energy derivative instruments settled during the period, net of tax of $(2,972), $(10,319) and $(5,610), respectively | | | (5,519 | ) | | (19,164 | ) | | (10,418 | ) |
| Gain (loss) from settlement of financing cash flow hedge contracts, net of tax of $7,239, $(12,363) and $0, respectively | | | 13,443 | | | (22,960 | ) | | -- | |
| Amortization of financing cash flow hedge contracts to earnings, net of tax of $289, $245 and $0, respectively | | | 537 | | | 455 | | | -- | |
| Deferral of energy cash flow hedges related to power cost adjustment mechanism, net of tax of $3,367, $6,949 and $(1,671), respectively | | | 6,253 | | | 12,905 | | | (3,103 | ) |
| Other comprehensive income (loss) | | | (15,226 | ) | | 21,931 | | | (6,544 | ) |
| Comprehensive income | | $ | 161,514 | | $ | 168,700 | | $ | 119,648 | |
The accompanying notes are an integral part of the consolidated financial statements.
Puget Sound Energy Consolidated Statements ofCASH FLOWS
(Dollars in Thousands) For Years Ended December 31 | | 2006 | | 2005 | | 2004 | | | 2009 | | | 2008 | | | 2007 | |
| Operating activities: | | | | | | | | | | | | | | | | |
| Net income | | $ | 176,740 | | $ | 146,769 | | $ | 126,192 | | | $ | 159,252 | | | $ | 162,736 | | | $ | 191,127 | |
| Adjustments to reconcile net income to net cash provided by operating activities: | | | | | | | | | | | | | | | | | | | | | | |
| Depreciation and amortization | | | 262,341 | | | 241,634 | | | 228,566 | | | | 332,852 | | | | 312,128 | | | | 279,222 | |
Deferred federal income taxes and tax credits - net | | | 34,283 | | | (57,597 | ) | | 72,446 | | |
| Conservation amortization | | | | 66,466 | | | | 61,650 | | | | 39,955 | |
| Deferred income taxes and tax credits, net | | | | 194,494 | | | | 78,050 | | | | 66,102 | |
| Power cost adjustment mechanism | | | 12,023 | | | (18,380 | ) | | 3,605 | | | | -- | | | | (12 | ) | | | 3,243 | |
| Amortization of gas pipeline capacity assignment | | | (10,632 | ) | | -- | | | -- | | | | (9,410 | ) | | | (9,346 | ) | | | (10,943 | ) |
| Non cash return on regulatory assets | | | (12,438 | ) | | -- | | | -- | | | | (9,586 | ) | | | (9,860 | ) | | | (10,194 | ) |
| Net unrealized (gain) loss on derivative instruments | | | 71 | | | 472 | | | (526 | ) | |
| Other (including conservation amortization) | | | 17,335 | | | (4,803 | ) | | 18,869 | | |
| Cash collateral received from (returned to) energy suppliers | | | (22,020 | ) | | 15,700 | | | 6,320 | | |
| Gas pipeline capacity assignment | | | -- | | | 55,000 | | | -- | | |
| BPA prepaid transmission | | | -- | | | (10,750 | ) | | -- | | |
| Chelan PUD contract initiation | | | (89,000 | ) | | -- | | | -- | | |
| Net unrealized loss (gain) on derivative instruments | | | | (1,254 | ) | | | 7,538 | | | | (2,687 | ) |
| Deferred regulatory costs for generation facilities | | | | (21,812 | ) | | | (288 | ) | | | (11,505 | ) |
| Pension funding | | | | (18,400 | ) | | | (24,900 | ) | | | -- | |
| Change in residential exchange program | | | | (740 | ) | | | 37,811 | | | | (28,133 | ) |
| Cash receipt from lease purchase option settlement | | | | -- | | | | -- | | | | 18,859 | |
| Storm damage deferred costs | | | (92,331 | ) | | -- | | | -- | | | | -- | | | | -- | | | | (29,274 | ) |
| Change in certain current assets and current liabilities: | | | | | | | | | | | |
| Other | | | | 17,117 | | | | 13,634 | | | | 17,252 | |
| Change in certain current assets and liabilities: | | | | | | | | | | | | | |
| Accounts receivable and unbilled revenue | | | (64,961 | ) | | (221,960 | ) | | 8,264 | | | | 64,349 | | | | (33,055 | ) | | | (5,215 | ) |
| Materials and supplies | | | (7,010 | ) | | (4,808 | ) | | (37,884 | ) | | | (2,580 | ) | | | 89 | | | | (18,613 | ) |
| Fuel and gas inventory | | | (24,694 | ) | | (25,163 | ) | | 17,512 | | | | 24,391 | | | | (20,433 | ) | | | 15,981 | |
| Income taxes | | | | (82,630 | ) | | | 24,497 | | | | (41,814 | ) |
| Prepayments and other | | | (1,636 | ) | | (776 | ) | | 38 | | | | 2,353 | | | | (3,055 | ) | | | (2,706 | ) |
| Purchased gas receivable / liability | | | 27,513 | | | (48,246 | ) | | (31,073 | ) | |
| Purchased gas receivable / payable | | | | 40,695 | | | | (68,972 | ) | | | 117,685 | |
| Accounts payable | | | 33,004 | | | 116,743 | | | 23,282 | | | | (35,205 | ) | | | 20,735 | | | | (52,908 | ) |
| Taxes payable | | | (56,535 | ) | | 30,265 | | | (707 | ) | | | (7,339 | ) | | | 313 | | | | 29,391 | |
| Tenaska disallowance reserve | | | -- | | | (3,156 | ) | | 3,156 | | |
| Accrued expenses and other | | | 30,588 | | | (2,201 | ) | | (2,664 | ) | | | 7,678 | | | | (2,840 | ) | | | 8,164 | |
| Net cash provided by operating activities | | | 212,641 | | | 208,743 | | | 435,396 | | | | 720,691 | | | | 546,420 | | | | 572,989 | |
| Investing activities: | | | | | | | | | | | | | | | | | | | | | | |
Construction expenditures - excluding equity AFUDC | | | (745,239 | ) | | (568,381 | ) | | (393,891 | ) | | | (775,688 | ) | | | (846,001 | ) | | | (737,258 | ) |
| Energy efficiency expenditures | | | (33,865 | ) | | (24,428 | ) | | (24,852 | ) | | | (87,176 | ) | | | (66,126 | ) | | | (43,398 | ) |
| Restricted cash | | | 208 | | | 586 | | | 905 | | | | (955 | ) | | | (18,090 | ) | | | 495 | |
| Cash received from property sales | | | 936 | | | 24,291 | | | 1,315 | | | | 28,175 | | | | 2,248 | | | | 6,468 | |
| Refundable cash received for customer construction projects | | | 12,253 | | | 9,869 | | | 13,424 | | |
| Other | | | 5,500 | | | 6,006 | | | 129 | | | | (926 | ) | | | (7,880 | ) | | | 16,875 | |
| Net cash used by investing activities | | | (760,207 | ) | | (552,057 | ) | | (402,970 | ) | |
| Net cash used in investing activities | | | | (836,570 | ) | | | (935,849 | ) | | | (756,818 | ) |
| Financing activities: | | | | | | | | | | | | | | | | | | | | | | |
Decrease in short-term debt - net | | | 287,055 | | | 41,000 | | | -- | | |
| Change in short-term debt and leases, net | | | | (113,286 | ) | | | 704,214 | | | | (67,569 | ) |
| Dividends paid | | | (109,782 | ) | | (89,199 | ) | | (87,700 | ) | | | (183,071 | ) | | | (145,840 | ) | | | (108,434 | ) |
| Issuance of bonds and notes | | | 550,000 | | | 400,000 | | | 200,000 | | | | 600,000 | | | | -- | | | | 250,000 | |
| Loan from Puget Energy | | | 24,303 | | | -- | | | -- | | |
| Redemption of trust preferred stock | | | (200,000 | ) | | (42,500 | ) | | -- | | |
| Loan from (payment to) Puget Energy | | | | (3,156 | ) | | | 10,287 | | | | (8,537 | ) |
| Redemption of preferred stock | | | | (1,889 | ) | | | -- | | | | (37,750 | ) |
| Redemption of bonds and notes | | | (81,000 | ) | | (231,000 | ) | | (157,658 | ) | | | (158,000 | ) | | | (179,500 | ) | | | (125,000 | ) |
| Settlement of derivatives | | | 20,682 | | | (35,323 | ) | | -- | | |
| Investment from Puget Energy | | | 70,114 | | | 314,687 | | | 5,016 | | |
| Issuance costs and other | | | (2,423 | ) | | (10,597 | ) | | 6,093 | | |
| Net cash provided (used) by financing activities | | | 558,949 | | | 347,068 | | | (34,249 | ) | |
| Increase (decrease) in cash from net income | | | 11,383 | | | 3,754 | | | (1,823 | ) | |
| Cash at beginning of year | | | 16,709 | | | 12,955 | | | 14,778 | | |
| Cash at end of year | | $ | 28,092 | | $ | 16,709 | | $ | 12,955 | | |
Supplemental cash flow information: | | | | | | | | | | | |
| Cash payments for: | | | | | | | | | | | |
| Interest (net of debt AFUDC) | | $ | 164,389 | | $ | 172,986 | | $ | 175,772 | | |
| Income taxes (net of refunds) | | | 123,100 | | | 126,591 | | | (1,042 | ) | |
| Investment from parent | | | | 25,960 | | | | -- | | | | 297,073 | |
| Issuance cost of bonds and other | | | | (10,742 | ) | | | (2,035 | ) | | | (3,273 | ) |
| Net cash provided by financing activities | | | | 155,816 | | | | 387,126 | | | | 196,510 | |
| Net increase (decrease) in cash and cash equivalents | | | | 39,937 | | | | (2,303 | ) | | | 12,681 | |
| Cash and cash equivalents at beginning of year | | | | 38,470 | | | | 40,773 | | | | 28,092 | |
| Cash and cash equivalents at end of year | | | $ | 78,407 | | | $ | 38,470 | | | $ | 40,773 | |
Supplemental cash flow information: | | | | | | | | | | | | | |
| Cash payments for interest (net of capitalized interest) | | | $ | 183,652 | | | $ | 204,837 | | | $ | 196,180 | |
| Cash payments (refunded) for income taxes | | | | (44,365 | ) | | | (40,034 | ) | | | 26,897 | |
The accompanying notes are an integral part of the consolidated financial statements.
To Consolidated Financial Statements of Puget Energy and Puget Sound Energy
NOTE 1. 1. Summary of Significant Accounting Policies
Basis of Presentation
Puget Energy, Inc. (Puget Energy) is aan energy services holding company that owns Puget Sound Energy, (PSE) and until May 7, 2006, a 90.9% interest in InfrastruX Group, Inc. (InfrastruX)(PSE). PSE is a public utility incorporated in the Statestate of Washington that furnishes electric and natural gas services in a territory covering 6,000 square miles, primarily in the Puget Sound region. On February 6, 2009, Puget Holdings LLC (Puget Holdings), a consortium of long-term infrastructure investors, completed its merger with Puget Energy. As a result of the merger, Puget Energy is a direct wholly owned subsidiary of Puget Equico LLC (Puget Equico), which is an indirect wholly owned subsidiary of Puget Holdings. Puget Energy’s basis of accounting incorporates the application of Financial Accounting Standards Board (FASB) Accounting Standards Codification (ASC) 805, “Business Combinations” (ASC 805) as of the date of the merger. ASC 805 requires the acquirer to recognize and measure identifiable assets acquired and liabilities assumed at fair value as of the merger date. Puget Energy consolidated financial statements and accompanying footnotes have been segregated to present pre-merger activity as the “Predecessor” Company and post-merger activity as the “Successor” Company.
The 2009 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 owned a 90.9% interest in InfrastruX until it was sold on May 7, 2006. 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.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 reclassifiedPSE’s basis of accounting will continue to conform with current year presentations with no effectbe on total equity or net income.a historical basis and PSE’s financial statements do not include any ASC 805 purchase accounting adjustments.
The preparation of financial statements in conformity with generally accepted accounting principles (GAAP) requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities, disclosure of contingent assets and liabilities at the date of the financial statements, and the reported amounts of revenues and expenses during the reporting period. Actual results could differ from those estimates.
Certain reclassifications have been made to prior fiscal year amounts or balances to conform to the presentation adopted in the current fiscal year.
Utility Plant
TheFor PSE, the cost of additions to utility plant, including renewals and betterments, are capitalized at original cost. Costs include indirect costs such as engineering, supervision, certain taxes, pension and other employee benefits and an allowance for funds used during construction. Replacements of minor items of property and major maintenance are included in maintenance expense. The original cost of operating property is charged to accumulated depreciation and costs associated with removal of property, less salvage, are charged to the cost of removal regulatory liability when the property is retired and removed from service.
For Puget Energy, the carrying amount of utility plant was remeasured to fair value on February 6, 2009, as a result of purchase accounting adjustments. After February 6, 2009, utility plant additions are capitalized at original cost.
Non-Utility Property, Plant and Equipment
TheFor PSE, the costs of other property, plant and equipment are stated at historical cost. Expenditures for refurbishment and improvements that significantly add to productive capacity or extend useful life of an asset are capitalized. Replacement of minor items is expensed on a current basis. Gains and losses on assets sold or retired are reflected in earnings.
Accounting forFor Puget Energy, the Impairmentcarrying amount of Long-Lived Assets
The Company evaluates impairmentnon-utility property, plant and equipment was remeasured to fair value on February 6, 2009, as a result of long-lived assets in accordance with Statement of Financial Accounting Standards (SFAS) No. 144, “Accounting for the Impairment or Disposal of Long-Lived Assets.” SFAS No. 144 establishespurchase accounting standards for determining if long-lived assets, including assets to be disposed of,adjustments. After February 6, 2009, non-utility property, plant and equipment are impaired and how losses, if any, should be recognized. The Company believes that the present value of the estimated future cash inflows from the use and eventual disposition of long-lived assets is sufficient to recover their carrying values.capitalized at original costs.
Depreciation and Amortization
For financial statement purposes, the Company provides for depreciation and amortization on a straight-line basis. Amortization is comprised of intangibles such as computer software small tools and office equipment.franchises. The depreciation of automobiles, trucks, power-operated equipment, tools and toolsoffice equipment is allocated to asset and expense accounts based on usage. The annual depreciation provision stated as a percent of average original cost ofa depreciable electric utility plant was 2.6%, 2.8% and 2.9% in 2006, 20052009, 2008 and 2004;2007, respectively; depreciable gas utility plant was 3.3% in 20063.6%, 3.4% and 3.4% in both 20052009, 2008 and 2004;2007, respectively; and depreciable common utility plant was 9.6%, 5.8% and 5.1% in 2006, 4.8% in 20052009, 2008 and 4.6 % in 2004.2007, respectively. Depreciation on other property, plant and equipment is calculated primarily on a straight-line basis over the useful lives of the assets. The cost of removal is collected from PSE’s customers through depreciation expense and any excess is recorded as a regulatory liability.
CashGoodwill
AllOn February 6, 2009, Puget Holdings completed its merger with Puget Energy. Puget Energy remeasured the carrying amount of all its assets and liabilities to fair value, which resulted in recognition of approximately $1.7 billion in goodwill. ASC 350, “Intangibles- Goodwill and Other,” (ASC 350) requires that goodwill be tested for impairment at the reporting unit level on an annual basis and between annual tests if an event occurs or circumstances change that would more likely than not reduce the fair value of a reporting unit below its carrying value. These events or circumstances could include a significant change in the business climate, legal factors, operating performance indicators, competition or sale or disposition of a significant portion of a reporting unit. Application of the goodwill impairment test requires judgment, including the identification of reporting unit, assignment of assets and liabilities to reporting unit, assignment of goodwill to reporting unit, and determination of the fair value of the reporting unit.
The goodwill represents the potential long-term return of Puget Energy to their investors. Goodwill is tested for impairment annually using a two-step process. The first step compares the carrying amount of the reporting unit with its fair value, with a carrying value higher than fair value indicating potential impairment. If the first step test fails, the second step is performed. This entails a full valuation of Puget Energy’s assets and liabilities and comparing the valuation to the carrying amount, with the difference indicating the amount of impairment. Goodwill of a reporting unit will be tested for impairment on an interim basis if an event occurs or circumstances change that would cause the fair value of a reporting unit to fall below its carrying amount.
Puget Energy conducted its annual impairment tests as of October 1, 2009. The fair value of Puget Energy’s reporting unit is estimated using both discounted cash flow and market approach. Such approaches are considered methodology that market participants would use. This analysis requires significant judgments, including estimation of future cash flows, which is dependent on internal forecasts, estimation of the long-term rate of growth for Puget Energy business, estimation of the useful life over which cash flows will occur and determination of our weighted average cost of capital. The market approach estimates the fair value of the business based on market prices of stocks of companies engaged in the same or similar lines of business. In addition, indications of market value are estimated by deriving multiples of equity or invested capital to various measures of revenue, earnings or cash flow. Changes in these estimates and or assumptions could materially affect the determination of fair value and goodwill impairment of the reporting unit. Based on the test performed, Management has determined that there is no impairment as of October 1, 2009. There were no events or circumstances from the date of the assessment through December 31, 2009 that would impact management’s conclusion.
Cash and Cash Equivalents
Cash and cash equivalents consist of demand bank deposits and short-term highly liquid investments with original maturities of three months or less at the datetime of purchasepurchase. Cash equivalents are considered cash. The Company maintains cash deposits in excessreported at cost, which approximates fair value, and were $44.3 million and $26.1 million as of insured limits with certain financial institutions.December 31, 2009 and 2008, respectively.
Restricted Cash
Restricted cash represents cash to be used for specific purposes. The restricted cash balance was $0.8$19.8 million and $1.0$18.9 million at December 31, 20062009 and 2005, respectively,2008, respectively. The restricted cash balance in both 2009 and 2008 includes $0.8 million which represents funds held by Puget Western, Inc., a PSE subsidiary, for a real estate development project. The long-termAs of December 31, 2009, other restricted cash balance was $3.8includes $13.5 million which represents management’s estimateat Bonneville Power Administration (BPA), $3.2 million in a Benefit Protection Trust, $2.1 million PSE received for the benefit of low-income customers from the aggregate fair value of the amount potentially payable under certain representationsEnron settlement and warranties made by InfrastruX concerning its business.$0.2 million in other restricted cash accounts.
MaterialMaterials and Supplies
MaterialMaterials and supplies consists primarily of materials and supplies used in the operation and maintenance of electric and natural gas distribution and transmission systems as well as spare parts for combustion turbines used for the generation of electricity. TheseFor PSE, these items are recorded at lowerweighted-average cost method.
For Puget Energy, the carrying amount of cost or marketmaterials and supplies was remeasured to fair value using the weighted averageon February 6, 2009, as a result of purchase accounting adjustments. Additionally, materials and supplies included emission allowances, renewable energy credits and carbon financials instruments. After February 6, 2009, additional items are recorded at weighted-average cost method.
Fuel and Gas Inventory
Fuel and gas inventory is used in the generation of electricity and for future sales to the Company’s natural gas customers. Fuel inventory consists of coal, diesel and natural gas used for generation. Gas inventory consists of natural gas and liquefied natural gas (LNG) held in storage for future sales. TheseFor PSE, these items are recorded at the lower of cost or market value using the weighted averageweighted-average cost method.
For Puget Energy, the carrying amount of fuel and gas inventory was remeasured to fair value on February 6, 2009, as a result of purchase accounting adjustments. After February 6, 2009, additional inventory are recorded at the lower of cost or market value using the weighted-average cost method.
Regulatory Assets and Liabilities
The CompanyPSE accounts for its regulated operations in accordance with SFAS No. 71, “Accounting for the Effects of Certain Types of Regulation.” SFAS No. 71ASC 980 “Regulated Operations” (ASC 980). ASC 980 requires the CompanyPSE to defer certain costs that would otherwise be charged to expense, if it were probable that future rates will permit recovery of such costs. Accounting under SFAS No. 71ASC 980 is appropriate as long as rates are established by or subject to approval by independent third-party regulators; rates are designed to recover the specific enterprise’s cost of service; and in view of demand for service, it is reasonable to assume that rates set at levels that will recover costs can be charged to and collected from customers. In most cases, the CompanyPSE classifies regulatory assets and liabilities as long-term assets or liabilities. The exception is the purchased gas adjustment receivablePurchased Gas Adjustment (PGA) payable which is a current asset.liability.
The CompanyPSE was allowed a return on the net regulatory assets and liabilities of 8.75%8.4%, or 7.01% after-tax, for electric rates beginning July 1, 2002 and gas rates beginning September 1, 2002 through March 3, 2005. Effectivethe period March 4, 2005 through January 12, 2007. Effective January 13, 2007, based on the 20042006 general rate case, the CompanyPSE is allowed a return on the net regulatory assets and liabilities of 8.4%, or 7.06% after-tax, for both electric and gas rates. after tax. Effective November 1, 2008, PSE was allowed 8.25%, or 7.00% after tax.
The net regulatory assets and liabilities at December 31, 20062009 and 20052008 included the following:
(Dollars in Millions) | | Remaining Amortization Period | | 2006 | | 2005 | |
| PURPA electric energy supply contract buyout costs | | | 1.5 to 5 years | | $ | 167.9 | | $ | 191.2 | |
| Deferred income taxes | | | * | | | 115.3 | | | 129.7 | |
Storm damage costs - electric | | | ** | | | 101.1 | | | 15.0 | |
| Chelan PUD contract initiation | | | *** | | | 95.5 | | | -- | |
| White River relicensing and other costs | | | **** | | | 69.1 | | | 66.1 | |
| PGA deferral of unrealized (gain) losses on derivative instruments | | | * | | | 54.8 | | | (25.7 | ) |
| Purchased gas adjustment (PGA) receivable | | | * | | | 39.8 | | | 67.3 | |
| Investment in Bonneville Exchange Power contract | | | 10 years | | | 37.0 | | | 40.6 | |
| Environmental remediation | | | **** | | | 36.3 | | | 34.2 | |
| Deferred AFUDC | | | 30 years | | | 33.3 | | | 32.0 | |
| Tree watch costs | | | 8.3 years | | | 19.8 | | | 24.2 | |
| Colstrip common property | | | 17 years | | | 12.5 | | | 13.2 | |
| Hopkins Ridge prepaid transmission upgrade | | | ***** | | | 8.9 | | | 10.8 | |
| Power cost adjustment (PCA) mechanism | | | * | | | 6.4 | | | 18.4 | |
| Carrying costs on income tax payments | | | * | | | 6.2 | | | -- | |
| Various other regulatory assets | | | 1 to 25 years | | | 34.6 | | | 31.6 | |
Total Regulatory Assets | | | | | $ | 838.5 | | $ | 648.6 | |
| Cost of removal | | | ****** | | $ | (127.1 | ) | $ | (125.3 | ) |
| Deferred credit gas pipeline capacity | | | 10.8 years | | | (44.4 | ) | | (55.0 | ) |
| Deferred gains on property sales | | | 3 years | | | (11.1 | ) | | (11.4 | ) |
| Gas supply contract settlement | | | 1.5 years | | | (5.7 | ) | | (9.5 | ) |
| PCA deferral of unrealized gain on derivative instruments | | | * | | | -- | | | (11.1 | ) |
| Various other regulatory liabilities | | | 1 to 21 years | | | (3.3 | ) | | (3.9 | ) |
Total Regulatory Liabilities | | | | | $ | (191.6 | ) | $ | (216.2 | ) |
| Net regulatory assets and liabilities | | | | | $ | 646.9 | | $ | 432.4 | |
Puget Sound Energy (Dollars in Millions) | | Remaining Amortization Period | | | 2009 | | | 2008 | |
Chelan PUD contract initiation 1 | | Varies | | | $ | 124.4 | | | $ | 114.8 | |
| Storm damage costs electric | | 3 to 9 years | | | | 105.7 | | | | 120.1 | |
Deferred income taxes 1 | | Varies | | | | 89.3 | | | | 95.4 | |
| PURPA electric energy supply contract buyout costs | | 2 years | | | | 78.1 | | | | 110.8 | |
| Baker Dam licensing operating and maintenance costs | | 50 years | | | | 70.0 | | | | 73.9 | |
PGA deferral of unrealized losses on derivative instruments 1 | | Varies | | | | 67.1 | | | | 187.2 | |
Environmental remediation 1 | | Varies | | | | 59.0 | | | | 54.5 | |
| Deferred Washington Commission allowance for funds used during construction (AFUDC) | | 27.3 years | | | | 51.8 | | | | 42.8 | |
Energy conservation costs 1 | | Varies | | | | 41.7 | | | | 17.5 | |
White River relicensing and other costs 1 | | Varies | | | | 34.2 | | | | 71.0 | |
| Investment in Bonneville Exchange power contract | | 7.5 years | | | | 26.5 | | | | 30.0 | |
California ISO/PX Receivable 3 | | Varies | | | | 21.1 | | | | -- | |
Mint Farm ownership and operating costs 1 | | Varies | | | | 20.8 | | | | 3.0 | |
| Unamortized loss on reacquired debt | | 2 to 26.5 years | | | | 19.5 | | | | 20.8 | |
| Various other regulatory assets | | Varies | | | | 15.8 | | | | 17.7 | |
| Colstrip common property | | 14.5 years | | | | 10.3 | | | | 11.1 | |
Snoqualmie licensing operating and maintenance costs 1 | | Varies | | | | 9.0 | | | | 9.6 | |
Power cost adjustment (PCA) mechanism 1 | | Varies | | | | 8.5 | | | | 3.1 | |
| Goldendale ownership and operating costs | | 2 years | | | | 7.6 | | | | 11.8 | |
| Tree watch costs | | 5.3 years | | | | 7.4 | | | | 11.0 | |
| Total PSE regulatory assets | | | | | $ | 867.8 | | | $ | 1,006.1 | |
Cost of removal 2 | | Varies | | | $ | (173.4 | ) | | $ | (156.7 | ) |
Purchased gas adjustment (PGA) payable 1 | | Varies | | | | (49.6 | ) | | | (8.9 | ) |
Renewable energy credits 1 | | Varies | | | | (34.7 | ) | | | (5.8 | ) |
| Summit purchase option buy-out | | 11 years | | | | (17.0 | ) | | | (18.6 | ) |
| Deferred credit on gas pipeline capacity | | 1 to 7.5 years | | | | (14.7 | ) | | | (24.1 | ) |
| Deferred gains on property sales | | Less than 1 year | | | | (8.7 | ) | | | (11.9 | ) |
Various other regulatory liabilities | | Less than 1 year to 7.5 years | | | | (2.1 | ) | | | (2.1 | ) |
| Total PSE regulatory liabilities | | | | | $ | (300.2 | ) | | $ | (228.1 | ) |
| PSE net regulatory assets and liabilities | | | | | $ | 567.6 | | | $ | 778.0 | |
| | | | | | | | | | | | |
Puget Energy (Dollars in Millions) | | Remaining Amortization Period | | | Successor 3 2009 | | | Predecessor 2008 | |
| Total PSE regulatory assets | | | N/A | | | $ | 867.8 | | | $ | 1,006.1 | |
| Puget Energy acquisition adjustments: | | | | | | | | | | | | |
| Regulatory assets related to power contracts | | 1 year to 28 years | | | | 210.3 | | | | -- | |
| Service provider contracts | | 2 to 4 years | | | | 29.6 | | | | -- | |
| Various other regulatory assets | | Varies | | | | 57.2 | | | | -- | |
| Total Puget Energy regulatory assets | | | | | | $ | 1,164.9 | | | $ | 1,006.1 | |
| | | | | | | | | | | | | |
| Total PSE regulatory liabilities | | | N/A | | | $ | (300.2 | ) | | $ | (228.1 | ) |
| Puget Energy acquisition adjustments: | | | | | | | | | | | | |
| Regulatory liabilities related to power contracts | | 2 to 43 years | | | | (1,034.2 | ) | | | -- | |
Various other regulatory liabilities 1 | | Varies | | | | (11.4 | ) | | | -- | |
| Total Puget Energy regulatory liabilities | | | | | | $ | (1,345.8 | ) | | $ | (228.1 | ) |
| Puget Energy net regulatory asset and liabilities | | | | | | $ | (180.9 | ) | | $ | 778.0 | |
_______________*1 | Amortization period varies depending on timing of underlying transactions. |
** | Amortization period for storm costs deferred in 2006 to be determinedtransactions, or awaiting regulatory approval in a future Washington Commission rate proceeding.
|
***2 | Amortization period will start in 2011 for a 20 year period.
|
**** | Amortization period to be determined in a future Washington Commission rate proceeding.
|
***** | Amortization varies and based upon BPA tariff rate and FERC interest rate.
|
****** | The balance is dependent upon the cost of removal of underlying assets and the life of utility plant. |
| 3 | Puget Energy’s regulatory assets and liabilities include purchase accounting adjustments as a result of the merger. See Note 3. |
If the Company, at some point in the future, determines that all or a portion of the utility operations no longer meets the criteria for continued application of SFAS No. 71,ASC 980, the Company would be required to adopt the provisions of SFAS No. 101, “Regulated Enterprises - Accounting for the Discontinuation of Application of Financial Accounting Standards Board (FASB) Statement No. 71.” Adoption of SFAS No. 101 would require the Company to write off the regulatory assets and liabilities related to those operations not meeting SFAS No. 71ASC 980 requirements. Discontinuation of SFAS No. 71ASC 980 could have a material impact on the Company’s financial statements.
In accordance with guidance provided by the SecuritiesASC 410, “Asset Retirement and Exchange Commission (SEC), the CompanyEnvironmental Obligations,” PSE reclassified from accumulated depreciation to a regulatory liability $127.1$173.4 million and $125.3$156.7 million in 20062009 and 2005,2008, respectively, for cost of removal for utility plant. These amounts are collected from PSE’s customers through depreciation rates.
Allowance for Funds Used During Construction
The allowanceAllowance for funds used during constructionFunds Used During Construction (AFUDC) represents the cost of both the debt and equity funds used to finance utility plant additions during the construction period. The amount of AFUDC recorded in each accounting period varies depending principally upon the level of construction work in progress and the AFUDC rate used. AFUDC is capitalized as a part of the cost of utility plant and is credited to interest expense and as a non-cash item to other income. Cash inflow related to AFUDC does not occur until these charges are reflected in rates. AFUDC interest credited to expense were $9.3 million, $8.6 million and $12.6 million for 2009, 2008 and 2007, respectively.
The AFUDC rate allowed by the Washington Utilities and Transportation Commission (Washington Commission) for natural gas utility plant additions was 8.4% beginning March 4, 2005 and 8.76% for the period September 1, 2002 through March 3, 2005. The allowed AFUDC rate on electric utility plant was 8.4% beginning March 4, 2005 and 8.76% for the period July 1, 2002 through March 3, 2005. To the extent amounts calculated using this rate exceed the AFUDC calculated rate using the Federal Energy Regulatory Commission (FERC) formula, the CompanyPSE capitalizes the excess as a deferred asset, crediting miscellaneousother income. The amounts included in other income were $2.7$10.7 million, $8.1 million and $4.4 million for 2006, $2.8 million for 20052009, 2008 and $1.4 million for 2004.2007, respectively. The deferred asset is being amortized over the average useful life of the Company’sPSE’s non-project electric utility plant.plant which is approximately 30 years.
California Reserve
PSE operates within the western wholesale market and has made sales into the California energy market. During 2003, FERC issued an order in the California Refund Proceeding adopting in part and modifying in part FERC’s earlier findings by the Administrative Law Judge. The amount of the receivable, $21.2 million at December 31, 2006 is subject to the outcome of the ongoing litigation.
Revenue Recognition
Operating utility revenues are recorded on the basis of serviceservices rendered which includesinclude estimated unbilled revenue. Sales to other utilities are recorded on a net revenue rendered basis in accordance with Emerging Issues Task Force of the Financial Accounting Standards Board (EITF) Issue No. 03-11, “Reporting Realized Gains and Losses on Derivative Instruments That Are Subject to FASB No. 133 and Not ‘Held for Trading Purposes’ as Defined in Issue No. 02-03.”ASC 605 “Revenue Recognition” (ASC 605). Non-utility subsidiaries recognize revenue when services are performed or upon the sale of assets. Revenue from retail sales is billed based on tariff rates approved by the Washington Commission. Sales of Renewable Energy Credits are deferred in regulatory liability until a ruling by the Washington Commission on the accounting petition.
PSE collected Washington Statestate excise taxes (which are a component of general retail rates) and municipal taxes of $203.7$247.8 million, $178.0$240.5 million and $153.4$229.0 million for 2006, 20052009, 2008 and 2004,2007, respectively. The Company’s policy is to report such taxes on a gross basis in operating revenues and taxes other than income taxes in the accompanying consolidated statements of income.
Allowance for Doubtful Accounts
An allowance for doubtful accounts is provided for energy customer accounts based upon a historical experience rate of write-offs of energy accounts receivable as compared to operating revenues. The allowance account is adjusted monthly for this experience rate. Other non-energy receivable balances are reserved for in the allowance account based on facts and circumstances surrounding the receivable, indicating some or all of the balance is uncollectible. Once exhaustive efforts have been made to collect these other receivables, the allowance account and corresponding receivable balance are written off.
For Puget Energy’sEnergy, the carrying amount of accounts receivable was remeasured to fair value on February 6, 2009, as a result of purchase accounting adjustments. Accordingly the allowance for doubtful accounts was reset to zero on February 6, 2009. The Company’s allowance for doubtful accounts at December 31, 20062009 and 20052008 was $2.8$8.1 million and $3.1$6.4 million, respectively.
Self-Insurance
The CompanyPSE currently has no insurance coverage for storm damage and environmental contamination that would occur in a current year on company-ownedPSE-owned property. The CompanyPSE is self-insured for a portion of the risk associated with comprehensive liability, workers’ compensation claims and catastrophic property losses other than those which are storm related. The Washington Commission has approved the deferral of certain uninsured storm damage costs that exceed $7.0 million for the years ending 2006 through 2008 and $8.0 million for subsequent years of qualifying storm damage costs for collection in future rates if the outage meets the Institute of Electrical and Electronics Engineers (IEEE) outage criteria for system average interruption duration index.
Federal Income Taxes
Prior to the merger on of Puget Energy on February 6, 2009, Puget Energy and its subsidiaries filefiled a consolidated federal income tax returns.return. Income taxes arewere allocated to the subsidiaries on the basis of separate company computations of taxabletax. After February 6, 2009, the results of Puget Energy and PSE are included in the consolidated tax return of Puget Holdings. Under the tax sharing agreement with Puget Holdings, income or loss. The Company providestaxes are allocated to each subsidiary on the basis of separate company computations of tax. Federal income taxes payable/receivable are settled with Puget Holdings as provided in the tax sharing agreement.
Puget Energy and PSE provide for deferred taxes on certain assets and liabilities that are reported differently for income tax purposes than for financial reporting purposes, as required by SFAS No. 109, “AccountingASC 740 “Income Taxes” (ASC 740). Uncertain tax positions are also accounted for Income Taxes.”under ASC 740. The company classifies interest as interest expense and penalties as other expense in the financial statements.
Energy Efficiency
The Company offers programs designed to help new and existing customers use energy efficiently. The primary emphasis is to provide information and technical services to enable customers to make energy efficient choices with respect to building design, equipment and building systems, appliance purchases and operating practices.
Since May 1997, the Company has recovered electric energy efficiency expenditures through a tariff rider mechanism. The rider mechanism allows the Company to defer the efficiency expenditures and amortize them to expense as PSE concurrently collects the efficiency expenditures in rates over a one-year period. As a result of the rider mechanism, electric energy efficiency expenditures have no impact on earnings.
Since 1995, the Company has been authorized by the Washington Commission to defer gas energy efficiency expenditures and recover them through a tariff tracker mechanism. The tracker mechanism allows the Company to defer efficiency expenditures and recover them in rates over the subsequent year. The tracker mechanism also allows the Company to recover an allowance for funds used to conserve energy on any outstanding balance that is not being recovered in rates. As a result of the tracker mechanism, gas energy efficiency expenditures have no impact on earnings.
Energy efficiency programs reduce customer consumption of energy thus impacting energy margins. The impact of load reductions is adjusted in rates at each general rate case.
Rate Adjustment Mechanisms
The CompanyPSE has a power cost adjustmentPower Cost Adjustment (PCA) mechanism that provides for a rate adjustment process if PSE’s costs to provide customers’ electricity falls outside certain bandsvaries from a normalized level ofbaseline power costscost rate established in an electrica rate case. On October 20, 2005, the Washington Commission approved an amendment to the PCA mechanism changing the PCA period to a calendar year beginning January 1, 2007. The Washington Commission also made provision to reduce the graduated scale to half the annual excess power costs for the period July 1, 2006 through December 31, 2006 without a cap on excess power costs.proceeding. All significant variable power supply cost drivers are included in the PCA mechanism (hydroelectric generation variability, market price variability for purchased power and surplus power sales, natural gas and coal fuel price variability, generation unit forced outage risk and wheeling cost variability). The PCA mechanism apportions increases or decreases in power costs, on a graduated scale, between PSE and its customers. Any unrealized gains and losses from derivative instruments accounted for under SFAS No. 133, “Accounting for Derivative Instruments and Hedging Activities,”ASC 815, are deferred in proportion to the cost-sharing arrangement under the PCA mechanism. On January 10, 2007, the Washington Commission approved the PCA mechanism with the same annual graduated scale but without a cap on excess power costs.
The graduated scale is as follows:
Annual Power Cost Variability | July 2006 - December 2006 Power Cost Variability1 | Customers’ Share | Company’s Share2 | Customers’ Share | Company’s Share |
+/- $20 million | +/- $10 million | 0% | 100% | 0% | 100% |
+/- $20 million - $40 million | +/- $10 - $20 million | 50% | 50% | 50% | 50% |
+/- $40 million - $120 million | +/- $20 - $60 million | 90% | 10% | 90% | 10% |
+/- $120 + million | +/- $60 million | 95% | 5% | 95% | 5% |
_______________
1
| In October 2005, the Washington Commission in its power cost only rate case order made a provision to reduce the power cost variability amounts to half the annual power cost variability for the period July 1, 2006 through December 31, 2006.
|
2
| Over the four-year period July 1, 2002 through June 30, 2006 the Company’s share of pre-tax cost variation was capped at a cumulative $40.0 million plus 1% of the excess. Power cost variation after December 31, 2006 will be apportioned on an annual basis, based on the graduated scale without a cap.
|
For the year ended December 31, 2009, PSE’s accumulated power costs were between $20.0 million and $40.0 million. Accordingly, PSE and the customer share the costs in excess of $20.0 million in equal proportion.
The differences between the actual cost of PSE’s natural gas supplies and natural gas transportation contracts and costs currently allowed by the Washington Commission are deferred and recovered or repaid through the purchased gas adjustment (PGA)PGA mechanism. 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 the PGA mechanism rates, including interest.
Natural Gas Off-System Sales and Capacity Release
The CompanyPSE contracts for firm natural gas supplies and holds firm transportation and storage capacity sufficient to meet the expected peak winter demand for natural gas by its firm customers. Due to the variability in weather, winter peaking consumption of natural gas by most of its customers and other factors, the CompanyPSE holds contractual rights to natural gas supplies and transportation and storage capacity in excess of its average annual requirements to serve firm customers on its distribution system. For much of the year, there is excess capacity available for third-party natural gas sales, exchanges and capacity releases. The CompanyPSE sells excess natural gas supplies, enters into natural gas supply exchanges with third parties outside of its distribution area and releases to third parties excess interstate natural gas pipeline capacity and natural gas storage rights on a short-term basis to mitigate the costs of firm transportation and storage capacity for its core natural gas customers. The proceeds from such activities, net of transactional costs, are accounted for as reductions in the cost of purchased natural gas and passed on to customers through the PGA mechanism, with no direct impact on net income. As a result, the CompanyPSE nets the sales revenue and associated cost of sales for these transactions in purchased natural gas.
Accounting for Derivatives
The Company follows the provisions of SFAS No. 133, “Accounting for Derivative InstrumentsASC 815, “Derivatives and Hedging, Activities,” as amended by SFAS No. 138 and SFAS No. 149 which(ASC 815) requires that all contracts considered to be derivative instruments be recorded on the balance sheet at their fair value. Certainvalue unless the contracts that would otherwise be considered derivatives are exempt from SFAS No. 133 if they qualify for a normal purchase normal sale exception. The Companyspecific exception provided in ASC 815. PSE enters into both physical and financial contracts to manage its energy resource portfolio.portfolio and interest rate exposure including forward physical and financial contracts and swaps. The majority of thesePSE’s physical contracts qualify for the normal purchase normal saleNormal Purchase Normal Sale (NPNS) exception forto derivative accounting rules. PSE may enter into financial fixed contracts to economically hedge the purposevariability of serving retail load. However, thosecertain index-based contracts. Those contracts that do not meet the normal purchase or normal saleNPNS exception are marked-to-market to current earnings in the statements of income, subject to deferral under ASC 980, for energy related derivatives due to the PCA mechanism and pursuantPGA mechanism.
On July 1, 2009, PSE elected to SFAS No. 133, arede-designate all energy related derivative contracts that previously had been recorded as cash flow hedges for the purpose of simplifying its financial reporting. The contracts that were de-designated related to physical electric supply contracts and natural gas swap contracts to fix the price of natural gas for electric generation. For these contracts, all future mark-to-market accounting will be recognized through earnings. The amount in accumulated OCI is transferred to earnings in the same period or periods during which the hedged transaction affected earnings or sooner if management determines that the forecasted transaction is probable of not occurring. As a result, the Company will likely continue to experience earnings volatility in future periods.
The Company may enter into swap instruments on other financial derivative instruments to manage the interest rate risk associated with its long-term debt financing and debt instruments. As of December 31, 2009, Puget Energy has interest rate swap contracts outstanding related to its long-term debt. See Note 9.
Fair Value Measurements of Derivatives
ASC 820, “ Fair Value Measurements and Disclosures” (ASC 820), defined fair value as the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date (exit price). However, as permitted under ASC 820, the Company utilizes a mid-market pricing convention (the mid-point price between bid and ask prices) as a practical expedient for valuing the majority of its assets and liabilities measured and reported at theirfair value. The Company utilizes market data or assumptions that market participants would use in pricing the asset or liability, including assumptions about risk and the risks inherent in the inputs to the valuation technique. These inputs can be readily observable, market corroborated or generally unobservable. The Company primarily applies the market approach for recurring fair value onmeasurements as it believes that this is the balance sheet. Changes in their fair value are reported in earnings unless they meet specific hedge accounting criteria, in which case changes in their fairapproach used by market value are recorded in comprehensive income untilparticipants for these types of assets and liabilities. Accordingly, the timeCompany utilizes valuation techniques that maximize the transaction that they are hedging is recorded in earnings. use of observable inputs and minimize the use of unobservable inputs.
The Company designatesvalues derivative instruments based on daily quoted prices from an independent external pricing service. When external quoted market prices are not available for derivative contracts, the Company uses a valuation model that uses volatility assumptions relating to future energy prices based on specific energy markets and utilizes externally available forward market price curves. All derivative instrument asinstruments are sensitive to market price fluctuations that can occur on a qualifying cash flow hedge if the change indaily basis.
Stock-Based Compensation
The Company applies the fair value of the derivative is highly effective in offsetting cash flows attributableapproach to an asset, a liability or a forecasted transaction. To the extent that a portion of a derivative designated as a hedge is ineffective, changes in thestock compensation and estimates fair value in accordance with provisions of the ineffective portion of that derivative are recognized currently in earnings. Changes in the market value of derivative transactions related to obtaining gas for the Company’s retail gas business are deferred as regulatory assets or liabilitiesASC 718, “Compensation – Stock Compensation.” Effective February 6, 2009, as a result of the Company’s PGA mechanismmerger, all outstanding shares of the Company were accelerated and vested, the stock compensation plan was terminated and there was no stock-based compensation. The Company recognized $14.5 million of stock compensation expense which was recorded in earnings as the transactions are executed.merger and related costs.
Stock-Based Compensation
Prior to 2006, the Company had various stock-based compensation plans which were accounted for according to Accounting Principles Board (APB) No. 25, “Accounting for Stock Issued to Employees,” and related interpretations as allowed by SFAS No. 123, “Accounting for Stock-Based Compensation.” In 2003, the Company adopted the fair value based accounting of SFAS No. 123 using the prospective method under the guidance of SFAS No. 148, “Accounting for Stock-Based Compensation - Transition and Disclosure.” The Company applied SFAS No. 123 accounting to stock compensation awards granted subsequent to January 1, 2003, while grants prior to 2003 continued to be accounted for using the intrinsic value method of APB No. 25. Effective January 1, 2006, the Company adopted the fair value recognition provisions of SFAS No. 123R, “Share-Based Payment,” using the modified-prospective transition method. Under that transition method, compensation cost recognized in 2006 includes: (a) compensation cost for all share-based payments granted prior to, but not yet vested as of January 1, 2006, based on the grant date fair value estimated in accordance with the original provisions of SFAS No. 123 and (b) compensation cost for all share-based payments granted subsequent to January 1, 2006, based on the grant date fair value estimated in accordance with the provisions of SFAS No. 123R. Results for prior periods have not been restated, as provided for under the modified-prospective method.
Had the Company used the fair value method of accounting specified by SFAS No. 123 for all grants at their grant date rather than prospectively implementing SFAS No. 123, net income and earnings per share would have been as follows:
(Dollars in Thousands, except per share amounts) Years Ended December 31 | | 2005 | | 2004 | |
| Net income, as reported | | $ | 155,726 | | $ | 55,022 | |
| Add: Total stock-based employee compensation expense included in net income, net of tax | | | 1,652 | | | 2,457 | |
| Less: Total stock-based employee compensation expense per the fair value method of SFAS No. 123, net of tax | | | (2,195 | ) | | (2,603 | ) |
| Pro forma net income | | $ | 155,183 | | $ | 54,876 | |
| Earnings per common share: | | | | | | | |
| Basic as reported | | $ | 1.52 | | $ | 0.55 | |
| Diluted as reported | | $ | 1.51 | | $ | 0.55 | |
| Basic pro forma | | $ | 1.51 | | $ | 0.55 | |
| Diluted pro forma | | $ | 1.51 | | $ | 0.55 | |
Debt Related Costs
Debt premiums, discounts, expenses and amounts received or incurred to settle hedges are amortized over the life of the related debt.debt for the Company. The premiums and costs associated with reacquired debt are deferred and amortized over the life of the related new issuance, in accordance with ratemaking treatment.treatment for PSE.
Earnings Per Common Share (Puget Energy Only)
Basic earnings per common share has been computed based on weighted average common shares outstanding of 115,999,000, 102,570,000 and 99,470,000 for 2006, 2005 and 2004, respectively. Diluted earnings per common share has been computed based on weighted average common shares outstanding of 116,457,000, 103,111,000 and 99,911,000 for 2006, 2005 and 2004, respectively, which includes the dilutive effect of securities related to employee stock-based compensation plans. In 2006, 46,000 shares related to stock options were excluded from the diluted weighted average common share calculation due to their antidilutive effect.
Accounts Receivable Securitization Program
OnIn December 20, 2005, PSE entered into a five-year Receivable Sales Agreement with PSE Funding, Inc. (PSE Funding), a wholly owned, bankruptcy-remote subsidiary of PSE formed for the purpose of purchasing customers’ accounts receivable, both billed and unbilled. The results of PSE Funding are consolidated in the financial statements of PSE. The accounts receivable are sold at estimated fair value, based on the present value of discounted cash flows taking into account anticipated credit losses, the speed of payments and the discount rate commensurate with the uncertainty involved. The PSE Funding agreement replaces the Rainier securitization facility that was terminated on December 20, 2005. In addition, PSE Funding entered into a Loan and Servicing Agreement with PSE and two banks. The Loan and Servicing Agreement allowsallowed 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. The PSE Funding receivables securitization facility expireswas terminated upon the closing of the merger on February 6, 2009 and the outstanding balance was paid in December 2010, and is terminable by PSE and PSE Funding upon notice to the banks.full. PSE Funding had $110.0$158.0 million of loans secured by accounts receivable pledged as collateral at December 31, 2006.
Rainier Receivables, Inc. (Rainier Receivables) was a wholly owned, bankruptcy-remote subsidiary of PSE formed in December 2002 for the purpose of purchasing customers’ accounts receivable, both billed and unbilled, of PSE. Rainier Receivables and PSE had an agreement whereby Rainier Receivables would sell, on a revolving basis, up to $150.0 million of those eligible receivables. The agreement expired December 20, 2005. Rainier Receivables was obligated to pay fees that approximate the third-party purchaser’s cost of issuing commercial paper equal in value to the interests in receivables sold.2008.
Consolidated Statements of Cash Flows
PSE funds cash dividends paid to the shareholders of Puget Energy. These funds are reflected in the Consolidated Statement of Cash Flows of Puget Energy as if Puget Energy received the cash from PSE and paid the dividends directly to the shareholders.
Comprehensive income includes net income, foreign currency translations, changes in the minimum pension liability, unrealized gains and losses on derivative instruments, reversals of unrealized gains and losses on derivative instruments, settlements and amortization of cash flow hedge contracts and deferrals of cash flow hedges related to the power cost mechanism. The following table presentsnon-cash investing and financing activities have occurred at the Company:
| · | PSE incurred capital lease obligations of $15.9 million for vehicles and $44.5 million for energy generation turbines for the years ended December 31, 2009 and 2008, respectively. |
| · | In connection with the February 6, 2009 merger, Puget Energy assumed $779.3 million of long-term debt in order to pay down PSE short-term debt. Also in connection with the merger, Puget Energy assumed $587.8 million of long-term debt to pay off the previous shareholders. This amount was included as part of the purchase price consideration. |
Accumulated Other Comprehensive Income (Loss)
The following tables set forth the components of the Company’s accumulated other comprehensive gainincome (loss) net of tax at December 31:
| (Dollars in Thousands) | | 2006 | | 2005 | |
| Unrealized gains (losses) on derivatives during the period | | $ | 9,584 | | $ | 42,397 | |
| Reversal of unrealized (gains) losses on derivatives during the period | | | (4,691 | ) | | 761 | |
| Adjustment to PCA | | | -- | | | (6,253 | ) |
| Settlement of cash flow hedge contract | | | 13,447 | | | 67 | |
| Amortization of cash flow hedge contracts | | | (21,972 | ) | | (22,505 | ) |
| Minimum pension liability adjustment | | | (4,413 | ) | | (7,286 | ) |
| Adjustment to initially apply SFAS No. 158 | | | (18,653 | ) | | -- | |
| Total PSE, net of tax | | $ | (26,698 | ) | $ | 7,181 | |
| Foreign currency translation adjustment | | | -- | | | 327 | |
| Total Puget Energy, net of tax | | $ | (26,698 | ) | $ | 7,508 | |
Puget Energy (Dollars in Thousands) | | Successor 2009 | | | Predecessor 2008 | |
| Net unrealized loss on energy derivatives during the period | | $ | (26,222 | ) | | $ | (139,723 | ) |
| Reclassification of net unrealized loss on energy derivatives during the period | | | 19,144 | | | | 28,007 | |
| Net unrealized loss on interest rate swaps | | | (22,777 | ) | | | -- | |
| Reclassification of net unrealized loss on interest rate swaps during the period | | | 18,884 | | | | -- | |
| Settlement of cash flow hedge contract | | | -- | | | | 13,443 | |
| Amortization of cash flow hedge contracts | | | -- | | | | (21,335 | ) |
| Net unrealized gain(loss) and prior service cost on pension plans | | | 34,458 | | | | (143,196 | ) |
| Total Puget Energy, net of tax | | $ | 23,487 | | | $ | (262,804 | ) |
Puget Sound Energy (Dollars in Thousands) | | 2009 | | | 2008 | |
| Net unrealized loss on energy derivatives during the period | | $ | (159,438 | ) | | $ | (139,723 | ) |
| Reclassification of net unrealized loss on energy derivatives during the period | | | 76,280 | | | | 28,007 | |
| Settlement of cash flow hedge contract | | | 13,443 | | | | 13,443 | |
| Amortization of cash flow hedge contracts | | | (21,017 | ) | | | (21,335 | ) |
| Net unrealized (loss) and prior service cost on pension plans | | | (119,388 | ) | | | (143,196 | ) |
| Total PSE, net of tax | | $ | (210,120 | ) | | $ | (262,804 | ) |
NOTE 2. New Accounting Pronouncements
Recently Adopted Accounting Pronouncements
Business Combinations. On January 1, 2009, Puget Energy adopted ASC 805, “Business Combinations.” The objective of the standard is to improve the relevance, representational faithfulness and comparability of the information that a reporting entity provides in its financial reports about a business combination and its effects. To accomplish that, the standard establishes principles and requirements for how the acquirer: (1) recognizes and measures in its financial statements the identifiable assets acquired, the liabilities assumed and any noncontrolling interest in the acquiree; (2) recognizes and measures the goodwill acquired in the business combination or a gain from a bargain purchase; and (3) determines what information to disclose to enable users of the financial statements to evaluate the nature and financial effects of the business combination. See Note 3.
Fair Value Measurements and Disclosures. In September 29, 2006,2009, the FASB issued SFASAccounting Standards Update (ASU) No. 158, “Employer’s Accounting2009-12, “Fair Value Measurements and Disclosures: Investments in Certain Entities that Calculate Net Asset Value per Share (or Its Equivalent).” The standard allows the reporting entity, as a practical expedient, to measure the fair value of investments that do not have readily determinable fair values on the basis of the net asset value per share of the investment if the net asset value of the investment is calculated in a matter consistent with Topic 946, “Financial Services – Investment Companies.” The standard requires disclosures about the nature and risk of the investments and whether the investments are probable of being sold at amounts different from the net asset value per share. The standard is effective for Retired Benefit Pension and Other Postretirement Plans.”the first reporting period ending after December 15, 2009, which is December 31, 2009 for the Company. See Note 14, “Retirement Benefits” for discussion of the new statement.17.
On September 15, 2006, FASB issued SFAS No. 157, “Fair Value Measurements.” SFAS No. 157 standardizesJanuary 1, 2008, the measurement ofCompany adopted ASC 820 for all financial assets and liabilities and nonfinancial assets and liabilities that are recognized or disclosed at fair value when it is required underin the financial statements on a recurring basis (at least annually). The standard defines fair value, establishes a framework for measuring fair value in generally accepted accounting principles, (GAAP). SFAS No. 157 is effectiveand expands disclosures about fair value measurements. This standard does not require any new fair value measurements, but provides guidance on how to measure fair value by providing a fair value hierarchy used to classify the source of the information.
The Company adopted ASC 820 on January 1, 2008, prospectively, as required by the Statement for financial and nonfinancial instruments measured on a recurring basis, with certain exceptions, including the initial impact of changes in fair value measurements of existing derivative financial instruments measured initially using the transaction price under ASC 815. The difference between the carrying amounts and the fair values of those instruments originally recorded under guidance in ASC 815 was recognized as a cumulative-effect adjustment to the opening balance of retained earnings of $9.0 million before tax as a result of recording a deferred loss on net derivative assets and liabilities.
In October 2008, the FASB issued new guidance permitting the deferral until fiscal years beginning after November 15, 2007, which will be2008 of applying previously issued fair value measurement guidance to nonfinancial assets and nonfinancial liabilities that are recognized or disclosed at fair value in the year beginningfinancial statements on a nonrecurring basis. The application of the fair value measurement guidance to nonrecurring nonfinancial assets and nonrecurring nonfinancial liabilities that are recognized or disclosed at fair value in the financial statements on a nonrecurring basis as of January 1, 2008,2009 did not impact the Company’s consolidated financial statements.
On February 6, 2009, Puget Holdings completed its merger with Puget Energy. Puget Energy remeasured the carrying amount of all its assets and liabilities to fair value, which resulted in the recognition of approximately $1.7 billion in goodwill. See Note 3.
Accounting Standards Codification. In June 2009, FASB issued ASU No. 2009-01, Topic 105, “Generally Accepted Accounting Principles amendments based on the Statement of Financial Standards No. 168 – The FASB Accounting Standards Codification and the Hierarchy of Generally Accepted Accounting Principles.” With this ASU, the FASB Codification became the authoritative source of GAAP. The FASB Codification was effective for interim and annual reporting periods ending after September 15, 2009, which was September 30, 2009 for the Company. The adoption of SFAS No. 157FASB Codification is not expected to have a material impact on the financial reporting of the Company.
Derivative Instruments Disclosures. On January 1, 2009, FASB issued a new standard, which required additional disclosures about the Company’s objectives in using derivative instruments and hedging activities, and tabular disclosures of the effects of such instruments and related hedged items on the Company’s financial statements.position, financial performance, and cash flows. See Note 14.
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 requires the useRetirement Benefits Disclosures. Effective December 31, 2009, ASC 715 “Compensation – Retirement Benefits” (ASC 715) directs companies to provide additional disclosures about plan assets of a two-step approachdefined benefit pension or other postretirement plan. The objectives of the disclosures are to disclose the following: (1) how investment allocation decisions are made, including the factors that are pertinent to an understanding of investment policies and strategies; (2) major categories of plan assets; (3) inputs and valuation techniques used to measure the fair value of plan assets; (4) effect of fair value measurements using significant unobservable inputs (Level 3) on changes in plan assets for recognizingthe period; and measuring tax positions taken or expected to be taken in a tax return. First,(5) significant concentrations of risk within plan assets. The standard is effective for the tax position should only be recognized when itfiscal year December 15, 2009, which 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 50.0% likelihood of being sustained.
FIN 48 was effective for the Company asfor the year ended December 31, 2009. See Note 17.
Subsequent Events. In May 2009, FASB issued ASC 855, “Subsequent Events,” a new standard on subsequent events. The standard does not require significant changes regarding recognition or disclosure of January 1, 2007. The change in net assets as a result of adopting FIN 48 will be treated as a change in accounting method. The cumulative effectsubsequent events but does require disclosure of the change will be recordeddate through which subsequent events have been evaluated for disclosure and recognition. The standard is effective for financial statements issued after June 15, 2009, which was the quarter ended June 30, 2009 for the Company. The implementation of this standard did not have a significant impact on the financial statements of the Company.
Recent Accounting Pronouncement Not Yet Adopted
Variable Interest Entities. In December 2009, the FASB issued ASU No. 2009-17, Topic 810, “Improvements to retained earnings. AdjustmentsFinancial Reporting by Enterprises Involved with Variable Interest Entities,” which amended the FASB Accounting Standards Codification for the issuance of pre-codification FASB Statement No. 167, Amendments to regulatory accounts,FASB Interpretation No. 46(R). This standard replaces the quantitative-based risks and rewards calculation for determining which reporting entity, if any, has a controlling financial interest in a VIE with an approach focused on identifying which reporting entity has the power to direct the activities of a VIE that most significantly impact the entity’s economic performance and: (1) the obligation to absorb losses of the entity; or (2) the right to receive benefits from the entity. An approach that is expected to be primarily qualitative is expected to be more effective for identifying which reporting entity has a controlling financial interest in a VIE. This standard also requires additional disclosures about a reporting entity’s involvement in VIE, which will be based on other applicable accounting standards. The Company is currently inenhance the processinformation provided to users of evaluating the provisions of FIN 48 to determine the potential impact, if any, the adoption will have on the Company’s financial statements. The standard is effective for the first annual reporting period beginning after November 15, 2009 and for interim periods within that first annual reporting period, which will be the period ending March 31, 2010 for the Company. The Company has determined that the adoption of FIN 48 isthis standard will not expected to have a material impact onto the Company’s retained earnings. Management’s estimated impact of adoption is subject to change due to potential changes in interpretation of FIN 48 byfinancial statements.
Fair Value Measurements and Disclosures. In January 2010, the FASB issued ASU 2010-6, “Improving Disclosures About Fair Value Measurements,” which requires reporting entities to make new disclosures about recurring or other regulatory bodiesnonrecurring fair-value measurements including significant transfers into and the finalizationout of the Company’s adoption efforts.
At its June 15, 2006 meeting, FASB’s Emerging Issues Task Force (EITF) approved the issuance of EITF Issue No. 06-3, “How Taxes Collected from CustomersLevel 1 and Remitted to Governmental Authorities Should Be Presented in the Income Statement (That Is, Gross versus Net Presentation).” EITF No. 06-3 requires companies to disclose whether or not the taxes collected from customersLevel 2 fair-value measurements and remitted to government authorities are reportedinformation on a gross (included in revenuespurchases, sales, issuances, and costs) or a net (excluded from revenues) basis. In addition, for any such taxes that are reportedsettlements on a gross basis a company should disclosein the amountsreconciliation of those taxes in interim andLevel 3 fair value measurements. ASU 2010-6 is effective for annual financial statementsreporting periods beginning after December 15, 2009, except for each periodLevel 3 reconciliation disclosures which are effective for which an income statement is presented if those amounts are significant. The EITF concluded that these requirements should be applied to financial reports for interim and annual periods beginning after December 15, 2006,2010. As these new requirements relate solely to disclosures, the adoption of this guidance will not impact the Company's consolidated financial statements.
On February 6, 2009, Puget Holdings completed its merger with Puget Energy. As a result of the merger, Puget Energy is the direct wholly owned subsidiary of Puget Equico, which is an indirect wholly owned subsidiary of Puget Holdings. After the merger, Puget Energy has 1,000 shares authorized, of which 200 shares have been issued at a par value of $0.01 per share.
At the time of the merger, each issued and outstanding share of common stock of Puget Energy was cancelled and converted automatically into the right to receive $30.00 in cash, without interest. The fair value of consideration transferred was $3.9 billion, including funding by Puget Holdings of $3.0 billion, debt of $0.6 billion issued by Puget Energy and $0.3 billion that was the result of the stepped-up basis of the investors’ previously owned shares.
