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As filed with the Securities and Exchange Commission on November 23, 2015

Registration 333-207875

 

 

 

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

 

 

FORM S-4/A

AMENDMENT NO. 1

TO

REGISTRATION STATEMENT

UNDER

THE SECURITIES ACT OF 1933

 

 

PUGET ENERGY, INC.

(Exact name of registrant as specified in its charter)

 

 

 

Washington		6719		91-1969407
(State or Other Jurisdiction of Incorporation or Organization)		(Primary Standard Industrial Classification Code Number)		(I.R.S. Employer Identification Number)

10885 N.E. 4th Street, Suite 1200

Bellevue, Washington 98004

(425) 454-6363

(Address, including zip code, and telephone number, including area code, of registrant’s principal executive offices)

 

 

Steve Secrist

Vice President, General Counsel and Chief Ethics and Compliance Officer

Puget Energy, Inc.

10885 N.E. 4th Street, Suite 1200

Bellevue, Washington 98004

(425) 454-6363

(Name, address, including zip code, and telephone number, including area code, of agent for service)

 

 

Copies to:

Andrew Bor

Perkins Coie LLP

1201 Third Avenue, Suite 4800

Seattle, Washington 98101-3099

(206) 359-8000

 

 

Approximate date of commencement of proposed sale to the public:

As soon as practicable after this Registration Statement becomes effective.

If the securities being registered on this Form are being offered in connection with the formation of a holding company and there is compliance with General Instruction G, check the following box.  ¨

If this Form is filed to register additional securities for an offering pursuant to Rule 462(b) under the Securities Act, check the following box and list the Securities Act registration statement number of the earlier effective registration statement for the same offering.  ¨

If this Form is a post-effective amendment filed pursuant to Rule 462(d) under the Securities Act, check the following box and list the Securities Act registration statement number of the earlier effective registration statement for the same offering.  ¨

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller reporting company. See the definitions of “large accelerated filer,” “accelerated filer” and “smaller reporting company” in Rule 12b-2 of the Exchange Act.

 

Large accelerated filer		¨		Accelerated filer		¨
Non-accelerated filer		x  (Do not check if a smaller reporting company)		Smaller reporting company		¨

If applicable, place an X in the box to designate the appropriate rule provision relied upon in conducting this transaction:

Exchange Act Rule 13e-4(i) (Cross-Border Issuer Tender Offer)  ¨

Exchange Act Rule 14d-1(d) (Cross-Border Third-Party Tender Offer)  ¨

 

 

The registrant hereby amends this Registration Statement on such date or dates as may be necessary to delay its effective date until the registrant shall file a further amendment which specifically states that this Registration Statement shall thereafter become effective in accordance with Section 8(a) of the Securities Act of 1933 or until this Registration Statement shall become effective on such date as the Securities and Exchange Commission, acting pursuant to said Section 8(a), may determine.

 

 

CALCULATION OF REGISTRATION FEE

 

Title of Each Class of Securities to be Registered		Amount to be Registered		Proposed Maximum Offering Price Per Unit(1)(2)		Proposed Maximum Aggregate Offering Price(1)(2)		Amount of Registration Fee
3.650% Senior Secured Notes due 2025		$400,000,000		100%		$400,000,000		$40,280(3)

(1)	Estimated solely for the purpose of calculating the registration fee pursuant to Rule 457(f) under the Securities Act of 1933.

(2)	Equals the aggregate principal amount of the securities being registered.

(3)	Previously paid in connection with the filing of this Registration Statement.

 

 

 

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P R O S P E C T U S

Puget Energy, Inc.

OFFER TO EXCHANGE ITS

3.650% Senior Secured Notes due 2025

that have been registered under the Securities Act of 1933, as amended

for any and all of its outstanding

3.650% Senior Secured Notes due 2025

that were issued and sold in a transaction

exempt from registration

under the Securities Act of 1933, as amended

 

 

Puget Energy, Inc., a Washington corporation, hereby offers to exchange, upon the terms and conditions set forth in this prospectus and the accompanying letter of transmittal, up to $400 million in aggregate principal amount of its 3.650% Senior Secured Notes due 2025, which we refer to as the “exchange notes,” for the same principal amount of its outstanding 3.650% Senior Secured Notes due 2025, which we refer to as the “original notes.” We refer to the original notes and the exchange notes, collectively, as the “Notes.” The original notes are and the exchange notes will be senior secured obligations and rank and will rank pari passu in right of payment with all of our existing and future senior secured indebtedness and will rank senior to all of our future subordinated indebtedness. Subject to certain exceptions, the Notes are and will be secured by a security interest in (i) substantially all of our assets, which for all practical purposes consists mainly of all of the issued and outstanding stock in our wholly owned operating subsidiary, Puget Sound Energy, Inc. (“PSE”) and (ii) all of our equity interests owned by our parent company, Puget Equico LLC (“Puget Equico”). These same assets also secure our obligations under our senior secured credit facility on an equal and ratable basis and may secure other obligations in the future on an equal and ratable basis.

The terms of the exchange notes are substantially identical to the terms of the original notes, except that the exchange notes will generally be freely transferable and do not contain certain terms with respect to registration rights and liquidated damages. We will issue the exchange notes under the indenture governing the original notes. For a description of the principal terms of the exchange notes, see “Description of Notes.”

The exchange offer will expire at 5:00 p.m. New York City time, on December 24, 2015, unless we extend the offer. At any time prior to the expiration date, you may withdraw your tender of any original notes; otherwise, such tender is irrevocable. We will receive no cash proceeds from the exchange offer.

The exchange notes constitute a new issue of securities for which there is no established trading market. Any original notes not tendered and accepted in the exchange offer will remain outstanding. To the extent original notes are tendered and accepted in the exchange offer, your ability to sell untendered, and tendered but unaccepted, original notes could be adversely affected. Following consummation of the exchange offer, the original notes will continue to be subject to their existing transfer restrictions and we will generally have no further obligations to provide for the registration of the original notes under the Securities Act of 1933, as amended, or the Securities Act. We cannot guarantee that an active trading market will develop or give assurances as to the liquidity of the trading market for either the original notes or the exchange notes. We do not intend to apply for listing of either the original notes or the exchange notes on any exchange or market.

Each broker-dealer that receives exchange notes for its own account pursuant to the exchange offer must acknowledge that it will deliver a prospectus in connection with any resale of its exchange notes. The letter of transmittal states that by so acknowledging and by delivering a prospectus, a broker-dealer will not be deemed to admit that it is an “underwriter” within the meaning of the Securities Act. This prospectus, as it may be amended or supplemented from time to time, may be used by a broker-dealer for a period of 180 days following the consummation of the exchange offer (or until such broker-dealer is no longer required to deliver a prospectus) in connection with resales of exchange notes received in exchange for notes where the notes were acquired by the broker-dealer as a result of market-making activities or other trading activities. See “Plan of Distribution.”

 

 

Investing in the exchange notes involves certain risks. Please read “Risk Factors” beginning on page 11 of this prospectus.

This prospectus and the letter of transmittal are first being mailed to all holders of the original notes on or about November 23, 2015.

 

 

Neither the Securities and Exchange Commission, or the SEC or the Commission, nor any state securities commission has approved or disapproved of the exchange notes or determined if this prospectus is truthful or complete. Any representation to the contrary is a criminal offense.

 

 

The date of this prospectus is November 23, 2015.

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You should rely only on the information provided in this prospectus or any prospectus supplement. We have not authorized anyone else to provide you with information different from that contained in this prospectus. We are offering to exchange original notes for exchange notes only in jurisdictions where such offer is permitted. You should not assume that the information in this prospectus or any prospectus supplement is accurate as of any other date other than the date on the front of these documents.

No dealer, salesperson or other person has been authorized to give any information or to make any representations other than those contained in this prospectus in connection with the exchange offer, and, if given or made, such information or representations must not be relied upon as having been authorized by Puget Energy. This prospectus does not constitute an offer of any securities other than those to which it relates or an offer or a solicitation by anyone in any jurisdiction in which such offer or solicitation is not authorized or in which the person making such offer or solicitation is not qualified to do so or to anyone to whom it is unlawful to make such offer or solicitation in such jurisdiction. Neither the delivery of this prospectus nor any sale made hereunder shall under any circumstance create an implication that there has been no change in the affairs of Puget Energy since the date hereof of this prospectus.

TABLE OF CONTENTS

 

		Page
Forward-Looking Statements			ii
Prospectus Summary			1
Ratio of Earnings to Fixed Charges			10
Risk Factors			11
Private Placement			25
The Exchange Offer			26
Use of Proceeds			35
Capitalization			36
Selected Financial Information			37
Management’s Discussion and Analysis			38
Description of Business			59
Description of Notes			69
Material United States Federal Income Tax Considerations			100
Plan of Distribution			101
Legal Matters			102
Experts			102
Where You Can Find More Information			102
Index to Consolidated Financial Statements			F-1

 

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FORWARD-LOOKING STATEMENTS

This prospectus contains forward-looking statements. Words or phrases such as “anticipates,” “believes,” “continues,” “could,” “estimates,” “expects,” “future,” “intends,” “may,” “might,” “plans,” “potential,” “predicts,” “projects,” “should,” “will likely result,” “will continue” or similar expressions are intended to identify certain of these forward-looking statements. Forward-looking statements provide our current expectations or forecasts of future events.

Forward-looking statements reflect current expectations and involve risks and uncertainties that could cause actual results or outcomes to differ materially from those expressed. Our expectations, beliefs and projections are expressed in good faith and are believed by us and PSE, as applicable, to have a reasonable basis, including without limitation, management’s examination of historical operating trends, data contained in records and other data available from third parties. However, there can be no assurance that our expectations, beliefs or projections will be achieved or accomplished.

In addition to other factors and matters discussed elsewhere in this prospectus, some important factors that could cause actual results 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, financing, 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, natural gas and electric distribution and transmission facilities, 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, implementation of energy efficiency programs and present or prospective wholesale and retail competition;

 

•

Failure of PSE to comply with the FERC or the 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 in a timely manner;

 

•

Changes in tax law, related regulations or differing interpretation or enforcement of applicable law by the Internal Revenue Service (“IRS”) or other taxing jurisdiction;

 

•

Inability to realize deferred tax assets and use Production Tax Credits (“PTCs”) due to insufficient future taxable income;

 

•

Inability to manage costs during the rate stay out period through March 31, 2016, due to unforeseen events which would cause increases in costs of operations;

 

•

Accidents or natural disasters, such as hurricanes, windstorms, earthquakes, floods, fires and landslides, which can interrupt service and lead to lost revenue, cause temporary supply disruptions and/or price spikes in the cost of fuel and raw materials and impose extraordinary costs;

 

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•

Commodity price risks associated with procuring natural gas and power in wholesale markets or counterparties extending credit to PSE without collateral posting requirements;

 

•

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, adversely affect the availability of and access to capital and credit markets and/or impact delivery of energy to PSE from its 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 revenue and expenses;

 

•

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 hydrological conditions, which can impact streamflow and PSE’s ability to generate electricity from hydroelectric facilities;

 

•

Electric 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 and generating facilities;

 

•

The ability to restart generation following a regional transmission disruption;

 

•

The 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;

 

•

Industrial, commercial and residential growth and demographic patterns in the service territories of PSE;

 

•

General economic conditions in the Pacific Northwest, which may impact customer consumption or affect PSE’s accounts receivable;

 

•

The loss of significant customers, changes in the business of significant customers or the condemnation of PSE’s facilities as a result of municipalization or other government action or negotiated settlement, 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, asset-based or cyber-based attacks, flu pandemic or similar significant events;

 

•

Capital market conditions, including changes in the availability of capital and interest rate fluctuations;

 

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•

Employee workforce factors, including strikes, work stoppages, availability of qualified employees or the loss of a key executive;

 

•

The ability to obtain insurance coverage, the availability of insurance for certain specific losses and the cost of such insurance;

 

•

The ability to maintain effective internal controls over financial 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 Puget Energy or PSE generally, or the failure to comply with the covenants in Puget Energy’s or PSE’s credit facilities, which would limit Puget Energy’s and PSE’s 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, we 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 us to predict all such factors, nor can we 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 “Risk Factors” included elsewhere in this prospectus.

 

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RISK FACTORS

You should carefully consider the following risks, as well as the other information contained in this prospectus, before exchanging the notes. The risks and uncertainties described below are not the only ones facing us. Additional risks and uncertainties not presently known or currently deemed immaterial may also impair our business operations and our ability to service the Notes.

RISKS RELATING TO THE EXCHANGE OFFER

Because there is no public market for the exchange notes, you may not be able to sell your exchange notes.

The exchange notes will be registered under the Securities Act, but will constitute a new issue of securities with no established trading market. There can be no assurance as to:

 

•

The liquidity of any trading market that may develop;

 

•

The ability of holders to sell their exchange notes; or

 

•

The price at which the holders would be able to sell their exchange notes.

The exchange notes will not be listed on any exchange or market. If a trading market were to develop, the exchange notes might trade at higher or lower prices than their principal amount or purchase price, depending on many factors, including prevailing interest rates, the market for similar securities and our financial performance.

Any market-making activity in the exchange notes will be subject to the limits imposed by the Securities Act and the Exchange Act. There can be no assurance that an active trading market will exist for the exchange notes or that any trading market that does develop will be liquid.

In addition, any original note holder who tenders in the exchange offer for the purpose of participating in a distribution of the exchange notes may be deemed to have received restricted securities and, if so, will be required to comply with the registration and prospectus delivery requirements of the Securities Act in connection with any resale transaction.

Your original notes will not be accepted for exchange if you fail to follow the exchange offer procedures.

We will issue exchange notes pursuant to the exchange offer only after a timely receipt of your original notes, a properly completed and duly executed letter of transmittal and all other required documents. Therefore, if you want to tender your original notes, please allow sufficient time to ensure timely delivery. If we do not receive your original notes, letter of transmittal and other required documents by the expiration date of the exchange offer, we will not accept your original notes for exchange. We are under no duty to give notification of defects or irregularities with respect to the tenders of original notes for exchange. If there are defects or irregularities with respect to your tender of original notes, we may not accept your original notes for exchange.

If you do not exchange your original notes, your original notes will continue to be subject to the existing transfer restrictions and you may be unable to sell your outstanding original notes.

We did not register the original notes and do not intend to do so following the exchange offer. Original notes that are not tendered will therefore continue to be subject to the existing transfer restrictions and may be transferred only in limited circumstances under applicable securities laws. If you do not exchange your original notes, you will lose your right, except in limited circumstances, to have your original notes registered under the federal securities laws. As a result, if you hold original notes after the exchange offer, you may be unable to sell your original notes and the value of the original notes may decline. We have no obligation, except in limited circumstances, and do not currently intend, to file an additional registration statement to cover the resale of original notes that did not tender in the exchange offer or to re-offer to exchange the exchange notes for original notes following the expiration of the exchange offer.

 

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RISKS RELATING TO PUGET ENERGY’S CORPORATE STRUCTURE

As a holding company, we depend on PSE’s ability to pay dividends.

As a holding company with no significant operations of our own, the primary source of funds for the repayment of debt and other expenses, as well as payment of dividends to our shareholder, are cash dividends PSE pays us. PSE is a separate and distinct legal entity and has no obligation to pay any amounts to us, whether by dividends, loans or other payments. The ability of PSE to pay dividends or make distributions to us, and accordingly, our ability to pay dividends or repay debt or other expenses, will depend on PSE’s earnings, capital requirements and general financial condition. If we do not receive adequate distributions from PSE, we may not be able to meet our obligations or pay dividends.

The payment of dividends by PSE to us is restricted by provisions of certain covenants applicable to long-term debt contained in PSE’s electric and natural gas mortgage indentures. In addition, beginning February 6, 2009, pursuant to the terms of the Washington Commission merger order, PSE may not declare or pay dividends if its 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. Also, 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, or if its credit ratings are below investment grade, PSE’s ratio of Earnings Before Interest, Tax, Depreciation and Amortization (“EBITDA”) to interest expense for the four most recently ended fiscal quarters prior to such date is equal to or greater than three to one. The common equity ratio, calculated on a regulatory basis, was 48.1% at September 30, 2015 and the EBITDA to interest expense was 4.5 to 1.0 for the 12 months then ended.

PSE’s ability to pay dividends is also limited by the terms of its credit facilities, pursuant to which PSE is not permitted to pay dividends during any Event of Default (as defined in the facilities), or if the payment of dividends would result in an Event of Default , such as failure to comply with certain financial covenants.

The Notes will be structurally subordinated to claims of creditors of PSE and our other subsidiaries.

The Notes will be structurally subordinated to indebtedness and other liabilities of PSE and our other subsidiaries. Any right that we have pursuant to our equity interest in PSE to receive any assets of PSE upon the liquidation or reorganization of PSE, and the consequent rights of holders of the Notes to realize proceeds from the sale of PSE’s assets, will effectively be subordinated to the claims of PSE’s creditors, including trade creditors. Accordingly, in the event of a bankruptcy, liquidation or reorganization of PSE, PSE will pay the holders of its indebtedness and its trade creditors before it will be able to distribute any of its assets to us on account of our equity interest in PSE. The security interest in the pledged stock of PSE will not alter the effective subordination of the Notes to the claims of creditors of PSE.

RISKS RELATING TO PSE’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 and the 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 the FERC with respect to the transmission of electric energy, the sale of electric energy at the wholesale level, 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.

 

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PSE’s recovery of costs is subject to regulatory review and its operating income may be adversely affected if its costs are disallowed.

The Washington Commission determines the rates PSE may charge to its electric retail customers based, in part, on historic test year costs plus normalized assumptions about rate year power costs, weather and hydrological conditions. 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 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 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 the aforementioned 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 PSE and its customers pursuant to a graduated scale, could result in significant increases in PSE’s expenses if power costs are significantly higher than the baseline rate.

PSE has a 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 hydrological 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. 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 PSE-owned and controlled power resources in the near future. 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 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 thus reducing 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.

PSE’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, 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:

 

•

Below normal energy generated by PSE-owned hydroelectric resources due to low streamflow conditions or precipitation;

 

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Extended outages of any of PSE-owned generating facilities or the transmission lines that deliver energy to load centers;

 

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Failure to perform on the part of any party from which PSE purchases capacity or energy; and

 

•

The effects of large-scale natural disasters 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, 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;

 

•

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 or safety related stoppages;

 

•

New laws or regulations that necessitate significant investments in PSE’s plants;

 

•

Future costs such as remediation that could necessitate significant expenditures but are presently unknown, not required by existing laws or regulations or are such that they are not estimable at this time;

 

•

Terrorist or other attacks (both cyber-based and/or asset-based); and

 

•

Catastrophic events such as fires, explosions, floods or acts of nature.

If PSE is unable to protect its physical assets from terrorist attacks or its information technology infrastructure and network against data corruption, cyber-based attacks or network security breaches, its operations could be disrupted.

Despite PSE’s implementation of security measures, its physical assets and technology systems may be vulnerable to disability, failures or unauthorized access due to hacking, viruses, acts of war or terrorism and other causes. If PSE’s technology systems were to fail or be breached and PSE was unable to recover in a timely manner, it may be unable to fulfill critical business functions and sensitive, confidential and other data could be compromised, which could have a material adverse effect on our results of operations, financial condition and cash flows. In addition, these physical asset- or cyber-based attacks could disrupt PSE’s ability to produce or distribute some portion of our energy products and could affect the reliability or operability of the electric and natural gas systems. As a result, PSE endeavors to maintain unceasing vigilance against the continuous threat of physical asset- and cyber-based attacks.

PSE is subject to the commodity price, delivery and credit risks associated with the energy markets, as well as to supply and price risks affecting PSE’s construction and maintenance programs.

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 takes into account the expected probability of default by counterparties, the actual exposure to a default by a particular counterparty could be greater than predicted.

 

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Further, as a consequence of its electric generation construction and reconstruction programs, and investments in its electric and gas distribution systems, PSE contracts to purchase substantial quantities of steel, cable, and similar materials, and thus is subject to supply and price risks affecting these items. 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.

Costs of compliance with environmental, climate change and endangered species laws are significant and the cost of compliance with new and emerging laws and regulations and the incurrence of associated liabilities could adversely affect PSE’s results of operations.

PSE’s operations are subject to extensive federal, state and local laws and regulations relating to environmental issues, including air emissions and climate change, endangered species protection, remediation of contamination, avian protection, waste handling and disposal, decommissioning, water protection and siting new facilities. To comply with these legal requirements, PSE must spend significant sums of money on measures including resource planning, remediation, monitoring, analysis, mitigation measures, pollution control equipment and emissions related abatement and fees. New environmental 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. Compliance with these or other future regulations could require significant 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 such expenditures through electric and natural gas rates at current levels in the future.

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. 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 standards and greenhouse gas legislation, including an emission performance standard provision. Recent decisions related to climate change by the United States Supreme Court and the Environmental Protection Agency, 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.

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 revenue, expenses and operating results. Demand for electricity is 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 PSE 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, repair and restart 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 effect on earnings as customers may be without electricity and natural gas for an extended period of time.

 

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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. Without a skilled workforce, PSE’s ability to provide quality service to PSE’s customers and to meet regulatory requirements could affect PSE’s 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, certain billing and metering processes, call center overflow and credit and collections. 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 the current interest rate environment, and, therefore, adverse market performance or low interest rates 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 2015 and beyond as well as the timing of the recovery of such contributions in general rate cases could impact PSE’s cash flow and liquidity.

Potential municipalization or technological developments may adversely affect PSE’s financial condition.

PSE may be adversely affected if it experiences a loss in the number of its customers due to municipalization or other related government action. When a town or city in PSE’s service territory establishes its own municipal-owned utility, it acquires PSE’s assets and takes over the delivery of energy services that PSE provides. Any such loss of customers and related revenue could negatively affect PSE’s financial condition. In addition, there is also the risk that advances in power generation, energy efficiency and other alternative energy technologies, such as solar generation, could lead to more wide-spread use of these technologies, thereby reducing customer demand for the energy supplied by PSE, which could negatively impact PSE’s revenue and financial condition.

RISKS RELATING TO OUR AND PSE’S BUSINESS

Puget Energy’s and PSE’s business is dependent on its ability to successfully access capital.

We rely, and PSE relies, on access to internally generated funds, bank borrowings through multi-year committed credit facilities and short-term money markets as sources of liquidity and longer-term debt markets to fund PSE’s utility construction program and other capital expenditure requirements of PSE. If we or PSE are unable to access capital on reasonable terms, our ability to pursue improvements or acquisitions, including generating capacity, which may be relied on for future growth and to otherwise implement our strategy, could be adversely affected. Capital and credit market disruptions, a downgrade of our or PSE’s credit rating or the imposition of restrictions on borrowings under our or PSE’s credit facilities in the event of a deterioration of financial ratios, may increase our and PSE’s cost of borrowing or adversely affect the ability to access one or more financial markets.

The amount of Puget Energy’s and PSE’s debt could adversely affect its liquidity and results of operations.

We and PSE have short-term and long-term debt, and may incur additional debt (including secured debt) in the future. We have access to a multi-year $800.0 million revolving credit facility, secured by substantially all of our

 

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assets, which has a maturity date of April 15, 2018. No amount was outstanding under the facility as of September 30, 2015. PSE also has two credit facilities, which provide PSE with access to $1.0 billion in short-term borrowing capability, and include an accordion feature that could, upon the banks’ approval, increase the size of the facilities to $1.45 billion. The two PSE credit facilities mature on April 15, 2019. As of September 30, 2015, no amounts were drawn and outstanding under the PSE credit facilities. In addition, we have issued $1.8 billion in senior secured notes, whereas PSE, as of September 30, 2015 had approximately $3.8 billion outstanding under first mortgage bonds, pollution control bonds, senior notes and junior subordinated notes. Our and PSE’s debt levels could have important effects on the business, including but not limited to:

 

•

Making it difficult to satisfy obligations under the debt agreements and increasing the risk of default on the debt obligations;

 

•

Making it difficult to fund non-debt service related operations of the business; and

 

•

Limiting our and PSE’s financial flexibility, including our ability to borrow additional funds on favorable terms or at all.

A downgrade in Puget Energy’s or PSE’s credit rating could negatively affect their ability to access capital and their ability to hedge in wholesale markets.

Although neither we nor PSE has any rating downgrade provisions in our or PSE’s credit facilities that would accelerate the maturity dates of outstanding debt, a downgrade in our or PSE’s credit ratings 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 each of our and PSE’s facilities, the borrowing spreads over the London Interbank Offered Rate (“LIBOR”) and commitment fees increase if 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 corporate credit rating could cause counterparties in the wholesale electric, wholesale natural gas and financial derivative markets to request 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.

We or PSE may be negatively affected by unfavorable changes in the tax laws or their interpretation.

Our and PSE’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. Changes in tax law, related regulations or differing interpretation or enforcement of applicable law by the IRS or other taxing jurisdiction could have a material adverse impact on our financial statements. The tax law, related regulations and case law are inherently complex. We 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 appeal or through litigation. These judgments may include reserves for potential adverse outcomes regarding tax positions that may be subject to challenge by the taxing authorities.

Potential legislation and regulatory actions could increase costs for us and PSE, reduce our and PSE’s revenue and cash flow, or otherwise alter the way we or PSE conduct business.

In July 2010, the Dodd-Frank Wall Street Reform and Consumer Protection Act (“Dodd-Frank”) was signed into law. Title VII of Dodd-Frank gave regulators including the Commodities Futures Trading Commission (“CFTC”) and the SEC the authority to create new oversight structures for derivative financial instruments, which were widely thought to have contributed to the 2008 financial crisis. The new legislation of certain over-the-counter swaps could expand collateral requirements of swaps, which may make it more costly for companies and/or limit our ability and the ability of PSE to enter into such transactions. Dodd-Frank amended section 2(h)(7) of the

 

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Commodities Exchange Act to provide an elective exemption from the clearing requirements of Title VII of Dodd-Frank for any entity that is not a financial entity, is using swaps to hedge or mitigate commercial risk, and notifies the CFTC, in a manner set forth by the CFTC, how it generally meets its financial obligations associated with entering into non-cleared swaps. We and PSE have elected to employ the “End-User Exception” to clearing on applicable treasury department transactions, and will likely employ he End-User Exception to clearing on commodities transactions after applicable final regulations for those transactions are adopted. We and PSE continue to evaluate the legislation and the CFTC’s implementation of it to determine its impact, if any, on our and PSE’s hedging program, results of operations and liquidity. We and PSE are aware that Dodd-Frank will increase recordkeeping and certain administrative costs for applicable transactions, but neither we nor PSE will know the full impact of the new legislation until the regulations are finalized.

RISKS RELATING TO THE NOTES

Proceeds from the Collateral may be inadequate to satisfy payments on the Notes.

The value of the Collateral will depend on market and economic conditions at the time, the availability of buyers and other factors beyond our control. The proceeds of any sale of the Collateral following a default by us may not be sufficient to satisfy the amounts due on the Notes. No appraisal of the fair market value of the Collateral has been prepared in connection with this offering, and the value of the interest of the holders of the Notes in the Collateral may not equal or exceed the principal amount of the Notes. The Collateral is by its nature illiquid, and therefore may not be able to be sold in a short period of time or at all.

In addition, the indenture and our senior secured credit facility permit us to incur additional debt secured equally and ratably by the Collateral. Therefore, the value of the Collateral may be inadequate to satisfy the amounts due under our secured indebtedness, including our senior secured credit facility, our existing senior secured notes, the Notes and any future indebtedness secured by the Collateral.

It may be difficult to realize the value of the Collateral securing the Notes.

The trustee’s ability to foreclose on the Collateral on behalf of the holders of the Notes may be subject to perfection, the consent of third parties, regulatory approvals, priority issues and other practical problems associated with the realization of the trustee’s security interest in the Collateral. We cannot assure holders of the Notes that any consents or approvals will be given if required and, therefore, the trustee may not have the ability to foreclose upon those assets or assume or transfer the right to those assets.

In addition, bankruptcy laws may limit the ability of the trustee to realize value from the Collateral. The right of the trustee to repossess and dispose of the Collateral upon the occurrence of an event of default under the indenture is likely to be significantly impaired by applicable bankruptcy law if a bankruptcy case were to be commenced by or against us. Under applicable bankruptcy law, secured creditors such as the holders of the Notes would be prohibited from foreclosing upon or disposing of a debtor’s property without prior bankruptcy court approval.

The indenture permits us to incur additional debt.

The indenture governing the Notes does not place any limitation on the amount of debt that may be incurred by us or PSE. We may therefore incur a significant amount of additional debt, including secured debt secured equally and ratably by the Collateral, as described under “Description of Notes—Security.” PSE may also incur additional debt, which could affect its ability to pay dividends to us. The incurrence of additional debt may have important consequences for holders of the Notes, including making it more difficult for us to satisfy our obligations with respect to the Notes, a loss in the trading value of the Notes, if any, and a risk that the credit rating of the Notes is lowered or withdrawn.

 

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We may incur additional indebtedness that may share in the liens on the Collateral securing the Notes, which will dilute the value of the Collateral.

The Collateral currently secures the senior secured credit facility and our existing senior secured notes. Under the terms of the indenture governing the Notes, we also will be permitted in the future to incur additional indebtedness and other obligations that may be secured by additional liens on the Collateral securing the Notes. Any additional obligations secured by a lien on the Collateral will dilute the value of the Collateral securing the Notes. See “Description of Notes—Security.”

The proceeds from the sale of all such Collateral may not be sufficient to satisfy the amounts outstanding under the Notes and all other indebtedness and obligations secured by such liens. If such proceeds were not sufficient to repay amounts outstanding under the Notes, then holders (to the extent not repaid from the proceeds of the sale of the Collateral) would only have an unsecured claim against our remaining assets, if any.

To the extent a security interest in any of the Collateral is created or perfected following the date of the issuance of the Notes, the security interest would remain at risk of being voided as a preferential transfer by a trustee in bankruptcy or being subject to the liens of intervening creditors.

The imposition of certain permitted liens could adversely affect the value of the Collateral.

The Collateral securing the Notes will be subject to liens permitted under the terms of the indenture governing the Notes, whether arising on or after the date the Notes are issued. The existence of any permitted liens could adversely affect the value of the Collateral securing the Notes as well as the ability of the collateral agent to realize or foreclose on such Collateral. The Collateral that will secure the Notes also secures our obligations under our senior secured credit facility and our existing senior secured notes and may also secure future indebtedness and other obligations of ours to the extent permitted by the indenture and the Security Documents. Your rights to the Collateral would be diluted by any increase in the indebtedness secured by this Collateral. To the extent we incur any permitted liens, the liens of holders may not be first priority.

You will have limited rights to enforce remedies under the Security Documents and the Collateral Agency Agreement, and the Collateral may be released without your consent in certain circumstances.

A collateral agent has been appointed by the holders of the liens on the Collateral, and such collateral agent (directly or through co-agents or sub-agents) is authorized to enforce all liens on the Collateral on behalf of the authorized representatives for the holders of the obligations secured by liens on the Collateral, including holders of Notes. Under the terms of the Security Documents, subject to certain exceptions, for so long as the senior secured credit facility remains outstanding, the collateral agent will pursue remedies and take other action related to the Collateral, including the release thereof, pursuant to the direction of the Credit Agreement Administrative Agent. Accordingly, during such time, the Credit Agreement Administrative Agent will have a right to control all remedies and the taking of other actions related to the Collateral, including the release thereof, without the consent of holders and the trustee under the indenture governing the Notes.

In addition, in the event the senior secured credit facility is no longer outstanding, the collateral agent will pursue remedies and take other action related to the Collateral, including the release thereof, pursuant to the direction of the authorized representative for the holders of the largest class of outstanding obligations secured by liens on the Collateral, which may or may not be the Notes. We will be permitted under the terms of the indenture to incur additional indebtedness secured on an equal basis with the Notes. As a result, the Notes may not ever represent the largest class of any remaining obligations secured by liens on the Collateral. Accordingly, holders may not ever have the right to control the remedies and the taking of other actions related to the Collateral.

In addition, all Collateral sold or otherwise disposed of in accordance with the terms of the documents governing the first lien obligations will automatically be released from the lien securing the Notes and the lien securing the

 

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other secured obligations. Accordingly, any such sale may result in a release of the Collateral subject to such sale or disposition.

Under the Collateral Agency Agreement, the authorized representative of the holders may not object following the filing of a bankruptcy petition to any debtor-in-possession financing or to the use of the shared Collateral to secure that financing, subject to conditions and limited exceptions.

After such a filing, the value of the Collateral could materially deteriorate, and holders would be unable to raise an objection.

The Notes will be secured only to the extent of the value of the assets that have been granted as security for the Notes and, as a result, there may not be sufficient Collateral to pay all or any of the Notes.

The Collateral has not been appraised in connection with this offering. The value of the Collateral and the amount that may be received upon a sale of the Collateral will depend upon many factors including, among others, the condition of the Collateral and of the electric transmission, distribution and generation and natural gas distribution industries, the ability to sell the Collateral in an orderly sale, the condition of the international, national and local economies, the availability of buyers and similar factors. By their nature, portions of the Collateral are illiquid and may have no readily ascertainable market value.

Additionally, applicable law requires that every aspect of any foreclosure or other disposition of Collateral be “commercially reasonable.” If a court were to determine that any aspect of the collateral agent’s exercise of remedies was not commercially reasonable, the ability of the trustee and you to recover the difference between the amount realized through such exercise of remedies and the amount owed on the Notes may be adversely affected and, in the worst case, you could lose all claims for such deficiency amount.