The table below is the consolidated statement of fair value of assets acquired and accrued liabilities assumed as of February 6, 2009 measured in accordance with ASC 805. There were no adjustments subsequent to the merger transaction date.
| (Dollars in Thousands) | | Amount | |
| Net utility plant | | $ | 6,346,032 | |
| Other property and investments | | | 151,913 | |
| Goodwill | | | 1,656,513 | |
| Current assets | | | 1,259,505 | |
| Long-term and regulatory assets | | | 2,497,355 | |
| Long-term debt | | | 2,490,544 | |
| Current liabilities | | | 2,173,079 | |
| Long-term liabilities | | | 3,358,000 | |
The following tables present the fair value adjustments to Puget Energy’s balance sheet and recognition of goodwill in accordance with ASC 805:
ASSETS
| (Dollars in Thousands) | | February 6, 2009 Increase (Decrease) | |
| Utility plant: | | | |
| Electric plant | | $ | (2,367,756 | ) |
| Gas plant | | | (666,278 | ) |
| Common plant | | | (302,015 | ) |
| Less: Accumulated depreciation and amortization | | | 3,381,095 | |
| Net utility plant | | | 45,046 | |
| Other property and investments: | | | | |
| Goodwill | | | 1,656,513 | |
| Non-utility property | | | 4,250 | |
| Total other property and investments | | | 1,660,763 | |
| Current assets: | | | | |
| Materials and supplies | | | 13,700 | |
| Fuel and gas inventory | | | (27,561 | ) |
| Unrealized gain on derivative instruments | | | 3,765 | |
| Power contract acquisition adjustment gain | | | 123,975 | |
| Deferred income taxes | | | 32,772 | |
| Total current assets | | | 146,651 | |
| Other long-term and regulatory assets: | | | | |
| Other regulatory assets | | | 145,711 | |
| Unrealized gain on derivative instruments | | | 1,359 | |
| Regulatory asset related to power contracts | | | 317,800 | |
| Power contract acquisition adjustment gain | | | 1,016,225 | |
| Other | | | (17,072 | ) |
| Total other long-term and regulatory assets | | | 1,464,023 | |
| Total assets | | $ | 3,316,483 | |
CAPITALIZATION AND LIABILITIES
| (Dollars in Thousands) | | February 6, 2009 Increase (Decrease) | |
| Capitalization: | | | |
| Common shareholders’ equity | | $ | 1,660,160 | |
| Long-term debt | | | (280,315 | ) |
| Total capitalization | | | 1,379,845 | |
| Current liabilities: | | | | |
| Unrealized loss on derivative instruments | | | 84,603 | |
| Current portion of deferred income taxes | | | 171 | |
| Power contract acquisition adjustment loss | | | 118,167 | |
| Other | | | 42,679 | |
| Total current liabilities | | | 245,620 | |
| Long-term liabilities and regulatory liabilities: | | | | |
| Deferred income taxes | | | 161,094 | |
| Unrealized loss on derivative instruments | | | 50,979 | |
| Regulatory liabilities | | | 17,417 | |
| Regulatory liabilities related to power contracts | | | 1,140,200 | |
| Power contract acquisition adjustment loss | | | 199,633 | |
| Other deferred credits | | | 121,695 | |
| Total long-term liabilities and regulatory liabilities | | | 1,691,018 | |
| Total capitalization and liabilities | | $ | 3,316,483 | |
The carrying values of net utility plant and the majority of regulatory assets and liabilities were determined to be stated at fair value at the acquisition date based on a conclusion that individual assets are subject to regulation by the Washington Commission and the FERC. As a result, the future cash flows associated with the assets are limited to the carrying value plus a return, and management believes that a market participant would not expect to recover any more or less than the carrying value. Furthermore, management believes that the current rate of return on plant assets is consistent with an amount that market participants would expect. ASC 805 requires that the beginning balance of fixed depreciable assets be shown net, with no accumulated amortization recorded, at the date of acquisition, consistent with fresh start accounting.
Other property and investments includes the carrying value of the investments in PSE subsidiaries and other non-utility assets adjusted to fair value based on a combination of the income approach, the market based approach and the cost approach.
The fair values of materials and supplies, which included emission allowances, renewable energy credits and carbon financial instruments, were established using a variety of approaches to estimate the market price. The carrying value of fuel inventory was adjusted to its fair value by applying market cost at the date of acquisition.
Energy derivative contracts were reassessed and revalued at the merger date based on forward market prices and forecasted energy requirements.
The fair value assigned to the power contracts was determined using an income approach comparing the contract rate to the market rate for power over the remaining period of the contracts incorporating nonperformance risk. Management also incorporated certain assumptions related to quantities and market presentation that it believes market participants would make in the valuation. The fair value of the power contracts will be amortized as the quarter ended March 31, 2007,contracts settle.
Other regulatory assets include service contracts which were valued using the income approach comparing the contract rate to the market rate over the remaining period of the contract.
The fair value of leases was determined using the income approach which calculated the favorable/unfavorable leasehold interests as the net present value of the difference between the contract lease rent and market lease rent over the remaining terms of the contracted lease obligation.
The fair value assigned to long-term debt was determined using two different methodologies. For those securities which were actively traded by a third party pricing service, the best indication of fair value was assumed to be the third party’s quoted price. For those securities for which the Company.
In December 2004, FASB issued SFAS No. 123R, “Share-Based Payment” (SFAS No. 123R), which revises SFAS No. 123, “Accounting For Stock-Based Compensation.” SFAS No. 123R requires companies that issue share-based payment awards to employees for goods or services to recognize as compensation expensethird party did not provide regular pricing, the fair value of the expected vested portiondebt was estimated by forecasting out all coupon and principal payments and discounting them to the present value at an approximated discount rate based on PSE’s risk of the awardnonperformance as of the grant date overmerger date.
The merger also triggered a new basis of accounting for Puget Energy for the vesting periodpostretirement benefit plans sponsored by PSE under ASC 805 which required remeasuring plan liabilities without the five year smoothing of market-related asset gains and losses.
For the twelve months ended December 31, 2009, Puget Energy incurred pre-tax merger expenses of $47.1 million primarily related to legal fees, transaction advisory services, new credit facility fees, change of control provisions and real estate excise tax. Puget Energy’s merger costs in 2009 will not be indicative for periods following the acquisition.
One day prior to the merger, PSE defeased its preferred stock in the amount of $1.9 million. In conjunction with the merger on February 6, 2009, Puget Energy contributed $805.3 million in capital to PSE, of which $779.3 million was used to pay off short-term debt owed by PSE, including $188.0 million in short-term debt outstanding through the PSE Funding accounts receivable securitization program that was terminated upon closing of the award. Forfeitures that occur before the award vesting date will be adjusted from the total compensation expense, but once the award vests, no adjustment to compensation expense will be allowed for forfeitures or unexercised awards. In addition, SFAS No. 123R requires recognition of compensation expense of all existing outstanding awards that are not fully vested for their remaining vesting period asmerger. An additional $26.0 million of the effective date that were not accounted for under a fair value method of accounting atcapital contribution was used to pay change in control costs associated with the time of their award. Effective January 1, 2006, the Company adopted the fair value recognition provisions of SFAS No. 123R, “Share-Based Payment,” using the modified-prospective transition method.
In March 2005, FASB issued Interpretation No. 47 (FIN 47), which finalized a proposed interpretation of SFAS No. 143 titled, “Accounting for Conditional Asset Retirement Obligations.” The interpretation addresses the issue of whether SFAS No. 143 requires an entity to recognize a liability for a legal obligation to perform asset retirement when the asset retirement activities are conditional on a future event, and if so, the timing and valuation of the recognition. The decision reached by FASB was that there are no instances where a law or regulation obligates an entity to perform retirement activities but then allows the entity to permanently avoid settling the obligation. FIN 47 was effective for the year ended December 15, 2005, and was required to be accounted for as a cumulative effect of an accounting change. The Company adopted FIN 47 in the fourth quarter 2005, which resulted in the recognition of a cumulative effect for the asset retirement obligations amounting to $0.1 million after-tax.
On May 19, 2004, FASB issued FASB Staff Position No. 106-2, “Accounting and Disclosure Requirements Related to the Medicare Prescription Drug, Improvement and Modernization Act of 2003,” as the result of the new Medicare Prescription Drug Improvement and Modernization Act which was signed into law in December 2003. The law provides a subsidy for plan sponsors that provide prescription drug benefits to Medicare beneficiaries that are equivalent to the Medicare Part D plan. Based on new Medicare regulations issued in May 2005, the Company determined that it provides benefits at a higher level than provided under Medicare Part D, and therefore would qualify for federal tax subsidies.merger.
NOTE 3. 4. Discontinued Operations and Corporate Guarantees (Puget Energy Only)
OnIn May 7, 2006, Puget Energy sold InfrastruX to an affiliate of Tenaska Power Fund, L.P. (Tenaska). After repayment in an all-cash transaction. As a part of debt, adjustments for working capital,the transaction, costs and distributions to minority interests, Puget Energy received after-tax cash proceeds of approximately $95.9 million for its 90.9% interest in InfrastruX in the second quarter 2006. The sale resulted in an after-tax gain of $29.8 million for the nine months ended September 30, 2006. Puget Energy accounted for InfrastruX as a discontinued operation under SFAS No. 144, “Accounting for the Impairment or Disposal of Long-Lived Assets” in 2005 and 2006.
Under the terms of the sale agreement, Puget Energy is obligated formade certain representations and warranties made byconcerning InfrastruX concerning its business.and indemnified Tenaska against certain future losses not to exceed $15.0 million. At the time of the sale, Puget Energy obtainedpurchased a representation and warranty insurance policy and deposited $3.7 million into an escrow account, to serve asrepresenting the full retention under the insurance policy. AsAdditionally at the time of December 31, 2006, long-term restricted cash in the amount of $3.8 million is included in the accompanying balance sheets; that amount represents management’s estimate of the aggregate fair value of the amount potentially payable under those representations and warranties and is Puget Energy’s maximum exposure related to those commitments. The obligation expires May 7, 2008. Should Tenaska make any such claims againstsale, Puget Energy payment for the claims would be made from the escrow account, and total payments are limited to $3.7recorded a $5.0 million plus any interest earned while the funds are heldloss reserve in the escrow account. Puget Energy also agreed to indemnify Tenaska for certain potential future losses related to one of InfrastruX’s subsidiary companies. Under the indemnity agreement, Puget Energy is liable for certain costsconnection with the maximum amount of loss not to exceed $15.0 million. As of December 31, 2006, a liability in the amount of $5.0 million is included in the accompanying balance sheets; that amount represents Puget Energy’s estimateindemnifications, which represented management’s measurement of the fair value of the amount potentially payablecorporate guarantees using a probability-weighted approach to a range of future cash flows. The obligation expires May 7, 2011.probability weighted approach. During 2007, Puget Energy also provided an environmental guarantee as partpaid $1.8 million from the escrow account, which included interest 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$0.2 million.
In April 2008, Puget Energy will shareand Tenaska entered into a Joint Notice of Distribution and Termination Agreement (Termination Agreement) which resulted in the next $6.4 million equally andextinguishment of all InfrastruX corporate guarantees made by Puget Energy will be responsible for the next $3.5 million. Puget Energy believes it will not havewhich management believed involved a futurerisk of loss in connection with the environmental guarantee. For 2006,sale of InfrastruX.
In 2008, Puget Energy reported InfrastruX related incomemade the remaining payments under the terms of the Termination Agreement totaling $7.1 million bringing total cash outlays equal to the Company’s original aggregate loss reserve amounts recorded in 2006.
Electric Regulation and Rates
Storm Damage Deferral Accounting
On February 18, 2005, the Washington Commission issued a general rate case order that defined deferrable catastrophic/extraordinary losses and provided that costs in excess of $7.0 million annually may be deferred for qualifying storm damage costs that meet the IEEE outage criteria for system average interruption duration index. PSE’s storm accounting, which allows deferral of certain storm damage costs, was subject to review by the Washington Commission at the end of a three-year period, which was December 31, 2007. In PSE’s electric general rate case, the annual threshold at which qualifying storm costs may be deferred has been modified to equal the four year average of normal storm expense as approved in rates which is currently $8.0 million and is currently effective beginning with calendar year 2009. In 2009, PSE incurred $4.7 million in storm-related electric transmission and distribution system restoration costs, of which none was deferred. In 2008, PSE incurred $11.4 million in storm-related electric transmission and distribution system restoration costs, of which $1.4 million was deferred.
Electric General Rate Case
On May 8, 2009, PSE filed a general rate case with the Washington Commission which proposed an increase in electric rates of $148.1 million or 7.4% annually, effective April 2010. On February 19, 2010, PSE filed a brief, which lowered the requested electric rate increase to $110.3 million or 5.5%. This rate request includes a capital structure that includes 48.0% common equity and a requested rate of return on equity of 10.8%. A final order from the Washington Commission is expected in April 2010.
On October 8, 2008, the Washington Commission issued its order in PSE’s electric general rate case filed in December 2007, approving a general rate increase for electric customers of $130.2 million or 7.1% annually. The rate increase for electric gas customers was effective November 1, 2008. In its order, the Washington Commission approved a weighted cost of capital of 8.25%, or 7.00% after-tax, and a capital structure that included 46.0% common equity with a return on equity of 10.15%.
Power Cost Only Rate Case
Power Cost Only Rate Case (PCORC), a limited-scope proceeding, was approved in 2002 by the Washington Commission to periodically reset power cost rates. In addition to providing the opportunity to reset all power costs, the PCORC proceeding also provides for timely review of new resource acquisition costs and inclusion of such costs in rates at the time the new resource goes into service. To achieve this objective, the Washington Commission approved an expedited six-month PCORC decision timeline rather than the statutory 11-month timeline for a general rate case. In an order issued January 15, 2009, the Washington Commission extended the expedited timeline from discontinued operations (netfive to six months.
Accounting Ordersand Petitions
On April 11, 2007, the Washington Commission approved PSE’s petition for issuance of taxesan accounting order that authorizes PSE to defer certain ownership and minority interest), including gain on sale, of $51.9 million compared to $9.5 million (net of taxes and minority interest) for 2005. Puget Energy’s income from discontinued operations for 2006 includes $7.3 millionoperating costs (and associated carrying costs) PSE incurred related to its purchase of Goldendale during the reversalperiod 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. Recovery of these costs over a carrying value adjustment recordedperiod of three years began November 2008 as allowed in 2005 as well as $10.0 million related to the anticipated realizationOctober 2008 general rate case order.
On April 13, 2007, PSE filed an accounting petition for a Washington Commission order authorizing the deferral and use of a deferred tax asset associated withnet revenues from the sale of Renewable Energy Credits (RECs) and Emission Reduction Allowances (ERA) to further the businessdevelopment of renewable generation resources in accordance with EITF No. 93-17, “RecognitionWashington State or to be credited to customers. The accounting petition also requests approval of Deferred Tax Assetsamortization of the deferred REC and ERA proceeds to expense. PSE filed an amended petition on October 7, 2009.
On May 30, 2007, PSE agreed to extend the terms of the existing leases of its Bellevue corporate office complex from ten 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 Parent Company’s Excess Tax Basiscash payment of $18.9 million, net of transaction fees, in exchange for the termination of the purchase option. PSE received authorization for deferred accounting treatment of the net proceeds in the Stock2007 General Rate Case. Amortization began effective November 1, 2008 for a period of 12 years.
On May 21, 2008, PSE filed an accounting petition for a Washington Commission order that authorizes the deferral of a Subsidiary that is Accounted for as a Discontinued Operation.”
| | | Twelve Months Ended December 31, | |
| (Dollars in Thousands) | | 20061 | | 2005 | | 2004 | |
| Revenues | | $ | 138,573 | | $ | 393,294 | | $ | 369,936 | |
| Goodwill impairment | | | -- | | | -- | | | (91,196 | ) |
| Operating expenses (including interest expense) | | | (128,605 | ) | | (356,934 | ) | | (357,990 | ) |
| Pre-tax income | | | 9,968 | | | 36,360 | | | (79,250 | ) |
| Income tax expense | | | (3,544 | ) | | (12,204 | ) | | 1,793 | |
| Puget Energy carrying value adjustment of InfrastruX | | | 7,269 | | | (7,269 | ) | | -- | |
| Puget Energy cost of sale related to InfrastruX, net of tax | | | (937 | ) | | (5,195 | ) | | -- | |
| Puget Energy deferred tax basis adjustment of InfrastruX | | | 9,966 | | | -- | | | -- | |
| Gain on sale, net of tax | | | 29,765 | | | -- | | | -- | |
| Minority interest in income of discontinued operations | | | (584 | ) | | (2,178 | ) | | 7,069 | |
| Income (loss) from discontinued operations | | $ | 51,903 | | $ | 9,514 | | $ | (70,388 | ) |
_______________1
| Results for January 1, 2006 to May 7, 2006, the date InfrastruX was sold.
|
In accordance with SFAS No. 144, InfrastruX discontinued depreciation and amortizationsettlement payment of its assets effective February 8, 2005. This discontinuation of depreciation and amortization resulted in $16.8$10.7 million ($10.8 million after-tax) and $6.7 million ($4.3 million after-tax) lower depreciation and amortization expense than otherwise would have been recorded as continuing operations for 2006 and 2005, respectively. Puget Energy recorded $0.2 million and $2.1 million of amortization expense related to the intangible assets of InfrastruX for 2005 and 2004, respectively.
Puget Energy’s balance sheet at December 31, 2006 does not include InfrastruX assets and liabilitiesincurred as a result of the dispositionrecent settlement of a lawsuit in May 2006. InfrastruX’s summarized assetsthe state of Montana over alleged damages caused by the operation of Colstrip. The payment was expensed pending resolution of the accounting petition. The petition is still pending approval by the Washington Commission and liabilities, including intercompany balances eliminatedis currently part of the electric general rate case.
On November 5, 2008, PSE filed an accounting petition for a Washington Commission order authorizing the deferral and recovery of interest due the IRS for tax years 2001 to 2006 along with carrying costs incurred in consolidation,connection with the interest due. In October 2005, the Washington Commission issued an order authorizing the deferral and recovery of costs associated with increased borrowings necessary to remit deferred taxes to the IRS. The petition is still pending approval by the Washington Commission and is currently part of the pending general rate case.
On November 6, 2008, PSE filed an accounting petition for a Washington Commission order authorizing accounting treatment and amortization related to payments received for taking assignment of Westcoast Pipeline Capacity. The accounting petition seeks deferred accounting treatment and amortization of the regulatory liability to power costs beginning in November 2009 and extending over the remaining primary term of the pipeline capacity contract through October 31, 2018. The petition is still pending approval by the Washington Commission and is currently part of the electric general rate case.
On December 30, 2008, the Washington Commission approved an order authorizing the sale of Puget Energy and PSE to Puget Holdings subject to a Settlement Stipulation which included 78 conditions. Items included in the conditions that may affect the financial statements are dividend restrictions for Puget Energy and PSE. These items are discussed in Note 7. In addition, the conditions provided for rate credits of $10.0 million per year (less certain merger savings) over a ten-year period beginning at the closing of the transaction.
On April 17, 2009, the Washington Commission issued an order approving and adopting a settlement agreement that authorized PSE to defer certain ownership and operating costs related to its purchase of the Mint Farm Generation Station (Mint Farm) that will be incurred prior to PSE recovering such costs in electric customer rates. Under Washington state law, a jurisdictional electric utility may defer the costs associated with purchasing and operating a natural gas plant that complies with the greenhouse gas (GHG) emissions performance standard until the plant is included in rates or for two years from the date of purchase, whichever occurs sooner. As of December 31, 2005 were:2009, the balance of the regulatory asset is $20.8 million. The prudence of the Mint Farm acquisition, recovery of costs of Mint Farm and compliance with the GHG emissions performance standard is addressed in PSE’s general rate proceeding.
On March 13, 2009, PSE filed with the Washington Commission an application for authority to sell and transfer certain assets related to the Company’s White River Hydroelectric Project (the Project) to the Cascade Water Alliance (CWA). PSE also requested in its application that the Commission waive applicable provisions of the Revised Code of Washington and Washington Administrative Code with regard to certain surplus property related to the Project, which PSE expects to sell in the near future but which is not part of the CWA transaction. On May 14, 2009, the application for authority to transfer certain assets to CWA was approved by the Washington Commission and the application for waiver with regard to the Surplus Property was denied.
On September 30, 2009, PSE filed an accounting petition requesting that the Washington Commission authorize PSE to normalize over 10 years any Treasury grant dollars received under Section 1603 of the American Recovery and Reinvestment Act of 2009 associated with the Wild Horse Expansion project. Treasury grants are tax free grants related to certain renewable energy infrastructure that are available in lieu of the production tax credit allowed under the Internal Revenue Code. The Washington Commission issued an order approving the accounting petition on December 10, 2009.
On October 7, 2009, PSE filed an amended accounting petition requesting that the Washington Commission authorize PSE to defer the net revenues from the sale of RECs and carbon financial instruments (collectively, REC Proceeds) and use the revenues to: (1) provide funding for low income energy efficiency and renewable energy services; (2) credit a portion of the REC Proceeds to the California Receivable (see Note 21 for further discussion); and (3) provide a credit to customers by offsetting the REC Proceeds against a regulatory asset. The accounting petition is an amended petition to the accounting petition originally filed in April 2007 that requested deferred accounting treatment for renewable energy credits. The petition is still pending approval by the Washington Commission.
On October 16, 2009, PSE filed an accounting petition requesting that the Washington Commission authorize the deferral and recovery of incremental costs associated with protecting the Company’s infrastructure, facilitating public safety, and preparing PSE’s electric and natural gas system in the Green River Valley flood plain in anticipation of release of water from the United States Army Corps of Engineers’ (Corps) Howard Hanson Dam (the Dam). In the event of actual flooding, PSE also petitioned the Washington Commission to allow the deferral of costs associated with the repair and restoration of any electric and gas system infrastructure affected by a flood.
On January 28, 2010, the Washington Commission approved PSE’s request for authorization to defer the costs associated with restoring the Company’s infrastructure, facilitating public safety, and repairing the Company’s electric and natural gas system in the Green River Valley flood plain in the event evacuation is required or flooding occurs due to operations associated with the Dam. This authorization is conditioned on PSE incurring incremental operation and maintenance costs in excess of $5.0 million per year associated with repair or restoration of the Company’s systems around the Green River. The Washington Commission’s Order will be effective until the date the Corps confirms that the Dam has been permanently repaired and that Corps’ operations will return to normal
(Dollars in thousands) | | December 31, 2005 | |
| Assets: | | | |
| Cash | | $ | 6,187 | |
| Accounts receivable | | | 78,842 | |
| Other current assets | | | 22,405 | |
| Total current assets | | | 107,434 | |
| Goodwill | | | 43,886 | |
| Intangibles | | | 14,443 | |
| Non-utility property and other | | | 108,784 | |
| Total long-term assets | | | 167,113 | |
| Total assets | | $ | 274,547 | |
Petitioners in several actions in the Ninth Circuit against BPA asserted that BPA acted contrary to law in entering into or performing or implementing a number of agreements, including the amended settlement agreement (and the May 2004 agreement) between BPA and PSE regarding the REP. Petitioners in several actions in the Ninth Circuit against BPA also asserted that BPA acted contrary to law in adopting or implementing the rates upon which the benefits received or to be received from BPA during the October 1, 2001 through September 30, 2006 period were based. A number of parties 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.
On May 3, 2007, the Ninth Circuit issued an opinion in Portland Gen. Elec. v. BPA, Case No. 01-70003, in which proceeding the actions of BPA in entering into settlement agreements regarding the REP with PSE and with other investor-owned utilities were challenged. In this opinion, the Ninth Circuit granted petitions for review and held the settlement agreements entered into between BPA and the investor-owned utilities being challenged in that proceeding to be inconsistent with statute. On May 3, 2007, the Ninth Circuit also issued an opinion in Golden Northwest Aluminum v. BPA, Case No. 03-73426, in which proceeding the petitioners sought review of BPA’s 2002-2006 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 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.
In March 2008, BPA and PSE signed an agreement pursuant to which BPA made a payment to PSE related to the REP benefits for the fiscal year ended September 30, 2008, which payment is subject to true-up depending upon the amount of any REP benefits ultimately determined to be payable to PSE.
In September 2008, BPA issued its record of decision in its reopened WP-07 rate proceeding to respond to the various Ninth Circuit opinions. In this record of decision, BPA adjusted its fiscal year 2009 rates, determined the amounts of REP benefits it considered to have been improperly paid after fiscal year 2001 to PSE and the other regional investor-owned utilities, and determined that such amounts are to be recovered through reductions in REP benefit payments to be made over a number of years. The amount determined by BPA to be recovered through reductions commencing October 2007 in REP payments for PSE’s residential and small farm customers was approximately $207.2 million plus interest on unrecovered amounts to the extent that PSE receives any REP benefits for its customers in the future. However, these BPA determinations are subject to subsequent administrative and judicial review, which may alter or reverse such determinations. PSE and others, including a number of preference agency and investor-owned utility customers of BPA, in December 2008 filed petitions for review in the Ninth Circuit of various of these BPA determinations.
In September 2008, BPA and PSE signed a short-term Residential Purchase and Sale Agreement (RPSA) under which BPA is to pay REP benefits to PSE for fiscal years ending September 30, 2009–2011. In December 2008, BPA and PSE signed another, long-term RPSA under which BPA is to pay REP benefits to PSE for the period October 2011 through September 2028. PSE and other customers of BPA in December 2008 filed petitions for review in the Ninth Circuit of the short-term and long-term RPSAs signed by PSE (and similar RPSAs signed by other investor-owned utility customers of BPA) and BPA’s record of decision regarding such RPSAs. Generally, REP benefit payments under a RPSA are based on the amount, if any, by which a utility’s average system cost exceeds BPA’s Priority Firm (PF) Exchange rate for such utility. The average system cost for a utility is determined using an average system cost methodology adopted by BPA. The average system cost methodology adopted by BPA and the average system cost determinations, REP overpayment determinations, and the PF Exchange rate determinations by BPA are all subject to FERC review or judicial review or both and are subject to adjustment, which may affect the amount of REP benefits paid or to be paid by BPA to PSE. As discussed above, BPA has determined to reduce such payments based on its determination of REP benefit overpayments after fiscal year 2001.
It is not clear what impact, if any, such development or review of such BPA rates, average system cost, average system cost methodology, and BPA determination of REP overpayments, review of such agreements, and the above described Ninth Circuit litigation may ultimately have on PSE.
Production Tax Credit
PSE has a tariff schedule which passes the benefits of the Production Tax Credit (PTCs) to customers based on estimated generation of the PTC credits. PSE may adjust the PTC tariff annually based on differences between the PTC credits provided to the customers and the PTC credits actually earned, plus estimated PTC credits for the following year, less interest associated with the deferred tax balance for the PTC credits. The tariff is not subject to the sharing bands in the PCA. Since customers receive the benefit of the tax credits as they are generated and the Company does not receive a credit from the IRS until the tax credits are utilized, the Company is reimbursed for its carrying costs for funds through this calculation.
On December 12, 2007, PSE revised its PTC electric tariff to decrease the revenue credit to customers from $28.8 million to $28.6 million, effective January 12, 2008. On October 30, 2009, PSE filed a revision to the PTC electric tariff to decrease the revenue credit to customers from $33.6 million to $24.7 million. The tariff is currently suspended and PSE is awaiting a pre-hearing conference to set a further procedural schedule.
Treasury Grant
Section 1603 of the American Recovery and Reinvestment Tax Act of 2009 (Section 1603) authorizes the United States Department of the Treasury (U.S. Treasury) to make grants to corporations who place specified energy property in service provided certain conditions are met. The Wild Horse expansion facility was placed into service in November 9, 2009. The Wild Horse facility was expanded from 229 MW to 273 MW through the addition of wind turbines. On December 22, 2009, PSE filed an application with the U.S. Treasury to request a grant on the expansion in the amount $28.7 million. Section 1603 precludes a recipient from claiming PTCs on property for which a grant is claimed. On February 19, 2010, the U.S. Treasury approved the grant and payment was received in February 2010.
PCA Mechanism
In 2002, the Washington Commission approved a PCA mechanism that triggers if PSE’s costs to provide customers’ electricity varies from a power cost baseline rate established in a rate proceeding. On January 5, 2007, the Washington Commission approved the continuation of the PCA mechanism 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. See Note 1 for the discussion of the accounting policy and PCA graduated scale.
Gas Regulation and Rates
Gas General Rate Case
On May 8, 2009 PSE filed a general rate case with the Washington Commission which proposed an increase in natural gas rates of $27.2 million or 2.2% annually, effective April 2010. On August 3, 2009, PSE filed an addendum to the natural gas rate request which changed the rate increase to $30.4 million or 2.5%. On December 17, 2009, PSE filed rebuttal testimony, which lowered the requested natural gas rate increase to $28.4 million or 2.3% annually. This rate request includes a capital structure with an equity component of 48.0% and a requested rate of return on equity of 10.8%. A final order from the Washington Commission is expected in April 2010.
On October 8, 2008, the Washington Commission issued its order in PSE’s natural gas general rate case filed in December 2007, approving a general rate increase for natural gas rates of $49.2 million or 4.6% annually. The rate increases for natural gas customers were effective November 1, 2008. In its order, the Washington Commission approved a weighted cost of capital of 8.25%, or 7.00% after tax and a capital structure that included 46.0% common equity with a return on equity of 10.15%.
On January 5, 2007, the Washington Commission issued its order in PSE’s natural gas general rate case, granting an increase for natural gas customers of $29.5 million or 2.8% annually, effective beginning January 13, 2007 which resulted in an increase in gas margin of approximately 9.8% annually. In its order the Washington Commission approved the same weighted cost of capital of 8.4%, or 7.06% after-tax and capital structure that included 44.0% common equity with a return on equity of 10.4%, consistent with PSE’s electric operations.
Purchased Gas Adjustment
PSE has a PGA mechanism in retail natural gas rates to recover variations in gas supply and transportation costs. Variations in gas rates are passed through to customers and, therefore, PSE’s gas margin and net income are not affected by such variations. On September 24, 2009, the Washington Commission approved PSE’s requested revisions to its PGA tariff schedules resulting in a decrease of $198.1 million or 17.1% on an annual basis in gas sales revenues effective October 1, 2009. The rate decrease was the result of lower costs of natural gas in the forward market and an increase of the credit for the accumulated PGA payable balance. The PGA rate change will impact PSE’s revenue but will not impact its net income as the decreased revenue will be offset by decreased purchased gas costs.
On May 28, 2009, the Washington Commission approved a PGA rate decrease of $21.2 million or 1.7% annually effective June 1, 2009. PGA rate changes do not impact net income.
On September 25, 2008, the Washington Commission approved PSE’s requested revisions to its PGA tariff schedules resulting in an increase of $108.8 million or 11.1% on an annual basis in gas sales revenues effective October 1, 2008. The rate increase was the result of higher costs of natural gas in the forward market and a reduction of the credit for the accumulated PGA payable balance. The PGA rate change will increase PSE’s revenue but will not impact the Company’s net income as the increased revenue will be offset by increased purchased gas costs.
The following rate adjustments were approved by the Washington Commission in relation to the PGA mechanism during 2009, 2008 and 2007:
| Effective Date | Percentage Increase (Decrease) in Rates | Annual Increase (Decrease) in Revenues (Dollars in Millions) |
| October 1, 2009 | (17.1)% | $ (198.1) |
| June 1, 2009 | (1.7) | (21.2) |
| October 1, 2008 | 11.1 | 108.8 |
| October 1, 2007 | (13.0) | (148.1) |
(Dollars in thousands) | | December 31, 2005 | |
| Liabilities: | | | |
| Accounts payable | | $ | 9,178 | |
| Short-term debt | | | 3,809 | |
| Current maturities of long-term debt | | | 6,477 | |
| Other current liabilities | | | 36,327 | |
| Total current liabilities | | | 55,791 | |
| Deferred income taxes | | | 24,645 | |
| Long-term debt | | | 120,013 | |
| Other deferred credits | | | 16,986 | |
| Total long-term liabilities | | | 161,644 | |
| Total liabilities | | $ | 217,435 | |
NOTE 4. 6. Utility and Non-Utility Plant
Utility Plant (Dollars In Thousands) At December 31 | | Estimated Useful Life (Years) | | 2006 | | 2005 | |
| Electric, gas and common utility plant classified by prescribed accounts at original cost: | | | | | | | |
| Distribution plant | | | 10-65 | | $ | 4,887,304 | | $ | 4,469,818 | |
| Production plant | | | 20-100 | | | 1,694,569 | | | 1,326,383 | |
| Transmission plant | | | 40-95 | | | 331,210 | | | 440,679 | |
| General plant | | | 10-35 | | | 367,806 | | | 363,382 | |
| Whitehorn capital lease | | | 10 | | | 23,004 | | | -- | |
| Construction work in progress | | | NA | | | 206,459 | | | 216,513 | |
| Intangible plant (including capitalized software) | | | 3-29 | | | 297,939 | | | 288,509 | |
| Plant acquisition adjustment | | | 21-34 | | | 77,871 | | | 77,871 | |
| Underground storage | | | 50-80 | | | 24,389 | | | 23,880 | |
| Liquefied natural gas storage | | | 14-50 | | | 14,217 | | | 12,339 | |
| Plant held for future use | | | NA | | | 8,315 | | | 9,153 | |
| Other | | | NA | | | 5,595 | | | 4,891 | |
| Less: accumulated provision for depreciation | | | | | | (2,757,632 | ) | | (2,602,500 | ) |
| Net utility plant | | | | | $ | 5,181,046 | | $ | 4,630,918 | |
Jointly owned generating plants service costs are included in utility plant service cost. The following table indicates the Company’s percentage ownership and the extent of the Company’s investment in jointly owned generating plants in service at December 31, 2006. These amounts are also included in the Utility Plant table above.
| | | | Company’s Share |
Jointly Owned Generating Plants (Dollars in Thousands) | Energy Source (Fuel) | Company’s Ownership Share | Plant in Service at Cost | Accumulated Depreciation |
| Colstrip Units 1 & 2 | Coal | 50% | $ 228,480 | $ (146,703) |
| Colstrip Units 3 & 4 | Coal | 25% | 479,228 | (272,003) |
| Colstrip Units 1 - 4 Common Facilities | Coal | * | 252 | (157) |
| Frederickson 1 | Gas | 49.85% | 73,740 | (6,281) |
_______________
*
| The Company’s ownership is 50% for Colstrip Units 1 & 2 and 25% for Colstrip Units 3 & 4.
|
Financing for a participant’s ownership share in the projects is provided by such participant. The Company’s share of related operating and maintenance expenses is included in corresponding accounts in the Consolidated Statements of Income.
Non-Utility Plant (Dollars In Thousands) At December 31 | | Estimated Useful Life (Years) | | 2006 | | 2005 | |
| Non-utility plant | | | 6-20 | | $ | 2,948 | | $ | 3,113 | |
| Less: accumulated provision for depreciation | | | | | | (446 | ) | | (445 | ) |
| Net non-utility plant | | | | | $ | 2,502 | | $ | 2,668 | |
Non-utility plant is composed primarily of land and land rights that are not included in rate-based property. Non-utility plant and accumulated depreciation are included in “other” under “other property and investments” in the Puget Energy and PSE balance sheets.
The Company identified various asset retirement obligations under SFAS No. 143, “Accounting for Asset Retirement Obligations,” upon initial adoption, and in 2005 identified additional asset retirement obligations to replace bare steel natural gas pipe and for the future removal of wind turbine generators. In March 2005, FASB issued FIN 47, “Accounting for Conditional Asset Retirement Obligations” (ARO), which provides guidance on when an asset retirement obligation that is conditional on a future event should be recognized. The Company adopted FIN 47 in the fourth quarter 2005 which resulted in the recognition of additional ARO. FIN 47 also requires that if an entity has any ARO for which no amount has been recognized, the existence of the ARO must be disclosed with the reasons why the liability has not been recognized.
Prior to the adoption of FIN 47, the Company recognized an obligation to: (1) dismantle two leased electric generation turbine units and deliver the turbines to the nearest railhead at the termination of the lease in 2009; (2) remove certain structures as a result of re-negotiations with the Department of Natural Resources of a now expired lease; (3) replace or line all cast iron pipes in its service territory by 2007 as a result of a 1992 Washington Commission order; (4) restore ash holding ponds at a jointly owned coal-fired electric generating facility in Montana; (5) replace all unprotected bare steel gas pipe in its service territory by 2015 as a result of a January 31, 2005 Washington Commission order; and (6) remove wind turbine generators and related equipment, improvements and fixtures at the termination of the related leases. The adoption of FIN 47 in the fourth quarter 2005 resulted in recognition of additional ARO to: (1) dispose of treated wood poles; (2) dispose of oil containing PCBs and the related equipment that held the oil; (3) remove asbestos in facilities that have been identified for remodeling or demolition; and (4) disconnect abandoned pipelines, purge the pipelines of gas and cut and cap their supplies of gas. In 2006, the Company recognized ARO for the decommissioning costs of the Frederickson facility at the end of its service life and costs related to wood poles, gas mains and contaminated oil in equipment placed in service in 2006.
The following table describes all changes to the Company’s asset retirement obligation liability:
(Dollars in Thousands) At December 31 | | 2006 | | 2005 | |
| Asset retirement obligation at beginning of year | | $ | 28,274 | | $ | 3,516 | |
| Liability recognized in transition | | | -- | | | 22,084 | |
| New asset retirement obligation liability recognized in the period | | | 487 | | | 2,841 | |
| Liability settled in the period | | | (1,351 | ) | | (382 | ) |
| Accretion expense | | | 946 | | | 215 | |
| Asset retirement obligation at December 31 | | $ | 28,356 | | $ | 28,274 | |
The Company has identified the following obligations which were not recognized at December 31, 2006: (1) a legal obligation under the Federal Dangerous Waste Regulations to dispose of asbestos-containing material in facilities that are not scheduled for remodeling, demolition or sale. The disposal cost related to these facilities could not be measured since the retirement date is indeterminable; therefore, the liability cannot be reasonably estimated currently; (2) an obligation under Washington state law to decommission the wells at the Jackson Prairie natural gas storage facility upon termination of the project. Since the project is expected to continue as long as the Northwest pipeline continues to operate, the liability cannot be reasonably estimated currently; (3) an obligation to pay its share of decommissioning costs at the end of the functional life of the major transmission lines. The major transmission lines are expected to be used indefinitely, therefore the liability cannot be reasonably estimated currently; (4) a legal obligation under the state of Washington environmental laws to remove and properly dispose of certain under and above ground storage fuel tanks. The disposal costs related to under and above ground storage tanks could not be measured since the retirement date is indeterminable; therefore the liability cannot be reasonably estimated currently; and (5) a potential legal obligation, arising (if at all) upon the expiration of an existing FERC hydropower license, were FERC to then order project decommissioning. Regardless, given the value of ongoing generation, flood control, and other benefits provided by these projects, PSE believes that the potential for decommissioning is both remote and cannot be reasonably estimated.
The pro forma asset retirement obligation liability balances as if SFAS No. 143, as interpreted by FIN 47, had been adopted on December 31, 2003 (rather than December 31, 2005) are as follows:
(Dollars in Thousands) | |
Pro forma amounts of liability for asset retirement obligation at December 31, 2003 | $ 25,281 |
Pro forma amounts of liability for asset retirement obligation at December 31, 2004 | 25,297 |
The pro forma income statement effect as if SFAS No. 143, as interpreted by FIN 47, had been adopted on December 31, 2003 (rather than December 31, 2005) is as follows:
| (Dollars in Thousands, except per share amounts) | | 2005 | | 2004 | |
| Net income, as reported | | $ | 155,726 | | $ | 55,022 | |
| Add: SFAS No. 143 transition adjustment, net of tax | | | -- | | | -- | |
| Add: FIN 47 transition adjustment, net of tax | | | 71 | | | -- | |
| Less: Pro forma accretion expense, net of tax | | | -- | | | -- | |
| Pro forma net income | | $ | 155,797 | | $ | 55,022 | |
| Earnings per share: | | | | | | | |
| Basic as reported | | $ | 1.52 | | $ | 0.55 | |
| Diluted as reported | | $ | 1.51 | | $ | 0.55 | |
| Basic pro forma | | $ | 1.52 | | $ | 0.55 | |
| Diluted pro forma | | $ | 1.51 | | $ | 0.55 | |
NOTE 5. Preferred Share Purchase Right
On October 23, 2000, the Board of Directors declared a dividend of one preferred share purchase right (a Right) for each outstanding common share of Puget Energy. The dividend was paid on December 29, 2000 to shareholders of record on that date. The Rights willwere to become exercisable only if a person or group acquires 10%acquired 10.0% or more of Puget Energy’s outstanding common stock or announcesannounced a tender offer which, if consummated, would resulthave resulted in ownership by a person or group of 10%10.0% or more of the outstanding common stock. Each Right will entitleentitled the holder to purchase from Puget Energy one one-hundredth of a share of preferred stock with economic terms similar to that of one share of Puget Energy’s common stock at a purchase price of $65.0,$65.00, subject to adjustments. The Rights expirewere terminated on December 21, 2010, unless redeemed or exchanged earlier by Puget Energy.February 6, 2009 in connection with the merger transaction.
NOTE 6. 7. Dividend Restrictions
The payment of dividends on common stockby PSE to Puget Energy is restricted by provisions of certain covenants applicable to preferred stock and long-term debt contained in PSE’s electric and natural gas mortgage indentures. At December 31, 2009, approximately $468.0 million of unrestricted retained earnings was available for the Company’s Restated Articlespayment of Incorporation and Mortgage Indentures. Underdividends under the most restrictive covenants of PSE, earnings reinvestedmortgage indenture covenant. In addition, beginning February 6, 2009, as approved in the businessWashington Commission merger order, dividends may not be declared or paid if PSE’s common equity ratio, calculated on a regulatory basis, is 44.0% or below except to the extent a lower equity ratio is ordered by the Washington Commission. In addition, pursuant to the merger order, PSE may not declare or make any distribution unless on the date of distribution PSE’s corporate credit/issuer rating is investment grade (equal to or greater than BBB- with Standard & Poor’s (S&P) and Baa3 with Moody’s Investors Services (Moody’s)), or the PSE’s ratio of Earnings Before Interest, Tax, Depreciation and Amortization (EBITDA) to interest for the most recently ended four fiscal quarter periods prior to such date is equal to or greater than three to one.
PSE’s ability to pay dividends is also limited by the terms of its credit facilities. Under the credit facilities, PSE is not permitted to pay dividends during any Event of Default (as defined in the facilities), such as failure to comply with certain financial covenants.
Puget Energy’s ability to pay dividends to its shareholder is also limited by the merger order as well as by the terms of its credit facilities, beginning February 6, 2009. Pursuant to the merger order, Puget Energy may not declare or make a distribution unless on such date Puget Energy’s ratio of consolidated EBITDA to consolidated interest expense for the four most recently ended fiscal quarters prior to such date is equal to or greater than two to one. In accordance with terms of the Puget Energy credit facilities, Puget Energy is not permitted to pay dividends during any Event of Default (as defined in the facilities), such as failure to comply with certain financial covenants. In addition, in order to declare or pay unrestricted dividends, Puget Energy’s FFO to Interest Coverage Ratio (as defined in the facility) may not be less than 1.5 to one and its FFO to Debt Ratio (as defined in the facility) may not be less than 8.25% for the 12 months ending each quarter-end. Puget Energy is also subject to other restrictions, such as a “lock up” provision that, in certain circumstances, such as failure to meet certain cash flow tests, may further restrict Puget Energy's ability to pay dividends.
At December 31, 2009, the Company met or exceeded all restrictive test minimums required for the payment of cash dividends were approximately $398.9 milliondividends.
| | | | | | Puget Energy | | | Puget Sound Energy | |
Utility Plant (Dollars In Thousands) At December 31 | | Estimated Useful Life (Years) | | | Successor 1 2009 | | | Predecessor 2008 | | | 2009 | | | 2008 | |
| Electric, gas and common utility plant classified by prescribed accounts at original cost: | | | | | | | | | | | | | | | |
| Distribution plant | | | 10-55 | | | $ | 3,986,453 | | | $ | 5,429,830 | | | $ | 5,759,617 | | | $ | 5,429,830 | |
| Production plant | | | 25-125 | | | | 1,365,601 | | | | 2,330,116 | | | | 2,385,228 | | | | 2,330,116 | |
| Transmission plant | | | 45-65 | | | | 277,038 | | | | 352,042 | | | | 403,657 | | | | 352,042 | |
| General plant | | | 5-35 | | | | 308,065 | | | | 407,367 | | | | 363,739 | | | | 407,367 | |
| Intangible plant (including capitalized software) | | | 3-50 | | | | 106,277 | | | | 381,880 | | | | 343,180 | | | | 381,880 | |
| Plant acquisition adjustment | | NA | | | | 211,728 | | | | 228,772 | | | | 251,693 | | | | 228,772 | |
| Underground storage | | | 25-60 | | | | 26,338 | | | | 27,602 | | | | 40,052 | | | | 27,602 | |
| Liquefied natural gas storage | | | 25-45 | | | | 12,440 | | | | 14,310 | | | | 14,310 | | | | 14,310 | |
| Plant held for future use | | NA | | | | 38,378 | | | | 16,829 | | | | 38,532 | | | | 16,829 | |
| Other | | NA | | | | 7,529 | | | | 7,037 | | | | 7,529 | | | | 7,037 | |
| Plant not classified | | NA | | | | 201,013 | | | | 126,052 | | | | 201,013 | | | | 126,052 | |
| Capital leases | | | 1-2 | | | | 86,285 | | | | 69,912 | | | | 55,396 | | | | 69,912 | |
| Less: accumulated provision for depreciation | | | | | | | (185,474 | ) | | | (3,358,816 | ) | | | (3,453,165 | ) | | | (3,358,816 | ) |
| Subtotal | | | | | | $ | 6,441,671 | | | $ | 6,032,933 | | | $ | 6,410,781 | | | $ | 6,032,933 | |
| Construction work in progress | | NA | | | | 358,732 | | | | 255,214 | | | | 358,732 | | | | 255,214 | |
| Net utility plant | | | | | | $ | 6,800,403 | | | $ | 6,288,147 | | | $ | 6,769,513 | | | $ | 6,288,147 | |
Jointly owned generating plant service costs are included in utility plant service cost. The following table indicates the Company’s percentage ownership and the extent of the Company’s investment in jointly owned generating plants in service at December 31, 2006. For2009. These amounts are also included in the years 2006, 2005 and 2004, the aggregate dividends per share declared by Puget Energy were $1.00, $1.00, and $1.00, respectively.
PSE paid cash dividends on its common stock to Puget Energy of $109.8 million, $89.2 million and $87.7 million for 2006, 2005 and 2004, respectively.Utility Plant table above.
| | | | | | | Puget Energy’s Share | | | Puget Sound Energy’s Share | |
| | | | | | | Successor 1 | | | | | | | |
Jointly Owned Generating Plants (Dollars in Thousands) | Energy Source (Fuel) | | Company’s Ownership Share | | | Plant in Service at Cost | | | Accumulated Depreciation | | | Plant in Service at Cost | | | Accumulated Depreciation | |
| Colstrip Units 1 & 2 | Coal | | | 50 | % | | $ | 108,978 | | | $ | 3 | | | $ | 255,732 | | | $ | (146,751 | ) |
| Colstrip Units 3 & 4 | Coal | | | 25 | % | | | 203,330 | | | | (5,349 | ) | | | 491,078 | | | | (293,097 | ) |
| Colstrip Units 1 – 4 Common Facilities 2 | Coal | | | various | | | | 83 | | | | (3 | ) | | | 252 | | | | (172 | ) |
| Frederickson 1 | Gas | | | 49.85 | % | | | 61,644 | | | | 4,614 | | | | 70,606 | | | | (4,348 | ) |
| 1 | The carrying amount was adjusted to fair value as a result of the merger. See Note 3. |
| 2 | The Company’s ownership is 50% for Colstrip Units 1 & 2 and 25% for Colstrip Units 3 & 4. |
There were no valuation adjustments to asset retirement obligations (ARO) in conjunction with the merger. In 2008, the Company recognized an ARO for the decommissioning costs for Wild Horse for the 43 turbines on lands owned by two Washington state agencies. The Company did not recognize any new ARO’s in 2009.
The following table describes all changes to the Company’s ARO liability:
NOTE 7. Redeemable Securities(Dollars in Thousands) At December 31 | | 2009 | | | 2008 | |
| Asset retirement obligation at beginning of period | | $ | 29,661 | | | $ | 29,608 | |
| New asset retirement obligation recognized in the period | | | -- | | | | 682 | |
| Liability settled in the period | | | (3,621 | ) | | | (1,819 | ) |
| Revisions in estimated cash flows | | | (3,483 | ) | | | (184 | ) |
| Accretion expense | | | 1,538 | | | | 1,374 | |
| Asset retirement obligation at end of period | | $ | 24,095 | | | $ | 29,661 | |
The Company is required to deposit funds annually in a sinking fund sufficient to redeemhas identified the following number of shares of each series of preferred stockobligations which were not recognized at $100 per share plus accrued dividends: 4.70% Series and 4.84% Series, 3,000 shares each. All previous sinking fund requirements have been satisfied. At December 31, 2006, there were 28,689 shares of the 4.70% Series and 12,192 shares of the 4.84% Series available for future sinking fund requirements. Upon involuntary liquidation, all preferred shares are entitled to their par value plus accrued dividends.2009:
The preferred stock subject to mandatory redemption may also be redeemed by the Company at the following redemption prices per share plus accrued dividends: 4.70% Series, $101.00 and 4.84% Series, $102.00.| · | a legal obligation under Federal Dangerous Waste Regulations to dispose of asbestos-containing material in facilities that are not scheduled for remodeling, demolition or sale. The disposal cost related to these facilities could not be measured since the retirement date is indeterminable; therefore, the liability cannot be reasonably estimated currently; |
| · | an obligation under Washington state law to decommission the wells at the Jackson Prairie natural gas storage facility upon termination of the project. Since the project is expected to continue as long as the Northwest pipeline continues to operate, the liability cannot be reasonably estimated currently; |
| · | an obligation to pay its share of decommissioning costs at the end of the functional life of the major transmission lines. The major transmission lines are expected to be used indefinitely, therefore the liability cannot be reasonably estimated currently; and |
| · | a legal obligation under Washington state environmental laws to remove and properly dispose of certain under and above ground fuel storage tanks. The disposal costs related to under and above ground storage tanks could not be measured since the retirement date is indeterminable; therefore the liability cannot be reasonably estimated currently. |
Puget Sound Energy Long-term debt (Dollars in Thousands) at December 31, 2009 | |
| First Mortgage Bonds, Pollution Bonds , Senior Notes and Junior Subordinated Notes | |
| Series | | Due | | 2009 | | 2008 | | Series | | Due | | 2009 | | 2008 | |
| 6.460 | % | | 2009 | | $ | -- | | $ | 150,000 | | | 9.570 | % | | 2020 | | $ | 25,000 | | $ | 25,000 | |
| 6.610 | % | | 2009 | | | -- | | | 3,000 | | | 7.150 | % | | 2025 | | | 15,000 | | | 15,000 | |
| 6.620 | % | | 2009 | | | -- | | | 5,000 | | | 7.200 | % | | 2025 | | | 2,000 | | | 2,000 | |
| 7.120 | % | | 2010 | | | 7,000 | | | 7,000 | | | 7.020 | % | | 2027 | | | 300,000 | | | 300,000 | |
| 7.960 | % | | 2010 | | | 225,000 | | | 225,000 | | | 7.000 | % | | 2029 | | | 100,000 | | | 100,000 | |
| 7.690 | % | | 2011 | | | 260,000 | | | 260,000 | | | 5.000 | %1 | | 2031 | | | 138,460 | | | 138,460 | |
| 6.830 | % | | 2013 | | | 3,000 | | | 3,000 | | | 5.100 | %1 | | 2031 | | | 23,400 | | | 23,400 | |
| 6.900 | % | | 2013 | | | 10,000 | | | 10,000 | | | 5.483 | % | | 2035 | | | 250,000 | | | 250,000 | |
| 5.197 | % | | 2015 | | | 150,000 | | | 150,000 | | | 6.724 | % | | 2036 | | | 250,000 | | | 250,000 | |
| 7.350 | % | | 2015 | | | 10,000 | | | 10,000 | | | 6.274 | % | | 2037 | | | 300,000 | | | 300,000 | |
| 7.360 | % | | 2015 | | | 2,000 | | | 2,000 | | | 5.757 | % | | 2039 | | | 350,000 | | | -- | |
| 6.750 | % | | 2016 | | | 250,000 | | | -- | | | 6.974 | %2 | | 2067 | | | 250,000 | | | 250,000 | |
| 6.740 | % | | 2018 | | | 200,000 | | | 200,000 | | | | | | | | | | | | | |
| Total PSE long-term debt | | $ | 3,120,860 | | $ | 2,678,860 | |
Puget Energy Long-term debt (Dollars in Thousands) at December 31, 2009 | | | | | Successor | | | Predecessor | |
| | | Due | | | 2009 | | | 2008 | |
| PSE long-term debt | | Various | | | $ | 3,120,860 | | | $ | 2,678,860 | |
Acquisition adjustment of PSE long-term debt 3 | | | | | | (286,681 | ) | | | -- | |
| Term loan | | 2014 | | | | 1,225,000 | | | | -- | |
| Capital expenditures facility | | 2014 | | | | 258,000 | | | | -- | |
| Original discount on Puget Energy term loan and capital expenditures facility | | | N/A | | | | (44,481 | ) | | | -- | |
| Total Puget Energy long-term debt | | | $ | 4,272,698 | | | $ | 2,678,860 | |
Junior Subordinated Debentures Of The Corporation Payable To A Subsidiary Trust Holding Mandatorily Redeemable Preferred Securities_______________In 1997 and 2001, the Company formed | 1 | Pollution Bonds |
| 2 | Junior Subordinated Notes |
| 3 | See Note 3 for additional information regarding fair value adjustments. |
Puget Sound Energy Capital Trust I and Puget Sound Energy Capital Trust II, respectively, forLong-Term Debt
In connection with the sole purpose of issuing and selling common and preferred securities (Trust Securities). The proceeds from the sale of Trust Securities were used to purchase junior subordinated debentures (Debentures) from the Company. The Debentures are the sole assetsclosing of the Trusts and the Company ownsmerger, all common securitiesshelf registration statements of the Trusts.
The Debentures of Trust I and Trust II have an interest rate of 8.231% and 8.4%, respectively, and a stated maturity date of June 1, 2027 and June 30, 2041, respectively. The Trust Securities are subject to mandatory redemption at par on the stated maturity date of the Debentures. On June 30, 2006, PSE called all of PSE’s 8.4% 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 sheets). The Capital Trust II SecuritiesPuget Energy were redeemed at par and dividends relating to the preferred securities were paid and included in interest expense. The Capital Trust Preferred Securities were redeemed using the proceeds of senior notes issued at an interest rate of 6.724%.
First Mortgage Bonds and Senior Notes (Dollars in Thousands) At December 31 |
| Series | | Due | | 2006 | | 2005 | | Series | | Due | | 2006 | | 2005 |
| 6.58 | % | 2006 | $ | -- | $ | 10,000 | | 7.69 | % | 2011 | $ | 260,000 | $ | 260,000 |
| 8.06 | % | 2006 | | -- | | 46,000 | | 6.83 | % | 2013 | | 3,000 | | 3,000 |
| 8.14 | % | 2006 | | -- | | 25,000 | | 6.90 | % | 2013 | | 10,000 | | 10,000 |
| 7.02 | % | 2007 | | 20,000 | | 20,000 | | 5.197 | % | 2015 | | 150,000 | | 150,000 |
| 7.04 | % | 2007 | | 5,000 | | 5,000 | | 7.35 | % | 2015 | | 10,000 | | 10,000 |
| 7.75 | % | 2007 | | 100,000 | | 100,000 | | 7.36 | % | 2015 | | 2,000 | | 2,000 |
| 3.363 | % | 2008 | | 150,000 | | 150,000 | | 6.74 | % | 2018 | | 200,000 | | 200,000 |
| 6.51 | % | 2008 | | 1,000 | | 1,000 | | 9.57 | % | 2020 | | 25,000 | | 25,000 |
| 6.53 | % | 2008 | | 3,500 | | 3,500 | | 7.15 | % | 2025 | | 15,000 | | 15,000 |
| 7.61 | % | 2008 | | 25,000 | | 25,000 | | 7.20 | % | 2025 | | 2,000 | | 2,000 |
| 6.46 | % | 2009 | | 150,000 | | 150,000 | | 7.02 | % | 2027 | | 300,000 | | 300,000 |
| 6.61 | % | 2009 | | 3,000 | | 3,000 | | 7.00 | % | 2029 | | 100,000 | | 100,000 |
| 6.62 | % | 2009 | | 5,000 | | 5,000 | | 5.483 | % | 2035 | | 250,000 | | 250,000 |
| 7.12 | % | 2010 | | 7,000 | | 7,000 | | 6.724 | % | 2036 | | 250,000 | | -- |
| 7.96 | % | 2010 | | 225,000 | | 225,000 | | 6.274 | % | 2037 | | 300,000 | | -- |
| | | | | | | | | Total | $ | 2,571,500 | $ | 2,102,500 |
terminated. On March 16, 2006, Puget Energy and13, 2009, PSE filed with the SEC a new shelf registration statement with the SECto provide for the offering of common stock, senior notes preferred stock,of PSE, secured by first mortgage bonds, and trust preferred securitiesunsecured debentures of Puget Sound Energy Capital Trust III. ThePSE. This shelf registration statement, is valid for three years and doeswhich did not specify the amount of securities that PSE may offer, was amended on January 26, 2010 and will remain valid until March 13, 2012. Under the shelf registration, as amended, PSE may offer senior notes secured by first mortgage bonds in an aggregate amount of up to $800.0 million. The Company also remains subject to the restrictions of PSE’s indentures on the amount of first mortgage bonds that PSE may offer.issue.
On June 30, 2006,January 23, 2009, PSE completed the issuance ofa $250.0 million issuance of senior secured notes. The notes athave a term of seven years and an interest rate of 6.724%, which are due on June 15, 2036. The net6.75%. Net proceeds from the issuance of the senior notes of approximately $247.8 million were used to redeem $200.0 million of 8.40% Capital Trust Preferred Securities, which were redeemed at par on June 30, 2006, and to repay a portion of PSE’s short-term debt. On September 18, 2006, PSE completed the issuance of $300.0 million of senior secured notes at a rate of 6.274%, which are due on March 15, 2037. The net proceeds from the issuance of the senior notes of approximately $297.4 millionissue were used to repay PSE’s outstandingshort-term debt incurred to fund in part the utility’s capital expenditures.
On September 11, 2009, PSE completed a $350.0 million issuance of senior secured notes. The notes have a term of 30 years and an interest rate of 5.757%. Net proceeds from the issue were used to repay short-term debt which washad been incurred primarily for earlier retirement of maturing long-term debt and to fund construction programs.
in part the utility’s capital expenditures. Substantially all utility properties owned by the CompanyPSE are subject to the lien of the Company’s electric and natural gas mortgage indentures. To issue additional first mortgage bonds under these indentures, PSE’s earnings available for interest must be at least twice the annual interest charges on outstanding first mortgage bonds. At December 31, 2006,2009, the earnings available for interest exceeded the required amount.
Puget Sound Energy Pollution Control Bonds
The CompanyPSE has two series of Pollution Control Bonds outstanding. On February 19, 2003, the Board of Directors approved the refinancing of all Pollution Control Bonds series, which were issued in March 2003. Amounts outstanding were borrowed from the City of Forsyth, Montana (the City). The City obtained the funds from the sale of Customized Pollution Control Refunding Bonds issued to finance pollution control facilities at Colstrip Units 3 & 4.
Each series of bonds is collateralized by a pledge of PSE’s first mortgage bonds, the terms of which match those of the Pollution Control Bonds. No payment is due with respect to the related series of first mortgage bonds so long as payment is made on the Pollution Control Bonds.
(Dollars in Thousands) At December 31 | |
| Series | | Due | | 2006 | | 2005 | |
2003A Series - 5.00% | | 2031 | | $ | 138,460 | | $ | 138,460 | |
2003B Series - 5.10% | | 2031 | | | 23,400 | | | 23,400 | |
| Total | | | | | $ | 161,860 | | $ | 161,860 | |
Effective with the close of the merger on February 6, 2009, Puget Energy has a $1.225 billion five-year term loan and a $1.0 billion credit facility. The term loan was issued at a discount of $54.3 million. Puget Energy entered into the term loan agreement to assist with funding the merger transaction and to repay short-term loans under the previous PSE credit facilities. Puget Energy entered into the credit facility to provide funding for capital expenditures. Prior to the merger close, Puget Energy had no credit facilities.
The two credit facilities mature in February 2014, contain similar terms and conditions and are syndicated among numerous banks and financial institutions. Concurrent with the borrowings under these credit agreements, Puget Energy entered into a series of interest rate swaps with a group of banks to fix the interest rates at 4.76% for the term of the credit facilities on these two loans totaling $1.483 billion.
Long-Term Debt Maturities
The principal amounts of long-term debt maturities for the next five years and thereafter are as follows:
Puget Energy and Puget Sound Energy (Dollars in Thousands) | | 2007 | | 2008 | | 2009 | | 2010 | | 2011 | | Thereafter | |
| Maturities of: | | | | | | | | | | | | | |
| Long-term debt | | $ | 125,000 | | $ | 179,500 | | $ | 158,000 | | $ | 232,000 | | $ | 260,000 | | $ | 1,778,860 | |
| (Dollars in Thousands) | | 2010 | | | 2011 | | | 2012 | | | 2013 | | | 2014 | | | Thereafter | | | Total | |
| Maturities of: | | | | | | | | | | | | | | | | | | | | | |
| PSE long-term debt | | $ | 232,000 | | | $ | 260,000 | | | $ | -- | | | $ | 13,000 | | | $ | -- | | | $ | 2,615,860 | | | $ | 3,120,860 | |
| Puget Energy long-term debt | | | -- | | | | -- | | | | -- | | | | -- | | | | 1,483,000 | | | | -- | | | | 1,483,000 | |
| Puget Energy long-term debt | | $ | 232,000 | | | $ | 260,000 | | | $ | -- | | | $ | 13,000 | | | $ | 1,483,000 | | | $ | 2,615,860 | | | $ | 4,603,860 | |
Financial Covenants
The Company’s long-term debt contains financial covenants related to cash flow interest coverage, cash flow debt leverage and debt service coverage. As of December 31, 2009, the Company is in compliance with its long-term debt financial covenants.
During 2006,2008, the Company was required to deposit funds on comparable securities annually in a sinking fund sufficient to redeem the following number of shares of each series of preferred stock at $100.00 per share plus accrued dividends: 4.70% Series and 4.84% Series, 3,000 shares each. All previous sinking fund requirements had been satisfied. At December 31, 2008, there were 22,689 shares of the 4.70% Series and 6,471 shares of the 4.84% Series available for future sinking fund requirements. Upon involuntary liquidation, all preferred shares were entitled to their par value plus accrued dividends.
On February 5, 2009, PSE deposited with its Redemption and Paying Agent approximately $1.9 million to defease the preferred stock and issued an irrevocable notice that the shares were to be redeemed on March 13, 2009. The Redemption and Paying Agent paid shareholders their redemption price plus accrued dividends through March 13, 2009. As of December 31, 2009, there were no outstanding shares of preferred stock or other redeemable securities.
The following table presents the carrying amounts and estimated fair values of Puget Energy’s financial instruments at December 31, 2009 and 2008:
| | | Successor December 31, 2009 | | | Predecessor December 31, 2008 | |
| (Dollars in Thousands) | | Carrying Amount | | | Fair Value | | | Carrying Amount | | | Fair Value | |
| Financial assets: | | | | | | | | | | | | |
| Cash and cash equivalents | | $ | 78,527 | | | $ | 78,527 | | | $ | 38,526 | | | $ | 38,526 | |
| Restricted cash | | | 19,844 | | | | 19,844 | | | | 18,889 | | | | 18,889 | |
| Notes receivable and other | | | 74,063 | | | | 74,063 | | | | 71,832 | | | | 71,832 | |
| Energy derivatives | | | 19,553 | | | | 19,553 | | | | 22,330 | | | | 22,330 | |
| Interest rate derivative instruments | | | 20,854 | | | | 20,854 | | | | -- | | | | -- | |
| Financial liabilities: | | | | | | | | | | | | | | | | |
| Short-term debt | | $ | 105,000 | | | $ | 105,000 | | | $ | 964,700 | | | $ | 964,700 | |
| Preferred stock subject to mandatory redemption | | | -- | | | | -- | | | | 1,889 | | | | 1,889 | |
| Junior subordinated notes | | | 250,000 | | | | 232,684 | | | | 250,000 | | | | 112,500 | |
| Current maturities of long-term debt (fixed-rate) | | | 232,000 | | | | 234,632 | | | | 158,000 | | | | 158,000 | |
| Long-term debt (fixed-rate) | | | 2,638,860 | | | | 2,815,048 | | | | 2,270,860 | | | | 1,950,995 | |
| Long-term debt (variable-rate) | | | 1,483,000 | | | | 1,478,632 | | | | -- | | | | -- | |
| Energy derivatives | | | 231,656 | | | | 231,656 | | | | 395,289 | | | | 395,289 | |
| Interest rate derivative instruments | | | 26,844 | | | | 26,844 | | | | -- | | | | -- | |
The following table presents the carrying amounts and estimated fair values of PSE’s financial instruments at December 31, 2009 and 2008:
| | | December 31, 2009 | | | December 31, 2008 | |
| (Dollars in Thousands) | | Carrying Amount | | | Fair Value | | | Carrying Amount | | | Fair Value | |
| Financial assets: | | | | | | | | | | | | |
| Cash and cash equivalents | | $ | 78,407 | | | $ | 78,407 | | | $ | 38,470 | | | $ | 38,470 | |
| Restricted cash | | | 19,844 | | | | 19,844 | | | | 18,889 | | | | 18,889 | |
| Notes receivable and other | | | 74,063 | | | | 74,063 | | | | 71,832 | | | | 71,832 | |
| Energy derivatives | | | 19,553 | | | | 19,553 | | | | 22,330 | | | | 22,330 | |
| Financial liabilities: | | | | | | | | | | | | | | | | |
| Short-term debt | | $ | 105,000 | | | $ | 105,000 | | | $ | 964,700 | | | $ | 964,700 | |
Short-term debt owed by PSE to Puget Energy 1 | | | 22,898 | | | | 22,898 | | | | 26,053 | | | | 26,053 | |
| Preferred stock subject to mandatory redemption | | | -- | | | | -- | | | | 1,889 | | | | 1,889 | |
| Junior subordinated notes | | | 250,000 | | | | 232,684 | | | | 250,000 | | | | 112,500 | |
| Current maturities of long-term debt (fixed-rate) | | | 232,000 | | | | 234,632 | | | | 158,000 | | | | 158,000 | |
| Non-current maturities of long-term debt (fixed-rate) | | | 2,638,860 | | | | 2,815,048 | | | | 2,270,860 | | | | 1,950,995 | |
| Energy derivatives | | | 227,247 | | | | 227,247 | | | | 395,289 | | | | 395,289 | |
________________| 1 | Short-term debt owed by PSE to Puget Energy is eliminated upon consolidation of Puget Energy. |
The fair value of the senior secured fixed notes and variable rate notes was estimated using U.S. Treasury yields and related current market credit spreads, interpolating to the maturity date of each issue. The fair value of the junior subordinated notes was priced on a yield to call basis using a market price from an independent financial institution.
The fair value of the preferred stock subject to mandatory redemption as of December 31, 2008 was estimated based on dealer quotes. The carrying values of short-term debt and notes receivable are considered to be a reasonable estimate of fair value. The carrying amount of cash, which includes temporary investments with original maturities of three months or less, is also considered to be a reasonable estimate of fair value. The Company values derivative instruments based on daily quoted prices from an independent external pricing service. When externally quoted market prices are not available for derivative contracts, the Company uses a valuation model that uses volatility assumptions relating to future energy prices based on specific energy markets and utilizes externally available forward market price curves.
As of December 31, 2009 and 2008, PSE had $105.0 million and $964.7 million in short-term debt outstanding, exclusive of the demand promissory note with Puget Energy, establishedwith a weighted average interest rate of 3.59% and 3.84%, respectively. As of December 31, 2008, PSE had four committed credit facilities that provided, in aggregate, $1.425 billion in short-term borrowing capability. Those included a $500.0 million unsecured revolving credit agreement, a $200.0 million accounts receivable securitization facility, a $375.0 million unsecured short-term credit facility and a $350.0 million unsecured credit agreement to support hedging activity. Effective with the merger on February 6, 2009, the existing credit agreements were replaced with three new credit facilities as described below.
Puget Sound Energy FoundationCredit Facilities
Effective February 6, 2009, with the merger of Puget Energy and Puget Holdings, PSE has three committed unsecured revolving credit facilities that provide, in the aggregate, $1.150 billion in short-term borrowing capability. These new facilities include a $400.0 million credit agreement for working capital needs, a $400.0 million credit facility for funding capital expenditures and a $350.0 million facility to aid qualifying nonprofit organizationssupport energy hedging activities.
PSE's credit agreements contain usual and customary affirmative and negative covenants that, helpamong other things, place limitations on its ability to incur additional indebtedness and liens, issue equity, pay dividends, transact with affiliates and make dispositions and investments. The credit agreements also contain financial covenants, whose measurement periods began with the third quarter 2009 financial statements, based on the following three ratios: cash flow interest coverage; cash flow debt leverage and debt service coverage. PSE certifies its compliance with such covenants each quarter with the lending banks. As of December 31, 2009, PSE exceeded each of the ratio minimums.
These facilities mature in 2014, contain similar terms and conditions and are syndicated among numerous committed lenders and financial institutions. The agreements provide PSE with the ability to borrow at different interest rate options and include variable fee levels. The bank credit agreements allow PSE to borrow at the bank’s prime rate or to make floating rate advances at LIBOR plus a spread that is based upon PSE’s credit rating. The $400.0 million working capital facility and $350.0 million credit agreement to support initiatives that back economic and environmental sustainability with a $15.0 million contributionenergy hedging allow for issuing standby letters of credit up to the Foundation from a portionentire amount of the proceeds from the sale of InfrastruX.credit agreements. The contribution was recorded as other income (deduction) expense. The Puget Sound Energy Foundation was established by Puget Energy$400.0 million working capital facility also serves as a nonprofit organization whose results are not consolidated by Puget Energy.backstop for PSE’s commercial paper program.
As of December 31, 2009, PSE had $105.0 million outstanding on the $400.0 million capital expenditures facility, no outstanding balance on the $400.0 million working capital facility and had a $7.0 million letter of credit outstanding under the $350.0 million facility supporting energy hedging.
Demand Promissory Note. 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 averageweighted-average interest rate ofof: (a) PSE’s outstanding commercial paper interest rate;rate, or (b) PSE’s senior unsecured revolving credit facility; or (c) theabsent such borrowings, interest rate available under the receivable securitization facility of PSE Funding, Inc., a PSE subsidiary, which is the London Interbank Offered Rate (LIBOR) ratecharged at one month LIBOR plus a marginal rate.0.25%. At December 31, 2006,2009, the outstanding balance of the Note was $24.3 million and the interest rate was 5.54%.$22.9 million. The outstanding balance and the related interest under the Note are eliminated by Puget Energy upon consolidation of PSE’s financial statements.
Puget Energy Credit Facilities
NOTE 10. Liquidity Facilities and Other Financing Arrangements
AtAs of December 31, 2006, PSE had borrowing arrangements that included2009, Puget Energy has a $1.225 billion five-year $500.0 million unsecured credit agreement with a group of banksterm loan and a five-year $200.0 million receivables securitization program. $1.0 billion credit facility for funding capital expenditures.
Puget Energy’s credit agreements contain usual and customary affirmative and negative covenants similar to PSE's credit facilities. Puget Energy's financial covenants include cash flow interest coverage and cash flow debt leverage ratios whose measurement periods began with the third quarter 2009 financial statements. Puget Energy certifies its compliance with such covenants each quarter with the lending banks. As of December 31, 2009, Puget Energy exceeded each of the ratio minimums.
These arrangementsfacilities mature in 2014, contain similar terms and conditions and are syndicated among numerous committed lenders and financial institutions. The agreements provide PSEPuget Energy with the ability to borrow at different interest rate options and include variable fee levels. The bank credit agreement allowsBorrowings may be at the Company to makebank’s prime rate or at floating rate advances at eitherrates based on LIBOR plus a spread orthat is based upon the banks’Puget Energy’s credit rating. Puget Energy must also pay a commitment fee on the unused portion of the $1.0 billion facility. The spreads and the commitment fee depend on Puget Energy’s credit ratings as determined by S&P and Moody’s. Based on Puget Energy’s credit ratings as of the date of this report, the spread over prime rate is 1.25%, the spread over the LIBOR is 2.25% and contains “credit sensitive” pricing with various spreads associated with various credit rating levels. The bank credit agreement also allows for issuing standby lettersthe commitment fee is 0.84%. As of credit up to the entire amount of the credit agreement. In April 2006, PSE amended this credit agreement to extend the expiration date from April 2010 to April 2011.
On December 20, 2005, PSE entered into a five-year Receivable Sales Agreement with PSE Funding, a wholly owned subsidiary of PSE, replacing the Rainier Receivables securitization facility that was terminated 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.
The PSE Funding receivables securitization facility expires in December 2010, and is terminable by PSE and PSE Funding upon notice to the banks. During 2006, PSE Funding borrowed a cumulative amount of $441.0 million secured by accounts receivable and had $110.0 million of loans secured by accounts receivable pledged as collateral at December 31, 2006. During 20052009, the term loan was fully drawn and 2004, Rainier Receivables had sold a cumulative amount of $351.9$258.0 million and $600.2 million in accounts receivable, respectively. At December 31, 2005, PSE Funding had $41.0 million of loans secured by accounts receivable pledged as collateral.
In addition, PSE uses commercial paper to fund its short-term borrowing requirements. The following table presentswas outstanding under the liquidity facilities and other financing arrangements at December 31, 2006 and 2005.
(Dollars in Thousands) At December 31 | | 2006 | | 2005 | |
| Committed financing arrangements: | | | | | |
PSE line of credit 1 | | $ | 500,000 | | $ | 500,000 | |
PSE receivables securitization program 2 | | | 200,000 | | | 200,000 | |
| Uncommitted financing agreements: | | | | | | | |
PSE Unsecured Credit Agreement 3 | | | -- | | | 20,000 | |
Puget Energy Demand Promissory Note 4 | | | 30,000 | | | -- | |
_______________
1
| Provides liquidity support for PSE’s outstanding commercial paper and letters of credit in the amount of $218.5 million in 2006 and $0.5 million in 2005, effectively reducing the available borrowing capacity under this credit line to $281.5 million and $499.5 million, respectively. There was $218.0 million of commercial paper outstanding at December 31, 2006 and no commercial paper outstanding at December 31, 2005.
|
2
| Provides liquidity support for PSE’s outstanding letters of credit and commercial paper. At December 31, 2006, PSE Funding had borrowed $110.0 million, leaving $90.0 million available to borrow under the receivables securitization program. At December 31, 2005, PSE Funding had $41.0 million of loans secured by accounts receivable pledged as collateral under the accounts receivable securitization program.
|
3
| An uncommitted, unsecured credit agreement with a bank to borrow at terms that varied with market conditions and the length of the loan. The agreement was terminated and no longer in effect at December 31, 2006.
|
4
| PSE has a revolving credit facility with Puget Energy in the form of a promissory note to borrow up to $30 million subject to approval by Puget Energy. At December 31, 2006, the outstanding balance on the note was $24.3 million. The outstanding balance and related interest are eliminated on Puget Energy’s balance sheet upon consolidation.
|
$1.0 billion facility.
The following table presents the carrying amounts and estimated fair values of the Company’s financial instruments at December 31, 2006 and 2005.
| | | 2006 | | 2005 | |
| (Dollars in millions) | | Carrying Amount | | Fair Value | | Carrying Amount | | Fair Value | |
| Financial assets: | | | | | | | | | |
| Cash | | $ | 28.1 | | $ | 28.1 | | $ | 16.7 | | $ | 16.7 | |
| Restricted cash | | | 0.8 | | | 0.8 | | | 1.0 | | | 1.0 | |
| Equity securities | | | 2.0 | | | 2.0 | | | 2.0 | | | 2.0 | |
| Notes receivable and other | | | 71.1 | | | 71.1 | | | 72.9 | | | 72.9 | |
| Energy derivatives | | | 23.8 | | | 23.8 | | | 103.5 | | | 103.5 | |
| Long-term restricted cash | | | 3.8 | | | 3.8 | | | -- | | | -- | |
| Financial liabilities: | | | | | | | | | | | | | |
| Short-term debt | | $ | 328.0 | | $ | 328.0 | | $ | 41.0 | | $ | 41.0 | |
Short-term debt owed by PSE to Puget Energy1 | | | 24.3 | | | 24.3 | | | -- | | | -- | |
| Preferred stock subject to mandatory redemption | | | 1.9 | | | 1.3 | | | 1.9 | | | 1.4 | |
| Junior subordinated debentures of the corporation payable to a subsidiary trust holding mandatorily redeemable preferred securities | | | 37.8 | | | 43.2 | | | 237.8 | | | 247.5 | |
Long-term debt - fixed-rate2 | | | 2,733.4 | | | 2,823.3 | | | 2,264.4 | | | 2,416.6 | |
| Energy derivatives | | | 71.0 | | | 71.0 | | | 9.8 | | | 9.8 | |
_______________
1
| Short-term debt owed by PSE to Puget Energy is eliminated upon consolidation of Puget Energy.
|
2
| PSE’s carrying value and fair value of fixed-rate long-term debt was the same as Puget Energy’s debt in 2006 and 2005.
|
The carrying amount of equity securities is considered to be a reasonable estimate of fair value due to limited market pricing and based on the market value as reported by the fund manager. The fair value of outstanding bonds including current maturities is estimated based on quoted market prices. The fair value of the preferred stock subject to mandatory redemption is estimated based on dealer quotes. The fair value of the junior subordinated debentures of the corporation payable to a subsidiary trust holding mandatorily redeemable preferred securities is estimated based on dealer quotes. The carrying values of short-term debt and notes receivable are considered to be a reasonable estimate of fair value. The carrying amount of cash, which includes temporary investments with original maturities of three months or less, is also considered to be a reasonable estimate of fair value.
Derivative instruments have been used by the Company and are recorded at fair value. The Company has a policy that financial derivatives are to be used only to mitigate business risk.
The Company leases buildings and assets under operating leases. In October 2006, the CompanyJanuary 2009, PSE entered into an agreement to purchase certain assets at the Whitehorn generating site,Fredonia combustion turbines for $42.4 million and its fleet vehicles for $11.8 million, which purchase was completed in January 2010. These historically had been leased under an operating lease. The entry in the purchase agreement resulted in the classification of the Whitehorn leaseFredonia and fleet leases as a capital lease.leases. In accordance with SFAS No. 71, “Accounting for the Effects of Certain Types of Regulation,”ASC 980, the amortization of the leased asset has been modified so that total interest and amortization is equal to the rental expense allowed for rate-making purposes. Interest accretion for 2006the Fredonia and fleet leases in 2009 was immaterial$0.2 million and capital lease amortization was $0.4$6.6 million for 2006.2009. Certain leases contain purchase options and renewal and escalation provisions. Rent expense net of sublease receipts were:
| (Dollars in Thousands) | | | |
| At December 31 | | | |
| 2009 | | $ | 31,747 | |
| 2008 | | | 29,087 | |
| 2007 | | | 27,012 | |
| (Dollars in Thousands) |
| At December 31 |
| 2006 | | $ | 24,184 | |
| 2005 | | | 17,145 | |
| 2004 | | | 17,618 | |
Payments received for the subleases of properties were approximately $0.1 million, $0.1 million and $0.1 million for 2006, 20052009, 2008 and 2004,2007, respectively.
Future minimum lease payments for non-cancelable leases net of sublease receipts are:
| (Dollars in Thousands) | | | | | |
| At December 31 | | Operating | | Capital | |
| 2007 | | $ | 13,834 | | $ | 1,605 | |
| 2008 | | | 13,976 | | | 1,605 | |
| 2009 | | | 12,600 | | | 23,453 | |
| 2010 | | | 11,237 | | | -- | |
| 2011 | | | 10,996 | | | -- | |
| Thereafter | | | 36,239 | | | -- | |
| Total minimum lease payments | | $ | 98,882 | | $ | 26,663 | |
(Dollars in Thousands) At December 31 | | Operating | | | Capital | |
| 2010 | | $ | 9,805 | | | $ | 91,699 | |
| 2011 | | | 11,390 | | | | 42,603 | |
| 2012 | | | 12,846 | | | | -- | |
| 2013 | | | 13,175 | | | | -- | |
| 2014 | | | 12,064 | | | | -- | |
| Thereafter | | | 82,995 | | | | -- | |
| Total minimum lease payments | | $ | 142,275 | | | $ | 134,302 | |
PSE leasesleased a portion of its owned natural gas transmission pipeline infrastructure under a non-cancelable operating lease to a third party. The lease expiresexpired in 2009. Future minimum
The capital lease paymentsschedule above includes Puget Energy estimates for leased Tenaska turbines in the amount of $37.4 million and $42.6 million for the years ended 2010 and 2011, respectively.
For Puget Energy, as a result of the merger, the Tenaska turbine lease was reclassified from a purchase power agreement to be received by PSE under this lease are:a capital lease.
(Dollars in Thousands) At December 31 | | 2007 | | 2008 | | 2009 | |
| Lease receipts | | $ | 1,182 | | $ | 1,182 | | $ | 886 | |
As a result of the merger, Puget Energy reassessed and revalued its derivative contracts that were designated on PSE’s books as NPNS or cash flow hedges which met the criteria defined in ASC 815. The fair value of the reassessed contracts was recorded as either assets or liabilities with an offset to goodwill. Therefore, the amount recorded in accumulated OCI at the time of the merger was reflected as goodwill.
PSE pursues various portfolio optimization strategies, but is not in the business of assuming risk for the purpose of realizing speculative trading revenues. The nature of serving regulated electric customers with its wholesale portfolio of owned and contracted electric generation resources exposes PSE and its customers to some volumetric and commodity price risks within the sharing mechanism of the PCA. Therefore, wholesale market transactions are focused on balancing PSE’s energy portfolio, reducing costs and risks where feasible and reducing volatility in wholesale costs and margin in the portfolio. PSE’s energy risk portfolio management function monitors and manages these risks using analytical models and tools. In order to manage risks effectively, PSE enters into physical and financial transactions which are appropriate for the service territory of PSE and are relevant to its regulated electric and gas portfolios.
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 recognition of future changes in value in the statements of income. As these contracts are settled, amounts previously deferred in OCI are recognized as energy costs and are included as part of the PCA mechanism.
On July 1, 2009, PSE elected to de-designate all energy related derivative contracts that previously had been recorded as cash flow hedges for the purpose of simplifying its financial reporting. The contracts that were de-designated related to physical electric supply contracts and natural gas swap contracts to fix the price of natural gas for electric generation. For these contracts, all future mark-to-market accounting will be recognized through earnings. The amount in accumulated OCI is transferred to earnings in the same period or periods during which the hedged transaction affected earnings or sooner if management determines that the forecasted transaction is probable of not occurring. As a result, the Company will likely continue to experience earnings volatility in future periods.
ASC 815 requires disclosures about a company’s derivative activities and how the related hedged items affect a company’s financial position, financial performance and cash flows. To meet the objectives, ASC 815 requires qualitative disclosures about the Company’s fair value amounts of gains and losses associated with derivative instruments, as well as disclosures about credit risk related contingent features in derivative agreements.
The following tables present the fair values and locations of Puget Energy’s derivative instruments recorded on the balance sheet at December 31, 2009 and December 31, 2008:
| Derivatives Designated as Hedging Instruments | |
| | | Successor at December 31, 2009 | | | Predecessor at December 31, 2008 | |
Puget Energy (Dollars in Thousands) | | Asset Derivatives 1 | | | Liability Derivatives 2 | | | Asset Derivatives 1 | | | Liability Derivatives 2 | |
| Interest rate swaps: | | | | | | | | | | | | |
| Current | | $ | -- | | | $ | 26,844 | | | $ | -- | | | $ | -- | |
| Long-term | | | 20,854 | | | | -- | | | | -- | | | | -- | |
| Electric portfolio: | | | | | | | | | | | | | | | | |
| Current | | | -- | | | | -- | | | | 53 | | | | 85,320 | |
| Long-term | | | -- | | | | -- | | | | 416 | | | | 93,091 | |
| Total derivatives | | $ | 20,854 | | | $ | 26,844 | | | $ | 469 | | | $ | 178,411 | |
| Derivatives Not Designated as Hedging Instruments | |
| | | Successor at December 31, 2009 | | | Predecessor at December 31, 2008 | |
Puget Energy (Dollars in Thousands) | | Asset Derivatives 1 | | | Liability Derivatives 2 | | | Asset Derivatives 1 | | | Liability Derivatives 2 | |
| Electric portfolio: | | | | | | | | | | | | |
| Current | | $ | 4,137 | | | $ | 79,732 | | | $ | 361 | | | $ | 5,256 | |
| Long-term | | | 1,003 | | | | 70,367 | | | | 119 | | | | 3,024 | |
Gas portfolio 3: | | | | | | | | | | | | | | | | |
| Current | | | 10,811 | | | | 62,207 | | | | 15,204 | | | | 146,290 | |
| Long-term | | | 3,602 | | | | 19,350 | | | | 6,177 | | | | 62,308 | |
| Total derivatives | | $ | 19,553 | | | $ | 231,656 | | | $ | 21,861 | | | $ | 216,878 | |
____________
| 1 | Balance sheet location: Unrealized gain on derivative instruments. |
| 2 | Balance sheet location: Unrealized loss on derivative instruments. |
| 3 | Puget Energy had a derivative liability and an offsetting regulatory asset of $67.1 million at December 31, 2009 and $187.2 million at December 31, 2008 related to financial contracts used to economically hedge the cost of physical gas purchased to serve natural gas customers. All fair value adjustments on derivatives relating to the natural gas business have been reclassified to a deferred account in accordance with ASC 980 due to the PGA mechanism. All increases and decreases in the cost of natural gas supply are passed on to customers with the PGA mechanism. As the gains and losses on the hedges are realized in future periods, they will be recorded as gas costs under the PGA mechanism. |
The following tables present the fair values and locations of PSE’s derivative instruments recorded on the balance sheet at December 31, 2009 and December 31, 2008:
| Derivatives Designated as Hedging Instruments | |
| | | at December 31, 2009 | | | at December 31, 2008 | |
Puget Sound Energy (Dollars in Thousands) | | Asset Derivatives 1 | | | Liability Derivatives 2 | | | Asset Derivatives 1 | | | Liability Derivatives 2 | |
| Electric portfolio: | | | | | | | | | | | | |
| Current | | $ | -- | | | $ | -- | | | $ | 53 | | | $ | 85,320 | |
| Long-term | | | -- | | | | -- | | | | 416 | | | | 93,091 | |
| Total derivatives | | $ | -- | | | $ | -- | | | $ | 469 | | | $ | 178,411 | |
| Derivatives Not Designated as Hedging Instruments | |
| | | at December 31, 2009 | | | at December 31, 2008 | |
Puget Sound Energy (Dollars in Thousands) | | Asset Derivatives 1 | | | Liability Derivatives 2 | | | Asset Derivatives 1 | | | Liability Derivatives 2 | |
| Electric portfolio: | | | | | | | | | | | | |
| Current | | $ | 4,137 | | | $ | 75,323 | | | $ | 361 | | | $ | 5,256 | |
| Long-term | | | 1,003 | | | | 70,367 | | | | 119 | | | | 3,024 | |
Gas portfolio: 3 | | | | | | | | | | | | | | | | |
| Current | | | 10,811 | | | | 62,207 | | | | 15,204 | | | | 146,290 | |
| Long-term | | | 3,602 | | | | 19,350 | | | | 6,177 | | | | 62,308 | |
| Total derivatives | | $ | 19,553 | | | $ | 227,247 | | | $ | 21,861 | | | $ | 216,878 | |
____________
| 1 | Balance sheet location: Unrealized gain on derivative instruments. |
| 2 | Balance sheet location: Unrealized loss on derivative instruments. |
| 3 | PSE had a derivative liability and an offsetting regulatory asset of $67.1 million at December 31, 2009 $187.2 million at December 31, 2008 related to financial contracts used to economically hedge the cost of physical gas purchased to serve natural gas customers. All fair value adjustments on derivatives relating to the natural gas business have been reclassified to a deferred account in accordance with ASC 980 due to the PGA mechanism. All increases and decreases in the cost of natural gas supply are passed on to customers with the PGA mechanism. As the gains and losses on the hedges are realized in future periods, they will be recorded as gas costs under the PGA mechanism. |
The following tables present the effect of hedging instruments on Puget Energy’s OCI and statements of income for the year ended December 31, 2009:
Puget Energy (Dollars in Thousands) Successor February 6, 2009 – December 31, 2009 | | Amount of Loss Recognized in OCI on Derivatives 5 | | Location of Loss Reclassified from Accumulated OCI into Income | | Amount of Loss Reclassified from Accumulated OCI into Income | | Location of Gain/(Loss) Recognized in Income on Derivatives | | Amount of Gain/(Loss) Recognized in Income on Derivatives | |
Derivatives in Cash Flow Hedging Relationships | | Effective Portion 1 | | Effective Portion 2 | | Ineffective Portion and Amount Excluded from Effectiveness Testing 2, 3 | |
| Interest rate contracts: | | $ | (22,777 | ) | Interest expense | | $ | 29,052 | | | | $ | -- | |
Commodity contracts: Electric derivatives | | | (19,933 | ) | Electric generation fuel | | | 25,296 | | Net unrealized gain on derivative instruments | | | 325 | |
| Electric derivatives | | | (6,289 | ) | Purchased electricity | | | 4,157 | | Net unrealized loss on derivative instruments | | | (2,897 | ) |
| Total | | $ | (48,999 | ) | | | $ | 58,505 | | | | $ | (2,572 | ) |
Puget Energy (Dollars in Thousands) Predecessor January 1, 2009 – February 5, 2009 | | Amount of Loss Recognized in OCI on Derivatives | | Location of Loss Reclassified from Accumulated OCI into Income | | Amount of Loss Reclassified from Accumulated OCI into Income | | Location of Loss Recognized in Income on Derivatives | | Amount of Loss Recognized in Income on Derivatives | |
Derivatives in Cash Flow Hedging Relationships | | Effective Portion 1,4 | | Effective Portion 2 | | Ineffective Portion and Amount Excluded from Effectiveness Testing 2, 3 | |
Commodity contracts: Electric derivatives | | $ | (20,791 | ) | Electric generation fuel | | $ | 5,003 | | Net unrealized loss on derivative instruments | | $ | -- | |
| Electric derivatives | | | (3,371 | ) | Purchased electricity | | | 1,934 | | Net unrealized loss on derivative instruments | | | (986 | ) |
| Total | | $ | (24,162 | ) | | | $ | 6,937 | | | | $ | (986 | ) |
____________
| 1 | Changes in OCI are reported in after tax dollars. |
| 2 | A reclassification of a loss in OCI increases accumulated OCI and decreases earnings. Amounts reported are in pre-tax dollars. |
| 3 | Ineffective portion of long-term power supply contracts that are designated as cash flow hedges. |
| 4 | The balances associated with the components of accumulated OCI (loss) on Predecessor basis were eliminated as a result of push-down accounting effective February 6, 2009, when the Successor period began. |
| 5 | On July 1, 2009 all electric and gas related cash flow hedge relationships were dedesignated, subsequent measurements of fair value are recorded through earnings, not OCI. |
The following table presents the effect of hedging instruments on PSE’s OCI and statements of income for the year ended December 31, 2009:
Puget Sound Energy (Dollars in Thousands) Twelve Months Ended December 31, 2009 | | Amount of Loss Recognized in OCI on Derivatives 4 | | Location of Loss Reclassified from Accumulated OCI into Income | | Amount of Loss Reclassified from Accumulated OCI into Income | | Location of Loss Recognized in Income on Derivatives | | Amount of Loss Recognized in Income on Derivatives | |
Derivatives in Cash Flow Hedging Relationships | | Effective Portion 1 | | Effective Portion 2 | | Ineffective Portion and Amount Excluded from Effectiveness Testing 2, 3 | |
| Interest rate contracts: | | $ | -- | | Interest expense | | $ | 488 | | | | $ | -- | |
Commodity contracts: Electric derivatives | | | (49,739 | ) | Electric generation fuel | | | 110,128 | | Net unrealized gain on derivative instruments | | | -- | |
| Electric derivatives | | | (11,538 | ) | Purchased electricity | | | 28,082 | | Net unrealized loss on derivative instruments | | | (2,749 | ) |
| Total | | $ | (61,277 | ) | | | $ | 138,698 | | | | $ | (2,749 | ) |
____________
| 1 | Changes in OCI are reported in after tax dollars. |
| 2 | A reclassification of a loss in OCI increases accumulated OCI and decreases earnings. Amounts reported are in pre-tax dollars. |
| 3 | Ineffective portion of long-term power supply contracts that are designated as cash flow hedges. |
| 4 | On July 1, 2009, all electric and gas related cash flow hedge relationships were dedesignated, subsequent measurements of fair value are recorded through earnings, not OCI. |
For derivative instruments that meet cash flow hedge criteria, the effective portion of the gain or loss on the derivative is reported as a component of OCI and reclassified into earnings in the same period or periods during which the hedged transaction affects earnings. Gains and losses on the derivatives representing hedge ineffectiveness are recognized in current earnings. PSE expects that $48.4 million of losses in OCI will be reclassified into earnings within the next twelve months. Puget Energy expects that $21.9 million of losses in OCI will be reclassified into earnings within the next twelve months. The maximum length of time over which Puget Energy and PSE are hedging their exposure to the variability in future cash flows extends to February 2015 for purchased electricity contracts and to September 2012 for electric generation fuel contracts. For Puget Energy Interest Rate Swaps, the maximum length is to February 2014.
The following tables present the effect of Puget Energy’s derivatives not designated as hedging instruments on income during the year ended December 31, 2009:
Puget Energy (Dollars in Thousands) | Location of Gain/(Loss) in Income on Derivatives | Successor February 6, 2009 - December 31, 2009 Amount of Gain/(Loss) Recognized in Income on Derivatives | | Predecessor January 1, 2009 - February 5, 2009 Amount of (Loss) Recognized in Income on Derivatives | |
Commodity contracts: Electric derivatives | Net unrealized gain (loss) on derivative instruments | $ | 117,023 | 1 | $ | (3,867 | ) |
| | Electric generation fuel | | 19,570 | | | (863 | ) |
| | Purchased electricity | | (15,325 | ) | | (243 | ) |
| Total | | $ | 121,268 | | $ | (4,973 | ) |
____________
| 1 | Differs from the amount stated in the statements of income as it does not include $42.3 million of NPNS amortization expense as well as prior year ineffectiveness of $(2.7) million measured in prior designated hedging relationships. |
The following table presents the effect of PSE’s derivatives not designated as hedging instruments during the year ended December 31, 2009:
Puget Sound Energy (Dollars in Thousands) | Location of Gain/(Loss) in Income on Derivatives | | Twelve Months Ended December 31, 2009 Amount of Gain/(Loss) Recognized in Income on Derivatives | |
Commodity contracts: Electric derivatives | Net unrealized gain on derivative instruments | | $ | 4,003 | 1 |
| | Electric generation fuel | | | 26,669 | |
| | Purchased electricity | | | (26,142 | ) |
| Total | | | $ | 4,530 | |
____________
| 1 | Differs from the amount stated in the statements of income as it does not include ineffectiveness of $(2.7) million measured in prior designated hedging relationships. |
The Company had the following outstanding commodity contracts as of December 31, 2009:
| |
Puget Energy at December 31, 2009 | Number of Units |
| Derivatives designated as hedging instruments: | |
| Interest rate swaps | $ 1.483 billion |
| Derivatives not designated as hedging instruments: | |
| Gas derivatives | 262,973,517 MMBtus |
| Electric generation fuel | 70,212,500 MMBtus |
| Purchased electricity | 6,679,502 MWh |
| |
Puget Sound Energy at December 31, 2009 | Number of Units |
| Derivatives not designated as hedging instruments: | |
Gas derivatives 1 | 262,973,517 MMBtus |
| Electric generation fuel | 70,212,500 MMBtus |
Purchased electricity 2 | 6,454,102 MWh |
________________
| 1 | Gas derivatives are deferred in accordance with ASC 980 due to the PGA mechanism. |
| 2 | As of December 31, 2009, there were eight forward contracts in Puget Energy’s portfolio that were not in PSE’s portfolio as a result of the revaluation of NPNS contracts at the merger date. |
The Company is exposed to credit risk primarily through buying and selling electricity and natural gas to serve its customers. Credit risk is the potential loss resulting from a counterparty’s non-performance under an agreement. The Company manages credit risk with policies and procedures for, among other things, counterparty analysis, exposure measurement, exposure monitoring, and exposure mitigation.
The Company monitors counterparties that are experiencing financial problems, have significant swings in credit default swap rates, have credit rating changes by external rating agencies, or have changes in ownership. Where deemed appropriate, the Company may request collateral or other security from its counterparties to mitigate potential credit default losses. Criteria employed in this decision include, among other things, the perceived creditworthiness of the counterparty and the expected credit exposure.
It is possible that volatility in energy commodity prices could cause the Company to have material 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 December 31, 2009, approximately 99.9% of the Company’s energy portfolio exposure, excluding NPNS transactions, is with counterparties that are rated at least investment grade by the major rating agencies and 0.1% are either rated below investment grade or are not rated by rating agencies. The Company assesses credit risk internally for counterparties that are not rated.
The Company generally enters into the following master agreements: (1) Western Systems Power Pool agreements (WSPP) – standardized power sales contract in the electric industry; (2) International Swaps and Derivatives Association agreements (ISDA) – standardized financial gas and electric contracts; and (3) North American Energy Standards Board agreements (NAESB) – standardized physical gas contracts. The Company believes that entering into such agreements reduces credit risk exposure because such agreements provide for the netting and set-off of monthly payments and, in the event of counterparty default, termination payments.
The Company computes credit reserves at a master agreement level (i.e. WSPP, ISDA or NAESB) by counterparty. The Company considers external credit ratings and market factors, such as credit default swaps and bond spreads, in determination of reserves. The Company recognizes that external ratings may not always reflect how a market participant perceives a counterparty’s risk of default. The Company uses both default factors published by S&P and factors derived through analysis of market risk, which reflect the application of an industry standard recovery rate. The Company selects a default factor by counterparty at an aggregate master agreement level based on a weighted average default tenor for that counterparty’s deals. The default tenor is used by weighting fair values and contract tenors for all deals for each counterparty and coming up with an average value. The default factor used is dependent upon whether the counterparty is in a net asset or a net liability position after applying the master agreement levels.
The Company applies the counterparty’s default factor to compute credit reserves for counterparties that are in a net asset position. Moreover, the Company applies its own default factor to compute credit reserves for counterparties in a net liability position. Credit reserves are booked as contra accounts to unrealized gain (loss) positions. As of December 31, 2009, PSE was in a net liability position with the majority of counterparties, so the default factors of counterparties did not have a significant impact on reserves for the year. The majority of the Company’s derivative contracts are with financial institutions and other utilities operating within the Western Electricity Coordinating Council.
The Company enters into energy contracts with various credit risk related contingent features, which could result in a counterparty requesting immediate payment or demanding immediate and ongoing full overnight collateralization on derivative instruments in a net liability position.
The tables below presents the fair value of the overall contractual contingent liability positions for the Company’s derivative activity at December 31, 2009:
Puget Energy Contingent Feature (Dollars in Thousands) | | Fair Value 3 Liability | | | Posted Collateral | | | Contingent Collateral | |
Credit rating 1 | | $ | (29,906 | ) | | $ | -- | | | $ | 29,906 | |
| Reasonable grounds for adequate assurance | | | (39,351 | ) | | | -- | | | | -- | |
Forward value of contract 2 | | | (19,616 | ) | | | 7,000 | | | | -- | |
| Total | | $ | (88,873 | ) | | $ | 7,000 | | | $ | 29,906 | |
Puget Sound Energy Contingent Feature (Dollars in Thousands) | | Fair Value 3 Liability | | | Posted Collateral | | | Contingent Collateral | |
Credit rating 1 | | $ | (25,468 | ) | | $ | -- | | | $ | 25,468 | |
| Reasonable grounds for adequate assurance | | | (39,351 | ) | | | -- | | | | -- | |
Forward value of contract 2 | | | (19,616 | ) | | | 7,000 | | | | -- | |
| Total | | $ | (84,435 | ) | | $ | 7,000 | | | $ | 25,468 | |
_________________
| 1 | PSE is required to maintain an investment grade credit rating from each of the major credit rating agencies. |
| 2 | Collateral requirements may vary, based on changes in forward value of underlying transactions. |
| 3 | Represents derivative fair values of contracts with contingent features for counterparties in net derivative liability positions at December 31, 2009. Excludes NPNS, accounts payable and accounts receivable activity. |
ASC 820 establishes a fair value hierarchy that prioritizes the inputs used to measure fair value. The hierarchy gives the highest priority to unadjusted quoted prices in active markets for identical assets or liabilities (Level 1 measurement) and the lowest priority to unobservable inputs (Level 3 measurement). The three levels of the fair value hierarchy defined by ASC 820 are as follows:
Level 1 – Quoted prices are available in active markets for identical assets or liabilities as of the reporting date. Active markets are those in which transactions for the asset or liability occur in sufficient frequency and volume to provide pricing information on an ongoing basis. Level 1 primarily consists of financial instruments such as exchange-traded derivatives and listed equities.
Level 2 – Pricing inputs are other than quoted prices in active markets included in Level 1, which are either directly or indirectly observable as of the reported date. Level 2 includes those financial instruments that are valued using models or other valuation methodologies. These models are primarily industry-standard models that consider various assumptions, including quoted forward prices for commodities, time value, volatility factors, and current market and contractual prices for the underlying instruments, as well as other relevant economic measures. Substantially all of these assumptions are observable in the marketplace throughout the full term of the instrument, can be derived from observable data or are supported by observable levels at which transactions are executed in the marketplace. Instruments in this category include non-exchange-traded derivatives such as over-the-counter forwards and options.
Level 3 – Pricing inputs include significant inputs that are generally less observable from objective sources. These inputs may be used with internally developed methodologies that result in management’s best estimate of fair value. Level 3 instruments include those that may be more structured or otherwise tailored to customers’ needs. At each balance sheet date, the Company performs an analysis of all instruments subject to ASC 820 and includes in Level 3 all of those whose fair value is based on significant unobservable inputs.
Financial assets and liabilities are classified in their entirety based on the lowest level of input that is significant to the fair value measurement. If a fair value measurement relies on inputs from different levels of the hierarchy, the entire measurement must be classified based on the lowest level input that is significant to the fair value measurement. The Company’s assessment of the significance of a particular input to the fair value measurement requires judgment and may affect the valuation of fair value assets and liabilities and their placement within the fair value hierarchy levels. The determination of the fair values incorporates various factors that not only include the credit standing of the counterparties involved and the impact of credit enhancements (such as cash deposits, letters of credit and priority interests), but also the impact of the Company’s nonperformance risk on its liabilities.
As of December 31, 2009, the Company considered the markets for its electric and natural gas Level 2 derivative instruments to be actively traded. Management’s assessment is based on the trading activity volume in real-time and forward electric and natural gas markets. The Company regularly confirms the validity of pricing service quoted prices (e.g. Level 2 in the fair value hierarchy) used to value commodity contracts to the actual prices of commodity contracts entered into during the most recent quarter.
The following tables set forth, by level within the fair value hierarchy, the Company’s financial assets and liabilities that were accounted for at fair value on a recurring basis and the reconciliation of the changes in the fair value of derivatives classified as Level 3 in the fair value hierarchy as of December 31, 2009 and December 31, 2008:
Puget Energy Recurring Fair Value Measures | | Successor at Fair Value as of December 31, 2009 | | | Predecessor at Fair Value as of December 31, 2008 | |
| (Dollars in Thousands) | | Level 1 | | | Level 2 | | | Level 3 | | | Total | | | Level 1 | | | Level 2 | | | Level 3 | | | Total | |
| Assets: | | | | | | | | | | | | | | | | | | | | | | | | |
| Energy derivative instruments | | $ | -- | | | $ | 16,767 | | | $ | 2,786 | | | $ | 19,553 | | | $ | -- | | | $ | 21,795 | | | $ | 535 | | | $ | 22,330 | |
| Cash equivalents | | | 38,835 | | | | 5,465 | | | | -- | | | | 44,300 | | | | 24,727 | | | | -- | | | | 1,392 | | | | 26,119 | |
| Restricted cash | | | 3,305 | | | | -- | | | | -- | | | | 3,305 | | | | 4,182 | | | | -- | | | | -- | | | | 4,182 | |
| Interest rate derivative instruments | | | -- | | | | 20,854 | | | | -- | | | | 20,854 | | | | -- | | | | -- | | | | -- | | | | -- | |
| Total assets | | $ | 42,140 | | | $ | 43,086 | | | $ | 2,786 | | | $ | 88,012 | | | $ | 28,909 | | | $ | 21,795 | | | $ | 1,927 | | | $ | 52,631 | |
| Liabilities: | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Energy derivative instruments | | $ | -- | | | $ | 128,537 | | | $ | 103,119 | | | $ | 231,656 | | | $ | -- | | | $ | 261,106 | | | $ | 134,183 | | | $ | 395,289 | |
| Interest rate derivative instruments | | | -- | | | | 26,844 | | | | -- | | | | 26,844 | | | | -- | | | | -- | | | | -- | | | | -- | |
| Total liabilities | | $ | -- | | | $ | 155,381 | | | $ | 103,119 | | | $ | 258,500 | | | $ | -- | | | $ | 261,106 | | | $ | 134,183 | | | $ | 395,289 | |
| | Successor | | | Predecessor | |
Puget Energy Level 3 Roll-Forward Net (Liability) (Dollars in Thousands) Twelve Months Ended December 31 | For the Period Ended February 6, 2009 - December 31, 2009 1 | | | For the Period Ended January 1, 2009 - February 5, 2009 1 | | | 2008 | |
| Balance at beginning of period | $ | (185,813 | ) | | $ | (132,256 | ) | | $ | (6,156 | ) |
| Changes during period: | | | | | | | | | | | |
| Realized and unrealized energy derivatives | | | | | | | | | | | |
| - included in earnings | | (14,832 | ) | | | (627 | ) | | | (2,935 | ) |
| - included in other comprehensive income | | (17,429 | ) | | | (14,821 | ) | | | (110,439 | ) |
| - included in regulatory assets/liabilities | | (4,345 | ) | | | (1,410 | ) | | | (17,311 | ) |
| Purchases, issuances, and settlements | | 26,374 | | | | 2,154 | | | | 6,677 | |
Transferred in/out of Level 3 2 | | 95,712 | | | | 8,560 | | | | (2,092 | ) |
| Balance at end of period | $ | (100,333 | ) | | $ | (138,400 | ) | | $ | (132,256 | ) |
_________________
| 1 | The beginning balance for the Successor period was adjusted to reflect the impact of certain fair value adjustments from the merger transaction. |
| 2 | Transferred in/out of Level 3 for the Successor includes the cash equivalents of $1.4 million. The cash equivalents became Level 2 during the second quarter 2009. |
Puget Sound Energy Recurring Fair Value Measures | | at Fair Value as of December 31, 2009 | | | at Fair Value as of December 31, 2008 | |
| (Dollars in Thousands) | | Level 1 | | | Level 2 | | | Level 3 | | | Total | | | Level 1 | | | Level 2 | | | Level 3 | | | Total | |
| Assets: | | | | | | | | | | | | | | | | | | | | | | | | |
| Energy derivative instruments | | $ | -- | | | $ | 16,767 | | | $ | 2,786 | | | $ | 19,553 | | | $ | -- | | | $ | 21,795 | | | $ | 535 | | | $ | 22,330 | |
| Cash equivalents | | | 38,835 | | | | 5,465 | | | | -- | | | | 44,300 | | | | 24,727 | | | | -- | | | | 1,392 | | | | 26,119 | |
| Restricted cash | | | 3,305 | | | | -- | | | | -- | | | | 3,305 | | | | 4,182 | | | | -- | | | | -- | | | | 4,182 | |
| Total assets | | $ | 42,140 | | | $ | 22,232 | | | $ | 2,786 | | | $ | 67,158 | | | $ | 28,909 | | | $ | 21,795 | | | $ | 1,927 | | | $ | 52,631 | |
| Liabilities: | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Energy derivative instruments | | $ | -- | | | $ | 124,128 | | | $ | 103,119 | | | $ | 227,247 | | | $ | -- | | | $ | 261,106 | | | $ | 134,183 | | | $ | 395,289 | |
| Total liabilities | | $ | -- | | | $ | 124,128 | | | $ | 103,119 | | | $ | 227,247 | | | $ | -- | | | $ | 261,106 | | | $ | 134,183 | | | $ | 395,289 | |
Puget Sound Energy Level 3 Roll-Forward Net (Liability) (Dollars in Thousands) | | 2009 | | | 2008 | |
| Balance at beginning of period | | $ | (132,256 | ) | | $ | (6,156 | ) |
| Changes during period: | | | | | | | | |
| Realized and unrealized energy derivatives | | | | | | | | |
| - included in earnings | | | (776 | ) | | | (2,935 | ) |
| - included in other comprehensive income | | | (38,047 | ) | | | (110,439 | ) |
| - included in regulatory assets/liabilities | | | (7,824 | ) | | | (17,311 | ) |
| Purchases, issuances, and settlements | | | 28,779 | | | | 6,677 | |
Transferred in/out of Level 3 1 | | | 49,791 | | | | (2,092 | ) |
| Balance at end of period | | $ | (100,333 | ) | | $ | (132,256 | ) |
_________________
| 1 | The energy derivatives transferred in/out of Level 3 in 2009 includes the cash equivalents of $1.4 million. These cash equivalents became Level 2 during the second quarter 2009. |
Realized gains and losses on energy derivatives are included in energy costs in the Company’s statements of income under purchased electricity, electric generation fuel or purchased natural gas when settled.
Unrealized gains and losses on energy derivatives are included in the net unrealized (gain)/loss on derivative instruments section in the Company’s statements of income and as a net unrealized gain/(loss) on derivative instruments in OCI.
Certain energy derivative instruments are classified as Level 3 in the fair value hierarchy because Level 3 inputs are significant to their fair value measurement. Energy derivatives transferred out of Level 3 represent existing assets or liabilities that were classified as Level 3 at the end of the prior reporting period for which the lowest significant input became observable during the current reporting period.
The Company has qualified Employee Investment Plans under which employee salary deferrals and after-tax contributions are used to purchase several different investment fund options. The Company’s contributions to the Employee Investment Plans were $11.4 million, $10.0 million and $9.0 million for the years 2009, 2008 and 2007, respectively. The Employee Investment Plan eligibility requirements are set forth in the plan documents.
PSE has a defined benefit pension plan, covering substantially all PSE employees, with a cash balance feature for all but International Brotherhood of Electrical Workers Union (IBEW) represented employees. Pension benefits earned are a function of age, salary and years of service. The Company also maintains a non-qualified SERP for certain of its senior management employees. In addition to providing pension benefits, the Company provides certain health care and life insurance benefits for retired employees. These benefits are provided principally through an insurance company. The insurance premiums are based on the benefits provided during the year, and are paid primarily by retirees.
The February 6, 2009 merger of Puget Energy with Puget Holdings triggered a new basis of accounting for PSE’s retirement benefit plans in the Puget Energy consolidated financial statements. PSE did not record the remeasurement of retirement plans as all the purchase accounting adjustments are recorded at Puget Energy.
Puget Energy
The following tables summarize Puget Energy’s change in benefit obligation, change in plan assets, net periodic benefit cost and other changes in OCI for the years ended December 31, 2009 and 2008:
| | | Qualified Pension Benefits | | | SERP Pension Benefits | | | Other Benefits | |
| | | Successor | | | Predecessor | | | Successor | | | Predecessor | | | Successor | | | Predecessor | |
| (Dollars in Thousands) | | 2009 | | | 2009 | | | 2009 | | | 2009 | | | 2009 | | | 2009 | |
| Change in benefit obligation: | | | | | | | | | | | | | | | | | | |
| Benefit obligation at beginning of period | | $ | 453,731 | | | $ | 460,586 | | | $ | 38,750 | | | $ | 39,348 | | | $ | 15,807 | | | $ | 18,089 | |
| Service cost | | | 12,469 | | | | 1,090 | | | | 951 | | | | 89 | | | | 114 | | | | 11 | |
| Interest cost | | | 25,912 | | | | 2,302 | | | | 2,178 | | | | 193 | | | | 894 | | | | 89 | |
| Actuarial loss | | | 33,458 | | | | -- | | | | 1,433 | | | | -- | | | | 770 | | | | -- | |
| Benefits paid | | | (20,784 | ) | | | (2,517 | ) | | | (4,160 | ) | | | (532 | ) | | | (2,050 | ) | | | (147 | ) |
| Medicare part D subsidy received | | | -- | | | | -- | | | | -- | | | | -- | | | | 418 | | | | 139 | |
| Benefit obligation at end of period | | $ | 504,786 | | | $ | 461,461 | | | $ | 39,152 | | | $ | 39,098 | | | $ | 15,953 | | | $ | 18,181 | |
| | | | | | | | | | | | | | | | | | | | | | | | | |
| Change in plan assets: | | | | | | | | | | | | | | | | | | | | | | | | |
| Fair value of plan assets at beginning of period | | $ | 373,767 | | | $ | 392,900 | | | $ | -- | | | $ | -- | | | $ | 7,829 | | | $ | 8,435 | |
| Actual return on plan assets | | | 114,306 | | | | 3,585 | | | | -- | | | | -- | | | | 2,272 | | | | 37 | |
| Employer contribution | | | 18,400 | | | | -- | | | | 4,160 | | | | 532 | | | | 739 | | | | 82 | |
| Benefits paid | | | (20,784 | ) | | | (2,517 | ) | | | (4,160 | ) | | | (532 | ) | | | (2,050 | ) | | | (147 | ) |
| Fair value of plan assets at end of period | | $ | 485,689 | | | $ | 393,968 | | | $ | -- | | | $ | -- | | | $ | 8,790 | | | $ | 8,407 | |
| Funded status at end of period | | $ | (19,097 | ) | | $ | (67,493 | ) | | $ | (39,152 | ) | | $ | (39,098 | ) | | $ | (7,163 | ) | | $ | (9,774 | ) |
| | | Qualified Pension Benefits | | | SERP Pension Benefits | | | Other Benefits | |
| December 31 | | Successor | | | Successor | | | Successor | |
| (Dollars in Thousands) | | 2009 | | | 2009 | | | 2009 | |
| Amounts recognized in Statement of Financial Position consist of: | | | | | | | | | |
| Current liabilities | | $ | -- | | | $ | (2,978 | ) | | $ | (39 | ) |
| Noncurrent liabilities | | | (19,097 | ) | | | (36,174 | ) | | | (7,124 | ) |
| Total | | $ | (19,097 | ) | | $ | (39,152 | ) | | $ | (7,163 | ) |
| Amounts recognized in Accumulated Other Comprehensive Income consist of: | | | | | | | | | | | | |
| Net loss/(gain) | | $ | (53,265 | ) | | $ | 1,434 | | | $ | (1,124 | ) |
| Total | | $ | (53,265 | ) | | $ | 1,434 | | | $ | (1,124 | ) |
| | | Qualified Pension Benefits | | | SERP Pension Benefits | | | Other Benefits | |
| | | Successor | | | Predecessor | | | Successor | | | Predecessor | | | Successor | | | Predecessor | |
| (Dollars in Thousands) | | 2009 | | | 2009 | | | 2009 | | | 2009 | | | 2009 | | | 2009 | |
| Components of net periodic benefit cost: | | | | | | | | | | | | | | | | | | |
| Service cost | | $ | 12,469 | | | $ | 1,090 | | | $ | 951 | | | $ | 89 | | | $ | 114 | | | $ | 11 | |
| Interest cost | | | 25,912 | | | | 2,302 | | | | 2,178 | | | | 193 | | | | 894 | | | | 89 | |
| Expected return on plan assets | | | (27,583 | ) | | | (3,585 | ) | | | -- | | | | -- | | | | (379 | ) | | | (37 | ) |
| Amortization of prior service cost | | | -- | | | | 95 | | | | -- | | | | 51 | | | | -- | | | | 7 | |
| Amortization of net loss (gain) | | | -- | | | | 269 | | | | -- | | | | 74 | | | | -- | | | | (15 | ) |
| Amortization of transition obligation | | | -- | | | | -- | | | | -- | | | | -- | | | | -- | | | | 4 | |
| Net periodic benefit cost | | $ | 10,798 | | | $ | 171 | | | $ | 3,129 | | | $ | 407 | | | $ | 629 | | | $ | 59 | |
| Successor | | Qualified Pension Benefits | | | SERP Pension Benefits | | | Other Benefits | |
| (Dollars in Thousands) | | 2009 | | | 2009 | | | 2009 | |
| Other changes (pre-tax) in plan assets and benefit obligations recognized in other comprehensive income: | | | | | | | | | |
| Net loss (gain) | | $ | (53,265 | ) | | $ | 1,434 | | | $ | (1,124 | ) |
| Total change in other comprehensive income for year | | $ | (53,265 | ) | | $ | 1,434 | | | $ | (1,124 | ) |
The estimated net loss (gain) and prior service cost (credit) for the pension plans that will be amortized from accumulated OCI into net periodic benefit cost in 2010 are immaterial. The estimated net loss (gain) and prior service cost (credit) for the SERP that will be amortized from accumulated OCI into net periodic benefit cost in 2010 are immaterial. The estimated net loss (gain), prior service cost (credit) and transition obligation (asset) for the other postretirement plans that will be amortized from accumulated OCI into net periodic benefit cost in 2010 are immaterial.
Puget Sound Energy
The following tables summarize PSE’s change in benefit obligation, change in plan assets, net periodic benefit cost and other changes in OCI for the years ended December 31, 2009 and 2008:
| | | Qualified Pension Benefits | | | SERP Pension Benefits | | | Other Benefits | |
| (Dollars in Thousands) | | 2009 | | | 2008 | | | 2009 | | | 2008 | | | 2009 | | | 2008 | |
| Change in benefit obligation: | | | | | | | | | | | | | | | | | | |
| Benefit obligation at beginning of period | | $ | 460,586 | | | $ | 426,253 | | | $ | 39,348 | | | $ | 37,111 | | | $ | 18,088 | | | $ | 18,863 | |
| Service cost | | | 14,141 | | | | 12,750 | | | | 1,068 | | | | 935 | | | | 125 | | | | 128 | |
| Interest cost | | | 27,734 | | | | 26,685 | | | | 2,315 | | | | 2,211 | | | | 960 | | | | 1,130 | |
| Amendment | | | -- | | | | 5,324 | | | | -- | | | | -- | | | | -- | | | | -- | |
| Actuarial loss (gain) | | | 25,094 | | | | 11,804 | | | | 707 | | | | 616 | | | | (1,296 | ) | | | (309 | ) |
| Benefits paid | | | (22,769 | ) | | | (22,230 | ) | | | (4,286 | ) | | | (1,525 | ) | | | (2,342 | ) | | | (2,123 | ) |
| Medicare part D subsidiary received | | | -- | | | | -- | | | | -- | | | | -- | | | | 418 | | | | 399 | |
| Benefit obligation at end of period | | $ | 504,786 | | | $ | 460,586 | | | $ | 39,152 | | | $ | 39,348 | | | $ | 15,953 | | | $ | 18,088 | |
| | | | | | | | | | | | | | | | | | | | | | | | | |
| Change in plan assets: | | | | | | | | | | | | | | | | | | | | | | | | |
| Fair value of plan assets at beginning of period | | $ | 392,900 | | | $ | 558,529 | | | $ | -- | | | $ | -- | | | $ | 8,435 | | | $ | 14,700 | |
| Actual return on plan assets | | | 97,158 | | | | (168,299 | ) | | | -- | | | | -- | | | | 1,952 | | | | (4,218 | ) |
| Employer contribution | | | 18,400 | | | | 24,900 | | | | 4,286 | | | | 1,525 | | | | 745 | | | | 76 | |
| Benefits paid | | | (22,769 | ) | | | (22,230 | ) | | | (4,286 | ) | | | (1,525 | ) | | | (2,342 | ) | | | (2,123 | ) |
| Fair value of plan assets at end of period | | $ | 485,689 | | | $ | 392,900 | | | $ | -- | | | $ | -- | | | $ | 8,790 | | | $ | 8,435 | |
| Funded status at end of period | | $ | (19,097 | ) | | $ | (67,686 | ) | | $ | (39,152 | ) | | $ | (39,348 | ) | | $ | (7,163 | ) | | $ | (9,653 | ) |
| | | Qualified Pension Benefits | | | SERP Pension Benefits | | | Other Benefits | |
| (Dollars in Thousands) | | 2009 | | | 2008 | | | 2009 | | | 2008 | | | 2009 | | | 2008 | |
| Amounts recognized in Statement of Financial Position consist of: | | | | | | | | | | | | | | | | | | |
| Current liabilities | | $ | -- | | | $ | -- | | | $ | (2,978 | ) | | $ | (4,027 | ) | | $ | (39 | ) | | $ | (58 | ) |
| Noncurrent liabilities | | | (19,097 | ) | | | (67,686 | ) | | | (36,174 | ) | | | (35,321 | ) | | | (7,124 | ) | | | (9,595 | ) |
| Total | | $ | (19,907 | ) | | $ | (67,686 | ) | | $ | (39,152 | ) | | $ | (39,348 | ) | | $ | (7,163 | ) | | $ | (9,653 | ) |
| Amounts recognized in Accumulated Other Comprehensive Income consist of: | | | | | | | | | | | | | | | | | | | | | | | | |
| Net loss (gain) | | $ | 173,822 | | | $ | 206,134 | | | $ | 8,876 | | | $ | 9,055 | | | $ | (5,281 | ) | | $ | (2,948 | ) |
| Prior service cost | | | 5,170 | | | | 6,304 | | | | 1,430 | | | | 2,046 | | | | 267 | | | | 350 | |
| Transition obligations | | | -- | | | | -- | | | | -- | | | | -- | | | | 150 | | | | 200 | |
| Total | | $ | 178,992 | | | $ | 212,438 | | | $ | 10,306 | | | $ | 11,101 | | | $ | (4,864 | ) | | $ | (2,398 | ) |
| | | Qualified Pension Benefits | | | SERP Pension Benefits | | | Other Benefits | |
| (Dollars in Thousands) | | 2009 | | | 2008 | | | 2007 | | | 2009 | | | 2008 | | | 2007 | | | 2009 | | | 2008 | | | 2007 | |
| Components of net periodic benefit cost: | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Service cost | | $ | 14,141 | | | $ | 12,750 | | | $ | 12,385 | | | $ | 1,068 | | | $ | 935 | | | $ | 926 | | | $ | 125 | | | $ | 128 | | | $ | 269 | |
| Interest cost | | | 27,734 | | | | 26,685 | | | | 24,433 | | | | 2,315 | | | | 2,211 | | | | 2,079 | | | | 960 | | | | 1,130 | | | | 1,250 | |
| Expected return on plan assets | | | (43,453 | ) | | | (41,555 | ) | | | (38,859 | ) | | | -- | | | | -- | | | | -- | | | | (455 | ) | | | (789 | ) | | | (826 | ) |
| Amortization of prior service cost | | | 1,134 | | | | 768 | | | | 677 | | | | 616 | | | | 616 | | | | 1,365 | | | | 83 | | | | 84 | | | | 353 | |
| Amortization of net loss (gain) | | | 3,702 | | | | 945 | | | | 4,193 | | | | 886 | | | | 732 | | | | 994 | | | | (460 | ) | | | (799 | ) | | | (834 | ) |
| Amortization of transition obligation | | | -- | | | | -- | | | | -- | | | | -- | | | | -- | | | | -- | | | | 50 | | | | 50 | | | | 234 | |
| Net periodic benefit cost (income) | | $ | 3,258 | | | $ | (407 | ) | | $ | 2,829 | | | $ | 4,885 | | | $ | 4,494 | | | $ | 5,364 | | | $ | 303 | | | $ | (196 | ) | | $ | 446 | |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
Curtailment/settlement cost 1 | | $ | -- | | | $ | -- | | | $ | -- | | | $ | -- | | | $ | -- | | | $ | -- | | | $ | -- | | | $ | -- | | | $ | 708 | |
_______________
| 1 | As part of the June 20, 2007 settlement, IBEW-represented employees with less than five years of service would no longer receive a medical subsidy at retirement and those employees with more than 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. |
| | | Qualified Pension Benefit | | | SERP Pension Benefits | | | Other Benefits | |
| (Dollars in Thousands) | | 2009 | | | 2008 | | | 2009 | | | 2008 | | | 2009 | | | 2008 | |
| Other changes (pre-tax) in plan assets and benefit obligations recognized in other comprehensive income: | | | | | | | | | | | | | | | | | | |
| Net loss (gain) | | $ | (28,610 | ) | | $ | 221,657 | | | $ | 707 | | | $ | 615 | | | $ | (2,794 | ) | | $ | 4,698 | |
| Amortization of net loss (gain) | | | (3,702 | ) | | | (945 | ) | | | (886 | ) | | | (731 | ) | | | 461 | | | | 799 | |
| Prior service cost (credit) | | | -- | | | | 5,325 | | | | -- | | | | -- | | | | -- | | | | -- | |
| Amortization of prior service cost | | | (1,134 | ) | | | (768 | ) | | | (616 | ) | | | (616 | ) | | | (83 | ) | | | (84 | ) |
| Amortization of transition (asset) obligation | | | -- | | | | -- | | | | -- | | | | -- | | | | (50 | ) | | | (50 | ) |
| Total change in other comprehensive income for year | | $ | (33,446 | ) | | $ | 225,269 | | | $ | (795 | ) | | $ | (732 | ) | | $ | (2,466 | ) | | $ | 5,363 | |
The estimated net loss (gain) and prior service cost (credit) for the pension plans that will be amortized from accumulated OCI into net periodic benefit cost in 2010 are $6.8 million and $0.7 million, respectively. The estimated net loss (gain), prior service cost (credit) and transition obligation (asset) for the other postretirement plans that will be amortized from accumulated OCI into net periodic benefit cost in 2010 total $0.6 million. The estimated net loss (gain) and prior service cost (credit) for the SERP that will be amortized from accumulated OCI into net periodic benefit cost in 2010 are $0.8 million and $0.6 million, respectively.