There are certain circumstances other than repayment or discharge of the Notes under which certain Collateral securing the Notes can be released without consent of the trustee or the holders.

Under certain circumstances, certain Collateral securing the Notes can be released without consent of the trustee or the holders, including:

 

•

upon a sale or other disposition of such Collateral in a transaction permitted under the indenture and the other credit documents, or

 

•

a release of less than a material portion of the Collateral, if consent to the release of all liens on such Collateral has been given by the required voting parties under the Collateral Agency Agreement, which do not include the trustee or holders of the Notes; however, release of a material portion or more of the Collateral will require unanimous consent of the voting parties under the Collateral Agency Agreement, which does include the trustee.

Any of these events will reduce the aggregate value of the Collateral securing the Notes.

We will in most cases have control over certain Collateral, and the sale of particular assets by us could reduce the pool of assets securing the Notes.

The Security Documents allow us to remain in possession of, retain exclusive control over, freely operate, and collect, invest and dispose of any income from, the Collateral securing the Notes (other than capital stock that has been pledged). So long as no default or event of default under the indenture would result therefrom, we may, among other things, without any release or consent by the collateral agent for the holders, conduct ordinary course activities with respect to Collateral (other than capital stock that has been pledged), such as selling, factoring, abandoning or otherwise disposing of Collateral and making ordinary course cash payments (including repayments of indebtedness). To the extent that additional indebtedness and obligations are secured by the Collateral, our control over the Collateral may be diminished.

 

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Your security interests in certain items of present and future Collateral may not be perfected. Even if your security interests in certain items of Collateral are perfected, it may not be practicable for you to enforce or economically benefit from your rights with respect to such security interests.

The security interests will not be perfected with respect to certain items of Collateral that cannot be perfected by the filing of financing statements or by “control” (as defined in the Uniform Commercial Code). Security interests in Collateral such as certain de minimis deposit accounts may not be perfected or may not have priority with respect to the security interests of other creditors. To the extent that the security interests in any items of Collateral are unperfected, the rights of holders with respect to such Collateral will be equal to the rights of our general unsecured creditors in the event of any bankruptcy filed by or against us under applicable U.S. federal bankruptcy laws.

There are certain categories of property that are excluded from the Collateral.

Certain categories of assets are excluded from the Collateral securing the Notes. Excluded assets include, among other categories, any lease, license, contract or agreement to which we are a party, and any rights or interest thereunder, if and to the extent that a security interest is prohibited by or in violation of any law or a term, provision or condition of any such lease, license, contract or agreement. The rights of holders with respect to such excluded property will be equal to the rights of our general unsecured creditors in the event of any bankruptcy filed by or against us under applicable U.S. federal bankruptcy laws.

Intervening creditors may have a perfected security interest in the Collateral.

The Collateral is subject to liens permitted under the terms of our senior secured credit facility and the indenture governing the Notes whether arising before, on or after the date the Notes are issued. There is a risk that there may be a creditor whose liens are permitted under our senior secured credit facility or the indenture governing the Notes, or an intervening creditor that has a perfected security interest in the Collateral securing the Notes. If there is such an intervening creditor, the lien of such creditor, whether or not permitted under our senior secured credit facility or the indenture governing the Notes, may be entitled to a higher priority than the liens securing the Notes. The existence of any liens securing obligations owed to intervening creditors, including liens permitted under the senior secured credit facility or the indenture governing the Notes and incurred or perfected prior to the liens securing the Notes, could adversely affect the value of the Collateral securing the Notes as well as the ability of the collateral agent to realize or foreclose on such Collateral.

The Collateral will also be subject to any and all exceptions, defects, encumbrances, liens and other imperfections as may be permitted by the senior secured credit facility or the indenture governing the Notes. The existence of any such exceptions, defects, encumbrances, liens and other imperfections could adversely affect the value of the Collateral that will secure the Notes, as well as the ability of the collateral agent to realize or foreclose on the Collateral for the benefit of holders.

Rights of holders in the Collateral may be adversely affected by the failure to perfect security interests in certain Collateral acquired in the future.

The security interest in the Collateral securing the Notes includes assets, both tangible and intangible, whether now owned or acquired or arising in the future. Applicable law requires that certain property and rights acquired after the grant of a general security interest can only be perfected at the time such property and rights are acquired and identified. There can be no assurance that the trustee or the collateral agent for the holders will monitor, or that we will inform the trustee or the collateral agent for the holders of, the future acquisition of property and rights that constitute Collateral, and that the necessary action will be taken to properly perfect the security interest in such after-acquired property. The trustee and the collateral agent for the holders have no obligation to monitor the acquisition of additional property or rights that constitute Collateral or the perfection of any security interest therein. Such failure may result in the loss of the security interest therein or the priority of the security interest in favor of the Notes against third parties.

 

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Rights of holders in the Collateral may be adversely affected by bankruptcy proceedings.

The right and ability of the collateral agent for the holders to repossess and dispose of the Collateral securing the Notes upon an event of default is likely to be significantly impaired by U.S. federal bankruptcy law if bankruptcy proceedings are commenced by or against us prior to, or possibly even after, the collateral agent has repossessed and disposed of the Collateral. Under the U.S. Bankruptcy Code, a secured creditor, such as the collateral agent for the holders, is prohibited from repossessing Collateral from a debtor in a bankruptcy case, or from disposing of Collateral repossessed from a debtor, without bankruptcy court approval. Moreover, bankruptcy law permits the debtor to continue to retain and to use Collateral, and the proceeds, products, rents or profits of the Collateral, even though the debtor is in default under the applicable debt instruments, provided that the secured creditor is given “adequate protection.” The meaning of the term “adequate protection” may vary according to circumstances, but it is intended in general to protect the value of the secured creditor’s interest in the Collateral and may include cash payments or the granting of additional security, if and at such time as the court in its discretion determines, for any diminution in the value of the Collateral as a result of the stay of repossession or disposition or any use of the Collateral by the debtor during the pendency of the bankruptcy case. In view of the broad discretionary powers of a bankruptcy court, it is impossible to predict how long payments under the Notes could be delayed following commencement of a bankruptcy case, whether or when the collateral agent could repossess or dispose of the Collateral, or whether or to what extent holders would be compensated for any delay in payment of loss of value of the Collateral through the requirements of “adequate protection.” Furthermore, in the event the bankruptcy court determines that the value of the Collateral is not sufficient to repay all amounts due on the Notes, holders would have “undersecured claims” as to the difference. U.S. federal bankruptcy laws do not permit the payment or accrual of interest, costs and attorneys’ fees for “undersecured claims” during the debtor’s bankruptcy case.

Any future pledge of Collateral might be voidable in bankruptcy.

Any future pledge of Collateral in favor of the collateral agent for the holders, including pursuant to security documents delivered after the date of the indenture governing the Notes, might be voidable by the pledgor (as debtor-in-possession) or by its trustee in bankruptcy if certain events or circumstances exist or occur, including, among others, if the pledgor is insolvent at the time of the pledge, the pledge permits holders to receive a greater recovery than if the pledge had not been given and a bankruptcy proceeding in respect of the pledgor is commenced within 90 days following the pledge, or, in certain circumstances, a longer period.

Federal and state fraudulent transfer laws may permit a court to void the Notes, subordinate claims in respect of the Notes and require holders to return payments received and, if that occurs, you may not receive any payments on the Notes.

Federal and state fraudulent transfer and conveyance statutes may apply to the issuance of the Notes. Under federal bankruptcy law and comparable provisions of state fraudulent transfer or conveyance laws, which may vary from state to state, the delivery of the Notes could be voided as a fraudulent transfer or conveyance if (a) we or our parent company, Puget Equico, as applicable, issued the Notes or granted securing interests on assets with the intent of hindering, delaying or defrauding creditors or (b) we or Puget Equico, as applicable, received less than reasonably equivalent value or fair consideration in return for either issuing the Notes or granting securing interests on assets and, in the case of (b) only, one of the following is also true at the time thereof:

 

•

we or Puget Equico, as applicable, were insolvent or rendered insolvent by reason of the issuance of the Notes;

 

•

the issuance of the Notes left us or Puget Equico with an unreasonably small amount of capital to carry on the business;

 

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we or Puget Equico intended to, or believed that we or Puget Equico would, incur debts beyond our or Puget Equico’s ability to pay such debts as they mature; or

 

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•

we or Puget Equico was a defendant in an action for money damages, or had a judgment for money damages docketed against us or Puget Equico, in either case, after final judgment, the judgment is unsatisfied.

A court would likely find that we or Puget Equico did not receive reasonably equivalent value or fair consideration for the Notes or granted securing interests on assets if we or Puget Equico did not substantially benefit directly or indirectly from the issuance of the Notes or the granting of security interests. As a general matter, value is given for a transfer or an obligation if, in exchange for the transfer or obligation, property is transferred or an antecedent debt is secured or satisfied. A debtor will generally not be considered to have received value in connection with a debt offering if the debtor uses the proceeds of that offering to make a dividend payment or otherwise to retire or redeem equity securities issued by the debtor.

We cannot be certain as to the standards a court would use to determine whether or not we or Puget Equico were solvent at the relevant time or, regardless of the standard that a court uses, that the granting of security interests would not be further subordinated to our or any of Puget Equico’s other debt. Generally, however, an entity would be considered insolvent if, at the time it incurred indebtedness:

 

•

the sum of its debts, including contingent liabilities, was greater than the fair saleable value of all its assets;

 

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the present fair saleable value of its assets was less than the amount that would be required to pay its probable liability on its existing debts, including contingent liabilities, as they become absolute and mature; or

 

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it could not pay its debts as they become due.

If a court were to find that the issuance of the Notes or granting or securing interests was a fraudulent transfer or conveyance, the court could void the payment obligation under the Notes or such securing interests, or further subordinate the Notes or such security interests to presently existing and future indebtedness of ours or Puget Equico, or require holders to repay any amounts received with respect to such security interests. In the event of a finding that a fraudulent conveyance occurred, you may not receive any repayment on the Notes. Further, the voidance of the Notes could result in an event of default with respect to our and our subsidiaries’ other debt that could result in acceleration of such debt.

The value of the Collateral may not be sufficient to secure post-petition interest.

In the event of a bankruptcy, liquidation, dissolution, reorganization or similar proceeding against us, holders will only be entitled to post-petition interest under the U.S. Bankruptcy Code to the extent that the value of their respective security interests in their Collateral is greater than their respective pre-bankruptcy claims. Holders may be deemed to have an unsecured claim to the extent that the fair market value of the Collateral securing the Notes, together with the other obligations secured by the same lien, is less than the face amount of all obligations secured by the same lien. In such case, holders will not be entitled to post-petition interest under the U.S. Bankruptcy Code. Upon a finding by a bankruptcy court that the Notes are under-collateralized, the claims in the bankruptcy proceeding with respect to the Notes would be bifurcated between a secured claim and an unsecured claim, and the unsecured claim would not be entitled to the benefits of security in the Collateral. Other consequences of a finding of under collateralization would be, among other things, a lack of entitlement on the part of the unsecured portion of the Notes to receive other “adequate protection” under the U.S. Bankruptcy Code. In addition, if any payments of post-petition interest had been made at the time of such a finding of under-collateralization, those payments could be recharacterized by the bankruptcy court as a reduction of the principal amount of the secured claim with respect to the Notes. No appraisal of the fair market value of the Collateral has been prepared in connection with the issuance of the Notes and, therefore, the value of the interests of holders in the Collateral may not equal or exceed the principal amount of the Notes and may not be sufficient to satisfy our obligations under all or any part of the Notes.

 

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In addition, under most circumstances, while you share equally and ratably with the other secured parties in all proceeds from any realization on the Collateral, subject to certain exceptions, you will not control the rights and remedies with respect to the Collateral upon an event of default and the exercise of any such rights and remedies following such an event of default will be made by the collateral agent, acting at the direction of the Credit Agreement Administrative Agent or the authorized representative of the largest outstanding debt secured by a pari passu lien on the Collateral.

We may not be able to repurchase the Notes upon a change in control or upon the exercise of the holders’ options to require repurchase of the Notes.

Upon the occurrence of specific types of change in control events, holders will have the right to require us to repurchase the Notes at a purchase price in cash equal to 101% of the principal amount of the Notes, plus accrued and unpaid interest, including additional interest, if any. In the event that we experience a change in control that results in a repurchase of the Notes or requires us to repurchase the Notes, we may not have sufficient financial resources to satisfy all of our obligations under the Notes. In addition, restrictions under our senior secured credit facility may not allow us to repurchase the Notes or otherwise refinance such indebtedness to satisfy our obligations.

An active trading market for the Notes may not develop.

There is currently no public market for the Notes and we do not currently plan to list the Notes on any national securities exchange. In addition, the liquidity of any trading market in the Notes, and the market price quoted for the Notes, may be adversely affected by changes in the overall market for such securities and by changes in our financial performance or prospects. A liquid trading market in the Notes may not develop.

The Notes have not been registered under the Securities Act or any state or foreign securities laws and until so registered, are subject to the restrictions on transfer and resale. We intend to use our reasonable best efforts to have this registration statement declared effective by the SEC. The SEC, however, has broad discretion to determine whether any registration statement will be declared effective and may delay or deny the effectiveness of any such registration statement filed by us for a variety of reasons. Failure to have this registration statement declared effective could adversely affect the liquidity and price of the Notes.

 

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PRIVATE PLACEMENT

We issued $400 million in principal amount of the original notes on May 12, 2015 to the initial purchasers of those notes and received proceeds that after deducting expenses and commissions represented an aggregate of approximately $396.7 million in net proceeds. We issued the original notes to the initial purchasers in transactions exempt from or not subject to registration under the Securities Act. The initial purchasers then offered and resold the original notes to qualified institutional buyers in compliance with Rule 144A or non-U.S. persons in compliance with Regulation S under the Securities Act.

 

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THE EXCHANGE OFFER

Purpose of the Exchange Offer

In connection with the sale of the original notes, we entered into a registration rights agreement with the initial purchasers of the original notes. In that agreement, we agreed to file a registration statement relating to an offer to exchange the original notes for the exchange notes. We also agreed to use our best efforts to have the SEC declare the registration statement effective 180 days after the issuance of the Notes. We are offering the exchange notes under this prospectus in an exchange offer for the original notes to satisfy our obligations under the registration rights agreement. We refer to our offer to exchange the exchange notes for the original notes as the “exchange offer.”

Resale of Exchange Notes

Based on interpretations of the SEC staff in no-action letters issued to third parties, we believe that each exchange note issued in the exchange offer may be offered for resale, resold and otherwise transferred by you without compliance with the registration and prospectus delivery requirements of the Securities Act if:

 

•

you are not our affiliate within the meaning of Rule 405 under the Securities Act;

 

•

you are acquiring such exchange notes in the ordinary course of your business;

 

•

you do not intend to participate in the distribution of exchange notes; and

 

•

you are not a broker-dealer and are not engaged in, and do not intend to engage in, the distribution of the exchange notes.

If you tender your original notes in the exchange offer with the intention of participating in any manner in a distribution of the exchange notes, you:

 

•

cannot rely on such interpretations of the SEC staff; and

 

•

must comply with the registration and prospectus delivery requirements of the Securities Act in connection with a secondary resale transaction of the exchange notes.

Unless an exemption from registration is otherwise available, the resale by any security holder intending to distribute exchange notes should be covered by an effective registration statement under the Securities Act containing the selling security holder’s information required under the Securities Act. This prospectus may be used for an offer to resell, a resale or other retransfer of exchange notes only as specifically described in this prospectus. Each broker-dealer that receives exchange notes for its own account in exchange for original notes, where that broker-dealer acquired such original notes as a result of market-making activities or other trading activities, must acknowledge that it will deliver a prospectus in connection with any resale of such exchange notes. Please read “Plan of Distribution” for more details regarding the transfer of exchange notes.

Terms of the Exchange Offer

Upon the terms and subject to the conditions described in this prospectus and in the letter of transmittal, we will accept for exchange any original notes properly tendered and not withdrawn prior to the expiration date of the exchange offer. We will issue $1,000 principal amount of exchange notes in exchange for each $1,000 principal amount of original notes surrendered under the exchange offer and accepted by us. Original notes may be tendered only in integral multiples of $1,000, subject to a $2,000 minimum, and untendered original notes may only be in a minimum denomination of $2,000 and integral

The terms of the exchange notes are identical in all material respects to those of the original notes, except the exchange notes will not be subject to transfer restrictions and holders of the exchange notes and with limited

 

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exceptions, will have no registration rights. Also, the exchange notes will not include provisions contained in the original notes that required payment of liquidated damages in the event we failed to satisfy our registration obligations with respect to the original notes. The exchange notes will be issued under and entitled to the benefits of the same indenture that authorized the issuance of the outstanding notes.

The exchange offer is not conditioned on any minimum aggregate principal amount of original notes being tendered for exchange.

As of the date of this prospectus, $400 million principal amount of original notes are outstanding. This prospectus and the letter of transmittal are being sent to all registered holders of the original notes. There will be no fixed record date for determining registered holders of the original notes entitled to participate in the exchange offer.

We intend to conduct the exchange offer in accordance with the provisions of the registration rights agreement, the applicable requirements of the Securities Act and the Securities Exchange Act of 1934, as amended, or the Exchange Act, and the SEC rules and regulations. Original notes that are not tendered for exchange in the exchange offer:

 

•

will remain outstanding,

 

•

will continue to accrue interest, and,

 

•

will be entitled to the rights and benefits that holders have under the indenture relating to the notes and, under limited circumstances, the registration rights agreement.

We will be deemed to have accepted for exchange properly tendered original notes when we have given oral or written notice of the acceptance to the exchange agent and complied with the applicable provisions of the registration rights agreement. The exchange agent will act as agent for the tendering holders for the purposes of receiving the exchange notes from us. We will issue the exchange notes promptly after the expiration of the exchange offer.

If you tender original notes in the exchange offer, you will not be required to pay brokerage commissions or fees or, subject to the instructions in the letter of transmittal, transfer taxes with respect to the exchange of original notes. We will pay all charges and expenses, other than certain applicable taxes described below, in connection with the exchange offer. It is important that you read “The Exchange Offer—Fees and Expenses” for more details about fees and expenses incurred in the exchange offer.

We will return any original notes that we do not accept for exchange for any reason without expense to the tendering holder promptly after the expiration or termination of the exchange offer.

Expiration Date

The exchange offer will expire at 5:00 p.m., New York City time, on December 24, 2015, unless at our sole discretion we extend the offer.

Extensions, Delay in Acceptance, Termination or Amendment

We expressly reserve the right, at any time or at various times, to extend the period of time during which the exchange offer is open. In the event of an extension of the exchange offer, we may delay acceptance for exchange of any original notes by giving oral or written notice of the extension to their holders. During any such extensions, all original notes you have previously tendered will remain subject to the exchange offer for that series, and we may accept them for exchange.

 

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To extend the exchange offer, we will notify the exchange agent orally or in writing (if oral, to be promptly confirmed in writing) of any extension. We also will make a public announcement of the extension no later than 9:00 a.m., New York City time, on the next business day after the previously scheduled expiration date.

If any of the conditions described below under “The Exchange Offer—Conditions to the Exchange Offer” have not been satisfied with respect to the exchange offer, we reserve the right, at our sole discretion:

 

•

to extend the exchange offer,

 

•

to delay accepting for exchange any original notes, or

 

•

to terminate the exchange offer.

We will give oral or written notice (if oral, to be promptly confirmed in writing) of such extension, delay or termination to the exchange agent. Subject to the terms of the registration rights agreement, we also reserve the right to amend the terms of the exchange offer in any manner.

Any such extension, delay in acceptance, termination or amendment will be followed as promptly as practicable by oral or written notice thereof to the registered holders of the original notes. If we amend the exchange offer in a manner that we determine to constitute a material change, including the waiver of a material condition, we will promptly disclose that amendment by means of a prospectus supplement and we will extend the offer period if necessary so that at least five business days remain in the offer period following notice of the material change. We will distribute the supplement to the registered holders of the original notes. Depending on the significance of the amendment and the manner of disclosure to the registered holders, we may extend, pursuant to the terms of the registration rights agreement and the requirements of federal securities law, the exchange offer if the exchange offer would otherwise expire during such period.

Without limiting the manner in which we may choose to make public announcements of any extension, delay in acceptance, termination or amendment of the exchange offer, we have no obligation to publish, advertise or otherwise communicate any such public announcement, other than by making a timely release to an appropriate news agency.

Conditions to the Exchange Offer

Notwithstanding any other provision of the exchange offer and subject to the terms of the registration rights agreement, we will not be required to accept for exchange, or to issue exchange notes in exchange for, any original notes and may terminate or amend the exchange offer, if at any time before the expiration date of the exchange offer there is a question as to whether the exchange offer is permitted by applicable law.

In addition, we will not be obligated to accept for exchange the original notes of any holder that has not made to us:

 

•

the representations described under “The Exchange Offer—Procedures for Tendering” and “Plan of Distribution,” and

 

•

such other representations as may be reasonably necessary under applicable SEC rules, regulations or interpretations to make available to us an appropriate form for registering the exchange notes under the Securities Act.

We expressly reserve the right to amend or terminate the exchange offer notwithstanding the satisfaction of the foregoing, and to reject for exchange any original notes upon the occurrence of any of the conditions to the exchange offer specified above. We will give oral or written notice of any extension, non-acceptance, termination or amendment to the holders of the original notes as promptly as practicable.

 

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These conditions are for our sole benefit, and we may assert them or waive them in whole or in part at any time or at various times at our sole discretion. Our failure at any time to exercise any of these rights will not mean that we have waived our rights. Each right will be deemed an ongoing right that we may assert at any time or at various times. If we waive a condition, we may be required in order to comply with applicable securities laws, to extend the expiration date of the exchange offer.

In addition, we will not accept for exchange any original notes tendered, and will not issue exchange notes in exchange for any such original notes, if at such time any stop order has been threatened or is in effect with respect to the registration statement of which this prospectus constitutes a part or the qualification of the indenture relating to the notes under the Trust Indenture Act of 1939.

Procedures for Tendering

How to Tender Generally

Only a holder of the original notes as determined by our records or those of the Trustee or DTC may tender original notes in the exchange offer. To tender in the exchange offer, a holder must either (1) comply with the procedures for physical tender or (2) comply with the automated tender offer program procedures of DTC, described below.

To complete a physical tender, a holder must:

 

•

complete, sign and date the letter of transmittal or a facsimile of the letter of transmittal,

 

•

have the signature on the letter of transmittal guaranteed if the letter of transmittal so requires,

 

•

mail or deliver the letter of transmittal or facsimile to the exchange agent prior to the expiration date, and

 

•

deliver the original notes to the exchange agent prior to the expiration date or comply with the guaranteed delivery procedures described below.

To be tendered effectively, the exchange agent must receive any physical delivery of the letter of transmittal and other required documents at its address provided above under “Prospectus Summary—The Exchange Agent” prior to the expiration date.

To complete a tender through DTC’s automated tender offer program, the exchange agent must receive, prior to the expiration date, a timely confirmation of book-entry transfer of such original notes into the exchange agent’s account at DTC according to the procedure for book-entry transfer described below or a properly transmitted agent’s message.

The tender by a holder that is not withdrawn prior to the expiration date and our acceptance of that tender will constitute an agreement between the holder and us in accordance with the terms and subject to the conditions described in this prospectus and in the letter of transmittal.

THE METHOD OF DELIVERY OF ORIGINAL NOTES, THE LETTER OF TRANSMITTAL AND ALL OTHER REQUIRED DOCUMENTS TO THE EXCHANGE AGENT IS AT YOUR ELECTION AND RISK. RATHER THAN MAIL THESE ITEMS, WE RECOMMEND THAT YOU USE AN OVERNIGHT OR HAND DELIVERY SERVICE. IN ALL CASES, YOU SHOULD ALLOW SUFFICIENT TIME TO ENSURE DELIVERY TO THE EXCHANGE AGENT BEFORE THE EXPIRATION DATE. YOU SHOULD NOT SEND THE LETTER OF TRANSMITTAL OR ORIGINAL NOTES TO US. YOU MAY REQUEST YOUR BROKER, DEALER, COMMERCIAL BANK, TRUST COMPANY OR OTHER NOMINEE TO EFFECT THE ABOVE TRANSACTIONS FOR YOU.

 

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How to Tender if You Are a Beneficial Owner

If you beneficially own original notes that are registered in the name of a broker, dealer, commercial bank, trust company or other nominee and you wish to tender those notes, you should contact the registered holder as soon as possible and instruct the registered holder to tender on your behalf. If you are a beneficial owner and wish to tender on your own behalf, you must, prior to completing and executing the letter of transmittal and delivering your original notes, either:

 

•

make appropriate arrangements to register ownership of the original notes in your name, or

 

•

obtain a properly completed bond power from the registered holder of your original notes.

The transfer of registered ownership may take considerable time and may not be completed prior to the expiration date.

Signatures and Signature Guarantees

You must have signatures on a letter of transmittal or a notice of withdrawal described below under “The Exchange Offer—Withdrawal of Tenders” guaranteed by an eligible institution unless the original notes are tendered:

 

•

by a registered holder who has not completed the box entitled “Special Issuance Instructions” or “Special Delivery Instructions” on the letter of transmittal, or

 

•

for the account of an eligible institution.

An “eligible institution” is a member firm of a registered national securities exchange, a commercial bank or trust company having an office or correspondent in the United States, or an eligible guarantor institution within the meaning of Rule 17Ad-15 under the Exchange Act, that is a member of one of the recognized signature guarantee programs identified in the letter of transmittal.

When Endorsements or Bond Powers Are Needed

If a person other than the registered holder of any original notes signs the letter of transmittal, the original notes must be endorsed or accompanied by a properly completed bond power. The registered holder must sign the bond power as the registered holder’s name appears on the original notes. An eligible institution must guarantee that signature.

If the letter of transmittal or any original notes or bond powers are signed by trustees, executors, administrators, guardians, attorneys-in-fact, or officers of corporations or others acting in a fiduciary or representative capacity, those persons should so indicate when signing. Unless we waive this requirement, they also must submit evidence satisfactory to us of their authority to deliver the letter of transmittal.

Tendering Through DTC’s Automated Tender Offer Program

The exchange agent and DTC have confirmed that any financial institution that is a participant in DTC’s system may use DTC’s automated tender offer program to tender. Accordingly, participants in the program may, instead of physically completing and signing the letter of transmittal and delivering it to the exchange agent, transmit their acceptance of the exchange offer electronically. They may do so by causing DTC to transfer the original notes to the exchange agent in accordance with its procedures for transfer. DTC will then send an agent’s message to the exchange agent.

 

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An agent’s message is a message transmitted by DTC to and received by the exchange agent and forming part of the book-entry confirmation, stating that:

 

•

DTC has received an express acknowledgment from a participant in DTC’s automated tender offer program that is tendering original notes that are the subject of such book-entry confirmation;

 

•

the participant has received and agrees to be bound by the terms of the letter of transmittal, or, in the case of an agent’s message relating to guaranteed delivery, the participant has received and agrees to be bound by the applicable notice of guaranteed delivery; and

 

•

we may enforce the agreement against such participant.

Determinations Under the Exchange Offer

We will determine at our sole discretion all questions as to the validity, form, eligibility, time of receipt, acceptance of tendered original notes and withdrawal of tendered original notes. Our determination will be final and binding. We reserve the absolute right to reject any original notes not properly tendered or any original notes our acceptance of which, in the opinion of our counsel, might be unlawful. Our interpretation of the terms and conditions of the exchange offer, including the instructions in the letter of transmittal, will be final and binding on all parties.

Unless waived, any defects or irregularities in connection with tenders of original notes must be cured within such time as we determine. Neither we, the exchange agent nor any other person will be under any duty to give notification of defects or irregularities with respect to tenders of original notes, nor will we or those persons incur any liability for failure to give such notification. Tenders of original notes will not be deemed made until such defects or irregularities have been cured or waived. Any original notes received by the exchange agent that are not properly tendered and as to which the defects or irregularities have not been cured or waived will be returned to the tendering holder, unless otherwise provided in the letter of transmittal, promptly following the expiration date.

When We Will Issue Exchange Notes

In all cases, we will issue exchange notes for original notes that we have accepted for exchange in the exchange offer only after the exchange agent timely receives:

 

•

original notes or a timely book-entry confirmation of transfer of such original notes into the exchange agent’s account at DTC, and

 

•

a properly completed and duly executed letter of transmittal and all other required documents or a properly transmitted agent’s message.

Return of Original Notes Not Accepted or Exchanged

If we do not accept any tendered original notes for exchange for any reason described in the terms and conditions of the exchange offer or if original notes are submitted for a greater principal amount than the holder desires to exchange, we will return the unaccepted or non-exchanged original notes without expense to their tendering holder. In the case of original notes tendered by book-entry transfer into the exchange agent’s account at DTC according to the procedures described below, such non-exchanged original notes will be credited to an account maintained with DTC. These actions will occur promptly after the expiration or termination of the exchange offer.

 

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Your Representations to Us

By signing or agreeing to be bound by the letter of transmittal, you will represent to us that, among other things:

 

•

you are acquiring the exchange notes in the ordinary course of your business;

 

•

you are not engaged in, and do not intend to engage in, and you have no arrangement or understanding with any person to participate in, the distribution of the original notes or the exchange notes within the meaning of the Securities Act;

 

•

you are not our affiliate, as defined in Rule 405 under the Securities Act;

 

•

if you are not a broker-dealer, you are not engaged in and do not intend to engage in the distribution of the exchange notes; and

 

•

if you are a broker-dealer or you are using the exchange offer to participate in the distribution of exchange notes, you agree and acknowledge that you could not under Commission policy, rely on certain no-action letters, and you must comply with the registration and prospectus delivery requirements in connection with a secondary resale transaction.

Book-Entry Transfer

The exchange agent will make a request to establish an account with respect to the original notes at DTC for purposes of the exchange offer promptly after the date of this prospectus. Any financial institution participating in DTC’s system may make book-entry delivery of original notes by causing DTC to transfer such original notes into the exchange agent’s account at DTC in accordance with DTC’s procedures for transfer. If you are unable to deliver confirmation of the book-entry tender of your original notes into the exchange agent’s account at DTC or all other documents required by the letter of transmittal to the exchange agent on or prior to the expiration date, you must tender your original notes according to the guaranteed delivery procedures described below.

Guaranteed Delivery Procedures

If you wish to tender your original notes but they are not immediately available or if you cannot deliver your original notes, the letter of transmittal or any other required documents to the exchange agent, or comply with the applicable procedures under DTC’s automated tender offer program prior to the expiration date, you may tender if:

 

•

the tender is made through a member firm of a registered national securities exchange, a commercial bank or trust company having an office or correspondent in the United States, or an eligible guarantor institution;

 

•

prior to the expiration date, the exchange agent receives from such member firm of a registered national securities exchange, commercial bank or trust company having an office or correspondent in the United States, or eligible guarantor institution either a properly completed and duly executed notice of guaranteed delivery by facsimile transmission, mail or hand delivery or a properly transmitted agent’s message and notice of guaranteed delivery:

 

•

stating your name and address, the registered number(s) of your original notes and the principal amount of original notes tendered,

 

•

stating that the tender is being made thereby, and

 

•

guaranteeing that, within three New York Stock Exchange trading days after the expiration date, the letter of transmittal or facsimile thereof or agent’s message in lieu thereof, together with the original notes or a book-entry confirmation, and any other documents required by the letter of transmittal will be deposited by the eligible guarantor institution with the exchange agent; and

 

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•

the exchange agent receives such properly completed and executed letter of transmittal or facsimile or agent’s message, as well as all tendered original notes in proper form for transfer or a book-entry confirmation, and all other documents required by the letter of transmittal, within three New York Stock Exchange trading days after the expiration date.

Upon request to the exchange agent, the exchange agent will send a notice of guaranteed delivery to you if you wish to tender your original notes according to the guaranteed delivery procedures described above.

Withdrawal of Tenders

Except as otherwise provided in this prospectus, you may withdraw your tender at any time prior to 5:00 p.m., New York City time, on the expiration date.

For a withdrawal to be effective:

 

•

the exchange agent must receive a written notice of withdrawal at one of the addresses listed above under “Prospectus Summary—The Exchange Agent,” and

 

•

the withdrawing holder must comply with the appropriate procedures of DTC’s automated tender offer program.

Any notice of withdrawal must:

 

•

specify the name of the person who tendered the original notes to be withdrawn,

 

•

identify the original notes to be withdrawn, including the registration number or numbers and the principal amount of such original notes,

 

•

be signed by the person who tendered the original notes in the same manner as the original signature on the letter of transmittal used to deposit those original notes or be accompanied by documents of transfer sufficient to permit the trustee to register the transfer in the name of the person withdrawing the tender, and

 

•

specify the name in which such original notes are to be registered, if different from that of the person who tendered the original notes.

If original notes have been tendered under the procedure for book-entry transfer described above, any notice of withdrawal must specify the name and number of the account at DTC to be credited with the withdrawn original notes and otherwise comply with the procedures of DTC.

We will determine all questions as to the validity, form, eligibility and time of receipt of notice of withdrawal, and our determination shall be final and binding on all parties. We will deem any original notes so withdrawn not to have been validly tendered for exchange for purposes of the exchange offer.

Any original notes that have been tendered for exchange but that are not exchanged for any reason will be returned to their holder without cost to the holder, or, in the case of original notes tendered by book-entry transfer into the exchange agent’s account at DTC according to the procedures described above, such original notes will be credited to an account maintained with DTC for the original notes. This return or crediting will take place promptly after withdrawal, rejection of tender or termination of the exchange offer. You may retender properly withdrawn original notes by following one of the procedures described under “The Exchange Offer—Procedures for Tendering” at any time on or prior to 5:00 p.m., New York City time, on the expiration date.