Assumptions
In accounting for pension and other benefit obligations and costs under the plans, the following weighted-average actuarial assumptions were used by the Company:
| | Qualified Pension Benefits | | SERP Pension Benefits | | Other Benefits |
| Benefit Obligation Assumptions | 2009 | 2008 | 2007 | | 2009 | 2008 | 2007 | | 2009 | 2008 | 2007 |
| Discount rate | 5.75% | 6.20% | 6.30% | | 5.75% | 6.20% | 6.30% | | 5.75% | 6.20% | 6.30% |
| Rate of compensation increase | 4.50% | 4.50% | 4.50% | | 4.50% | 4.50% | 4.50% | | 4.50% | 4.50% | -- |
| Medical trend rate | -- | -- | -- | | -- | -- | -- | | 7.50% | 8.00% | 9.00% |
| | | | | | |
| Benefit Cost Assumptions | | | | | | | | | | | |
| Discount rate | 6.50% 1 | 6.30% | 5.80% | | 6.50% 1 | 6.30% | 5.80% | | 6.50% 1 | 6.30% | 5.80% |
| Rate of plan assets | 8.25% | 8.25% | 8.25% | | -- | -- | -- | | 7.60% | -- | 3.9-8% |
| Rate of compensation increase | 4.50% | 4.50% | 4.50% | | 4.50% | 4.50% | 4.50% | | 4.50% | 4.50% | -- |
| Medical trend rate | -- | -- | -- | | -- | -- | -- | | 9.00% | 9.00% | 10.00% |
_______________
| 1 | 6.50% is the benefit cost discount rate used by Puget Energy. 6.20% is the benefit cost discount rate use by PSE. The discount rates for the net periodic costs for Puget Energy and PSE were different because of the discount rates in effect as of February 5, 2009, and December 31, 2008, respectively. |
The assumed medical inflation rate used to determine benefit obligations is 7.50% in 2010 grading down to 5.0% in 2011. A 1.0% change in the assumed medical inflation rate would have the following effects:
| | | 2009 | | | 2008 | |
| (Dollars in Thousands) | | 1% Increase | | | 1% Decrease | | | 1% Increase | | | 1% Decrease | |
| Effect on post-retirement benefit obligation | | $ | 131 | | | $ | 119 | | | $ | 184 | | | $ | (171 | ) |
| Effect on service and interest cost components | | | 7 | | | | 6 | | | | 12 | | | | (11 | ) |
The Company has selected the expected return on plan assets based on a historical analysis of rates of return and the Company’s investment mix, market conditions, inflation and other factors. The expected rate of return is reviewed annually based on these factors. The Company’s accounting policy for calculating the market-related value of assets for the Company’s retirement plan is as follows. PSE market-related value of assets is based on a five-year smoothing of asset gains/losses measured from the expected return on market-related assets. This is a calculated value that recognizes changes in fair value in a systematic and rational manner over five years. The same manner of calculating market-related value is used for all classes of assets, and is applied consistently from year to year.
Puget Energy’s pension and other postretirement benefits income or costs depend on several factors and assumptions, including plan design, timing and amount of cash contributions to the plan, earnings on plan assets, discount rate, expected long-term rate of return, mortality and health care costs trends. Changes in any of these factors or assumptions will affect the amount of income or expense that Puget Energy records in its financial statements in future years and its projected benefit obligation. Puget Energy has selected an expected return on plan assets based on a historical analysis of rates of return and Puget Energy’s investment mix, market conditions, inflation and other factors. As required by merger accounting rules, market-related value was reset to market value effective with the merger.
The discount rates were determined by using market interest rate data and the weighted-average discount rate from Citigroup Pension Liability Index Curve. The Company also takes into account in determining the discount rate the expected changes in market interest rates and anticipated changes in the duration of the plan liabilities.
The aggregate expected contributions by the Company to fund the retirement plan, SERP and the other postretirement plans for the year ending December 31, 2010 are $12.0 million, $3.0 million and $0.5 million, respectively.
Plan Benefits
The expected total benefits to be paid under the qualified pension plans for the next five years and the aggregate total to be paid for the five years thereafter are as follows:
| (Dollars in Thousands) | | 2010 | | | 2011 | | | 2012 | | | 2013 | | | 2014 | | | | 2015-2019 | |
| Total benefits | | $ | 31,200 | | | $ | 31,900 | | | $ | 33,300 | | | $ | 34,800 | | | $ | 35,400 | | | $ | 195,100 | |
The expected total benefits to be paid under the SERP for the next five years and the aggregate total to be paid for the five years thereafter are as follows:
| (Dollars in Thousands) | | 2010 | | | 2011 | | | 2012 | | | 2013 | | | 2014 | | | | 2015-2019 | |
| Total benefits | | $ | 2,978 | | | $ | 2,258 | | | $ | 2,891 | | | $ | 3,796 | | | $ | 3,198 | | | $ | 20,875 | |
The expected total benefits to be paid under the other benefits for the next five years and the aggregate total to be paid for the five years thereafter are as follows:
| (Dollars in Thousands) | | 2010 | | | 2011 | | | 2012 | | | 2013 | | | 2014 | | | | 2015-2019 | |
| Total benefits | | $ | 1,555 | | | $ | 1,553 | | | $ | 1,493 | | | $ | 1,424 | | | $ | 1,354 | | | $ | 5,836 | |
| Total benefits without Medicare Part D subsidy | | $ | 1,943 | | | $ | 1,942 | | | $ | 1,915 | | | $ | 1,868 | | | $ | 1,821 | | | $ | 8,146 | |
Plan Assets
Plan contributions and the actuarial present value of accumulated plan benefits are prepared based on certain assumptions pertaining to interest rates, inflation rates and employee demographics, all of which are subject to change. Due to uncertainties inherent in the estimations and assumptions process, changes in these estimates and assumptions in the near term may be material to the financial statements.
The Company has a Retirement Plan Committee that establishes investment policies, objectives and strategies designed to balance expected return with a prudent level of risk. All changes to the investment policies are reviewed and approved by the Retirement Plan Committee prior to being implemented.
The Retirement Plan Committee invests trust assets with investment managers who have historically achieved above-median long-term investment performance within the risk and asset allocation limits that have been established. Interim evaluations are routinely performed with the assistance of an outside investment consultant. To obtain the desired return needed to fund the pension benefit plans, the Retirement Plan Committee has established investment allocation percentages by asset classes as follows:
| | Allocation |
| Asset Class | Minimum | Target | Maximum |
| Domestic large cap equity | 25% | 32% | 40% |
| Domestic small cap equity | 0% | 10% | 15% |
| Non-U.S. equity | 10% | 20% | 30% |
| Tactical asset allocation | 0% | 5% | 10% |
| Fixed income | 15% | 23% | 30% |
| Real estate | 0% | 0% | 10% |
| Absolute return | 5% | 10% | 15% |
| Private equity funds | 0% | 0% | 0% |
| Cash | 0% | 0% | 5% |
Plan Fair Value Measurements
Effective December 31, 2009, ASC 715 directs companies to provide additional disclosures about plan assets of a defined benefit pension or other postretirement plan. The objectives of the disclosures are to disclose the following: (1) how investment allocation decisions are made, including the factors that are pertinent to an understanding of investment policies and strategies; (2) major categories of plan assets; (3) inputs and valuation techniques used to measure the fair value of plan assets; (4) effect of fair value measurements using significant unobservable inputs (Level 3) on changes in plan assets for the period; and (5) significant concentrations of risk within plan assets.
In September 2009, the FASB issued Accounting Standards Update (ASU) No. 2009-12, “Fair Value Measurements and Disclosures: Investments in Certain Entities that Calculate Net Asset Value per Share (or Its Equivalent).” The standard allows the reporting entity, as a practical expedient, to measure the fair value of investments that do not have readily determinable fair values on the basis of the net asset value per share of the investment if the net asset value of the investment is calculated in a matter consistent with ASC 946, “Financial Services – Investment Companies.” The standard requires disclosures about the nature and risk of the investments and whether the investments are probable of being sold at amounts different from the net asset value per share.
The following table sets forth by level, within the fair value hierarchy, the qualified pension plan assets at fair value that were accounted for at fair value on a recurring basis as of December 31, 2009:
Recurring Fair Value Measures (Dollars in Thousands) As of December 31, 2009 | | | | |
| Assets: | | Level 1 | | | Level 2 | | | Level 3 | | | Fair Value |
| Equities: | | | | | | | | | | | |
Non-US equity 1 | | $ | 50,890 | | | $ | 48,062 | | | $ | -- | | | $ | 98,952 | |
Domestic large cap equity 2 | | | 134,754 | | | | 24,641 | | | | -- | | | | 159,395 | |
Domestic small cap equity 3 | | | 49,513 | | | | -- | | | | -- | | | | 49,513 | |
| Total equities | | | 235,157 | | | | 72,703 | | | | -- | | | | 307,860 | |
Tactical asset allocation 4 | | | -- | | | | 25,469 | | | | -- | | | | 25,469 | |
Fixed income securities 5 | | | 43,244 | | | | 51,244 | | | | -- | | | | 94,488 | |
Absolute return 6 | | | -- | | | | -- | | | | 46,226 | | | | 46,226 | |
Cash and cash equivalents 7 | | | -- | | | | 9,588 | | | | -- | | | | 9,588 | |
| Subtotal | | $ | 278,401 | | | $ | 159,004 | | | $ | 46,226 | | | $ | 483,631 | |
| Net receivables | | | | | | | | | | | | | | | 1,629 | |
| Accrued income | | | | | | | | | | | | | | | 429 | |
| Total assets | | | | | | | | | | | | | | $ | 485,689 | |
__________________| 1 | Non – US Equity investments are comprised of a (1) mutual fund; and (2) commingled fund. The investment in the mutual fund is valued using quoted market prices multiplied by the number of shares owned as of December 31, 2009. The investment in the commingled fund is valued at the net asset value per share multiplied by the number of shares held as of December 31, 2009. |
| 2 | Domestic large cap equity investments are comprised of (1) common stock, and (2) commingled fund. Investments in common stock are valued using quoted market prices multiplied by the number of shares owned as of December 31, 2009. The investment in the commingled fund is valued at the net asset value per share multiplied by the number of shares held as of December 31, 2009. |
| 3 | Domestic small cap equity investments are comprised of common stock and are valued using quoted market prices multiplied by the number of shares owned as of December 31, 2009. |
| 4 | The tactical asset allocation investment are compromised of a commingled fund, which is valued at the net asset value per share multiplied by the number of shares held as of the measurement date. |
| 5 | Fixed income securities consist of a mutual fund, convertible securities, corporate bonds, and mortgage backed mortgage pools guaranteed by GNMA, FNMA and FHLMC. The investment in the mutual fund is valued using quoted market prices multiplied by the number of shares owned as of December 31, 2009. The other investments are valued using various valuation techniques and sources such as value generation models, broker quotes, benchmark yields and/or other applicable data. |
| 6 | Absolute return investments consist of a mutual fund and a partnership. The mutual fund is valued using the net asset value per share multiplied by the number of shares held as of December 31, 2009. The partnership is valued using the financial reports as of December 31, 2009. Both investments are a Level 3 under ASC 820 because the plan does not have the ability to redeem the investment in the near-term at the net asset value per share. |
| 7 | The investment consists of a money market fund, which is valued at the net asset value per share of $1.00 per unit as of December 31, 2009. The money market fund invests primarily in commercial paper, notes, repurchase agreements, and other evidences of indebtedness which are payable on demand or which have a maturity date not exceeding thirteen months from the date or purchase. |
Level 3 Roll-Forward
The following table sets forth a reconciliation of changes in the fair value of the plan’s Level 3 assets for the year ended December, 31, 2009:
| (Dollars in Thousands) | | Partnership | | | Mutual funds | | | total | |
| Balance as of December 31, 2008 | | $ | 20,514 | | | $ | 19,137 | | | $ | 39,651 | |
| Unrealized gains/(losses) relating to instruments still held at the reporting date | | | 2,700 | | | | 3,875 | | | | 6,575 | |
| Balance as of December 31, 2009 | | $ | 23,214 | | | $ | 23,012 | | | $ | 46,226 | |
The following table sets forth by level, within the fair value hierarchy, the Other Benefits plan assets at fair value as of December 31, 2009:
Recurring Fair Value Measures (Dollars in Thousands) as of December 31, 2009 | | | | | | | | | |
| Assets: | | Level 1 | | | Level 2 | | | Fair Value | |
Mutual fund 1 | | $ | 8,321 | | | $ | -- | | | $ | 8,321 | |
Cash equivalents 2 | | | -- | | | | 469 | | | | 469 | |
| Total assets | | $ | 8,321 | | | $ | 469 | | | $ | 8,790 | |
| 1 | This is a publicly traded balanced mutual fund that seeks regular income, conservation of principal, and an opportunity for long-term growth of principal and income. The fair value is determined by taking the number of shares owned by the plan, and multiplying by the market price as of December 31, 2009. |
| 2 | This is a deposit fund. The fair value is calculated by using the financial reports available as of December 31, 2009. |
The Company’s Long-Term Incentive Plan (LTI Plan), approved by the shareholders in 2005, encompasses many of the awards granted to employees. The LTI Plan applied to officers and key employees of the Company and awards granted under this plan included stock awards, performance awards, stock options and restricted stocks which were added to reduce the volatility of the plan. Any shares awarded were either purchased on the open market or were a new issuance. Certain plan participants who met or exceeded the Company’s stock ownership guidelines could elect to be paid up to 50.0% of the share award in cash. With the completion of the merger, all shares outstanding under the LTI Plan were fully vested and settled in cash to plan participants. Puget Energy paid and recognized $14.5 million merger expense in connection to the vesting of the LTI Plan shares.
Performance Share Grants
The Company generally awarded performance share grants annually under the LTI Plan. These were granted to key employees and vested at the end of three years. The number of shares awarded and the amount of expense recorded depended on Puget Energy’s performance as compared to other companies and service quality indices for customer service. Compensation expense related to performance share grants was $9.6 million, $3.7 million and $7.9 million for 2009, 2008 and 2007, respectively. The weighted-average fair value per performance share granted for the years ended 2008 and 2007 was $26.72 and $24.75, respectively.
Performance shares activity for the periods ended February 5, 2009 and December 31, 2008 was as follows:
| Predecessor | | Number of Shares | | | Weighted-Average Fair Value Per Share | |
| Performance Shares Outstanding at December 31, 2007: | | | 285,119 | | | $ | 23.60 | |
| Granted | | | 111,208 | | | | 26.72 | |
| Vested | | | (141,406 | ) | | | 22.52 | |
| Forfeited | | | (10,531 | ) | | | 23.56 | |
| Total at December 31, 2008: | | | 244,390 | | | $ | 25.65 | |
| Granted | | | -- | | | | -- | |
| Vested | | | (244,390 | ) | | | 25.65 | |
| Forfeited | | | -- | | | | -- | |
| Performance Shares Outstanding at February 5, 2009: | | | -- | | | | -- | |
Plan participants meeting the Company’s stock ownership guidelines could elect to be paid up to 50.0% of the share award in cash. The portion of the performance share grants that could be paid in cash was classified and accounted for as a liability. As a result, the compensation expense of these liability awards was recognized over the performance period based on the fair value (i.e. cash value) of the award, and was periodically updated based on expected ultimate cash payout. Compensation cost recognized during the performance period for the liability portion of the performance grants was based on the closing price of the Company’s common stock on the date of measurement and the number of months of service rendered during the period. The equity portion was valued at the closing price of the Company’s common stock on the grant date. In connection with the completion of the merger in 2009, all shares vested and the Company paid and recognized $9.6 million recorded in merger and related costs.
Stock Options
In 2002, Puget Energy’s Board of Directors granted 40,000 stock options under the LTI Plan and an additional 260,000 options outside the LTI Plan (for a total of 300,000 non-qualified stock options) to the President and Chief Executive Officer. These options could be exercised at the grant date market price of $22.51 per share and vested annually over four and five years. The fair value of the stock option award was estimated at $3.33 per share on the date of grant using the Black-Scholes option valuation model. The options were cancelled at the time of the merger and $2.3 million was paid in cash to the President and Chief Executive Officer based on the terms of the merger agreement.
Restricted Stock
Restricted stock activity for the twelve months ended December 31, 2009 and 2008 was as follows:
| Predecessor | Number of Shares | | | Weighted-Average Fair Value Per Share | |
| Restricted Stock Outstanding at December 31, 2007: | | 260,382 | | | $ | 22.98 | |
| Granted | | 91,115 | | | | 26.72 | |
| Vested | | (117,439 | ) | | | 22.99 | |
| Forfeited | | (6,415 | ) | | | 23.21 | |
| Restricted Stock Outstanding at December 31, 2008: | | 227,643 | | | $ | 24.64 | |
| Granted | | -- | | | | -- | |
| Vested | | (227,643 | ) | | | 24.64 | |
| Forfeited | | -- | | | | -- | |
| Restricted Stock Outstanding at February 5, 2009: | | -- | | | $ | -- | |
Compensation expense related to the restricted shares was $2.2 million and $2.4 million for 2009 and 2008, respectively.
Retirement Equivalent Stock
The Company has a retirement equivalent stock agreement under which in lieu of participating in the Company’s executive supplemental retirement plan, the President and Chief Executive Officer was granted performance-based stock equivalents in January of each year, which were deferred under the Company’s deferred compensation plan. Retirement equivalent stock activity was as follows:
| | | Number of Shares | | | Weighted -Average Fair Value Per Share | |
| Retirement Equivalent Stock Awarded: | | | | | | |
| 2007 | | | 9,476 | | | $ | 25.36 | |
| 2008 | | | 7,574 | | | | 27.43 | |
All shares vested in May 2008. Compensation expense related to the retirement equivalent stock agreement was $0.3 million and $0.1 million in 2008 and 2007, respectively. All equivalent stock units vested prior to the merger.
Non-Employee Director Stock Plan
Prior to February 6, 2009, when it was terminated, the Company had a director stock plan for all non-employee directors of Puget Energy and PSE. An amended and restated plan was approved by shareholders in 2005. Under the plan, which had a term through December 31, 2015, non-employee directors received a portion of their quarterly retainer fees in Puget Energy stock except that 100.0% of quarterly retainers were paid in Puget Energy stock until the director held a number of shares equal in value to two years of their retainer fees. Directors could choose to continue to receive their entire retainer in Puget Energy stock. The compensation expense related to the director stock plan was $0.4 million and $0.7 million in 2009 and 2008, respectively. As of December 31, 2008, the number of shares that had been purchased for the director stock plan was 62,362 and deferred was 121,253, for a total of 183,615 shares. The director stock plan was terminated on February 6, 2009 by action of the Board of Directors upon completion of the merger and director payments were paid in cash.
In May 2003, approximately 50 plaintiffs initiated an action against the owners of Colstrip alleging that: (1) seepage from two different wastewater pond areas caused groundwater contamination and threatened to contaminate domestic water wells and the Colstrip water supply pond; and (2) seepage from the Colstrip water supply pond caused structural damage to buildings and toxic mold. The defendants reached agreement on a global settlement with all plaintiffs on April 29, 2008 and PSE paid its share of the settlement in the amount of $10.7 million, net of insurance proceeds, in July 2008. PSE had previously expensed the settlement in the first quarter 2008. PSE has also filed an accounting petition with the Washington Commission to recover such costs over five years in its current electric rate proceeding. This matter is included in PSE’s pending general rate case and an order is expected in April 2010.
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. Discovery is ongoing and trial is scheduled to begin on May 16, 2011.
The federal Clean Air Mercury Rule, enacted by the Environmental Protection Agency (EPA) in May 2005, was vacated by the D.C. Circuit Court in February 2008. Final resolution of this matter is still pending. However, the Montana Board of Environmental Review approved a Montana mercury control rule to limit mercury emissions from coal-fired plants on October 16, 2006 (with a limit of 0.9 lbs/Trillion British thermal units (TBtu) for plants burning coal like that used at Colstrip) which remains in effect. In 2008 the Colstrip owners, based on testing performed in 2006, 2007 and 2008, ordered mercury control equipment intended to achieve the new limit. The equipment has been fully installed and is in regular operation. The Colstrip mercury control equipment is operating at a level that meets the current Montana limit, which is based on a rolling 12 month average so compliance cannot be fully confirmed until January 1, 2011. Optimization of the feed rates of calcium bromide and activated carbon is underway. Depending on actual long-term performance, an evaluation will be conducted to determine whether additional controls, if any, are necessary.
On June 15, 2005, 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 EPA’s BART requirements. PSE submitted a BART engineering analysis for Colstrip Units 1 & 2 in August 2007 and responded to an EPA request for additional analyses with an addendum in June 2008. PSE cannot yet determine the outcome.
A lawsuit was filed in February 2009 against the Colstrip operator related to a fatality that occurred at the plant in June 2008. Discovery ends April 1, 2010 and trial is scheduled for July 12, 2010. PSE’s level of exposure in this matter is currently unknown.
The details of income taxes on continuing operations are as follows:
| Puget Energy | | | | | | | |
| (Dollars In Thousands) | | 2006 | | 2005 | | 2004 | |
| Charged to operating expense: | | | | | | | |
| Current: | | | | | | | |
| Federal | | $ | 62,122 | | $ | 145,342 | | $ | 5,506 | |
| State | | | 979 | | | 1,936 | | | (21 | ) |
| Deferred - federal | | | 33,673 | | | (58,116 | ) | | 71,864 | |
| Deferred investment tax credits | | | (503 | ) | | (553 | ) | | (593 | ) |
| Total charged to operations | | | 96,271 | | | 88,609 | | | 76,756 | |
| Charged to miscellaneous income: | | | | | | | | | | |
| Current | | | (4,596 | ) | | (3,338 | ) | | (5,305 | ) |
| Deferred | | | 812 | | | 769 | | | 2,470 | |
| Total charged to miscellaneous income | | | (3,784 | ) | | (2,569 | ) | | (2,835 | ) |
| Cumulative effect of accounting change | | | 48 | | | (38 | ) | | -- | |
| Total income taxes | | $ | 92,535 | | $ | 86,002 | | $ | 73,921 | |
| | | Successor | | | Predecessor | | | | | | | |
Puget Energy (Dollars in Thousands) For Years Ended December 31 | | February 6, 2009 – December 31, 2009 | | | January 1, 2009 – February 5, 2009 | | | 2008 | | | 2007 | |
| Charged to operating expenses: | | | | | | | | | | | | |
| Current: | | | | | | | | | | | | |
| Federal | | $ | (161,087 | ) | | $ | 10,185 | | | $ | (16,625 | ) | | $ | 3,238 | |
| State | | | (988 | ) | | | 87 | | | | (85 | ) | | | (189 | ) |
| Deferred - federal | | | 244,116 | | | | (1,275 | ) | | | 76,616 | | | | 69,533 | |
| Total income taxes from continuing operations | | $ | 82,041 | | | $ | 8,997 | | | $ | 59,906 | | | $ | 72,582 | |
| Puget Sound Energy | | | | | | | |
| (Dollars In Thousands) | | 2006 | | 2005 | | 2004 | |
| Charged to operating expense: | | | | | | | |
| Current: | | | | | | | |
| Federal | | $ | 62,825 | | $ | 146,110 | | $ | 5,825 | |
| State | | | 979 | | | 1,936 | | | (21 | ) |
| Deferred - federal | | | 33,926 | | | (57,864 | ) | | 71,966 | |
| Deferred investment tax credits | | | (503 | ) | | (553 | ) | | (593 | ) |
| Total charged to operations | | | 97,227 | | | 89,629 | | | 77,177 | |
| Charged to miscellaneous income: | | | | | | | | | | |
| Current | | | 650 | | | (3,338 | ) | | (5,305 | ) |
| Deferred | | | 812 | | | 769 | | | 2,470 | |
| Total charged to miscellaneous income | | | 1,462 | | | (2,569 | ) | | (2,835 | ) |
| Cumulative effect of accounting change | | | 48 | | | (38 | ) | | -- | |
| Total income taxes | | $ | 98,737 | | $ | 87,022 | | $ | 74,342 | |
Puget Sound Energy (Dollars in Thousands) For Years Ended December 31 | | 2009 | | | 2008 | | | 2007 | |
| Charged to operating expenses: | | | | | | | | | |
| Current: | | | | | | | | | |
| Federal | | $ | (126,156 | ) | | $ | (13,103 | ) | | $ | 5,555 | |
| State | | | (901 | ) | | | (85 | ) | | | (189 | ) |
| Deferred - federal | | | 194,701 | | | | 74,070 | | | | 68,815 | |
| Total income taxes from continuing operations | | $ | 67,644 | | | $ | 60,882 | | | $ | 74,181 | |
The following reconciliation compares pre-tax book income at the federal statutory rate of 35%35.0% to the actual income tax expense in the Consolidated Statements of Income:
| Puget Energy | | | | | | | |
| (Dollars In Thousands) | | 2006 | | 2005 | | 2004 | |
| Income taxes at the statutory rate | | $ | 90,947 | | $ | 81,275 | | $ | 69,766 | |
| Increase (decrease): | | | | | | | | | | |
| Utility plant depreciation differences | | | 9,307 | | | 9,534 | | | 10,723 | |
| AFUDC excluded from taxable income | | | (7,987 | ) | | (4,536 | ) | | (2,270 | ) |
| Capitalized Interest | | | 5,806 | | | 3,026 | | | 1,471 | |
| Production Tax Credit | | | (7,019 | ) | | (564 | ) | | -- | |
| Other - net | | | 1,481 | | | (2,733 | ) | | (5,769 | ) |
| Total income taxes | | $ | 92,535 | | $ | 86,002 | | $ | 73,921 | |
| Effective tax rate | | | 35.6 | % | | 37.0 | % | | 37.1 | % |
| Puget Sound Energy | | | | | | | | |
| (Dollars In Thousands) | | 2006 | | 2005 | | 2004 | | |
| | | | Successor | | | Predecessor | | | | | | | |
Puget Energy (Dollars in Thousands) For Years Ended December 31 | | | February 6, 2009 – December 31, 2009 | | | January 1, 2009 – February 5, 2009 | | | 2008 | | | 2007 | |
| Income taxes at the statutory rate | | $ | 96,417 | | $ | 81,827 | | $ | 70,187 | | | $ | 89,620 | | | $ | 7,613 | | | $ | 75,069 | | | $ | 89,966 | |
| Increase (decrease): | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Utility plant depreciation differences | | | 9,307 | | | 9,534 | | | 10,723 | | |
| Production tax credit | | | | (13,871 | ) | | | (5,870 | ) | | | (23,112 | ) | | | (20,154 | ) |
| AFUDC excluded from taxable income | | | (7,987 | ) | | (4,536 | ) | | (2,270 | ) | | | (5,326 | ) | | | (1,771 | ) | | | (4,670 | ) | | | (5,055 | ) |
| Capitalized interest | | | 5,806 | | | 3,026 | | | 1,471 | | | | 5,028 | | | | 914 | | | | 3,653 | | | | 3,649 | |
| Production Tax Credit | | | (7,019 | ) | | (564 | ) | | -- | | |
| Utility plant differences | | | | 4,323 | | | | 1,472 | | | | 5,882 | | | | 6,032 | |
| Tenaska gas contract | | | | 3,049 | | | | 1,429 | | | | 3,198 | | | | 2,057 | |
| Transaction costs | | | | 201 | | | | 5,544 | | | | 2,266 | | | | -- | |
| Other - net | | | 2,213 | | | (2,265 | ) | | (5,769 | ) | | | (983 | ) | | | (334 | ) | | | (2,380 | ) | | | (3,913 | ) |
| Total income taxes | | $ | 98,737 | | $ | 87,022 | | $ | 74,342 | | | $ | 82,041 | | | $ | 8,997 | | | $ | 59,906 | | | $ | 72,582 | |
| Effective tax rate | | | 35.8 | % | | 37.2 | % | | 37.1 | % | | | 32.0 | % | | | 41.4 | % | | | 27.9 | % | | | 28.2 | % |
Puget Sound Energy (Dollars in Thousands) For Years Ended December 31 | | 2009 | | | 2008 | | | 2007 | |
| Income taxes at the statutory rate | | $ | 79,414 | | | $ | 78,266 | | | $ | 92,858 | |
| Increase (decrease): | | | | | | | | | | | | |
| Production tax credit | | | (19,741 | ) | | | (23,112 | ) | | | (20,154 | ) |
| AFUDC excluded from taxable income | | | (7,097 | ) | | | (4,670 | ) | | | (5,055 | ) |
| Capitalized interest | | | 5,942 | | | | 3,653 | | | | 3,649 | |
| Utility plant differences | | | 5,795 | | | | 5,882 | | | | 6,032 | |
| Tenaska gas contract | | | 4,478 | | | | 3,198 | | | | 2,057 | |
| Other - net | | | (1,147 | ) | | | (2,335 | ) | | | (5,206 | ) |
| Total income taxes | | $ | 67,644 | | | $ | 60,882 | | | $ | 74,181 | |
| Effective tax rate | | | 29.8 | % | | | 27.2 | % | | | 28.0 | % |
The Company’s deferred tax liability at December 31, 2006, 20052009 and 20042008 is composed of amounts related to the following types of temporary differences:
| Puget Energy | | | | | |
| (Dollars In Thousands) | | 2006 | | 2005 | |
| Utility plant and equipment | | $ | 736,368 | | $ | 700,415 | |
| Capitalized overhead costs | | | -- | | | 33,166 | |
| Other deferred tax liabilities | | | 96,486 | | | 97,197 | |
| Subtotal deferred tax liabilities | | | 832,854 | | | 830,778 | |
| Contributions in aid of construction | | | (58,038 | ) | | (49,171 | ) |
| Other deferred tax assets | | | (30,896 | ) | | (31,830 | ) |
| Subtotal deferred tax assets | | | (88,934 | ) | | (81,001 | ) |
| Total | | $ | 743,920 | | $ | 749,777 | |
Puget Energy (Dollars in Thousands) At December 31 | | Successor 2009 | | | Predecessor 2008 | |
| Utility plant and equipment | | $ | 930,946 | | | $ | 746,486 | |
| Regulatory asset for income taxes | | | 89,303 | | | | 95,417 | |
| Fair value of debt instruments | | | 86,047 | | | | -- | |
| Pensions and other compensation | | | 42,395 | | | | (62,837 | ) |
| Storm damage | | | 37,002 | | | | 42,037 | |
| Other deferred tax liabilities | | | 85,797 | | | | 47,963 | |
| Subtotal deferred tax liabilities | | | 1,271,490 | | | | 869,066 | |
| Fair value of derivative instruments | | | (75,964 | ) | | | (69,259 | ) |
| Production tax credit | | | (45,730 | ) | | | (25,990 | ) |
| Other deferred tax assets | | | (42,106 | ) | | | (33,490 | ) |
| Subtotal deferred tax assets | | | (163,800 | ) | | | (128,739 | ) |
| Total | | $ | 1,107,690 | | | $ | 740,327 | |
Puget Sound Energy (Dollars In Thousands) | | 2009 | | | 2008 | |
| Utility plant and equipment | | $ | 930,946 | | | $ | 746,486 | |
| Regulatory asset for income taxes | | | 89,303 | | | | 95,417 | |
| Storm damage | | | 37,002 | | | | 42,037 | |
| Other deferred tax liabilities | | | 77,917 | | | | 48,637 | |
| Subtotal deferred tax liabilities | | | 1,135,168 | | | | 932,577 | |
| Fair value of derivative instruments | | | (53,271 | ) | | | (69,259 | ) |
| Production tax credit | | | (45,730 | ) | | | (25,990 | ) |
| Pensions and other compensation | | | (35,290 | ) | | | (62,837 | ) |
| Other deferred tax assets | | | (43,082 | ) | | | (33,490 | ) |
| Subtotal deferred tax assets | | | (177,373 | ) | | | (191,576 | ) |
| Total | | $ | 957,795 | | | $ | 741,001 | |
The above amounts have been classified in the Consolidated Balance Sheets as follows:
| Puget Energy | | | | | | |
| (Dollars In Thousands) | | 2006 | | 2005 | | |
Puget Energy (Dollars in Thousands) | | | | | | | |
| Current deferred taxes | | $ | (1,175 | ) | $ | 10,968 | | | $ | (39,977 | ) | | $ | (75,135 | ) |
| Non-current deferred taxes | | | 745,095 | | | 738,809 | | | | 1,147,667 | | | | 815,462 | |
| Total | | $ | 743,920 | | $ | 749,777 | | | $ | 1,107,690 | | | $ | 740,327 | |
| Puget Sound Energy | | | | | |
| (Dollars In Thousands) | | 2006 | | 2005 | |
| Utility plant and equipment | | $ | 736,368 | | $ | 700,415 | |
| Capitalized overhead costs | | | -- | | | 33,166 | |
| Other deferred tax liabilities | | | 100,425 | | | 97,550 | |
| Subtotal deferred tax liabilities | | | 836,793 | | | 831,131 | |
| Contributions in aid of construction | | | (58,038 | ) | | (49,171 | ) |
| Other deferred tax assets | | | (30,897 | ) | | (31,830 | ) |
| Subtotal deferred tax assets | | | (88,935 | ) | | (81,001 | ) |
| Total | | $ | 747,858 | | $ | 750,130 | |
Puget Sound Energy (Dollars in Thousands) | | 2009 | | | 2008 | |
| Current deferred taxes | | $ | (38,781 | ) | | $ | (75,135 | ) |
| Non-current deferred taxes | | | 996,576 | | | | 816,136 | |
| Total | | $ | 957,795 | | | $ | 741,001 | |
The above amounts have been classified in the Consolidated Balance Sheets as follows:
| Puget Sound Energy | | | | | |
| (Dollars In Thousands) | | 2006 | | 2005 | |
| Current deferred taxes | | $ | (1,175 | ) | $ | 10,968 | |
| Non-current deferred taxes | | | 749,033 | | | 739,162 | |
| Total | | $ | 747,858 | | $ | 750,130 | |
The Company calculates its deferred tax assets and liabilities under SFAS No. 109, “Accounting for Income Taxes.” SFAS No. 109ASC 740. ASC 740 requires recording deferred tax balances, at the currently enacted tax rate, on assets and liabilities that are reported differently for income tax purposes than for financial reporting purposes. The utilization of deferred tax assets requires sufficient taxable income in the future years. ASC 740 requires a valuation allowance on deferred tax assets when it is more likely than not that the deferred tax asset will not be realized. The Company’s production tax credit carryforwards expire from 2026 through 2029.
For ratemaking purposes, deferred taxes are not provided for certain temporary differences. Because of prior and expected future ratemaking treatment for temporary differences for which flow-through tax accounting has been utilized, PSE has established a regulatory asset for income taxes recoverable through future rates related to those differences. The balance of this asset was $115.3 million at December 31, 2006temporary differences for which no deferred taxes have been provided, based on prior and $129.7 million at December 31, 2005.expected future ratemaking treatment.
IRS Audit
As a matter of course, the Company’s tax returns are routinely audited by federal, state and city tax authorities. In May of 2006, the IRS completed its examination of the company’s 2001, 2002 and 2003 federal income tax returns. The Company is formally appealing two IRS audit adjustments. The first adjustment relates to the receivable balance due from the California Independent System Operator (CAISO). The IRS claims that the deduction was not validaccounts for the 2003uncertain tax year and would require repayment of approximately $14.5 million in tax. Management of Puget Energy believes the deduction is valid and intends to vigorously defend the deduction. Any potential tax payment (excluding interest) would have no impact on earnings, as it would be recognized as a deferred tax asset. If the Company is unsuccessful, a charge for interest expense would apply.
The second IRS audit adjustment relates to the company’s accounting method with respect to capitalized internal labor and overheads. 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 audit, the IRS disallowed the deduction. On August 2, 2005, the Internal Revenue Service and the Treasury Department issued Revenue Ruling 2005-53 and related Regulations. The Revenue Ruling and the Regulations required utility companies, including PSE, to adopt a less advantageous method of accounting and to repay the accumulated tax benefits. Through September 30, 2005, the Company claimed $66.3 million in accumulated tax benefits. PSE accounted for the accumulated tax benefits as temporary differences in determining its deferred income tax balances. Consequently, the repayment of the tax benefits did not impact earnings but did have a cash flow impact of $33.2 million in the fourth quarter 2005 and $33.1 million in 2006. As of December 31, 2006, the full tax benefit had been repaid. There is some uncertainty in the new guidance. PSE believes that the new Regulations required the Company to repay the accumulated tax benefits over the 2005 and 2006 tax years and that the tax deductions claimed on the Company’s tax returns were appropriate based on the applicable statutes, Regulations, and case law in effect at the time. However, there is no assurance that PSE’s appeal will prevail. If the Company is unsuccessful, a charge for interest expense would apply.
On October 19, 2005, PSE filed an accounting petition with the Washington Commission to defer the capital costs associated with repayment of the deferred tax. The Washington Commission had reduced PSE’s ratebase by $72 million in its order of February 18, 2005. The accounting petition was approved by the Washington Commission on October 26, 2005, for deferral of additional capital costs beginning November 1, 2005 using PSE’s allowed net of tax rate of return. The Washington Commission granted amortization of these deferred carrying costs over two years, beginning January 13, 2007.
Accounting for Uncertainty in Income Taxes
In July 2006, FASB issued FIN 48, “Accounting for Uncertainty in Income Taxes, an Interpretation of FASB Statement No. 109,”position under ASC 740, 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 48statements. ASC 740 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%50.0% likelihood of being sustained.
FIN 48 was effective forAs of December 31, 2009 and 2008, the Company as of January 1, 2007. The change in net assets ashad no material unrecognized tax benefits. As a result, of adopting FIN 48 will be treated as a change in accounting method. The cumulative effect ofno interest or penalties were accrued for unrecognized tax benefits during the change will be recorded to retained earnings. Adjustments to regulatory accounts, if any, will be based on other applicable accounting standards.year.
For ASC 740 purposes, the Company has open tax years from 2006 through 2009. The Company is currentlyclassifies interest as interest expense and penalties as other expense in the process of evaluatingfinancial statements.
California Regulatory Asset
PSE has held a receivable relating to unpaid bills for power sold into the provisions of FIN 48markets maintained by the CAISO. At December 31, 2009, the net receivable for such sales was $21.2 million, which was reclassified to determine the potential impact, if any, the adoption will have on the Company’s financial statements.a regulatory asset. The adoption of FIN 48 is not expected to have a material impact on the Company’s retained earnings. Management’s estimated impact of adoptioncollectability is subject to change duethe outcome of the Washington Commission ruling on the accounting petition. On October 7, 2009, PSE filed an amended accounting petition requesting that the Washington Commission authorize PSE to potential changesdefer the net revenues from the sale of renewable energy credits (RECs) and carbon financial instruments (collectively, REC Proceeds) and use the revenues to: (1) provide funding for low income energy efficiency and renewable energy services, (2) credit a portion of the REC Proceeds to the California Receivable and (3) provide a credit to customers by offsetting the REC Proceeds against a regulatory asset. The accounting petition is an amended petition to the accounting petition originally filed in interpretationApril 2007 that requested deferred accounting treatment for renewable energy credits. The petition is scheduled for hearing in March 2010 and a Washington Commission order is anticipated in the first half of FIN 482010.
Proceedings Relating to the Western Power Market
The following discussion summarizes the status as of the date of this report of ongoing proceedings relating to the western power markets to which PSE is a party. PSE is vigorously defending the remaining claims. 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 will not materially and adversely affect PSE’s financial condition, results of operations or liquidity.
PSE Settlement of California Matters. On May 8, 2009, PSE and certain California parties filed a proposed settlement with FERC, seeking FERC’s approval to resolve all the matters and disputes pending between PSE and California parties relating to the western energy crisis. On July 1, 2009, FERC approved that settlement.
Under the settlement, PSE releases all claims to amounts held in, or presumed payable into, certain escrow accounts. In particular, the California Power Exchange and Pacific Gas & Electric delivered $59.9 million, plus up to $36.8 million in interest, from escrows they maintain to the California parties. The release of those funds fully satisfies all claims by the FASB or other regulatory bodiesCalifornia parties against PSE, and the finalizationCalifornia parties assume the risk of any shortfalls or adjustments that occur in those accounts.
The settlement resolves all claims by the California parties against PSE in all proceedings and resolves all claims by PSE against California energy purchasers in all proceedings, except that PSE retains any claims or defenses that pertain to the Pacific Northwest Refund Proceedings at FERC.
In addition to the FERC approval obtained on July 1, 2009, PSE’s settlement with the California parties was expressly conditioned upon two other actions: (1) the California Energy Commission’s approval as qualifying facilities under California renewable energy rules of PSE’s Wild Horse and Hopkins Ridge wind farms; and (2) the approval by the California Public Utility Commission of a renewable power agreement between PSE and Southern California Edison (SCE), under which PSE will sell qualifying renewable power to SCE in 2009 and 2010. PSE entered into the SCE contract in January 2009, and all required approvals for that contract were obtained by June 18, 2009.
Use of the Company’s adoption efforts.proceeds from the renewable power transaction, for ratemaking and accounting purposes, will be determined by the Washington Commission. PSE anticipates recovery of the net California receivable through this proceeding.
The settlement means that PSE’s exposure to western energy crisis claims is now limited to the Pacific Northwest Refund Proceeding, described previously and updated below.
Pacific Northwest Refund Proceeding. In October 2000, PSE filed a complaint at FERC (Docket No. EL01-10) against “all jurisdictional sellers” in the Pacific Northwest seeking prospective price caps consistent with any result FERC ordered for the California markets. In April 2009, the Ninth Circuit rejected the requests for rehearing filed in this matter and remanded the proceeding to FERC. FERC is now considering what response to take to the Court remand order, as petitions for review by the Supreme Court were denied on January 11, 2010. PSE intends to vigorously defend its position but is unable to predict the outcome of this matter.
Proceedings Related to Bonneville Power Administration
NOTE 14. Retirement Benefits
Petitioners in several actions in the Ninth Circuit against BPA asserted that BPA acted contrary to law in entering into or performing or implementing a number of agreements, including the amended settlement agreement (and the May 2004 agreement) between BPA and PSE regarding the REP. Petitioners in several actions in the Ninth Circuit against BPA also asserted that BPA acted contrary to law in adopting or implementing the rates upon which the benefits received or to be received from BPA during the October 1, 2001 through September 30, 2006 period were based. A number of parties 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.
On May 3, 2007, the Ninth Circuit issued an opinion in Portland Gen. Elec. v. BPA, Case No. 01-70003, in which proceeding the actions of BPA in entering into settlement agreements regarding the REP with PSE and with other investor-owned utilities were challenged. In this opinion, the Ninth Circuit granted petitions for review and held the settlement agreements entered into between BPA and the investor-owned utilities being challenged in that proceeding to be inconsistent with statute. On May 3, 2007, the Ninth Circuit also issued an opinion in Golden Northwest Aluminum v. BPA, Case No. 03-73426, in which proceeding the petitioners sought review of BPA’s 2002-2006 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 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.
In March 2008, BPA and PSE signed an agreement pursuant to which BPA made a payment to PSE related to the REP benefits for the fiscal year ended September 29, 2006, FASB30, 2008, which payment is subject to true-up depending upon the amount of any REP benefits ultimately determined to be payable to PSE.
In September 2008, BPA issued SFAS No. 158, “Employers’ Accountingits record of decision in its reopened WP-07 rate proceeding to respond to the various Ninth Circuit opinions. In this record of decision, BPA adjusted its fiscal year 2009 rates, determined the amounts of REP benefits it considered to have been improperly paid after fiscal year 2001 to PSE and the other regional investor-owned utilities, and determined that such amounts are to be recovered through reductions in REP benefit payments to be made over a number of years. The amount determined by BPA to be recovered through reductions commencing October 2007 in REP payments for Defined Benefit PensionPSE’s residential and Other Postretirement Plans.” SFAS No. 158small farm customers was approximately $207.2 million plus interest on unrecovered amounts to the extent that PSE receives any REP benefits for its customers in the future. However, these BPA determinations are subject to subsequent administrative and judicial review, which may alter or reverse such determinations. PSE and others, including a number of preference agency and investor-owned utility customers of BPA, in December 2008 filed petitions for review in the Ninth Circuit of various of these BPA determinations.
In September 2008, BPA and PSE signed a short-term Residential Purchase and Sale Agreement (RPSA) under which BPA is effectiveto pay REP benefits to PSE for fiscal years ending afterSeptember 30, 2009–2011. In December 15, 2006,2008, BPA and PSE signed another, long-term RPSA under which BPA is the year ended December 31, 2006to pay REP benefits to PSE for the Company. SFAS No. 158 was adopted prospectively as required by the statement. SFAS No. 158 requires the Company to report the overfunded or underfunded statusperiod October 2011 through September 2028. PSE and other customers of defined benefit postretirement plansBPA in December 2008 filed petitions for review in the Company’s consolidated balance sheet. An overfunded status would result inNinth Circuit of the recognitionshort-term and long-term RPSAs signed by PSE (and similar RPSAs signed by other investor-owned utility customers of an assetBPA) and an underfunded status would result in the recognitionBPA’s record of decision regarding such RPSAs. Generally, REP benefit payments under a liability. This amount is to be measured as the difference between the fair value of plan assets and the projected benefit obligation.
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.
In addition to providing pension benefits, the Company provides certain health care and life insurance benefits for retired employees. These benefits are provided principally through an insurance company whose premiumsRPSA are based on the amount, if any, by which a utility's average system cost exceeds BPA’s Priority Firm (PF) Exchange rate for such utility. The average system cost for a utility is determined using an average system cost methodology adopted by BPA. The average system cost methodology adopted by BPA and the average system cost determinations, REP overpayment determinations, and the PF Exchange rate determinations by BPA are all subject to FERC review or judicial review or both and are subject to adjustment, which may affect the amount of REP benefits paid during the year.
| | | Pension Benefits | | Other Benefits | |
| (Dollars in Thousands) | | 2006 | | | | 2006 | | 2005 | |
Change in benefit obligation: | | | | | | | | | |
| Benefit obligation at beginning of year | | | $ | 454,519 | | $ | 438,635 | | $ | 26,251 | | $ | 31,094 | |
| Service cost | | | | 12,554 | | | 11,549 | | | 361 | | | 305 | |
| Interest cost | | | | 24,668 | | | 23,855 | | | 1,522 | | | 1,409 | |
Amendment1 | | | | -- | | | -- | | | -- | | | 359 | |
| Actuarial loss (gain) | | | | 4,774 | | | 3,236 | | | 1,261 | | | (4,796 | ) |
| Benefits paid | | | | (27,505 | ) | | (22,756 | ) | | (2,189 | ) | | (2,120 | ) |
| Benefit obligation at end of year | | | $ | 469,010 | | $ | 454,519 | | $ | 27,206 | | $ | 26,251 | |
_______________1
| The Company has an amendment related to changes in eligibility criteria.
|
| | | Pension Benefits | | Other Benefits | |
| (Dollars in Thousands) | | 2006 | | 2005 | | 2006 | | 2005 | |
Change in plan assets: | | | | | | | | | |
| Fair value of plan assets at beginning of year | | | $ | 481,444 | | $ | 458,980 | | $ | 15,668 | | $ | 15,959 | |
| Actual return on plan assets | | | | 75,278 | | | 43,119 | | | 1,699 | | | 696 | |
| Employer contribution | | | | 3,391 | | | 2,101 | | | 669 | | | 1,133 | |
| Benefits paid | | | | (27,505 | ) | | (22,756 | ) | | (2,189 | ) | | (2,120 | ) |
| Fair value of plan assets at end of year | | | $ | 532,608 | | $ | 481,444 | | $ | 15,847 | | $ | 15,668 | |
| Funded status at end of year | | | $ | 63,598 | | $ | 26,925 | | $ | (11,359 | ) | $ | (10,583 | ) |
| | | Pension Benefits | | Other Benefits | |
| (Dollars in Thousands) | | 2006 | | 2005 | | 2006 | | 2005 | |
Amounts recognized in Statement of Financial Position consist of: | | | | | | | | | |
| Noncurrent assets | | | $ | 101,708 | | $ | -- | | $ | -- | | $ | -- | |
| Current liabilities | | | | (4,533 | ) | | -- | | | (50 | ) | | -- | |
| Noncurrent liabilities | | | | (33,577 | ) | | -- | | | (11,309 | ) | | -- | |
| Total | | | $ | 63,598 | | $ | -- | | $ | (11,359 | ) | $ | -- | |
Amounts recognized in Accumulated Other Comprehensive Income consist of: | | | | | | | | | | | | | | |
| Net loss (gain) | | | $ | 29,984 | | $ | -- | | $ | (6,341 | ) | $ | -- | |
| Prior service cost / (credit) | | | | 6,452 | | | -- | | | 2,862 | | | -- | |
| Transition obligations / (assets) | | | | -- | | | -- | | | 2,529 | | | -- | |
| Total | | | $ | 36,436 | | $ | -- | | $ | (950 | ) | $ | -- | |
The projected benefit obligation, fair value of plan assets and the funded status, measured as the difference between the fair value of plan assets and the benefit obligation for the non-qualified pension plan were $38.1 million, none, and $(38.1) million, respectively, as of December 31, 2006. For the qualified pension plan the projected benefit obligation, fair value of plan assets and the funded status were $430.9 million, $532.6 million and $101.7 million, respectively, as of December 31, 2006.
The projected benefit obligation, fair value of plan assets and the funded status of plan assets for the non-qualified pension plan, were $39.2 million, none, and $(39.2) million, respectively, as of December 31, 2005. For the qualified pension plan, the projected benefit obligation, fair value of plan assets, and the funded status were $415.3 million, $481.4 million and $66.1 million, respectively, as of December 31, 2005.
| | | Pension Benefits | | | Other Benefits | |
| (Dollars in Thousands) | | 2006 | | 2005 | | 2004 | | | 2006 | | 2005 | | 2004 | |
Components of net periodic benefit cost: | | | | | | | | | | | | | | |
| Service cost | | $ | 12,553 | | $ | 11,549 | | $ | 10,249 | | | $ | 361 | | $ | 305 | | $ | 283 | |
| Interest cost | | | 24,667 | | | 23,855 | | | 24,016 | | | | 1,522 | | | 1,409 | | | 1,736 | |
| Expected return on plan assets | | | (37,572 | ) | | (37,928 | ) | | (39,106 | ) | | | (871 | ) | | (878 | ) | | (858 | ) |
| Amortization of prior service cost | | | 2,341 | | | 2,867 | | | 3,033 | | | | 534 | | | 466 | | | 465 | |
| Amortization of net loss (gain) | | | 5,230 | | | 3,354 | | | 1,221 | | | | (273 | ) | | (612 | ) | | (332 | ) |
| Amortization of transition (asset) obligation | | | -- | | | (163 | ) | | (1,104 | ) | | | 418 | | | 418 | | | 418 | |
| Net periodic benefit cost (income) | | $ | 7,219 | | $ | 3,534 | | $ | (1,691 | ) | | $ | 1,691 | | $ | 1,108 | | $ | 1,712 | |
| | | Pension Benefits | | Other Benefits | |
| (Dollars in Thousands) | | 2006 | | 2005 | | 2006 | | 2005 | |
Other changes (pre-tax) in plan assets and benefit obligations recognized in other comprehensive income: | | | | | | | | | |
| (Increase) / decrease during year under SFAS 132R | | | $ | (497 | ) | $ | -- | | $ | -- | | $ | -- | |
| (Increase) / decrease due to adoption of SFAS 158 | | | | 29,647 | | | -- | | | (950 | ) | | -- | |
| Total change in other comprehensive income for year | | | $ | 29,150 | | $ | -- | | $ | (950 | ) | $ | -- | |
| | | Before Application of Statement 158 | | Adjustments | | After Application of Statement 158 | |
| (Dollars in Thousands) | | Pension Plan | | Other Benefits | | Pension Plan | | Other Benefits | | Pension Plan | | Other Benefits | |
Transition Adjustments for Statement of Financial Position: | | | | | | | | | | | | | |
| Prepaid benefit cost | | $ | 122,274 | | $ | -- | | $ | (122,274 | ) | $ | -- | | $ | -- | | $ | -- | |
| Accrued benefit (liability) | | | (33,056 | ) | | (12,309 | ) | | 33,056 | | | 12,309 | | | -- | | | -- | |
| Intangible asset | | | 4,027 | | | -- | | | (4,027 | ) | | -- | | | -- | | | -- | |
| Accumulated other comprehensive income, (pre-tax) | | | 6,789 | | | -- | | | 29,647 | | | (950 | ) | | 36,436 | | | (950 | ) |
| Noncurrent asset | | | -- | | | -- | | | 101,708 | | | -- | | | 101,708 | | | -- | |
| Current liability | | | -- | | | -- | | | (4,533 | ) | | (50 | ) | | (4,533 | ) | | (50 | ) |
| Noncurrent liability | | | -- | | | -- | | | (33,577 | ) | | (11,309 | ) | | (33,577 | ) | | (11,309 | ) |
| Total | | $ | 100,034 | | $ | (12,309 | ) | $ | -- | | $ | -- | | $ | 100,034 | | $ | (12,309 | ) |
The estimated net loss (gain) and prior service cost (credit) for the pension plans that will be amortized from accumulated other comprehensive income into net periodic benefit cost in 2007 are $4.7 million and $2.0 million, respectively. The estimated net loss (gain), prior service cost (credit) and transition obligation (asset) for the other postretirement plans that will be amortized from accumulated other comprehensive income into net periodic benefit cost in 2007 are $(0.2) million, $0.5 million and $0.4 million.
In accounting for pension and other benefit obligations and costs under the plans, the following weighted average actuarial assumptions were used:
| | | Pension Benefits | | Other Benefits | |
Benefit Obligation Assumptions | | 2006 | | 2005 | | 2004 | | 2006 | | 2005 | | 2004 | |
| Discount rate | | | 5.80 | % | | 5.60 | % | | 5.60 | % | | 5.80 | % | | 5.60 | % | | 5.60 | % |
| Rate of compensation increase | | | 4.50 | % | | 4.50 | % | | 4.50 | % | | -- | | | -- | | | -- | |
| Medical trend rate | | | -- | | | -- | | | -- | | | 10.00 | % | | 11.00 | % | | 12.00 | % |
| | | Pension Benefits | | Other Benefits | |
Benefit Cost Assumptions | | 2006 | | 2005 | | 2004 | | 2006 | | 2005 | | 2004 | |
| Discount Rate | | | 5.60 | % | | 5.60 | % | | 6.25 | % | | 5.60 | % | | 5.60 | % | | 6.25 | % |
| Return on plan assets | | | 8.25 | % | | 8.25 | % | | 8.25 | % | | 4.3-8 | % | | 4.3-8 | % | | 4.3-8.25 | % |
| Rate of compensation increase | | | 4.50 | % | | 4.50 | % | | 4.50 | % | | -- | | | -- | | | -- | |
| Medical trend rate | | | -- | | | -- | | | -- | | | 11.00 | % | | 12.00 | % | | 9.00 | % |
The assumed medical inflation rate used to determine benefit obligations is 10.0% in 2007 grading down to 6.0% in 2011. A 1% change in the assumed medical inflation rate would have the following effects:
| | | 2006 | | 2005 | |
| (Dollars in Thousands) | | 1% Increase | | 1% Decrease | | 1% Increase | | 1% Decrease | |
| Effect on post-retirement benefit obligation | | $ | 752 | | $ | (666 | ) | $ | 437 | | $ | (378 | ) |
| Effect on service and interest cost components | | | 42 | | | (38 | ) | | 30 | | | (27 | ) |
The Company has selected the expected return on plan assets based on a historical analysis of rates of return and the Company’s investment mix, market conditions, inflation and other factors. The expected rate of return is reviewed annually based on these factors and adjusted accordingly. The Company’s accounting policy for calculating the market-related value of assets for the Company’s retirement plan is as follows. The market-related value of assets is based on a five-year smoothing of asset gains/losses measured from the expected return on market-related assets. This is a calculated value that recognizes changes in fair value in a systematic and rational manner over five years. The same manner of calculating market-related value is used for all classes of assets, and is applied consistently from year to year.
The discount rate was determined by using market interest rate data and the weighted average discount rate from Citigroup Pension Liability Index Curve. The Company also takes into account in determining the discount rate the expected changes in market interest rates and anticipated changes in the duration of the plan liabilities.
The aggregate expected contributions by the Company to fund the pension and other benefit plans for the year ending December 31, 2007 are $4.5 million and $0.3 million, respectively. The full amount of the pension funding for 2007 is for the Company’s non-qualified supplemental retirement plan.
The fair value of the plan assets of the pension benefits and other benefits are invested as follows at December 31:
| | | 2006 | | 2005 | |
| | | Pension Benefits | | Other Benefits | | Pension Benefits | | Other Benefits | |
| Short-term investments and cash | | | 2.7 | % | | -- | | | 2.4 | % | | 1.9 | % |
| Equity securities | | | 62.9 | % | | -- | | | 62.3 | % | | -- | |
| Fixed income securities | | | 14.8 | % | | 13.4 | % | | 15.3 | % | | 17.3 | % |
| Mutual funds (equity and fixed income) | | | 19.6 | % | | 86.6 | % | | 20.0 | % | | 80.8 | % |
The expected total benefitsor to be paid under both plans for the next five years and the aggregate totalby BPA to be paid for the five years thereafter are as follows:
| (Dollars in Thousands) | 2007 | 2008 | 2009 | 2010 | 2011 | 2012-2016 |
| Total benefits | $33,797 | $31,578 | $32,817 | $35,350 | $35,028 | $197,315 |
The CompanyPSE. As discussed above, BPA has a Retirement Committee that establishes investment policies, objectives and strategies designeddetermined to balance expected return with a prudent level of risk. All changes to the investment policies are reviewed and approved by the Retirement Committee prior to being implemented.