 

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Fees and Expenses

We will bear the expenses of soliciting tenders. The principal solicitation is being made by mail; however, we may make additional solicitation by facsimile, email, telephone or in person by our officers and regular employees and those of our affiliates.

We have not retained any dealer-manager in connection with the exchange offer and will not make any payments to broker-dealers or others soliciting acceptances of the exchange offer. We will, however, pay the exchange agent reasonable and customary fees for its services and reimburse it for its related reasonable out-of-pocket expenses. We may also pay brokerage houses and other custodians, nominees and fiduciaries the reasonable out-of-pocket expenses incurred by them in forwarding copies of this prospectus, letters of transmittal and related documents to the beneficial owners of the original notes and in handling or forwarding tenders for exchange.

We will pay the cash expenses to be incurred in connection with the exchange offer. They include:

 

•

SEC registration fees for the exchange notes,

 

•

fees and expenses of the exchange agent and the trustee,

 

•

accounting and legal fees,

 

•

printing costs, and

 

•

related fees and expenses.

Transfer Taxes

If you tender your original notes for exchange, you will not be required to pay any transfer taxes. We will pay all transfer taxes, if any, applicable to the exchange of original notes in the exchange offer. The tendering holder will, however, be required to pay any transfer taxes, whether imposed on the registered holder or any other person, if:

 

•

certificates representing exchange notes or original notes for principal amounts not tendered or accepted for exchange are to be delivered to, or are to be issued in the name of, any person other than the registered holder of the original notes tendered,

 

•

tendered original notes are registered in the name of any person other than the person signing the letter of transmittal, or

 

•

a transfer tax is imposed for any reason other than the exchange of original notes for exchange notes in the exchange offer.

If satisfactory evidence of payment of any transfer taxes payable by a tendering holder is not submitted with the letter of transmittal, the amount of the transfer taxes will be billed directly to that tendering holder. The exchange agent will retain possession of exchange notes with a face amount equal to the amount of the transfer taxes due until it receives payment of the taxes.

Accounting Treatment

We will record the exchange notes at the same carrying value as the original notes as reflected in our accounting records on the date of the exchange. Accordingly, we will not recognize any gain or loss for accounting purposes upon completion of the exchange offer.

Consequences of Failure to Exchange

If you do not exchange your original notes for exchange notes in the exchange offer, you will remain subject to the existing restrictions on transfer of the original notes. In general, you may not offer or sell the original notes

 

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unless either they are registered under the Securities Act or the offer or sale is exempt from or not subject to registration under the Securities Act and applicable state securities laws. Except as required by the registration rights agreement, we do not intend to register resales of the original notes under the Securities Act. We have no obligation to re-offer to exchange the exchange notes for original notes following the expiration of the exchange offer.

The tender of original notes in the exchange offer will reduce the outstanding principal amount of the original notes. Due to the corresponding reduction in liquidity, this may have an adverse effect on, and increase the volatility of, the market price of any original notes that you continue to hold.

Other

Participation in the exchange offer is voluntary, and you should carefully consider whether to accept. You are urged to consult your financial and tax advisors in making your decision on what action to take. In the future, we may at our discretion seek to acquire untendered original notes in open market or privately negotiated transactions, through subsequent exchange offers or otherwise. We have no present plan to acquire any original notes that are not tendered in the exchange offer or to file a registration statement to permit resales of any untendered original notes, except as required by the registration rights agreement.

USE OF PROCEEDS

We are making the exchange offer to satisfy our obligations under the original notes, the indenture and the registration rights agreement. We will not receive any cash proceeds from the exchange offer. In consideration of issuing the exchange notes in the exchange offer, we will receive an equal principal amount of original notes. Any original notes that are properly tendered and accepted in the exchange offer will be canceled.

 

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CAPITALIZATION

The following table presents our consolidated cash and cash equivalents and capitalization as of September 30, 2015. This table should be read in conjunction with the information contained in “Use of Proceeds” and our consolidated financial statements and related notes included elsewhere in this prospectus.

 

		As of September 30, 2015
		As Adjusted
		(in millions)
Cash and equivalents		$	20.2
Short-term debt			79.5
PSE long-term debt			3,774.4
Puget Energy long-term debt(1)
Senior secured credit facility			—
Existing senior secured notes			1,400.0
3.650% senior secured notes due 2025			400.0
Equity			3,486.9
Total Capitalization(2)		$	9,161.0

 

(1)	Excludes fair value accounting treatment from our financial statements where our long-term debt, comprised of our senior secured credit facility, is valued at $1.589 billion at September 30, 2015.

(2)	Differs from 10-Q balance sheet due to $(210.1) million merger related fair value adjustment.

 

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SELECTED FINANCIAL INFORMATION

The following tables show selected financial data. This information should be read in conjunction with the Management’s Discussion and Analysis and the audited consolidated financial statements and the related notes incorporated herein by reference.

 

Puget Energy Summary of Operations (Dollars in thousands)		Fiscal Year Ended December 31,
		2014				2013				2012				2011				2010
Operating revenue		$	3,113,171			$	3,187,297			$	3,215,156			$	3,318,765			$	3,122,217
Operating income			577,851				755,160				715,535				474,940				308,234
Income from continuing operations			171,835				285,728				273,821				123,290				30,311
Net income			171,835				285,728				273,821				123,290				30,311
Basic earnings per common share from continuing operations			N/A				N/A				N/A				N/A				N/A
Basic earnings per common share			N/A				N/A				N/A				N/A				N/A
Diluted earnings per common share from continuing operations			N/A				N/A				N/A				N/A				N/A
Diluted earnings per common share			N/A				N/A				N/A				N/A				N/A
Dividends per common share			N/A				N/A				N/A				N/A				N/A
Book value per common share			N/A				N/A				N/A				N/A				N/A
Total assets at year end			12,835,048				12,906,575				12,835,275				12,407,306				11,929,336
Long-term debt			4,831,608				4,982,476				5,083,200				5,027,367				4,132,713
Preferred stock subject to mandatory redemption			—				—				—				—				—
Junior subordinated notes			250,000				250,000				250,000				250,000				250,000
Capital lease obligations			9,473				17,051				24,629				32,207				42,603

 

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MANAGEMENT’S DISCUSSION AND ANALYSIS

The following discussion and analysis should be read in conjunction with the financial statements and related notes thereto included elsewhere in this prospectus. The discussion contains forward-looking statements that involve risks and uncertainties, such as Puget Energy’s and PSE’s objectives, expectations and intentions. Words or phrases such as “anticipates,” “believes,” “continues,” “could,” “estimates,” “expects,” “future,” “intends,” “may,” “might,” “plans,” “potential,” “predicts,” “projects,” “should,” “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 prospectus. Except as required by law, neither Puget Energy nor PSE undertakes any 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 (SEC) 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 is an energy services holding company and all of its operations are conducted through its subsidiary PSE, a regulated electric and natural gas utility company. PSE is the largest electric and natural gas utility in the state of Washington, primarily engaged in the business of electric transmission, distribution and 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. Puget Holdings is owned by a consortium of long-term infrastructure investors including Macquarie Infrastructure Partners I, Macquarie Infrastructure Partners II, Macquarie Capital Group Limited, FSS Infrastructure Trust, the Canada Pension Plan Investment Board, the British Columbia Investment Management Corporation, and the Alberta Investment Management Corporation. All of Puget Energy’s common stock is indirectly owned by Puget Holdings. Puget Energy and PSE are collectively referred to herein as “the Company.”

The Company’s mission is to be a safe, dependable, and efficient utility. The Company’s objectives are to focus on safety, employee engagement, operational excellence, customer service and financial strength. The Company’s strategies are aligned to achieve these objectives and ultimately the Company’s mission.

These strategies involve numerous commitments and investments related to utility infrastructure and customer service which may give rise to expenditures that may not be recovered timely through the ratemaking process. PSE has undertaken several initiatives to reduce the volatility and regulatory lag in the business. During 2013, PSE completed an expedited rate filing (“ERF”), which is a limited scope rate proceeding, and established a decoupling mechanism for gas operations and electric transmission, distribution and administrative costs. The ERF proceeding established baseline rates on which the decoupling mechanism will operate going forward. The ERF also established a property tax tracker mechanism in which any difference between amounts in rates and property tax payments will be deferred and recovered in an annual filing based on the annual cash payments for the year.

The decoupling mechanism allows PSE to recover costs on a per customer basis rather than on a consumption basis. Included in the decoupling petition was a rate plan that allows PSE an opportunity to earn its authorized rate of return without the need for another general rate case (“GRC”) process during the rate plan period. The rate

 

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plan included predetermined annual increases to PSE’s allowed electric and natural gas revenue. This plan, with limited exceptions (i.e., power cost only rate cases (“PCORC”) or emergency rate relief), requires PSE to file a GRC no sooner than April 1, 2015 and no later than April 1, 2016. The decoupling mechanism also allows for decoupling revenue on a per customer basis to subsequently increase by 3.0% for electric customers and 2.2% for natural gas customers on January 1 of each year, until the conclusion of PSE’s next GRC. In addition, the decoupling mechanism reduces earnings volatility but does not materially affect the timing of cash flow due to the timing difference between the recognition of decoupling revenue and resulting impacts on rates.

Washington state law also requires PSE to pursue conservation initiatives that promote efficient use of energy. PSE’s mandate to pursue conservation initiatives may have a negative impact on the electric business financial performance due to lost margins from lower sales volumes as power costs are not part of the decoupling mechanism. This mandate, however, will only have a slight negative impact on natural gas business financial performance due to the natural gas business being almost fully decoupled.

PSE generates revenue and cash flow primarily from the sale of electric and natural gas services 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. PSE continually balances its load requirements and generation resources to meet customer demand. The Company’s external financing requirements principally reflect the cash needs of its construction program, its schedule of maturing debt and certain operational needs. PSE requires access to bank and capital markets to meet its financing needs.

For the three and nine months ended September 30, 2015, as compared to the same periods in 2014, PSE’s net income was affected primarily by the following factors: (1) a decrease in electric margin due to higher purchased electricity costs and lower decoupling and miscellaneous revenues; (2) a decrease in natural gas margin due to lower residential therm sales due to warmer weather; and (3) changes in unrealized (gain) loss on derivative instruments.

Factors and Trends Affecting PSE’s Performance

The principal business, economic and other factors that affect PSE’s operations and financial performance include the following:

 

•

The rates PSE is allowed to charge for its services;

 

•

PSE’s ability to recover power costs that are included in rates which are based on volume;

 

•

PSE’s ability to manage costs during the rate stay out period through March 31, 2016;

 

•

Weather conditions, including snow-pack affecting hydrological conditions;

 

•

Regulatory decisions allowing PSE to recover 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;

 

•

Equal sharing between PSE and its customers of earnings which exceed PSE’s authorized rate of return;

 

•

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, state and local environmental laws and regulations;

 

•

Wholesale commodity prices of electricity and natural gas;

 

•

Increasing depreciation;

 

•

Bonus depreciation and the impact on rate base;

 

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•

General economic conditions in PSE’s service territory and its effects on customer growth and use-per-customer;

 

•

Conservation investments by customers; and

 

•

Federal, state, and local taxes.

Further detail regarding the factors and trends affecting performance of the Company during the fiscal quarter ended September 30, 2015 is set forth below in this “Overview” section as well as in other sections of the Management’s Discussion & Analysis.

Regulation of PSE Rates and Recovery of PSE Costs

PSE’s regulatory requirements and operational needs require the investment of substantial capital in 2015 and future years. Because PSE intends to seek recovery of these investments through the regulatory process, its financial results depend heavily upon favorable outcomes from that process. The rates that PSE is allowed to charge for its services influence its financial condition, results of operations and liquidity. PSE is highly regulated and the rates that it charges its retail customers are approved by the Washington Utilities and Transportation Commission (“Washington Commission”). The Washington Commission has traditionally required that these rates be determined based, to a large extent, on historic test year costs plus weather normalized assumptions about hydroelectric conditions and power costs in the relevant rate year. Incremental customer growth and sales typically have not provided sufficient revenue to cover year-to-year cost growth, thus rate increases are required. If, in a particular year, PSE’s costs are higher than what is currently allowed to be recovered in rates, revenue may not be sufficient to permit PSE to earn its allowed return. 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 applied, those costs may be disallowed partially or entirely and not recovered in rates.

Power Cost Only Rate Case. 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 has used an expedited six-month PCORC decision timeline rather than the statutory 11-month timeline for a GRC.

On November 3, 2014 the Washington Commission issued an order on the settlement of the PCORC which PSE filed on May 23, 2014. The original filing proposed a decrease of $9.6 million (or an average of approximately 0.5%) in the Company’s overall power supply costs. PSE filed joint testimony supporting a settlement stipulation. Customer rates decreased by approximately $19.4 million, or 0.9%, annually, as a result of the settlement effective December 1, 2014.

Expedited Rate Filing. On February 4, 2013, PSE filed revised tariffs seeking to update its rates established in its base rate proceedings in May 2012. This filing was limited in scope and rate impact. This filing was primarily intended to establish baseline rates on which the decoupling mechanisms, described below, are proposed to operate. The filing also provided for the collection of property taxes through a property tax tracker mechanism based on cash payments of property tax made by PSE during the year. Any difference between the cash payments and property tax accruals will be deferred and recovered in a property tax tracker.

Decoupling. On October 25, 2012, PSE and the Northwest Energy Coalition (“NWEC”) filed a petition for an order seeking approval of an electric and a natural gas decoupling mechanism for the recovery of PSE’s delivery-system costs and authority to record accounting entries associated with the mechanisms. Included in the amended decoupling petition was a rate plan that allows PSE an opportunity to earn its authorized rate of return without the need for another GRC process over the plan period. The rate plan includes predetermined annual increases

 

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(escalating factors referred to as the K-Factor) to PSE’s allowed electric and gas delivery revenue (transmission and distribution), which are effective January 1 of each year, currently 3.0% for electric and 2.2% for natural gas. Under this plan, PSE, with limited exceptions, would be allowed to file its next GRC no sooner than April 1, 2015 and no later than April 1, 2016 unless agreed to otherwise by the parties. PSE would continue to be authorized to file for rate changes under existing rate mechanisms such as the power cost adjustment (“PCA”) mechanism, the purchased gas adjustment (“PGA”) mechanism, and emergency rate relief during the rate plan period.

PSE’s rates related to the cumulative deferred decoupling mechanism accrued by each rate group through the calendar year and effective May 1 in the following year will be subject to a 3.0% cap on rate increases. Any amount in excess of the cap will be added to the decoupling tracker in subsequent rate periods, subject to a 3.0% cap on rate increases in the subsequent year. In addition, PSE and its customers would share 50.0% each in any earnings in excess of the authorized rate of return of 7.77%. The customers’ share of any earnings would be returned to customers over the subsequent 12-month period beginning May 1 of each year.

On April 24, 2014, the Washington Commission approved PSE’s request to change rates under its electric and natural gas decoupling mechanism, effective May 1, 2014. The rate change incorporated the effects of an increase to the allowed delivery revenue per customer as well as true-ups to the rate from the prior year. This represents a rate increase for electric customers of $10.6 million, or 0.5%, annually on total electric revenue, and a rate decrease for natural gas customers of $1.0 million, or 0.1%, annually on total gas revenue.

On April 22, 2015, the Washington Commission approved PSE’s request to change rates under its electric and natural gas decoupling mechanism, effective May 1, 2015. As part of this filing, PSE also requested to change the methodology of how decoupling deferrals are calculated going forward and adjust deferrals calculated in 2014. The change was done to ensure that the amortization of prior years’ accumulated decoupling deferrals were not included in the calculation of the current year decoupling deferrals. The effect of the methodology change was a reduction of approximately $12.0 million previously recognized revenue from May through December 2014. The overall changes represent a rate increase for electric customers of $53.8 million, or 2.6%, annually, and a rate increase for natural gas customers of $22.0 million, or 2.1%, annually, effective May 1, 2015. In addition, PSE exceeded the earnings test threshold for its natural gas business in 2014. As a result, PSE recorded a reduction in natural gas decoupling deferral and revenue of $1.3 million. This was reflected as a reduction to the natural gas rate increases noted above.

The Company is also limited to a 3.0% annual decoupling related cap on increases in total revenue. This limitation was triggered for certain rate classes. The resulting amount of deferral that was not included in the 2015 rate increase is $1.9 million for electric revenue and $8.2 million for natural gas revenue that was accrued through December 31, 2014. These amounts may be included in customer rates beginning in May 2016, subject to subsequent application of the earnings test and the 3.0% cap on decoupling related rate increases.

Due to the 3.0% annual decoupling increase cap noted above and the growing size of decoupling deferrals, PSE performed an analysis as of September 30, 2015 to determine if electric and natural gas decoupling revenue deferrals would be collected from customers within 24 months of December 31, 2015. The analysis indicated $5.0 million of natural gas decoupling revenue will not be collected within 24 months, therefore PSE did not recognize this portion of decoupling revenue. However, once it is determined to be collectible within 24 months it will be recognized.

Washington Commission Decision. On July 24, 2013, the Public Counsel Division of the Washington State Attorney General’s Office (Public Counsel) and the Industrial Customers of Northwest Utilities each filed a petition in Thurston County Superior Court (the Court) seeking judicial review of various aspects of the Washington Commission’s ERF and decoupling mechanism final order. The parties’ petitions argued that the order violated various procedural and substantive requirements of the Washington Administrative Procedure Act, and so requested that it be vacated and that the matter be remanded to the Washington Commission. Oral

 

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arguments regarding this matter were held on May 9, 2014. On June 25, 2014, the court issued a decision in which it affirmed the attrition adjustment K-Factor and the Washington Commission’s decision not to consider the case as a GRC, but reversed and remanded the cost of equity for further adjudication consistent with the court’s decision. In the remand proceeding evidentiary hearings regarding return on equity were held in February 2015 and initial briefs and reply briefs were filed in March 2015. The Washington Commission issued a final order on remand on June 29, 2015, in which it found that 9.8% is a reasonable return on equity for PSE for the term of the rate plan, taking decoupling and other relevant factors into account.

Other Proceedings. On August 11, 2015, PSE filed with the Washington Commission a petition for approval of a special contract for the liquefied natural gas (“LNG”) fuel service with Totem Ocean Trailer Express, Inc. (“TOTE”) which upon the Washington Commission approval, has a delivery term that commences January 1, 2019. Additionally, the filing contained a request for a declaratory order approving the methodology for allocating costs between regulated and non-regulated LNG services. A prehearing conference was held on October 13, 2015, which provided for simultaneous briefs on November 20, 2015 and hearings on January 29, 2016.

On March 26, 2015, PSE filed a request with the Washington Commission to change rates under its electric and natural gas property tax tracker mechanism, effective May 1, 2015. PSE filed a substitute filing with the Washington Commission on April 15, 2015 for the electric property tax tracker mechanism. The proposed rate change incorporates the effects of an increase to property taxes paid as well as true-ups to the rate from the prior year. This represents a rate increase for electric customers of $6.5 million, or 0.3% annually. PSE made a subsequent substitute natural gas filing with the Washington Commission on May 1, 2015, which changed the rate effective date to June 1, 2015, and represented a rate decrease for natural gas customers of $2.3 million or 0.2% annually.

On April 24, 2014, the Washington Commission approved PSE’s request to change rates under its electric and natural gas property tax tracker mechanism, effective May 1, 2014. The rate change incorporated the effects of an increase in the amount of property taxes paid as well as true-ups to the rate from the prior year. This represents a rate increase for electric customers of $11.0 million, or 0.5% annually, and a rate increase for natural gas customers of $5.6 million, or 0.6% annually.

On April 24, 2014, the Washington Commission also approved PSE’s request to change rates under its electric and natural gas conservation riders, effective May 1, 2014. The rate change incorporated the effects of changes in the annual conservation budgets as well as true-ups to the rate from the prior year. The rate change represents a rate increase for electric customers of $12.2 million, or 0.6% annually, and a rate increase for natural gas customers of $0.3 million.

Electric Rates

PSE currently has a PCA mechanism that provides for the recovery of power costs from customers or refunding of power cost savings to customers in the event those costs vary from the “power cost baseline” level of power costs. The “power cost baseline” levels are set, in part, based on normalized assumptions about weather and hydroelectric 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. The graduated scale currently applicable is as follows:

 

Annual Power Cost Variability		Company’s Share				Customers’ Share
+/- $20 million			100	%			—	%
+/- $20 million - $40 million			50				50
+/- $40 million - $120 million			10				90
+/- $120 + million			5				95

 

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On August 7, 2015, the Washington Commission issued an order approving the settlement proposing changes to the PCA mechanism. The settlement agreement will not take effect until January 1, 2017. Key components of the settlement will include the following changes to the PCA mechanism:

 

Annual Power Cost Variability		Company’s Share								Customers’ Share
		Over				Under				Over				Under
+/- $17 million			100	%			100	%			—	%			—	%
+/- $17 million - $40 million			35				50				65				50
+/- $40 + million			10				10				90				90

 

•

Reducing the cumulative deferral trigger for surcharge or refund from $30.0 million to $20.0 million;

 

•

Removing fixed production costs from the PCA mechanism and placing them in the decoupling mechanism if the decoupling mechanism continues as part of the next GRC;

 

•

Suspending the requirement that a GRC must be filed within three months after rates are approved in a PCORC, and agreeing, for a five-year period, that PSE will not file a GRC or PCORC within six months of the date rates go into effect for a PCORC filing; and

 

•

Establishing a five-year moratorium on changes to the PCA/PCORC.

PSE had an unfavorable PCA imbalance for the three and nine months ended September 30, 2015, which was $9.8 million and $14.8 million, respectively, above the “power cost baseline” level, of which no amount was apportioned to customers. This compares to an unfavorable imbalance for the three months ended September 30, 2014 of $9.8 million of which $4.1 million was apportioned to customers, and an unfavorable imbalance for the nine months ended September 30, 2015 of $24.1 million of which $4.1 million was apportioned to customers.

As discussed above, the Washington Commission approved rate increases related to the recovery of PSE’s electric delivery system costs. The following table sets forth the associated electric rate adjustments approved by the Washington Commission and the corresponding impact to PSE’s annual revenue based on the effective dates:

 

Type of Rate Adjustment		Effective Date		Average Percentage Increase (Decrease) in Rates				Annual Increase (Decrease) in Rates (Dollars in Millions)
Decoupling rate filing		May 1, 2015			2.6	%		$	53.8
PCORC		December 1, 2014			(0.9	)			(19.4	)
Conservation rider		May 1, 2014			0.6				12.2
Decoupling rate filing		May 1, 2014			0.5				10.6
Property tax tracker		May 1, 2014			0.5				11.0

In addition, PSE will be increasing the allowed delivery revenue per customer under the decoupling filing by 3.0% for electric customers on January 1 of each year until the conclusion of PSE’s next GRC.

Natural Gas Rates

PSE has a PGA mechanism that 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 natural gas cost amount in PGA mechanism rates, including accrued interest. 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 natural gas cost through rates.

On September 18, 2015, PSE filed its PGA natural gas tariff filing with an effective date of November 1, 2015, which reflected changes in wholesale natural gas and pipeline transportation costs and changes in deferral amortization rates. The impact to the PGA rates is an annual revenue decrease of $185.9 million, or 17.4%, with no impact on net operating income.

 

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As discussed above, the Washington Commission approved rate increases related to the recovery of PSE’s gas delivery system costs. The following table sets forth the associated natural gas rate adjustments, including those for the PGA, that were approved by the Washington Commission and the corresponding impact to PSE’s annual revenue based on the effective dates:

 

Type of Rate Adjustment		Effective Date		Average Percentage Increase (Decrease) in Rates				Annual Increase (Decrease) in Rates (Dollars in Millions)
Purchased gas adjustment		November 1, 2015			(17.4	)%		$	(185.9	)
Decoupling rate filing		May 1, 2015			2.1			$	22.0
Purchased gas adjustment		November 1, 2014			2.5				23.3
Decoupling rate filing		May 1, 2014			(0.1	)			(1.0	)
Property tax tracker		May 1, 2014			0.6				5.6

In addition, PSE will be increasing the allowed delivery revenue per customer under the decoupling filing by 2.2% for natural gas customers on January 1 of each year until the conclusion of PSE’s next GRC.

Other Factors and Trends

Weather Conditions. Weather conditions in PSE’s service territory have an impact on customer energy usage, affecting PSE’s billed revenue and energy supply expenses. PSE’s operating revenue and associated energy supply expenses are not generated evenly throughout the year. While both PSE’s electric and natural gas sales are generally greatest during winter months, variations in energy usage by customers occur from season to season also and 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 reported lower customer usage in the nine months ended September 30, 2015, primarily due to Pacific Northwest temperatures being warmer on average as compared to the same period in the prior year. The actual average temperature during the nine months ended September 30, 2015 was 58.44 degrees, or 1.31 degrees warmer than the same period in the prior year, and 3.66 degrees warmer when compared to the historical average.

Revenue Decoupling. While fluctuations in weather conditions will continue to affect PSE’s billed revenue and energy supply expenses from month to month, PSE’s decoupling mechanisms, which went into effect on July 1, 2013 for electric and natural gas operations, are expected to diminish the impact of weather on operating revenue and net income. The Washington Commission has allowed PSE to record a monthly adjustment to its electric and natural gas operating revenues related to electric transmission and distribution, natural gas operations and general administrative costs from residential, commercial and industrial customers to eliminate the effects of abnormal weather, conservation impacts and changes in usage patterns per customer with the exception of the electric business where power costs are not part of the decoupling mechanism. As a result, these electric and natural gas revenues will be recovered on a per customer basis regardless of actual consumption levels. The energy supply costs, which are part of the PCA and PGA mechanisms, are not included in the decoupling mechanism. The revenue recorded under the decoupling mechanisms will be affected by customer growth and not actual consumption. Following each calendar year, PSE will recover or refund the difference between allowed decoupling revenue and the corresponding actual revenue to affected customers during the following May to April time period.

Customer Demand. PSE expects the number of natural gas customers to grow at rates slightly above that of electric customers. PSE also expects energy usage by both residential electric and natural gas customers to continue a long-term trend of slow decline primarily due to continued energy efficiency improvements.

 

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Access to Debt Capital. PSE relies on access to bank borrowings and short-term money markets as sources of liquidity and longer-term capital markets to fund its utility construction program, to meet maturing debt obligations 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 have any debt outstanding whose maturity would accelerate upon a credit rating downgrade. However, a ratings downgrade could adversely affect the Company’s 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 increase as their respective credit ratings decline due to increases in credit spreads and commitment fees. 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. PSE’s credit facilities mature in 2019 and Puget Energy’s senior secured credit facility matures in 2018. (See discussion on credit facilities in Item 2, “Financing Program—Credit Facilities and Commercial Paper”).

Regulatory Compliance Costs and Expenditures. PSE’s operations are subject to extensive federal, state and local laws and regulations. These regulations cover electric system reliability, gas pipeline system safety and energy market transparency, among other areas. Environmental laws and regulations related to air and water quality, including climate change and endangered species protection, waste handling and disposal (including generation by-products such as coal ash), remediation of contamination and siting new facilities also impact the Company’s operations. PSE must spend significant amounts to fulfill requirements set by regulatory agencies, many of which have greatly expanded mandates on measures including, but not limited to, resource planning, remediation, monitoring, pollution control equipment and emissions-related abatement and fees.

Compliance with these or other future regulations, such as those pertaining to climate change and generation by-products, could require significant capital expenditures by PSE and may adversely affect PSE’s financial position, results of operations, cash flows and liquidity.

Other Challenges and Strategies

Competition. PSE’s electric and natural gas utility retail customers currently do not have the ability to choose their electric or natural gas supplier and therefore, PSE’s business has historically been recognized as a natural monopoly. However, PSE faces increasing competition for sales to its retail customers. Alternative methods of electric energy generation, including solar and other self-generation methods, compete with PSE for sales to existing electric retail customers. In addition, PSE’s natural gas customers may elect to use heating oil, propane or other fuels instead of using and purchasing natural gas from PSE. Further, PSE faces competition from public utility districts and municipalities that want to establish their own municipal-owned utility, as a result of which PSE may lose a number of customers in its service territory.

Energy Supply. In PSE’s draft Integrated Resource Plan (IRP), final to be filed with the Washington Commission on November 30, 2015, PSE projects that beginning in 2021, its future energy needs will exceed current resources in its supply portfolio. The IRP identifies declining regional surpluses, 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 cannot acquire needed energy supply resources at a reasonable cost, it may be required to purchase additional power in the open market at a cost that could, in the absence of regulatory relief, significantly increase its expenses and reduce earnings and cash flows. Therefore, PSE, for the first time, explicitly incorporated physical risk in the wholesale markets into the Company’s needs assessment.

Infrastructure Investment. PSE is investing in its utility infrastructure and customer service functions in order to meet regulatory requirements, serve customers’ energy needs and replace aging infrastructure. These

 

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investments and operating requirements give rise to significant growth in depreciation, amortization and operating expenses, which are not recovered through the ratemaking process in a timely manner.

Operational Risks Associated With Generating Facilities. PSE owns and operates coal, natural gas-fired, hydroelectric, wind-powered, solar and oil-fired generating facilities. The 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. PSE does not have business interruption insurance coverage to cover replacement power costs.

Markets For Intangible Power Attributes. The Company is actively engaged in monitoring the development of the commercial markets for such intangible power attributes as renewable energy credits and carbon financial instruments. The Company supports the development of regional and national markets for these products that are open, transparent and liquid.

Results of Operations

Puget Sound Energy

The following discussion should be read in conjunction with the unaudited consolidated financial statements and the related notes included elsewhere in this document. The following discussion provides the significant items which impacted PSE’s results of operations:

 

Puget Sound Energy		Three Months Ended September 30,												Nine Months Ended September 30,
(Dollars in Thousands)		2015				2014				Favorable/ (Unfavorable)				2015				2014				Favorable/ (Unfavorable)
Operating revenue:
Electric
Residential sales		$	222,619			$	200,640				11.0	%		$	728,988			$	753,496				(3.3	)%
Commercial sales			215,621				208,203				3.6				636,350				624,486				1.9
Industrial sales			28,810				27,981				3.0				84,570				81,466				3.8
Other retail sales			4,970				4,071				22.1				15,204				14,001				8.6
Total retail sales			472,020				440,895				7.1				1,465,112				1,473,449				(0.6	)
Transportation sales			2,949				2,764				6.7				7,478				7,133				4.8
Sales to other utilities and marketers			18,642				10,427				78.8				30,911				31,049				(0.4	)
Decoupling revenue			(12,050	)			2,797				*				13,891				28,967				(52.0	)
Other			1,225				11,647				(89.5	)			8,637				37,065				(76.7	)
Total electric operating revenue			482,786				468,530				3.0				1,526,029				1,577,663				(3.3	)
Natural gas
Residential sales			69,836				64,616				8.1				398,090				439,418				(9.4	)
Commercial sales			41,006				38,266				7.2				188,728				197,444				(4.4	)
Industrial sales			3,680				3,993				(7.8	)			15,858				17,872				(11.3	)
Total retail sales			114,522				106,875				7.2				602,676				654,734				(8.0	)
Transportation sales			4,478				4,150				7.9				13,728				12,595				9.0
Decoupling revenue			(2,674	)			7,112				(137.6	)			27,087				15,205				78.1
Other			3,256				3,265				(0.3	)			9,894				10,246				(3.4	)
Total natural gas operating revenue			119,582				121,402				(1.5	)			653,385				692,780				(5.7	)
Non-utility operating revenue			3,545				4,019				(11.8	)			11,683				11,799				(1.0	)
Total operating revenue			605,913				593,951				2.0				2,191,097				2,282,242				(4.0	)

 

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Puget Sound Energy		Three Months Ended September 30,												Nine Months Ended September 30,
(Dollars in Thousands)		2015				2014				Favorable/ (Unfavorable)				2015				2014				Favorable/ (Unfavorable)
Operating expenses:
Energy costs
Purchased electricity			97,694				67,984				(43.7	)			355,645				363,769				2.2
Electric generation fuel			76,863				92,510				16.9				180,531				202,741				11.0
Residential exchange			(19,530	)			(30,963	)			(36.9	)			(92,297	)			(84,587	)			9.1
Purchased natural gas			46,436				42,550				(9.1	)			282,334				310,128				9.0
Net unrealized (gain) loss on derivative instruments			5,588				32,648				82.9				(5,795	)			8,284				170.0
Utility operations and maintenance			131,208				132,109				0.7				400,355				411,068				2.6
Non-utility expense and other			5,605				5,899				5.0				18,953				17,451				(8.6	)
Depreciation and amortization			107,759				105,905				(1.8	)			314,348				312,821				(0.5	)
Conservation amortization			24,224				23,047				(5.1	)			78,389				74,554				(5.1	)
Taxes other than income taxes			64,030				59,945				(6.8	)			228,942				228,534				(0.2	)
Total operating expenses			539,877				531,634				(1.6	)			1,761,405				1,844,763				4.5
Operating income (loss)			66,036				62,317				6.0				429,692				437,479				(1.8	)
Other income			4,731				10,953				(56.8	)			14,770				19,815				(25.5	)
Other expense			(1,621	)			(1,806	)			10.2				(4,843	)			(5,032	)			3.8
Interest charges			(58,629	)			(67,565	)			13.2				(181,348	)			(194,563	)			6.8
Income (loss) before income taxes			10,517				3,899				169.7				258,271				257,699				0.2
Income tax (benefit) expense			641				842				23.9				76,596				75,726				(1.1	)
Net income (loss)		$	9,876			$	3,057				*			$	181,675			$	181,973				(0.2	)%

 

*	Percent change not applicable or meaningful.

NON-GAAP FINANCIAL MEASURES—Electric and Natural Gas Margins

The following discussion includes financial information prepared in accordance with U.S. Generally Accepted Accounting Principles (“GAAP”), as well as two other financial measures, electric margin and natural gas margin, that are considered “non-GAAP financial measures.” Generally, a non-GAAP financial measure is a numerical measure of a company’s financial performance, financial position or cash flows that exclude (or include) amounts that are included in (or excluded from) the most directly comparable measure calculated and presented in accordance with GAAP. The presentation of electric margin and natural gas margin is intended to supplement an understanding of PSE’s operating performance. Electric margin and natural gas margin are used by PSE to determine whether PSE is collecting the appropriate amount of energy costs from its customers to allow recovery of operating costs. PSE’s electric margin and natural gas margin measures may not be comparable to other companies’ electric margin and natural 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.

 

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Electric Margin

Electric margin represents electric sales to retail and transportation customers less the cost of generating and purchasing electric energy sold to customers, including transmission costs to bring electric energy to PSE’s service territory. The following table displays the details of PSE’s electric margin changes:

 

Electric Margin		Three Months Ended September 30,												Nine Months Ended September 30,
(Dollars in Thousands)		2015				2014				Favorable/ (Unfavorable)				2015				2014				Favorable/ (Unfavorable)
Electric operating revenue:
Residential sales		$	222,619			$	200,640				11.0	%		$	728,988			$	753,496				(3.3	)%
Commercial sales			215,621				208,203				3.6				636,350				624,486				1.9
Industrial sales			28,810				27,981				3.0				84,570				81,466				3.8
Other retail sales			4,970				4,071				22.1				15,204				14,001				8.6
Total retail sales			472,020				440,895				7.1				1,465,112				1,473,449				(0.6	)
Transportation sales			2,949				2,764				6.7				7,478				7,133				4.8
Sales to other utilities and marketers			18,642				10,427				78.8				30,911				31,049				(0.4	)
Decoupling revenue			(12,050	)			2,797				*				13,891				28,967				(52.0	)
Other			1,225				11,647				(89.5	)			8,637				37,065				(76.7	)
Total electric operating revenues1			482,786				468,530				3.0				1,526,029				1,577,663				(3.3	)
Minus electric energy costs:
Purchased electricity1			97,694				67,984				(43.7	)			355,645				363,769				2.2
Electric generation fuel1			76,863				92,510				16.9				180,531				202,741				11.0
Residential exchange1			(19,530	)			(30,963	)			(36.9	)			(92,297	)			(84,587	)			9.1
Total electric energy costs			155,027				129,531				(19.7	)			443,879				481,923				7.9
Electric margin2		$	327,759			$	338,999				(3.3	)%		$	1,082,150			$	1,095,740				(1.2	)%

 

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.

*	Percent change not applicable or meaningful.

Electric margin decreased $11.2 million and $13.5 million, or 3.3% and 1.2%, to $327.8 million and $1,082.2 million from $339.0 million and $1,095.7 million for the three and nine months ended September 30, 2015, respectively, as compared to the same period in 2014. The following is a discussion of significant items that impact electric operating revenue and electric energy costs, which are included in electric margin:

Electric Operating Revenue

Electric operating revenues increased $14.3 million, or 3.0%, to $482.8 million from $468.5 million for the three months ended September 30, 2015 as compared to the same period in 2014. The increase in operating revenues was primarily due to higher residential sales of $22.0 million and sales to other utilities and marketers of $8.2 million, partially offset by a decrease in decoupling revenue of $14.8 million. These items are discussed in more detail below.

Electric operating revenues decreased $51.7 million, or 3.3%, to $1,526.0 million from $1,577.7 million for the nine months ended September 30, 2015 as compared to the same period in 2014. The decrease in operating revenues was primarily due to lower non-core gas sales of $19.0 million, lower decoupling revenue of $15.1 million, and lower electric retail sales of $8.3 million. These items are discussed in more detail below.

 

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Electric retail sales increased $31.1 million, or 7.1%, to $472.0 million from $440.9 million for the three months ended September 30, 2015 as compared to the same period in 2014. The increase in electric retail sales primarily resulted from a rate increase of $30.2 million during the three months ended September 30, 2015 as compared to the same period in the prior year.

Electric retail sales decreased $8.3 million, or 0.6%, to $1,465.1 million from $1,473.4 million for the nine months ended September 30, 2015 as compared to the same period in 2014. The decrease in electric retail sales primarily resulted from $21.7 million due to lower retail electricity usage of 221,966 Megawatt Hours (MWhs), or 1.5% and a credit related to Jefferson County gain to customers of $6.5 million, which was partially offset by a rate increase of $19.8 million during the nine months ended September 30, 2015 as compared to the same period in the prior year.

Sales to other utilities and marketers increased $8.2 million, or 78.8%, to $18.6 million from $10.4 million for the three months ended September 30, 2015 as compared to the same period in 2014. The increase was primarily driven by a $12.2 million increase related to higher sales volumes partially offset by a $4.0 million decrease related to lower wholesale prices for the three months ended September 30, 2015 as compared to the same prior year period.

Decoupling revenue decreased $14.8 million due to $3.6 million reduction in decoupling revenue from an increase in retail sales from higher than normal temperatures, amortization of prior year decoupling revenue of $6.1 million and excess earnings over the rate of return of $5.1 million for the three months ended September 30, 2015 as compared to the same period in the prior year.

Decoupling revenue decreased $15.1 million due to amortization of prior year decoupling revenue of $4.9 million, excess earnings over the rate of return of $5.2 million, as well as a reduction in decoupling revenue of $5.0 million for the nine months ended September 30, 2015 as compared to the same period in the prior year. The 2015 decoupling revenue does not include the excess over the rate of return, which will be given back to customers in 2016. The 2015 decoupling receivable will be recovered from customers through a future rate filing beginning May 1, 2016.

Other electric operating revenue decreased $10.4 million, or 89.5%, to $1.2 million from $11.6 million for the three months ended September 30, 2015 as compared to the same period in 2014. The decrease was primarily the result of a decrease of $3.9 million due to lower non-core gas sales.

Other electric operating revenue decreased $28.5 million, or 76.7%, to $8.6 million from $37.1 million for the nine months ended September 30, 2015 as compared to the same period in 2014. The decrease was primarily the result of lower non-core gas sales of $19.0 million.

Electric Energy Costs

Purchased electricity expense increased $29.7 million, or 43.7%, to $97.7 million from $68.0 million for the three months ended September 30, 2015 as compared to the same period in 2014. The increase was primarily the result of an $18.0 million increase related to a new purchase power contract, $5.4 million related to higher secondary purchases and no sharing of power costs in 2015.

Purchased electricity expense decreased $8.2 million, or 2.2%, to $355.6 million from $363.8 million for the nine months ended September 30, 2015 as compared to the same period in 2014. The decrease was primarily the result of a $59.2 million decrease in secondary purchases, which was partially offset by a $52.7 million increase in a new purchase power contract.

To meet customer demand, PSE economically dispatches resources in its power supply portfolio, such as fossil-fuel generation, owned and contracted hydroelectric energy and long-term contracted power. However, depending principally upon availability of hydroelectric and wind energy, plant availability, fuel prices and/or

 

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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 as well as through other risk management techniques.

Electric generation fuel expense decreased $15.6 million, or 16.9%, to $76.9 million from $92.5 million for the three months ended September 30, 2015 as compared to the same period in 2014. The decrease was primarily due to a $15.9 million decrease in fuel expense at PSE’s combustion turbine facilities due to lower prices of natural gas, partially offset by higher production of 128,436 MWhs.

Electric generation fuel expense decreased $22.2 million, or 11.0%, to $180.5 million from $202.7 million for the nine months ended September 30, 2015 as compared to the same period in 2014. The decrease was primarily due to a $21.3 million decrease in fuel expense at PSE’s combustion turbine facilities due to lower prices of natural gas which was offset by an increase in production at PSE’s combustion turbine facilities of 895,752 MWhs.

Residential exchange credits decreased $11.5 million, or 36.9%, to $19.5 million from $31.0 million for the three months ended September 30, 2015 as compared to the same period in 2014 as a result of warmer temperatures, lower electric retail sales and higher Residential Exchange Program (REP) tariff prices associated with the Bonneville Power Administration (BPA) REP for the period June 1, 2014 through May 31, 2015. The REP credit is a pass-through tariff item with a corresponding credit in electric operating revenue, with no impact on net income.

Residential exchange credits increased $7.7 million, or 9.1%, to $92.3 million from $84.6 million for the nine months ended September 30, 2015 as compared to the same period in 2014 as a result of higher REP tariff prices associated with the BPA REP for the period June 1, 2014 through May 31, 2015. The REP credit is a pass-through tariff item with a corresponding credit in electric operating revenue, with no impact on net income.

Natural Gas Margin

Natural gas margin is natural gas sales to retail and transportation customers less the cost of natural gas purchased, including transportation costs to bring natural gas to PSE’s service territory. The following table displays the details of PSE’s natural gas margin:

 

Natural Gas Margin		Three Months Ended September 30,												Nine Months Ended September 30,
(Dollars in Thousands)		2015				2014				Favorable/ (Unfavorable)				2015				2014				Favorable/ (Unfavorable)
Natural gas operating revenue:
Residential sales		$	69,836			$	64,616				8.1	%		$	398,090			$	439,418				(9.4	)%
Commercial sales			41,006				38,266				7.2				188,728				197,444				(4.4	)
Industrial sales			3,680				3,993				(7.8	)			15,858				17,872				(11.3	)
Total retail sales			114,522				106,875				7.2				602,676				654,734				(8.0	)
Transportation sales			4,478				4,150				7.9				13,728				12,595				9.0
Decoupling revenue			(2,674	)			7,112				(137.6	)			27,087				15,205				78.1
Other			3,256				3,265				(0.3	)			9,894				10,246				(3.4	)
Total natural gas operating revenues1			119,582				121,402				(1.5	)			653,385				692,780				(5.7	)
Minus purchased natural gas energy costs1			46,436				42,550				(9.1	)			282,334				310,128				9.0
Natural gas margin2		$	73,146			$	78,852				(7.2	)%		$	371,051			$	382,652				(3.0	)%

 

1	As reported on PSE’s Consolidated Statement of Income.

2	Natural gas margin does not include any allocation for amortization/depreciation expense or natural gas operations and maintenance expense.

 

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Natural gas margin decreased $5.7 million and $11.6 million, or 7.2% and 3.0%, to $73.1 million and $371.1 million from $78.9 million and $382.7 million for the three and nine months ended September 30, 2015 as compared to the same period in 2014. The following is a discussion of significant items of natural gas operating revenue and natural gas energy costs which are included in gas margin:

Natural Gas Operating Revenue

Natural gas operating revenues decreased $1.8 million, or 1.5%, to $119.6 million from $121.4 million for the three months ended September 30, 2015 as compared to the same period in 2014. The decrease was due to lower decoupling revenue, which was partially offset by an increase in natural gas retail sales, as discussed in more detail below.

Natural gas operating revenues decreased $39.4 million, or 5.7%, to $653.4 million from $692.8 million for the nine months ended September 30, 2015 as compared to the same period in 2014. The decrease was due to lower natural gas retail sales, which was partially offset by an increase in decoupling revenue, as discussed in more detail below.

Natural gas retail sales increased $7.6 million, or 7.2%, to $114.5 million from $106.9 million for the three months ended September 30, 2015 as compared to the same period in 2014. The increase was primarily due to higher natural gas therm sales of $4.8 million, or 4.5%, and due to a rate increase of $2.8 million attributed to a PGA rate increase effective November 1, 2014 and decoupling rate filings.

Natural gas retail sales decreased $52.0 million, or 8.0%, to $602.7 million from $654.7 million for the nine months ended September 30, 2015 as compared to the same period in 2014. The decrease was primarily due to an $84.4 million, or 12.9%, reduction in natural gas therm sales due to warmer weather during nine months ended September 30, 2015 , which was offset by rate increases of $32.3 million attributed to a PGA rate increase effective November 1, 2014 and decoupling rate filings.

Decoupling revenue decreased $9.8 million for the three months ended September 30, 2015 as compared to the same period in the prior year primarily due to a reduction of $8.3 million related to excess earnings over the rate of return, which is shared with customers. PSE is limited to a 3.0% annual decoupling rate increase which resulted in not recognizing $5.0 million of natural gas decoupling revenues which will not be collected within 24 months. PSE will record the decoupling revenue once it meets the 24-month collection period under GAAP or when collected from customers. The 2015 decoupling receivable will be recovered from customers through a future rate filing beginning May 1, 2016 and 2017.

Decoupling revenue increased $11.9 million due to $23.3 million reduction in decoupling revenue from lower volumetric sales as a result of warmer than normal weather, which was partially offset by a reduction of $10.2 million related to excess earnings over the rate of return, which is shared with customers for the nine months ended September 30, 2015 as compared to the same period in 2014. PSE did not recognize $5.0 million of decoupling revenue that will not be collected within a 24-month period due to excess earning over PSE’s rate of return. The 2015 decoupling receivable will be recovered from customers through a future rate filing beginning May 1, 2016 and 2017.

Natural Gas Energy Costs

Purchased natural gas expenses increased $3.8 million, or 9.1%, to $46.4 million from $42.6 million for the three months ended September 30, 2015 as compared to the same period in 2014. The increase was primarily due to PGA deferral commodity costs and amortization of $12.4 million, which was partially offset by a decrease in natural gas purchases of $11.1 million.

 

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Purchased natural gas expenses decreased $27.8 million, or 9.0%, to $282.3 million from $310.1 million for the nine months ended September 30, 2015 as compared to the same period in 2014. The decrease was primarily due to a reduction in customer usage of 12.9%, offset by an increase in PGA rates of $23.3 million, annually, that were effective November 1, 2014.

The PGA mechanism provides the rates used to determine natural gas costs based on customer usage. The PGA mechanism allows PSE to recover expected natural gas supply and transportation costs and defer, as a receivable or payable, any natural gas supply and transportation costs that exceed or fall short of this expected natural gas cost amount in PGA mechanism rates, including accrued interest. 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 natural gas cost through rates. A payable balance reflects over-recovery of natural gas cost through rates. The PGA mechanism payable balance at September 30, 2015 was $8.3 million.

Other Operating Expenses

Net unrealized loss on derivative instruments decreased $27.0 million, or 82.9%, to $5.6 million from $32.6 million for the three months ended September 30, 2015 as compared to the same period in 2014. The decrease was due to settlements of $20.6 million and an increase in wholesale forward commodity prices of $6.5 million.

Net unrealized gain on derivative instruments increased $14.1 million, or 170.0%, to a gain of $5.8 million from a loss of $8.3 million for the nine months ended September 30, 2015 as compared to the same period in 2014. The increase was due to settlements of $73.8 million, partially offset by a decrease in wholesale forward commodity prices of $59.8 million.

Utility operations and maintenance expense decreased $10.7 million, or 2.6%, to $400.4 million from $411.1 million for the nine months ended September 30, 2015 as compared to the same period in 2014. The decrease was primarily driven by a decrease in customer service expenses, primarily related to $7.1 million in uncollectible accounts expense and $3.3 million in meter reading expense.

Taxes other than income tax increased $4.1 million, or 6.8%, to $64.0 million from $59.9 million for the three months ended September 30, 2015 as compared to the same period in 2014. The increase was primarily due to an increase in state excise and municipal taxes for electric utilities.

Other income decreased $6.3 million, or 56.8%, to $4.7 million from $11.0 million for the three months ended September 30, 2015 as compared to the same period in 2014. The decrease was primarily due to a gain of $7.5 million for the JPUD sale that was recorded in three months ended September 30, 2014.

Other income decreased $5.0 million, or 25.5%, to $14.8 million from $19.8 million for the nine months ended September 30, 2015 as compared to the same period in 2014. The decrease was primarily due to a gain of $7.5 million for the JPUD sale that was recorded in nine months ended September 30, 2014.

Interest expense decreased $9.0 million, or 13.2%, to $58.6 million from $67.6 million due to a reduction of regulatory interest expense on regulatory liabilities for the three months ended September 30, 2015 as compared to the same period in 2014.

Interest expense decreased $13.3 million, or 6.8%, to $181.3 million from $194.6 million for the nine months ended September 30, 2015 as compared to the same period in 2014. The decrease was due to a reduction of regulatory interest expense on regulatory liabilities in 2015 as compared to the same period in 2014.

 

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Puget Energy

Summary Results of Operations

All the operations of Puget Energy are conducted through its subsidiary PSE. Puget Energy’s net income (loss) for the three and nine months ended September 30, 2015, and the same period in 2014 are as follows:

 

Benefit/(Expense)		Three Months Ended September 30,												Nine Months Ended September 30,
(Dollars in Thousands)		2015				2014				Percent Change				2015				2014				Percent Change
PSE net income		$	9,876			$	3,057				*			$	181,675			$	181,973				(0.2	)%
Other operating revenue			—				(235	)			100.0				—				(235	)			100.0
Net unrealized gain on energy derivative instruments			—				—				—				544				570				(4.6	)
Non-utility expense and other			3,853				2,987				29.0				11,659				8,823				32.1
Unhedged interest rate swap (expense)			(1,156	)			(322	)			*				(4,571	)			(2,428	)			(88.3	)
Interest expense1			(28,022	)			(24,217	)			(15.7	)			(80,874	)			(76,933	)			(5.1	)
Income tax benefit (expense)			7,521				5,772				30.3				24,931				23,977				4.0
Puget Energy net income (loss)		$	(7,928	)		$	(12,958	)			38.8	%		$	133,364			$	135,747				(1.8	)%

 

*	Percent change not applicable or meaningful.

1	Puget Energy’s interest expense includes elimination adjustments of intercompany interest on short-term debt.

Puget Energy’s net loss for the three months ended September 30, 2015 was $7.9 million with operating revenue of $605.7 million as compared to a net loss of $13.0 million with operating revenue of $593.7 million for the same period in 2014. Puget Energy’s net income for the nine months ended September 30, 2015 was $133.4 million with operating revenue of $2.2 billion as compared to a net income of $135.7 million with operating revenue of $2.3 billion for the same period in 2014. In addition to the items discussed above regarding PSE, which also impacted Puget Energy’s net income, Puget Energy holds an additional $1.6 billion in long term debt (net of discount), resulting in additional interest expense as shown above.

Capital Requirements

Contractual Obligations and Commercial Commitments

There have been no material changes to the contractual obligations and consolidated commercial commitments set forth in Part II, Item 7 in the Company’s Annual Report on Form 10-K for the year ended December 31, 2014.

On May 12, 2015, Puget Energy issued $400.0 million of senior secured notes, and on May 26, 2015, PSE issued $425.0 million of senior notes secured by first mortgage bonds. The net proceeds of these issuances were used to pay down existing long-term debt, as described in more detail elsewhere in this prospectus and therefore did not materially impact the contractual obligations and consolidated commercial commitments as previously set forth in Part II, Item 7 in the Company’s combined Annual Report on Form 10-K for the year ended December 31, 2014.

 

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The following are the Company’s aggregate availability under commercial commitments as of September 30, 2015:

 

Puget Sound Energy and Puget Energy		Amount of Available Commitments Expiration Per Period
(Dollars in Thousands)		Total				2015				2016-2018				2019-2020				Thereafter
PSE liquidity facility1		$	650,000			$	—			$	—			$	650,000			$	—
PSE energy hedging facility1			350,000				—				—				350,000				—
Inter-company short-term debt2			30,000				—				—				—				30,000
Total PSE commercial commitments		$	1,030,000			$	—			$	—			$	1,000,000			$	30,000
Puget Energy revolving credit facility3			800,000				—				800,000				—				—
Less: Inter-company short-term debt elimination2			(30,000	)			—				—				—				(30,000	)
Total Puget Energy commercial commitments		$	1,800,000			$	—			$	800,000			$	1,000,000			$	—

 

1

As of September 30, 2015, PSE had credit facilities totaling $1.0 billion which will mature in April 2019. These facilities consisted of a $650.0 million liquidity facility to fund operating expenses and serve as a backstop to the Company’s commercial paper program, and a $350.0 million hedging facility to support electric and natural gas hedging. The $650.0 million liquidity facility includes a swingline feature allowing same day availability on borrowings up to $75.0 million. The credit facilities also have an accordion feature that, upon the banks’ approval, would increase the total size of these facilities to $1.450 billion. As of September 30, 2015, $79.5 million was outstanding under the PSE energy hedging facility, no loans or letters of credit were outstanding under the PSE liquidity facility and no amounts were outstanding under the commercial paper program. The credit agreements are syndicated among numerous lenders. Outside of the credit agreements, PSE had a $3.9 million letter of credit in support of a long-term transmission contract and a $1.0 million letter of credit in support of natural gas purchases in Canada.

2	As of September 30, 2015, PSE had a revolving credit facility with Puget Energy in the form of a promissory note to borrow up to $30.0 million. On September 30, 2015 PSE repaid in full the outstanding balance under the note of $28.9 million.

3

As of September 30, 2015, Puget Energy had a revolving credit facility totaling $800.0 million, which matures in April 2018. The revolving credit facility is syndicated among numerous lenders. The revolving credit facility also has an accordion feature that, upon the banks’ approval, would increase the size of the facility to $1.3 billion. As of September 30, 2015, no amount was outstanding under the Puget Energy credit facility.

Utility Construction Program

PSE’s construction programs for generating facilities, the electric transmission system and the natural gas and electric distribution systems are designed to meet regulatory requirements and customer growth and to support reliable energy delivery. Construction expenditures, excluding equity allowance for funds used during construction (“AFUDC”), were $419.4 million for the nine months ended September 30, 2015. Presently planned utility construction expenditures, excluding AFUDC, are as follows:

 

Capital Expenditure Projections
(Dollars in Thousands)		2015				2016				2017
Total energy delivery, technology and facilities expenditures		$	593,606			$	671,060			$	674,555

The program is subject to change based upon general business, economic and regulatory conditions. Utility construction expenditures and any new generation resource expenditures may be funded from a combination of

 

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sources which may include cash from operations, short-term debt, long-term debt and/or equity. PSE’s planned capital expenditures may result in a level of spending that will exceed its cash flow from operations. As a result, execution of PSE’s strategy is dependent in part on continued access to capital markets.

Capital Resources

Cash from Operations

Puget Sound Energy

Cash generated from operations for the nine months ended September 30, 2015 was $533.3 million, a decrease of $144.0 million from $677.3 million generated during the nine months ended September 30, 2014. The decrease was primarily the result of a $172.6 million decrease in the collection of accounts receivable, a $28.3 million decrease in other liabilities and a $25.2 million decrease in regulatory assets cash flow, partially offset by a $67.8 million increase in cash flow related to a PGA rate increase effective November 1, 2014 and a $33.0 million increase related to regulatory liabilities.

Puget Energy

Cash generated from operations for the nine months ended September 30, 2015 was $466.0 million, a decrease of $139.2 million from $605.2 million generated during the nine months ended September 30, 2014. The net decrease was primarily impacted by $144.0 million from cash used in the operating activities of PSE, as previously discussed.

Financing Program

The Company’s external financing requirements principally reflect the cash needs of its construction program, its schedule of maturing debt and certain operational needs. The Company anticipates refinancing the redemption of bonds or other long-term borrowings with its credit facilities and/or the issuance of new long-term debt. Access to funds depends upon factors such as Puget Energy’s and PSE’s credit ratings, prevailing interest rates and investor receptivity to investing in the utility industry, Puget Energy and PSE. The Company believes there is sufficient liquidity to fund its needs over the next twelve months.

Credit Facilities and Commercial Paper. Proceeds from PSE’s short-term borrowings and sales of commercial paper are used to provide working capital and the interim funding of utility construction programs. Puget Energy and PSE continue to have reasonable access to the capital and credit markets.

Puget Sound Energy Credit Facilities. PSE has two unsecured revolving credit facilities which provide, in aggregate, $1.0 billion of short-term liquidity needs. These facilities consist of a $650.0 million revolving liquidity facility (which includes a liquidity letter of credit facility and a swingline facility) to be used for general corporate purposes, including a backstop to the Company’s commercial paper program and a $350.0 million revolving energy hedging facility (which includes an energy hedging letter of credit facility). The $650.0 million liquidity facility includes a swingline feature allowing same day availability on borrowings up to $75.0 million. The credit facilities also have an accordion feature which, upon the banks’ approval, would increase the total size of these facilities to $1.450 billion.

In April 2014, the Company completed a one-year extension on both of the liquidity and hedging facilities, extending the maturity from February 2018 to April 2019, and updating or clarifying the definitions of other terms and conditions of the facilities from when they were committed in 2013. The credit agreements are syndicated among numerous lenders and contain usual and customary affirmative and negative covenants that, among other things, place limitations on PSE’s ability to transact with affiliates, make asset dispositions and investments or permit liens to exist. The credit agreements also contain a financial covenant of total debt to total capitalization of 65% or less. PSE certifies its compliance with such covenants to participating banks each quarter. As of September 30, 2015, PSE was in compliance with all applicable covenant ratios.

 

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The credit agreements provide PSE with the ability to borrow at different interest rate options. The credit agreements allow PSE to borrow at the bank’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. PSE must pay a commitment fee on the unused portion of the credit facilities. The spreads and the commitment fee depend on PSE’s credit ratings. As of the date of this report, the spread to the LIBOR is 1.25% and the commitment fee is 0.175%.

As of September 30, 2015, no amounts were drawn under either PSE’s $650.0 million liquidity facility or PSE’s $350.0 million energy hedging facility. No letters of credit were outstanding under either facility, and $79.5 million was outstanding under the commercial paper program. Outside of the credit agreements, PSE had a $3.9 million letter of credit in support of a long-term transmission contract and a $1.0 million letter of credit in support of natural gas purchases in Canada.

Demand Promissory Note. On June 1, 2006, PSE entered into a revolving credit facility with Puget Energy, in the form of a credit agreement and a demand promissory note (“Note”) pursuant to which 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 lower of the weighted-average interest rates of PSE’s outstanding commercial paper or PSE’s senior unsecured revolving credit facility. Absent such borrowings, interest is charged at one-month LIBOR plus 0.25%. On June 30, 2015, PSE repaid in full the $28.9 million outstanding balance under the Note.

Puget Energy Credit Facilities. At September 30, 2015, Puget Energy maintained an $800.0 million revolving senior secured credit facility. In April 2014, the Company completed an amendment to the senior secured credit facility, extending the maturity from February 2017 to April 2018, updating the fee structure, eliminating a financial covenant and updating or clarifying the definitions of other terms and conditions of the facility. The Puget Energy revolving senior secured credit facility also has an accordion feature which, upon the banks’ approval, would increase the size of the facility to $1.3 billion.

The revolving senior secured credit facility provides Puget Energy the ability to borrow at different interest rate options and includes variable fee levels. Interest rates may be based on the bank’s prime rate or LIBOR, plus a spread based on Puget Energy’s credit ratings. Puget Energy must pay a commitment fee on the unused portion of the facility. As of September 30, 2015, there was no amount drawn and outstanding under the facility. As a result of Puget Energy’s credit rating upgrade in 2014, the spread over LIBOR was 1.75% and the commitment fee was 0.275% as of the date of this report. Puget Energy entered into interest rate swap contracts to manage the interest rate risk associated with the credit facility or similar variable rate debt (see Note 3 for more details).

The revolving senior secured credit facility contains usual and customary affirmative and negative covenants. The agreement also contains a maximum leverage ratio financial covenant as defined in the agreement governing the senior secured credit facility. As of September 30, 2015, Puget Energy was in compliance with all applicable covenants.

Term Loans. In June 2014, Puget Energy entered into three bilateral term loans, with two and three year maturities, which in total, equal $299.0 million. The proceeds of the term loans were used to pay off the outstanding Puget Energy revolving credit facility balance, which subsequently allows the Company to carry the debt with lower interest expense. On May 12, 2015, Puget Energy issued $400.0 million of senior secured notes and utilized the net proceeds to repay the three term loans in full.

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 September 30, 2015, approximately $441.0 million of unrestricted retained earnings was available for the payment of dividends under the most restrictive mortgage indenture covenant.

 

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Pursuant to the terms of the Washington Commission merger order, PSE may not declare or pay dividends 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. Also, 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, or, if its credit ratings are below investment grade, PSE’s ratio of earnings before interest, tax, depreciation and amortization (“EBITDA”) to interest expense for the most recently ended four fiscal quarter periods prior to such date is equal to or greater than 3 to one. The common equity ratio, calculated on a regulatory basis, was 48.1% at September 30, 2015 and the EBITDA to interest expense was 4.5 to one for the twelve months ended September 30, 2015.

PSE’s ability to pay dividends is also limited by the terms of its credit facilities, pursuant to which PSE is not permitted to pay dividends during any Event of Default (as defined in the facilities), or if the payment of dividends would result in an Event of Default, such as failure to comply with certain financial covenants.

Puget Energy’s ability to pay dividends is also limited by the merger order issued by the Washington Commission. 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 2 to one. Puget Energy’s EBITDA to interest expense was 3.2 to one for the twelve months ended September 30, 2015.

At September 30, 2015, the Company was in compliance with all applicable covenants, including those pertaining to the payment of dividends.

Debt Restrictive Covenants. The type and amount of future long-term financings for PSE may be limited by provisions in PSE’s electric and natural gas mortgage indentures.

PSE’s ability to issue additional secured debt may also be limited by certain restrictions contained in its electric and natural gas mortgage indentures. Under the most restrictive tests, as of September 30, 2015, PSE could issue:

 

•

Approximately $2.2 billion of additional first mortgage bonds under PSE’s electric mortgage indenture based on approximately $3.7 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 September 30, 2015; and

 

•

Approximately $331.0 million of additional first mortgage bonds under PSE’s natural gas mortgage indenture based on approximately $551.7 million of gas bondable property available for issuance, subject to a combined gas and electric interest coverage test of 1.75 times net earnings available for interest and a gas interest coverage test of 2.0 times net earnings available for interest (as defined in the natural gas utility mortgage), both of which PSE exceeded at September 30, 2015.

At September 30, 2015, PSE had approximately $6.9 billion in electric and natural gas rate base to support the interest coverage ratio limitation test for net earnings available for interest.

The Company was required to refinance its debt in place at the time of the merger. The Company has met this refinancing requirement as of September 30, 2015.

Shelf Registrations and Long-Term Debt Activity

Puget Sound Energy. PSE has in effect a shelf registration statement under which it may issue, from time to time, senior notes secured by first mortgage bonds. The Company remains subject to the restrictions of PSE’s indentures and credit agreements on the amount of first mortgage bonds that PSE may issue.

 

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On May 26, 2015, PSE issued $425.0 million of senior notes secured by first mortgage bonds. The notes mature in May 2045 and have an interest rate of 4.30%, which is payable semi-annually in May and November. Net proceeds of the issuance were used to fund the early retirement, including accrued interest and make-whole call premiums, of the Company’s $150.0 million 5.197% senior notes maturing in October 2015 and the Company’s $250.0 million 6.75% senior notes maturing in January 2016.

Puget Energy. On May 12, 2015, Puget Energy issued $400.0 million of senior secured notes. The notes mature in May 2025 and have an interest rate of 3.65%, which is payable semi-annually in May and November. Net proceeds of the issuance were used to repay all amounts outstanding under Puget Energy’s three term loans, and to fund a special dividend to shareholders of approximately $96.7 million.

Other

New Accounting Pronouncements

For the discussion of new accounting pronouncements, see Note 2 in the Combined Notes to the Consolidated Financial Statements in Part I.

Colstrip

PSE has a 50% ownership interest in Colstrip Units 1 and 2, and a 25% interest in Colstrip Units 3 and 4. On March 6, 2013, the Sierra Club and the Montana Environmental Information Center filed a Clean Air Act citizen suit against all Colstrip owners in the U.S. District Court, District of Montana. Based on a second amended complaint filed in August 2014, Plaintiffs’ lawsuit currently alleges violations of permitting requirements under the New Source Review program of the Clean Air Act and the Montana State Implementation Plan arising from seven projects undertaken at Colstrip during 2001-2012. Plaintiffs have since indicated that they do not intend to pursue three of the seven projects, leaving a total of four projects remaining. The lawsuit claims that, for each project, the Colstrip plant should have obtained a permit and installed pollution control equipment at Colstrip. The Plaintiffs’ complaint also seeks civil penalties and other appropriate relief. The case has been bifurcated into separate liability and remedy trials. The liability trial is currently set for March 2016, and a date for the remedy trial has yet to be determined. PSE is litigating the allegations set forth in the complaint, and as such, it is not reasonably possible to estimate the outcome of this matter.

Coal Combustion Residuals

On April 17, 2015, the U.S. Environmental Protection Agency (“EPA”) published a final rule, effective October 19, 2015, that regulates Coal Combustion Residuals (“CCR”) under the Resource Conservation and Recovery Act , Subtitle D. The CCR rule addresses the risks from coal ash disposal, such as leaking of contaminants into ground water, blowing of contaminants into the air as dust, and the catastrophic failure of coal ash surface impoundments by establishing technical requirements for CCR landfills and surface impoundments. The rule also sets out recordkeeping and reporting requirements including requirements to post specific information to a publicly-accessible website.