The Retirement Committee contracts with investment managers who have historically achieved above-median long-term investment performance within the risk and asset allocation limits that have been established. Interim evaluations are routinely performed with the assistance of an outside investment consultant. To obtain the desired return needed to fund the pension benefit plans, the Retirement Committee has established investment allocation percentages by asset classes as follows:
| | | Allocation | |
| Asset Class | | Minimum | Target | Maximum |
| Short-term investments and cash | | | -- | | | -- | | | 5 | % |
| Equity securities | | | 40 | % | | 70 | % | | 95 | % |
| Fixed-income securities | | | 15 | % | | 30 | % | | 55 | % |
| Real estate | | | -- | | | -- | | | 10 | % |
On May 19, 2004, FASB issued FASB Staff Position No. 106-2, “Accounting and Disclosure Requirements Related to the Medicare Prescription Drug, Improvement and Modernization Act of 2003” as the result of the new Medicare Prescription Drug Improvement and Modernization Act which was signed into law in December 2003. The law provides a subsidy for plan sponsors that provide prescription drug benefits to Medicare beneficiaries that are equivalent to the Medicare Part D plan. Based on new Medicare regulations issued in May 2005, the Company determined that it provides benefits at a higher level than provided under Medicare Part D, and therefore would qualify for federal tax subsidies.
NOTE 15. Employee Investment Plans
The Company has qualified Employee Investment Plans under which employee salary deferrals and after-tax contributions are used to purchase several different investment fund options.
The Company’s contributions to the Employee Investment Plans were $7.9 million, $6.9 million and $6.3 million for the years 2006, 2005 and 2004, respectively. The Employee Investment Plan eligibility requirements are set forth in the plan documents.
NOTE 16. Stock-based Compensation Plans
Prior to 2006, the Company had various stock-based compensation plans which were accounted for according to APB No. 25, “Accounting for Stock Issued to Employees,” and related interpretations as allowed by SFAS No. 123, “Accounting for Stock-Based Compensation.” In 2003, the Company adopted the fair value based accounting of SFAS No. 123 using the prospective method under the guidance of SFAS No. 148, “Accounting for Stock-Based Compensation - Transition and Disclosure.” The Company applied SFAS No. 123 accounting to stock compensation awards granted subsequent to January 1, 2003, while grants prior to 2003 continued to be accounted for using the intrinsic value method of APB No. 25. Effective January 1, 2006, the Company adopted the fair value recognition provisions of SFAS No. 123R, “Share-Based Payment,” using the modified-prospective transition method. Under that transition method, compensation cost recognized in 2006 includes: (a) compensation cost for all share-basedreduce such payments granted prior to, but not yet vested as of January 1, 2006, based on the grant date fair value estimated in accordance with the original provisionsits determination of SFAS No. 123 and (b) compensation cost for all share-based payments granted subsequent to January 1, 2006, based on the grant date fair value estimated in accordance with the provisions of SFAS No. 123R. Results for prior periods have not been restated, as provided for under the modified-prospective method.REP benefit overpayments after fiscal year 2001.
The adoption of SFAS No. 123R resulted in a cumulative benefit from an accounting change of $0.1 million, net of tax, for the quarter ended March 31, 2006. The cumulative effect adjustment is the result of the inclusion of estimated forfeitures occurring before award vesting dates in the computation of compensation expense for unvested awards.
As a result of adopting SFAS No. 123R on January 1, 2006, the Company’s income before income taxes and net income from continuing operations at December 31, 2006, is $0.1 million and $0.1 million higher, respectively, than if it had continued to account for share-based compensation under SFAS No. 123 due to the inclusion of estimated forfeitures in compensation cost. There is no difference between basic and diluted earnings per share for income from continuing operations at December 31, 2006 under SFAS No. 123R as compared to earlier methods.
The Company’s Long-Term Incentive Plan (LTI Plan), established in 1995 after approval by shareholders, encompasses many of the awards granted to employees. The plan was amended and restated in 2005, and approved by shareholders. The LTI Plan applies to officers and key employees of the Company and awards granted under this plan include stock awards, performance awards or other stock-based awards as defined by the plan. Any shares awarded are either purchased on the open market or are a new issuance. The 2006 cycle included a grant of restricted stock, which was added to reduce the volatility of the plan. Beginning with the 2004 share grants, plan participants meeting the Company’s stock ownership guidelines can elect to be paid up to 50.0% of the share award in cash. The maximum number of shares that may be purchased or issued as new shares for the LTI Plan is 4,200,000.
Performance Share Grants
The Company generally awards performance share grants annually under the LTI Plan. These are granted to key employees and vest at the end of three years for grants made in 2004, 2005 and 2006. Grants made in 2003 vest over a four year period. The number of shares awarded and expense recorded depends on Puget Energy’s performance as compared to other companies and service quality indices for customer service.
Compensation expense related to performance share grants was $(1.6) million, $1.0 million and $2.5 million for 2006, 2005 and 2004, respectively. As of December 31, 2006, $3.0 million of total unrecognized compensation cost, net of forfeitures, related to nonvested performance share grants. That cost is expected to be recognized over a weighted-average period of 1.7 years. A summary of the performance shares activity is as follows:
Performance shares grants outstanding: | | 2006 | |
Beginning of Year | | | 907,983 | |
Granted | | | 152,254 | |
Vested | | | (40,851 | ) |
Cancelled* | | | (572,393 | ) |
Forfeited | | | (68,782 | ) |
End of Year | | | 378,211 | |
_______________
*
| Performance shares at December 31, 2006 were cancelled because performance modifiers were not achieved.
|
During 2006 there were four active grant cycles. The two remaining grants outstanding at December 31, 2006 were as follows:
| | | Performance Share Grants Cycles as of December 31, 2006 | |
| Performance share grants cycle: | | 2006 | | 2005 | |
| Number of awards granted | | | 152,254 | | | 251,660 | |
| Estimated forfeiture rate | | | 10.10 | % | | 11.80 | % |
| Estimated forfeited awards | | | 15,378 | | | 29,696 | |
| Weighted average fair value (per share) | | $ | 24.77 | | $ | 21.20 | |
Measurement of Performance Share Grants
The portion of the performance share grants that can be paid in cash is classified and accounted for as a liability under SFAS No. 123R. As a result, the expense recognized over the performance period for a portion of the performance share grants will equal the fair value (i.e. cash value) of the award as of the last day of the performance period times the number of awards that are earned. Furthermore, SFAS No. 123R requires that the quarterly expense recognized during the performance period is based on the fair value of the performance share grants as of the end of the most recent quarter. Prior to the end of the performance period, compensation costs for the liability portion of performance share grants are based on the awards’ most recent quarterly fair values and the number of months of service rendered during the performance period. The fair value of the performance share grants is based on the closing price of the Company’s common stock on the date of measurement. The fair value of the 2006 performance share grants takes into consideration the historical performance of the performance share grants and prospective analysis using the Capital Asset Pricing Model and expected EPS growth rates. Shares granted prior to 2006 were valued using the Black-Scholes option pricing model. A small percentage of the performance share grants are classified as equity awards because the employee does not have the option to receive the payment of these awards in cash. The equity portion is valued at the closing price of the Company’s common stock on the grant date.
Stock Options
In 2002, Puget Energy’s Board of Directors granted 40,000 stock options under the LTI Plan and an additional 260,000 options outside of the LTI Plan (for a total of 300,000 non-qualified stock options) to the Chairman, President and Chief Executive Officer. These options can be exercised at the grant date market price of $22.51 per share and vest annually over four and five years although the options would become fully vested upon a change of control of the Company or an employment termination without cause. The options expire 10 years from the grant date and have a remaining contractual term of approximately 6 years. All 300,000 options remained outstanding at December 31, 2006, with 270,000 options exercisable. At December 31, 2005, 202,500 options were exercisable. The fair value of the options at the grant date was $3.33 per share. Compensation expense related to stock options was immaterial to the financial statements for 2006. The total fair value of stock options vested during 2006 and 2005 was $0.2 million and $0.2 million, respectively. The fair value of the stock option award was estimated on the date of grant using the Black-Scholes option valuation model.
Restricted Stock
In 2006, 2005, 2004 and 2003, the Company granted 107,555 shares, 50,000 shares, 40,000 shares and 11,000 shares, respectively, of restricted stock under the LTI Plan to be purchased on the open market or as a new issuance. Under the 2006 grant, the shares vest 15.0% on January 1, 2007, 25.0% vest on January 1, 2008, and the remaining 60.0% vest on January 1, 2009 based upon a performance and service condition. Under the 2005 grant, 40,000 shares vest in one installment on the date of the 2008 Annual Shareholders’ Meeting based upon performance criteria and the remaining 10,000 shares vest equally over three years. The 2004 grant vests 8,000 shares in three years and the remaining 32,000 shares in four years. For the 2003 grant, 1,000 vested in 2003 with the remaining shares vesting evenly over the following five years.
At December 31, 2006, there were 205,656 total shares of nonvested restricted stock and the weighted average grant date fair value of these shares was $22.02. There was $1.7 million of total unrecognized compensation cost related to nonvested restricted stock at December 31, 2006. That cost is expected to be recognized over a weighted-average period of 1.6 years. Compensation expense related to the restricted shares was $2.0 million and $0.7 million for 2006 and 2005, respectively. Dividends are paid on all outstanding shares of restricted stock and are accounted for as a Puget Energy common stock dividend, not as compensation expense. The weighted average grant date fair value for all outstanding shares of restricted stock granted in 2006 and 2005 was $21.32 and $21.86, respectively. During 2006, 15,333 shares of restricted stock vested and 2,566 shares of restricted stock were forfeited. No restricted stock was forfeited during 2005. The fair value of the restricted stock is based on the closing price of the Company’s common stock on the date of grant.
Restricted Stock Units
In 2004, the Company granted 10,000 restricted stock units outside of the LTI Plan but subject to the terms and conditions of the plan. The units vest 2,000 shares in three years and the remaining 8,000 shares in four years. At December 31, 2006, there were 10,000 total shares of nonvested restricted stock units and the weighted average fair value of these units was $25.36. There was $0.1 million of total unrecognized compensation cost related to nonvested restricted stock units as of December 31, 2006. That cost is expected to be recognized over a weighted-average period of 1.3 years. There were no restricted stock units granted or forfeited during 2006 and 2005. The restricted stock units will be settled in cash when they become vested at the end of each cycle. Dividends are paid on the outstanding stock units and are accounted for as compensation expense. Compensation expense related to the restricted stock units agreement was $0.1 million for 2006 and 2005. The fair value of the restricted stock units is based on the closing price of the Company’s common stock at each reporting period.
Retirement Equivalent Stock
The Company has a retirement equivalent stock agreement under which in lieu of participating in the Company’s executive supplemental retirement plan, the Chairman, President and Chief Executive Officer is granted performance-based stock equivalents in January of each year, which are deferred under the Company’s deferred compensation plan. In 2006, 2005, 2004 and 2003, the Company awarded 8,218, 6,063, 6,469 and 4,319 shares, respectively, which vest over a period from January 1, 2002 to May 2008 at 15.0% per year for the first six years and the remaining 10.0% in the seventh year. The weighted average grant date fair value for the retirement equivalent stock was $20.42, $24.70, $23.77 and $22.05 for 2006, 2005, 2004 and 2003, respectively.
At December 31, 2006, there were 6,268 total shares of nonvested retirement equivalent stock units and the weighted average grant date fair value of these units was $22.60. There was $0.1 million unrecognized compensation cost related to nonvested retirement equivalent stock units as of December 31, 2006. That cost is expected to be recognized over a weighted-average period of 1.4 years. The equivalent value of dividends is paid on the accumulated retirement equivalent stock units and added to the deferred compensation account. Compensation expense related to the retirement equivalent stock agreement was $0.2 million and $0.1 million in 2006 and 2005, respectively. During 2006, 8,043 retirement equivalent stock units vested. The fair value of the restricted stock is based on the closing price of the Company’s common stock on the date of grant.
Employee Stock Purchase Plan
The Company has a shareholder-approved Employee Stock Purchase Plan (ESPP) open to all employees. Offerings occur at six-month intervals at the end of which the participating employees receive shares for 85.0% of the lower of the stock’s fair market price at the beginning or the end of the six-month period. A maximum of 500,000 shares may be sold to employees under the plan through May 2007. At December 31, 2006, 82,318 shares could still be sold to employees under the plan. In 2006 and 2005, 66,496 and 58,132 shares were issued for the ESPP, respectively. Under SFAS No. 123 accounting that the Company adopted in 2003 and under SFAS No. 123R, the ESPP is considered to be compensatory and the amount is immaterial to the financial statements. Dividends are not paid on ESPP shares until they are purchased by employees and thus are accounted for as dividends, not compensation expense.
Non-Employee Director Stock Plan
The Company has a director stock plan for all non-employee directors of Puget Energy and PSE. An amended and restated plan was approved by shareholders in 2005. Under the plan, which has a term through December 31, 2015, non-employee directors receive a portion of their quarterly retainer fees in Puget Energy stock except that 100.0% of quarterly retainers are paid in Puget Energy stock until the director holds a number of shares equal in value to two years of their retainer fees. Directors may choose to continue to receive their entire retainer in Puget Energy stock. The compensation expense related to the director stock plan was $0.5 million and $0.4 million in 2006 and 2005, respectively. The Company issues new shares or purchases stock for this plan on the open market up to a maximum of 350,000 shares. As of December 31, 2006, 34,166 shares had been issued or purchased for the director stock plan and 92,807 deferred, for a total of 126,973 shares. As of December 31, 2005, the number of shares that had been purchased for the director stock plan was 25,221 and deferred was 77,741, for a total of 102,962 shares.
Option Model Assumptions
The Company used the Black-Scholes option pricing model to determine the fair value of certain stock-based awards to employees. The following assumptions were used for awards outstanding in 2006 and 2005.
| Stock issuance cycle | | 2006 | | 2005 | | 2004 | | 2003 | | 2002 | |
| Stock options | | | | | | | | | | | |
| Risk-free interest rate | | | * | | | * | | | * | | | * | | | 4.32 | % |
Expected lives - years | | | * | | | * | | | * | | | * | | | 4.5 | |
| Expected stock volatility | | | * | | | * | | | * | | | * | | | 23.62 | % |
| Dividend yield | | | * | | | * | | | * | | | * | | | 5.00 | % |
| Performance awards | | | | | | | | | | | | | | | | |
| Risk-free interest rate | | | ** | | | 2.50 | % | | 2.59 | % | | 2.35 | % | | * | |
Expected lives - years | | | 3.0 | | | 3.0 | | | 3.0 | | | 4.0 | | | * | |
| Expected stock volatility | | | ** | | | 15.10 | % | | 22.24 | % | | 23.85 | % | | * | |
| Dividend yield | | | * | | | 4.18 | % | | 4.45 | % | | 4.86 | % | | * | |
| Employee Stock Purchase Plan | | | | | | | | | | | | | | | | |
| Risk-free interest rate | | | 4.96 | % | | 2.68 | % | | 1.28 | % | | 1.07 | % | | * | |
Expected lives - years | | | 0.5 | | | 0.5 | | | 0.5 | | | 0.5 | | | * | |
| Expected stock volatility | | | 9.79 | % | | 13.98 | % | | 9.89 | % | | 19.47 | % | | * | |
| Dividend yield | | | 4.55 | % | | 4.17 | % | | 4.42 | % | | 4.39 | % | | * | |
_______________*
| Not applicable
|
**
| Fair value is determined by end of period market value.
|
The expected lives of the securities represent the estimated period of time until exercise and are based on the vesting period of the award and the historical exercise experience of similar awards. All participants were assumed to have similar exercise behavior. Expected volatility is based on historical volatility over the approximate expected term of the option.
NOTE 17. Accounting for Derivative Instruments and Hedging Activities
SFAS No. 133, “Accounting for Derivative Instruments and Hedging Activities,” as amended by SFAS No. 138 and SFAS No. 149, requires that all contracts considered to be derivative instruments be recorded on the balance sheet at their fair value. The Company enters into contracts to manage its energy resource portfolio and interest rate exposure including forward physical and financial contracts, option contracts and swaps. The majority of these contracts qualify for the normal purchase normal sale (NPNS) exception to derivative accounting rules if they meet certain criteria. Generally, NPNS applies if PSE deems the counterparty creditworthy, has energy resources within the western region to allow for physical delivery of the energy and if the transaction is within PSE’s forecasted load requirements. Those 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 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 CompanyIt is not engaged in the businessclear what impact, if any, such development or review of assuming risk for the purposesuch BPA rates, average system cost, average system cost methodology, and BPA determination 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 territoryREP overpayments, review of the Company and are relevant to its regulated electric and gas portfolios.
The Company’s energy portfolio management staff develops hedging strategies for the Company’s energy supply portfolio. The first priority is to obtain reliable supply for delivery to the Company’s retail customers. The second priority is to protect against unwanted risk exposure. The third priority is to optimize excess capacity or flexibility within the energy portfolio. At December 31, 2006, the Company was subject to a range of netting provisions, including both stand alonesuch agreements, and the provisions associated with the Western Systems Power Pool agreement, of which many energy suppliers in the western United States are a part.above described Ninth Circuit litigation may ultimately have on PSE.
During the twelve months ended December 31, 2006, 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 approximately $0.1 million compared to a decrease in earnings of approximately $0.5 million and an increase of $0.5 million for the twelve months ended December 31, 2005 and December 31, 2004 respectively.
At December 31, 2006, the Company had a net unrealized gain recorded in other comprehensive income of $4.9 million after-tax related to energy contracts which meet the criteria for designation as cash flow hedges under SFAS No. 133. The amount of cash flow hedges associated with these energy contracts that will reverse and be settled into the income statement during 2007 is approximately $0.7 million. At December 31, 2006, PSE had a short-term asset of $9.2 million and a long-term asset of $6.8 million as well as short-term liability of $8.0 million and a long-term liability of $0.4 million related to energy contracts designated as cash flow hedges that represent forward financial purchases of gas supply for electric generation from PSE-owned electric plants in future periods. If it is determined that it is uneconomical to run the plants in the future period, the hedging relationship is ended and the cash flow hedge is de-designated and any unrealized gains and losses are recorded in the income statement. Gains and losses when these de-designated cash flow hedges are settled are recognized in energy costs and are included as part of the PCA mechanism. At December 31, 2005, the Company had an unrealized gain recorded in other comprehensive income of $43.2 million (net of tax), before SFAS No. 71 deferrals of $6.3 million, related to energy contracts which met the criteria for designation as cash flow hedges under SFAS No. 133. This was mainly the result of higher forward market prices for natural gas and electricity at December 31, 2005 compared to December 31, 2006.At December 31, 2006, the Company also had a short-term asset of $6.8 million and a short-term liability of approximately $61.6 million and a long-term asset of $0.1 million related to the hedge of gas contracts to serve natural gas customers. All mark-to-market adjustments relating to the natural gas business have been reclassified to a deferred account in accordance with SFAS No. 71 due to the purchased gas adjustment (PGA) mechanism. 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 December 31, 2005, the company had a net asset of $25.7 million related to the hedge of gas contracts to serve natural gas customers.
In the second quarter 2006, the Company settled two forward starting swap contracts originating in May 2005. The purpose of the forward starting swap contracts was to hedge a debt offering of $200.0 million that was completed on June 30, 2006. PSE received $21.3 million from the counterparties when the contracts were settled. The forward starting swap contracts were designated and documented under SFAS No. 133 criteria as cash flow hedges, with all changes in market value for each reporting period presented net of tax in other comprehensive income. In the second quarter 2006, the settlement of these instruments resulted in a gain of $13.9 million after-tax, which was recorded in other comprehensive income.
In the third quarter 2006, the Company settled two forward starting swap contracts originating in September 2006. The purpose of the forward starting swap contracts was to hedge a $300.0 million debt offering that was priced on September 13, 2006. PSE paid $0.6 million to the counterparties when the contracts were settled. The forward starting swap contracts were designated and documented under SFAS No. 133 criteria as cash flow hedges, with all changes in market value presented net of tax in other comprehensive income. In the third quarter of 2006, the settlement of these instruments resulted in a loss of $0.4 million after-tax, which was recorded in other comprehensive income. In accordance with SFAS No. 133, the loss will be amortized out of other comprehensive income to current earnings as an increase to interest expense over the life of the new debt issued.
The ending balance in other comprehensive income related to swaps contracts at December 31, 2006 was a loss of $8.5 million after-tax and accumulated amortization. This compares to a loss of $22.4 million in other comprehensive income after-tax and accumulated amortization at December 31, 2005 related to forward starting swaps and previously settled treasury lock contracts.
In May 2003, approximately 50 plaintiffs broughtaccordance with ASC 810, “Consolidation” (ASC 810), a variable interest entity (VIE) is an action againstentity in which the ownersinvestors as a group do not have: (1) the characteristics of Colstrip which has since been amended to add additional claims. The lawsuit alleges that certain domestic water wells anda controlling financial interest in 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. In December 2005, Colstrip Unit 1 & 2 owners extended city water to certain residents who lived near the plant, including the domestic well plaintiffs. Discovery is ongoing and the case is currently scheduled for trial in January 2008.
On May 18, 2005, the Environmental Protection Agency (EPA) enacted the Clean Air Mercury Rule (CAMR) that will permanently cap and reduce mercury emissions from coal-fired power plants. The Montana Board of Environmental Review approved a more stringent rule to limit mercury emissions from coal-fired plants on October 16, 2006 (0.9 lbs/TBtu, insteadequity of the federal 1.4 lbs/TBtu). The Colstrip owners are still evaluating the potential impact of the new Montana rule and it is still unknown whether the new rule will be appealed. Preliminary treatment technology studies undertaken by the Colstrip owners estimate that PSE’s portion of the costs to comply with the new rule could be as much as $75.0 million in construction expenditures, but this number could change as new information becomes available.
In December 2003, the EPA issued an Administrative Consent Order (ACO) which alleged violation of the Clean Air Act permit requirement to submit, for review and approval by the EPA, an analysis and proposal for reducing emissions of nitrogen oxide to address visibility concerns upon the occurrence of certain triggering events which EPA asserts occurred in 1980. Although Colstrip owners believe that the ACO is unfounded, the Colstrip owners signed a settlement agreement in December 2006 that is now awaiting signature by the EPA, and then will be entered by the court. The agreement includes installation of low nitrogen oxide equipment installation on Colstrip Units 3 & 4 which will cost PSE approximately $2.65 million.
On June 15, 2005, the 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 requirements for electric generating units, including presumptive limits for sulfur dioxide and nitrogen oxide controls for large units. Colstrip was originally required to submit analyses of visibility impacts for Colstrip 1 & 2 by December 2006 but the EPA has not yet completed the required preliminary analyses. PSE cannot yet determine the need for or costs of additional controls to comply with this rule, which could be significant.
NOTE 19. Taxes Other Than Income Taxes
| (Dollars in thousands) | | 2006 | | 2005 | | 2004 | |
| Taxes other than income taxes: | | | | | | | |
| Real estate and personal property | | $ | 39,832 | | $ | 44,472 | | $ | 43,843 | |
| State business | | | 107,140 | | | 93,893 | | | 82,408 | |
| Municipal and occupational | | | 97,671 | | | 85,154 | | | 72,405 | |
| Other | | | 33,144 | | | 30,841 | | | 27,766 | |
| Total taxes other than income taxes | | $ | 277,787 | | $ | 254,360 | | $ | 226,422 | |
| Charged to: | | | | | | | | | | |
| Operating expense | | $ | 255,712 | | $ | 233,742 | | $ | 208,989 | |
| Other accounts, including construction work in progress | | | 22,075 | | | 20,618 | | | 17,433 | |
| Total taxes other than income taxes | | $ | 277,787 | | $ | 254,360 | | $ | 226,422 | |
NOTE 20. Regulation and Rates
Electric Regulation and Rates
Storm Damage Deferral Accounting
On February 18, 2005, the Washington Commission issued a general rate case order that defined deferrable catastrophic/extraordinary losses and provided that costs in excess of $7.0 million annually may be deferred for qualifying storm damage costs that meet the IEEE outage criteria for system average interruption duration index. In 2006, PSE incurred $103.2 million in storm-related electric transmission and distribution system restoration costs, of which $92.3 million was deferred for future recovery in electric rates and will be determined in a future general rate case.
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 are 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 power cost only rate case (PCORC) increase of $96.1 million annually effective July 1, 2006.
Power Cost Only Rate Case
PCORC, a limited-scope proceeding, was created in 2002 by the Washington Commission to periodically reset power cost rates. The main objective of the PCORC proceeding is to provide for timely review of new resource acquisitions costs and inclusion of such costs in rates at the time the new resource goes into service. To achieve this objective, the Washington Commission agreed to an expedited five-month PCORC decision timeline rather than the statutory 11-month timeline for a general rate case.
On October 20, 2005, the Washington Commission approved a PCORC filing that increased electric rates 3.7% or $55.6 million annually. Included in the increase is the recovery of capital and operating costs of the Hopkins Ridge wind generating facility. The Hopkins Ridge wind generating facility was completed on November 27, 2005. As a wind generating facility, Hopkins Ridge is eligible for Federal Production Tax Credits (PTCs) that will ultimately offset some of the costs associated with generating power from Hopkins Ridge. The PTC is a tax credit provided by the Federal government for generating electricity from certain renewable resources. The current amount of the tax credit is $0.019 per kilowatt hour (kWh) for wind generation and may be subject to inflation adjustments over time. The tax credit can be claimed for 10 years for a new wind project put into service prior to January 1, 2008. The use of the credit is restricted to offset only 25% of current taxes payable. Unused credits can be carried forward for up to 20 years.
In the Washington Commission’s October 2005 order, a new tariff schedule was approved which provides for the pass through to ratepayers of all benefits of the PTCs for the Hopkins Ridge project. This mechanism (a PTC Tracker) will pass through to the customer the actual production tax credits of the Hopkins Ridge project as they are generated. The PTC Tracker would not be subject to the sharing bands in the PCA. The credits passed through to the customer will be adjusted by the carrying costs of unused PTCs. Since the customer is receiving the benefit of the tax credits as they are generated and the Company does not receive a credit from the IRS until the tax credits are utilized, the Company is reimbursed its carrying costs for funds through this calculation.
Production Tax Credit
On October 30, 2006, PSE revised its PTC electric tariff to increase the 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.
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 1.0% of the excess. In October 2005, the Washington Commission approved a shift to an annual PCA 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 (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 | July-December 2006 Power Cost Variability1 | Customers’ Share | Company’s Share2 |
| +/- | $20 million | +/- | $10 million | 0 | % | 100 | % |
| +/- | $20 - $40 million | +/- | $10 - $20 million | 50 | % | 50 | % |
| +/- | $40 - $120 million | +/- | $20 - $60 million | 90 | % | 10 | % |
| +/- | $120 million | +/- | $60 million | 95 | % | 5 | % |
_____________
1
| In October 2005, the Washington Commission in its Power Cost Only Rate Case order allowed for a reduction to the power cost variability amounts to half the annual power cost variability for the period July 1, 2006 through December 31, 2006.
|
2
| Over the four-year period July 1, 2002 through June 30, 2006, the Company’s share of pre-tax power cost variations is capped at a cumulative $40.0 million plus 1.0% of the excess. Power cost variation after December 31, 2006 will be apportioned on a calendar year basis, without a cumulative cap.
|
On April 26, 2006, the Washington Commission approved an accounting petition on a temporary basis to defer an $89.0 million one-time capacity reservation charge along with accrual of interest at the authorized after-tax rate of return. As part of the general rate case order of January 5, 2007, the Washington Commission approved the regulatory accounting treatment that had been approved in the accounting petition. The payment was made in relation to an agreement for the purchase of power from Chelan County PUD (Chelan). PSE and Chelan have entered into an agreement which provides for the purchase of 25.0% of the output of Chelan’s Rock Island (622 megawatts (MW)) and Rocky Reach (1,237 MW) dams on the Columbia River. The agreement called for PSE to make a one-time payment of $89.0 million on April 27, 2006. Then, upon the expiration of the existing contracts in 2011, PSE will begin purchasing 25.0% of the output at the projects’ costs for the next 20 years.
On January 25, 2006, the Washington Commission approved an accounting order to defer, as a regulatory liability, two payments in the amount of $42.0 million and $13.0 million received from Duke Energy Trading and Marketing (Duke) in December 2005 in return for assuming the gas transportation capacity on Northwest Pipeline and Westcoast Pipeline from Duke Energy Trading and Marketing. The regulatory liability will be amortized to gas costs from January 2006 through October 2017 based upon the approved schedule. These credits are an offset to gas transportation costs that are in excess of PSE’s gas transportation capacity needs. The $42.0 million payment was received to compensate the Company for the Northwest capacity payments that must be made until February 2011 when the capacity will be needed to serve load. The $13.0 million payment was received to compensate the Company for the difference between the assumed tariff rates and market value of the Westcoast Pipeline capacity through October 2017.
On April 7, 2004, the Washington Commission approved PSE’s recovery on the unamortized White River plant investment. At December 31, 2006, the White River project net book value totaled $69.1 million, which included $43.4 million of net utility plant, $17.1 million of capitalized FERC licensing costs, $4.3 million of costs related to construction work in progress and $1.8 million related to dam operations and safety. On February 18, 2005, the Washington Commission approved the recovery of the White River net utility plant costs but did not allow current recovery of FERC licensing costs and other related costs until all costs associated with selling the White River plant and any sales proceeds are known. Any proceeds from the sale of the White River assets and water rights will reduce the balance of the deferred regulatory asset. Neither the outcome of this matter nor any potential associated financial impacts can be predicted at this time.
Gas Regulation and Rates
Gas General Rate Case
On January 5, 2007, the Washington Commission issued its order in PSE’s gas general rate case, granting an increase for gas customers of $29.5 million or 2.8% annually, effective beginning 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 capital structure that included 44.0% common equity with a return on equity of 10.4%, consistent with the Company’s electric operations.
Purchased Gas Adjustment
PSE has a PGA mechanism in retail gas rates to recover variations in gas supply and transportation costs. Variations in gas rates are passed through to customers, therefore PSE’s gas margin and net income are not affected by such variations. On September 27, 2006, the Washington Commission approved a revision of PSE's PGA tariff schedule that went into effect on October 1, 2006. The tariff changes will increase gas revenue approximately $95.1 million, or 9.9%, on an annual basis. The rate increase authorized PSE to recover higher projected future gas and gas transportation costs, as well as to collect an accumulated deficit (receivable) balance in its PGA balancing account over a 24-month period (beginning October 1, 2006). The PGA rate change will increase PSE's gas revenue, but will not impact the Company's net income as the increased revenue will be offset by increased purchased gas costs. The following rate adjustments were approved by the Washington Commission in relation to the PGA mechanism during 2006, 2005 and 2004:
| Effective Date | Percentage Increase in Rates | Annual Increase in Revenues (Dollars In Millions) |
| October 1, 2006 | 10.2% | $ 95.1 |
| October 1, 2005 | 14.7% | 121.6 |
| October 1, 2004 | 17.6% | 121.7 |
The Washington Commission issued an order on May 13, 2004 determining that PSE did not prudently manage gas costs for the Tenaska electric generating plant and ordered PSE to adjust its PCA deferral account to reflect a disallowance of accumulated costs under the PCA mechanism for these excess costs. The increase in purchased electricity expense resulting from the disallowance totaled $9.0 million, $4.1 million and $43.4 million in 2006, 2005 and 2004, respectively. The order also established guidelines and a benchmark to determine PSE’s recovery on the Tenaska regulatory asset starting with the PCA 3 period (July 1, 2004) through the expiration of the Tenaska contract in the year 2011. The benchmark is defined as the original cost of the Tenaska contract adjusted to reflect the 1.2% disallowance from a 1994 Prudence Order.
In December 2003, PSE notified FERC that it rejected the 1997 license for the White River project because the 1997 license contained terms and conditions that rendered ongoing operations of the project uneconomical relative to alternative resources. As a result, generation of electricity ceased at the White River project on January 15, 2004. At December 31, 2006, the White River project net book value totaled $69.1 million, which included $43.4 million of net utility plant, $17.1 million of capitalized FERC licensing costs, $4.3 million of costs related to construction work in progress and $1.8 million related to dam operation and safety. PSE sought recovery of the relicensing, other construction work in progress and dam operations and safety costs in its general rate filing of April 2004, over a 10-year amortization period. In the third quarter 2004, the Washington Commission staff recommended that PSE be allowed recovery of the White River net utility plant costs noted above, but defer any amortization of the FERC licensing and other costs until all costs and any sales proceeds are known. On February 18, 2005, the Washington Commission agreed to allow PSE to recover the White River net utility plant costs noted above. However, amortization of the FERC licensing and other costs will not begin until all costs and any sales proceeds are known.
In November 2005, Puget Energy sold 15 million shares of common stock to Lehman Brothers Inc. for $312.0 million before underwriting discount. The net proceeds of approximately $309.8 million were invested in PSE and used to repay short-term debt incurred primarily to fund PSE’s construction program.
In January 2003, FASB issued Interpretation No. 46, “Consolidation of Variable Interest Entities” (FIN 46), as further revised in December 2003 with FIN 46R, which clarifies the application of Accounting Research Bulletin No. 51, “Consolidated Financial Statements,” to certain entities in which equity investors do not have a controlling interest orentity; (2) sufficient equity at risk for the entity to finance its activities without additional subordinated financial support. FIN 46Rsupport; or (3) symmetry between voting rights and economic interests and where substantially all of the entity’s activities either involve or are conducted on behalf of an investor with disproportionally few voting rights. Variable interests in a VIE are contractual, ownership or other pecuniary interests in an entity that change with changes in the fair value of the entity’s net assets exclusive of variable interest.
ASC 810 requires that if a business entity has a controlling financial interest in a variable interest entity,VIE, the financial statements must be included in the consolidated financial statements of the business entity. The adoptionA primary beneficiary of FIN 46R for all interests ina VIE is the variable interest entities created after January 31, 2003 was effective immediately. Forholder (e.g. a contractual counterparty or capital provider), who is deemed to have the controlling financial interest(s) and is considered to be exposed to the majority of the risks and rewards associated with the VIE and therefore must consolidate it. The Company enters into a variety of contracts for energy with other counterparties and evaluates all contracts for variable interests. The Company’s variable interests primarily arise through power purchase agreements where it is required to buy all or a majority of generation from a plant at rates set forth in a power purchase agreement.
The Company evaluates potential variable interest entities created before February 1, 2003,relationships based on significance. If the Company did not participate significantly in the design or redesign of an entity and the variable interest is not potentially significant to the consolidated financial statements, no further evaluation is performed. In addition, purchase power contracts with governmental organizations are outside the scope of ASC 810. When it was effective July 1, 2003. The adoption of FIN 46R was effective March 31, 2004 fordetermines a significant variable interest may exist with another party, the Company. FIN 46R also impactedCompany requests information necessary to determine if it is the treatment of the Company’s mandatorily redeemable preferred securities of a wholly owned subsidiary trust holding solely junior subordinated debentures of the corporation (trust preferred securities). Previously, these trust preferred securities were consolidated into the Company’s operations. As a result of FIN 46R, these securities have been deconsolidated and were classified as junior subordinated debentures of the corporation payable to a subsidiary trust holding mandatorily redeemable preferred securities (junior subordinated debt). This change had no impact on the Company’s results of operations. The Company alsoprimary beneficiary.
PSE evaluated its power purchase agreements and determined that three counterpartiestwo power purchase agreements may be considered significant variable interest entities.interest. As a result, PSE submitted requests for information to those parties;the relevant entities; however, the partiesthey have refused to submit to PSE the necessary information for PSE to determine whether they meetit is the requirements of a variable interest entity. PSE determined that it does not have a contractual right to such information.primary beneficiary. PSE will continue to submit requests for information to the counterparties on a quarterly basisannually to determine if FIN 46RASC 810 is applicable.
For The Company’s purchased electricity expense for the threeyears ended December 31, 2009, 2008 and 2007 with the two potential VIE entities was $181.2 million, $196.3 million, and $216.5 million, respectively. The power purchase agreements that may be considered variable interest entities under FIN 46R,mentioned as potential VIEs for both Puget Energy & PSE is requiredare set to buy allexpire in December 2011.
The following tables present the generation from these plants, subjectCompany’s potential VIE relationships, irrespective of significance, related 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 purchase power agreement prices. PSE’s Purchased Electricity expense for 2006, 2005agreements as of December 31, 2009 and 2004 for these three entities was $259.8 million, $267.0 million and $251.2 million, respectively.2008:
(Dollars in Thousands) Year Ended December 31, 2009 | | | | | | | | | |
| Nature of Variable Interest | Longest Contract Tenor | | Number of Counterparties | | | Aggregate Carrying Value Asset/(Liability) 2 | | | Level of Activity - 2009 Expenses | |
Electric- Combustion Turbine Co-generation plant 1 | 2011 | | | 2 | | | $ | (15,779 | ) | | $ | 181,240 | |
| Electric- Hydro | 2037 | | | 7 | | | | (789 | ) | | | 10,391 | |
| Total | | | | 9 | | | $ | (16,568 | ) | | $ | 191,631 | |
_____________
| 1 | Variable interests may be significant. |
| 2 | Carrying values are classified on the balance sheet in accounts payable and expenses are classified on the statements of income in purchased electricity. |
(Dollars in Thousands) Year Ended December 31, 2008 | | | | | | | | | |
| Nature of Variable Interest | Longest Contract Tenor | | Number of Counterparties | | | Aggregate Carrying Value Asset/(Liability) 2 | | | Level of Activity – 2008 Expenses 2 | |
Electric- Combustion Turbine Co-generation plant 1 | 2011 | | | 2 | | | $ | (17,096 | ) | | $ | 196,757 | |
| Electric- Hydro | 2037 | | | 8 | | | | (922 | ) | | | 12,419 | |
| Total | | | | 10 | | | $ | (18,018 | ) | | $ | 209,176 | |
_____________
| 1 | Variable interests may be significant. |
| 2 | Carrying values are classified on the balance sheet in accounts payable and expenses are classified on the statements of income in purchased electricity. |
NOTE 22. 23. Commitments and Contingencies
For the year ended December 31, 2006,2009, approximately 23.1%20.7% of the Company’s energy output was obtained at an average cost of approximately $0.014$0.018 per kWh through long-term contracts with severalthree of the Washington Public Utility Districts (PUDs) owningthat own hydroelectric projects on the Columbia River.
The purchase of power from the Columbia River projects is on a pro rata share basis under which the Company pays a proportionate share of the annual debt service, operating and maintenance costs and other expenses associated with each project in proportion to the contractual shares that PSE obtains from that project. In these instances, PSE’s payments are not contingent upon the projects being operable, which meansoperable; therefore, PSE is required to make the payments even if power is not being delivered. These projects are financed through substantially level debt service payments and their annual costs should not vary significantly over the term of the contracts unless additional financing is required to meet the costs of major maintenance, repairs or replacements, or license requirements. The Company’s share of the costs and the output of the projects is subject to reduction due to various withdrawal rights of the PUDs and others over the lives of the contracts.
As of December 31, 2006, the Company was entitled to purchase portions of the power output of the PUDs’ projects as set forth in the following tabulation:
| | | | Total Bonds Outstanding 12/31/062 (Millions) | Company’s Annual Amount Purchasable (Approximate) |
| Project | Contract Exp. Date | License1 Exp. Date | % of Output | | Megawatt Capacity | Cost3 (Millions) |
| Rock Island | | | | | | | |
| Original units | 2012 | 2029 | $ 109.3 | 50.0 | } | 330 | $ 34.4 |
| Additional units | 2012 | 2029 | 322.4 | 50.0 |
Rocky Reach 8 | 2011 | 2006 | 380.2 | 38.9 | | 501 | 27.2 |
| Wells | 2018 | 2012 | 208.4 | 29.9 | | 251 | 11.0 |
Priest Rapids 4,5,6 | TBD7 | TBD7 | 265.5 | 4.3 | | 39 | 9.2 |
Wanapum 4,5,6 | 2009 | TBD7 | 441.8 | 10.8 | | 106 | 4.3 |
| Total | | | $ 1,727.6 | | | 1,227 | $ 86.1 |
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1
| The Company is unable to predict whether the licenses under the Federal Power Act will be renewed to the current licensees. FERC has issued orders for the Rocky Reach, Wells and Priest Rapids/Wanapum projects under Section 22 of the Federal Power Act, which affirm the Company’s contractual rights to receive power under existing terms and conditions even if a new licensee is granted a license prior to expiration of the contract term.
|
2
| The contracts for purchases initially were generally coextensive with the term of the PUD bonds associated with the project. Under the terms of some financings and re-financings, however, long-term bonds were sold to finance certain assets whose estimated useful lives extend beyond the expiration date of the power sales contracts. Of the total outstanding bonds sold for each project, the percentage of principal amount of bonds which mature beyond the contract expiration date are: 77.1% at Rock Island; 64.6% at Rocky Reach; and 29.0% at Wells. There are no maturities beyond the contract expiration date for Priest Rapids and Wanapum which assumes a 40-year FERC license extension.
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3
| The components of 2006 costs associated with the interest portion of debt service are: Rock Island, $13.3 million for all units; Rocky Reach, $8.2 million; Wells, $3.2 million; Priest Rapids, $0.4 million; and Wanapum, $1.5 million.
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4
| On December 28, 2001, PSE signed a contract offer for three new contracts related to the Priest Rapids and Wanapum Developments. On April 12, 2002, PSE signed amendments to those agreements which are technical clarifications of certain sections of the agreements. On May 27, 2005, PSE signed additional amendments to those agreements which provided technical clarifications of certain sections of the agreements and consolidated the terms into two contracts. Under the terms of these contracts, PSE will continue to obtain capacity and energy for the term of any new FERC license to be obtained by Grant County PUD. The new contracts’ terms begin in November of 2005 for the Priest Rapids Development and in November of 2009 for the Wanapum Development. On March 8, 2002, the Yakama Nation filed a complaint with FERC which alleged that Grant County PUD’s new contracts unreasonably restrain trade and violate various sections of the FPA and Public Law 83-544. On November 21, 2002, FERC dismissed the complaint while agreeing that certain aspects of the complaint had merit. As a result, FERC has ordered Grant County PUD to remove specific sections of the contract which constrain the parties to the Grant County PUD contracts from competing with Grant County PUD for a new license. A rehearing was requested but was denied by FERC on April16, 2003. Both the Yakama Nation and Grant County PUD have appealed the FERC decision and the appeals have been consolidated in the Ninth Circuit Court of Appeals. The complaint is still pending and is in a mediation process.
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5
| Grant County PUD filed an “Application for New License for the Priest Rapids Project” on October 29, 2003 and the original FERC license expired at the end of October 2005. Grant County PUD continues to operate the Priest Rapids Project under annual license extensions pending issuance of a new FERC license and the new contracts will be concurrent with the new license which will be at least 30 years.
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6
| Unlike PSE’s expiring contracts with Grant County PUD, in the new contracts PSE’s share of power from the Priest Rapids Development and Wanapum Development declines over time as Grant County PUD’s load increases. PSE’s share of the Wanapum Development will remain at 10.8% until November 2009 and will be adjusted annually thereafter for the remaining term of the new contracts. PSE’s share of the Priest Rapids Development declines to approximately 4.3% in 2006 and will be adjusted annually for the remaining term of the new contract.
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7
| To be determined. (See notes 4-6.)
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8
| On February 3, 2006, PSE and Chelan entered into a new Power Sales Agreement and a related Transmission Agreement for 25.0% of the output of Chelan’s Rocky Reach and Rock Island hydroelectric generating facilities located on the mid-Columbia River in exchange for PSE paying 25.0% of the operating costs of the facilities. PSE’s share of the output represents approximately 487 MW of capacity and 243 average MW of energy. The agreements terminate in 2031 and provide that PSE will begin to receive power upon expiration of PSE’s existing long-term contracts with Chelan for the Rocky Reach and Rock Island output (expiring in 2011 and 2012, respectively). The agreements have been approved by both FERC and the WUTC.
|
The following table summarizes the Company’s estimated payment obligations for power purchases from the Columbia River projects, contracts with other utilities and contracts under non-utility generators under the Public Utility Regulatory Policies Act (PURPA).Act. These contracts have varying terms and may include escalation and termination provisions.
| (Dollars in millions) | 2007 | 2008 | 2009 | 2010 | 2011 | 2012 & There-after | Total | |
| (Dollars in Thousands) | | | 2010 | | | 2011 | | | 2012 | | | 2013 | | | 2014 | | | 2015 & There- after | | | Total | |
| Columbia River projects | $ | 97.7 | $ | 100.0 | $ | 105.0 | $ | 107.2 | $ | 111.6 | $ | 1,762.0 | $ | 2,283.5 | | $ | 86,864 | | | $ | 105,772 | | | $ | 67,749 | | | $ | 66,866 | | | $ | 68,126 | | | $ | 1,035,624 | | | $ | 1,431,001 | |
| Other utilities | | 83.0 | | 83.8 | | 85.9 | | 83.3 | | 37.1 | | 235.1 | | 608.2 | | | 178,555 | | | | 138,664 | | | | 128,860 | | | | 68,623 | | | | 49,601 | | | | 343,583 | | | | 907,886 | |
| Non-utility generators | | 200.0 | | 195.4 | | 201.2 | | 199.7 | | 200.1 | | 105.1 | | 1,101.5 | | | 169,092 | | | | 171,502 | | | | -- | | | | -- | | | | -- | | | | -- | | | | 340,594 | |
| Total | $ | 380.7 | $ | 379.2 | $ | 392.1 | $ | 390.2 | $ | 348.8 | $ | 2,102.2 | $ | 3,993.2 | | $ | 434,511 | | | $ | 415,938 | | | $ | 196,609 | | | $ | 135,489 | | | $ | 117,727 | | | $ | 1,379,207 | | | $ | 2,679,481 | |
Total purchased power contracts provided the Company with approximately 9.68.3 million, 9.68.7 million and 9.4 million megawatt hours (MWh) of firm energy at a cost of approximately $421.7$363.3 million, $419.7$384.0 million and $404.7$390.6 million for the years 2006, 20052009, 2008 and 2004,2007, respectively.
As part of its electric operations and in connection with the 1997 restructuring of the Tenaska Power Purchase Agreement, PSE is obligated to deliver to Tenaska up to 48,00050,000 MMBtu (one million British thermal units, equal to one Dth) per day of natural gas for operation of Tenaska’s natural gas-fired cogeneration facility. This obligation continues for the remaining term of the agreement, through December 31, 2011, provided that no deliveries are required during the month of May. The price paid by Tenaska for this natural gas is reflective of the daily price of natural gas at the United States/Canada border near Sumas, Washington. PSE has entered into a financial arrangement to hedge a portion, 5,000 MMBtu to 10,000 MMBtu per day, of future gas supply costs associated with this obligation.
The Company has a maximum financial obligation under this hedge agreement of $1.1 million in 2007. The Company hasnatural gas-fired generation facility obligations for natural gas supply amounting to $8.9an estimated $96.8 million in 20072010. Two longer term agreements for the Tenaska plant.
As part of its electric operations and in connection with the 1999 buyout of the Cabotnatural gas supply contract, PSE is obligatedamount to deliver to Encogen up to 21,800 MMBtu per day of natural gasan estimated $131.2 million for operation of the Encogen natural gas-fired cogeneration facility. This obligation continues for the remaining term of the original Cabot agreement. The Company entered into a financial arrangement to hedge a portion of future gas supply costs associated with this obligation, 10,000 MMBtu per day, for the remaining term of the agreement. The Company has a maximum financial obligation under this hedge agreement of $9.2 million in 2007 and $9.6 million in 2008. Depending on actual market prices, these costs will be partially, or perhaps entirely, offset by floating price payments received under the hedge arrangement. Encogen has two gas supply agreements that comprise 40% of the plant’s requirements with remaining terms ranging from less than 1 year to 2.5 years. The obligations under these contracts are $21.9 million in 2007 and $11.1 million in 2008. The Company has obligations for gas supply amounting to $2.0 million in 2007.2011 through 2029.
PSE enters into short-term energy supply contracts to meet its core customer needs. These contracts are generally classified as normal purchases and normal salesNPNS or in some cases recorded at fair value in accordance with SFAS No. 133 and SFAS No. 149.ASC 815. Commitments under these contracts are $181.2$128.1 million, $77.7 million and $19.6 million in 20072010, 2011 and $19.8 million in 2008.2012, respectively.
Natural Gas Supply
The Company has also entered into various firm supply, transportation and storage service contracts in order to ensure adequate availability of natural gas supply for its firm customers. Many of these contracts, which have remaining terms from less than 1one year to 1735 years, provide that the Company must pay a fixed demand charge each month, regardless of actual usage. The Company contracts for all of its long-term natural gas supply on a firm basis, which means the Company has a 100% daily take obligation and the supplier has a 100% daily delivery obligation. The Company incurred demand charges in 20062009 for firm natural gas supply, firm transportation service and firm storage and peaking service of $1.8$1.0 million, $93.5$117.0 million and $8.4$8.0 million, respectively. WNG CAP I, a PSE subsidiary, incurred demand charges in 2006 for firm transportation service of $3.2 million, which is included in the total Company demand charges. The Company incurred demand charges in 20062009 for firm transportation service for the natural gas supply for its combustion turbines in the amount of $11.6$17.0 million, which is included in the total Company demand charges.
The following table summarizes the Company’s obligations for future demand charges through the primary terms of its existing contracts. The quantified obligations are based on current contract prices and FERC authorized rates, which are subject to change.
Demand Charge Obligations (Dollars in millions) | 2007 | 2008 | 2009 | 2010 | 2011 | 2012 & There-after | Total | |
| Firm gas supply | $ | 1.8 | $ | 1.0 | $ | 0.5 | $ | 0.5 | $ | 0.5 | $ | -- | $ | 4.3 | |
Demand Charge Obligations (Dollars in Thousands) | | | 2010 | | | 2011 | | | 2012 | | | 2013 | | | 2014 | | | 2015 & There- after | | | Total | |
| Firm transportation service | | 109.1 | | 94.8 | | 75.5 | | 35.7 | | 35.7 | | 219.1 | | 569.9 | | $ | 131,652 | | | $ | 125,988 | | | $ | 116,715 | | | $ | 111,007 | | | $ | 86,783 | | | $ | 246,769 | | | $ | 818,914 | |
| Firm storage service | | 9.4 | | 9.0 | | 7.7 | | 7.7 | | 7.7 | | 21.5 | | 63.0 | | | 9,241 | | | | 8,949 | | | | 7,567 | | | | 2,997 | | | | 1,507 | | | | 8,584 | | | | 38,845 | |
| Firm natural gas supply | | | | 553 | | | | -- | | | | -- | | | | -- | | | | -- | | | | -- | | | | 553 | |
| Total | $ | 120.3 | $ | 104.8 | $ | 83.7 | $ | 43.9 | $ | 43.9 | $ | 240.6 | $ | 637.2 | | $ | 141,446 | | | $ | 134,937 | | | $ | 124,282 | | | $ | 114,004 | | | $ | 88,290 | | | $ | 255,353 | | | $ | 858,312 | |
Service Contracts
On August 30, 2001, PSE and Alliance Data Systems Corp. (Alliance Data) announced a contract under which Alliance Data will provide data processing and billing servicesThe following table summarizes the Company’s estimated obligations for PSE. In providing services to PSE underservice contracts through the 10-year agreement, Alliance Data will use ConsumerLinX software, PSE’s customer-information software developed by a former subsidiary, ConneXt. Alliance Data acquired the assets of ConneXt, including the exclusive use of the ConsumerLinX software for five years with an option for renewal. Alliance Data will offer ConsumerLinX as partterms of its integrated, single-source customer relationship management solution for large-scale, regulated utility clients. The obligations under the contract are $23.3 million in 2007, $23.9 million in 2008, $24.5 million in 2009, $25.1 million in 2010 and $17.1 million thereafter.existing contracts.
In April 2004, PSE acquired a 49.85% interest in the Frederickson 1 generating facility. As part of that acquisition, PSE became subject to an existing long-term parts and service maintenance contract for the upkeep of the natural gas combined cycle unit. The contract was initiated in December 2000, and runs for the earlier of 96,000 factored fired hours or 18 years. The contract requires payments based on both a fixed and variable cost component, depending on how much the facility is used. PSE’s share of the estimated obligation under the contract based on projected future use of the facility is $1.2 million in 2007, $6.3 million in 2008, $1.1 million in 2009, $2.6 million in 2010, $1.9 million in 2011 and $14.4 million in the aggregate thereafter.
In March 2005, in connection with its purchase of the Hopkins Ridge wind power project, PSE entered into an Operations, Maintenance and Warranty Agreement (OM&W Agreement) with Vestas-American Wind Technology, Inc. (Vestas), pursuant to which Vestas will operate, maintain, service and remedy any defects or deficiencies in the constructed wind turbine generators (WTGs) at Hopkins Ridge and their associated equipment on PSE’s behalf. Vestas also provides certain warranties in relation to the availability, production and noise of the Hopkins Ridge project. The OM&W Agreement provides for a five-year term continuing until November 2010. The annual fee is approximately $2.6 million and will escalate on each January 1 during the term by the Consumer Price Index.Service Contract Obligations (Dollars in Thousands) | | 2010 | | | 2011 | | | 2012 | | | 2013 | | | 2014 | | | 2015 & There- after | | | Total | |
| Automated meter reading system | | $ | 35,189 | | | $ | 35,261 | | | $ | 36,166 | | | $ | 37,234 | | | $ | 38,344 | | | $ | 49,678 | | | $ | 231,872 | |
Energy production service contracts 1 | | | 14,465 | | | | 12,254 | | | | 5,760 | | | | 14,099 | | | | 14,990 | | | | 96,428 | | | | 157,996 | |
| Information technology service contracts | | | 23,845 | | | | 24,141 | | | | 22,215 | | | | 14,016 | | | | -- | | | | -- | | | | 84,217 | |
| Total | | $ | 73,499 | | | $ | 71,656 | | | $ | 64,141 | | | $ | 65,349 | | | $ | 53,334 | | | $ | 146,106 | | | $ | 474,085 | |
In September 2005, in connection with its purchase of the Wild Horse wind power project, PSE entered into a Service & Maintenance Agreement and a Warranty Agreement (the Agreements) with Vestas-American Wind Technology, Inc. (Vestas American), pursuant to which Vestas American will operate, maintain, service and remedy any defects or deficiencies in the constructed WTGs at Wild Horse and their associated equipment on PSE’s behalf. Vestas American also provides certain warranties in relation to the availability performance of the Wild Horse project. The Agreements provide for a five-year term continuing until November 2011. The first-year annual fee is approximately $5.1 million and will escalate each January 1 thereafter during the term by the Gross Domestic Product Implicit Price Deflator (GDPIPD).| 1 | Energy production service contracts include operations and maintenance contracts on Mint Farm, Wild Horse, Goldendale, Hopkins Ridge and Sumas facilities. |
Fredonia 3 and 4 Operating Lease
PSE leases two combustion turbines for its Fredonia 3 and 4 electric generating facility pursuant to a master operating lease that was amended for this purpose in April 2001. The lease has a term expiring in 2011, but can be canceled by PSE at any time. Payments under the lease vary with changes in the LIBOR. At December 31, 2006, PSE’s outstanding balance under the lease was $51.1 million. The expected residual value under the lease is the lesser of $37.4 million or 60.0% of the cost of the equipment. In the event the equipment is sold to a third party upon termination of the lease and the aggregate sales proceeds are less than the unamortized value of the equipment, PSE would be required to pay the lessor contingent rent in an amount equal to the deficiency up to a maximum of 87.0% of the unamortized value of the equipment.
Surety Bond
The Company has a self-insurance surety bond in the amount of $10.1$5.6 million, which expires on July 1, 2010 and is renewed annually, guaranteeing compliance with the Industrial Insurance Act (workers’ compensation) and nine self-insurer’s pension bonds totaling $1.5$1.4 million.
Environmental Remediation
The Company is subject to environmental laws and regulations by federal, state and local authorities and has been required to undertake certain environmental investigative and remedial efforts as a result of these laws and regulations. The Company has also been named by the Environmental Protection Agency,EPA, the Washington State Department of Ecology and/or other third parties as potentially responsible at several contaminated sites and manufactured gas plant sites. PSE has implemented an ongoing program to test, replace and remediate certain underground storage tanks (UST) as required by federal and state laws. The UST replacement component of this effort is finished, but PSE continues its work remediating and/or monitoring relevant sites. During 1992, the Washington Commission issued orders regarding the treatment of costs incurred by the Company for certain sites under its environmental remediation program. The orders authorize the Company to accumulate and defer prudently incurred cleanup costs paid to third parties for recovery in rates established in future rate proceedings, subject to Washington Commission review. The Washington Commission consolidated the gas and electric methodological approaches to remediation and deferred accounting in an order issued October 8, 2008. The Company reviews its estimated future obligations and adjusts loss reserves quarterly as management believes necessary per the guidance of ASC 450, “Contingencies.” Management’s estimates include an assessment of the impact of the potential outcomes of disputes with certain property owners and other potentially responsible parties. The Company believes a significant portion of its past and future environmental remediation costs isare recoverable from insurance companies, from third parties or from customers under a Washington Commission order. At December 31, 2006,2009, the Company had $1.7$5.9 million and $34.6$53.1 million in deferred electric and natural gas environmental costs, respectively.
In November,
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 Crystal Mountain Generation Station had an accidental release of approximately 18,000 gallons of diesel oil. PSE crews and consultants responded and worked with applicable state and federal agencies to control and removeoutstanding commercial paper interest rate; (b) PSE’s senior unsecured revolving credit facility; or (c) the spilled product. Through February 2007, over 9,500 gallons have been removed. Due to weather and snow in particular (the site is located very near the Crystal Mountain Ski Resort), additional recovery of diesel is not feasible until later in 2007. However, the remaining recoverable diesel is presumed to be contained within a limited area and largely embedded in soilsinterest rate available under the generator station. Total removal costs asreceivable securitization facility of February 14, 2007 are approximately $8.8 million. PSE Funding, a PSE subsidiary, which is currently projecting the total remediation cost to be between $10.3 million and $13.3 million.one-month LIBOR plus 0.25%. At December 31, 2006, PSE had an insurance receivable2009 and December 31, 2008, the outstanding balance of the Note was $22.9 million and $26.1 million, respectively, and the interest rate was 1.2% and 1.7%, respectively. The outstanding balance and the related interest under the Note are eliminated by Puget Energy upon consolidation of PSE’s financial statements. The $30.0 million credit facility with Puget Energy was unaffected by the merger.
Effective with the close of the merger on February 6, 2009, Puget Energy has a $1.225 billion five-year term loan and a $1.0 billion credit facility for funding capital expenditures. These facilities mature in 2014, contain similar terms and conditions and are syndicated among numerous committed banks and other financial institutions. One of these banks is Macquarie Bank Limited, which has a commitment of $25.2 million to the term loan and a $20.6 million commitment to the capital expenditure credit facility. As of December 31, 2009, the term loan was fully drawn at $1.225 billion and $258.0 million was outstanding under the $1.0 billion credit facility. On February 6, 2009, Puget Energy entered into several interest rate swap instruments to hedge volatility associated with these two loans. Two of the swap instruments were entered into with Macquarie Bank Limited with a total notional amount of $7.9 million accrued associated with the Crystal Mountain electric generating facility oil spill. PSE management will be filing proof of loss claims with insurers once damage repair costs are known within an acceptable level of precision.
Litigation
There are several actions in the U.S. Ninth Circuit Court of Appeals (Ninth Circuit) against Bonneville Power Administration (BPA), in which the petitioners assert or may assert that BPA acted contrary to law or without authority in deciding to enter into, or 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 Purchase and Sale 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. There are also several actions in the U.S. Ninth Circuit Court of Appeals against BPA, in which petitioners assert that BPA acted contrary to law in adopting or implementing the rates or rate adjustment clause upon which the benefits received or to be received from BPA during the October 1, 2001 through September 30, 2006 period are based. The parties to these various actions presented oral arguments to the U.S. Ninth Circuit Court of Appeals in November 2005. A decision from the Court is anticipated in 2007. 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. It is not clear what impact, if any, development or review of such rates, review of such agreements and the above described Ninth Circuit actions may have on PSE.$444.9 million.
The Washington Commission issued an order on May 13, 2004 determining that PSE did not prudently manage natural gas costs for the Tenaska Power Fund, L.P. (Tenaska) electric generating plant and ordered PSE to adjust its PCA deferral account to reflect a disallowance of accumulated costs under the PCA mechanism for these excess costs. The increase in purchased electricity expense resulting from the disallowance totaled $1.0 million, $6.4 million and $7.8 million in 2009, 2008 and 2007, respectively. The order also established guidelines and a benchmark to determine PSE’s recovery on the Tenaska regulatory asset starting with the PCA 3 period (July 1, 2004) through the expiration of the Tenaska contract in the year 2011. The benchmark is defined as the original cost of the Tenaska contract adjusted to reflect the 1.2% disallowance from a 1994 Prudence Order.
In December 2003, PSE notified FERC that it rejected the 1997 license for the White River project because the 1997 license contained terms and conditions that rendered ongoing operations of the project uneconomical relative to alternative resources. As a result, generation of electricity ceased at the White River project on January 15, 2004. PSE sought recovery of the relicensing, other construction work in progress and dam operations and safety costs in its general rate filing of April 2004 over a 10-year amortization period. On February 18, 2005, the Washington Commission agreed to allow PSE to recover the White River net utility plant costs noted above. However, amortization of the FERC licensing and other costs will not begin until all costs and any sales proceeds are known. At December 31, 2009, the White River project net book value totaled $34.7 million, which included $10.3 million of net utility plant, $15.3 million of capitalized FERC licensing costs, $5.8 million of costs related to construction work in progress and $3.3 million related to dam operation and safety. The net utility plant amount and the dam operation and safety amount include $ 25.0 million proceeds received on December 21, 2009 from the sale of portions of the White River project and $ 9.6 million related reimbursement costs from the purchaser. This transaction was approved by the Washington Commission which allows PSE to apply the proceeds from the sale and disposition of assets as salvage against unamortized White River regulatory asset account balances.
Puget Energy operates in one business segment referred to as the regulated utility segment. The regulated utility segment includes the account receivables securitization program.program which was terminated during the merger. Puget Energy’s regulated utility operation generates, purchases and sells electricity and purchases, transports and sells natural gas. The service territory of PSE covers approximately 6,000 square miles in the state of Washington.