The CCR rule requires significant changes to the Company’s Colstrip operations and those changes were reviewed by the Company and the plant operator in the second quarter of 2015. PSE had previously recognized a legal obligation under EPA rules to dispose of coal ash material at Colstrip, in 2003. Due to the CCR rule, additional disposal costs were added to the asset retirement obligation.

EPA Draft Rule 111(d)

In June 2014, the EPA issued a proposed Clean Power Plan rule under Section 111(d) of the Clean Air Act designed to regulate greenhouse gas emissions from existing power plants. The proposed rule includes state-

 

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specific goals and guidelines for states to develop plans for meeting these goals. PSE filed comments on this rule in December 2014. The EPA issued a pre-publication version of the final Clean Power Plan rule under Section 111(d) on August 3, 2015. To date the rule has not yet been published in the Federal Register, so the effective date has not yet been triggered. PSE is reviewing the final rule and working with key stakeholders in preparation towards implementation. PSE cannot yet provide a determination of how the final rule may impact PSE or its existing generation facilities, if at all.

DESCRIPTION OF BUSINESS

GENERAL

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, PSE, a utility company. Puget Energy has no significant assets other than the stock of PSE.

On 2009, Puget Holdings LLC (“Puget Holdings”) completed its merger with Puget Energy. Puget Holdings is owned by 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. As a result of the merger, all of Puget Energy’s common stock is indirectly owned by Puget Holdings.

CORPORATE 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 distribution. Puget Energy’s business strategy is to generate stable earnings and cash flow by offering reliable electric and natural gas service in a cost-effective manner through PSE.

PUGET 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.

The following table presents the number of PSE customers as of December 31, 2014 and 2013:

 

		ELECTRIC												GAS
		DECEMBER 31												DECEMBER 31
		2014				2013				PERCENT CHANGE				2014				2013				PERCENT CHANGE
Customers:(1)
Residential			966,144				957,897				0.9	%			733,135				722,680				1.4	%
Commercial			121,814				119,709				1.8				55,021				54,569				0.8
Industrial			3,457				3,442				0.4				2,392				2,409				(0.7	)
Other			6,144				5,937				3.5				209				208				0.5
Total			1,097,559				1,086,985				1.0	%			790,757				779,866				1.4	%

 

(1)	At December 31, 2014 approximately 381,500 customers purchased both electricity and natural gas from PSE as compared to 374,200 at December 31, 2013.

 

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During 2014, PSE’s billed retail and transportation revenue from electric utility operations were derived 51.5% from residential customers, 41.7% from commercial customers, 5.4% from industrial customers and 1.4% from other customers. PSE’s billed retail revenue from natural gas utility operations were derived 66.5% from residential customers, 29.1% from commercial customers, 2.6% from industrial customers and 1.8% from transportation customers in 2014. During this period, the largest customer accounted for approximately 1.5% of PSE’s operating revenue.

PSE’s revenues and associated expenses are not generated evenly throughout the year, primarily due to seasonal weather patterns and varying wholesale prices for electricity and the amount of hydroelectric energy supplies available to PSE, which makes quarter-to-quarter comparisons difficult. Weather conditions in PSE’s service territory have an impact on customer energy usage, affecting PSE’s billed revenue and energy supply expenses. PSE normally experiences its highest retail energy sales, and subsequently often higher power costs, during the winter heating season in the first and fourth quarters of the year and its lowest sales and subsequently lower power costs in the third quarter of the year. While fluctuations in weather conditions will continue to affect PSE’s billed revenue and energy supply expenses from month to month, PSE’s decoupling mechanisms which went into effect on July 1, 2013 for electric and gas operations, are expected to diminish the impact of weather on operating revenue and net income. Under the decoupling mechanism, the Washington Commission allows PSE to record a monthly adjustment to its electric and gas operating revenues related to electric transmission and distribution, gas operations and general administrative costs from residential, commercial and industrial customers to eliminate the effects of abnormal weather, conservation impacts and changes in usage patterns per customer with the exception of the electric business where power costs are not part of the decoupling mechanism. As a result, these electric and gas revenues will be recovered on a per customer basis regardless of actual consumption levels. The energy supply costs, which are part of the Power Cost Adjustment (PCA) and Purchased Gas Adjustment (PGA) mechanisms, are not included in the decoupling mechanism.

In the five-year period ended December 31, 2014, PSE’s gross electric utility plant additions were $3.7 billion and retirements were $409.3 million. In the same five-year period, PSE’s gross natural gas utility plant additions were $723.2 million and retirements were $96.6 million and PSE’s gross common utility plant additions were $390.7 million and retirements were $372.4 million. Gross electric utility plant at December 31, 2014 was approximately $9.3 billion, which consisted of 36.0% distribution, 41.8% generation, 14.0% transmission and 8.2% general plant and other. Gross natural gas utility plant at December 31, 2014 was approximately $3.3 billion, which consisted of 93.3% distribution and 6.7% general plant and other. Gross common utility general and intangible plant at December 31, 2014 was approximately $512.8 million.

EMPLOYEES

At December 31, 2014, Puget Energy had no employees and PSE had approximately 2,700 full-time employees. Approximately 1,100 PSE employees are represented by the United Association of Plumbers and Pipefitters (“UA”) and the International Brotherhood of Electrical Workers Union (“IBEW”). The current contracts with the UA and the IBEW expire on September 30, 2017 and March 31, 2017, respectively.

CORPORATE LOCATION

Puget Energy’s and PSE’s principal executive offices are located at 10885 NE 4th Street, Suite 1200, Bellevue, Washington 98004 and the telephone number is (425) 454-6363.

AVAILABLE INFORMATION

The information required by Item 101(e) of Regulation S-K is incorporated herein by reference to the material under “Where You Can Find More Information” in this prospectus.

REGULATION AND RATES

PSE is subject to the regulatory authority of: (1) the FERC with respect to the transmission of electricity, the sale of electricity at wholesale, accounting and certain other matters; and (2) the Washington Commission as to retail

 

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rates, accounting, the issuance of securities and certain other matters. PSE also must comply with mandatory electric system reliability standards developed by the NERC, the electric reliability organization certified by the FERC, which standards are enforced by the Western Electricity Coordinating Council in PSE’s operating territory.

ENERGY EFFICIENCY

PSE is required under Washington state law to pursue all available conservation that is cost-effective, reliable and feasible. 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 efficient choices with respect to building design, equipment and building systems, appliance purchases and operating practices. PSE recovers the actual costs of its electric and natural gas energy efficiency programs through rider mechanisms. However, the rider mechanisms do not provide for any cost recovery of lost sales margin associated with reduced energy sales. To address this issue, PSE received approval in 2013 from the Washington Commission for electric and gas decoupling mechanisms.

Since 1997, PSE has recovered direct electric energy efficiency (or conservation) expenditures through an electric rider mechanism. To recover gas expenditures, from 1997 to 2011, PSE used a tracker mechanism, which recovered actual gas expenditures in the year following the year in which the expenditures were incurred. In 2012, the Washington Commission directed PSE to convert gas expenditure recovery to a rider mechanism, consistent with the electric expenditure recovery methodology. The rider mechanism allows PSE to defer the efficiency expenditures and amortize them to expense as PSE collects them in rates over a one-year period.

ENVIRONMENT

PSE’s operations, including generation, transmission, distribution, service and storage facilities, are subject to environmental laws and regulations by federal, state and local authorities. The primary areas of environmental law that have the potential to most significantly impact PSE’s operations and costs include:

Air and Climate Change Protection

PSE owns numerous thermal generation facilities, including natural gas plants and an ownership percentage of a coal plant in Colstrip, Montana. All these facilities are governed by the Clean Air Act (“CAA”) and all have CAA Title V operation permits which must be renewed every five years. This renewal process could result in additional costs to the plants. PSE continues to monitor these developments to determine the corresponding potential impact to the plants. These facilities also emit greenhouse gases (“GHG”), and thus are also subject to any current or future GHG or climate change legislation or regulation. The Colstrip plant represents PSE’s most significant source of GHG emissions.

Species Protection

PSE owns hydroelectric plants, wind farms and numerous miles of above ground electric distribution and transmission lines which can be impacted by laws related to species protection. A number of species of fish have been listed as threatened or endangered under the Endangered Species Act (ESA), which influences hydroelectric operations, and may affect PSE operations, potentially representing cost exposure and operational constraints. Similarly, there are a number of avian and terrestrial species that have been listed as threatened or endangered under the ESA or are protected by the Migratory Bird Act. Designations of protected species under these two laws have the potential to influence operation of our wind farms and above ground transmission and distribution systems.

 

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Remediation of Contamination

PSE and its predecessors are responsible for environmental remediation at various sites. These include properties currently and formerly owned by PSE (or its predecessors), as well as third party owned properties where hazardous substances were allegedly generated, transported or released. The primary cleanup laws that PSE is subject to include the Comprehensive Environmental Response, Compensation and Liability Act (federal) and the Model Toxics Control Act (state). These laws may hold liable any current or past owner or operator of a contaminated site, as well as any generator, transporter, arranger, or disposer of regulated substances.

Hazardous and Solid Waste and PCB Handling and Disposal

Related to certain operations, including power generation and transmission and distribution maintenance, PSE must handle and dispose of certain hazardous and solid wastes. These actions are regulated by the Solid Waste Disposal Act, as amended by the Resource Conservation and Recovery Act (federal), the Toxic Substances Control Act (federal), and the dangerous waste regulations (state) that impose complex requirements on handling and disposing of regulated substances.

Water Protection

PSE facilities that discharge wastewater or storm water or store bulk petroleum products are governed by the Clean Water Act (federal and state) which includes the Oil Pollution Act amendments. This includes most generation facilities (and all those with water discharges and some with bulk fuel storage), and many other facilities and construction projects depending on drainage, facility or construction activities, and chemical, petroleum and material storage.

Siting New Facilities

In siting new generation, transmission, distribution or other related facilities, PSE is subject to the State Environmental Policy Act, and may be subject to the federal National Environmental Policy Act, if there is a federal nexus, in addition to other possible local siting and zoning ordinances. These requirements may potentially require mitigation of environmental impacts as well as other measures that can add significant cost to new facilities.

RECENT AND FUTURE ENVIRONMENTAL LAW AND REGULATION

Recent and future environmental laws and regulations may be imposed at a federal, state or local level and may have a significant impact on the cost of PSE operations. PSE monitors legislative and regulatory developments for environmental issues with the potential to alter the operation and cost of our generation plants, transmission and distribution system, and other assets. Described below are the recent, pending and potential future environmental law and regulations with the most significant potential impacts to PSE’s operations and costs.

Climate Change and Greenhouse Gas Emissions

PSE recognizes the growing concern that increased atmospheric concentrations of GHG contribute to climate change. PSE believes that climate change is an important issue that requires careful analysis and considered responses. As climate policy continues to evolve at the state and federal levels, PSE remains involved in state, regional and federal policymaking activities. PSE will continue to monitor the development of any climate change or climate change related air emission reduction initiative at the state and western regional level. PSE will also consider the known impact of any future legislation or new government regulation on the cost of generation in its IRP process.

On January 8, 2014, the Environmental Protection Agency (“EPA”) issued a proposed New Source Performance Standard (“NSPS”) for the control of carbon dioxide (“CO2”) from new power plants that burn fossil fuels under

 

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section 111(b) of the Clean Air Act. The EPA first proposed a NSPS for emissions for CO2 from new power plants in April 2012. However, after more than 2.5 million comments on the original proposal, the EPA decided that a new approach was warranted and rescinded the April 2012 proposal. The EPA is currently proposing an emissions limit for coal-fired sources of 1,100 lb. CO2/MWh, and proposes standards for natural gas combined cycle sources from 1,000 to 1,100 lb. CO2/MWh depending on the size and type of unit. Under the January 8, 2014 NSPS proposal, the Agency concluded that Carbon Capture and Storage (“CCS”) has been adequately demonstrated as a technology for controlling CO2 emissions in full-scale commercial applications at coal-fired electrical generating units (“EGUs”), while reaching the opposite conclusion, that CCS is not adequately demonstrated, in the case of gas-fired generators. PSE submitted comments by the end of the comment period on May 9, 2014. The EPA is expected to issue the final rule within the next 12 months. States have one year after the effective date of the standard to adopt the final rule.

On June 2, 2014, the EPA proposed guidelines under section 111(d) of the Clean Air Act for the control of CO2 emissions from existing fossil fuel-fired power plants. The proposed guidelines are estimated by the EPA to reduce total power sector carbon emissions 30% from 2005 levels by 2030 through the setting of individual emissions targets for each state. The EPA is applying its “best system of emission reductions” (“BSER”) approach for reducing CO2 emissions from the electric power sector, consisting of increasing the efficiency of power generation and substituting higher emitting plants with lower emitting technologies. The EPA is using the following four step approach to establish its reduction targets: (1) improving the heat rate of individual generating units, thereby reducing the amount of CO2 produced per unit of electricity generated, (2) prioritizing dispatch of existing (and new) natural gas combined cycle (“NGCC”) generation over coal-fired generation, (3) accounting for increasing renewable generation and nuclear generation that is under construction or will have extended life and (4) improving demand-side energy efficiency to reduce the amount of electricity generation required. States will be given the flexibility to choose the emissions reduction strategies best suited to their reduction requirements, and they can select technologies and techniques beyond what is defined in BSER, provided the emission reductions are verifiable and approved by the EPA. States must achieve their state-specific interim goal by 2025 and their state-specific final goal by 2030. PSE filed comments on this rule on December 1, 2014, which was the end of the comment period. The EPA initially stated that it will issue a final rule in June 2015 and that states must submit a plan for implementing CO2 reductions to the EPA one to three years following issuance of the final rule. Recently the EPA extended this timeframe and stated that it plans to issue the final 111(d) and 111(b) rules simultaneously in August 2015.

Each year, PSE is required to submit, on an annual basis, a report of its GHG emissions to the State of Washington including a report of emissions from all individual power plants emitting over 10,000 tons per year of GHGs and from certain natural gas distribution operations. Emissions exceeding 25,000 tons per year of GHGs from these sources must also be reported to the EPA. Capital investments to monitor GHGs from the power plants and in the distribution system are not required at this time. Since 2002, PSE has voluntarily undertaken an annual inventory of its GHG emissions associated with PSE’s total electric retail load served from a supply portfolio of owned and purchased resources. The most recent data indicate that PSE’s total GHG emissions (direct and indirect) from its electric supply portfolio in 2013 were 9.9 million tons of carbon dioxide equivalents. Approximately 41.4% of PSE’s total GHG emissions (approximately 4.1 million tons) are associated with PSE’s ownership and contractual interests in Colstrip.

While Colstrip remains a significant portion of PSE’s GHG emissions, Colstrip is an essential part of the existing diversified portfolio PSE owns and/or operates for its customers. Consequently, PSE’s overall emissions strategy demonstrates a concerted effort to manage customers’ needs with an appropriate balance of new renewable generation, existing generation owned and/or operated by PSE and significant energy efficiency efforts.

Mercury Emissions

Mercury control equipment has been installed at Colstrip and has operated at a level that meets the current Montana requirement. Compliance based on a rolling 12-month average was first confirmed in January 2011 and has continued to meet the requirement.

 

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The EPA published the final Mercury and Air Toxics Standard (MATS) in February 2012. Generating units have 3 years, until April 2015, to comply with MATS and could receive up to a 1-year extension from state permitting authorities if necessary for the installation of controls. Testing confirms that Colstrip currently meets the MATS limits for mercury and acid gases. Units 3 & 4 meet the particulate surrogate for other metals. Modifications to the Unit 1 & 2 scrubbers are required to meet the particulate limit in the MATS rule. PSE has installed sieve trays in three of the six scrubbers and will install them in the remaining scrubbers by 2016. Testing of the scrubbers subsequent to modification shows that it can meet the MATS particulate limit.

Additional Colstrip Emission Controls

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 (BART) requirements for electric generating units, including presumptive limits for sulfur dioxide, particulate matter and nitrogen oxide controls for large units. The final Federal Implementation Plan for Montana (“FIP”) for Regional Haze was issued in September 2012. There are no immediate requirements for Units 3&4, but Units 1&2 will need to upgrade pollution controls to meet new sulfur dioxide and nitrogen oxide limits. The Sierra Club filed an appeal of the FIP with the United States Court of Appeals for the Ninth Circuit (Ninth Circuit) on November 15, 2012 and PPL Montana also filed an appeal as the Colstrip operator. The case was heard on May 15, 2014 in Seattle, Washington and a final decision by the Ninth Circuit is still pending. PSE cannot at this time predict the impact of the matter on the Company.

Coal Combustion Residuals

On April 17, 2015, the U.S. Environmental Protection Agency (“EPA”) published a final rule, effective October 19, 2015, that regulates Coal Combustion Residuals (“CCR”) under the Resource Conservation and Recovery Act , Subtitle D. The CCR rule addresses the risks from coal ash disposal, such as leaking of contaminants into ground water, blowing of contaminants into the air as dust, and the catastrophic failure of coal ash surface impoundments by establishing technical requirements for CCR landfills and surface impoundments. The rule also sets out recordkeeping and reporting requirements including requirements to post specific information to a publicly-accessible website.

The CCR rule requires significant changes to the Company’s Colstrip operations and those changes were reviewed by the Company and the plant operator in the second quarter of 2015. PSE had previously recognized a legal obligation under EPA rules to dispose of coal ash material at Colstrip, in 2003. Due to the CCR rule, additional disposal costs were added to the asset retirement obligation.

PCB Handling and Disposal

On April 7, 2010, the EPA issued an Advance Notice of Proposed Rule Making (“ANPRM”) soliciting information on a broad range of questions concerning inventory, management, use, and disposal of polychlorinated biphenyl (“PCB”) containing equipment. The EPA is using this ANPRM to seek data to better evaluate whether to initiate a rulemaking process geared toward a mandatory phase-out of all PCBs.

The rule is currently scheduled to be published in July 2015. Because the EPA received extensive comments, the rule has undergone multiple extensions and revisions. At this point, PSE cannot determine what impacts this ANPRM will have on its operations, if any, but will continue to work closely with the Utility Solid Waste Activities Group (“USWAG”) and the American Gas Association (“AGA”) to monitor developments.

DESCRIPTION OF PROPERTY

The principal electric generating plants and underground natural gas storage facilities owned by PSE are described above in the section entitled “Business—Electric Supply and Gas Supply.” PSE owns its transmission

 

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and distribution facilities and various other properties. Substantially all properties of PSE are subject to the liens of PSE’s mortgage indentures. The Company’s corporate headquarters is housed in a leased building located in Bellevue, Washington.

LEGAL PROCEEDINGS

For details on legal proceedings, see the Litigation footnote in the notes to the consolidated financial statements included with this prospectus. Contingencies arising out of the normal course of PSE’s business existed as of June 30, 2015. Litigation is subject to numerous uncertainties and PSE is unable to predict the ultimate outcome of these matters.

CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE

None.

QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

Energy Portfolio Management

PSE maintains energy risk policies and procedures to manage commodity and volatility risks and the related effects on credit, tax, accounting, financing and liquidity. PSE’s Energy Management Committee establishes PSE’s risk management policies and procedures and monitors compliance. The Energy Management Committee is comprised of certain PSE officers and is overseen by the PSE Board of Directors.

PSE’s objective is to minimize commodity price exposure and risks associated with volumetric variability in the natural gas and electric portfolios and related effects. It is not engaged in the business of assuming risk for the purpose of speculative trading. PSE 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 PSE’s natural gas and power portfolios will perform under various weather, hydroelectric and unit performance conditions.

The nature of serving regulated electric customers with its 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. PSE’s natural gas retail customers are served by natural gas purchase contracts which expose PSE’s customers to commodity price risks through the PGA mechanism. All purchased natural gas costs are recovered through customer rates with no direct impact on PSE. Therefore, wholesale market transactions and related hedging strategies are focused on reducing costs and risks where feasible, thus reducing volatility in costs 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 forward physical electric and natural gas purchase and sale agreements, fixed-for-floating swap contracts, and commodity call/put options. The forward physical electric contracts are both fixed and variable (at index), while the physical natural gas contracts are variable. To fix the price of wholesale electricity and natural gas, PSE may enter into fixed-for-floating swap (financial) contracts. PSE also utilizes natural gas call and put options as an additional hedging instrument to increase the hedging portfolio’s flexibility to react to commodity price fluctuations. As of December 31, 2014, approximately 91% of these contracts, including NPNS transactions, are entered into with investment grade counterparties which, in the majority of cases, do not require collateral calls on the contracts.

 

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The following table presents the fair value of the Company’s energy derivatives instruments, recorded on the balance sheets:

 

Puget Energy and Puget Sound Energy		December 31, 2014								December 31, 2013
(Dollars in Thousands)		Assets				Liabilities				Assets				Liabilities
Electric portfolio:
Current		$	3,217			$	69,771			$	14,565			$	17,731
Long-term			1,605				37,457				3,914				19,581
Total electric derivatives		$	4,822			$	107,228			$	18,479			$	37,312
Natural Gas portfolio:
Current		$	17,961			$	66,202			$	4,302			$	23,734
Long-term			1,565				22,605				3,819				11,942
Total natural gas derivatives		$	19,526			$	88,807			$	8,121			$	35,676
Total energy derivatives		$	24,348			$	196,035			$	26,600			$	72,988

At December 31, 2014, the Company had total assets of $24.3 million and total liabilities of $196.0 million related to derivative contracts used to hedge the supply and cost of electricity and natural gas to serve PSE customers. As the gains and losses in the electric portfolio are realized, they will be recorded as either purchased power costs or electric generation fuel costs under the PCA mechanism. Any fair value adjustments relating to the natural gas business have been deferred in accordance with ASC 980, due to the PGA mechanism, which passes 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 natural gas costs under the PGA mechanism.

A hypothetical 10.0% increase or decrease in market prices of natural gas and electricity would change the fair value of the Company’s derivative contracts by $25.7 million.

The change in fair value of the Company’s outstanding energy derivative instruments from December 31, 2013 through December 31, 2014 is summarized in the table below:

 

Puget Energy and Puget Sound Energy Energy Derivative Contracts Gain (Loss)
(Dollars in Thousands)
Fair value of contracts outstanding at December 31, 2013		$	(46,388	)
Contracts realized or otherwise settled during 2014			(6,713	)
Change in fair value of derivatives			(118,586	)
Fair value of contracts outstanding at December 31, 2014		$	(171,687	)

The fair value of the Company’s outstanding derivative instruments at December 31, 2014, based on pricing source and the period during which the instrument will mature, is summarized below:

 

Puget Energy and Puget Sound Energy Source of Fair Value		Fair Value of Contracts by Settlement Year
(Dollars in Thousands)		2015				2016-2017				2018-2019				Thereafter				Total
Prices provided by external sources1		$	(113,636	)		$	(43,703	)		$	(248	)		$	—			$	(157,587	)
Prices based on internal models and valuation methods			(1,159	)			(11,210	)			(1,745	)			14				(14,100	)
Total fair value		$	(114,795	)		$	(54,913	)		$	(1,993	)		$	14			$	(171,687	)

 

1	Prices provided by external pricing service, which utilizes broker quotes and pricing models.

 

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For further details regarding both the fair value of derivative instruments and the impacts such instruments have on current period earnings, see Notes 9 and 10 to the consolidated financial statements.

Contingent Features and Counterparty Credit Risk

PSE 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. PSE manages credit risk with policies and procedures for, among other things, counterparty analysis and measurement, monitoring and mitigation of exposure.

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: WSPP, Inc. (“WSPP”) agreements which standardize physical power contracts in the electric industry; International Swaps and Derivatives Association (“ISDA”) agreements which standardize financial gas and electric contracts; and North American Energy Standards Board (“NAESB”) agreements which standardize physical gas contracts. PSE believes that entering into such agreements reduces the credit risk exposure because such agreements provide for the netting and offsetting of monthly payments as well as right of set-off in the event of counterparty default. It is possible that volatility in energy commodity prices could cause PSE to have material credit risk exposures with one or more counterparties. If such counterparties fail to perform their obligations under one or more agreements, PSE could suffer a material financial loss.

Where deemed appropriate, and when allowed under the terms of the agreements, 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, 2014, PSE held approximately $1.0 billion in standby letters of credit or limited parental guarantees and had 11 counterparties with unlimited parental guarantees, in support of various electric and natural gas transactions. 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 may impact PSE’s decisions on derivative accounting treatment.

Should a counterparty file for bankruptcy, which would 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 terminations receivable or payable, based on the terms of existing master agreements. The Company computes credit reserves at a master agreement level by counterparty (i.e., WSPP, ISDA or NAESB). 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 Standard & Poor’s 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 determined by weighting the fair value and contract tenors for all deals for each counterparty and arriving at 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. The Company 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 credit and non-performance reserves. As of December 31, 2014, the Company was in a net liability position with the majority of its counterparties, therefore the default factors of counterparties did not have a significant impact on reserves for the year. As of December 31, 2014, PSE has posted a $1.0 million letter of credit as a condition of transacting on a physical energy exchange and clearinghouse in Canada. PSE did not trigger any collateral requirements with any of its counterparties, nor were any of PSE’s counterparties required to post additional collateral resulting from credit rating downgrades.

 

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Interest Rate Risk

The Company believes its interest rate risk primarily relates to the use of short-term debt instruments, variable-rate leases and anticipated long-term debt financing needed to fund capital requirements. The Company manages its interest rate risk through the issuance of mostly fixed-rate debt of various maturities. The Company utilizes internal cash from operations, borrowings under its commercial paper program, and its credit facilities to meet short-term funding needs. Short-term obligations are commonly refinanced with fixed-rate bonds or notes when needed and when interest rates are considered favorable.

The following table presents the carrying value and fair value of Puget Energy and Puget Sound Energy’s debt instruments:

 

Financial Debt Instruments		December 31, 2014								December 31, 2013
(Dollars in Thousands)		Carrying Amount				Fair Value				Carrying Amount				Fair Value
Puget Energy		$	5,328,608			$	6,743,789			$	5,394,476			$	6,324,680
Puget Sound Energy		$	3,877,192			$	4,827,641			$	3,954,856			$	4,499,419

For further details regarding Puget Energy and Puget Sound Energy debt instruments, see Notes 6 and 10 to the financial statements included herein.

From time to time, PSE may enter into treasury locks 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, 2014 was a net loss of $6.0 million after tax and accumulated amortization. This compares to an after-tax loss of $6.3 million in OCI as of December 31, 2013. All financial hedge contracts of this type are reviewed by an officer, presented to the Board of Directors, or a committee of the Board, as applicable and are approved prior to execution. PSE had no treasury locks or forward starting swap contracts outstanding at December 31, 2014.

The Company may also enter into swap instruments or other financial hedge instruments to manage the interest rate risk associated with these debts. As of December 31, 2014, Puget Energy had two interest rate swap contracts outstanding and PSE did not have any outstanding interest rate swap instruments. At December 31, 2014, the fair value of the interest rate swaps was a $9.1 million pre-tax loss. The fair value considers the risk of Puget Energy’s non-performance by using its incremental borrowing rate on unsecured debt over the risk-free rate in the valuation estimate. Currently, all changes in market value are recorded in earnings.

A hypothetical 10% increase or decrease in interest rates would change the fair value of Puget Energy’s interest rate swaps by $0.8 million.

The following table presents the fair value of Puget Energy’s interest rate swaps:

 

Puget Energy		December 31, 2014								December 31, 2013
(Dollars in Thousands)		Assets				Liabilities				Assets				Liabilities
Interest rate swaps:
Current		$	—			$	6,222			$	—			$	6,584
Long-term			—				2,851				—				6,639
Total interest rate swaps		$	—			$	9,073			$	—			$	13,223

 

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The change in fair value of Puget Energy’s outstanding interest rate swaps from December 31, 2013 through December 31, 2014 is summarized in the table below:

 

Puget Energy Interest Rate Swap Contracts Gain (Loss)
(Dollars in Thousands )
Fair value of contracts outstanding at December 31, 2013		$	(13,223	)
Contracts realized or otherwise settled during 2014			2,396
Change in fair value of derivatives			1,754
Fair value of contracts outstanding at December 31, 2014		$	(9,073	)

The fair value of Puget Energy’s outstanding interest rate swaps at December 31, 2014, based on pricing source and the period during which the instrument will mature, is summarized below:

 

Source of Fair Value		Fair Value of Contracts by Settlement Year
(Dollars in Thousands)		2015				2016				2017				Total
Prices provided by external sources1		$	(6,222	)		$	(2,798	)		$	(53	)		$	(9,073	)

 

1	Prices provided by external pricing service, which may utilize broker quotes and internal pricing models. Significant pricing inputs are based on observable market data.

DESCRIPTION OF NOTES

General

We will issue the exchange notes under an indenture dated as of December 6, 2010, between us and Wells Fargo Bank, N.A., as trustee, and the fourth supplemental indenture, dated as of May 12, 2015, also between us and Wells Fargo Bank, N.A., as trustee. We refer to the indenture and the third supplemental indenture as the “indenture.” The terms of the Notes include those stated in the indenture and those made part of the indenture by reference to the Trust Indenture Act of 1939 (the “Trust Indenture Act”).

The following description is only a summary of the material provisions of the indenture and the Collateral Documents relating to the Notes and does not purport to be complete. We urge you to read the indenture and such Collateral Documents because they, and not this description, will define your rights as holders of the Notes. You may request copies of the proposed form of the indenture and the Collateral Documents as described under “Where You Can Find More Information.”

The Notes will:

 

•

be our senior secured obligations;

 

•

rank pari passu in right of payment, to the extent of the value of the Collateral securing the Notes, with all of our existing and future senior secured obligations;

 

•

be senior in right of payment to any of our future subordinated indebtedness; and

 

•

be structurally subordinated to all existing and future indebtedness and other liabilities (including trade payables) of our subsidiaries, including PSE.

Except as described below under “—Certain Covenants—Limitation on Liens,” the indenture does not limit our ability to incur other indebtedness or to issue other securities, including other series of debt securities.

 

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The Notes will be denominated in U.S. dollars and principal and interest will be paid in U.S. dollars. We will issue the Notes in denominations of $2,000 and integral multiples of $1,000 in excess thereof. The Notes will not be subject to any conversion, amortization or sinking fund. You will not have the right to require us to redeem or repurchase the Notes at your option.

The Notes will not be guaranteed by, or otherwise be obligations of, our parent company, any of its direct or indirect subsidiaries other than us, or the members of the consortium that own our parent company, and will not be guaranteed by any of our affiliates.

Because we are a holding company, our rights and the rights of our creditors, including holders of the Notes, in respect of claims on the assets of our subsidiary, PSE, upon any liquidation or administration are structurally subordinated to, and therefore will be subject to the prior claims of PSE’s creditors (including trade creditors of and holders of debt issued by PSE). At September 30, 2015, PSE had total long-term debt and current liabilities of approximately $4.5 billion, all of which would be effectively senior to the Notes.

Our ability to pay interest on the Notes is dependent upon the receipt of dividends and other distributions from PSE. The availability of distributions from PSE is subject to the satisfaction of various covenants and conditions contained in PSE’s existing and future financing documents.

In the discussion that follows, “Puget Energy,” “the Company,” “we,” “us” and “our” refer only to Puget Energy, Inc., and any successor obligor on the Notes, and not to PSE or any other subsidiary of ours. References to paying principal on the Notes are to payment at maturity or redemption.

Definitions of certain defined terms used in this “Description of Notes” section but not defined below have the meanings assigned to them under “—Definitions.”

Principal, Maturity and Interest

The Notes initially will be issued in an aggregate principal amount of $400 million. The Notes will bear interest at the rate of 3.650% per year and will mature on May 15, 2025. Interest will be payable on the Notes semiannually on May 15 and November 15 of each year, beginning on November 15, 2015, until the principal is paid or made available for payment. Interest on the Notes will accrue from the most recent date to which interest has been paid or, if no interest has been paid, from the date of issuance. Payment of interest on the Notes will be made to the person in whose name such Notes are registered at the close of business on the May 1 and November 1 immediately preceding the relevant interest payment date. Interest will be computed based on a 360-day year consisting of twelve 30-day months. If any date on which interest is payable on the Notes is not a business day, then payment of the interest payable on that date will be made on the next succeeding day which is a business day (and without any additional interest or other payment in respect of any delay), with the same force and effect as if made on such date. If there has been a default in the payment of interest on any Note, such defaulted interest may be payable to the holder of such Note as of the close of business on a date selected by the trustee which is not more than 30 days and not less than 10 days before the date proposed by the Company for payment of such defaulted interest or in any other lawful manner, if the trustee deems such manner of payment practicable.

Payment of principal of the Notes will be made against surrender of such Notes at the corporate trust office of the trustee in Minneapolis, Minnesota, as paying agent for us. We may change the paying agent at our discretion. For so long as the Notes are issued in book-entry form, payments of principal and interest shall be made in immediately available funds by wire transfer to The Depository Trust Company, or “DTC”, or its nominee.

All amounts paid by us for the payment of principal, premium (if any) or interest on any Notes that remain unclaimed at the end of two years, or prior to the applicable escheat date, after such payment has become due and payable will be repaid to us and the holders of such Notes will thereafter look only to us for payment thereof.

 

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Form and Denomination; Registration and Transfer

The Notes will be issued in fully registered form only in denominations of $2,000 and integral multiples of $1,000 in excess thereof. We will initially issue the Notes in global book-entry form. So long as the Notes are in book-entry form, transfers and exchanges will be registered on the records of the depositary or its participants. If the Notes are issued in certificated form, holders of Notes may register the transfer of Notes, and may exchange Notes for other Notes of the same series and tranche, of authorized denominations and having the same terms and aggregate principal amount, at the corporate trust office of Wells Fargo Bank, N.A., as security registrar for the Notes. We may change the place for registration of transfer and exchange of the Notes, may appoint one or more additional security registrars (including us) and may remove any security registrar, all at our discretion. No service charge will be made for any transfer or exchange of the Notes, but we may require payment of a sum sufficient to cover any tax or other governmental charge that may be imposed in connection with any registration of transfer or exchange of the Notes. We will not be required to execute or provide for the registration of transfer of or the exchange of (a) any Note during a period of 15 days before giving any notice of redemption or (b) any Note selected for redemption in whole or in part, except the unredeemed portion of any Note being redeemed in part. See “—Book-Entry; Delivery and Form.”

Further Issuances

The Notes initially will be limited to $400 million in aggregate principal amount. We may, from time to time, without notice to or the consent of the holders of the Notes, create and issue additional debt securities under the indenture having the same terms as, and ranking equally with, the Notes in all respects (except for the offering price and issue date), provided that such debt securities are fungible with the previously issued and outstanding debt securities for U.S. federal income tax purposes. The Notes offered hereby and any such further Notes subsequently issued under the indenture will be treated as a single class for all purposes under the indenture, including, without limitation, waivers, amendments, redemptions and offers to purchase.

Ranking

The Notes will:

 

•

be our senior secured obligations;

 

•

rank pari passu in right of payment, to the extent of the value of the Collateral securing the Notes, with all of our existing and future senior secured indebtedness (as of the date hereof, our obligations under our senior secured credit facility and our existing senior secured notes constitute our only other senior secured indebtedness);

 

•

be senior in right of payment to any of our future subordinated indebtedness; and

 

•

be structurally subordinated to all existing and future indebtedness and other liabilities (including trade payables) of our subsidiaries, including PSE.

Because we are a holding company and substantially all of our operations are conducted by our subsidiaries (principally PSE), holders of our debt securities, including holders of the Notes, will have a junior position to claims of creditors and certain security holders of our subsidiaries, including trade creditors, debt holders, secured creditors, taxing authorities and guarantee holders. To the extent that we may be a creditor with recognized claims against any of our subsidiaries, our claims would also effectively be subordinated to any security interest in, or mortgages or other liens on, the assets of our subsidiaries and would be subordinated to any indebtedness or other liabilities of our subsidiaries senior to our interest. Certain of our operating subsidiaries, principally PSE, have ongoing corporate debt programs used to finance their business activities. As of September 30, 2015, PSE had approximately $3.8 billion of outstanding debt. We and PSE retain the ability to incur substantial additional indebtedness and other liabilities. Moreover, our ability to pay principal and interest on the Notes is dependent upon the earnings of our subsidiaries and the distribution or other payments from our

 

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subsidiaries to us in the form of dividends, loans, advances or the repayment of loans and advances from us. The indenture does not contain any limitation on our ability to incur additional debt or on our subsidiaries’ ability to incur additional debt to us or to third parties. In addition, we lend funds to our subsidiary PSE from time to time through a demand promissory note.

No Guarantees

The Notes will not be guaranteed by any of our subsidiaries or other affiliates. Because the Notes will not be guaranteed by our subsidiaries, the Notes will be structurally subordinated to all existing and future liabilities of our subsidiaries. See “—Ranking” above.

Security

General

The Notes will be secured by liens (subject to Permitted Liens) on the same assets that secure our other Secured Obligations, including our Credit Agreement Obligations, which assets currently consist of: (a) subject to certain exceptions, substantially all of our tangible and intangible assets, other than real property, including 100% of the equity interests of PSE (the “Pledged PSE Stock”) and (b) 100% of the equity interests of Puget Energy, Inc., which are owned by our parent, Puget Equico LLC (the “Pledged Puget Energy Stock” and, collectively with the Pledged PSE Stock, the “Pledged Stock”).

The Collateral will exclude certain of our assets as more specifically set forth in the Collateral Documents, including without limitation, any lease, license, contract or agreement to which we are a party, and any of our rights or interests thereunder, if and to the extent that a security interest is prohibited by or in violation of (a) any law, rule or regulation applicable to us, or (b) a term, provision or condition of any such lease, license, contract, property right or agreement (unless such law, rule, regulation, term, provision or condition would be rendered ineffective with respect to the creation of the security interest under the Collateral Agreements pursuant to Sections 9-406, 9-407, 9-408 or 9-409 of the Uniform Commercial Code (or any successor provision or provisions) of any relevant jurisdiction or any other applicable law (including the U.S. Bankruptcy Code) or principles of equity).

Under the terms of the Collateral Agency Agreement, the Collateral securing the Notes will be shared equally and ratably (subject to Permitted Liens) with the liens securing other Secured Obligations, which includes the Credit Agreement Obligations, the existing senior secured note obligations and any future Additional Secured Obligations. As of the date hereof, obligations under our senior secured credit facility and our existing senior secured notes constitute our only other Secured Obligations.

Pursuant to the indenture and the Collateral Documents relating to the Notes, substantial additional Indebtedness may, without the consent of holders, constitute Secured Obligations. So long as any Credit Agreement Obligations remain outstanding and a Majority Non-Controlling Voting Party Enforcement Date has not occurred, the Authorized Representative for our senior secured credit facility will have the right to control the remedies with respect to the Collateral. See “—Collateral Agency Agreement.” Such rights, if exercised, could adversely affect the value of the Collateral on behalf of the holders of the Notes. We will also be able to incur additional Secured Obligations and other Indebtedness and obligations secured by Permitted Liens. The amount of such obligations could be significant. The existence of any Permitted Liens could adversely affect the value of the Collateral securing the Notes, as well as the ability of the collateral agent to realize or foreclose on such Collateral. Your rights to the Collateral would be diluted by any increase in the obligations secured by such Collateral.

 

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Sufficiency of Collateral

The Collateral has not been appraised in connection with this offering. The value of the Collateral and the amount to be received upon a sale of the Collateral will depend upon many factors including, among others, the condition of the Collateral and of the electric transmission, distribution and generation and natural gas distribution industries, the ability to sell the Collateral in an orderly sale, the condition of the international, national and local economies, the availability of buyers and similar factors. The book value of the Collateral should not be relied on as a measure of realizable value for these assets. By their nature, portions of the Collateral are illiquid and may have no readily ascertainable market value. In addition, a significant portion of the Collateral includes assets that may only be usable, and thus retain value, as part of our existing business operations. Accordingly, any sale of such assets separate from the sale of our business operations may not be feasible or of significant value.

We and Puget Equico have limited obligations to perfect the security interest of the holders in certain specified Collateral. For example, the collateral agent and the other Authorized Representatives under the Collateral Agency Agreement may not have control over, and hence will not have a perfected security interest in, any of our deposit accounts.

After-acquired Collateral

From and after the issue date and subject to certain limitations and exceptions, if we acquire, or Puget Equico acquires, any property or asset that would constitute Collateral, pursuant to the terms of the Collateral Documents relating to the Notes, holders of the Notes will obtain a lien (subject to Permitted Liens) upon such property or asset as security for the Notes. However, there can be no assurance that the trustee or the collateral agent will monitor, or that we or Puget Equico will inform the trustee or the collateral agent of, the future acquisition of property and rights that constitute Collateral, and that the necessary actions will be taken to properly perfect the security interest in such after-acquired property.

Foreclosure

Upon the occurrence and during the continuance of an Event of Default, the Collateral Agency Agreement provides for (among other available remedies) the foreclosure upon and sale of the applicable Collateral by the collateral agent, at the direction of the Controlling Authorized Representative and the Required Voting Parties, and the distribution of the net proceeds of any such sale to the holders of Secured Obligations, including the holders, on a pro rata basis. In the event of foreclosure on the Collateral, the proceeds from the sale of the Collateral may not be sufficient to satisfy in full our obligations under the Notes. Pursuant to the Collateral Agency Agreement, only the collateral agent, acting at the direction of the Controlling Authorized Representative and the Required Voting Parties may exercise remedies with respect to the Liens securing Secured Obligations. The Credit Agreement Administrative Agent will be the Controlling Authorized Representative for so long as any Credit Agreement Obligations are secured by the Collateral and thereafter the Authorized Representative for the holders of the largest class of outstanding Secured Obligations will be the Controlling Authorized Representative. Accordingly, holders may not ever have the right to control the remedies and the taking of other actions related to the Collateral.

Regulatory considerations may affect the ability of the collateral agent to exercise certain rights with respect to the Pledged Stock upon the occurrence of an Event of Default. Because PSE is a regulated public utility, such foreclosure proceedings, the enforcement of the Collateral Documents and the right to take other actions with respect to the Pledged Stock may be limited and subject to regulatory approval. PSE is subject to regulation at the state level by the Washington Commission. At the federal level, it is subject to regulation by the FERC. See “Business—Regulation and Rates” in our Annual Report on Form 10-K for the year ended December 31, 2014. Regulation by the Washington Commission and the FERC includes regulation with respect to the change of control, transfer or ownership of utility property. In particular, such foreclosure proceedings, the enforcement of

 

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the pledge agreement and the right to take other actions or exercise other remedies with respect to the Pledged Stock could require approval by the FERC and/or the Washington Commission. There can be no assurance that any such regulatory approval can be obtained on a timely basis, or at all.

Certain bankruptcy limitations

The right and ability of the collateral agent to repossess and dispose of the Collateral upon the occurrence of an Event of Default would be significantly impaired by applicable bankruptcy law in the event that a bankruptcy case were to be commenced by or against us or Puget Equico prior to the collateral agent having repossessed and disposed of the Collateral. Upon the commencement of a case for relief under the U.S. Bankruptcy Code, a secured creditor such as the collateral agent is prohibited from repossessing collateral from a debtor in a bankruptcy case, or from disposing of collateral repossessed from a debtor, without bankruptcy court approval.

In view of the broad equitable powers of a U.S. bankruptcy court, it is impossible to predict how long payments under the Notes could be delayed following commencement of a bankruptcy case, whether or when the collateral agent could repossess or dispose of the Collateral, the value of the Collateral at the time of the bankruptcy petition or whether or to what extent holders would be compensated for any delay in payment or loss of value of the Collateral. The U.S. Bankruptcy Code permits only the payment and/or accrual of post-petition interest, costs and attorneys’ fees to a secured creditor during a debtor’s bankruptcy case to the extent the value of the Collateral is determined by the bankruptcy court to exceed the aggregate outstanding principal amount of the obligations secured by the Collateral.

Furthermore, in the event a bankruptcy court determines that the value of the Collateral is not sufficient to repay all amounts due on the Notes, the holders would hold secured claims only to the extent of the value of the Collateral, and unsecured claims with respect to any shortfall.

Any future pledge of Collateral in favor of the collateral agent, including pursuant to Collateral Documents relating to the Notes delivered after the date of the indenture, might be voidable by the pledgor (as debtor-in-possession) or by its trustee in bankruptcy if certain events or circumstances exist or occur, including, among others, if the pledgor is insolvent at the time of the pledge, the pledge permits the holders of the Notes to receive a greater recovery than if the pledge had not been given and a bankruptcy proceeding in respect of the pledgor is commenced within 90 days following the pledge, or, in certain circumstances, a longer period.

See “Risk Factors—Risks Relating to the Notes—Rights of Holders in the Collateral may be adversely affected by bankruptcy proceedings” and “Risk Factors—Risks Relating to the Notes—Any future pledge of Collateral might be voidable in bankruptcy.”

Certain covenants with respect to the Collateral

The Collateral will be pledged pursuant to the Collateral Documents, which contain provisions relating to identification of the Collateral and the maintenance of perfected Liens securing obligations under the Notes. The following is a summary of some of the covenants and provisions set forth in the Collateral Documents relating to the Notes and the indenture as they relate to the Collateral.

The Collateral Documents provide that as necessary, or upon reasonable request of the collateral agent, we and Puget Equico shall, at our and Puget Equico’s sole expense, execute, acknowledge and deliver such documents and instruments and take such other actions, which may be necessary, or as the collateral agent may reasonably request, to perfect and protect any pledge or security interest granted or purported to be granted by the Collateral Documents, including with respect to after-acquired Collateral, to the extent required thereunder.

The Collateral Documents provide that we will (a) cause PSE not to issue any equity interests in addition to or in substitution for the equity interests issued by PSE, except to us, and (b) pledge, immediately upon our acquisition (directly or indirectly) thereof, any and all additional equity interests issued to us by PSE.

 

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Collateral Agency Agreement

The trustee has signed a joinder to the Collateral Agency Agreement as Authorized Representative for the holders of all notes issued under the indenture, including the Notes. The Collateral Agency Agreement governs the rights of the holders of Secured Obligations, including the holders, with respect to the Collateral, and may be amended from time to time without the consent of the trustee or the holders to add other parties holding Additional Secured Obligations permitted to be incurred under the indenture, our senior secured credit facility, any other Security Documents and the Collateral Agency Agreement.

Under the Collateral Agency Agreement, only the Controlling Authorized Representative has the right to instruct the collateral agent to commence any judicial or nonjudicial foreclosure proceedings with respect to, seek to have a trustee, receiver, liquidator or similar official appointed for or over, attempt any action to take possession of, exercise any right, remedy or power with respect to, or otherwise take any action to enforce its security interest in or realize upon, or take any other action available to it in respect of, any Collateral, whether under any Security Document, applicable law or otherwise. Only the collateral agent, acting on the instructions of the Controlling Authorized Representative or the Required Voting Parties and in accordance with the applicable Security Documents, is entitled to take any such actions or exercise any such remedies with respect to the Collateral and the Authorized Representatives of all other classes of Secured Obligations have no right to instruct the collateral agent or otherwise to take actions with respect to the Collateral except as described below, even though all holders of Secured Obligations will share equally and ratably in the proceeds. The Controlling Authorized Representative will initially be the Credit Agreement Administrative Agent. The trustee, who will act as Authorized Representative in respect of the Notes, will have no rights to take any action under the Collateral Agency Agreement except as described below.

The Credit Agreement Administrative Agent will be the Controlling Authorized Representative for so long as any Credit Agreement Obligations are secured by the Collateral and thereafter, the Controlling Authorized Representative will be the Authorized Representative of the class of Secured Obligations that constitutes the largest outstanding principal amount of any then-outstanding class of Secured Obligations with respect to the Collateral; provided, in each case, that if there occurs one or more Majority Non-Controlling Voting Party Enforcement Dates, the Controlling Authorized Representative will be the Authorized Representative representing the largest principal amount of Secured Obligations then outstanding.

The “Majority Non-Controlling Voting Party Enforcement Dates” is, with respect to any Series of Secured Obligations, the date which is 90 days (throughout which 90-day period such Series of Secured Obligations was the Series constituting the Majority Non-Controlling Voting Parties) after the occurrence of both (a) an Event of Default (under and as defined in the Credit Document applicable to such Majority Non-Controlling Voting Parties) and (b) the collateral agent’s and each other Authorized Representative’s receipt of written notice from the Authorized Representative for the Majority Non-Controlling Voting Parties certifying that (i) the holders of such Series of Secured Obligations are the Majority Non-Controlling Voting Parties and that an Event of Default (under and as defined in the Credit Document applicable to such Majority Non-Controlling Voting Parties) has occurred and is continuing and (ii) the Secured Obligations of such Series are currently due and payable in full (whether as a result of acceleration thereof or otherwise) in accordance with the terms of the applicable Credit Document governing the Series for such Majority Non-Controlling Voting Parties; provided that such 90-day period will be stayed and the Majority Non-Controlling Voting Party Enforcement Date will be stayed and shall not occur and will be deemed not to have occurred with respect to any Collateral (A) at any time the collateral agent has commenced and is diligently pursuing any enforcement action with respect to such Collateral or (B) at any time we are, or Puget Equico or any grantor which has granted a security interest in such Collateral is, then a debtor under or with respect to any Insolvency or Liquidation Proceeding.

Only the collateral agent will act with respect to the Collateral. Only the Controlling Authorized Representative and the Required Voting Parties will have the right to instruct the collateral agent to act or refrain from acting with respect to the Collateral. No representative of any non-controlling secured party may contest, protest or

 

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object to any foreclosure proceeding or action brought by the collateral agent or any other exercise by the collateral agent of any rights and remedies relating to the Collateral or cause the collateral agent to do so. The foregoing shall not be construed to limit the rights and priorities of any Secured Party or Authorized Representative with respect to any property not constituting Collateral. Neither the collateral agent nor any other Authorized Representative will accept any Lien on any Collateral other than pursuant to the Collateral Documents.

If an event of default has occurred and is continuing under any Credit Document and the collateral agent is taking action to enforce rights in respect of any Collateral, or any distribution is made with respect to any Collateral in any bankruptcy proceeding of us or Puget Equico or any Secured Party receives any payment pursuant to any Security Documents (other than the Collateral Agency Agreement) with respect to any Collateral, the proceeds of any sale, collection or other liquidation of any such Collateral by any Secured Party or received by the collateral agent or any other Secured Party pursuant to any such Credit Document with respect to such Collateral and proceeds of any such distribution (subject, in the case of any such distribution, to the paragraph immediately following) to which the Secured Obligations are entitled under any agreement (other than the Collateral Agency Agreement) will be applied pursuant to the Collateral Agency Agreement in the following order of priority:

 

•

First, to the payment of the costs and expenses of such exercise of remedies, including reasonable out-of-pocket costs and expenses of the Agents, the reasonable fees and expenses of their agents and counsel and all other reasonable expenses incurred and advances made by the Agents in that connection;

 

•

Next, to the payment in full of the remaining Secured Obligations equally and ratably in accordance with their respective amounts then due and owing in respect of the Credit Documents, or as the Secured Parties holding the same may otherwise unanimously agree; and

 

•

Finally, subject to the rights of any other holder or holders of any Lien on the relevant Collateral, to the payment to us, or our respective successors or assigns, or as a court of competent jurisdiction may direct, of any surplus then remaining.

Holders of Secured Obligations of each class (and not the Secured Parties of any other class) bear the risk of any determination by a court of competent jurisdiction that (a) any of the Secured Obligations of such class are unenforceable under applicable law or are subordinated to any other obligations (other than another class of Secured Obligations) and (b) any of the Secured Obligations of such class do not have an enforceable security interest in any of the Collateral securing any other class of Secured Obligations.

In any Insolvency or Liquidation Proceeding and prior to the Discharge of Secured Obligations, the collateral agent (acting at the direction of the Required Voting Parties) on behalf of all Secured Parties and Authorized Representatives, may consent to any order: (a) for use of cash collateral; (b) approving a debtor-in-possession financing secured by a Lien upon any property of the estate in such Insolvency or Liquidation Proceeding; (c) granting any relief on account of Secured Obligations as adequate protection (or its equivalent) for the benefit of the Secured Parties in the Collateral subject to Liens granted to the collateral agent, for the benefit of the Secured Parties; or (d) relating to a sale of our assets or assets of Puget Equico that provides, to the extent the Collateral sold is to be free and clear of Liens, that all Liens granted to the collateral agent, for the benefit of the Secured Parties will attach to the proceeds of the sale; provided, however, that any Secured Party will retain the right to object to any cash collateral, debtor-in-possession financing or adequate protection order to the extent such order provides for priming of Liens over any Collateral if the terms thereof, including the terms of adequate protection (if any) granted to the Secured Parties in connection therewith, do not provide for materially equal treatment to all Secured Parties.

Unless at the direction of, or as consented to by, the Required Voting Parties, the Secured Parties will not file or prosecute in any Insolvency or Liquidation Proceeding any motion for adequate protection (or any comparable request for relief) based upon their interest in the Collateral under the Liens granted to the collateral agent, for the

 

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benefit of the Secured Parties, except that, without any action by the Required Voting Parties, they may vote their claims in respect of the Series of Secured Obligations owed to them in connection with, and have their right to object to, the confirmation of any plan of reorganization or similar dispositive restructuring plan to the extent any such action is not inconsistent with their obligations under the Collateral Agency Agreement.

If any Secured Party is required in any Insolvency or Liquidation Proceeding or otherwise to turn over or otherwise pay to the estate of Puget Equico or us for any reason, including without limitation, because it was found to be a fraudulent or preferential transfer, any amount paid in respect of the Secured Obligations, whether received as proceeds of security, enforcement of any right of set-off or otherwise, then such Secured Party will be entitled to a reinstatement of the Secured Obligations with respect to all such recovered amounts. In such event, (a) the Discharge of Secured Obligations or Discharge of Credit Agreement Obligations, as applicable, will be deemed not to have occurred, and (b) if the Collateral Agency Agreement has been terminated prior to such recovery or avoidance action, the Collateral Agency Agreement will be reinstated in full force and effect, and such prior termination will not diminish, release, discharge, impair or otherwise affect the obligations of the parties thereto from such date of reinstatement.

Each Secured Party, including the holders and the trustee, agrees that (a) it will not challenge or question in any proceeding the validity or enforceability of any Secured Obligations of any Series or any Credit Document or the validity, attachment, perfection or priority of any Lien under any Security Document or the validity or enforceability of the priorities, rights or duties established by or other provisions of the Collateral Agency Agreement; (b) it will not take or cause to be taken any action the purpose or intent of which is, or could be, to interfere, hinder or delay, in any manner, whether by judicial proceedings or otherwise, any sale, transfer or other disposition of the Collateral by the collateral agent, (c) except in accordance with the Collateral Agency Agreement, it will have no right to direct the collateral agent or any other Secured Party to exercise any right, remedy or power with respect to any Collateral unless such Secured Party is the Controlling Authorized Representative, (d) it will not institute any suit or assert in any suit, bankruptcy, insolvency or other proceeding any claim against the collateral agent or any other Secured Party seeking damages from or other relief by way of specific performance, instructions or otherwise with respect to any Collateral, and none of the collateral agent, any Controlling Authorized Representative or any other Secured Party will be liable for any action taken or omitted to be taken by the collateral agent, such Controlling Authorized Representative or other Secured Party with respect to any Collateral in accordance with the provisions of the Collateral Agency Agreement, (e) it will not seek, and hereby waives any right, to have any Collateral or any part thereof marshalled upon any foreclosure or other disposition of such Collateral, (f) it will not attempt, directly or indirectly, whether by judicial proceedings or otherwise, to challenge the enforceability of any provision of the Collateral Agency Agreement, and (g) it will not (and shall waive any right to) contest or support any other person in contesting, in any proceeding (including any Insolvency or Liquidation Proceeding), the perfection, priority, validity or enforceability of a Lien held by the collateral agent on behalf of any of the Secured Parties in all or any part of the Collateral, or the provisions of the Collateral Agency Agreement.

Notwithstanding the foregoing, a Secured Party will not be prohibited from taking the following actions: (a) in any Insolvency or Liquidation Proceeding commenced by or against us or Puget Equico, each Secured Party may file a claim or statement of interest with respect to its Series of Secured Obligations, as applicable, (b) each Authorized Representative may take and may direct the collateral agent to take any action (not adverse to the Liens of the collateral agent securing the Secured Parties) in order to preserve or protect its interest in and Liens created by the Security Documents on the Collateral, (c) the Secured Parties will be entitled to file any necessary responsive or defensive pleadings in opposition to any motion, claim, adversary proceeding or other pleading made by any person objecting to or otherwise seeking the disallowance of their claims, including any claims secured by the Collateral, if any, (d) in any Insolvency or Liquidation Proceeding, the Secured Parties will be entitled to file any pleadings, objections, motions or agreements which assert rights or interests available to unsecured creditors of Puget Equico or us arising under either Debtor Relief Laws or applicable non-bankruptcy law, in each case not in contravention of the terms of the Collateral Agency Agreement, (e) in any Insolvency or Liquidation Proceeding, the Secured Parties will be entitled to vote on any plan of reorganization and (f) both

 

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before and during an Insolvency or Liquidation Proceeding, any Secured Party may take any actions and exercise any and all rights that would be available to a holder of unsecured claims, including, without limitation, the commencement of an Insolvency or Liquidation Proceeding against us or Puget Equico in accordance with applicable law and the termination of any agreement by the holder of any such obligation in accordance with the terms thereof.

Each Secured Party agrees that if it obtains possession of any Collateral or realizes any proceeds or payment in respect of any such Collateral pursuant to any Collateral Document or by the exercise of any rights available to it under applicable law or in any insolvency or liquidation proceeding or through any other exercise of remedies at any time prior to the Discharge of each of the Secured Obligations (determined, solely for this purpose, as if the Secured Obligations owing to such Secured Party did not exist), then it will hold such Collateral, proceeds or payment in trust for the other Secured Parties and promptly transfer such Collateral, proceeds or payment, as the case may be, to the collateral agent, to be distributed in accordance with the Collateral Agency Agreement.

The collateral agent, on behalf of the holders of the Notes, and each other Secured Party, will acknowledge that the Secured Obligations of any class may, subject to the limitations set forth in the other Credit Documents outstanding at such time, be increased, extended, renewed, replaced, restated, supplemented, restructured, repaid, refunded, refinanced or otherwise amended or modified from time to time, all without affecting the priorities set forth in the Collateral Agency Agreement defining the relative rights of the Secured Parties of any class.

Collateral Agent

Pursuant to the Collateral Agency Agreement, we have appointed JPMorgan Chase Bank, N.A. to serve as the collateral agent for the benefit of the Secured Parties.

Additional debt

To the extent, but only to the extent, permitted by the provisions of the then-extant Credit Documents, we may incur or issue and sell one or more classes of additional Indebtedness. The obligations in respect of any such additional Indebtedness may be secured by a Lien on the Collateral on a pari passu basis, in each case under and pursuant to the Collateral Documents, if and subject to the condition that the representative of any such additional class or series of Indebtedness, acting on behalf of the holders of such Indebtedness, becomes a party to the Collateral Agency Agreement by satisfying the conditions set forth therein.

Release of Collateral

The Collateral Documents relating to the Notes and the indenture provide that the Liens on the Collateral may be released:

(a) in whole, upon the Discharge of the Secured Obligations;

(b) as to any Collateral that is released, sold, transferred or otherwise disposed of by us or Puget Equico to a person that is not (either before or after such release, sale, transfer or disposition) us or Puget Equico in a transaction or other circumstance that complies with the terms of the then-extant Credit Documents (for so long as any Credit Document is in effect) and is permitted by all of the then-extant Credit Documents, at the time of such release, sale, transfer or other disposition or to the extent of the interest released, sold, transferred or otherwise disposed of;

(c) as to a release of less than all or a material portion of the Collateral, at any time prior to the Discharge of Secured Obligations, if consent to the release of all Liens on such Collateral has been given by the Required Voting Parties; and

(d) as to a release of all or any material portion of the Collateral (other than upon the Discharge of Secured Obligations), if consent to release of that Collateral has been given by the Unanimous Voting Parties.

 

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Upon request by the collateral agent at any time, the Secured Parties will confirm in writing the collateral agent’s authority to release its interest in particular types or items of property pursuant to the Collateral Agency Agreement. In each case as specified in the Collateral Agency Agreement, the collateral agent will (and each Secured Party irrevocably authorizes the collateral agent to), at our expense, execute and deliver to us or Puget Equico, as applicable, such documents as such person may reasonably request to evidence the release of such item of Collateral from the assignment and security interest granted under the Security Documents, in accordance with the terms of the Collateral Agency Agreement or any other Credit Document.

Under the Collateral Agency Agreement, if at any time the collateral agent forecloses upon or otherwise exercises remedies against any Collateral, then (whether or not any insolvency or liquidation proceeding is pending at the time) the Liens in favor of the collateral agent for the benefit of the holders and the Liens upon such Collateral securing all other Secured Obligations will automatically be released and discharged pursuant to the Collateral Agency Agreement and the Collateral Documents. However, any proceeds of any Collateral realized therefrom will be applied as described under “—Collateral Agency Agreement.”

Amendments

The collateral agent may, without obtaining the consent of the Required Voting Parties or any other Secured Party other than as set forth in the Collateral Agency Agreement, modify any Security Document to which it is a party or the Collateral Agency Agreement to (a) cure any ambiguity or to cure, correct or supplement any provision contained therein which is inconsistent with any other provisions contained therein, (b) make, complete or confirm any grant of Collateral permitted or required by the Collateral Agency Agreement or the Security Documents or any release of any Collateral permitted under the Collateral Agency Agreement, or (c) to make changes that would provide additional benefits or rights to the Secured Parties.

Subject to certain exceptions, the Collateral Agency Agreement may be amended with the consent of the Required Voting Parties provided that if any amendment adversely affects us or any class of Secured Obligations, consent of the Authorized Representative for such class or of us, as applicable, is required.

Authorization of actions to be taken

Each holder of Notes, by its acceptance thereof, will be deemed to have consented and agreed to the terms of each Collateral Document, as originally in effect and as amended, supplemented or replaced from time to time in accordance with its terms or the terms of the indenture, to have authorized and directed the trustee to enter into a Joinder Agreement to the Collateral Agency Agreement, and to have authorized and empowered the trustee and (through the Collateral Agency Agreement) the collateral agent to bind the holders of Notes as set forth in the Collateral Documents to which they are a party and to perform its respective obligations and exercise its respective rights and powers thereunder.

Optional Redemption

At any time prior to February 15, 2025, we may, at our option, redeem the Notes, in whole at any time or in part from time to time, upon notice by mail not less than 30 nor more than 60 days before the date fixed for redemption, at a redemption price equal to the greater of:

(a) 100% of the principal amount of the Notes then outstanding to be redeemed; and

(b) the sum of the present values of the remaining scheduled payments of principal and interest on the Notes being redeemed (not including any portion of such interest payments accrued to the date of redemption) discounted to the redemption date on a semiannual basis (assuming a 360-day year consisting of twelve 30-day months) at the Treasury Rate plus 25 basis points, as calculated by an Independent Investment Banker;

plus, in either of the above cases, accrued and unpaid interest, including additional interest, if any, thereon to the date of redemption.

 

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At any time on or after February 15, 2025, we may, at our option, redeem the Notes, in whole or in part, at 100% of the principal amount being redeemed plus accrued and unpaid interest thereon to, but excluding, the redemption date.

If less than all the Notes are to be redeemed, the particular Notes to be redeemed will be selected by the security registrar from the outstanding Notes not previously called for redemption by lot or by such method as Wells Fargo Bank, N.A., as trustee for the Notes, deems fair and appropriate.

Any notice of redemption at our option may state that such redemption will be conditional upon receipt by the paying agent or agents, on or before the date fixed for such redemption, of money sufficient to pay the principal of and premium, if any, and interest, if any, on such Notes and that if such money has not been so received, such notice will be of no force or effect and we will not be required to redeem such Notes.

Unless we default in payment of the redemption price, on and after the redemption date, interest will cease to accrue on the Notes or portions thereof called for redemption.

Purchase of Notes Upon Change of Control Repurchase Event

In the event of any Change of Control Repurchase Event (the effective date of such Change of Control Repurchase Event being the “Change of Control Date”) each holder of a Note will have the right, at such holder’s option, subject to the terms and conditions of the indenture, to require us to repurchase all or any part (equal to $2,000 or an integral multiple of $1,000 in excess thereof) of that holder’s Notes on a date selected by us that is no earlier than 60 days nor later than 90 days (the “Purchase Date”) after the mailing of written notice by us of the occurrence of such Change of Control Repurchase Event, at a repurchase price payable in cash equal to 101% of the principal amount of such Notes plus accrued interest, including additional interest, if any, thereon to the Purchase Date (the “Change of Control Purchase Price”).

Within 30 days after the Change of Control Date, we are obligated to mail to each holder of a Note a notice regarding the Change of Control Repurchase Event, which notice shall state, among other things:

(a) that a Change of Control Repurchase Event has occurred and that each such holder has the right to require us to repurchase all or any part of such holder’s Notes at the Change of Control Purchase Price;

(b) the Change of Control Purchase Price;

(c) the Purchase Date;

(d) the name and address of the paying agent; and

(e) the procedures that holders must follow to cause the Notes to be repurchased.

To exercise this right, a holder must deliver a written notice (the “Change of Control Purchase Notice”) to the paying agent (initially the trustee) at its corporate trust office in New York, New York, or any other office of the paying agent maintained for such purposes (or if notes are held in book entry form, in accordance with DTC’s applicable procedures), not later than 30 days prior to the Purchase Date. The Change of Control Purchase Notice shall state:

(a) the portion of the principal amount of any Notes to be repurchased, which must be a minimum of $2,000 or an integral multiple of $1,000 in excess thereof;

(b) that such Notes are to be repurchased by us pursuant to the applicable Change of Control provisions of the indenture; and

(c) unless the Notes are represented by one or more global Notes, the certificate numbers of the Notes to be repurchased.

 

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Any Change of Control Purchase Notice may be withdrawn by the holder by a written notice of withdrawal delivered to the paying agent (or if notes are held in book entry form, in accordance with DTC’s applicable procedures)not later than three business days prior to the Purchase Date. The notice of withdrawal shall state the principal amount and, if applicable, the certificate numbers of the Notes as to which the withdrawal notice relates and the principal amount, if any, that remains subject to a Change of Control Purchase Notice.

If a Note is represented by a global Note, DTC or its nominee will be the holder of such Note and therefore will be the only entity that can require us to repurchase Notes upon a Change of Control Repurchase Event. To obtain repayment with respect to such Note upon a Change of Control Repurchase Event, the beneficial owner of such Note must provide to the broker or other entity through which it holds the beneficial interest in such Note (a) the Change of Control Purchase Notice signed by such beneficial owner, and such signature must be guaranteed by a member firm of a registered national securities exchange or of the Financial Industry Regulatory Authority, Inc. or a commercial bank or trust company having an office or correspondent in the United States, and (b) instructions to such broker or other entity to notify DTC of such beneficial owner’s desire to cause us to repurchase such Notes. Such broker or other entity will provide to the paying agent (i) a Change of Control Purchase Notice received from such beneficial owner and (ii) a certificate satisfactory to the paying agent from such broker or other entity that it represents such beneficial owner. Such broker or other entity will be responsible for disbursing any payments it receives upon the repurchase of such Notes by us.