One minor non-utilityNon-utility business segment which includes two PSE subsidiaries, and Puget Energy, is described as other.Other. The PSE subsidiaries are a real estate investment aand development company and a holding company for a small non-utility wholesale generator. Reconciling items between segments are not significant.
Effective February 6, 2009, all merger related fair value adjustments were retained in Puget Energy. Accordingly, only the financial statements of Puget Energy were adjusted to reflect the purchase accounting. Prior to 2005, InfrastruX was a reportablethe merger, the business segment offinancial statements for Puget Energy. InfrastruX was sold on May 7, 2006Energy and is not considered a reportable segment. See Note 3 for InfrastruX summarized financial information and discussion of discontinued operations.PSE were the same.
2006 (Dollars in Thousands) | | Regulated Utility | | Other | | Reconciling Item | | Puget Energy Total | | |
| | | | Successor February 6, 2009 - December 31, 2009 | | | Predecessor January 1, 2009 - February 5, 2009 | |
Puget Energy (Dollars in Thousands) 2009 | | | Regulated Utility | | | Other | | | Regulated Utility | | | Other | |
| Revenues | | $ | 2,897,864 | | $ | 7,829 | | $ | -- | | $ | 2,905,693 | | | $ | 2,921,550 | | | $ | 3,598 | | | $ | 403,713 | | | $ | -- | |
| Depreciation and amortization | | | 262,129 | | | 212 | | | -- | | | 262,341 | | | | 305,904 | | | | 39 | | | | 26,742 | | | | -- | |
| Income tax | | | 95,271 | | | 1,000 | | | -- | | | 96,271 | | | | 113,241 | | | | (31,200 | ) | | | 10,537 | | | | (1,540 | ) |
| Operating income | | | 323,497 | | | 3,119 | | | -- | | | 326,616 | | | | 477,082 | | | | (2,219 | ) | | | 55,830 | | | | (20,420 | ) |
| Interest charges, net of AFUDC | | | 183,922 | | | -- | | | -- | | | 183,922 | | | | 176,858 | | | | 79,953 | | | | 16,966 | | | | (25 | ) |
| Net income from continuing operations | | | 172,735 | | | (5,511 | ) | | -- | | | 167,224 | | |
| Net income | | | | 229,973 | | | | (55,958 | ) | | | 31,611 | | | | (18,855 | ) |
| Total assets | | | 6,993,131 | | | 72,908 | | | -- | | | 7,066,039 | | | | 10,117,563 | | | | 1,782,577 | | | | 8,507,548 | | | | 87,288 | |
| Construction expenditures - excluding equity AFUDC | | | 749,516 | | | -- | | | -- | | | 749,516 | | | | 726,157 | | | | -- | | | | 49,531 | | | | -- | |
2005 (Dollars in Thousands) | | Regulated Utility | | Other | | Reconciling Item | | Puget Energy Total | |
| Revenues | | $ | 2,565,384 | | $ | 7,826 | | $ | -- | | $ | 2,573,210 | |
| Depreciation and amortization | | | 241,385 | | | 249 | | | -- | | | 241,634 | |
| Income tax | | | 87,749 | | | 860 | | | -- | | | 88,609 | |
| Operating income | | | 299,541 | | | 3,622 | | | -- | | | 303,163 | |
| Interest charges, net of AFUDC | | | 164,965 | | | 224 | | | -- | | | 165,189 | |
| Net income from continuing operations | | | 142,861 | | | 3,422 | | | -- | | | 146,283 | |
Total assets1 | | | 6,267,012 | | | 68,392 | | | 274,547 | | | 6,609,951 | |
| Construction expenditures - excluding equity AFUDC | | | 568,381 | | | -- | | | -- | | | 568,381 | |
2004 (Dollars in Thousands) | | Regulated Utility | | Other | | Reconciling Item | | Puget Energy Total | |
| Revenues | | $ | 2,192,340 | | $ | 6,537 | | $ | -- | | $ | 2,198,877 | |
| Depreciation and amortization | | | 228,310 | | | 256 | | | -- | | | 228,566 | |
| Income tax | | | 75,754 | | | 1,002 | | | -- | | | 76,756 | |
| Operating income | | | 285,258 | | | 2,420 | | | -- | | | 287,678 | |
| Interest charges, net of AFUDC | | | 166,411 | | | 219 | | | -- | | | 166,630 | |
| Net income from continuing operations | | | 123,401 | | | 2,009 | | | -- | | | 125,410 | |
Total assets1 | | | 5,509,358 | | | 70,641 | | | 271,220 | | | 5,851,219 | |
| Construction expenditures - excluding equity AFUDC | | | 393,891 | | | -- | | | -- | | | 393,891 | |
_______________1
| Reconciling item consists of assets of InfrastruX which is presented as discontinued operations.
|
Puget Sound Energy (Dollars in Thousands) 2009 | | Regulated Utility | | | Other | |
| Revenues | | $ | 3,325,263 | | | $ | 3,238 | |
| Depreciation and amortization | | | 332,646 | | | | 206 | |
| Income tax | | | 69,890 | | | | (2,246 | ) |
| Operating income | | | 387,652 | | | | (4,517 | ) |
| Interest charges, net of AFUDC | | | 202,527 | | | | -- | |
| Net income | | | 161,508 | | | | (2,256 | ) |
| Total assets | | | 8,765,189 | | | | 51,382 | |
| Construction expenditures - excluding equity AFUDC | | | 775,688 | | | | -- | |
Puget Sound Energy and Puget Energy (Dollars in Thousands) 2008 | | Regulated Utility | | | Other | | | Puget Energy Total | |
| Revenues | | $ | 3,351,108 | | | $ | 6,665 | | | $ | 3,357,773 | |
| Depreciation and amortization | | | 311,920 | | | | 208 | | | | 312,128 | |
| Income tax | | | 59,071 | | | | 835 | | | | 59,906 | |
| Operating income | | | 386,912 | | | | (4,164 | ) | | | 382,748 | |
| Interest charges, net of AFUDC | | | 193,978 | | | | (6 | ) | | | 193,972 | |
| Net income | | | 159,373 | | | | (4,444 | ) | | | 154,929 | |
| Total assets | | | 8,347,974 | | | | 86,128 | | | | 8,434,102 | |
| Construction expenditures - excluding equity AFUDC | | | 846,001 | | | | -- | | | | 846,001 | |
Puget Sound Energy and Puget Energy (Dollars in Thousands) 2007 | | Regulated Utility | | | Other | | | Puget Energy Total | |
| Revenues | | $ | 3,207,061 | | | $ | 13,086 | | | $ | 3,220,147 | |
| Depreciation and amortization | | | 279,014 | | | | 208 | | | | 279,222 | |
| Income tax | | | 70,794 | | | | 1,788 | | | | 72,582 | |
| Operating income | | | 439,433 | | | | 1,601 | | | | 441,034 | |
| Interest charges, net of AFUDC | | | 205,209 | | | | -- | | | | 205,209 | |
| Net income from continuing operations | | | 184,049 | | | | 627 | | | | 184,676 | |
| Total assets | | | 7,513,884 | | | | 84,852 | | | | 7,598,736 | |
| Construction expenditures - excluding equity AFUDC | | | 737,258 | | | | -- | | | | 737,258 | |
The following unaudited amounts, in the opinion of the Company, include all adjustments (consisting of normal recurring adjustments) necessary for a fair statement of the results of operations for the interim periods. Quarterly amounts vary during the year due to the seasonal nature of the utility business.
Puget Energy(Unaudited; Dollars in Thousands)
| Puget Energy | | | | | | | |
| (Unaudited; dollars in thousands except per share amounts) | | | | | | | |
| 2006 Quarter | | First | | Second | | Third | | Fourth | |
| Operating revenues | | $ | 877,735 | | $ | 574,222 | | $ | 519,463 | | $ | 934,273 | |
| Operating income | | | 112,825 | | | 66,540 | | | 52,254 | | | 94,998 | |
| Net income before cumulative effect of accounting change | | | 92,520 | | | 53,529 | | | 15,922 | | | 57,156 | |
| Net income | | | 92,609 | | | 53,529 | | | 15,922 | | | 57,156 | |
| Basic earnings per common share | | $ | 0.80 | | $ | 0.46 | | $ | 0.14 | | $ | 0.49 | |
| Diluted earnings per common share | | $ | 0.79 | | $ | 0.46 | | $ | 0.14 | | $ | 0.49 | |
| 2009 Quarter | | First | | | Second | | | Third | | | Fourth | |
| | | Successor February 6, 2009 - March 31, 2009 | | | Predecessor January 1, 2009 - February 5, 2009 | | | | | | | | | | |
| Operating revenues | | $ | 703,842 | | | $ | 403,713 | | | $ | 686,637 | | | $ | 592,626 | | | $ | 942,043 | |
| Operating income | | | 116,646 | | | | 35,410 | | | | 117,625 | | | | 101,632 | | | | 138,960 | |
| Net income | | | 52,060 | | | | 12,756 | | | | 43,570 | | | | 24,507 | | | | 53,878 | |
| (Unaudited; dollars in thousands except per share amounts) | | | | | | | |
| 2005 Quarter | | First | | Second | | Third | | Fourth | |
| Operating revenues | | $ | 741,653 | | $ | 510,114 | | $ | 490,383 | | $ | 831,061 | |
| Operating income | | | 110,534 | | | 51,919 | | | 47,528 | | | 93,180 | |
| Net income before cumulative effect of accounting change | | | 71,075 | | | 13,895 | | | 5,911 | | | 64,915 | |
| Net income | | | 71,075 | | | 13,895 | | | 5,911 | | | 64,844 | |
| Basic earnings per common share | | $ | 0.71 | | $ | 0.14 | | $ | 0.06 | | $ | 0.60 | |
| Diluted earnings per common share | | $ | 0.71 | | $ | 0.13 | | $ | 0.06 | | $ | 0.60 | |
| (Unaudited; Dollars in Thousands) | |
| 2008 Quarter | | First | | | Second | | | Third | | | Fourth | |
| Operating revenues | | $ | 1,050,932 | | | $ | 712,404 | | | $ | 606,162 | | | $ | 988,275 | |
| Operating income | | | 157,868 | | | | 86,470 | | | | 33,474 | | | | 104,936 | |
| Net income (loss) | | | 79,813 | | | | 33,654 | | | | (8,225 | ) | | | 49,687 | |
Puget Sound Energy
| (Unaudited; Dollars in Thousands) | | | | | | | | | | | | |
| 2009 Quarter | | First | | | Second | | | Third | | | Fourth | |
| Operating revenues | | $ | 1,107,555 | | | $ | 686,280 | | | $ | 592,626 | | | $ | 942,040 | |
| Operating income | | | 161,894 | | | | 94,887 | | | | 56,015 | | | | 70,339 | |
| Net income | | | 84,977 | | | | 43,777 | | | | 7,842 | | | | 22,656 | |
| (Unaudited; Dollars in Thousands) | | | | | | | | | | | | |
| 2008 Quarter | | First | | | Second | | | Third | | | Fourth | |
| Operating revenues | | $ | 1,050,932 | | | $ | 712,404 | | | $ | 606,162 | | | $ | 988,275 | |
| Operating income | | | 159,586 | | | | 92,148 | | | | 34,770 | | | | 105,882 | |
| Net income (loss) | | | 80,904 | | | | 39,110 | | | | (7,276 | ) | | | 49,998 | |
| Puget Sound Energy | | | | | | | | | |
| (Unaudited; dollars in thousands) | | | | | | | | | |
| 2006 Quarter | | First | | Second | | Third | | Fourth | |
| Operating revenues | | $ | 877,735 | | $ | 574,224 | | $ | 519,463 | | $ | 934,273 | |
| Operating income | | | 113,002 | | | 66,829 | | | 52,305 | | | 95,353 | |
| Net income before cumulative effect of accounting change | | | 73,750 | | | 30,100 | | | 15,632 | | | 57,168 | |
| Net income | | | 73,839 | | | 30,100 | | | 15,632 | | | 57,168 | |
| (Unaudited; dollars in thousands) | | | | | | | | | |
| 2005 Quarter | | First | | Second | | Third | | Fourth | |
| Operating revenues | | $ | 741,653 | | $ | 510,114 | | $ | 490,383 | | $ | 831,062 | |
| Operating income | | | 110,555 | | | 52,044 | | | 47,705 | | | 93,195 | |
| Net income before cumulative effect of accounting change | | | 72,182 | | | 12,166 | | | 6,170 | | | 56,323 | |
| Net income | | | 72,182 | | | 12,166 | | | 6,170 | | | 56,252 | |
Condensed Financial Information of Puget Energy
Puget Energy Condensed Statements of
INCOME
(Dollars in Thousands, except per share amounts) For Years Ended December 31 | | 2006 | | 2005 | | 2004 | |
| Equity in earnings of subsidiary | | $ | 177,585 | | $ | 146,769 | | $ | 126,192 | |
| Other operations and maintenance | | | (1,830 | ) | | (1,354 | ) | | (983 | ) |
| Income taxes | | | 957 | | | 1,021 | | | 420 | |
| Other income (deductions): | | | | | | | | | | |
| Charitable foundation contributions | | | (15,000 | ) | | -- | | | -- | |
| Interest Income | | | 356 | | | -- | | | -- | |
| Interest expense | | | -- | | | (224 | ) | | (219 | ) |
| Income taxes | | | 5,245 | | | -- | | | -- | |
| Net income from continuing operations | | | 167,313 | | | 146,212 | | | 125,410 | |
| Equity in earnings of discontinued subsidiary | | | 51,903 | | | 9,514 | | | (70,388 | ) |
| Net income | | $ | 219,216 | | $ | 155,726 | | $ | 55,022 | |
| Basic earnings per share from continuing operations | | | 1.44 | | | 1.43 | | | 1.26 | |
| Discontinued operations | | | 0.45 | | | 0.09 | | | (0.71 | ) |
| Basic earnings per share | | $ | 1.89 | | $ | 1.52 | | $ | 0.55 | |
| Diluted earnings per share from continuing operations | | $ | 1.44 | | $ | 1.42 | | $ | 1.25 | |
| Discontinued operations | | | 0.44 | | | 0.09 | | | (0.70 | ) |
| Diluted earnings per share | | $ | 1.88 | | $ | 1.51 | | $ | 0.55 | |
| (Dollars in Thousands) | | Successor February 6, 2009 - December 31, 2009 | | Predecessor January 1, 2009 - February 5, 2009 | | | 2008 | | | | 2007 | |
Equity in earnings of subsidiary 1 | | $ | 231,978 | | | $ | 31,611 | | | $ | 162,736 | | | $ | 191,127 | |
| Non-utility expense and other | | | (1,526 | ) | | | (4 | ) | | | (386 | ) | | | (1,206 | ) |
| Merger and related costs | | | (2,731 | ) | | | (20,416 | ) | | | (9,252 | ) | | | (8,143 | ) |
| Other income (deductions): | | | | | | | | | | | | | | | | |
| Charitable foundation contributions | | | (5,000 | ) | | | -- | | | | -- | | | | -- | |
| Interest income | | | 240 | | | | 25 | | | | 863 | | | | 1,300 | |
| Interest expense | | | (80,193 | ) | | | -- | | | | (8 | ) | | | -- | |
| Income taxes | | | 31,247 | | | | 1,540 | | | | 976 | | | | 1,598 | |
| Net income from continuing operations | | | 174,015 | | | | 12,756 | | | | 154,929 | | | | 184,676 | |
| Equity in earnings of discontinued subsidiary | | | -- | | | | -- | | | | -- | | | | (212 | ) |
| Net income | | $ | 174,015 | | | $ | 12,756 | | | $ | 154,929 | | | $ | 184,464 | |
_______________
| 1 | Equity earnings of subsidiary for successor include earnings from PSE of $127,641 and $104,337 related to purchase accounting adjustments recorded at Puget Energy for PSE. |
See accompanying notes to the consolidated financial statements.
Puget Energy Condensed
BALANCE SHEETS
(Dollars in Thousands) At December 31 | | 2006 | | 2005 | | | Successor 2009 | | | Predecessor 2008 | |
| Assets: | | | | | | | | | | | |
| Investment in & advances to Subs | | $ | 761,686 | | $ | 714,214 | | |
Investment in subsidiaries 1 | | | $ | 3,147,625 | | | $ | 2,249,186 | |
| Other property and investments: | | | | | | | | | |
| Goodwill | | | | 1,656,513 | | | | -- | |
| Current assets: | | | | | | | | | | | | | | | |
| Cash | | | 25 | | | 1 | | | | 119 | | | | 57 | |
| Receivables from affiliates | | | 24,659 | | | 1,618 | | |
| Prepayments and other | | | 570 | | | 573 | | |
| Tax receivable | | | 388 | | | -- | | |
Receivables from affiliates 2 | | | | 22,918 | | | | 26,092 | |
| Income taxes | | | | 34,670 | | | | 1,804 | |
| Prepaid expense and other | | | | -- | | | | 545 | |
| Deferred income taxes | | | | 9,395 | | | | -- | |
| Total current assets | | | 25,642 | | | 2,192 | | | | 67,102 | | | | 28,498 | |
| Long-term assets: | | | | | | | | | | | | | | | |
| Restricted cash | | | 3,813 | | | -- | | |
| Unrealized gain on derivative instruments | | | | 20,854 | | | | -- | |
| Deferred income taxes | | | 3,939 | | | 353 | | | | 1,261 | | | | 674 | |
| Other | | | 217 | | | 460 | | | | 930 | | | | 56 | |
| Total long-term assets | | | 7,969 | | | 813 | | | | 23,045 | | | | 730 | |
| Total assets | | $ | 795,297 | | $ | 717,219 | | | $ | 4,894,285 | | | $ | 2,278,414 | |
| Capitalization and liabilities: | | | | | | | | | | | | | | | |
| Common equity | | $ | 785,432 | | $ | 699,148 | | | $ | 3,423,468 | | | $ | 2,273,201 | |
| Long-term debt | | | | 1,438,519 | | | | -- | |
| Total capitalization | | | 785,432 | | | 699,148 | | | | 4,861,987 | | | | 2,273,201 | |
| Minority interest in discontinued operations | | | -- | | | 6,816 | | |
| Current liabilities: | | | | | | | | | | | | | | | |
| Accounts payable | | | 325 | | | -- | | | | 48 | | | | 5,213 | |
| Payable to affiliates | | | -- | | | 5,427 | | |
| Taxes | | | -- | | | 960 | | |
| Salaries and wages | | | 531 | | | -- | | |
| Other | | | -- | | | 4,763 | | |
| Interest | | | | 5,406 | | | | -- | |
| Unrealized loss on derivative instruments | | | | 26,844 | | | | -- | |
| Total current liabilities | | | 856 | | | 11,150 | | | | 32,298 | | | | 5,213 | |
| Long-term liabilities: | | | | | | | | |
| Other deferred credits | | | 9,009 | | | 105 | | |
| Total long-term liabilities | | | 9,009 | | | 105 | | |
| Total capitalization and liabilities | | $ | 795,297 | | $ | 717,219 | | | $ | 4,894,285 | | | $ | 2,278,414 | |
_______________
| 1 | Investment in subsidiaries for successor include Puget Energy business combination accounting adjustments under ASC 805 that are recorded at Puget Energy. |
| 2 | Eliminated in consolidation. |
See accompanying notes to the consolidated financial statements.
Puget Energy Condensed Statements of
CASH FLOWS
(Dollars in Thousands) For Years Ended December 31 | | 2006 | | 2005 | | 2004 | |
| Operating activities: | | | | | | | |
| Net income | | $ | 219,216 | | $ | 155,726 | | $ | 55,022 | |
| Adjustments to reconcile net income to net cash provided by operating activities: | | | | | | | | | | |
Deferred income taxes and tax credits - net | | | (3,586 | ) | | (252 | ) | | 63 | |
| Equity in earnings of discontinued subsidiary | | | (51,903 | ) | | (9,514 | ) | | 70,388 | |
| Equity in earnings of subsidiary | | | (177,586 | ) | | (146,769 | ) | | (126,192 | ) |
| Other | | | (94 | ) | | 303 | | | (450 | ) |
| Dividends received from subsidiaries | | | 109,782 | | | 89,199 | | | 87,700 | |
| (Increase) decrease in accounts receivable | | | (355 | ) | | (1,617 | ) | | -- | |
| (Increase) decrease in tax receivable | | | (388 | ) | | 319 | | | (319 | ) |
| (Increase) decrease in prepayments | | | -- | | | -- | | | 9 | |
| Increase (decrease) in accounts payable | | | 325 | | | -- | | | -- | |
| Increase (decrease) in affiliated payables | | | (5,427 | ) | | 4,297 | | | 304 | |
| Increase (decrease) in accrued tax payable | | | (960 | ) | | 960 | | | -- | |
| Increase (decrease) in accrued expenses and other | | | (4,763 | ) | | (208 | ) | | -- | |
| Net cash provided (used) by operating activities | | | 84,261 | | | 92,444 | | | 86,525 | |
| Investing activities: | | | | | | | | | | |
| Cash proceeds from sale of InfrastruX | | | 275,000 | | | -- | | | -- | |
| Increase in restricted cash | | | (3,813 | ) | | -- | | | -- | |
| Investment in subsidiaries | | | (70,114 | ) | | (314,686 | ) | | (5,016 | ) |
| Loans to subsidiaries | | | (24,303 | ) | | -- | | | -- | |
| Net cash provided (used) by investing activities | | | 176,770 | | | (314,686 | ) | | (5,016 | ) |
| Financing activities: | | | | | | | | | | |
| Dividends paid | | | (104,332 | ) | | (88,071 | ) | | (86,873 | ) |
| Common stock issued | | | 5,877 | | | 317,607 | | | 5,413 | |
| Long-term debt and lease payments | | | (151,849 | ) | | (5,000 | ) | | -- | |
| Payments made to minority interest | | | (10,451 | ) | | -- | | | -- | |
| Issue costs of stocks | | | (252 | ) | | (2,293 | ) | | (49 | ) |
| Net cash provided (used) by financing activities | | | (261,007 | ) | | 222,243 | | | (81,509 | ) |
| Increase (decrease) in cash | | | 24 | | | 1 | | | -- | |
| Cash at beginning of year | | | 1 | | | -- | | | -- | |
| Cash at end of year | | $ | 25 | | $ | 1 | | $ | -- | |
(Dollars in Thousands) For Years Ended December 31 | | Successor February 6, 2009 - December 31, 2009 | | Predecessor January 1, 2009 - February 5, 2009 | | | 2008 | | | 2007 | |
| Operating activities: | | | | | | | | | | | | |
| Net income | | $ | 174,015 | | | $ | 12,756 | | | $ | 154,929 | | | $ | 184,464 | |
| Adjustments to reconcile net income to net cash provided by (used in) operating activities: | | | | | | | | | | | | | | | | |
Deferred income taxes and tax credits - net | | | (7,886 | ) | | | -- | | | | 2,548 | | | | 718 | |
Equity in earnings of subsidiary 1 | | | (231,978 | ) | | | (31,611 | ) | | | (162,736 | ) | | | (191,127 | ) |
| Other | | | 3,153 | | | | (14 | ) | | | (7,332 | ) | | | (1,447 | ) |
| Dividends received from subsidiaries | | | 183,071 | | | | -- | | | | 145,840 | | | | 108,434 | |
| Accounts receivable | | | -- | | | | -- | | | | 38 | | | | 279 | |
| Income taxes | | | (21,951 | ) | | | (1,539 | ) | | | 810 | | | | (2,101 | ) |
| Accounts payable | | | (88,912 | ) | | | -- | | | | 1,946 | | | | (10 | ) |
| Affiliated payables | | | -- | | | | 20,015 | | | | -- | | | | 563 | |
| Accrued interest | | | 5,406 | | | | -- | | | | -- | | | | (531 | ) |
| Net cash provided by (used in) operating activities | | | 14,918 | | | | (393 | ) | | | 136,043 | | | | 99,242 | |
| Investing activities: | | | | | | | | | | | | | | | | |
| Restricted cash | | | -- | | | | -- | | | | 3,994 | | | | (181 | ) |
| Investment in subsidiaries | | | (25,960 | ) | | | -- | | | | -- | | | | (297,073 | ) |
| (Increase) decrease in loan to subsidiaries | | | 2,828 | | | | 346 | | | | (10,287 | ) | | | 8,537 | |
| Net cash provided by (used in) investing activities | | | (23,132 | ) | | | 346 | | | | (6,293 | ) | | | (288,717 | ) |
| Financing activities: | | | | | | | | | | | | | | | | |
| Dividends paid | | | (121,178 | ) | | | -- | | | | (129,677 | ) | | | (108,434 | ) |
| Common stock issued | | | -- | | | | -- | | | | -- | | | | 300,544 | |
| Proceeds from debt issuance | | | 50,211 | | | | -- | | | | -- | | | | -- | |
| Issue costs | | | (6,428 | ) | | | -- | | | | (40 | ) | | | (2,636 | ) |
| Net cash provided by (used in) by financing activities | | | (77,395 | ) | | | -- | | | | (129,717 | ) | | | 189,474 | |
| Increase (decrease) in cash | | | (85,609 | ) | | | (47 | ) | | | 33 | | | | (1 | ) |
| Cash at beginning of year | | | 85,728 | | | | 57 | | | | 24 | | | | 25 | |
| Cash at end of year | | $ | 119 | | | $ | 10 | | | $ | 57 | | | $ | 24 | |
_______________
| 1 | Equity earnings of subsidiary for successor include earnings from PSE of $127,641 and $104,337 related to purchase accounting adjustments recorded at Puget Energy for PSE. |
See accompanying notes to the consolidated financial statements.
Valuation and Qualifying Accounts and Reserves
Puget Energy (Dollars in Thousands) | | Balance At Beginning of Period | | Additions Charged to Costs and Expenses | | Deductions | | Balance At End Of Period | |
| Year Ended December 31, 2006 | | | | | | | | | |
| Accounts deducted from assets on balance sheet: | | | | | | | | | |
| Allowance for doubtful accounts receivable | | $ | 3,074 | | $ | 7,623 | | $ | 7,935 | | $ | 2,762 | |
| Reserve on wholesale sales | | | 41,488 | | | -- | | | -- | | | 41,488 | |
| Deferred tax asset valuation allowance | | | 16,075 | | | -- | | | 16,075 | | | -- | |
| Year Ended December 31, 2005 | | | | | | | | | | | | | |
| Accounts deducted from assets on balance sheet: | | | | | | | | | | | | | |
| Allowance for doubtful accounts receivable | | $ | 2,670 | | $ | 8,275 | | $ | 7,871 | | $ | 3,074 | |
| Reserve on wholesale sales | | | 41,488 | | | -- | | | -- | | | 41,488 | |
| Deferred tax asset valuation allowance | | | 17,988 | | | -- | | | 1,913 | | | 16,075 | |
| Year Ended December 31, 2004 | | | | | | | | | | | | | |
| Accounts deducted from assets on balance sheet: | | | | | | | | | | | | | |
| Allowance for doubtful accounts receivable | | $ | 2,484 | | $ | 7,343 | | $ | 7,157 | | $ | 2,670 | |
| Reserve on wholesale sales | | | 41,488 | | | -- | | | -- | | | 41,488 | |
| Deferred tax asset valuation allowance | | | -- | | | 17,988 | | | -- | | | 17,988 | |
Puget Sound Energy (Dollars in Thousands) | | Balance At Beginning of Period | | Additions Charged to Costs and Expenses | | Deductions | | Balance At End Of Period | |
| Year Ended December 31, 2006 | | | | | | | | | |
| Accounts deducted from assets on balance sheet: | | | | | | | | | |
| Allowance for doubtful accounts receivable | | $ | 3,074 | | $ | 7,623 | | $ | 7,935 | | $ | 2,762 | |
| Reserve on wholesale sales | | | 41,488 | | | -- | | | -- | | | 41,488 | |
| Year Ended December 31, 2005 | | | | | | | | | | | | | |
| Accounts deducted from assets on balance sheet: | | | | | | | | | | | | | |
| Allowance for doubtful accounts receivable | | $ | 2,670 | | $ | 8,275 | | $ | 7,871 | | $ | 3,074 | |
| Reserve on wholesale sales | | | 41,488 | | | -- | | | -- | | | 41,488 | |
| Year Ended December 31, 2004 | | | | | | | | | | | | | |
| Accounts deducted from assets on balance sheet: | | | | | | | | | | | | | |
| Allowance for doubtful accounts receivable | | $ | 2,484 | | $ | 7,343 | | $ | 7,157 | | $ | 2,670 | |
| Reserve on wholesale sales | | | 41,488 | | | -- | | | -- | | | 41,488 | |
Valuation and Qualifying Accounts and Reserves
Puget Energy (Dollars in Thousands) | | Balance At Beginning of Period | | | Additions Charged to Costs and Expenses | | | Deductions | | | Balance At End Of Period | |
Successor Period from February 6, 2009 to December 31, 2009 | | | | | | | | | | | | |
| Accounts deducted from assets on balance sheet: | | | | | | | | | | | | |
| Allowance for doubtful accounts receivable | | $ | -- | | | $ | 25,378 | | | $ | 17,284 | | | $ | 8,094 | |
Predecessor Period from January 1, 2009 to February 5, 2009 | | | | | | | | | | | | | | | | |
| Accounts deducted from assets on balance sheet: | | | | | | | | | | | | | | | | |
| Allowance for doubtful accounts receivable | | $ | 6,392 | | | $ | 1,285 | | | $ | 7,677 | | | $ | -- | |
| Year Ended December 31, 2008 | | | | | | | | | | | | | | | | |
| Accounts deducted from assets on balance sheet: | | | | | | | | | | | | | | | | |
| Allowance for doubtful accounts receivable | | $ | 5,465 | | | $ | 13,126 | | | $ | 12,199 | | | $ | 6,392 | |
| Year Ended December 31, 2007 | | | | | | | | | | | | | | | | |
| Accounts deducted from assets on balance sheet: | | | | | | | | | | | | | | | | |
| Allowance for doubtful accounts receivable | | $ | 2,762 | | | $ | 13,019 | | | $ | 10,316 | | | $ | 5,465 | |
Puget Sound Energy (Dollars in Thousands) | | Balance At Beginning of Period | | | Additions Charged to Costs and Expenses | | | Deductions | | | Balance At End Of Period | |
| Year Ended December 31, 2009 | | | | | | | | | | | | |
| Accounts deducted from assets on balance sheet: | | | | | | | | | | | | |
| Allowance for doubtful accounts receivable | | $ | 6,392 | | | $ | 20,220 | | | $ | 18,518 | | | $ | 8,094 | |
| Year Ended December 31, 2008 | | | | | | | | | | | | | | | | |
| Accounts deducted from assets on balance sheet: | | | | | | | | | | | | | | | | |
| Allowance for doubtful accounts receivable | | $ | 5,465 | | | $ | 13,126 | | | $ | 12,199 | | | $ | 6,392 | |
| Year Ended December 31, 2007 | | | | | | | | | | | | | | | | |
| Accounts deducted from assets on balance sheet: | | | | | | | | | | | | | | | | |
| Allowance for doubtful accounts receivable | | $ | 2,762 | | | $ | 13,019 | | | $ | 10,316 | | | $ | 5,465 | |
| CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE |
None.
PugetEnergy
Evaluation of Disclosure Controls and Procedures
Under the supervision and with the participation of Puget Energy’s management, including the President and Chief Executive Officer and SeniorExecutive Vice President Finance 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 December 31, 2006,2009, the end of the period covered by this report. Based upon that evaluation, the President and Chief Executive Officer and SeniorExecutive Vice President Finance and Chief Financial Officer of Puget Energy concluded that these disclosure controls and procedures are effective.
Changes in Internal Control Over Financial Reporting
There have been no changes in Puget Energy’s internal control over financial reporting during the quarter ended December 31, 20062009 that have materially affected, or are reasonably likely to materially affect, Puget Energy’s internal control over financial reporting.
Management’s Report on Internal Control Over Financial Reporting
Puget Energy’s management is responsible for establishing and maintaining adequate internal control over financial reporting (as defined in Rule 13a-15(f) under the Securities Exchange Act of 1934). Under the supervision and with the participation of Puget Energy’s President and Chief Executive Officer and SeniorExecutive Vice President Finance and Chief Financial Officer, Puget Energy’s management assessed the effectiveness of internal control over financial reporting based on the framework in Internal Control -– Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission. Based on the assessment, Puget Energy’s management concluded that its internal control over financial reporting was effective as of December 31, 2006.2009.
Puget Energy’s management assessment of the effectiveness of internal control over financial reporting as of December 31, 2006,2009 has been audited by PricewaterhouseCoopers LLP, an independent registered public accounting firm, as stated in their report which is included herein.
Puget Sound Energy
Evaluation of Disclosure Controls and Procedures
Under the supervision and with the participation of PSE’s management, including the President and Chief Executive Officer and SeniorExecutive Vice President Finance 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 December 31, 2006,2009, the end of the period covered by this report. Based upon that evaluation, the President and Chief Executive Officer and SeniorExecutive Vice President Finance and Chief Financial Officer of PSE concluded that these disclosure controls and procedures are effective.
Changes in Internal Control Over Financial Reporting
There have been no changes in PSE’s internal control over financial reporting during the quarter ended December 31, 2006,2009 that have materially affected, or are reasonably likely to materially affect, PSE’s internal control over financial reporting.
Management’s Report on Internal Control Over Financial Reporting
PSE’s management is responsible for establishing and maintaining adequate internal control over financial reporting (as defined in Rule 13a-15(f) under the Securities Exchange Act of 1934). Under the supervision and with the participation of PSE’s President and Chief Executive Officer and SeniorExecutive Vice President Finance and Chief Financial Officer, Puget Sound Energy’s management assessed the effectiveness of internal control over financial reporting based on the framework in Internal Control -– Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission. Based on the assessment, PSE’s management concluded that its internal control over financial reporting was effective as of December 31, 2006.2009.
PSE’s management assessment of the effectiveness of internal control over financial reporting as of December 31, 20062009 has been audited by PricewaterhouseCoopers LLP, an independent registered public accounting firm, as stated in their report which is included herein.
None.Effective February 25, 2010, Stephen P. Reynolds, the President and CEO of Puget Energy and PSE, waived rights to payments or other benefits under the employment agreement with Stephen P. Reynolds dated January 1, 2002, as amended by the First, Second and Third Amendments dated as of May 12, 2005, February 9, 2006 and February 8, 2008, respectively, as a result of a Change in Control (as defined in such employment agreement, as amended).
ITEM 10. DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE
Board of Directors
ITEM 10.Eleven directors currently constitute Puget Energy’s Board of Directors and twelve directors currently constitute PSE’s Board of Directors, as set forth below. The directors are selected in accordance with the Amended and Restated Bylaws of each of Puget Energy and PSE, pursuant to which, the investor-owners of Puget Holdings (the indirect parent company of both Puget Energy and PSE) are entitled to select individuals to serve on the boards of Puget Energy and PSE.DIRECTORS, EXECUTIVE AND CORPORATE GOVERNANCE
William S. Ayer, age 55, is a director on the boards of both Puget Energy and PSE and has extensive experience as the Chief Executive Officer of a locally-based public company with sophisticated operational requirements. Mr. Ayer has been a director of Puget Energy and PSE since 2005. Mr. Ayer has been Chairman, President and Chief Executive Officer of Alaska Air Group (air transportation) since 2003. He is also Chairman and Chief Executive Officer of Alaska Airlines, Inc. since 2008. He served as Alaska Airlines’ Chairman, President and Chief Executive Officer from 2003 to 2008, Chief Executive Officer from 2002 to 2003, and President and Chief Operating Officer from 1997 to 2002. Mr. Ayer also serves on the board of the Seattle Branch, Federal Reserve Bank of San Francisco.
Graeme Bevans, age 52, is a director on the boards of both Puget Energy and PSE. Mr. Bevans is currently Vice President and Head of Infrastructure at CPP Investment Board, which position he has held since 2006. Prior to joining CPP Investment Board, Mr. Bevans served as Senior Investment Manager - Infrastructure at Industry Funds Management in Melbourne, Australia from 2002 to 2006. Mr. Bevans is currently a director on the board of Anglian Water Group, a United Kingdom water/waste-water company and Doowron PTY LTD, a private Australian company. Mr. Beyans has been a director of Puget Energy and PSE since February 2009.
Andrew Chapman, age 54, is a director on the boards of both Puget Energy and PSE. Mr. Chapman is currently a director on the Board of Duquesne Light Holdings, Inc. and Duquesne Light Company, which position he has held since February 1, 2010. Mr. Chapman is currently a Managing Director in the Macquarie Capital Funds division of the Macquarie Group, which position he has held since 2006. Prior to joining the Macquarie Group, Mr. Chapman was Vice President – Strategy & Regulation for American Water from 2005 to 2006 and Regional Managing Director from 2003 to 2004. Mr. Chapman has been a director of Puget Energy and PSE since February 2009.
Alan James, age 56, is a director on the boards of both Puget Energy and PSE. Mr. James is currently the Senior Managing Director of Macquarie Capital (USA) Inc., which position he has held since 2005. Prior to that time, Mr. James was Managing Director and Head, Investment Banking Australia and New Zealand at Citigroup from 2002 to 2005. Mr. James has been a director of Puget Energy and PSE since February 2009.
Alan Kadic, age 38, is a director on the boards of both Puget Energy and PSE. Mr. Kadic is currently a Senior Principal in the Infrastructure Group of the Private Investments department at the Canada Pension Plan Investment Board, which position he has held since 2007. Prior to joining CPP Investment Board, Mr. Kadic served as Vice President at Macquarie Bank Limited in Toronto, Canada from 2004 to 2007. Mr. Kadic is currently a director on the board of Wales and West Utilities, a United Kingdom natural gas distribution company. Mr. Kadic has been a director of Puget Energy and PSE since February 2009.
Christopher Leslie, age 45, is a director on the boards of both Puget Energy and PSE. Mr. Leslie is currently the Executive Director in the Macquarie Capital Funds division of the Macquarie Group, which position he has held since 2005 and has also served as the Chief Executive Officer of Macquarie Infrastructure Partners I and II since 2006. Mr. Leslie served as Executive Director of Macquarie Bank Limited from 2004 to 2005. Mr. Leslie is currently a director on the boards of Duquesne Light Holdings, Inc. and Duquesne Light Company. Mr. Leslie has been a director of Puget Energy and PSE since February 2009.
William McKenzie, age 53, is a director on the boards of both Puget Energy and PSE. Mr. McKenzie has been Senior Vice President - Infrastructure and Timber Investments for Alberta Investment Management Corporation since December 2008. He served as Head, Infrastructure and Timber Investments from 2005 to 2008 and Senior Portfolio Manager, Infrastructure and Timber Investments from 2005 to 2008. Prior to that time, Mr. McKenzie was Managing Director for VectorWest Growth Capital in 2004. Mr. McKenzie has been a director of Puget Energy and PSE since February 2009.
Stephen P. Reynolds, age 61, is a director on the boards of both Puget Energy and PSE, which positions he has held since 2002. Mr. Reynolds has also been President and Chief Executive Officer since February 6, 2009. Prior to the merger on February 6, 2009, Mr. Reynolds was Chairman, President and Chief Executive Officer of Puget Energy and PSE since May 2005, and was President and Chief Executive Officer from January 2002 to April 2005. Mr. Reynolds also serves as a director of Intermec, Inc. and Green Diamond Resources Company.
Herbert B. Simon, age 65, is a director only on the board of PSE and has a deep involvement in commercial and community activities in the Company’s service territory. Mr. Simon has served as a director of Puget Energy and PSE since March 2006. Mr. Simon has been a member of Simon Johnson, L.L.C. (real estate and venture capital projects investment company located in Tacoma, Washington) and its predecessor company since 1985. In addition, Mr. Simon serves as a Regent of the University of Washington.
Chris Trumpy, age 55, became a director on the boards of both Puget Energy and PSE on January 12, 2010. Mr. Trumpy is currently the Chairman of the Pacific Carbon Trust, which position he has held since 2008. He also served as Chairman of the British Columbia Investment Management Corporation (or bcIMC) from 2000 to 2008.
Lincoln Webb, age 38, was a director on the boards of both Puget Energy and PSE at December 31, 2009, which position he held since February 6, 2009. Mr. Webb is currently the Vice President of the Private Placements group at bcIMC, which position he has held since 2005. He also served as Portfolio Manager from 2004 to 2005. Mr. Webb currently serves as a director on the Corix group of companies. Mr. Webb departed the Board of Directors on January 12, 2010.
Mark Wiseman, age 39, is a director on the boards of both Puget Energy and PSE. Mr. Wiseman is currently the Senior Vice President in the Private Investments department at the Canada Pension Plan (CPP) Investment Board, which position he has held since 2005. Mr. Wiseman has served as a director of Puget Energy and PSE since October 16, 2009.
Mark Wong, age 37, is a director on the boards of both Puget Energy and PSE. Mr. Wong is currently the Executive Director in the Macquarie Capital Funds division of the Macquarie Group, which position he has held since 2008 and serves as the Chief Financial Officer and Treasurer of Macquarie Infrastructure Partners I and II, which positions he has held since 2006. Mr. Wong also served as Chief Executive Officer and Secretary of Macquarie Canadian Infrastructure Limited from 2004 to 2005. Mr. Wong has been a director of Puget Energy and PSE since February 2009.
Executive Officers
The information required by this item with respect to Puget Energy and PSE is incorporated herein by reference to the material under “Available Information”“Executive Officers of the Registrants” in Part I of this reportreport.
Audit Committee
The Puget Energy and “Proposal 1 - ElectionPSE Boards of Directors” “Directors Continuing have both established an Audit Committee. Directors Andrew Chapman, Alan Kadic, William McKenzie and William S. Ayer are the members of the Audit Committee. The Board has determined that Andrew Chapman meets the definition of “Audit Committee Financial Expert” under SEC rules. Puget Energy and PSE currently do not have any outstanding stock listed on a national securities exchange and, therefore, there are no independence standards applicable to either company in Office,” “Boardconnection with the independence of its Audit Committee members.
Changes to the Procedures by which Shareholders may recommend Nominees to the Board of Directors
Following the closing of the merger, members of the Boards of Directors of Puget Energy and PSE are nominated and elected in accordance with the provisions of their respective Amended and Restated Bylaws.
Code of Ethics
Puget Energy and PSE have adopted a Corporate Governance,Ethics and Compliance Code applicable to all directors, officers and employees and a Code of Ethics applicable to the Chief Executive Officer and senior financial officers, which are available on the website www.pugetenergy.com. If any material provisions of the Corporate Ethics and Compliance Code or the Code of Ethics are waived for the Chief Executive Officer or senior financial officers, or if any substantive changes are made to either code as they relate to any director or executive officer, we will disclose that fact on our website within four business days. In addition, any other material amendments of these codes will be disclosed.
Communications with the Board
Interested parties may communicate with an individual director or the Board of Directors as a group via U.S. Postal mail directed to: Chairman of the Board of Directors, c/o Corporate Secretary, Puget Energy, Inc., P.O. Box 97034, PSE-12, Bellevue, Washington 98009-9734. Please clearly specify in each communication the applicable addressee or addressees you wish to contact. All such communications will be forwarded to the intended director or Board as a whole, as applicable.
Section 16(a) Beneficial Ownership Reporting Compliance
Prior to the closing of the merger on February 6, 2009, Section 16(a) of the Securities Exchange Act of 1934 required the directors and officers of Puget Energy to file reports of ownership and changes in ownership with respect to the equity securities of Puget Energy with the SEC. To Puget Energy’s knowledge, based on our review of the reports furnished to Puget Energy in 2009 and written representations that no other reports were required, all directors and officers of Puget Energy who were subject to the Section 16 reporting requirements, the applicability of which terminated with the merger, filed the required reports on a timely basis in 2008.
Puget Energy
Puget Sound Energy
Executive Compensation
Compensation and Leadership Development Committee Interlocks and Insider Participation
The members of the Compensation and Leadership Development Committees (referred to as the Committee) of the Boards of Directors (referred to as the Board) of Puget Energy and PSE (referred to as the Company) are named in the Compensation and Leadership Development Committee Report. No members of the Committee were officers or employees of the Company or any of its subsidiaries during 2009, were formerly Company officers or had any relationship otherwise requiring disclosure.
This section provides information about the compensation program for the Company’s Named Executive Officers who are included in the Summary Compensation Table: the President and Chief Executive Officer (CEO), the Chief Financial Officer and the three other most highly compensated executive officers for 2009. It includes a discussion and analysis of the overall objectives of our compensation program and each element of compensation the Company provides. This section also discusses certain changes made to our compensation programs in connection with the completion of the Company’s merger on February 6, 2009, after which time the Company no longer had publicly traded stock. These changes included replacement of equity awards with cash-based incentive awards and certain changes to the performance measures under the incentive plans. Notwithstanding these changes, the Company’s compensation programs generally have maintained their same objectives, basic designs, and participant opportunity.
Compensation Program Objectives
The Company’s executive compensation program has two main objectives:
| · | Support sustained Company performance by having talented people running the business. |
| · | Align compensation payment levels with achievement of Company goals. |
The following is a discussion of the specific strategies the Committee and management used in 2009 to accomplish each of these objectives.
| 1. | Our objective of supporting sustained Company performance by having talented people running the business is supported by the following strategies: |
| · | Designing and delivering compensation programs that attract, retain, and motivate a talented executive team. |
Several factors are critical to attracting and retaining executives for the Company. One is ensuring that total pay opportunity is competitive with similar companies so that new executives will want to join the Company and current executives are not hired away. As described below in the discussion of Compensation Program Elements (Review of Pay Element Competitiveness), the Committee annually compares executive pay to external market data from similar companies in our industry. Base pay and total direct compensation (which is base salary plus annual and long-term incentive pay) are targeted to the 50th percentile of our comparator group. Individual pay adjustments are reviewed to see how they position the executive in relation to the median of market pay, while also considering the executive’s recent performance and experience level. The Company may choose to pay an individual above or below the median level of market pay when our executive has a role with greater or lesser responsibility than the best comparison job or when our executive’s experience and performance exceed those typically found in the market. The Committee recommends the pay level for our President and Chief Executive Officer and the pay levels for the other executives, based on recommendations from our President and Chief Executive Officer, to the full Board for approval.
Another factor critical to attracting, retaining, and motivating our executives is to provide incentive compensation for meeting and exceeding target levels of annual and long-term goals. By establishing goals, monitoring results, and providing payments and recognition for accomplishment of results, the Company focuses executives on actions that will improve the Company and enhance investor value, while also retaining key talent. As described below, the Company’s policies and practices surrounding incentive pay reduce the risk that employees would seek to take untoward risks in an attempt to increase incentive results.
A final critical factor in attracting, retaining, and motivating our executives is to provide them with retirement income. We recognize that executives choose to work for the Company from a variety of other alternative organizations, and one financial goal of employees is to provide a secure future for themselves and their families. The Committee reviews the design of retirement programs provided by the comparator group and provides benefits that are commensurate with this group.
| · | Designing and delivering incentive programs that support the Company’s business direction as approved by the Board and align executive interests with those of investors and customers. |
In addition to rewarding performance that meets or exceeds goals, our annual and long-term incentives help executives focus on the priorities of our investors and customers. Both the annual incentive plan and the long-term incentive plan measure and reward the Company’s performance on Service Quality Indices (SQIs). These reporting measures were developed in collaboration with the Company’s regulator and provide customers with a report card on the Company’s customer service and reliability. In fact, we provide an annual accounting on these measures to our customers each year. (See the section Annual Incentive Compensation below) Additional key measures used in 2009 for determining incentives were Earnings Before Interest, Taxes, Depreciation and Amortization (EBITDA) in the annual incentive plan and Total Return in the long-term incentive plan. EBITDA and Total Return are important performance measures to our investors, and their accomplishment also indicates to our customers that the Company has the financial strength needed for long-term sustainability.
The Committee evaluates the performance factors and targets for its annual and long-term incentive programs each year. The Committee believes that the programs’ design and the balance between annual and long-term incentives and the performance targets based on management’s operating plan, which includes providing good customer service, do not provide an incentive to executives to take unreasonable risks that could have a material adverse effect relating to the Company’s business.
| · | Executing the Company’s succession planning process to ensure that executive leadership continues uninterrupted by executive retirements or other personnel changes. |
The President and CEO leads the talent reviews for leadership succession planning through meetings with his executive team. Each executive conducts talent reviews of senior employees who have high potential for assuming greater responsibility in the Company. The talent reviews include evaluations prepared within the Company and by external organizational development consultants. The Committee annually reviews these assessments of executive readiness, the plans for development of the Company’s key executives, and progress made on these succession plans. The Committee directly participates in discussion of succession plans for the position of President and CEO.
| 2. | Our objective of aligning compensation payment levels with achievement of Company goals is supported by the following strategy: |
| · | Placing a significant portion of each executive’s total direct compensation at risk to align executive compensation with financial and operating performance. |
When Company results are above expectations, total direct compensation is higher than our target of the 50th percentile of our comparator group. If results are below expectations, total direct compensation is lower than this targeted level. Under a philosophy of “pay for performance,” “Directorthe Company’s variable pay program helps focus executives and creates a record of their results. The Company structures its incentive compensation programs so that individual award opportunities are defined and subject to limits, goal funding is based on collective company performance, and all incentive awards to individual executives are subject to discretionary review by management and/or the Board.
Compensation Program Elements
This section identifies the elements of the Company’s compensation program in greater detail and examines how these elements function and why the Committee and Board chooses to include the items in the compensation program.
The Company’s compensation policies encompass a mix of base salary, annual and long-term incentive compensation, retirement programs, health and welfare benefits and a small number of perquisites. The Company also provides certain post-termination and change in control benefits to executives. The total package is designed to provide participants with appropriate incentives that are competitive with the comparator group and achieve current operational performance and customer service goals as well as the long-term objective of enhancing investor value. The Company does not have a specific policy regarding the mix of compensation elements, though long-term incentive programs are designed to comprise the largest portion of each executive’s incentive pay. The Company arrives at a mix of pay by setting each compensation element relative to market comparators. The Company delivered cash compensation to the Named Executive Officers in 2009 through base salary to provide liquidity for the executives and through incentive programs to focus performance on important Company goals and to increase the connection to investors. Annually the Committee reviews total compensation opportunity and actual total compensation received over the prior years by each executive officer in the form of a tally sheet. This review helps inform the Committee’s decisions on program designs by allowing the Committee to review overall pay received in relation to Company results.
Review of Pay Element Competitiveness
In making compensation decisions on base salary and annual and long-term incentive programs, management prepares comprehensive surveys of pay for review by the Committee and the Committee’s outside executive pay consultant, Towers Watson (formerly Towers Perrin). The surveys summarize data provided by the Towers Perrin 2008 Energy Services survey for a selection of utility and other companies that are most similar in scope and size to Puget Sound Energy. For the review of compensation pay levels and practices in 2009, we included the following utility companies in our comparator group that were all of similar scope (generally $1.5 billion — $6.0 billion revenue and $4.0 billion — $11.0 billion asset size) and also participated in the Towers Perrin 2008 Energy Services survey:
| 1. | AGL Resources | 7. | New York Power Authority | 13. | Pinnacle West Capital |
| 2. | Allegheny Energy | 8. | Northeast Utilities | 14. | Portland General Electric |
| 3. | Alliant Energy | 9. | Nicor | 15. | SCANA |
| 4. | Avista | 10. | NSTAR | 16. | Southern Union Company |
| 5. | City Public Service | 11. | OGE Energy | 17. | Westar Energy |
| 6. | MDU Resources | 12. | PNM Resources | 18. | Wisconsin Energy |
Base Salary
Base salaries are generally targeted at the 50th percentile for the comparator group. Actual salaries vary by individual and depend on additional factors, such as expertise, individual performance achievement, level of experience and level of contribution relative to others in the organization.
Generally, base salaries for executives are determined by the Committee on an individual basis using as a guideline, median salary levels of our comparator group companies, as well as internal pay equity among executives. We recognize that it is necessary to provide executives with a portion of total compensation that is delivered each month and provides a balance to other pay elements that are at risk.
Base Salary Adjustments
The Committee did not change the base salaries of the Named Executive Officers for 2009, in light of the difficult economic environment faced by many of our customers. Base salaries generally remained at the median of market among the comparator group.
Annual Incentive Compensation
In addition to reviewing base salaries paid by our market comparator group, we also review annual incentive payments through an annual review of total cash compensation (base salaries plus incentives). Total cash compensation is targeted at the 50th percentile of total cash compensation for the industry comparator group if the Company’s annual performance goals are achieved at target. If performance goals significantly exceed target, total cash compensation can approach the 75th percentile.
All PSE employees, including executive officers, participate in an annual incentive program referred to as the “Goals and Incentive Plan.” The plan is designed to provide financial incentives to executives for achieving desired annual operating results while meeting the Company’s service quality commitment to customers. The Company’s service quality commitment is measured by performance against 10 SQIs covering three broad categories, set forth below. These are the same SQIs for which the company is accountable to the Washington Commission. The Company is required to provide an annual report to the Washington Commission and PSE’s customers describing each SQI, how it is measured, the Company’s required level of achievement, and performance results. This report for prior years and for 2009 is available at http://www.PSE.com/PerformanceReportCards.
The SQIs for 2009 were as follows:
| · | Customer Satisfaction (3 SQIs) |
| | ¾ | Customer satisfaction with the telephone access center, gas field services and Washington Commission complaints |
| · | Customer Service (3 SQIs) |
| | ¾ | Calls answered “live,” on-time appointments and limiting disconnects for non-payment |
| · | Safety and Reliability (4 SQIs) |
| | ¾ | Gas emergency response, electric emergency response, non-storm outage frequency and non-storm outage duration |
The annual incentive plan had a funding level based on EBITDA and attainment of SQIs as shown in the table below.
| Annual Incentive Performance Payout Scale |
| Performance | 2009 EBITDA (In Millions) | SQI* | Funding Level |
| Maximum | $1,233 | 10/10 | 200% |
| Target | 913 | 10/10 | 100% |
| Trigger Payout Funding | 822 | 6/10 | 30% |
| _________________ |
| * | SQI results of 6/10 or better required for any incentive payout funding. SQI results below 10/10 reduce funding (e.g., 9/10 = 90%, 8/10 = 80%, etc.). |
| 2009 Actual Performance | $876.5 | 9/10 | 72.4% |
The Committee can adjust EBITDA used in the annual incentive calculation to exclude nonrecurring items that are outside the normal course of business for the year, but did not do so for 2009. Individual awards may be adjusted based on a subjective evaluation of an executive officer’s performance against team and individual goals. Individual goals were developed from the overall corporate goals for 2009:
2009 Corporate Goals
| · | Enhance Customer Service — Respond to our customers by listening, leveraging new systems, updating processes and providing innovative and improved services, products and programs. |
| · | Optimize Generation and Delivery — Secure and maintain reliable resources, build or replace infrastructure in a way that meets our customers’ needs, promotes environmental stewardship and provides a fair return to investors. |
| · | Be a Good Neighbor — Embrace our role as a leader to protect and improve our natural gas and electric service, promote energy efficiency initiatives, encourage corporate giving and instill community involvement. |
| · | Value Employees — Safety is key; work safely. Value diversity, teamwork and open communication. Support employees through technology, process improvement, recognition, training and development. Strive to make PSE a great place to work. |
| · | Own it — Conduct ourselves and our business in a manner that is ethical, responsible and meets or exceeds any internal or external compliance obligation. Take personal responsibility for meeting customer needs while using company resources and facilities wisely. |
| · | Continue to Learn and Grow — Strive to get better at what we do every day. Continuously examine past practices, challenge our assumptions and apply lessons learned to improve our efforts on behalf of customers and the community. |
Actual performance of the corporate goals for 2009 was below target but above the threshold level for EBITDA, and below target for SQI achievement. PSE EBITDA was $876.5 million, and SQI achievement was 9 out of 10, leading to a funding level of 72.4%.
For 2009, the target incentives for this plan varied by executive officer as a percentage of base salary as shown in the table below. The maximum incentive for exceptional performance in this plan is twice the target incentive. An individual executive officer’s formula amount can be increased or decreased based on a subjective assessment by the CEO (or the Board in the case of the CEO) of the officer’s individual and team performance results. After considering performance on individual and team goals, which were met by each executive officer, small adjustments were made by the CEO for individual performance of the Named Executive Officers below CEO in 2009 and the following amounts were approved by the Board and paid at the amounts as shown below. The adjustments for individual performance did not materially change amounts from the formula amount of 72.4% of target.
| Name | | Target Incentive (% of Base Salary) | | 2009 Actual Incentive Paid | | 2009 Actual Incentive (% of Base Salary) |
| Stephen P. Reynolds | | | 85 | % | | $ | 507,705 | | | | 62 | % |
| Bertrand A. Valdman | | | 60 | % | | | 154,429 | | | | 39 | % |
| Eric M. Markell | | | 60 | % | | | 172,022 | | | | 48 | % |
| Kimberly J. Harris | | | 60 | % | | | 172,022 | | | | 48 | % |
| Jennifer L. O’Connor | | | 50 | % | | | 101,161 | | | | 33 | % |
Long-Term Incentive Compensation
Total direct compensation opportunities (base salary, annual incentive and long-term incentives) are designed to be competitive with market practices, generally targeting the 50th percentile of the comparator group for performance at target. Prior to the merger, executives received equity awards under the Puget Energy 2005 Long-Term Incentive Plan (LTIP) in the form of performance shares and performance-based restricted stock. Awards vested based on the Company achieving a targeted level of performance during a three-year performance cycle. Upon the merger, all unvested LTIP awards accelerated in vesting and became payable in cash pursuant to the terms of the LTIP. Performance shares under the LTIP were paid based upon 149.5% achievement of the target performance level for each outstanding performance cycle plus the amount of associated dividend equivalents. The amounts paid as a result of the merger for the 2007-2009 and 2008-2010 LTIP performance cycles were previously described in the Company’s 2008 Form 10-K and are shown in the Option Exercises and Stock Vested in 2009 Table.
Effective for 2009, the Company has continued the basic design of the LTIP program, including retention of three-year performance cycles, one of which begins each year. Since the Company no longer has publicly listed stock, LTIP awards for the 2009-2011 performance cycle are denominated in units and will be settled in cash if threshold performance measures are met. The total amount payable for a performance cycle is calculated at the end of the performance cycle based on the performance measures of Total Return and SQIs according to the percentages shown below as well as the per unit dollar value at the end of the performance cycle. Unit value is re-calculated each year based on the change in Total Return for the prior year as measured by an independent auditing firm. For any award to be earned in a performance cycle, average SQI results must meet or exceed 8 out of the 10 SQIs set forth above under Annual Incentive Compensation. Executives must be employed on a payment date to receive a cash payment under the LTIP, except in the event of retirement at normal retirement age or approved early retirement, disability or death.
| Grant Cycle | SQI Component | Total Return Component |
| 2009-2011* | 50% | 50% |
______________| * | CEO grants are split 30% SQI component and 70% Total Return Component. |
| Service Quality Indices (SQIs) Component Table |
| SQI Result, 3 year average | Percentage of LTIP Target Award |
| 8 of 10 or above | 100% |
| Below 8 | 0% |
The table below shows the percentage of LTIP target awards under the Total Return Component that will be earned based on three-year performance. Percentages will be interpolated if performance falls between the values shown below.
| Total Return Component Table |
| Percentage of LTIP Target Award |
Annualized 3 Year Return | 10/10 SQI (3 year average) | 9/10 SQI (3 year average) | 8/10 SQI (3 year average) | <8/10 SQI (3 year average) |
| 15% or more | 210% | 175% | 155% | 0% |
| 14% | 180% | 150% | 130% | 0% |
| 13% | 150% | 125% | 105% | 0% |
| 12% | 120% | 100% | 80% | 0% |
| 11% | 80% | 65% | 50% | 0% |
| 10% | 40% | 30% | 20% | 0% |
| <10% | 0% | 0% | 0% | 0% |
The Committee determined the number of LTIP units granted to each executive by evaluating the actual payment and forecast target payment of long-term incentive awards of our market comparator group for comparable levels of responsibility. The Committee generally did not consider previously granted awards or the level of accrued value from prior programs when granting annual incentive awards or making new LTIP grants. Each year’s grant is primarily viewed in the context of the compensation opportunity needed to maintain the Company’s competitive position relative to the comparator group. Target LTIP awards are calculated based on a percentage of annual salary. Target LTIP awards for 2009-2011 performance cycle were 170% of base salary for Mr. Reynolds; 110% for Mr. Valdman, Mr. Markell and Ms. Harris; and 95% for Ms. O’Connor. The points below summarize the performance measures and design of the LTIP grants.