Payment of the Change of Control Purchase Price for a Note in registered, certificated form (a “Certificated Note”) for which a Change of Control Purchase Notice has been delivered and not withdrawn is conditioned upon delivery of such Certificated Note (together with necessary endorsements) to the trustee, as our paying agent, at its corporate trust office in New York, New York, or any other office of the paying agent maintained for such purpose, at any time (whether prior to, on or after the Purchase Date) after the delivery of such Change of Control Purchase Notice. We may change the paying agent at our discretion. Payment of the Change of Control Purchase Price for such Certificated Note will be made promptly following the later of the Purchase Date or the time of delivery of such Certificated Note.

If the paying agent holds, in accordance with the terms of the indenture, money sufficient to pay the Change of Control Purchase Price of a Note on the business day following the Purchase Date for such Note, then, on and after such date, interest on such Note will cease to accrue, whether or not such Note is delivered to the paying agent, and all other rights of the holder shall terminate (other than the right to receive the Change of Control Purchase Price upon delivery of the Note).

The definition of Change of Control set forth in the indenture with respect to the Notes differs from the definition of change of control in our senior secured credit facility. Depending on the circumstances, it is possible that a change of control may occur for purposes of our senior secured credit facility without constituting a Change of Control for purposes of the indenture.

The definition of Change of Control includes a phrase relating to the direct or indirect sale, transfer, assignment, lease, conveyance or other disposition of “all or substantially all” of the assets of us and our subsidiaries, considered as a whole. Although there is a limited body of case law interpreting the phrase “substantially all,” there is no precise established definition of the phrase under applicable law. Accordingly, the ability of a holder of Notes to require us to repurchase the Notes as a result of a sale, transfer, assignment, lease, conveyance or other disposition of less than all of the assets of us and our subsidiaries, considered as a whole, may be uncertain.

Under clause (c) of the definition of Change of Control below, a Change of Control will occur when a majority of our board of directors (for so long as the Bylaws are in effect, together with any replacement or new directors appointed to such board of directors in accordance with the terms of the Bylaws, and to the extent the terms of the Bylaws are no longer in effect, together with any new directors whose election or appointment by such board of directors or whose nomination for election by our shareholders was approved by a vote of a majority of the directors then still in office who were either directors at the beginning of such period or whose election or

 

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nomination for election was previously so approved), during any period, cease to constitute a majority of our board of directors then in office. In San Antonio Fire & Police Pension Fund v. Amylin Pharmaceuticals, Inc. et al. (May 2009), the Delaware Court of Chancery held that the occurrence of a change of control under a similar indenture provision may nevertheless be avoided if the existing directors were to approve the slate of new director nominees, provided the incumbent directors gave their approval in the good faith exercise of their fiduciary duties owed to the corporation and its shareholders. Therefore, in certain circumstances involving a significant change in the composition of our board of directors, holders of the Notes may not be entitled to require us to repurchase the Notes as described above.

The indenture requires us to comply with the provisions of Regulation 14E and any other tender offer rules under the Securities Exchange Act of 1934, as amended (the “Exchange Act”) that may then be applicable in connection with any offer by us to purchase Notes at the option of holders upon a Change of Control Repurchase Event. The Change of Control Repurchase Event purchase feature of the Notes may in certain circumstances make more difficult or discourage a takeover and, thus, the removal of incumbent management. The Change of Control Repurchase Event purchase feature, however, is not the result of management’s knowledge of any specific effort to obtain control of us, or part of a plan by management to adopt a series of anti-takeover provisions. Instead, the Change of Control Repurchase Event purchase feature is a term contained in many similar debt offerings and the terms of such feature result from negotiations between us and the initial purchasers. Our management has no present intention to propose any anti-takeover measures although it is possible that we could decide to do so in the future.

No Note may be repurchased by us as a result of a Change of Control Repurchase Event if there has occurred and is continuing an event of default described under “—Events of Default” below (other than a default in the payment of the Change of Control Purchase Price with respect to the Notes). In addition, our ability to purchase Notes may be limited by our financial resources and our inability to raise the required funds because of restrictions on issuance of securities contained in other contractual arrangements.

Certain Covenants

Merger, Consolidation, Sale, Lease or Conveyance

The indenture will provide that we may not, directly or indirectly (a) consolidate or merge with or into another person, whether or not we are the surviving corporation, or (b) sell, assign, transfer, convey or otherwise dispose of all or substantially all of our or our subsidiaries’ properties or assets taken as a whole, in one or more related transactions, to another person, unless:

(i) either (A) we are the surviving corporation or (B) the person formed by or surviving any such consolidation or merger (if other than us) or to which such sale, assignment, transfer, conveyance or other disposition has been made is a corporation, partnership or limited liability company organized or existing under the laws of the United States, any state of the United States or the District of Columbia; provided that if the person is a partnership or limited liability company, then a corporation that (1) is wholly owned by such person, (2) is organized or existing under the laws of the United States, any state of the United States or the District of Columbia, and (3) does not and will not have any material assets or operations, shall become a co-issuer of the Notes pursuant to a supplemental indenture duly executed by the trustee;

(ii) the person formed by or surviving any such consolidation or merger (if other than us) or the person to which such sale, assignment, transfer, conveyance or other disposition has been made assumes all of our obligations under the Notes and the indenture pursuant to a supplemental indenture or other documents and agreements reasonably satisfactory to the trustee;

(iii) immediately after such consolidation or merger, no Event of Default exists; and

(iv) we deliver an officer’s certificate and opinion of counsel to the trustee stating that such transaction is authorized under the indenture.

 

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In addition, we may not, directly or indirectly, lease all or substantially all of our properties or assets, in one or more related transactions, to any other person.

Limitations on Liens

So long as the Notes are outstanding, we will not pledge, mortgage, hypothecate or grant a security interest in, or permit any mortgage, pledge, security interest or other lien upon, the Collateral, other than Permitted Liens. For purposes of this covenant, “Indebtedness” means all indebtedness, whether or not represented by bonds, debentures, notes or other securities, created or assumed by us for the repayment of money borrowed.

Limitation on Sale-Leaseback Transactions

We will not enter into any sale-leaseback transaction involving any of our properties whether now owned or hereafter acquired, whereby we sell or transfer such properties and then or thereafter lease such properties or any part thereof or any other properties which we intend to use for substantially the same purpose or purposes as the properties sold or transferred.

Reports and Other Information

Whether or not required by the SEC’s rules and regulations, so long as any Notes are outstanding, we will furnish to the holders of Notes or cause the trustee to furnish to the holders of Notes:

(a) within 90 days of the end of each fiscal year and within 60 days of the end of each fiscal quarter, all annual and quarterly reports that would be required to be filed with the SEC on Forms 10-K and 10-Q if we were required to file such reports; and

(b) within the time periods specified in the SEC’s rules and regulations that would be applicable if we were subject to such rules and regulations, all current reports that would be required to be filed with the SEC on Form 8-K if we were required to file such reports.

All such reports will be prepared, within the time periods specified above, in all material respects in accordance with all of the rules and regulations applicable to such reports. Each annual report on Form 10-K will include a report on our consolidated financial statements by our independent registered public accounting firm or independent auditors. In addition, we will file a copy of each of the reports referred to in clauses (a) and (b) above with the SEC for public availability within the time periods specified in clauses (a) and (b) above (unless the SEC will not accept such a filing). We agree that we will not take any action for the purpose of causing the SEC not to accept any such filings. If, notwithstanding the foregoing, the SEC will not accept our filings for any reason, we will use our reasonable best efforts to post the reports referred to in the preceding paragraph on our website within the time periods specified above. To the extent such filings are made, the reports will be deemed to be furnished to the trustee and holders of Notes on the date filed.

In addition, for so long as any Notes remain outstanding, we will furnish to prospective purchasers of Notes, upon their request, the information described above as well as any other information required to be delivered pursuant to Rule 144A(d)(4) under the Securities Act for compliance with Rule 144A.

Information Regarding Collateral

We will furnish to the collateral agent prompt written notice of any change in our (a) legal name, (b) jurisdiction of incorporation, or (c) identity or corporate structure. We will agree not to effect or permit any change referred to in the preceding sentence unless all filings have been made or will have been made within any applicable statutory period under the Uniform Commercial Code or otherwise that are required in order for the collateral agent to continue at all times following such change to have a valid, legal and perfected security interest in all the Collateral. We also agree promptly to notify the collateral agent if any material portion of the Collateral is damaged, destroyed or condemned.

 

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In addition, each year, at the time of delivery of the annual financial statements with respect to the preceding fiscal year, we will deliver to the trustee a certificate of a financial officer setting forth the information required pursuant to the schedules required by the Security Documents or confirming that there has been no change in such information since the date of the prior annual financial statements.

No Liability of Directors, Officers, Employees, Incorporators and Shareholders

None of our directors, officers, employees, incorporators, members or shareholders, as such, will have any liability for any of our obligations under the Notes or the indenture or for any claim based on, in respect of, or by reason of, such obligations. Each holder of Notes by accepting a Note waives and releases all such liability. The waiver and release are part of the consideration for issuance of the Notes. This waiver may not be effective to waive liabilities under the federal securities laws and it is the view of the SEC that such a waiver is against public policy.

Events of Default

Any one or more of the following events with respect to the Notes that has occurred and is continuing will constitute an “Event of Default” with respect to the Notes under the indenture:

(a) failure to pay interest within 30 days after the same becomes due and payable;

(b) failure to pay the principal of, or any premium on, the Notes at maturity, upon redemption, upon required purchase, upon acceleration or otherwise;

(c) failure to perform or breach of any covenant, representation, warranty or other agreement contained in the indenture, the Notes or the Security Documents (other than a default referred to in clauses (a) and (b) above) for 60 days after written notice to us by the trustee or to us and the trustee by the holders of at least 25% in principal amount of the Notes as provided in the indenture unless the trustee, or the trustee and the holders of a principal amount of the Notes not less than the principal amount of Notes the holders of which gave such notice, as the case may be, agree in writing to an extension of such period before its expiration; provided, however, that the trustee, or the trustee and the holders of such principal amount of Notes, as the case may be, will be deemed to have agreed to an extension of such period if corrective action is initiated by us within such period and is being diligently pursued;

(d) the occurrence of a matured event of default, as defined in any of our instruments or any Significant Subsidiary’s instruments under which there is or by which there is evidenced any Indebtedness of us or any Significant Subsidiary, that has resulted in the acceleration of such Indebtedness in excess of $100 million, or any default in payment of Indebtedness in excess of $100 million at final maturity, after the expiration of any applicable grace or cure periods; provided, however, that the waiver or cure of any such default under any such instrument or Indebtedness shall constitute a waiver and cure of the corresponding Event of Default under the indenture and the rescission and annulment of the consequences thereof shall constitute a rescission and annulment of the corresponding consequences under the indenture;

(e) certain events of bankruptcy or insolvency described in the indenture with respect to us or any Significant Subsidiary of ours;

(f) our repudiation of any of our obligations under any of the Security Documents or the unenforceability of any of the Security Documents against us for any reason if such unenforceability shall be applicable to (i) Collateral having an aggregate Fair Market Value of $100 million or more or (ii) the Pledged Stock and any such unenforceability has not been cured within 60 days after written notice to us by the trustee or to us and the trustee by the holders of at least 25% in principal amount of the Notes as provided in the indenture;

(g) any Security Document or any lien purported to be granted thereby on (i) the Pledged Stock or (ii) assets having a Fair Market Value in excess of $100 million is held in any judicial proceeding to be unenforceable or invalid, in whole or in part, or ceases for any reason (other than pursuant to a release that is delivered or

 

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becomes effective as set forth in the indenture) to be fully enforceable and perfected and any such unenforceability or lack of perfection has not been cured within 60 days after written notice to us by the trustee or to us and the trustee by the holders of at least 25% in principal amount of the Notes as provided in the indenture; and

(h) the failure by us to pay final judgments aggregating in excess of $100 million, which judgments are not paid, discharged or stayed for a period of 60 days.

As used herein, “Fair Market Value” means the value that would be paid by a willing buyer to a willing seller in a transaction not involving distress or necessity of either party, determined in good faith by our chief financial officer or our board of directors.

Remedies

Acceleration of Maturity

In the case of an Event of Default arising from certain events of bankruptcy or insolvency with respect to us or any Significant Subsidiary, then the principal, premium, if any, and accrued interest on the Notes will be immediately due and payable, without any declaration or other act on the part of the trustee or any holder. If any other Event of Default occurs and is continuing, then either the trustee or the holders of not less than 25% in aggregate principal amount of the outstanding Notes may declare the principal amount of all of the outstanding Notes to be due and payable immediately by written notice to us (and to the trustee if given by holders); provided, however, that if an Event of Default occurs and is continuing with respect to more than one series of securities outstanding under the indenture, including the Notes, the trustee or the holders of not less than 25% in aggregate principal amount of such securities, considered as one class, may make such declaration of acceleration and not the holders of any one series of such securities.

At any time after such a declaration of acceleration with respect to any series of securities outstanding under the indenture has been made, but before a judgment or decree for payment of the money due has been obtained, such declaration and its consequences will, without further act, be deemed to have been rescinded and annulled, if

(a) We have paid or deposited with the trustee a sum sufficient to pay:

(i) all overdue interest, if any, on all securities of such series;

(ii) the principal of and premium, if any, on any securities of such series which have become due otherwise than by such declaration of acceleration and interest, if any, thereon at the rate or rates prescribed therefor in such securities;

(iii) interest, if any, upon overdue interest, if any, at the rate or rates prescribed therefor in the securities, to the extent that payment of such interest is lawful; and

(iv) all amounts due to the trustee under the indenture in respect of compensation and reimbursement of expenses; and

(b) all Events of Default with respect to the securities of such series, other than the nonpayment of the principal of the securities of such series which has become due solely by such declaration of acceleration, have been cured or waived as provided in the indenture.

Right to Direct Proceedings

If an Event of Default with respect to any series of securities outstanding under the indenture occurs and is continuing, the holders of a majority in principal amount of such securities will have the right to direct the time, method and place of conducting any proceedings for any remedy available to the trustee or exercising any trust or power conferred on the trustee; provided, however, that if an Event of Default occurs and is continuing with respect to more than one series of securities outstanding under the indenture, the holders of a majority in

 

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aggregate principal amount of the outstanding securities of all such series, considered as one class, will have the right to make such direction, and not the holders of the securities of any one of such series; and provided, further, that (a) such direction does not conflict with any rule of law or with the indenture, and could not involve the trustee in personal liability in circumstances where indemnity would not, in the trustee’s sole discretion, be adequate, (b) the trustee does not determine that the action so directed would be unjustly prejudicial to the holders of such series of securities not taking part in such direction and (c) the trustee may take any other action deemed proper by the trustee which is not inconsistent with such direction.

Limitation on Right to Institute Proceedings

No holder of any Note will have any right to institute any proceeding, judicial or otherwise, with respect to the indenture or for the appointment of a receiver or for any other remedy thereunder unless:

(a) such holder has previously given to the trustee written notice of a continuing Event of Default with respect to the Notes;

(b) the holders of at least 25% in aggregate principal amount of securities of all series outstanding under the indenture in respect of which such Event of Default has occurred, considered as one class, have made written request to the trustee to institute proceedings in respect of such Event of Default and have offered the trustee reasonable indemnity against costs, expenses and liabilities to be incurred in complying with such request; and

(c) for 60 days after receipt of such notice, the trustee has failed to institute any such proceeding and no direction inconsistent with such request has been given to the trustee during such 60-day period by the holders of a majority in aggregate principal amount of securities then outstanding under the indenture.

Furthermore, no holder of Notes will be entitled to institute any such action if and to the extent that such action would disturb or prejudice the rights of other holders of Notes.

No Impairment of Right to Receive Payment

Notwithstanding that the right of a holder of Notes to institute a proceeding with respect to the indenture is subject to certain conditions precedent, each holder of a Note will have the right, which is absolute and unconditional, to receive payment of the principal of and premium, if any, and interest, if any, on such Note when due and to institute suit for the enforcement of any such payment, and such rights may not be impaired or affected without the consent of such holder.

Notice of Default

The trustee is required to give the holders of securities outstanding under the indenture notice of any default under the indenture to the extent required by the Trust Indenture Act, unless such default has been cured or waived, except that no such notice to holders of a default of the character described in clause (iii) under “—Events of Default” may be given until at least 75 days after the occurrence thereof. For purposes of the preceding sentence, the term “default” means any event which is, or after notice or lapse of time, or both, would become, an Event of Default. The Trust Indenture Act currently permits the trustee to withhold notices of default (except for certain payment defaults) if the trustee in good faith determines the withholding of such notice to be in the interests of the holders.

Reporting

The indenture requires that certain of our officers certify, on or before a date not more than 120 days after the end of each fiscal year, that to the best of those officers’ knowledge, we have fulfilled all our obligations under the indenture. We are also obligated to notify the trustee of any default or defaults in the performance of any covenants or agreements under the indenture, but a failure by us to deliver such notice of a default will not constitute a default under the indenture if we have remedied such default within any applicable cure period.

 

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Modification of Indenture

Modifications Without Consent

We and the trustee may enter into one or more supplemental indentures without the consent of any holders of the Notes, for any of the following purposes:

(a) to evidence the succession of another person to the Company and the assumption by any such successor of the covenants of such party;

(b) to add one or more covenants of the Company or other provisions for the benefit of holders of the Notes, or to surrender any right or power conferred upon us by the indenture;

(c) to change or eliminate any provision of the indenture or to add any new provision to the indenture, provided that if such change, elimination or addition adversely affects the interests of the holders of the Notes in any material respect, such change, elimination or addition will become effective only when no Notes are outstanding;

(d) to comply with any requirements of the SEC in connection with the qualification of the indenture under the Trust Indenture Act;

(e) to make, complete or confirm any grant of Collateral permitted or required by the Security Documents or, with the consent of the collateral agent, any release of Collateral that becomes effective as set forth in the Security Documents;

(f) to establish the form or terms of securities of any series or tranche under the indenture as permitted by the indenture;

(g) to provide for the authentication and delivery of bearer securities and coupons appertaining thereto representing interest, if any, thereon and for the procedures for the registration, exchange and replacement thereof and for the giving of notice to, and the solicitation of the vote or consent of, the holders thereof, and for any and all other matters incidental thereto;

(h) to evidence and provide for the acceptance of appointment by a successor trustee;

(i) to provide for the procedures required to permit the utilization of a non-certificated system of registration for all, or any series or tranche of, the securities under the indenture;

(j) to change any place or places where—

(i) the principal of and premium, if any, and interest, if any, on all or any series of securities under the indenture, or any tranche thereof, will be payable,

(ii) all or any series of securities under the indenture, or any tranche thereof, may be surrendered for registration of transfer,

(iii) all or any series of securities under the indenture, or any tranche thereof, may be surrendered for exchange, and

(iv) notices and demands to or upon us in respect of all or any series of securities under the indenture, or any tranche thereof, and the indenture may be served;

(k) to cure any ambiguity, to correct or supplement any provision therein which may be defective or inconsistent with any other provision therein, or to make any other changes to the provisions thereof or to add other provisions with respect to matters and questions arising under the indenture, so long as such other changes or additions do not adversely affect the interests of the holders of any series or tranche of securities under the indenture in any material respect; or

(l) to waive the rights of other secured debt holders.

 

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In addition, if the Trust Indenture Act is amended after the date of the original indenture in such a way as to require changes to the indenture or the incorporation therein of additional provisions or so as to permit changes to, or the elimination of, provisions which, at the date of the original indenture or at any time thereafter, were required by the Trust Indenture Act to be contained in the indenture, the indenture will be deemed to have been amended so as to conform to such amendment or to effect such changes or elimination, and we and the trustee may, without the consent of any holders of securities outstanding under the indenture, enter into one or more supplemental indentures to evidence such amendment.

Modifications Requiring Consent

Except as provided above, the consent of the holders of a majority in aggregate principal amount of all series of securities then outstanding under the indenture, considered as one class, is required for the purpose of adding any provisions to, or changing in any manner, or eliminating any of the provisions of, the indenture pursuant to one or more supplemental indentures; provided, however, that if less than all of the series of securities outstanding under the indenture are directly affected by a proposed supplemental indenture, then the consent only of the holders of a majority in aggregate principal amount of outstanding securities of all series so directly affected, considered as one class, will be required; and provided, further, that if the securities of any series have been issued in more than one tranche and if the proposed supplemental indenture directly affects the rights of the holders of one or more, but less than all, of such tranches, then the consent only of the holders of a majority in aggregate principal amount of the outstanding securities of all tranches so directly affected, considered as one class, will be required; and provided, further, that no such supplemental indenture may:

(a) reduce the principal amount of or change the stated maturity of any installment of principal of the Notes;

(b) reduce the rate of or change the stated maturity of any interest payment on the Notes;

(c) reduce the amount payable upon the redemption of the Notes, in respect of an optional redemption, change the times at which the Notes may be redeemed or, once notice of redemption has been given, the time at which they must thereupon be redeemed;

(d) waive an Event of Default in the payment of principal of, or premium, if any, or interest on, the Notes (except a rescission of acceleration of such Notes by the holders of at least a majority in aggregate principal amount of such Notes and a waiver of the payment default that resulted from such acceleration);

(e) make the Notes payable in money other than that stated in the Notes;

(f) impair the right of any holder of Notes to receive any principal payment or interest payment on such holder’s Notes, on or after the stated maturity thereof, or to institute suit for the enforcement of any such payment;

(g) make any change in the percentage of the principal amount of the Notes required for amendments or waivers; or

(h) modify or change any provision of the indenture affecting the ranking of the Notes in a manner adverse to the holders of the Notes.

It is not necessary for holders to approve the particular form of any proposed amendment, supplement or waiver, but it is sufficient if their consent approves the substance thereof.

Neither we nor any of our subsidiaries or affiliates may, directly or indirectly, pay or cause to be paid any consideration, whether by way of interest, fee or otherwise, to any holder for or as an inducement to any consent, waiver or amendment of any of the terms or provisions of the indenture or the Notes unless such consideration is offered to be paid or agreed to be paid to all holders of the Notes that consent, waive or agree to amend such term or provision within the time period set forth in the solicitation documents relating to the consent, waiver or amendment.

 

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A supplemental indenture which changes or eliminates any covenant or other provision of the indenture which has expressly been included solely for the benefit of the holders of, or which is to remain in effect only so long as there shall be outstanding, securities of one or more specified series outstanding under the indenture, or one or more tranches thereof, or modifies the rights of the holders of securities of such series or tranches with respect to such covenant or other provision, will be deemed not to affect the rights under the indenture of the holders of the securities of any other series or tranche.

If the supplemental indenture or other document establishing any series or tranche of securities under the indenture so provides, and as specified in the applicable prospectus supplement and/or pricing supplement, the holders of such securities will be deemed to have consented, by virtue of their purchase of such securities, to a supplemental indenture containing the additions, changes or eliminations to or from the indenture which are specified in such supplemental indenture or other document, no act of such holders will be required to evidence such consent and such consent may be counted in the determination of whether the holders of the requisite principal amount of securities have consented to such supplemental indenture.

Satisfaction and Discharge

The Notes, or any portion of the principal amount thereof, will be deemed to have been paid for purposes of the indenture and, at our election, our entire indebtedness in respect thereof will be deemed to have been satisfied and discharged, if there shall have been irrevocably deposited with the trustee, in trust:

(a) money in an amount which will be sufficient,

(b) in the case of a deposit made before the maturity of such Notes, Eligible Obligations (as described below), which do not contain provisions permitting the redemption or other prepayment thereof at the option of the issuer thereof, the principal of and the interest on which when due, without any regard to reinvestment thereof, will provide moneys which, together with the money, if any, deposited with or held by the trustee, will be sufficient, or

(c) a combination of (a) and (b) which will be sufficient,

to pay when due the principal of and premium, if any, and interest, if any, due and to become due on such Indenture Securities. For this purpose, Eligible Obligations include direct obligations of, or obligations unconditionally guaranteed by, the United States, entitled to the benefit of the full faith and credit thereof and certificates, depositary receipts or other instruments which evidence a direct ownership interest in such obligations or in any specific interest or principal payments due in respect thereof, and such other obligations or instruments as shall be specified in an accompanying prospectus supplement.

The indenture will be deemed to have been satisfied and discharged when no Indenture Securities remain outstanding thereunder and we have paid or caused to be paid all other sums payable by us under the indenture.

Our right to cause our entire indebtedness in respect of any Notes to be deemed to be satisfied and discharged as described above will be subject to the delivery to the trustee of an opinion of counsel to the effect that in connection with any such deposit above, the holders of such Notes will not recognize income, gain or loss for United States federal income tax purposes as a result of the satisfaction and discharge of our indebtedness in respect thereof and will be subject to United States federal income tax on the same amounts, at the same times and in the same manner as if such satisfaction and discharge had not been effected.

Concerning the Trustee

Wells Fargo Bank, N.A. is the trustee under the indenture.

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indenture against the trustee. In case an Event of Default has occurred and is continuing, the trustee will exercise those rights and powers vested in it by the indenture and use the same degree of care and skill in their exercise as a prudent man would exercise or use under the circumstances in the conduct of his own affairs. No provision of the indenture will require the trustee to expend or risk its own funds or otherwise incur any financial liability in the performance of its duties thereunder, or in the exercise of its rights or powers, unless it receives indemnity satisfactory to it against any loss, liability or expense.

The indenture and provisions of the Trust Indenture Act incorporated by reference therein contain limitations on the rights of the trustee, should it become a creditor of us, to obtain payment of claims in certain cases, or to realize on certain property received in respect of any such claim as security or otherwise. The trustee is permitted to engage in other transactions with us and our affiliates; provided that if it acquires any conflicting interest it must either eliminate the conflict within 90 days, apply to the SEC for permission to continue or resign.

Book-Entry; Delivery and Form

The original notes are, and the exchange notes will be, issued in the form of one or more global certificates, known as “Global Notes.” The Global Notes will be deposited on the date of the acceptance for exchange of the original notes and the issuance of the exchange notes with, or on behalf of DTC and registered in the name of Cede & co., as DTC’s nominee.

Beneficial interests in the Global Notes may not be exchanged for Notes in certificated form except in the limited circumstances described below. See “—Exchange of Global Notes for Certificated Notes.” Except in the limited circumstances described below, owners of beneficial interests in the Global Notes will not be entitled to receive physical delivery of Notes in certificated form. Persons holding interests in the global securities may hold their interests directly through DTC or indirectly through organizations that are participants in DTC (such as Euroclear and Clearstream).

Exchange of Global Notes for Certificated Notes

A Global Note is exchangeable for Notes in registered certificated form (“Certificated Notes”) if:

(a) DTC (a) notifies the Company that it is unwilling or unable to continue as depositary for the Global Notes or (b) has ceased to be a clearing agency registered under the Exchange Act, and the Company fails to appoint a successor depositary within 90 days;

(b) we, in our sole discretion, determine that the Notes shall no longer be represented by such Global Notes;

(c) there shall have occurred a Default or Event of Default with respect to the Notes.

In addition, beneficial interests in a Global Note may be exchanged for Certificated Notes upon prior written notice given to the Trustee by or on behalf of DTC in accordance with the indenture governing the Notes. In all cases, Certificated Notes delivered in exchange for any Global Note or beneficial interests in Global Notes will be registered in the names, and issued in any approved denominations, requested by or on behalf of the depositary (in accordance with its customary procedures) and will bear the applicable restrictive legend unless that legend is not required by applicable law.

Book-Entry Procedures for the Global Notes

The description of the operations and procedures of DTC, Euroclear and Clearstream set forth below are provided solely as a matter of convenience and are not intended to serve as a representation or warranty of any kind. These operations and procedures are solely within the control of these settlement systems and are subject to change by term from time to time. Neither we nor the initial purchasers take any responsibility for these operations or procedures, and investors are urged to contact the relevant system and its participants directly to discuss these matters.

 

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The following is based upon information furnished by DTC:

DTC is a limited-purpose trust company organized under the New York Banking Law, a “banking organization” within the meaning of the New York Banking Law, a member of the Federal Reserve System, a “clearing corporation” within the meaning of the New York Uniform Commercial Code, and a “clearing agency” registered pursuant to the provisions of Section 17A of the Exchange Act. DTC holds and provides asset servicing for issues of U.S. and non-U.S. equity, corporate and municipal debt issues, and money market instruments that DTC’s participants (“Direct Participants”) deposit with DTC. DTC also facilitates the post-trade settlement among Direct Participants of sales and other securities transactions in deposited securities through electronic computerized book-entry transfers and pledges between Direct Participants’ accounts. This eliminates the need for physical movement of securities certificates. Direct Participants include both U.S. and non-U.S. securities brokers and dealers, banks, trust companies, clearing corporations, and certain other organizations. DTC is a wholly owned subsidiary of The Depository Trust & Clearing Corporation (“DTCC”). DTCC is the holding company for DTC, National Securities Clearing Corporation and Fixed Income Clearing Corporation, all of which are registered clearing agencies. DTCC is owned by the users of its regulated subsidiaries. Access to the DTC system is also available to others such as both U.S. and non-U.S. securities brokers and dealers, banks, trust companies and clearing corporations that clear through or maintain a custodial relationship with a Direct Participant, either directly or indirectly (“Indirect Participants”). The DTC Rules applicable to its Direct and Indirect Participants are on file with the SEC. More information about DTC can be found at www.dtcc.com.

Purchases of Notes under the DTC system must be made by or through Direct Participants, which will receive a credit for the Notes on DTC’s records. The ownership interest of each actual purchaser of each Note (“Beneficial Owner”) is in turn to be recorded on the Direct and Indirect Participants’ records. Beneficial Owners will not receive written confirmation from DTC of their purchase. Beneficial Owners are, however, expected to receive written confirmations providing details of the transaction, as well as periodic statements of their holdings, from the Direct or Indirect Participant through which the Beneficial Owner entered into the transaction. Transfers of ownership interests in the Notes are to be accomplished by entries made on the books of Direct Participants and Indirect Participants acting on behalf of Beneficial Owners. Transfers between participants in Euroclear and Clearstream will be effected in the ordinary way in accordance with their respective rules and operating procedures. Beneficial Owners will not receive certificates representing their ownership interests in Notes, except in the event that use of the book-entry system for the Notes is discontinued.

To facilitate subsequent transfers, all Notes deposited by Direct Participants with DTC are registered in the name of DTC’s partnership nominee, Cede & Co., or such other name as may be requested by an authorized representative of DTC. The deposit of Notes with DTC and their registration in the name of Cede & Co. or such other nominee do not effect any change in beneficial ownership. DTC has no knowledge of the actual Beneficial Owners of the Notes; DTC’s records reflect only the identity of the Direct Participants to whose accounts such Notes are credited, which may or may not be the Beneficial Owners. The Direct and Indirect Participants will remain responsible for keeping account of their holdings on behalf of their customers.

Conveyance of notices and other communications by DTC to Direct Participants, by Direct Participants to Indirect Participants, and by Direct Participants and Indirect Participants to Beneficial Owners will be governed by arrangements among them, subject to any statutory or regulatory requirements as may be in effect from time to time.

Beneficial Owners of Notes may wish to take certain steps to augment transmission to them of notices of significant events with respect to the Notes, such as redemptions, tenders, defaults and proposed amendments to the Security Documents. For example, Beneficial Owners of Notes may wish to ascertain that the nominee holding the Notes for their benefit has agreed to obtain and transmit notices to Beneficial Owners; in the alternative, Beneficial Owners may wish to provide their names and addresses to the registrar and request that copies of the notices be provided directly to them.

 

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Redemption notices shall be sent to DTC. If less than all of the Notes within an issue are being redeemed, DTC’s practice is to determine by lot the amount of the interest of each Direct Participant in such issue to be redeemed.

Neither DTC nor Cede & Co. (nor other DTC nominee) will consent or vote with respect to the Notes unless authorized by a Direct Participant in accordance with DTC’s procedures. Under its usual procedures, DTC mails an omnibus proxy to the issuer as soon as possible after the record date. The omnibus proxy assigns Cede & Co.’s consenting or voting rights to those Direct Participants to whose accounts the Notes are credited on the record date (identified in a listing attached to the omnibus proxy).

Redemption proceeds, distributions and interest payments on the Notes will be made to Cede & Co. or such other nominee as may be requested by an authorized representative of DTC. DTC’s practice is to credit Direct Participants’ accounts, upon DTC’s receipt of funds and corresponding detailed information from the issuer or agent, on the payable date in accordance with their respective holdings shown on DTC’s records. Payments by Direct or Indirect Participants to Beneficial Owners will be governed by standing instructions and customary practices, as is the case with securities held for the accounts of customers in bearer form or registered in “street name,” and will be the responsibility of such Direct or Indirect Participant and not of DTC or its nominee, agent or issuer, subject to any statutory or regulatory requirements as may be in effect from time to time. Payment of redemption proceeds, distributions and dividend payments to Cede & Co. (or such other nominee as may be requested by an authorized representative of DTC) is the responsibility of the issuer or agent, disbursement of such payments to Direct Participants will be the responsibility of DTC, and disbursement of such payments to the Beneficial Owners will be the responsibility of Direct and Indirect Participants.