SQI Component:
| · | A target number of units are granted at the beginning of a three-year performance cycle that will be paid in cash to the participant if the Company achieves the targeted level of 8 of 10 SQIs during the performance cycle. The actual award is paid at target level if an average of 8 out of 10 SQIs are satisfied during the performance cycle, but is not paid if the average is below 8 out of 10. If threshold SQI performance is met, the amount payable is equal to the product of the target number of units granted and the per unit value at the end of the performance cycle. |
| · | If 8 of out 10 SQIs are met during the performance cycle, but the Total Return threshold of 10% is not met, the SQI component will still be paid at target. |
Total Return Component:
| · | A target number of units are granted at the beginning of a three-year performance cycle that will be paid in cash to the participant if the Company achieves the targeted level of Total Return performance during the three-year performance cycle. The actual award paid is based on Company performance relative to target, subject to a minimum threshold level of performance of 10% for Total Return (based on average Total Return over the performance cycle) and SQI achievement of 8 out of 10 SQIs. |
| · | The LTIP unit value is determined annually by applying the Total Return for each year to the prior year’s unit price. Total Return is measured at the Puget Holdings LLC level and is calculated based on an annual valuation prepared by an independent auditing firm that reflects the annual change in the value of the company plus any distributions made to investors. |
| · | At the completion of the performance cycle, if the Total Return component is paid, the participant receives a cash payment equal to the number of units earned based on performance during the performance cycle multiplied by the unit price at the end of the performance cycle. |
| · | If the Total Return component exceeds 10% annualized 3-year return, but the SQI threshold is not met, the Total Return component will not be paid. |
| LTIP Performance of Outstanding Awards |
| The Company’s 2009-2011 LTIP grants are outstanding and had the following performance during 2009: |
| · | 2009-2011 Grant: Award calculation is based on the full three-year performance cycle, so no award payment calculations will be made until after 2011. Performance on the Total Return component during 2009 was 5.2%, below the three-year average threshold needed for payment. Performance on the SQI component of the grant was at 9 out of 10, which if continued for the remaining two years of the performance cycle would mean that the SQI component would pay based on the target number of units granted to a Named Executive Officer. |
Retirement Plans — Supplemental Executive Retirement Plan (SERP)
The Company maintains the SERP for executives to provide a benefit that is coordinated with the tax-qualified Retirement Plan for Employees of Puget Sound Energy, Inc. (Retirement Plan). Without the addition of the SERP, these executives would receive lower percentages of replacement income during retirement than other employees. All the Named Executive Officers except Mr. Reynolds participate in the SERP. When Mr. Reynolds was hired, he elected to receive an annual contribution to his account in the Deferred Compensation Plan for Key Employees in lieu of participating in the SERP, as described in the following paragraph. He participates in the Retirement Plan. Additional information regarding the Retirement Plan and the SERP is shown in the “2009 Pension Benefits” table.
Retirement Plans — Deferred Compensation Plan for Key Employees (Deferred Compensation Plan)
The Named Executive Officers are eligible to participate in the Deferred Compensation Plan. The Deferred Compensation Plan provides executives an opportunity to defer up to 100% of base salary, annual incentive bonus and LTIP awards, plus receive additional Company contributions made by PSE into an account that, until February 5, 2009, had four investment tracking fund choices (three choices after February 5, 2009). The funds mirror performance in major asset classes of bonds, stocks, an interest crediting fund that changes rate quarterly based on corporate bond rates, and Puget Energy stock until it was delisted. Similar to the SERP, the Deferred Compensation Plan is intended to allow the executives to defer current income, without being limited by the Internal Revenue Code contribution limitations for 401(k) plans and therefore have a deferral opportunity similar to other employees as a percentage of eligible compensation. The Company contributions are also intended to restore benefits not available to executives under PSE’s tax-qualified plans due to Internal Revenue Code limitations on compensation and benefits applicable to those plans. Under the terms of Mr. Reynolds’ employment agreement, he additionally receives an annual Company contribution to his Deferred Compensation Plan account equal to 15% of the base salary and annual incentive payment he received during the prior year. Additional information regarding the Deferred Compensation Plan and Mr. Reynolds’ employment agreement arrangement, as well as his year-end balance, is shown in the “2009 Nonqualified Deferred Compensation” table.
Post-Termination Benefits
The Company has entered into agreements with its executive officers, including the Named Executive Officers, that provide for certain payments and “Securitybenefits if an executive’s employment is terminated or terminates for certain reasons, such as following a change in control. Benefits provided under these agreements are important for two primary reasons. First, many executives when joining a new company require a level of assurance that they will receive pay in the event of a termination of employment following a change in control after they join the company. Second, the Company provides these agreements so that the executives are focused on the Company’s ongoing operations and are not distracted by the employment uncertainty that can arise in the event of a change in control. The Committee periodically reviews existing change in control arrangements for the comparator group considering benchmarking information provided by Towers Watson. Based on this information, the Committee believes that the arrangements generally provide benefits that are similar to those of the comparator group.
The Company’s merger, which was completed on February 6, 2009, was a change in control event under the Company’s then effective change in control agreements and arrangements that resulted in the payment to each Named Executive Officer of the amounts included in the Option Exercises and Stock Vested in 2009 Table. Effective March 30, 2009, the Company entered into new Executive Employment Agreements with the Named Executive Officers, except Mr. Reynolds, which amended and restated existing Amended and Restated Change of Control Agreements between the Company and each of the executives. The Executive Employment Agreements provide for an employment period of two years following completion of the merger and generally provide benefits similar to those under the previous Change of Control Agreements. In addition, the agreements provide for a merger performance bonus payable on or shortly following each of the first and second anniversaries of the completion of the merger if the Company achieves specified minimum SQI performance goals established by the Committee (for 2009, 8 out of 10 SQIs or better) and the executive remains employed at the Company until the anniversary of the merger for which payment is made. Following the merger, Mr. Reynolds’ employment agreement, as amended, continued, except that effective as of December 31, 2009, Mr. Reynolds agreed to waive benefits and payments that might otherwise be payable under the agreement upon a subsequent change in control. The “Potential Payments Upon Termination or Change in Control” section describes the current post-termination arrangements with the Named Executive Officers as well as other plans and arrangements that would provide benefits on termination of employment or a change in control, and the estimated potential incremental payments upon a termination of employment or change in control based on an assumed termination or change in control date of December 31, 2009.
Other Compensation
In addition to base salary and annual and long-term incentive award opportunities, the Company also provides the Named Executive Officers with benefits and perquisites targeted to competitive practices. The executives participate in the same group health and welfare plans as other employees. Company vice presidents and above, including the Named Executive Officers, are eligible for additional disability and life insurance benefits. The executives are also eligible to receive reimbursement for financial planning, tax preparation, legal services, business club memberships and executive physicals. The reimbursement for financial planning, tax preparation and legal services is provided to allow executives to concentrate on their business responsibilities. Business club memberships are provided to allow access for business meetings and business events at club facilities and executives are required to reimburse the Company for individual use of club facilities. Perquisites do not make up a significant portion of executive compensation, amounting to less than $10,000 in total for each Named Executive Officer in 2009.
Relationship among Compensation Elements
A number of compensation elements increase in absolute dollar value as a result of increases to other elements. Base salary increases translate into higher dollar value incentive opportunity for annual and long-term incentives, because each plan operates with a target level award set as a percentage of base salary. Base salary increases also increase the level of retirement benefits, as do actual annual incentive plan payments. Some key compensation elements are excluded from consideration when determining other elements of pay. Retirement benefits exclude LTIP payments in the calculation of qualified retirement (pension and 401(k)) and SERP benefits.
Impact of Accounting Treatment of Compensation
The accounting treatment of compensation generally has not been a factor in determining the amounts of compensation for our executive officers. However, the Company considers the accounting impact of various program designs to balance the potential cost to the Company with the benefit/value to the executive.
The Board delegates responsibility to the Compensation and Leadership Development Committee to establish and oversee the Company’s executive compensation program. Except as noted below, each member of the Committee was appointed February 6, 2009 and served during 2009. Each member meets the independence requirements of the SEC and the NYSE.
The Committee’s members listed below, have reviewed and discussed the “Compensation Discussion and Analysis” with the Company’s management. Based on this review and discussion, the Committee recommended to the current Board, and the current Board has approved, that the “Compensation Discussion and Analysis” be included in the Company’s Annual Report on Form 10-K for the year ended December 31, 2009 for filing with the SEC.
Compensation and Leadership
Development Committee of
Puget Energy, Inc.
Puget Sound Energy, Inc.
Graeme Bevans, Chair
Christopher Leslie
Herb Simon (PSE Only)
Chris Trumpy (appointed January 12, 2010)
The following information is furnished for the year ended December 31, 2009 with respect to the “Named Executive Officers” during 2009. The positions and offices below are at Puget Energy and PSE, except that Mr. Valdman and Ms. Harris are officers of PSE only. Salary compensation includes amounts deferred at the executive’s election.
| Name and Principal Position | Year | | Salary | | Bonus | | Stock Awards 1 | | Option Awards 1 | | Non-Equity Incentive Plan Compensation 2 | | Change in Pension Value and Nonqualified Deferred Compensation Earnings 3 | | All Other Compensation 4 | | Total |
| | | | | | | | | | | | | | | | | | |
| Stephen P. Reynolds President and Chief Executive Officer | 2009 | | $ | 825,000 | | $ | -- | | $ | -- | | $ | -- | | $ | 507,705 | | $ | 69,885 | | $ | 6,595,041 | | $ | 7,997,631 |
| 2008 | | | 819,792 | | | -- | | | 1,341,221 | | | -- | | | 788,906 | | | 29,910 | | | 316,124 | | | 3,295,953 |
| 2007 | | | 794,896 | | | -- | | | 1,538,955 | | | -- | | | 722,160 | | | 20,328 | | | 330,647 | | | 3,406,986 |
| | | | | | | | | | | | | | | | | | | | | | | | | | |
Bertrand A. Valdman Executive Vice President and Chief Operating Officer | 2009 | | $ | 395,000 | | $ | -- | | $ | -- | | $ | -- | | $ | 154,429 | | $ | 158,380 | | $ | 373,521 | | $ | 1,081,330 |
| 2008 | | | 390,836 | | | -- | | | 416,284 | | | -- | | | 266,625 | | | 136,157 | | | 47,660 | | | 1,257,562 |
| 2007 | | | 372,754 | | | -- | | | 448,501 | | | -- | | | 238,950 | | | 107,558 | | | 48,111 | | | 1,215,874 |
| | | | | | | | | | | | | | | | | | | | | | | | | | |
Eric M. Markell Executive Vice President and Chief Financial Officer | 2009 | | $ | 360,000 | | $ | 15,638 | | $ | -- | | $ | -- | | $ | 156,384 | | $ | 309,648 | | $ | 289,672 | | $ | 1,115,704 |
| 2008 | | | 347,500 | | | -- | | | 379,422 | | | -- | | | 243,000 | | | 281,473 | | | 39,767 | | | 1,291,162 |
| 2007 | | | 288,154 | | | -- | | | 284,050 | | | -- | | | 175,230 | | | 175,460 | | | 31,968 | | | 954,862 |
| | | | | | | | | | | | | | | | | | | | | | | | | | |
| Kimberly J. Harris Executive Vice President and Chief Resource Officer | 2009 | | $ | 360,000 | | $ | 15,638 | | $ | -- | | $ | -- | | $ | 156,384 | | $ | 222,948 | | $ | 270,937 | | $ | 1,010,269 |
| 2008 | | | 347,499 | | | -- | | | 379,422 | | | -- | | | 243,000 | | | 183,238 | | | 22,372 | | | 1,175,531 |
| 2007 | | | 288,604 | | | -- | | | 289,206 | | | -- | | | 175,230 | | | 74,582 | | | 22,876 | | | 850,498 |
| | | | | | | | | | | | | | | | | | | | | | | | | | |
Jennifer L. O’Connor Senior Vice President General Counsel, Corporate Secretary, and Chief Ethics and Compliance Officer | 2009 | | $ | 310,500 | | $ | -- | | $ | -- | | $ | -- | | $ | 101,161 | | $ | 162,103 | | $ | 255,244 | | $ | 829,008 |
| 2008 | | | 308,313 | | | -- | | | 282,641 | | | -- | | | 174,656 | | | 172,627 | | | 31,684 | | | 969,921 |
| 2007 | | | 297,754 | | | -- | | | 309,880 | | | -- | | | 143,370 | | | 125,354 | | | 29,002 | | | 905,360 |
| 1 | Reflects the grant date fair value of LTIP grants. Assumptions used in the calculation of these amounts are included in note 18 to the Company’s audited financial statements for the fiscal year ended December 31, 2009 included in the Company’s Form 10-K (the “2009 Form 10-K”). LTIP awards under the 2007 and 2008 LTIP performance cycles accelerated in vesting upon the merger and were paid in cash, as described in the “Compensation Discussion and Analysis” and “Option Exercises and Stock Vested in 2009” table. |
| 2 | Reflects annual cash incentive compensation paid under the 2009 Goals and Incentive Plan. These amounts are based on performance in 2009, but were determined by the Board in February 2010 and paid shortly thereafter or deferred at the executive’s election. The 2009 Goals and Incentive Plan is described in further detail under “Compensation Discussion and Analysis.” The threshold, target and maximum amounts of annual cash incentive compensation that could have been paid for 2009 performance are set forth in the “2009 Grants of Plan-Based Awards” table. |
| 3 | Reflects the aggregate increase in the actuarial present value of the executive’s accumulated benefit under all pension plans during the year. The amounts are determined using interest rate and mortality rate assumptions consistent with those used in the Company’s financial statements and include amounts which the executive may not currently be entitled to receive because such amounts are not vested. Information regarding these pension plans is set forth in further detail under “2009 Pension Benefits.” Mr. Reynolds does not participate in the SERP, and his accumulated benefit shown is only from the qualified pension plan. The change in pension value amounts for 2009 are: Mr. Reynolds, $20,079; Mr. Valdman, $156,597; Mr. Markell, $304,746; Ms. Harris, $219,277; and Ms. O’Connor $156,346. Also included in this column are the portion of Deferred Compensation Plan earnings that are considered above market. These amounts for 2009 are: Mr. Reynolds, $49,806; Mr. Valdman, $1,783; Mr. Markell, $4,902; Ms. Harris, $3,671; and Ms. O’Connor, $5,757. See the “2009 Nonqualified Deferred Compensation” table for all Deferred Compensation Plan earnings. |
| 4 | All Other Compensation is shown in detail in the table below. |
Detail of All Other Compensation
| Name | | Perquisites and Other Personal Benefits 1 | | | Accelerated LTIP And Merger Related Payments 2 | | | Tax Reimbursements | | | Payments/ Accruals on Termination Plans | | | Registrant Contributions to Defined Contribution Plans 3 | | | Other 4 | |
| Stephen P. Reynolds | | $ | 9,644 | | | $ | 6,215,172 | | | $ | -- | | | $ | -- | | | $ | 365,868 | | | $ | 4,356 | |
| Bertrand A. Valdman | | | 6412 | | | | 322,450 | | | | -- | | | | -- | | | | 41,998 | | | | 2,661 | |
| Eric M. Markell | | | 4754 | | | | 244,839 | | | | -- | | | | -- | | | | 38,480 | | | | 1,600 | |
| Kimberly J. Harris | | | 5,419 | | | | 246,880 | | | | -- | | | | -- | | | | 17,000 | | | | 1,638 | |
| Jennifer L. O’Connor | | | 2,500 | | | | 221,052 | | | | -- | | | | -- | | | | 30,973 | | | | 719 | |
| 1 | Annual reimbursement for financial planning, tax planning, and/or legal planning, up to a maximum of $2,500 for Ms. O’Connor and $5,000 for other Named Executive Officers. Club use is primarily for business purposes, but Company club expense is included where the executive is also able to use the club for personal use. Expenses for personal club use are directly paid by the executive, not PSE. |
| 2 | This column includes payments made as a result of the merger: cash severance of $4,578,750 to Mr. Reynolds and the amount of accelerated LTIP payments that were not previously disclosed in the Stock Awards column of the Summary Compensation Table for 2007 and 2008. LTIP payments were: Mr. Reynolds, $1,636,422; Mr. Valdman, $322,450; Mr. Markell, $244,839; Ms. Harris, $246,880; and Ms. O’Connor, $221,052. The total amount paid as a result of accelerated LTIP payments is shown in the “Option Exercises and Stock Vested in 2009” table. |
| 3 | Includes Company contributions during 2009 to PSE’s Investment Plan (a tax qualified 401(k) plan) and the Deferred Compensation Plan. For Mr. Reynolds, this includes the Company contribution to the Performance-Based Retirement Equivalent Stock Account, which is described in more detail in the “2009 Nonqualified Deferred Compensation” section. |
| 4 | Reflects the value of imputed income for life insurance. |
2009 Grants of Plan-Based Awards
The following table presents information regarding 2009 grants of non-equity annual incentive awards LTIP awards and the merger performance bonus, including, as applicable, the range of potential payouts for the awards:
| | | | Estimated Future Payouts under Non-Equity Incentive Plan Awards | |
Name | Grant Date | | Number Of Units Granted | | | Threshold | | | Target | | | Maximum | |
| | | | | | | | | | | | | | |
| Stephen P. Reynolds | | | | | | | | | | | | | |
Annual Incentive 1 | 1/1/2009 | | | | | $ | 210,375 | | | $ | 701,250 | | | $ | 1,402,500 | |
LTIP 2009-2011 2 | 5/19/2009 | | | 46,750 | | | | 420,750 | | | | 1,970,412 | | | | 3,775,458 | |
| | | | | | | | | | | | | | | | | | |
| Bertrand A. Valdman | | | | | | | | | | | | | | | | | |
Annual Incentive 1 | 1/1/2009 | | | | | | $ | 71,100 | | | $ | 237,000 | | | $ | 474,000 | |
LTIP 2009-2011 2 | 5/19/2009 | | | 14,484 | | | | 217,252 | | | | 610,445 | | | | 1,024,278 | |
Merger Performance Bonus3 – Year 1 | 3/30/2009 | | | | | | | | | | | 395,000 | | | | | |
Merger Performance Bonus3—Year 2 | 3/30/2009 | | | | | | | | | | | 395,000 | | | | | |
| | | | | | | | | | | | | | | | | | |
| Eric M. Markell | | | | | | | | | | | | | | | | | |
Annual Incentive 1 | 1/1/2009 | | | | | | $ | 64,800 | | | $ | 216,000 | | | $ | 432,000 | |
LTIP 2009-2011 2 | 5/19/2009 | | | 13,200 | | | | 198,000 | | | | 556,351 | | | | 933,513 | |
Merger Performance Bonus3 – Year 1 | 3/30/2009 | | | | | | | | | | | 360,000 | | | | | |
Merger Performance Bonus3—Year 2 | 3/30/2009 | | | | | | | | | | | 360,000 | | | | | |
| | | | | | | | | | | | | | | | | | |
| Kimberly J. Harris | | | | | | | | | | | | | | | | | |
Annual Incentive 1 | 1/1/2009 | | | | | | $ | 64,800 | | | $ | 216,000 | | | $ | 432,000 | |
LTIP 2009-2011 2 | 5/19/2009 | | | 13,200 | | | | 198,000 | | | | 556,351 | | | | 933,513 | |
Merger Performance Bonus3 – Year 1 | 3/30/2009 | | | | | | | | | | | 360,000 | | | | | |
Merger Performance Bonus3—Year 2 | 3/30/2009 | | | | | | | | | | | 360,000 | | | | | |
| | | | | | | | | | | | | | | | | | |
| Jennifer L. O’Connor | | | | | | | | | | | | | | | | | |
Annual Incentive 1 | 1/1/2009 | | | | | | $ | 46,575 | | | $ | 155,250 | | | $ | 341,550 | |
LTIP 2009-2011 2 | 5/19/2009 | | | 9,834 | | | | 147,488 | | | | 414,419 | | | | 695,361 | |
Merger Performance Bonus3 – Year 1 | 3/30/2009 | | | | | | | | | | | 310,500 | | | | | |
Merger Performance Bonus3—Year 2 | 3/30/2009 | | | | | | | | | | | 310,500 | | | | | |
_______________
| 1 | Annual Goals and Incentive Plan. As described in the “Compensation Discussion and Analysis,” the plan had dual funding triggers in 2009 of $822 million EBITDA and SQI performance of 6/10. Payment would be $0 if either trigger is not met. The threshold estimate assumes $822 million EBITDA and SQI performance at 6/10. The target estimate assumes $913 million EBITDA and SQI performance at 10/10. The maximum estimate assumes $1,233 million EBITDA or higher and SQI performance at 10/10. |
| 2 | LTIP grants as described in the “Compensation Discussion and Analysis.” Payment of LTIP grants are calculated based on the three-year performance of SQIs and Total Return at Puget Holdings LLC and the unit value at the end of the performance cycle. Threshold estimate assumes that SQI results average 8/10, Total Return is below 10%, and ending unit value is $30. Target estimate assumes that SQI results average 9/10, Total Return averages 12%, and ending unit value is $42.15. Maximum estimate assumes that SQI results average 10/10, Total Return averages 15%, and ending unit value is $45.63. |
| 3 | Merger performance bonus is payable to Mr. Valdman, Mr. Markell, Ms. Harris, and Ms. O’Connor based upon Amended and Restated Executive Employment Agreements executed on March 30, 2009. If the Company achieves 8 out of 10 SQIs or higher and the executive continues employment until the first anniversary of the merger, 100% of then current base salary will be paid. Likewise, if the Company achieves 8 out of 10 SQIs or higher and the executive continues employment until the second anniversary of the merger, 100% of then current base salary will be paid. No amounts are shown at threshold or maximum as the award provides for only a single payment if performance measures are met and employment continues until the required date(s). Merger performance bonuses for Year 2 are based on 2009 base salaries. |
Outstanding Equity Awards at 2009 Fiscal Year-End
No equity awards were outstanding at 2009 fiscal year-end. In connection with the completion of the merger on February 6, 2009, all outstanding equity awards were cancelled in exchange for the cash payments described in the “Options Exercises and Stock Vested in 2009” table.
Option Exercises and Stock Vested in 2009
In connection with completion of the merger on February 6, 2009, the Company cancelled all outstanding equity awards in exchange for cash payments. The table below shows the number of shares for which payment was made (though no shares were actually acquired by a Named Executive Officer in connection with such payment) and the pre-tax dollar amount received.
| | | Option Awards | | | Stock Awards | |
| Name | | Number of Shares Acquired on Exercise | | | Value Realized on Exercise | | | Number of Shares Acquired on Vesting | | | Value Realized on Vesting | |
Stephen P. Reynolds 1 | | | 300,000 | | | $ | 2,247,000 | | | | 143,099 | | | $ | 4,516,599 | |
Bertrand A. Valdman 2 | | | -- | | | | -- | | | | 37,949 | | | | 1,187,235 | |
Eric M. Markell 2 | | | -- | | | | -- | | | | 29,108 | | | | 908,311 | |
Kimberly J. Harris 2 | | | -- | | | | -- | | | | 29,335 | | | | 915,509 | |
Jennifer L. O'Connor2 | | | -- | | | | -- | | | | 26,002 | | | | 813,573 | |
_______________
| 1 | Cash payment for cancellation of vested stock option for 300,000 shares based on the difference between the per share merger consideration ($30 per share) and the per share exercise price for the option ($22.51 per share). |
| 2 | Cash payment for acceleration of unvested performance shares, including dividend equivalents and unvested performance-based restricted stock from the 2007-2009 and 2008-2010 LTIP performance cycles. |
2009 Pension Benefits
The Company and its affiliates maintain two pension plans: the Retirement Plan and the SERP. The following table provides information for each of the Named Executive Officers regarding the actuarial present value of the officer’s accumulated benefit and years of credited service under the Retirement Plan and the SERP. The present value of accumulated benefits was determined using interest rate and mortality rate assumptions consistent with those used in the Company’s financial statements. Except as described below in footnote (1), relating to Mr. Reynolds, each of the Named Executive Officers participates in both plans.
Name | Plan Name | | Number of Years Credited Service | | | Present Value of Accumulated Benefit 2,3 | | | Payments During Last Fiscal Year | |
Stephen P. Reynolds 1 | PSE Retirement Plan | | | 8.0 | | | $ | 169,236 | | | $ | -- | |
| | PSE SERP | | | n/a | | | | n/a | | | | n/a | |
| Bertrand A. Valdman | PSE Retirement Plan | | | 6.1 | | | | 86,257 | | | | -- | |
| | PSE SERP | | | 6.1 | | | | 541,962 | | | | -- | |
| Eric M. Markell | PSE Retirement Plan | | | 7.4 | | | | 142,415 | | | | -- | |
| | PSE SERP | | | 7.4 | | | | 1,029,960 | | | | -- | |
| Kimberly J. Harris | PSE Retirement Plan | | | 10.7 | | | | 141,321 | | | | -- | |
| | PSE SERP | | | 10.7 | | | | 674,427 | | | | -- | |
| Jennifer L. O’Connor | PSE Retirement Plan | | | 6.9 | | | | 105,093 | | | | -- | |
| | PSE SERP | | | 6.9 | | | | 617,427 | | | | -- | |
_______________
| 1 | Mr. Reynolds participates in the Retirement Plan, but does not participate in the SERP. In lieu of participating in the SERP, Mr. Reynolds received prior to the merger an annual credit of performance-based stock equivalents to a Performance-Based Retirement Equivalent Stock Account in the Deferred Compensation Plan. Following the delisting of Puget Energy stock, the credit will be made in dollars equal to 15% of Mr. Reynolds’ base salary and annual incentive for the preceding year. The value of this account at December 31, 2009 of $3,369,089 is also shown in the “2009 Nonqualified Deferred Compensation Plan” table and the stock equivalent program is further described in the narrative text accompanying that table. |
| 2 | The amounts reported in this column for each officer were calculated assuming no future service or pay increases. Present values were calculated assuming no pre-retirement mortality or termination. The values under the Retirement Plan and the SERP are the actuarial present values as of December 31, 2009 of the benefits earned as of that date and payable at normal retirement age (age 65 for the Retirement Plan and age 62 for the SERP). Future cash balance interest credits are 4.0% for 2010 and are assumed to average 5.5% annually thereafter. The discount assumption is 5.75%, and the post-retirement mortality assumption is based on the 2010 417(e) unisex mortality table. Annuity benefits are converted to lump sum amounts at retirement based on assumed future 417(e) segment rates of 5.03%, 6.73%, and 6.82% (the 24 month average of the underlying rates as of September 2009). These assumptions are consistent with the ones used for the Retirement Plan and the SERP for financial reporting purposes for 2009. In order to determine the change in pension values for the “Summary Compensation” table, the values of the Retirement Plan and the SERP benefits were also calculated as of December 31, 2008 for the benefits earned as of that date using the assumptions used for financial reporting purposes for 2008. These assumptions included assumed average cash balance interest credits of 4% for 2009 and 6.5% for all future years, a discount assumption of 6.2% and post-retirement mortality assumption based on the 2009 417(e) unisex mortality table and assumed lump sum interest rate of 6%. Other assumptions used to determine the value as of December 31, 2008 were the same as those used for December 31, 2009. |
| 3 | As described in footnote (2) above, the amounts reported for the SERP in this column are actuarial present values, calculated using the actuarial assumption used for financial reporting purposes. These assumptions are different from those used to calculate the actual amount of benefit payments under the SERP (see text below for a discussion of the actuarial assumptions used to calculate actual payment amounts). The following table shows the estimated lump sum amount that would be paid under the SERP to each SERP-eligible Named Executive Officer at age 62 (without discounting to the present), calculated as if such Named Executive Officer had terminated employment on December 31, 2009. Each SERP-eligible Named Executive Officer was vested in his or her SERP benefits as of December 31, 2009. |
| Name | | Lump Sum | |
| Bertrand A. Valdman | | $ | 1,259,498 | |
| Eric M. Markell | | | 1,252,569 | |
| Kimberly J. Harris | | | 1,680,794 | |
| Jennifer L. O’Connor | | | 1,011,724 | |
Retirement Plan
Under the Retirement Plan, Puget Energy’s and PSE’s eligible salaried employees, including the Named Executive Officers, accrue benefits in accordance with a cash balance formula, beginning on the later of their date of hire or March 1, 1997. Under this formula, for each calendar year after 1996, age-weighted pay credits are allocated to a bookkeeping account (a “Cash Balance Account”) for each participant. The pay credits range from 3% to 8% of eligible compensation. Eligible compensation generally includes base salary and bonuses (other than bonuses paid under the LTIP, signing, retention and similar bonuses), up to the limit imposed by the Internal Revenue Code. For 2009 and 2010, the Internal Revenue Code compensation limit was $245,000. In addition, as of March 1, 1997, the Cash Balance Account of each participant who was participating in the Retirement Plan on March 1, 1997 was credited with an amount based on the actuarial present value of that participant’s accrued benefit, as of February 28, 1997, under the Retirement Plan’s previous formula.
Amounts in the Cash Balance Accounts are also credited with interest. The interest crediting rate is 4% per year or such higher amount as PSE may determine. For 2009 and 2010 the annual interest crediting rate was 4.0%.
A participant’s Retirement Plan benefit generally vests upon the earlier of the participant’s completion of three years of active service with Puget Energy, PSE or their affiliates or attainment of age 65 (the Retirement Plan’s normal retirement age) while employed by the Company or one of its affiliates. Normal retirement benefit payments begin to a vested participant as of the first day of the month following the later of the participant’s termination of employment or attainment of age 65. However, a vested participant may elect to have his or her benefit under the Retirement Plan paid, or commence to be paid, as of the first day of any month commencing after the date on which his or her employment with Puget Energy, PSE and their affiliates terminates. If benefit payments commence prior to the participant’s attainment of age 65, then the amount of the monthly payments will be reduced for early commencement to reflect the fact that payments will be made over a longer period of time. This reduction is subsidized — that is, it is less than a pure actuarial reduction. The amount of this reduction is, on average, 0.30% for each of the first 60 months, 0.33% for each of the second 60 months, 0.23% for each of the third 60 months and 0.17% for each of the fourth 60 months that the payment commencement date precedes the participant’s 65th birthday. Further reductions apply for each additional month that the payment commencement date precedes the participant’s 65th birthday. As of December 31, 2009, all the Named Executive Officers were vested in their benefits under the Retirement Plan and, hence, would be eligible to commence benefit payments upon termination.
The normal form of benefit payment for unmarried participants is a straight life annuity providing monthly payments for the remainder of the participant’s life, with no death benefits. The straight life annuity payable on or after the participant's normal retirement age is actuarially equivalent to the balance in the participant’s Cash Balance Account as of the date of distribution. For married participants, the normal form of benefit payment is an actuarially equivalent joint and 50% survivor annuity with a “pop-up” feature providing reduced monthly payments (as compared to the straight life annuity) for the remainder of the participant’s life and, upon the participant’s death, monthly payments to the participant’s surviving spouse for the remainder of the spouse’s life in an amount equal to 50% of the amount being paid to the participant. Under the pop-up feature, if the participant’s spouse predeceases the participant, the participant’s monthly payments increase to the level that would have been provided under the straight life annuity. In addition, the Retirement Plan provides several other annuity payment options and a lump sum payment option that can be elected by participants. All payment options are actuarially equivalent to the straight life annuity. However, in no event will the amount of the lump sum payment be less than the balance in the participant’s Cash Balance Account as of the date of distribution (in some instances the amount of the lump sum distribution may be greater than the balance in the Cash Balance Account due to differences in the mortality table and interest rates used to calculate actuarial equivalency).
If a participant in the cash balance portion of the Retirement Plan dies while employed by the Company or any of its affiliates, then his or her Retirement Plan benefit will be immediately vested. If a vested participant dies before his or her Retirement Plan benefit is paid, or commences to be paid, then the participant’s Retirement Plan benefit will be paid to his or her beneficiary(ies). If a participant dies after his or her Retirement Plan benefit has commenced to be paid, then any death benefit will be governed by the form of payment elected by the participant.
Supplemental Executive Retirement Plan The SERP provides a benefit to participating Named Executive Officers that supplements the retirement income provided to the executives by the Retirement Plan. As discussed in the Compensation Discussion and Analysis, Mr. Valdman, Mr. Markell, Ms. Harris and Ms. O’Connor participate in the SERP. A participating Named Executive Officer's SERP benefit generally vests upon the executive’s completion of five years of participation in the SERP while employed by the Company or any of its affiliates. Mr. Markell, Ms. Harris and Ms. O’Connor are vested in their SERP benefits based on their years of service. By agreement with PSE, Mr. Valdman became vested in his SERP benefit on the date he was hired. The monthly benefit payable under the SERP to a vested executive (calculated in the form of a straight life annuity payable for the executive’s lifetime commencing at the later of the executive’s date of termination or attainment of age 62) is equal to (1) below minus the sum of (2) and (3) below:
| (1) | One-twelfth (1/12) of the executive’s highest average earnings times the executive’s years of credited service (not in excess of 15) times 3-1/3%. For purposes of the SERP, “highest average earnings” means the average of the executive’s highest three calendar years of earnings. The three calendar years do not have to be consecutive, but they must be among the last ten calendar years completed by the executive prior to his or her termination. “Earnings” for this purpose include base salary and annual bonus, but do not include long-term incentive compensation. An executive will receive one “year of credited service” for each consecutive 12-month period he or she is employed by the Company or its affiliates. If an executive becomes entitled to disability benefits under PSE’s long-term disability plan, then the executive’s highest average earnings will be determined as of the date the executive became disabled, but the executive will continue to accrue years of credited service until he or she begins to receive SERP benefits. |
| (2) | The monthly amount payable (or that would be payable) under the Retirement Plan to the executive in the form of a straight life annuity commencing as of the first day of the month following the later of the executive’s date of termination or attainment of age 62, and includes amounts previously paid or segregated pursuant to a qualified domestic relations order. |
| (3) | The actuarially equivalent monthly amount payable (or that would be payable) to the executive as of the first day of the month following the later of the executive’s date of termination or attainment of age 62 from any pension-type rollover accounts (including the Annual Cash Balance Restoration Account) within the Deferred Compensation Plan. These accounts are described in more detail in the “2009 Nonqualified Deferred Compensation” section. |
Normal retirement benefits under the SERP generally are paid or commence to be paid within 90 days following the later of the Named Executive Officer’s termination of employment or attainment of age 62. Except as provided below, SERP benefits are normally paid in a lump sum that is equal to the actuarial present value of the monthly straight life annuity benefit. An executive may have elected on or before December 31, 2008 to have this lump sum transferred to the Deferred Compensation Plan, rather than paid directly to the executive, after which it will be paid in accordance with the provisions of the Deferred Compensation Plan. In lieu of the normal form of payment, an executive may elect to receive his or her SERP benefit in the form of monthly installment payments over a period of two to 20 years, in a straight life annuity or in a joint and survivor annuity with a 100%, 75%, 50% or 25% survivor benefit. All payment options are actuarially equivalent to the straight life annuity. Mr. Markell is the only Named Executive Officer eligible for early retirement benefit payments under the SERP. Payments to the executives following termination of employment of SERP benefits are delayed for six months to the extent required by Section 409A of the Internal Revenue Code.
If a participating Named Executive Officer dies while employed by Puget Energy, PSE or any of their affiliates or after becoming vested in his or her SERP benefit, but before his or her SERP benefit has commenced to be paid, then the executive’s surviving spouse will receive a lump sum benefit equal to the actuarial equivalent of the survivor benefit such spouse would have received under the joint and 50% survivor annuity option. This amount will be calculated assuming the executive would have commenced benefit payments in that form on the first day of the month following the later of his or her death or attainment of age 62. If the executive is eligible for early retirement, the death benefit will be calculated based on the survivor benefit the spouse would have received as of the earliest commencement date. Distribution will be made to the executive’s surviving spouse as soon as administratively practicable after the executive’s death. If the executive is not married, then no death benefit will be paid. If an executive dies after his or her SERP benefit has commenced to be paid, then any death benefit will be governed by the form of payment elected by the executive.
2009 Nonqualified Deferred Compensation
The following table provides information for each of the Named Executive Officers regarding aggregate executive and Company contributions and aggregate earnings for 2009 and year-end account balances under the Deferred Compensation Plan.
Name | | Executive Contributions in 2009 1 | | | Registrant Contributions in 2009 2 | | | Aggregate Earnings in 2009 3 | | | Aggregate Withdrawals/ Distributions 4 | | | Aggregate Balance at December 31, 2009 5 | |
| Stephen P. Reynolds | | $ | 112,613 | | | $ | 349,819 | | | $ | 439,036 | | | $ | 153,750 | | | $ | 3,369,089 | |
| Bertrand A. Valdman | | | 36,430 | | | | 24,998 | | | | 22,950 | | | | -- | | | | 283,084 | |
| Eric M. Markell | | | 31,740 | | | | 21,480 | | | | 26,562 | | | | -- | | | | 317,875 | |
| Kimberly J. Harris | | | -- | | | | -- | | | | 33,991 | | | | -- | | | | 227,671 | |
| Jennifer L. O’Connor | | | 12,609 | | | | 13,973 | | | | 19,921 | | | | -- | | | | 336,580 | |
_______________
| 1 | The amount in this column for each executive reflects elective deferrals by the officer of salary, annual incentive compensation or LTIP awards paid in 2009. Deferred salary amounts are: Mr. Reynolds, $55,000; Mr. Valdman, $26,333; Mr. Markell, $24,000; Ms. Harris, $0; and Ms. O’Connor, $12,609. Deferred incentive compensation amounts are: Mr. Reynolds, $57,613; Mr. Valdman, $10,097; Mr. Markell, $7,740; Ms. Harris, $0; and Ms. O’Connor, $0. |
| 2 | The amount reported in this column for each executive reflects contributions by PSE consisting of the Annual Investment Plan Restoration Amount and Annual Cash Balance Restoration Amount. For Mr. Reynolds, the amount also includes $266,734 in value of performance-based stock equivalents credited in the Deferred Compensation Plan’s Performance-Based Retirement Equivalent Stock Account and calculated pursuant to his employment agreement based on the average of the high and low price of Puget Energy stock on January 21, 2009 of $28.90. These amounts are also included in the total amounts shown in the All Other Compensation column of the Summary Compensation Table. |
| 3 | The amount in this column for each officer reflects dividends on deferred stock units prior to the merger and the change in value of other investment tracking funds. |
| 4 | The amount in this column for Mr. Reynolds reflects a scheduled interim payment pursuant to the terms of the Deferred Compensation Plan. |
| 5 | Of the amounts in this column, the following amounts have also been reported in the Summary Compensation Table for 2009, 2008 and 2007. |
Name | | Reported for 2009 | | | Reported for 2008 | | | Reported for 2007 | |
| Stephen P. Reynolds | | $ | 462,431 | | | $ | 395,062 | | | $ | 403,540 | |
| Bertrand A. Valdman | | | 61,428 | | | | 58,870 | | | | 54,733 | |
| Eric M. Markell | | | 53,220 | | | | 44,168 | | | | 31,005 | |
| Kimberly J. Harris | | | -- | | | | -- | | | | -- | |
| Jennifer L. O’Connor | | | 26,582 | | | | 24,021 | | | | 21,234 | |
Deferred Compensation Plan
The Named Executive Officers are eligible to participate in the Deferred Compensation Plan and may defer up to 100% of base salary, annual incentive compensation and LTIP grants. In addition, each year, executives are eligible to receive Company contributions to restore benefits not available to them under the Company's tax-qualified plans due to limitations imposed by the Internal Revenue Code. The Annual Investment Plan Restoration Amount equals the additional matching and any other employer contribution under the 401(k) plan that would have been credited to an electing executive’s 401(k) plan account if the Internal Revenue Code limitations were not in place and if deferrals under the Deferred Compensation Plan were instead made to the 401(k) plan. The Annual Cash Balance Restoration Amount equals the actuarial equivalent of any reductions in an executive’s accrued benefit under the Retirement Plan due to Internal Revenue Code limitations or as a result of deferrals under the Deferred Compensation Plan. An executive must generally be employed on the last day of the year to receive these Company contributions, unless he or she retires or dies during the year in which case the Company will contribute a prorated amount.
In lieu of participation in the SERP and prior to completion of the merger, Mr. Reynolds received an annual credit of performance-based stock equivalents to his Deferred Compensation Plan’s Performance-Based Retirement Equivalent Stock Account each January commencing on January 1, 2003. The number of stock equivalents was determined by calculating the number of shares obtained by taking 15% of Mr. Reynolds’ base salary and annual bonus for the preceding year and dividing that amount by the average per-share closing price of Puget Energy stock on the last day of October, November and December of the preceding year. The stock equivalents were fully vested on May 6, 2008 and upon the merger were credited within the Deferred Compensation Plan based on the $30 per share merger price. In 2010 and future years, Mr. Reynolds’ contribution will be contributed as a cash deferral equal to 15% of his base salary and annual bonus received for the preceding year.
The Named Executive Officers choose how to credit deferred amounts among four investment tracking funds. The tracking funds mirror performance in major asset classes of bonds, stocks, Puget Energy stock, and interest crediting. The tracking funds differ from the investment funds offered in the 401(k) plan. The 2009 calendar year returns of these tracking funds were:
| Vanguard Total Bond Market Index | 6.09% |
| Vanguard 500 Index | 26.49% |
| Puget Energy Stock (from 1/1/2009 until 2/5/2009) | 11.11% |
| Interest Crediting Fund | 6.73% |
As of the delisting of Puget Energy stock following the Company’s change in control on February 6, 2009, the Puget Energy tracking fund was no longer available and the deferred amounts credited therein were reallocated in accordance with the executive’s direction, or if none, into the interest crediting tracking fund.
The Named Executive Officers may change how deferrals are allocated to the tracking funds at any time, subject to insider trading rules. Changes generally become effective as of the first trading day of the following calendar quarter.
The Named Executive Officers generally may choose how and when to receive payments under the Deferred Compensation Plan. There are three types of in-service withdrawals. First, an executive may choose an interim payment of deferred based salary, annual bonus or vested performance shares by designating a plan year for payment at the time of his or her deferral election. The interim payment is made in a lump sum within 60 days after the last day of the designated plan year, which must be at least two years following the plan year of the deferral. Second, an in-service withdrawal may also be made to an executive upon a qualifying hardship event and demonstrated need. Third, only with respect to amounts deferred and vested prior to 2005, the executive may elect an in-service withdrawal for any reason by paying a 10% penalty. Payments upon termination of employment depend on whether the executive is then eligible for retirement. If the executive's termination occurs prior to his or her retirement date (generally the earlier of attaining age 62 or age 55 with five years of credited service), the executive will receive a lump sum payment of his or her account balance. If the executive’s termination occurs after his or her retirement date, the executive may choose to receive payments in a lump sum or via one of several installment options (fixed amount, specified amount, annual or monthly installments, of up to 20 years). Mr. Reynolds and Mr. Markell are the only Named Executive Officers currently retirement eligible. Payments to the executive following a termination or retirement date are generally delayed for six months in accordance with the requirements of Section 409A of the Internal Revenue Code.
Potential Payments Upon Termination or Change in Control
The “Estimated Potential Incremental Payments Upon Termination or Change in Control” table reflects the estimated amount of incremental compensation payable to each of the Named Executive Officers in the event of (i) an involuntary termination without cause or for good reason not in connection with a change in control; (ii) a change in control, (iii) an involuntary termination without cause or for good reason in connection with a change in control, including the merger; (iv) retirement; (v) disability; or (vi) death.
Certain Company benefit plans provide incremental benefits or payments in the event of certain terminations of employment. In addition, each Named Executive Officer, other than Mr. Reynolds, entered into an Amended and Restated Executive Employment Agreement with the Company in March 2009, which provides for benefits or payments upon certain terminations of employment from the Company following the merger or a subsequent change in control. Mr. Reynolds’ employment agreement provides for certain benefits and payments following a termination of employment by the Company without cause or by Mr. Reynolds with good reason. The only benefit payable to the Named Executive Officers solely upon a change in control is accelerated vesting of LTIP awards, described below.
Disability and Life Insurance Plans
If a Named Executive Officer’s employment terminates due to disability or death, the executive or his or her estate will receive benefits under the PSE disability plan or life insurance plan available generally to all salaried employees. These disability and life insurance amounts are not reflected in the table below. The Named Executive Officer is also eligible to receive supplemental disability and life insurance. The supplemental monthly disability coverage is 65% of monthly base salary and target incentive pay, reduced by (i) amounts receivable under the PSE disability plan generally available to salaried employees and (ii) certain other income benefits. The supplemental life insurance benefit is provided at two times base salary and target annual incentive bonus if the executive dies while employed by PSE with a reduction for amounts payable under the applicable group life insurance policy.
LTIP Awards
If a Named Executive Officer’s employment terminates due to disability or death, the executive or his or her estate will be paid a pro-rata portion of LTIP awards that were granted in a prior year. In the case of retirement at normal retirement age or approved early retirement, pro-rata LTIP awards will be paid in the first quarter following the year of retirement, based on performance through the prior year. In the event of a change in control, outstanding LTIP awards will be paid at target.
Employment Agreement with Mr. Reynolds
Puget Energy and Puget Sound Energy (together, the “Company”) entered into an employment agreement with Mr. Reynolds as of January 1, 2002 to secure his services as Chief Executive Officer and President. The agreement has an initial term of three years after which time it automatically renews for one-year terms unless notice of termination is given by either party at least 180 days prior to the expiration of the then current term. The agreement was amended on May 10, 2005, February 9, 2006 and February 28, 2008. Effective as of December 31, 2009, Mr. Reynolds agreed to waive all payments and benefits upon a future change in control for which he was previously eligible under his employment agreement.
If at any time the Company terminates Mr. Reynolds’ employment without cause, or Mr. Reynolds terminates his employment with good reason, Mr. Reynolds will receive the following severance benefit:
| o | an amount equal to two times his then current annual base salary and target annual incentive bonus. |
In the event of termination by death or disability, Mr. Reynolds will receive his annual incentive bonus at the target level pro-rated through the date of termination (which amount is not disclosed in the table below since it was earned for 2009) and continued group medical, dental, disability and life insurance benefits as are provided to the other Named Executive Officers under the terms of their employment agreements. Mr. Reynolds also will receive a cash payment equal to any excise taxes imposed by Section 4999 of the Internal Revenue Code due to payments received under the employment agreement or any other payment or benefit from the Company, plus the income taxes payable by him resulting from this cash payment.
The employment agreement contains a noncompetition covenant pursuant to which Mr. Reynolds commits that for a period of two years following his voluntary termination without good reason, he will not perform services for any person or entity selling or distributing electric power or natural gas in Washington, Oregon or Idaho, unless the Company consents in writing. The Company may enforce this covenant through injunctive relief or other appropriate remedies. The employment agreement also contains an indemnification clause in favor of Mr. Reynolds. The Company commits to defend, indemnify and hold harmless Mr. Reynolds from all liabilities in connection with his service. As part of that commitment, the Company will cover him under the Company’s directors’ and officers’ liability insurance for six years following his termination of employment.
Under Mr. Reynolds’ employment agreement, “cause” and “good reason” have the following meanings:
Cause means willfully engaging in illegal or grossly wrongful misconduct that results in financial detriment materially and demonstrably injurious to the Company. Cause does not include any act or omission believed to be in good faith and in the best interests of the Company.
Good Reason includes the following actions by the Company: (i) assigning duties inconsistent with, or taking actions in diminution of, Mr. Reynolds’ position (including status, offices, titles and reporting requirements), authority, duties or responsibility under the employment agreement; (ii) failing to comply with the provisions of the employment agreement; (iii) requiring that Mr. Reynolds be based at any location other than the Company’s corporate headquarters or relocating the corporate headquarters more than 25 miles from Bellevue, Washington; and (iv) failing to assign the employment agreement to a successor or the successor failing to assume and be bound by it explicitly. Good Reason is triggered on a reasonable determination by Mr. Reynolds that any of the above events has occurred.
Employment Agreements with Other Named Executive Officers
In March 2009, PSE entered into Amended and Restated Executive Employment Agreements (Employment Agreements) with each of Mr. Valdman, Mr. Markell, Ms. Harris and Ms. O’Connor (Executives), the terms of which are the same for all four Executives and which amended and restated existing Amended and Restated Change of Control Agreements between the Company and each of the Executives. The Employment Agreements provide for an employment period of two years after the completion of the merger (Employment Period) and generally provide benefits similar to those provided under the previous Change of Control Agreements. In the event of termination of employment prior to the second anniversary of the merger or termination of employment within two years of a change in control that follows the Employment Period, an Executive is eligible to receive the payments described below. A change in control generally means any person (or group of persons) acquires (i) beneficial ownership of more than 55% of the total combined voting power of the Company’s securities outstanding immediately after such acquisition (other than through a registered public offering) or (ii) all or substantially all of the Company’s assets.
Payments upon Involuntary Termination without Cause or for Good Reason
If an Executive’s employment is terminated without cause by the Company or is terminated by the Executive for good reason during the Employment Period, the Executive is eligible to receive the following compensation and benefits:
| · | Three times the sum of annual base salary and annual incentive bonus for the year in which termination occurs; |
| · | Pro-rated annual incentive bonus for the year in which termination occurs (Annual Bonus). Since this amount was earned for 2009, no amount is show in the table below; |
| · | Supplemental retirement benefit equal to the difference between (x) the actuarial equivalent of the amount the Executive would have received under the Retirement Plan and the SERP had his or her employment continued until the end of the employment period, and (y) the actuarial equivalent of the amount the Executive actually receives or is entitled to receive under the Retirement Plan and SERP; |
| · | Merger performance bonus equal to the amount the Executive would have received had his or her employment continued until each of the first and second anniversaries of the merger. In the event of termination after the first anniversary of the merger but on or prior to the second anniversary of the merger, the Executive is eligible to receive the merger performance bonus that would have been payable as of the second anniversary; and |
| · | Continued group medical, dental, disability and life insurance benefits to the Executive and his or her family. Benefits will be paid by the Company while the Executive is eligible for COBRA and thereafter by reimbursement of payments made by the Executive for such coverage (including related tax amounts), except that if the Executive becomes re-employed with another employer and is eligible to receive medical or other welfare benefits under another employer-provided plan, the medical and other welfare benefits under the Employment Agreement will become secondary to those provided by the other employer (the foregoing benefit is referred to as Health and Welfare Benefit Continuation). |
Under the Employment Agreements, “cause” and “good reason” have the following meanings:
Cause generally means (i) the willful and continued failure by the Executive to substantially perform the Executive’s duties with the Company (other than any such failure resulting from incapacity due to physical or mental illness) for a period of 30 days after written notice of demand for substantial performance has been delivered to the Executive or (ii) the Executive’s willfully engaging in gross misconduct materially and demonstrably injurious to the Company, as determined by the Board after notice to the executive and opportunity for a hearing. No act or failure to act on the Executive’s part is considered “willful” unless the Executive has acted or failed to act with an absence of good faith and without a reasonable belief that the Executive’s action or failure to act was in the best interests of the Company.
Good Reason generally means (i) the assignment of the Executive to a nonofficer position with the Company, which the parties agree would constitute a material reduction in the Executive’s authority, duties or responsibilities; (ii) a material diminution in the Executive’s total compensation opportunities under the Employment Agreement; (iii) the Company’s requiring the Executive to be based at any location that represents a material change from the Executive’s location in the Seattle/Bellevue metropolitan area, unless the Executive consents to the relocation; or (iv) a material breach of the Employment Agreement by the Company, provided that, in any of the foregoing, the Company has not remedied the alleged violation(s) within 60 days of notice from the Executive.
Payments upon Retirement, Disability or Death
If an Executive’s employment terminates due to voluntary retirement after having attained age 55 with a minimum of five years of service to the Company, a pro-rated Annual Bonus is payable. The bonus is payable at the time the Executive otherwise would have received the payment had employment continued, based on the Company’s actual achievement of performance goals.
If an Executive’s employment terminates due to disability or death, the Executive is eligible to receive the following compensation and benefits:
| · | Pro-rated Annual Bonus; and |
| · | Health and Welfare Benefit Continuation. |
In addition, upon termination for any of the foregoing reasons during the Employment Period, other than by reason of retirement, the Executive is eligible to receive the perquisite of financial planning.
Except as otherwise described above, payments of salary and bonus will be paid after the date of termination, subject to the Executive’s timely execution of a general waiver and release of claims and subject to a six-month delay if required for compliance with Section 409A of the Internal Revenue Code.
The Employment Agreements also contain noncompetition and anti-solicitation provisions that restrict the Executive during the employment period and for twelve months thereafter from, respectively, engaging in activities related to selling or distributing electric power or natural gas in Washington or soliciting others to leave the Company or causing them to be hired from the Company by another entity. The Employment Agreements contain a non-disparagement clause and a confidentiality clause pursuant to which the Executives must keep confidential all secret or confidential information, knowledge or data relating to the Company and its affiliates obtained during their employment. The Executives may not disclose any such information, knowledge or data after their respective terminations of employment unless PSE consents in writing or as required by law.
If any payments paid or payable in connection with the merger, whether paid or payable pursuant to the Employment Agreements or otherwise, are characterized as “excess parachute payments” within the meaning of Section 280G of the Internal Revenue Code, then the Company will make a cash payment to or on behalf of the Executive equal to any excise taxes imposed by Section 4999 of the Internal Revenue Code on such payments, plus the income taxes payable by him or her resulting from this cash payment. If a change in control occurs subsequent to the merger while the Company’s stock is not traded on an established securities market or otherwise immediately prior to such change in control, then the Executive will agree to execute a waiver of any “excess parachute payments” that would result from such payments, provided that the Company agrees to seek, but is not required to obtain, shareholder approval of the amount payable in connection with termination of employment, in which case the waived amounts will be restored to the Executive.
Estimated Potential Incremental Payments Upon Termination or Change in Control
The amounts shown in the table below assume that the termination of employment or change in control was effective as of December 31, 2009. The amounts below are estimates of the incremental amounts that would be paid out to the Named Executive Officer upon a termination of employment or change in control. Actual amounts payable can only be determined at the time of a termination of employment or change in control.
| | | Involuntary Termination w/o Cause or for Good Reason | | | Upon Change in Control | | | After Change in Control Involuntary Termination w/o Cause or for Good Reason1 | | | Retirement | | | Disability | | | Death | |
| | | | | | | | | | | | | | | | | | | |
| Stephen P. Reynolds | | | | | | | | | | | | | | | | | | |
| Cash Severance (salary and/or annual incentive) | | $ | 3,052,500 | | | $ | -- | | | $ | -- | | | $ | -- | | | $ | -- | | | $ | -- | |
| Long Term Incentive Plan | | | -- | | | | 1,402,500 | | | $ | 1,402,500 | | | | -- | | | | -- | | | | -- | |
Benefits (continuation)3 | | | -- | | | | -- | | | | 37,778 | | | | -- | | | | 37,778 | | | | 37,778 | |
| Supplemental Life Insurance | | | -- | | | | -- | | | | -- | | | | -- | | | | -- | | | | 2,452,500 | |
| Excise Tax Gross-Up | | | -- | | | | -- | | | | -- | | | | -- | | | | -- | | | | -- | |
| Total Estimated Incremental Value | | $ | 3,052,500 | | | $ | 1,402,500 | | | $ | 1,440,278 | | | $ | -- | | | $ | 37,778 | | | $ | 2,490,278 | |
| | | | | | | | | | | | | | | | | | | | | | | | | |
| Bertrand A. Valdman | | | | | | | | | | | | | | | | | | | | | | | | |
| Cash Severance (salary and/or annual incentive) | | $ | n/a | | | | -- | | | $ | 1,896,015 | | | $ | -- | | | $ | -- | | | $ | -- | |
| Long Term Incentive Plan | | | -- | | | $ | 434,503 | | | | 434,503 | | | | -- | | | | -- | | | | -- | |
| Merger Performance Bonus | | | -- | | | | -- | | | | 790,005 | | | | -- | | | | -- | | | | -- | |
SERP (additional years of credited service)2 | | | -- | | | | -- | | | | 484,331 | | | | -- | | | | -- | | | | -- | |
Benefits (continuation) 3 | | | n/a | | | | -- | | | | 44,619 | | | | -- | | | | 44,619 | | | | 44,619 | |
| Supplemental Life Insurance | | | n/a | | | | -- | | | | -- | | | | -- | | | | -- | | | | 869,000 | |
| Excise Tax Gross-Up | | | n/a | | | | -- | | | | 869,071 | | | | -- | | | | -- | | | | -- | |
| Total Estimated Incremental Value | | $ | n/a | | | $ | 434,503 | | | $ | 4,518,544 | | | $ | -- | | | $ | 44,619 | | | $ | 913,619 | |
| | | | | | | | | | | | | | | | | | | | | | | | | |
| Eric M. Markell | | | | | | | | | | | | | | | | | | | | | | | | |
| Cash Severance (salary and/or annual incentive) | | $ | n/a | | | | -- | | | $ | 1,728,000 | | | $ | -- | | | $ | -- | | | $ | -- | |
| Long Term Incentive Plan | | | -- | | | $ | 396,000 | | | | 396,000 | | | | -- | | | | -- | | | | -- | |
| Merger Performance Bonus | | | -- | | | | -- | | | | 720,000 | | | | -- | | | | -- | | | | -- | |
SERP (additional years of credited service) 2 | | | -- | | | | -- | | | | 581,027 | | | | -- | | | | -- | | | | -- | |
Benefits (continuation) 3 | | | n/a | | | | -- | | | | 46,454 | | | | -- | | | | 46,454 | | | | 46,454 | |
| Supplemental Life Insurance | | | n/a | | | | -- | | | | -- | | | | -- | | | | -- | | | | 792,000 | |
| Excise Tax Gross-Up | | | n/a | | | | -- | | | | 1,014,253 | | | | -- | | | | -- | | | | -- | |
| Total Estimated Incremental Value | | $ | n/a | | | $ | 396,000 | | | $ | 4,485,734 | | | $ | -- | | | $ | 46,454 | | | $ | 838,454 | |
| | | | | | | | | | | | | | | | | | | | | | | | | |
| Kimberly J. Harris | | | | | | | | | | | | | | | | | | | | | | | | |
| Cash Severance (salary and/or annual incentive) | | $ | n/a | | | | -- | | | $ | 1,728,000 | | | $ | -- | | | $ | -- | | | $ | -- | |
| Long Term Incentive Plan | | | -- | | | $ | 396,000 | | | | 396,000 | | | | -- | | | | -- | | | | -- | |
| Merger Performance Bonus | | | -- | | | | -- | | | | 720,000 | | | | -- | | | | -- | | | | -- | |
SERP (additional years of credited service) 2 | | | -- | | | | -- | | | | 809,891 | | | | -- | | | | -- | | | | -- | |
Benefits (continuation) 3 | | | n/a | | | | -- | | | | 31,065 | | | | -- | | | | 31,065 | | | | 31,065 | |
| Supplemental Life Insurance | | | n/a | | | | -- | | | | -- | | | | -- | | | | -- | | | | 792,000 | |
| Excise Tax Gross-Up | | | n/a | | | | -- | | | | 913,524 | | | | -- | | | | -- | | | | -- | |
| Total Estimated Incremental Value | | $ | n/a | | | $ | 396,000 | | | $ | 4,598,480 | | | $ | -- | | | $ | 31,065 | | | $ | 823,065 | |
| | | | | | | | | | | | | | | | | | | | | | | | | |
| Jennifer L. O’Connor | | | | | | | | | | | | | | | | | | | | | | | | |
| Cash Severance (salary and/or annual incentive) | | $ | n/a | | | | -- | | | $ | 1,397,250 | | | $ | -- | | | $ | -- | | | $ | -- | |
| Long Term Incentive Plan | | | -- | | | $ | 294,975 | | | | 294,975 | | | | -- | | | | -- | | | | -- | |
| Merger Performance Bonus | | | -- | | | | -- | | | | 621,000 | | | | -- | | | | -- | | | | -- | |
SERP (additional years of credited service) 2 | | | n/a | | | | -- | | | | 374,996 | | | | -- | | | | -- | | | | -- | |
Benefits (continuation) 3 | | | n/a | | | | -- | | | | 39,498 | | | | -- | | | | 39,498 | | | | 39,498 | |
| Supplemental Life Insurance | | | n/a | | | | -- | | | | -- | | | | -- | | | | -- | | | | 621,000 | |
| Excise Tax Gross-Up | | | n/a | | | | -- | | | | 736,180 | | | | -- | | | | -- | | | | -- | |
| Total Estimated Incremental Value | | $ | n/a | | | $ | 294,975 | | | $ | 3,463,899 | | | $ | -- | | | $ | 39,498 | | | $ | 660,498 | |
| 1 | If the termination of employment had been in connection with the merger, the Excise Tax Gross-Up amounts reported above would have been payable. If the termination of employment had followed a change in control other than the merger, the Named Executive Officers (other than Mr. Reynolds) would not have received an Excise Tax Gross-Up. |
| 2 | SERP values are shown as the estimated incremental value that the Named Executive Officer would receive at age 62 as a result of the termination event shown in the column, relative to the vested benefit as of December 31, 2009. These values are based on interest rate and mortality rate assumptions consistent with those used in the Company’s financial statements. |
| 3 | Benefits (continuation) reflects the value of continued medical, dental, disability and life insurance benefits as well as financial planning benefit in the amount of $5,000 for each Named Executive Officer, except $2,500 for Ms. O’Connor. |
Director Compensation for Fiscal Year 2009
The following table sets forth information regarding compensation for each of the Company’s nonemployee directors for 2009. The composition of the Board changed effective with the completion of the Company’s merger on February 6, 2009, and the directors named in the table are those persons who received compensation from the Company in 2009 for service as a nonemployee director, whether prior to or following the merger. Directors who are employed by the Company’s investor-owners are not paid separately for their service and thus are not named in the table below. The directors who served in 2009 who are employed by the Company’s investor-owners are: Graeme Bevans, Andrew Chapman, Alan James, Alan Kadic, Christopher Leslie, William McKenzie, Lincoln Webb, Mark Wiseman and Mark Wong.
As described in further detail below, the Company’s nonemployee director compensation program in 2009 consisted of quarterly retainer cash fees of $20,000. Additional quarterly retainer amounts associated with serving as lead director, chairing Board committees and serving on the Audit Committee, and meeting fees were also paid in cash.
| Name | | Fees Earned or Paid in Cash1 | | | Nonqualified Deferred Compensation Earnings2 | | | Total | |
| William S. Ayer | | $ | 163,022 | | | $ | 6,341 | | | $ | 169,363 | |
Phyllis J. Campbell 3 | | | 16,964 | | | | 16,554 | | | | 33,518 | |
Craig W. Cole 3 | | | 16,839 | | | | 8,838 | | | | 25,677 | |
Stephen E. Frank 3 | | | 12,773 | | | | -- | | | | 12,773 | |
Tomio Moriguchi 3 | | | 8,000 | | | | 12,759 | | | | 20,759 | |
Dr. Kenneth P. Mortimer 3 | | | 16,633 | | | | -- | | | | 16,633 | |
Sally G. Narodick 3 | | | 17,250 | | | | -- | | | | 17,250 | |
| Herbert B. Simon | | | 114,100 | | | | -- | | | | 114,100 | |
George W. Watson 3 | | | 6,811 | | | | -- | | | | 6,811 | |
_______________
| 1 | The amounts in this column reflect director compensation earned and paid in cash including amounts deferred under our Deferred Compensation Plan for Nonemployee Directors. |
| 2 | Represents earnings accrued to deferred compensation considered to be above market. |
| 3 | These individuals are no longer directors as of December 31, 2009, but served on the Board of Directors through February 6, 2009. |
Nonemployee Independent Director Compensation Program. The 2009 nonemployee independent director compensation program is based on the following principles: (i) the level of nonemployee director compensation should be based on Board and committee responsibilities and be competitive with comparable companies and (ii) a significant portion of nonemployee director compensation should align director interests with the long-term interests of investors.
The 2009 compensation program for independent nonemployee directors was as follows:
| · | A base cash quarterly retainer fee of $20,000 |
| · | $1,600 for attendance at each Board and committee meeting, and $800 for each telephonic meeting lasting 60 minutes or less, |
In 2009, nonemployee independent directors were paid the following additional cash quarterly retainer fees:
| · | Independent Board Chairman, $10,000 |
| · | Lead independent director, $3,750 |
| · | Chair of the Audit Committee, $2,500 |
| · | Chair of the Compensation and Leadership Development Committee, $2,000 |
| · | Chair of the Governance and Public Affairs Committees, $1,500 |
| · | Each member of the Audit Committee other than the chair, $1,000 |
Subsequent to the merger, all fees were paid in cash.
All quarterly retainer and meeting attendance fees were paid on the last business day of March, June, September and December. Nonemployee directors were reimbursed for actual travel and out-of-pocket expenses incurred in connection with their services. Directors who also served as employees of the Company or the Company’s investor-owners did not receive compensation for their service on the Board or any committees.
Nonemployee independent directors are eligible to participate in the Company’s matching gift program on the same terms as all Puget Energy employees. Under this program, the Company would match up to a total of $300 a year in contributions by a director to non-profit organizations which had an IRS 501(c)(3) tax exempt status and was located in and served the people of PSE’s service territory in Washington State.
Deferral of Compensation. Prior to the merger, nonemployee directors could defer receipt of all or a part of their quarterly retainer fees that were required to be paid in Puget Energy stock into unfunded deferred stock unit accounts under the Company’s Nonemployee Director Plan. Deferred stock units earned the equivalent of dividends, which were credited as additional deferred stock units. Nonemployee directors did not have the right to vote or transfer the deferred stock units. This plan was terminated concurrent with the merger.
Nonemployee directors could also elect to defer all or a part of their fees payable in cash under the Company's Deferred Compensation Plan for Nonemployee Directors. Nonemployee directors could allocate these deferrals into one or more “measurement funds,” which included an interest crediting fund, an equity index fund, a bond index fund and, prior to the merger, a Puget Energy stock fund. Nonemployee directors were permitted to make changes in measurement fund allocations quarterly.
As a result of the delisting of Puget Energy stock following the completion of the merger on February 6, 2009, the Puget Energy stock unit accounts in the Nonemployee Director Plan were transferred as stock accounts to the Company’s Deferred Compensation Plan for Nonemployee Directors, and all amounts allocated to stock accounts in that plan were reallocated to other accounts in accordance with the director’s direction or, if none, into an interest crediting tracking fund.
Security Ownership of Directors, Executive Officers and Certain Beneficial Owners” inOwners
The following tables show the number of shares of common stock beneficially owned as of December 31, 2009 by each person or group that we know owns more than 5.0% of Puget Energy’s proxy statementand PSE’s common stock. No director, executive officer or executive officer named in the Summary Compensation Table in Item 11 of Part III of this report owns any of the outstanding shares of common stock of Puget Energy or PSE. Puget Equico LLC and its affiliates beneficially own 100.0% of the outstanding common stock of Puget Energy. Puget Energy holds 100.0% of the outstanding common stock of PSE. Percentage of beneficial ownership is based on 200 shares of Puget Energy common stock and 85,903,791 shares of Puget Sound Energy common stock outstanding as of December 31, 2009.
Beneficial Ownership Table of Puget Energy and PSE
| Number of Beneficially Owned Shares |
| Name | Puget Energy | PSE |
| Puget Equico LLC and affiliates | 200 1, 2 | -- |
| Puget Energy | -- | 85,903,7913 |
_______________
| 1 | Information presented above and in this footnote is based on Amendment No. 2 to Schedule 13D/A filed on February 13, 2009 (the Schedule 13D) by Puget Equico LLC (Puget Equico), Puget Intermediate Inc. (Puget Intermediate), Puget Holdings LLC (Puget Holdings and together with Puget Intermediate, the Parent Entities), Macquarie Infrastructure Partners I (formerly MIP Padua Holdings GP) (MIP), Macquarie Infrastructure Partners II (formerly MIP Washington Holdings, L.P.) (MIP II), Macquarie FSS Infrastructure Trust (MFIT), Padua MG Holdings LLC CPP Investment Board (USRE II) Inc. (CPP), 6860141 Canada Inc. as trustee for British Columbia Investment Management Corporation (bcIMC), PIP2PX (Pad) Ltd. And PIP2GV (Pad) Ltd. and together with all the preceding entities other than the Puget Equico and the Parent Entities, the Investors). Puget Equico is a wholly owned subsidiary of Puget Intermediate, Puget Intermediate is a wholly owned subsidiary of Puget Holdings and the Investors are the direct or indirect owners of Puget Holdings. The Parent Entities and the Investors are the direct or indirect owners of Puget Equico. Although the Parent Entities and the Investors do not own any shares of Puget Energy directly, Puget Equico, the Parent Entities and the Investors may be deemed to be members of a “group,” within the meaning of Section 13(d)(3) of the Securities Exchange Act of 1934, as amended. Accordingly, each such entity may be deemed to beneficially own the 200 shares of Puget Energy common stock owned by Puget Equico. Such shares of common stock constitute 100.0% of the issued and outstanding shares of common stock of Puget Energy. Under Section 13(d)(3) of the Exchange Act and based on the number of shares outstanding, Puget Equico, the Parent Entities and the Investors may be deemed to have shared power to vote and shared power to dispose of such shares of Puget Energy common stock that may be beneficially owned by Puget Equico. However, each of Puget Equico, the Parent Entities and the Investors expressly disclaims beneficial ownership of such shares of common stock other than those shares held directly by such entity. According to the Schedule 13D, as of February 13, 2009: |
| ·The address of the principal office of Puget Holdings is 125 West 55th Street, Level 22, New York, NY 10019. |
| ·The address of the principal office of Puget Intermediate and Puget Equico is The PSE Building, 10885 NE 4th Street, Bellevue, WA 98009. |
| ·The address of the principal office of MIP and MIP II is 125 West 55th Street, Level 22, New York, NY 10019. |
| ·The address of the principal office of MFIT is Level 11, 1 Martin Place, Sydney, Australia NSW 2000. |
| ·The address of the principal office of PMGH is 125 West 55th Street, Level 22, New York, NY 10019. |
| ·The address of the principal office of CPP is One Queen Street East, Suite 2600, P.O. Box 101, Toronto, Ontario, Canada M5C 2W5. |
| ·The address of the principal office of bcIMC is Sawmill Point, Suite 301-2940 Jutland Road, Victoria, British Columbia, Canada V8T 5K6. |
| ·The address of the principal office of PIP2PX and PIP2GV is 340 Terrace Building, 9515-107 Street, Edmonton, Alberta, Canada T5K 2C3. |
| 2 | Pursuant to that certain Pledge Agreement dated as of February 6, 2009, made by Puget Equico LLC to Barclays Bank PLC, as collateral agent the outstanding stock of Puget Energy held by Puget Equico was pledged by Puget Equico to secure the obligations of Puget Energy under the Credit Agreement dated as of May 16, 2008 among Puget Merger Sub Inc., as Borrower, Barclays Bank PLC, as Facility Agent, the other agents party thereto, and the lender party thereto (which agreement was subsequently assumed by Puget Energy. |
| 3 | Pursuant to that certain Borrower’s Security Agreement dated as of February 6, 2009, the outstanding stock of PSE held by Puget Energy was pledged by Puget Energy to secure its obligations under the Credit Agreement dated as of May 16, 2008 among Puget Merger Sub Inc,. as Borrower, Barclays Bank PLC, as Facility Agent, the other agents party thereto, and the lender party thereto (which agreement was subsequently assumed by Puget Energy. |
Equity Compensation Plan Information
In connection with the merger of Puget Energy with Puget Holdings, which was completed on February 6, 2009, all compensation plans under which equity securities were authorized for its 2007 Annual Meetingissuance have been terminated.
Transactions with Related Persons
Our Boards of Shareholders (Commission file No. 1-16305). ReferenceDirectors have adopted a written policy for the review and approval or ratification of related person transactions. Under the policy, our directors and executive officers are expected to disclose to our Chief Compliance Officer the material facts of any transaction that could be considered a related person transaction promptly upon gaining knowledge of the transaction. A related person transaction is also madegenerally defined as any transaction required to be disclosed under Item 404(a) of Regulation S-K, the SEC’s related person transaction disclosure rule.
Any transaction reported to the informationChief Compliance Officer will be reviewed according to the following procedures:
| · | If the Chief Compliance Officer determines that disclosure of the transaction is not required under the SEC’s related person transaction disclosure rule, the transaction will be deemed approved and will be reported to the Audit Committee. |
| · | If disclosure is required, the Chief Compliance Officer will submit the transaction to the Chair of the Audit Committee who will review and, if authorized, will determine whether to approve or ratify the transaction. The Chair is authorized to approve or ratify any related person transaction involving an aggregate amount of less than $1.0 million or when it would be impracticable to wait for the next Audit Committee meeting to review the transaction. |
| · | If the transaction is outside the Chair’s authority, the Chair will submit the transaction to the Audit Committee for review and approval or ratification. |
When determining whether to approve or ratify a related person transaction, the Chair of the Audit Committee or the Audit Committee, as applicable, will review relevant facts regarding the related person transaction, including:
· | The extent of the related person’s interest in the transaction; |
· | Whether the terms are comparable to those generally available in arms’ length transactions; and |
· | Whether the related person transaction is consistent with the best interests of the Company. |
If any related person transaction is not approved or ratified, the Committee may take such action as it may deem necessary or desirable in the best interests of the Company and its shareholders.
Each of the directors of Puget Energy and PSE (with the exception of Herbert Simon, who only serves on the Board of Directors of PSE) are on the Board of Managers of Puget Holdings, which was a party to that certain merger agreement entered into by Puget Holdings and Puget Energy, pursuant to which Puget Holdings acquired Puget Energy for $30.00 per share.
Board of Directors and Corporate Governance
Independence of the Board
The Boards of Puget Energy and PSE have reviewed the relationships between Puget Energy and PSE (and their respective subsidiaries) and each of their respective directors, including those directors serving prior to the closing of the merger on February 6, 2009. Based on this review, the Boards have determined that all of the directors serving prior to the closing of the merger, other than Stephen P. Reynolds, Puget Energy’s executive officers set forth in Part IChairman, President and CEO, were independent under the New York Stock Exchange (NYSE) corporate governance listing standards and Puget Energy’s Corporate Governance Guideline during that time. In addition, the Boards have determined that of this report.
the members constituting the Boards following the closing of the merger, William S. Ayer (member of the Boards of both Puget Sound Energy
The information called for and PSE) and Herbert B. Simon (member of the Board of PSE) are independent under the NYSE corporate governance listing standards and also meet the definition of an “Independent Director” under the Company’s Amended and Restated Bylaws. Under the Amended and Restated Bylaws of Puget Energy and PSE, an Independent Director is a director who: (a) shall not be a member of Puget Holdings (referred to as a Holdings Member) or an affiliate of any Holdings Member (including by Item 10way of being a member, stockholder, director, manager, partner, officer or employee of any such member), (b) shall not be an officer or employee of PSE, (c) shall be a resident of the state of Washington, and (d) if and to the extent required with respect to any specific director, shall meet such other qualifications as may be required by any applicable regulatory authority for an independent director or manager. The Company’s definition of “Independent Director” is available in the Corporate Governance Guidelines at www.pugetenergy.com.
In making these independence determinations, the Boards have established a categorical standard that a director’s independence is not impaired solely as a result of the director, or a company for which the director or an immediate family member of the director serves as an executive officer, making payments to PSE for power or natural gas provided by PSE at rates fixed in conformity with law or governmental authority, unless such payments would automatically disqualify the director under the NYSE’s corporate governance listing standards. The Board has also established a categorical standard that a director’s independence is omittednot impaired if a director is a director, employee or executive officer of another company that makes payments to or receives payments from Puget Energy, PSE or any of their affiliates, for property or services in an amount which is less than the greater of $1.0 million or one percent of such other company’s consolidated gross revenues, determined for the most recent fiscal year. These categorical standards will not apply, however, to the extent that Puget Energy or PSE would be required to disclose an arrangement as a related person transaction pursuant to General Instruction I(2)(c) to Form 10-K (omissionItem 404 of information by certain wholly owned subsidiaries).
Puget EnergyRegulation S-K.
The informationBoards considered all relationships between its directors and Puget Energy and PSE (and there respective subsidiaries), including some that are not required to be disclosed in this report as related-person transactions. Messrs. Ayer and Simon serve as directors or officers of, or otherwise have a financial interest in, entities that make payments to PSE for energy services provided to those entities at tariff rates established by this itemthe Washington Utilities and Transportation Commission. These transactions fall within the first categorical independence standard described above. In addition, PSE has entered into transactions with respectentities for whom Mr. Simon serves as a director or officer, or in which he otherwise has a financial interest, that involve amounts that are less than the greater of $1.0 million or 1% of those entities’ consolidated gross revenues. These transactions fall within the second categorical standard described above. Because these relationships either fall within the Board’s categorical independence standards or involve an amount that is not material to Puget Energy is incorporated herein by reference toor the material under “Director Compensation,” “Compensation Discussion and Analysis” and “Summary Compensation” in Puget Energy’s proxy statement for its 2007 Annual Meetingother entity, the Board has concluded that none of Shareholders (Commission File No. 1-16305).these relationships impair the independence of the applicable directors.
Puget Sound EnergyExecutive Sessions
The information called for byNon-management directors meet in executive session on a regular basis, generally on the same date as each scheduled Board meeting. Mr. Ayer, who is not a member of management, presides over the executive sessions. Interested parties may communicate with the non-management directors of the Board through the procedures described in Item 1110 of Part III of this annual report under the section “Communications with respect to PSE is omitted pursuant to General Instruction I (2)(c) to Form 10-K (omission of information by certain wholly owned subsidiaries).the Board.”
| SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED SHAREHOLDER MATTERS |
Puget Energy
Equity Compensation Plan Information
The information required by this item with respect to Puget Energy is incorporated herein by reference to the material under “Equity Compensation Plan Information” in Puget Energy’s proxy statement for its 2007 Annual Meeting of Shareholders (Commission File No. 1-16305).
Beneficial Ownership
The information required by this item with respect to Puget Energy is incorporated herein by reference to the material under “Security Ownership of Directors, Executive Officers and Certain Beneficial Owners” in Puget Energy’s proxy statement for its 2007 Annual Meeting of Shareholders (Commission File No. 1-16305).
Puget Sound Energy
Equity Compensation Plan Information
The information called for by this item with respect to PSE is omitted pursuant to General Instruction I (2)(e) to Form 10-K (omission of information by wholly owned subsidiaries).
Beneficial Ownership
As of December 31, 2006, all of the issued and outstanding shares of PSE’s common stock were held beneficially and of record by Puget Energy.
| CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS, AND DIRECTOR INDEPENDENCE |
None.
| PRINCIPAL ACCOUNTANT FEES AND SERVICES |
The aggregate fees billed by PricewaterhouseCoopers LLP, the Company’s independent registered public accounting firm, for the year ended December 31 were as follows:
| | | 2009 | | | 2008 | |
| (Dollars in Thousands) | | Puget Energy | | | PSE | | | Puget Energy | | | PSE | |
Audit fees 1 | | $ | 1,753 | | | $ | 1,632 | | | $ | 1,837 | | | $ | 1,837 | |
Audit related fees 2 | | | 207 | | | | 187 | | | | 112 | | | | 112 | |
Tax fees 3 | | | 150 | | | | 100 | | | | 100 | | | | 100 | |
| Total | | $ | 2,110 | | | $ | 1,919 | | | $ | 2,049 | | | $ | 2,049 | |
| | | 2006 | | 2005 | |
| (Dollars in Thousands) | | Puget Energy | | PSE | | Puget Energy | | PSE | |
Audit fees1 | | $ | 1,653 | | $ | 1,530 | | $ | 2,023 | | $ | 1,422 | |
Audit related fees2 | | | 100 | | | 100 | | | 103 | | | 81 | |
Tax fees3 | | | 34 | | | 34 | | | 45 | | | 33 | |
| Total | | $ | 1,787 | | $ | 1,664 | | $ | 2,171 | | $ | 1,536 | |
1 | For professional services rendered for the audit of Puget Energy’s and PSE’s annual financial statements, reviews of financial statements included in the Companies’Company’s Forms 10-Q and consents and reviews of documents filed with the Securities and Exchange Commission. The 20062009 fees are estimated and include an aggregate amount of $1.1$1.0 million and $1.0$0.9 million billed to Puget Energy and PSE, respectively, through December 2006. The 2005 fees include an aggregate amount of $1.1 million and $1.0 million billed to Puget Energy and PSE, respectively, through December 31, 2005. 2009. |
2 | Consists of employee benefit plan audits and due diligence reviews and assistance with Sarbanes-Oxley readiness. reviews. |
3 | Consists of tax consulting and tax return reviews. |
The Audit Committee of the Company has adopted policies for the pre-approval of all audit and non-audit services provided by the Company’s independent auditor.registered public accounting firm. The policies are designed to ensure that the provision of these services does not impair the auditor’sfirm’s independence. Under the policies, unless a type of service to be provided by the independent auditorregistered public accounting firm has received general pre-approval, it will require specific pre-approval by an Audit Committee. In addition, any proposed services exceeding pre-approved cost levels will require specific pre-approval by an Audit Committee.
The annual audit services engagement terms and fees, as well as any changes in terms, conditions and fees relating to the engagement, are subject to specific pre-approval by the Audit Committees.Committee. In addition, on an annual basis, the Audit Committees grantCommittee grants general pre-approval for specific categories of audit, audit-related, tax and other services, within specified fee levels, that may be provided by the independent registered public accounting firm. With respect to each proposed pre-approved service, the independent registered public accounting firm is required to provide detailed back-up documentation to the Audit CommitteesCommittee regarding the specific services to be provided. Under the policies, the Audit CommitteesCommittee may delegate pre-approval authority to one or more of their members. The member or members to whom such authority is delegated shall report any pre-approval decision to anthe Audit Committee at its next scheduled meeting. The Audit Committees doCommittee does not delegate responsibilities to pre-approve services performed by the independent registered public accounting firm to management.
For 20062009 and 2005,2008, all audit and non-audit services were pre-approved.
| EXHIBITS AND FINANCIAL STATEMENT SCHEDULES |
| a) | Documents filed as part of this report: |
| 2) | Financial Statement Schedules. Financial Statement Schedules of the Company, as required for the years ended December 31, 2006, 20052009, 2008 and 2004,2007, consist of the following: |
Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, each registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.
PUGET ENERGY, INC. | | PUGET SOUND ENERGY, INC. |
| | | |
| /s/ Stephen P. Reynolds | | /s/ Stephen P. Reynolds |
| Stephen P. Reynolds | | Stephen P. Reynolds |
Chairman, President and Chief Executive Officer | | Chairman, President and Chief Executive Officer |
| | | |
Date: March 1, 2007February 25, 2010 | | Date: March 1, 2007February 25, 2010 |
Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of each registrant and in the capacities and on the dates indicated.
| Signature | Title | Date |
| | (Puget Energy and PSE unless otherwise noted) |
| | |
| | |
| /s/ Stephen P. Reynolds | Chairman, President and | March 1, 2007February 25, 2010 |
| (Stephen P. Reynolds) | Chief Executive Officer | |
| | | |
| | | |
/s/ Bertrand A. ValdmanEric M. Markell | SeniorExecutive Vice President Finance and | |
(Bertrand A. Valdman)Eric M. Markell) | Chief Financial Officer | |
| | | |
| | | |
| /s/ James W. Eldredge | Vice President, Corporate SecretaryController | |
| (James W. Eldredge) | and Chief Accounting Officer | |
| | | |
| | | |
| /s/ William S. Ayer | Chairman and Director | |
| (William S. Ayer) | | |
| | | |
| | |
/s/ Phyllis J. CampbellGraeme Bevans | Director | |
(Phyllis J. Campbell)Graeme Bevans) | | |
| | | |
| | | |
/s/ Craig W. ColeAndrew Chapman | Director | |
(Craig W. Cole)Andrew Chapman) | | |
| | | |
| | | |
/s/ Stephen E. FrankAlan W. James | Director | |
(Stephen E. Frank)Alan W. James) | | |
| | | |
| | |
/s/ Tomio MoriguchiAlan Kadic | Director | |
(Tomio Moriguchi)Alan Kadic) | | |
| | | |
| | | |
/s/ Dr. Kenneth P. MortimerChristopher J. Leslie | Director | |
(Dr. Kenneth P. Mortimer)Christopher J. Leslie) | | |
| | |
| | |
| | | |
| | | |
/s/ Sally G. NarodickWilliam R. McKenzie | Director | |
(Sally G. Narodick)William R. McKenzie) | | |
| | | |
| | | |
/s/ Herbert B. SimonChris Trumpy | Director | |
(Herbert B. Simon)Chris Trumpy) | | |
| | | |
| | | |
/s/ George W. WatsonMark Wiseman | Director | |
(George W. Watson)Mark Wiseman) | | |
| | |
| | |
| /s/ Mark Wong | Director | |
| (Mark Wong) | | |
| | |
| | |
| /s/ Herbert B. Simon | Director of PSE only | |
| (Herbert B. Simon) | | |
| | |
Certain of the following exhibits are filed herewith. Certain other of the following exhibits have heretofore been filed with the Securities and Exchange Commission and are incorporated herein by reference.
| | 3(i).12.1 | Restated ArticlesAgreement and Plan of Incorporation ofMerger, dated October 25, 2007, by and among Puget Energy, (IncorporatedInc., Padua Holdings LLC, Padua Intermediate Holdings Inc. and Padua Merger Sub Inc. (incorporated herein by reference to Exhibit 99.2,2.1 to Puget Energy’s Current Report on Form 8-K, dated January 2, 2001,October 25, 2007, Commission File No. 333-77491)1-16305). |
| | 3(i).1 | Amended Articles of Incorporation of Puget Energy (incorporated herein by reference to Exhibit 3.1 to Puget Energy’s Current Report on Form 8-K, dated February 6, 2009, Commission File No. 1-16305). |
| 3(i).2 | Amended and Restated Articles of Incorporation of PSE (included as Annex FPuget Sound Energy, Inc. (incorporated herein by reference to the Joint Proxy Statement/Prospectus filedExhibit 3.2 to Puget Sound Energy’s Current Report on Form 8-K, dated February 1, 1996, Registration6, 2009, Commission File No. 333-617)1-4393). |
| | 3(ii).1 | Amended and Restated Bylaws of Puget Energy dated March 7, 2003 (Exhibit 3(ii).1February 6, 2009 (incorporated herein by reference to the AnnualExhibit 3.3 to Puget Energy’s Current Report on Form 10-K for the fiscal year ended December 31, 2002,8-K, Commission File No. 1-16305 and 1-4393)1-16305). |
| | 3(ii).2 | Amended and Restated Bylaws of PSEPuget Sound Energy, Inc. dated March 7, 2003 (Exhibit 3(ii).2February 6, 2009 (incorporated herein by reference to the AnnualExhibit 3.4 to Puget Sound Energy’s Current Report on Form 10-K for the fiscal year ended December 31, 2002,8-K, Commission File No. 1-16305 and 1-4393). |
| | 4.1 | Fortieth through Eighty-fourthIndenture between Puget Sound Energy, Inc. and U.S. Bank National Association (as successor to State Street Bank and Trust Company) defining the rights of the holders of Puget Sound Energy’s senior notes (incorporated herein by reference to Exhibit 4-a to Puget Sound Energy’s Report on Form 10-Q for the quarter ended June 30, 1998, Commission File No. 1-4393). |
| 4.2 | First, Second, Third and Fourth Supplemental Indentures defining the rights of the holders of PSE’sPuget Sound Energy’s senior notes (incorporated herein by reference to Exhibit 4-b to Puget Sound Energy’s Report on Form 10-Q for the quarter ended June 30, 1998, Commission File No. 1-4393; Exhibit 4.26 to Puget Sound Energy’s Current Report on Form 8-K, dated March 4, 1999, Commission File No. 1-4393; Exhibit 4.1 to Puget Sound Energy’s Current Report on Form 8-K, dated November 2, 2000, Commission File No. 1-4393; and Exhibit 4.1 to Puget Sound Energy’s Current Report on Form 8-K, dated May 28, 2003, Commission File No. 1-4393). |
| 4.3 | Fortieth through Sixtieth Supplemental Indentures defining the rights of the holders of Puget Sound Energy’s Electric Utility First Mortgage Bond (incorporated herein by reference to Exhibits 4.3 through and including 4.23 to Puget Sound Energy’s Registration Statement on Form S-3ASR, filed March 13, 2009, Registration No. 333-157960). |
| 4.4 | Sixty-first through Eighty-seventh Supplemental Indentures defining the rights of the holders of Puget Sound Energy’s Electric Utility First Mortgage Bonds (Exhibit 2-d(incorporated herein by reference to Registration No. 2-60200; Exhibit 4-c to Registration No. 2-13347; Exhibits 2-e through and including 2-k to Registration No. 2-60200; Exhibit 4-h to Registration No. 2-17465; Exhibits 2-l, 2-m and 2-n to Registration No. 2-60200; Exhibit 2-m to Registration No. 2-37645; Exhibits 2-o through and including 2-s to Registration No. 2-60200; Exhibit 5-b to Registration No. 2-62883; Exhibit 2-h to Registration No. 2-65831; Exhibit (4)-j-1 to Registration No. 2-72061; Exhibit (4)-a to Registration No. 2-91516; Exhibit (4)-b to AnnualPuget Sound Energy’s Report on Form 10-K for the fiscal year ended December 31, 1985, Commission File No. 1-4393; Exhibits (4)-b(a) and (4)(b) to Puget Sound Energy’s Current Report on Form 8-K, dated April 22, 1986, Commission File No. 1-4393; Exhibit (4)(b) to Puget Sound Energy’s Current Report on Form 8-K, dated September 5, 1986, Commission File No. 1-4393; Exhibit (4)-b to Puget Sound Energy’s Report on Form 10-Q for the quarter ended September 30, 1986, Commission File No. 1-4393; Exhibit (4)-c to Registration No. 33-18506; Exhibit (4)-b to Puget Sound Energy’s Report on Form 10-K for the fiscal year ended December 31, 1989, Commission File No. 1-4393; Exhibit (4)-b to Puget Sound Energy’s Report on Form 10-K for the fiscal year ended December 31, 1990, Commission File No. 1-4393; Exhibits (4)-d and (4)-e to Registration No. 33-45916; Exhibit (4)-c to Registration No. 33-50788; Exhibit (4)-a to Registration No. 33-53056; Exhibit 4.3 to Registration No. 33-63278; Exhibit 4.254-c to RegistrationPuget Sound Energy’s Report on Form 10-Q for the quarter ended June 20, 1998, Commission File No. 333-41181;1-4393; Exhibit 4.27 to Puget Sound Energy’s Current Report on Form 8-K, dated March 5, 1999;4, 1999, Commission File No. 1-4393; Exhibit 4.2 to Puget Sound Energy’s Current Report on Form 8-K, dated November 2, 2000;2000, Commission File No. 1-4393; Exhibit 4.2 to Puget Sound Energy’s Current Report on Form 8-K, dated June 3, 2003;May 28, 2003, Commission File No. 1-4393; Exhibit 4.28 to AnnualPuget Sound Energy’s Report on Form 10-K for the fiscal year ended December 31, 2004, Commission File No. 1-16305 and 1-4393; Exhibit 4.1 to Puget Sound Energy’s Current Report on Form 8-K, dated May 23, 2005, Commission File No. 1-16305 and 1-4393; Exhibit 4.30 to AnnualPuget Sound Energy’s Report on Form 10-K for the fiscal year ended December 31, 2005, Commission fileFile No. 1-16305 and 1-4393); andExhibit 4.4 to Post-Effective Amendment No. 2 to Puget Sound Energy’s Registration Statement on Form S-3, filed February 9, 2009, Registration No. 333-132497-01; Exhibit 4.1 to Puget Sound Energy’s Current Report on Form 8-K, dated September 14,13, 2006, Commission File No. 1-4393; Exhibit 4.1 to Puget Sound Energy’s Report on Form 10-K for the fiscal year ended December 31, 2007, Commission File No. 1-4393; and Exhibit 4.5 to Post-Effective Amendment No. 2 to Puget Sound Energy’s Registration Statement on Form S-3, filed February 9, 2009, Registration No. 333-132497-01); Exhibit 4.1 to Puget Sound Energy’s Current Report on Form 8-K, dated September 8, 2009, Commission File No. 1-4393. |
| | 4.2
4.5 | Indenture of First Mortgage, dated as of April 1, 1957, defining the rights of the holders of PSE’s senior notesPuget Sound Energy’s Gas Utility First Mortgage Bonds (incorporated herein by reference to Puget Sound Energy’s Registration Statement on Form S-3ASR, filed March 13, 2009, Registration No. 333-157960). |
| 4.6 | First, Sixth, Seventh and Seventeenth Supplemental Indenture to the Gas Utility First Mortgage, dated as of October 1, 1959, August 1, 1966, February 1, 1967, June 1, 1977 and August 9, 1978, respectively (incorporated herein by reference to Exhibits 4.26 through and including 4.30 to Puget Sound Energy's Registration Statement on Form S-3ASR, filed March 13, 2009, Registration No. 333-157960). |
| 4.7 | Twenty-second Supplemental Indenture to the Gas Utility First Mortgage, dated as of July 15, 1986 (incorporated herein by reference to Exhibit 4-a4-B.20 to PSE’s QuarterlyWashington Natural Gas Company’s Report on Form 10-Q10-K for the quarterfiscal year ended JuneSeptember 30, 1998,1986, Commission File No. 1-4393)0-951). |
| | 4.3
4.8 | FirstTwenty-seventh Supplemental Indenture definingto the rightsGas Utility First Mortgage, dated as of the holders of PSE’s senior notes, Series ASeptember 1, 1990 (incorporated herein by reference to Exhibit 4-b4.12 to PSE’s Quarterly ReportPost-Effective Amendment No. 2 to Puget Sound Energy’s Registration Statement on Form 10-Q for the quarter ended June 30, 1998, Commission FileS-3, filed February 9, 2009, Registration No. 1-4393)333-132497-01). |
| | 4.4
4.9 | SecondTwenty-eighth through Thirty-sixth Supplemental Indenture definingIndentures to the rights of the holders of PSE’s senior notes, Series BGas Utility First Mortgage (incorporated herein by reference to Exhibit 4.64-A to PSE’s CurrentWashington Natural Gas Company’s Report on Form 8-K, dated March 5, 1999, Commission File No. 1-4393). |
| 4.5
| Third Supplemental Indenture defining the rights of the holders of PSE’s senior notes, Series C (incorporated herein by reference to Exhibit 4.1 to PSE’s Current Report on Form 8-K, dated November 2, 2000, Commission File No. 1-4393). |
| 4.6
| Fourth Supplemental Indenture defining the rights of the holders of PSE’s senior notes (incorporated herein by reference to Exhibit 4.1 to PSE’s Current Report on Form 8-K, dated June 3, 2003, Commission File No. 1-4393). |
| 4.7
| Rights Agreement dated as of December 21, 2000 between Puget Energy and Wells Fargo Bank, N.A., as Rights Agent (incorporated herein by reference to Exhibit 4.1 to Puget Energy’s Registration Statement on Form S-3, dated January 11, 2007, Commission File No. 1-16305). |
| 4.8
| Indenture between PSE and the First National Bank of Chicago dated June 6, 1997 (incorporated herein by reference to Exhibit 4.1 of PSE’s Quarterly Report on Form 10-Q for the quarter ended June 30, 1997, Commission File No. 1-4393). |
| 4.9
| Amended and Restated Declaration of Trust between Puget Sound Energy Capital Trust and the First National Bank of Chicago dated June 6, 1997 (incorporated herein by reference to Exhibit 4.2 of PSE’s Quarterly Report on Form 10-Q for the quarter ended June 30, 1997, Commission File No. 1-4393). |
| 4.10
| Series A Capital Securities Guarantee Agreement between PSE and the First National Bank of Chicago dated June 6, 1997 (incorporated herein by reference to Exhibit 4.3 of PSE’s Quarterly Report on Form 10-Q for the quarter ended June 30, 1997, Commission File No. 1-4393). |
| 4.11
| First Supplemental Indenture dated as of October 1, 1959 (Exhibit 4-D to Registration No. 2-17876). |
| 4.12
| Sixth Supplemental Indenture dated as of August 1, 1966 (Exhibit to Form 8-K for month of August 1966, File No. 0-951). |
| 4.13
| Seventh Supplemental Indenture dated as of February 1, 1967 (Exhibit 4-M, Registration No. 2-27038). |
| 4.14
| Sixteenth Supplemental Indenture dated as of June 1, 1977 (Exhibit 6-05 to Registration No. 2-60352). |
| 4.15
| Seventeenth Supplemental Indenture dated as of August 9, 1978 (Exhibit 5-K.18 to Registration No. 2-64428). |
| 4.16
| Twenty-second Supplemental Indenture dated as of July 15, 1986 (Exhibit 4-B.20 to Form 10-K for the year ended September 30, 1986, File No. 0-951). |
| 4.17
| Twenty-seventh Supplemental Indenture dated as of September 1, 1990 (Exhibit 4-B.20, Form 10-K for the year ended September 30, 1998, File No. 10-951). |
| 4.18
| Twenty-eighth Supplemental Indenture dated as of July 31, 1991 (Exhibit 4-A, Form 10-Q for the quarter ended March 31, 1993, Commission File No. 0-951). |
| 4.19
| Twenty-ninth Supplemental Indenture dated as of June 1, 1993 (Exhibit0-951; Exhibit 4-A to Registration No. 33-49599). |
| 4.20
| Thirtieth Supplemental Indenture dated as of August 15, 1995 (incorporated herein by reference to Exhibit 4-A of Washington Natural Gas Company’s Registration Statement on Form S-3, Registration No. 33-49599; Exhibit 4-A to Washington Natural Gas Company’s Registration Statement on Form S-3, Registration No. 33-61859). |
| 4.21
| Thirty-first Supplemental Indenture dated February 10, 1997 (Exhibit33-61859; Exhibit 4.30 to the AnnualPuget Sound Energy’s Report on Form 10-K for the fiscal year ended December 31, 2002, Commission File No. 1-63051-4393; Exhibits 4.22 and 1-4393)4.23 to Puget Sound Energy’s Report on Form 10-K for the fiscal year ended December 31, 2005, Commission File No. 1-4393; Exhibits 4.22 and 4.23 to Puget Sound Energy’s Report on Form 10-K for the fiscal year ended December 31, 2007, Commission File No. 1-4393; and Exhibit 4.14 to Post-Effective Amendment No. 2 to Puget Sound Energy’s Registration Statement on Form S-3, filed February 9, 2009, Registration No. 333-132497-01). |
| | 4.22
4.10 | Thirty-second SupplementalUnsecured Debt Indenture, dated April 1, 2005,as of May 18, 2001, between Puget Sound Energy, Inc. and The Bank of New York Trust Company, N.A. (as successor to Bank One Trust Company, N.A.) defining the rights of the holders of PSE’s gas utility First Mortgage Bond.Puget Sound Energy’s unsecured debentures (incorporated herein by reference to Exhibit 4.3 to Puget Sound Energy’s Current Report on Form 8-K, dated May 18, 2001, Commission File No. 1-4393). |
| | 4.23
4.11 | Thirty-thirdSecond Supplemental Indenture to the Unsecured Debt Indenture, dated April 27, 2005,June 1, 2007, between Puget Sound Energy, Inc. and The Bank of New York Trust Company, N.A. defining the rights of the holders of PSE’s gas utility First Mortgage Bond.Puget Sound Energy’s Series A Enhanced Junior Subordinated Notes due June 1, 2067 (incorporated herein by reference to Exhibit 4.1 to Puget Sound Energy’s Current Report on Form 8-K, dated May 30, 2007, Commission File No. 1-4393). |
| | 4.24
4.12 | Form of Replacement Capital Covenant of Puget Sound Energy, Inc. (incorporated herein by reference to Exhibit 4.2 to Puget Sound Energy’s Current Report on Form 8-K, dated May 30, 2007, Commission File No. 1-4393). |
| 4.13 | Pledge Agreement dated March 11, 2003 between Puget Sound Energy, Inc. and Wells Fargo Bank Northwest, National Association, as Trustee (incorporated herein by reference to Exhibit 4.24 to the Company’s Post-Effective Amendment No. 1 to Puget Sound Energy’s Registration Statement on Form S-3, datedfiled July 11, 2003, Commission FileRegistration No. 333-82940-02). |
| | 4.25
4.14 | Loan Agreement dated as of March 1, 2003, between the City of Forsyth, Rosebud County, Montana and Puget Sound Energy, Inc. (incorporated herein by reference to Exhibit 4.25 to the Company’s Post-Effective Amendment No. 1 to Puget Sound Energy’s Registration Statement on Form S-3, datedfiled July 11, 2003, Commission FileRegistration No. 333-82490-02)333-82490). |
| | 10.1 | First Amendment dated as of October 4, 1961 to Power Sales Contract between Public Utility District No. 1 of Chelan County, Washington and PSE,Puget Sound Energy, Inc., relating to the Rocky Reach Project (Exhibit 13-d(incorporated herein by reference to RegistrationExhibit 10.1 to Puget Sound Energy’s Report on Form 10-Q for the quarter ended March 31, 2009, Commission File No. 2-24252)1-4393). |
| | 10.2 | First Amendment dated February 9, 1965 to Power Sales Contract between Public Utility District No. 1 of Douglas County, Washington and PSE,Puget Sound Energy, Inc., relating to the Wells Development (Exhibit 13-p(incorporated herein by reference to RegistrationExhibit 10.2 to Puget Sound Energy’s Report on Form 10-Q for the quarter ended March 31, 2009, Commission File No. 2-24252)1-4393). |
| | 10.3 | Contract dated November 14, 1957 between Public Utility District No. 1 of Chelan County, Washington and PSE,Puget Sound Energy, Inc., relating to the Rocky Reach Project (Exhibit 4-1-a(incorporated herein by reference to RegistrationExhibit 10.3 to Puget Sound Energy’s Report on Form 10-Q for the quarter ended March 31, 2009, Commission File No. 2-13979)1-4393). |
| | 10.4 | Power Sales Contract dated as of November 14, 1957 between Public Utility District No. 1 of Chelan County, Washington and PSE,Puget Sound Energy, Inc., relating to the Rocky Reach Project (Exhibit 4-c-1(incorporated herein by reference to RegistrationExhibit 10.4 to Puget Sound Energy’s Report on Form 10-Q for the quarter ended March 31, 2009, Commission File No. 2-13979)1-4393). |
| | 10.5 | Power Sales Contract dated May 21, 1956 between Public Utility District No. 2 of Grant County, Washington and PSE,Puget Sound Energy, Inc., relating to the Priest Rapids Project (Exhibit 4-d(incorporated herein by reference to RegistrationExhibit 10.5 to Puget Sound Energy’s Report on Form 10-Q for the quarter ended March 31, 2009, Commission File No. 2-13347)1-4393). |
| | 10.6 | First Amendment to Power Sales Contract dated as of August 5, 1958 between PSEPuget Sound Energy, Inc. and Public Utility District No. 2 of Grant County, Washington, relating to the Priest Rapids Development (Exhibit 13-h(incorporated herein by reference to RegistrationExhibit 10.6 to Puget Sound Energy’s Report on Form 10-Q for the quarter ended March 31, 2009, Commission File No. 2-15618)1-4393). |
| | 10.7 | Power Sales Contract dated June 22, 1959 between Public Utility District No. 2 of Grant County, Washington and PSE,Puget Sound Energy, Inc., relating to the Wanapum Development (Exhibit 13-j(incorporated herein by reference to RegistrationExhibit 10.7 to Puget Sound Energy’s Report on Form 10-Q for the quarter ended March 31, 2009, Commission File No. 2-15618)1-4393). |
| | 10.8 | Agreement to Amend Power Sales Contracts dated July 30, 1963 between Public Utility District No. 2 of Grant County, Washington and PSE,Puget Sound Energy, Inc., relating to the Wanapum Development (Exhibit 13-1(incorporated herein by reference to RegistrationExhibit 10.8 to Puget Sound Energy’s Report on Form 10-Q for the quarter ended March 31, 2009, Commission File No. 2-21824)1-4393). |
| | 10.9 | Power Sales Contract executed as of September 18, 1963 between Public Utility District No. 1 of Douglas County, Washington and PSE,Puget Sound Energy, Inc., relating to the Wells Development (Exhibit 13-r(incorporated herein by reference to RegistrationExhibit 10.9 to Puget Sound Energy’s Report on Form 10-Q for the quarter ended March 31, 2009, Commission File No. 2-21824)1-4393). |
| | 10.10 | Construction and Ownership Agreement dated as of July 30, 1971 between The Montana Power Company and PSE (Exhibit 5-bPuget Sound Energy, Inc. (incorporated herein by reference to RegistrationExhibit 10.10 to Puget Sound Energy’s Report on Form 10-Q for the quarter ended March 31, 2009, Commission File No. 2-45702)1-4393). |
| | 10.11 | Operation and Maintenance Agreement dated as of July 30, 1971 between The Montana Power Company and PSE (Exhibit 5-cPuget Sound Energy, Inc. (incorporated herein by reference to RegistrationExhibit 10.11 to Puget Sound Energy’s Report on Form 10-Q for the quarter ended March 31, 2009, Commission File No. 2-45702)1-4393). |
| | 10.12 | Contract dated June 19, 1974 between PSEPuget Sound Energy, Inc. and P.U.D. No. 1 of Chelan County (Exhibit D(incorporated herein by reference to Exhibit 10.12 to Puget Sound Energy’s Report on Form 8-K dated July 5, 1974)10-Q for the quarter ended March 31, 2009, Commission File No. 1-4393). |
| | 10.13 | Transmission Agreement dated April 17, 1981 between the Bonneville Power Administration and PSEPuget Sound Energy, Inc. (Colstrip Project) (Exhibit(incorporated herein by reference to Exhibit (10)-55 to Annual Report on Form 10-K for the fiscal year ended December 31, 1987, Commission File No. 1-4393). |
| | 10.14 | Transmission Agreement dated April 17, 1981 between the Bonneville Power Administration and Montana Intertie Users (Colstrip Project) (Exhibit(incorporated herein by reference to Exhibit (10)-56 to Annual Report on Form 10-K for the fiscal year ended December 31, 1987, Commission File No. 1-4393). |
| | 10.15 | Ownership and Operation Agreement dated as of May 6, 1981 between PSEPuget Sound Energy, Inc. and other Owners of the Colstrip Project (Colstrip 3 and 4) (Exhibit(incorporated herein by reference to Exhibit (10)-57 to Annual Report on Form 10-K for the fiscal year ended December 31, 1987, Commission File No. 1-4393). |
| | 10.16 | Colstrip Project Transmission Agreement dated as of May 6, 1981 between PSEPuget Sound Energy, Inc. and Owners of the Colstrip Project (Exhibit(incorporated herein by reference to Exhibit (10)-58 to Annual Report on Form 10-K for the fiscal year ended December 31, 1987, Commission File No. 1-4393). |
| | 10.17 | Common Facilities Agreement dated as of May 6, 1981 between PSEPuget Sound Energy, Inc. and Owners of Colstrip 1 and 2, and 3 and 4 (Exhibit(incorporated herein by reference to Exhibit (10)-59 to Annual Report on Form 10-K for the fiscal year ended December 31, 1987, Commission File No. 1-4393). |
| | 10.18 | Amendment dated as of June 1, 1968, to Power Sales Contract between Public Utility District No. 1 of Chelan County, Washington and PSEPuget Sound Energy, Inc. (Rocky Reach Project) (Exhibit(incorporated herein by reference to Exhibit (10)-66 to Annual Report on Form 10-K for the fiscal year ended December 31, 1987, Commission File No. 1-4393). |
| | 10.19 | Transmission Agreement dated as of December 30, 1987 between the Bonneville Power Administration and PSEPuget Sound Energy, Inc. (Rock Island Project) (Exhibit(incorporated herein by reference to Exhibit (10)-74 to Annual Report on Form 10-K for the fiscal year ended December 31, 1988, Commission File No. 1-4393). |
| | 10.20 | Power Sales Agreement between Northwestern Resources (formerly The Montana Power Company) and PSEPuget Sound Energy, Inc. dated as of October 1, 1989 (Exhibit(incorporated herein by reference to Exhibit (10)-4 to Quarterly Report on Form 10-Q for the quarter ended September 30, 1989, Commission File No. 1-4393). |
| | 10.21 | Amendment No. 1 to the Colstrip Project Transmission Agreement dated as of February 14, 1990 among The Montana Power Company, The Washington Water Power Company (Avista), Portland General Electric Company, , PacifiCorp and PSE (ExhibitPuget Sound Energy, Inc. (incorporated herein by reference to Exhibit (10)-91 to Annual Report on Form 10-K for the fiscal year ended December 31, 1990, Commission File No. 1-4393). |
| | 10.22 | Agreement for Firm Power Purchase (Thermal Project) dated December 27, 1990 among March Point Cogeneration Company, a California general partnership comprising San Juan Energy Company, a California corporation; Texas-Anacortes Cogeneration Company, a Delaware corporation; and PSE (ExhibitPuget Sound Energy, Inc. (incorporated herein by reference to Exhibit (10)-4 to Quarterly Report on Form 10-Q for the quarter ended March 31, 1991, Commission File No. 1-4393). |
| | 10.23 | Agreement for Firm Power Purchase dated March 20, 1991 between Tenaska Washington, Inc., a Delaware corporation, and PSE (ExhibitPuget Sound Energy, Inc. (incorporated herein by reference to Exhibit (10)-1 to Quarterly Report on Form 10-Q for the quarter ended June 30, 1991, Commission File No. 1-4393). |
| | 10.24 | Amendment of Seasonal Exchange Agreement, dated December 4, 1991 between Pacific Gas and Electric Company and PSE (ExhibitPuget Sound Energy, Inc. (incorporated herein by reference to Exhibit (10)-107 to Annual Report on Form 10-K for the fiscal year ended December 31, 1991, Commission File No. 1-4393). |
| | 10.25 | Capacity and Energy Exchange Agreement, dated as of October 4, 1991 between Pacific Gas and Electric Company and PSE (ExhibitPuget Sound Energy, Inc. (incorporated herein by reference to Exhibit (10)-108 to Annual Report on Form 10-K for the fiscal year ended December 31, 1991, Commission File No. 1-4393). |
| | 10.26 | General Transmission Agreement dated as of December 1, 1994 between the Bonneville Power Administration and PSEPuget Sound Energy, Inc. (BPA Contract No. DE-MS79-94BP93947) (Exhibit(incorporated herein by reference to Exhibit 10.115 to Annual Report on Form 10-K for the fiscal year ended December 31, 1994, Commission File No. 1-4393). |
| | 10.27 | PNW AC Intertie Capacity Ownership Agreement dated as of October 11, 1994 between the Bonneville Power Administration and PSEPuget Sound Energy, Inc. (BPA Contract No. DE-MS79-94BP94521) (Exhibit(incorporated herein by reference to Exhibit 10.116 to Annual Report on Form 10-K for the fiscal year ended December 31, 1994, Commission File No. 1-4393). |
| | 10.28 | Amendment to Gas Transportation Service Contract dated July 31, 1991 between Washington Natural Gas Company and Northwest Pipeline Corporation (Exhibit(incorporated herein by reference to Exhibit 10-E.2 to Washington Natural Gas Company’s Form 10-K for the fiscal year ended September 30, 1995, Commission File No. 11271)1-11271). |
| | 10.29 | Firm Transportation Service Agreement dated January 12, 1994 between Northwest Pipeline Corporation and Washington Natural Gas Company for firm transportation service from Jackson Prairie (Exhibit(incorporated herein by reference to Exhibit 10-P to Washington Natural Gas Company’s Form 10-K for the fiscal year ended September 30, 1994, Commission File No. 1-11271). |
| | 10.30 | PowerProduct Sales Contract dated April 15, 2002,December 13, 2001 and Amendment No. 1 thereto, between Public Utility District No. 2 of Grant County, Washington, and PSE,Puget Sound Energy, Inc., relating to the Priest Rapids Project. (ExhibitProject (incorporated herein by reference to Exhibit 10-1 to Puget Sound Energy’s Report on Form 10-Q for the quarter ended June 30, 2002, File No. 1-16305 and 1-4393). |
| | 10.31 | Reasonable Portion Power Sales Contract dated April 15, 2002,December 13, 2001 and Amendment No. 1 thereto, between Public Utility District No. 2 of Grant County, Washington, and PSE,Puget Sound Energy, Inc., relating to the Priest Rapids Project. (ExhibitProject (incorporated herein by reference to Exhibit 10-2 to Puget Sound Energy’s Report on Form 10-Q for the quarter ended June 30, 2002, Commission File No. 1-16305 and 1-4393). |
| | 10.32 | Additional PowerProducts Sales ContractAgreement dated April 15, 2002,December 13, 2001, and Amendment No. 1 thereto, between Public Utility District No. 2 of Grant County, Washington, and PSE,Puget Sound Energy, Inc., relating to the Priest Rapids Project. (Exhibit 10-3Project (incorporated herein by reference to Exhibit 10.3 to Puget Sound Energy’s Report on Form 10-Q for the quarter ended June 30, 2002, Commission File No. 1-16305 and 1-4393). |
| | 10.33 | Amended and Restated Credit Agreement dated March 25, 2005 covering PSEas of May 16, 2008 among Puget Merger Sub Inc., as Borrower, Barclays Bank PLC, as Facility Agent, the other agents party thereto, and various banks named therein, Wachovia Bank National Association as administrative agent. (Exhibit 99.1the lenders party thereto (incorporated herein by reference to CurrentExhibit 10.1 to Puget Energy’s and Puget Sound Energy’s Report on Form 8-K, dated March 29, 2005, Commission File No. 1-4393 and 1-16305). |
| 10.34
| First Amendment to10-Q for the Amended and Restated Credit Agreement dated April 4, 2006 cover PSE and various banks named therein, Wachovia Bank National Association as administrative agent. (Exhibit 10.1 to the Current Report of Form 10-Q, dated March 31, 2006,quarter ended September 30, 2009, Commission File Nos. 1-16305 and 1-4393). |
| | 10.35
10.34 | Loan and ServingCredit Agreement dated December 20, 2005,as of February 6, 2009 among PSE, PSE Funding,Puget Sound Energy, Inc., as Borrower, Barclays Bank PLC, as Facility Agent, the other agents party thereto, and J.P. Morgan Chase Bank as program agent (Exhibitthe lenders party thereto (incorporated herein by reference to Exhibit 10.2 to the CurrentPuget Energy’s and Puget Sound Energy’s Report on Form 8-K dated December 22, 2005, Commission File No. 1-4393 and 1-16305). |
| 10.36
| Receivable Sale Agreement dated December 20, 2005, among PSE and PSE Funding, Inc. (Exhibit 10.1 to10-Q for the Current Report on Form 8-K dated December 22, 2005,quarter ended September 30, 2009, Commission File Nos. 1-16305 and 1-4393). |
| ** | 10.37
| Puget Energy, Inc. Non-employee Director Stock Plan. (Appendix B to definitive Proxy Statement, dated March 7, 2005, Commission File No. 1-16305). |
** | 10.38
| Puget Energy, Inc. Employee Stock Purchase Plan. (Incorporated herein by reference to Exhibit 99.1 to Puget Energy’s Post Effective Amendment No. 1 to Form S-8 Registration Statement, dated January 2, 2001, Commission File No. 333-41113-99.) |
** | 10.39
| Puget Energy 2005 Long-Term Incentive Plan. (Appendix A to definitive Proxy Statement, dated March 7, 2005, Commission File No. 1-16305). |
** | 10.40
| Amendment No. 1 to 2005 Long-Term Incentive Plan of Puget Energy, Inc. (Exhibit 10.1 to the Current Report on Form 8-K, dated February 14, 2006, Commission File Nos. 1-16305 and 1-4393). |
** | 10.41
10.35 | Employment agreement with S. P. Reynolds, Chief Executive Officer and President, dated January 7,1, 2002 (Exhibit(incorporated herein by reference to Exhibit 10.104 to the Annual Report on Form 10-K for the fiscal year ended December 31, 2001, Commission File No.Nos. 1-16305 and 1-4393). |
| ** | 10.42
10.36 | First Amendment datedeffective May 10,12, 2005 to employment agreement with S.P. Reynolds, Chief Executive Officer and President, dated as of January 1, 2002 (Exhibit(incorporated herein by reference to Exhibit 10.3 to the Current Report on Form 8-K, dated May 12, 2005, Commission File Nos. 1-16305 and 1-4393). |
| ** | 10.43
10.37 | Second Amendment dated February 9, 2006 to employment agreement with S. P. Reynolds, Chief Executive Officer and President, dated as of January 1, 2002 and amended as of May 10, 2005 (Exhibit(incorporated herein by reference to Exhibit 10.2 to the Current Report on Form 8-K, dated February 14, 2006, Commission File Nos. 1-16305 and 1-4393). |
| ** | 10.44
10.38 | Restricted Stock Award AgreementThird Amendment dated February 28, 2008 to employment agreement with S. P.S.P. Reynolds, Chief Executive Officer and President, dated as of January 8, 2004 (Exhibit 10.901, 2002 and amended as of February 9, 2006 (incorporated herein by reference to the AnnualExhibit 10.44 to Puget Energy’s Report on Form 10-K for the fiscal year ended December 31, 2003,2007, Commission File No. 1-16305 and 1-4393). |
| ** | 10.45
10.39 | Restricted Stock Unit AwardForm of Executive Employment Agreement with S.Executive Officers (incorporated herein by reference to Exhibit 10.1 to Puget Sound Energy’s Current Report on Form 8-K, dated April 3, 2009, Commission File No. 1-4393). |
| *** | 10.40 | Waiver of rights to certain payments and other benefits, executed by Stephen P. Reynolds, Chief Executive Officer and President, dated February 25, 2010. |
| ** | 10.41 | Puget Sound Energy, Inc. Amended and Restated Supplemental Executive Retirement Plan effective January 8, 2004 (Exhibit 10.911, 2009 (incorporated herein by reference to the AnnualExhibit 10.39 to Puget Energy’s and Puget Sound Energy’s Report on Form 10-K for the fiscal year ended December 31, 2003,2008, Commission File No. 1-16305 and 1-4393). |
| ** | 10.46
| Restricted Stock Award Agreement with S. P. Reynolds, Chief Executive Officer and President, dated January 8, 2002 (Exhibit 99.1 to Form S-8 Registration Statement, dated January 8, 2002, Commission File No. 333-76424). |
** | 10.47
| Nonqualified Stock Option Grant Notice/Agreement with S. P. Reynolds, Chief Executive Officer and President dated March 11, 2002 (Exhibit 99.1 and Exhibit 99.2 to Form S-8 Registration Statement dated March 18, 2002, Commission File No. 333-84426). |
** | 10.48
10.42 | Puget Sound Energy, Inc. Amended and Restated Supplemental Executive RetirementDeferred Compensation Plan for Senior Management dated October 5, 2004. (Exhibit 10.55Key Employees effective January 1, 2009 (incorporated herein by reference to AnnualExhibit 10.40 to Puget Energy’s and Puget Sound Energy’s Report on Form 10-K for the fiscal year ended December 31, 2005,2008, Commission File No. 1-16305 and 1-4393). |
| ** | 10.49
10.43 | Puget Sound Energy, Inc. Amended and Restated Deferred Compensation Plan for Key Employees datedNonemployee Directors effective January 1, 2003. (Exhibit 10.562009 (incorporated herein by reference to AnnualExhibit 10.41 to Puget Energy’s and Puget Sound Energy’s Report on Form 10-K for the fiscal year ended December 31, 2005,2008, Commission File No. 1-16305 and 1-4393). |
| ** | 10.50
10.44 | Summary of Director Compensation (incorporated herein by reference to Exhibit 10.51 to Puget Energy’s and Puget Sound Energy Amended and Restated Deferred Compensation Plan for Nonemployee Directors dated October 1, 2000. (Exhibit 10.57 to AnnualEnergy’s Report on Form 10-K for the fiscal year ended December 31, 2005,2006, Commission File No. 1-16305 and 1-4393). |
| * | 10.51
| Summary of Director Compensation |
** | 10.52
| Performance-Based Restricted Stock Award Agreement with S.P. Reynolds, Chief Executive Officer and President, dated May 12, 2005 (Exhibit 10.4 to the Current Report on Form 8-K, dated May 12, 2005, Commission File Nos. 1-16305 and 1-4393). |
** | 10.53
10.45 | Form of Amended and Restated Change of Control Agreement between Puget Sound Energy, Inc. and Executive Officers (Exhibit(incorporated herein by reference to Exhibit 10.3 to the Current Report on Form 8-K, dated February 14, 2006, Commission File Nos. 1-4393). |
| ** | 10.46 | Puget Sound Energy, Inc. Supplemental Death Benefit Plan for Executive Employees, effective October 1, 2000, as amended (incorporated herein by reference to Exhibit 10.45 to Puget Energy’s and Puget Sound Energy’s Report on Form 10-K for the fiscal year ended December 31, 2008, Commission File No. 1-16305 and 1-4393). |
| ** | 10.54
10.47 | Form of Performance-Based Restricted Stock Award Agreement between Puget Sound Energy, Inc. Supplemental Death Benefit Plan for Executive Employees, effective January 1, 2002, as amended (incorporated herein by reference to Exhibit 10.46 to Puget Energy’s and Key Employees (Exhibit 10.1 to the CurrentPuget Sound Energy’s Report on Form 8-K, dated February 28, 2006,10-K for the fiscal year ended December 31, 2008, Commission File No. 1-16305)1-16305 and 1-4393). |
| ** | 10.5510.48 | Summary of Severance BenefitPuget Sound Energy, Inc. Supplemental Disability Plan for B. A. Valdman, Senior Vice President FinanceExecutive Employees, effective October 1, 2000, as amended (incorporated herein by reference to Exhibit 10.47 to Puget Energy’s and Chief Financial Officer. Puget Sound Energy’s Report on Form 10-K for the fiscal year ended December 31, 2008, Commission File No. 1-16305 and 1-4393). |
| ** | 10.5610.49 | Restricted Stock Award Agreement with B. A. Valdman, Senior Vice President FinancePuget Sound Energy, Inc. Supplemental Death Benefit Plan for Executive Employees, effective November 1, 2007, as amended (incorporated herein by reference to Exhibit 10.48 to Puget Energy’s and Chief Financial Officer, datedPuget Sound Energy’s Report on Form 10-K for the fiscal year ended December 4, 2003.31, 2008, Commission File No. 1-16305 and 1-4393). |
| * | 12.1 | Statement setting forth computation of ratios of earnings to fixed charges of Puget Energy, (2002Inc. (2005 through 2006)2009). |
| * | 12.2 | Statement setting forth computation of ratios of earnings to fixed charges of Puget Sound Energy, (2002Inc. (2005 through 2006)2009). |
| * | 21.1 | Subsidiaries of Puget Energy.Energy, Inc. |
| * | 21.2 | Subsidiaries of PSE.Puget Sound Energy, Inc. |
| * | 23.1 | Consent of PricewaterhouseCoopers LLP. |
| * | 31.1 | Certification of Puget Energy, Inc. - Certification Pursuant to 18 U.S.C. Section 1350, as Adopted Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002 -– Stephen P. Reynolds. |
| * | 31.2 | Certification of Puget Energy, Inc. - Certification Pursuant to 18 U.S.C. Section 1350, as Adopted Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002 - Bertrand A. Valdman.– Eric M. Markell. |
| * | 31.3 | Certification of Puget Sound Energy, Inc. - Certification Pursuant to 18 U.S.C. Section 1350, as Adopted Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002 -– Stephen P. Reynolds. |
| * | 31.4 | Certification of Puget Sound Energy, -Inc. – Certification Pursuant to 18 U.S.C. Section 1350, as Adopted Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002 - Bertrand A. Valdman.– Eric M. Markell. |
| * | 32.1 | Certification Pursuant to 18 U.S.C. Section 1350, as Adopted Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002 -– Stephen P. Reynolds. |
| * | 32.2 | Certification Pursuant to 18 U.S.C. Section 1350, as Adopted Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002 - Bertrand A. Valdman.– Eric M. Markell. |
| 99.1 | Washington Commission Order (incorporated herein by reference to Exhibit 99.1 to Puget Energy’s and Puget Sound Energy’s Current Report on Form 8-K, dated December 30, 2008, Commission File Nos. 1-16305 and 1-4393). |
_______________
* | Filed herewith. |
** | Management contract or compensating plan or arrangement. |
| *** | Management contract or compensating plan or arrangement filed herewith. |