Cross-market transfers between DTC, on the one hand, and directly or indirectly through Euroclear or Clearstream participants, on the other, will be effected in DTC in accordance with DTC rules on behalf of Euroclear or Clearstream, as the case may be, by its respective depositary; however, such cross-market transactions will require delivery of instructions to Euroclear or Clearstream, as the case may be, by the counterparty in such system in accordance with its rules and procedures and within its established deadlines (Brussels time). Euroclear or Clearstream, as the case may be, will, if the transaction meets its settlement requirements, deliver instructions to its respective depositary to take action to effect final settlement on its behalf by delivering or receiving interests in the global securities in DTC, and making or receiving payment in accordance with normal procedures for same-day funds settlement applicable to DTC. Euroclear participants and Clearstream participants may not deliver instructions directly to the depositaries for Euroclear or Clearstream.

Because of time zone differences, the securities account of a Euroclear or Clearstream participant purchasing an interest in the global securities from a DTC participant will be credited during the securities settlement processing day (which must be a business day for Euroclear or Clearstream, as the case may be) immediately following the DTC settlement date, and such credit of any transactions in the global securities settled during such processing day will be reported to the relevant Euroclear or Clearstream participant on such day. Cash received by Euroclear or Clearstream as a result of sales of interests in the global securities by or through a Euroclear or Clearstream participant to a DTC participant will be received with value on the DTC settlement date, but will be available in the relevant Euroclear or Clearstream cash account only as of the business day following settlement in DTC.

If DTC at any time is unwilling or unable to continue as a depositary, defaults in the performance of its duties as depositary or ceases to be a clearing agency registered under the Exchange Act or other applicable statute or regulation, and a successor depositary is not appointed by us within ninety (90) days, we will issue Notes in definitive form in exchange for the global securities relating to the Notes. In addition, we may at any time and in our sole discretion, subject to the procedures of the depositary and DTC, determine not to have the Notes or portions of the Notes represented by one or more global securities and, in that event, will issue individual Notes in exchange for the global security or securities representing the Notes. Further, if we so specify with respect to any Notes, an owner of a beneficial interest in a global security representing the Notes may, on terms acceptable to us and the depositary for the global security, receive individual Notes in exchange for such beneficial interest,

 

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subject to DTC’s procedures. In any such instance, an owner of a beneficial interest in a global security will be entitled to physical delivery in definitive form of Notes represented by the global security equal in principal amount to the beneficial interest, and to have the Notes registered in its name. Notes so issued in definitive form will be issued as registered Notes in minimum denominations of $2,000 and integral multiples of $1,000 in excess thereof, unless otherwise specified by us. Such Notes will be subject to certain restrictions on registration of transfers as described under “Notice to Investors” and will bear the legend set forth thereunder. The Notes may not be resold or transferred except as permitted under the Securities Act and the applicable state securities laws pursuant to registration or exemption therefrom. We will have no obligation to register the Notes offered hereby for resale under United States securities laws, and have no plans to do so. Furthermore, we have not registered the Notes under any other country’s securities laws.

Governing Law

The indenture and the Notes shall be governed by, and construed in accordance with, the laws of the State of New York.

Definitions

“Additional Credit Document” means any indenture, note, promissory note, instrument or other agreement entered into by us after the date of the Collateral Agency Agreement, if any, pursuant to which we will incur Additional Secured Obligations from time to time, to the extent permitted under the Credit Documents, and which have been designated as Additional Credit Documents in accordance with the Collateral Agency Agreement.

“Additional Secured Obligations” means any of our indebtedness and obligations arising under any Additional Credit Document that we designate as Additional Secured Obligations in accordance with the terms of the Collateral Agency Agreement, in each case to the extent permitted (if addressed therein, or, otherwise, not prohibited) under the senior secured credit facility and the other Credit Documents as of the date of such designation; provided that the holder of such indebtedness or other obligations (or the agent, trustee or representative acting on behalf of the holder of such indebtedness or other obligation) is either a party to the Collateral Agency Agreement or shall have executed and delivered to the collateral agent a Joinder Agreement pursuant to which such holder (or such agent, trustee or representative acting on behalf of such holder) has become a party to the Collateral Agency Agreement and has agreed to be bound by the obligations of a “Secured Party” under the terms of the Collateral Agency Agreement. Subject to meeting the requirements of the preceding sentence, Additional Secured Obligations will include (a) advances to us and our debts, liabilities, obligations, covenants and duties arising under any Additional Credit Documents, whether direct or indirect (including those acquired by assumption), absolute or contingent, due or to become due, now existing or hereafter arising and including interest and fees that accrue after the commencement by or against us, of any proceeding under any Debtor Relief Laws naming such person as the debtor in such proceeding, regardless of whether such interest and fees are allowed claims in such proceeding, (b) the obligation to pay principal, interest, reimbursement obligations, charges, expenses, fees, attorney fees and expenses, indemnities and other amounts payable by us under any Additional Credit Document, and (c) our obligation to reimburse any amount in respect of any of the foregoing that any Additional Secured Party, in its sole discretion, may elect to pay or advance on our behalf.

“Additional Secured Parties” means any holders of any Additional Secured Obligations and any Authorized Representative with respect thereto.

“Affiliate” of any specified person means any other person directly or indirectly controlling or controlled by or under direct or indirect common control with such specified person. For the purposes of this definition, “control,” when used with respect to any specified person, means the power to direct generally the management and policies of such person, directly or indirectly, whether through the ownership of voting securities, by contract or otherwise; and the terms “controlling” and “controlled” have meanings correlative to the foregoing.

 

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“Agents” means, collectively, the collateral agent, each Authorized Representative and each of their respective successors and assigns.

“Authorized Representative” means (a) in the case of any Credit Agreement Obligations or the lenders under our senior secured credit facility, the Credit Agreement Administrative Agent, (b) in the case of any Secured Hedge Obligations and the Interest Rate Hedge Banks, such Interest Rate Hedge Bank or any person appointed by such Interest Rate Hedge Bank to act as its agent or representative, (c) in the case of the indenture, the Notes and our existing senior secured notes, the trustee, and (d) in the case of any Series of Additional Secured Obligations or Additional Secured Parties that become subject to the Collateral Agency Agreement after the date hereof, the Authorized Representative named for such Series in the applicable Joinder Agreement.

“Business Day” means any day, other than a Saturday or Sunday, that is not a day on which banking institutions or trust companies in the place of payment are generally authorized or required by law, regulation or executive order to remain closed.

“Change of Control” means the occurrence of any of the following events:

(a) any “person” or “group” (as such terms are used in Sections 13(d) and 14(d) of the Exchange Act or any successor provisions to either of the foregoing), other than the Permitted Holders, becomes the “beneficial owners” (as used in Rules 13d-3 and 13d-5 under the Exchange Act, except that a person or group will be deemed to have “beneficial ownership” of all shares that any such person or group has the right to acquire, whether such right is exercisable immediately or only after the passage of time), directly or indirectly, of a majority of the total voting power of our Voting Stock, whether as a result of the issuance of our securities, any merger, consolidation, liquidation or dissolution of us or otherwise;

(b) the sale, transfer, assignment, lease, conveyance or other disposition, directly or indirectly, of all or substantially all the assets of us and our subsidiaries, considered as a whole (other than a disposition of such assets as an entirety or virtually as an entirety to a wholly-owned subsidiary) to any person other than the Permitted Holders occurs, or we merge, consolidate or amalgamate with or into any other person or any other person merges, consolidates or amalgamates with or into us, in any such event pursuant to a transaction in which our outstanding Voting Stock is reclassified into or exchanged for cash, securities or other property, other than any such transaction where (i) our outstanding Voting Stock is reclassified into or exchanged for other Voting Stock of us or for Voting Stock of the surviving corporation and (ii) the holders of our Voting Stock immediately prior to such transaction own, directly or indirectly, a majority of our Voting Stock or the surviving corporation immediately after such transaction;

(c) during any period, individuals who at the beginning of such period constituted our board of directors (for so long as our Amended and Restated Bylaws, dated February 6, 2009 (as amended from time to time, the “Bylaws”) are in effect, together with any replacement or new directors appointed to such board of directors in accordance with the terms of the Bylaws, and to the extent the terms of the Bylaws are no longer in effect, together with any new directors whose election or appointment by such board of directors or whose nomination for election by our shareholders was approved by a vote of a majority of the directors then still in office who were either directors at the beginning of such period or whose election or nomination for election was previously so approved) cease for any reason to constitute a majority of our board of directors then in office; or

(d) our shareholders approve any plan of liquidation or dissolution of us.

“Change of Control Repurchase Event” means the occurrence of both a Change of Control and a Ratings Event.

“Collateral” means all the “Collateral,” as defined in each of the Security Documents.

“Collateral Agency Agreement” means the Amended and Restated Collateral Agency Agreement, dated as of February 6, 2009 and amended and restated as of May 10, 2010 and further amended as of February 10, 2012,

 

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and as supplemented by a Joinder Agreement thereto dated as of December 6, 2010, among the collateral agent, the Credit Agreement Administrative Agent, certain authorized representatives, Puget Equico LLC and the Puget Energy, Inc.

“Collateral Documents” means the Collateral Agency Agreement, the Pledge Agreement and the Security Agreement.

“Comparable Treasury Issue” means the United States Treasury security selected by an Independent Investment Banker as having a maturity comparable to the remaining term of the Notes to be redeemed that would be used, at the time of selection and in accordance with customary financial practice, in pricing new issues of corporate debt securities of comparable maturity to the remaining term of the Notes.

“Comparable Treasury Price” means, with respect to any redemption date, (a) the average of the bid and asked prices for the Comparable Treasury Issue (expressed in each case as a percentage of its principal amount) on the third Business Day preceding such redemption date, as set forth in the daily statistical release (or any successor release) published by the Federal Reserve Bank of New York and designated “Composite 3:30 p.m. Quotations for U.S. Government Securities” or (b) if such release (or any successor release) is not published or does not contain such prices on such third Business Day, (i) the average of the Reference Treasury Dealer Quotations for such redemption date, after excluding the highest and lowest of such Reference Treasury Dealer Quotations or (ii) if the Independent Investment Banker obtains fewer than five such Reference Treasury Dealer Quotations, the average of all such Quotations.

“Controlling Authorized Representative” means (a) until the earlier to occur of (i) the Discharge of Credit Agreement Obligations and (ii) the occurrence of the Majority Non-Controlling Voting Party Enforcement Date (if any), the Credit Agreement Administrative Agent and (b) from and after the earlier to occur of (i) Discharge of Credit Agreement Obligations and (ii) the occurrence of the Majority Non-Controlling Voting Party Enforcement Date, the Authorized Representative for the Majority Non-Controlling Voting Parties at such time.

“Credit Agreement” means the Credit Agreement, dated as of February 10, 2012 among Puget Energy, Inc., the Credit Agreement Administrative Agent, the other agents party thereto and the lenders party thereto, as amended, restated or otherwise modified from time to time,

“Credit Agreement Administrative Agent” means JPMorgan Chase Bank, N.A., in its capacity as administrative agent for the lenders under the Credit Agreement.

“Credit Agreement Obligations” means all Obligations as such term is defined under the Credit Agreement.

“Credit Documents” means, collectively (without duplication), each Financing Document and any Additional Credit Document providing for or evidencing any Additional Secured Obligations.

“Debtor Relief Laws” means the U.S. Bankruptcy Code, and all other liquidation, conservatorship, bankruptcy, assignment for the benefit of creditors, moratorium, rearrangement, receivership, insolvency, reorganization, or similar debtor relief laws of the United States or other applicable jurisdictions from time to time in effect and affecting the rights of creditors generally.

“Discharge of Credit Agreement Obligations” means, except as expressly set forth in the Financing Documents, the payment in full in cash of all outstanding principal amount of Loans under the Credit Agreement, all interest due (including, without limitation, interest accruing at the then applicable rate provided in the Credit Agreement after the maturity of the Loans and any post-petition interest) on all “Obligations” outstanding under the Credit Agreement and all fees payable or otherwise accrued under the Financing Documents (other than any contingent indemnity obligations that expressly survive the termination of the Financing Documents).

 

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“Discharge of Secured Obligations” means, except as otherwise provided in the Financing Documents, the payment in full in cash of all (a) outstanding Secured Obligations under any Credit Document, (b) interest (including, without limitation, interest accruing at the then applicable rate provided in the applicable Credit Document after the maturity of the Loans or other indebtedness or other relevant Secured Obligations and postpetition interest) on all Secured Obligations outstanding under any Credit Document and (c) all fees and other Secured Obligations outstanding under each Credit Document (other than any contingent indemnity obligations that expressly survive the termination of the Credit Documents).

“Equity Interests” means, with respect to any person, all of the shares, membership interests, rights, participations or other equivalents (however designated) of capital stock of (or other ownership or profit interests or units in) such person and all of the warrants, options or other rights for the purchase, acquisition or exchange from such person of any of the foregoing (including through convertible securities).

“Event of Default” means (a) an “event of default” under and as defined in the Credit Agreement or any Additional Credit Document or (b) any event leading to an “early termination date” or an “early termination event” under any Interest Rate Hedging Agreement with respect to which Puget Equico is or we are the defaulting party or affected party, as the case may be.

“Financing Documents” means (i) the Credit Agreement, (ii) any promissory notes issued pursuant to Section 2.10(e) of the Credit Agreement, (iii) Interest Hedging Agreements with any Interest Rate Hedge Bank, (iv) any Letter of Credit applications, (v) the Security Documents, (vi) the Collateral Agency Agreement and (vii) all other agreements, instruments, documents and certificates identified in Section 4.01 of the Credit Agreement executed and delivered to, or in favor of, the Credit Agreement Administrative Agent or any lenders under the Credit Agreement and including all other pledges, powers of attorney, consents, assignments, contracts, notices, letter of credit agreements and all other written matter whether heretofore, now or hereafter executed by or on behalf of us, or any of our employees, and delivered to the Credit Agreement Administrative Agent or any lender under the Credit Agreement in connection with the Credit Agreement or the transactions contemplated thereby. Any reference in the Credit Agreement or any other Financing Document to a Financing Document shall include all appendices, exhibits or schedules thereto, and all amendments, restatements, supplements or other modifications thereto, and shall refer to the Credit Agreement or such Financing Document as the same may be in effect at any and all times such reference becomes operative.

“GAAP” means generally accepted accounting principles in the United States of America, as in effect from time to time, consistently applied.

“Indebtedness” means, as to any person at a particular time, without duplication, all of the following, whether or not included as indebtedness or liabilities in accordance with GAAP:

(a) all obligations of such person for borrowed money and all obligations of such person evidenced by bonds, debentures, notes, loan agreements or other similar instruments, including, without limitation, hybrid debt securities;

(b) letters of credit (including standby and commercial), bankers’ acceptances, bank guaranties and similar instruments issued or created by or for the account of such person;

(c) net obligations of such person under any Interest Hedging Agreement (the amount of any such net obligation to be the amount that is or would be payable upon settlement, liquidation, termination or acceleration thereof at the time of calculation);

(d) all obligations of such person to pay the deferred purchase price of property or services (other than (i) trade accounts payable in the ordinary course of business, (ii) accrued expenses in the ordinary course of business, (iii) any earn-out obligation until such obligation becomes a liability on the balance sheet of such person in accordance with GAAP, and (iv) obligations with respect to commodity purchase contracts);

 

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(e) indebtedness (excluding prepaid interest thereon) secured by a Lien on property owned or being purchased by such person (including indebtedness arising under conditional sales or other title retention agreements and mortgage, industrial revenue bond, industrial development bond and similar financings), whether or not such indebtedness shall have been assumed by such person or is limited in recourse;

(f) for any capital lease, the capitalized amount that would appear on a balance sheet prepared in accordance with GAAP;

(g) all obligations of such person to purchase, redeem, retire, defease or otherwise make any payment in respect of any Redeemable Equity Interests in such person or any other or any warrants, rights or options to acquire such Equity Interests, valued, in the case of Redeemable Preferred Interests, at the greater of its voluntary or involuntary liquidation preference plus accrued and unpaid dividends; and

(h) all guarantees of such person in respect of Indebtedness referred to in any of the foregoing clauses (a) through (g).

“Indenture Securities” means all debt securities outstanding under the indenture.

“Independent Investment Banker” means each of Barclays Capital Inc., Merrill Lynch, Pierce, Fenner & Smith Incorporated and Mizuho Securities USA Inc., or their respective successors, or if any such firm is unwilling or unable to serve as such, an independent investment banking institution of national standing appointed by us.

“Insolvency or Liquidation Proceeding” means (a) any voluntary or involuntary case or proceeding under Debtor Relief Laws with respect to Puget Equico or us, (b) any other voluntary or involuntary insolvency, reorganization or bankruptcy case or proceeding, or any receivership, liquidation, reorganization or other similar case or proceeding with respect to Puget Equico or us or with respect to a material portion of their or our respective assets, (c) any liquidation, dissolution, reorganization or winding up of Puget Equico or us whether voluntary or involuntary and whether or not involving insolvency or bankruptcy or (d) any assignment for the benefit of creditors or any other marshalling of assets and liabilities of Puget Equico or us.

“Intercreditor Vote” means a vote conducted in accordance with the procedures set forth in Article 3 of the Collateral Agency Agreement among the Voting Parties for the Series entitled to vote with respect to the particular decision at issue.

“Interest Hedging Agreements” means any rate swap, cap or collar agreement or similar arrangement between one or more interest rate hedge providers and us designed to protect such person against fluctuations in interest rates. For purposes of the Collateral Agency Agreement, our indebtedness at any time under an Interest Hedging Agreement will be determined at such time in accordance with the methodology set forth in such Interest Hedging Agreement.

“Interest Rate Hedge Banks” means (a) any person that is a lender under our senior secured credit facility or an Affiliate of a lender under our senior secured credit facility at the time it enters into an Interest Hedging Agreement or (b) Macquarie Bank Limited to the extent it enters into an Interest Hedging Agreement, in each case, in its capacity as a party to such Interest Hedging Agreement and only for so long as any of our obligations remain outstanding under the Interest Hedging Agreement to which such Interest Rate Hedge Bank is a party; provided that such Interest Rate Hedge Bank executes a Joinder Agreement pursuant to the terms of the Collateral Agency Agreement; and provided, further, that no Affiliate of ours other than Macquarie Bank Limited and its successors may become an Interest Rate Hedge Bank.

“Investment Grade” means BBB- or higher by S&P and Baa3 or higher by Moody’s, or the equivalent of such ratings by S&P or Moody’s or, if either S&P or Moody’s does not make a rating on the Notes publicly available, another Rating Agency.

 

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“Investors” means (i) Macquarie Infrastructure Partners I, (ii) Macquarie Infrastructure Partners II, (iii) Macquarie Capital Group Limited, (iv) FSS Infrastructure Trust, (v) the Canada Pension Plan Investment Board, (vi) the British Columbia Investment Management Corporation, (vii) the Alberta Investment Management Corporation and (viii) each of their respective Affiliates (not including, however, any portfolio companies of any of the Investors). For purposes of the preceding sentence, the term “portfolio companies” does not include, without limitation, (i) any investment fund or investment vehicle managed or co-managed by any Investor or by any of such investment funds’ or investment vehicles’ Affiliates or (ii) any direct or indirect non-operating subsidiary of any Investor.

“Joinder Agreement” means a Joinder Agreement executed by the collateral agent and each Authorized Representative for the Secured Obligations subject thereto in accordance with the terms of the Collateral Agency Agreement.

“Lien” means any mortgage, pledge, hypothecation, assignment, deposit arrangement, encumbrance, lien (statutory or other), charge, or preference, priority or other security interest or preferential arrangement, of any kind or nature whatsoever (including any conditional sale or other title retention agreement, any easement, right of way or other encumbrance on title to real property, and any capitalized lease having substantially the same economic effect as any of the foregoing).

“Loan” means a loan made pursuant to the Credit Agreement.

“Majority Non-Controlling Voting Parties” means, at any time, the Secured Parties owed or holding Secured Obligations that constitute the largest total outstanding amount of any then outstanding Series of Secured Obligations.

“Permitted Holders” means each of the Investors and members of our management (or of our direct or indirect parent) who are holders of our Voting Stock (or any of its direct or indirect parent companies) on the issue date of the Notes and any “group” (as such term is used in Section 13(d) and 14(d) of the Exchange Act or any successor provision) of which any of the foregoing are members; provided, that, in the case of such group and without giving effect to the existence of such group or any other group, such Investors and members of management, collectively, have beneficial ownership of a majority of the total voting power of our Voting Stock.

“Permitted Liens” means liens securing our Indebtedness and liens permitted by our senior secured credit facility (and any amendments, refinancings and replacements thereof).

“Pledge Agreement” means the Amended and Restated Pledge Agreement dated as of February 6, 2009, as amended and restated as of May 10, 2010, and as amended by Amendment No. 1 to Amended and Restated Pledge Agreement dated as of February 10, 2012.

“Rating Agency” means each of Standard & Poor’s and Moody’s or, if Standard & Poor’s or Moody’s or both does not make a rating on the Notes publicly available, a nationally recognized statistical rating organization or organizations, as the case may be, selected by us (as certified by a resolution of our board of directors), which will be substituted for Standard & Poor’s or Moody’s, or both, as the case may be.

“Ratings Event” means a decrease in the ratings of the Notes by one or more gradations (including gradations within categories as well as between rating categories) by each of the Rating Agencies on any date from the date of the public notice of an arrangement that could result in a Change of Control until the end of the 30-day period following public notice of the occurrence of the Change of Control (which 30-day period will be extended so long as the rating of the Notes is under publicly announced consideration for possible downgrade by either of the Rating Agencies and the other Rating Agency has either downgraded, or publicly announced that it is considering downgrading, the Notes). Notwithstanding the foregoing, if the rating of the Notes by each of the Rating Agencies is Investment Grade, then “Ratings Event” means a decrease in the ratings of the Notes by one or more

 

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gradations (including gradations within categories as well as between rating categories) by each of the Rating Agencies such that the rating of the Notes by each of the Rating Agencies falls below Investment Grade on any date from the date of the public notice of an arrangement that could result in a Change of Control until the end of the 30-day period following public notice of the occurrence of the Change of Control (which 30-day period will be extended so long as the rating of the Notes is under publicly announced consideration for possible downgrade by either of the Rating Agencies and the other Rating Agency has either downgraded, or publicly announced that it is considering downgrading, the Notes).

“Reference Treasury Dealer” means (a) Barclays Capital Inc. or its successor, Merrill Lynch, Pierce, Fenner & Smith Incorporated or its successor and Mizuho Securities USA Inc. or its successor, and (b) one other primary U.S. Government securities dealer in New York City selected by us.

“Reference Treasury Dealer Quotation” means, with respect to each Reference Treasury Dealer and any redemption date, the average, as determined by the Independent Investment Banker, of the bid and asked prices for the Comparable Treasury Issue (expressed in each case as a percentage of its principal amount) quoted in writing to the Independent Investment Banker by such Reference Treasury Dealer at or before 5:00 p.m., New York City time, on the third Business Day preceding such redemption date.

“Required Voting Parties” means, with respect to any proposed decision or action hereunder, the Secured Parties owed or holding more than 50% of the Total Outstandings at such time under (a) until the earlier to occur of (i) the Discharge of Credit Agreement Obligations and (ii) the occurrence of the Majority Non-Controlling Voting Party Enforcement Date (if any), the Credit Agreement, and (b) from and after the earlier to occur of the (i) Discharge of Credit Agreement Obligations and (ii) the occurrence of the Majority Non-Controlling Voting Party Enforcement Date, the applicable Credit Document governing the Series of Secured Obligations of the Majority Non-Controlling Voting Parties at such time.

“Secured Hedge Obligations” means all amounts payable to any Interest Rate Hedge Bank under any Interest Hedging Agreement.

“Secured Obligations” means, (a) all Credit Agreement Obligations, (b) all Secured Hedge Obligations and (c) any Additional Secured Obligations, in each case, whether fixed or contingent, matured or unmatured, whether or not allowed or allowable in an Insolvency and Liquidation Proceeding.

“Secured Parties” means, collectively, the Agents, the lenders under our senior secured credit facility, the Interest Rate Hedge Banks, any Additional Secured Parties and each co-agent or sub-agent appointed by any Agent or from time to time pursuant to any Credit Document or the Collateral Agency Agreement.

“Security Agreement” means the Amended and Restated Borrower Security Agreement, dated as of February 6, 2009 and as amended and restated as of May 10, 2010 and as further amended as of February 10, 2012, between the Borrower and the Collateral Agent (as amended, restated, supplemented or otherwise modified from time to time).

“Security Documents” means, collectively, the Security Agreement, the Pledge Agreement and any other security agreements, pledge agreements or other similar agreements delivered to the Agents, the lenders under our senior secured credit facility, the Interest Rate Hedge Banks and the Additional Secured Parties, and any other agreements, instruments or documents that create or purport to create a Lien in favor of the collateral agent for the benefit of the Secured Parties.

“Series” means each of (a) the Credit Agreement Obligations, (b) any Additional Obligations incurred pursuant to any Additional Credit Document which, pursuant to any Joinder Agreement, are represented hereunder by a common Authorized Representative (in its capacity as such for such Secured Obligations) and (c) the Secured Hedge Obligations.

 

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“Significant Subsidiary” means any subsidiary that would be considered a “significant subsidiary” under Article 1 of Regulation S-X under the Exchange Act.

“Total Outstandings” means, with respect to any Credit Document (other than any Interest Rate Hedging Agreement), at any time, an amount equal to the sum of, without duplication, the aggregate unpaid principal amount of Loans or other indebtedness outstanding under such Credit Document at such time after giving effect to any borrowings, advances and prepayments or repayments of any Loans or indebtedness under the Credit Agreement or such other Credit Document, as the case may be, on such date, plus the amount of any unfunded commitments under the Credit Agreement or such other Credit Document, as the case may be, on such date.

“Treasury Rate” means, with respect to any redemption date, the rate per year equal to the semiannual equivalent yield to maturity of the Comparable Treasury Issue, assuming a price for the Comparable Treasury Issue (expressed as a percentage of its principal amount) equal to the Comparable Treasury Price for such redemption date.

“Unanimous Voting Parties” means, with respect to any Intercreditor Vote, each of the Credit Agreement Administrative Agent, each of the Authorized Representatives appointed under each Additional Credit Document and each Interest Rate Hedge Bank, in each case casting votes representing 100% of the Voting Party Percentage applicable to each such Series of Secured Obligations.

“Voting Parties” means the lenders under our senior secured credit facility, any Additional Secured Party and, subject to the terms of the Collateral Agency Agreement, each Interest Rate Hedge Bank.

“Voting Party Percentage” means, in connection with any proposed decision or action under the Collateral Agency Agreement, the actual percentage, as determined pursuant to the terms of the Collateral Agency Agreement, of allotted votes cast in favor of such decision or action by the Secured Parties entitled to vote with respect to such decision or action.

“Voting Stock” means securities of any class or classes the holders of which are ordinarily, in the absence of contingencies, entitled to vote for corporate directors (or persons performing similar functions).

MATERIAL UNITED STATES FEDERAL INCOME TAX CONSIDERATIONS

The following summary describes the material United States federal income tax consequences relevant to the exchange of original notes for exchange notes pursuant to the exchange offer. The following discussion is based on the provisions of the United States Internal Revenue Code of 1986, as amended, or the Code, and related United States Treasury regulations, administrative rulings and judicial decisions now in effect, changes to which subsequent to the date hereof may affect the tax consequences described below.

We encourage holders to consult their own tax advisors regarding the United States federal tax consequences of the exchange offer and being a holder of the notes in light of their particular circumstances, as well as any tax consequences arising under the laws of any state, local or foreign taxing jurisdiction.

An exchange of original notes for exchange notes pursuant to the exchange offer will not be a taxable event for United States federal income tax purposes. Consequently, holders will not recognize any taxable gain or loss as a result of exchanging original notes for exchange notes pursuant to the exchange offer. The holding period of the exchange notes will include the holding period of the original notes, and the tax basis in the exchange notes will be the same as the tax basis in the original notes immediately before the exchange.

 

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PLAN OF DISTRIBUTION

Based on interpretations of the SEC staff in no-action letters issued to third parties, we believe that you may resell or otherwise transfer exchange notes issued in the exchange offer without further compliance with the registration and prospectus delivery requirements of the Securities Act if:

 

•

you are not our affiliate within the meaning of Rule 405 under the Securities Act;

 

•

you are acquiring such exchange notes in the ordinary course of your business;

 

•

you do not intend to participate in the distribution of exchange notes; and

 

•

you are not a broker-dealer and are not engaged in, and do not intend to engage in, the distribution of the exchange notes.

We believe that you may not transfer exchange notes issued in the exchange offer without further compliance with such requirements or an exemption from such requirements if you are:

 

•

our affiliate within the meaning of Rule 405 under the Securities Act, or

 

•

a broker-dealer that acquired original notes as a result of market-making or other trading activities.

The information described above concerning interpretations of and positions taken by the SEC staff is not intended to constitute legal advice. Broker-dealers should consult their own legal advisors with respect to these matters.

If you wish to exchange your original notes for exchange notes in the exchange offer, you will be required to make representations to us as described in “The Exchange Offer—Procedures for Tendering” and “—Your Representations to Us” of this prospectus and in the letter of transmittal. In addition, if a broker-dealer acquired original notes as a result of market-making activities or other trading activities, it may exchange them for exchange notes, however, such broker-dealer may be deemed to be an “underwriter” within the meaning of the Securities Act and must, therefore, deliver a prospectus meeting the requirements of the Securities Act in connection with any resales of the exchange notes received by such broker-dealer and such broker-dealer will be required to acknowledge the same. The letter of transmittal states that, by acknowledging that it will deliver and by delivering a prospectus, a broker-dealer will not be deemed to admit that it is an underwriter within the meaning of the Securities Act. A broker-dealer may use this prospectus, as amended or supplemented, in connection with these resales, and all dealers effecting transactions in the exchange notes may be required to deliver a prospectus, as amended or supplemented for 180 days following consummation of the exchange offer or until such time that the broker-dealer is no longer required to deliver a prospectus in connection with market-making or other trading activities. We will provide copies of this prospectus and any amendment or supplement to this prospectus to any broker-dealer that requests such documents during such 180-day (or shorter, if no longer required to deliver a prospectus) period in order to facilitate such resales. We have agreed to pay all expenses incident to the exchange offer (including certain expenses of counsel for the initial purchasers) other than dealers’ and brokers’ discounts, commissions and counsel fees and will indemnify the holders of the exchange notes (including any broker-dealer) against certain liabilities, including liabilities under the Securities Act.

We will not receive any proceeds from any sale of exchange notes by broker-dealers. Exchange notes received by broker-dealers for their own account in the exchange offer may be sold from time to time in one or more transactions:

 

•

in the over-the-counter market,

 

•

in negotiated transactions,

 

•

through the writing of options on the exchange notes, or

 

•

a combination of such methods of resale.

 

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The prices at which these sales occur may be:

 

•

at market prices prevailing at the time of resale,

 

•

at prices related to such prevailing market prices, or

 

•

at negotiated prices.

Any such resale may be made directly to purchasers or to or through brokers or dealers who may receive compensation in the form of commissions or concessions from any such broker-dealer or the purchasers of any exchange notes. Any profit on any resale of exchange notes and any commission or concessions received by any such persons may be deemed to be underwriting compensation.

LEGAL MATTERS

Certain legal matters in connection with the exchange of the Notes will be passed upon for us by Perkins Coie LLP, 1201 Third Avenue, Seattle, Washington.

EXPERTS

The financial statements as of December 31, 2014 and 2013 and for each of the three years in the period ended December 31, 2014 and management’s assessment of the effectiveness of internal control over financial reporting (which is included in Management’s Report on Internal Control over Financial Reporting) as of December 31, 2014 included in this prospectus have been so included in reliance on the reports of PricewaterhouseCoopers LLP, an independent registered public accounting firm, given on the authority of said firm as experts in auditing and accounting.

WHERE YOU CAN FIND MORE INFORMATION

We and our subsidiary PSE each file reports and information statements and other information with the SEC. You can inspect and copy reports and other information filed by us and PSE at the public reference facilities maintained by the SEC at Headquarters Office, 100 F Street, N.E., Washington, D.C. 20549. The public may obtain information on the operation of the Public Reference Room by calling the SEC at 1-800-SEC-0330. Such material may also be accessed electronically by means of the SEC’s website on the Internet at http://www.sec.gov. Additionally, Puget Energy’s and PSE’s reports on Form 10-K, quarterly reports on Form 10-Q, current reports on Form 8-K and amendments to these 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 at the Company’s website, www.pugetenergy.com.

 

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INDEX TO CONSOLIDATED FINANCIAL STATEMENTS

 

		PAGE
Report of Independent Registered Public Accounting Firm
Report of Independent Registered Public Accounting Firm—Puget Energy			F-2
Audited Consolidated Financial Statements of Puget Energy:
Consolidated Statements of Income - Years Ended December 31, 2014 and 2013			F-3
Consolidated Balance Sheets - December 31, 2014 and 2013			F-5
Consolidated Statements of Common Shareholder’s Equity - Years Ended December 31, 2014 and 2013			F-7
Notes to Consolidated Financial Statements			F-9
Unaudited Consolidated Financial Statements of Puget Energy:
Consolidated Statements of Income - Three and Nine Months Ended September 30, 2015 and 2014			F-57
Consolidated Statements of Comprehensive Income - Three and Nine Months Ended September 30, 2015 and 2014			F-58
Consolidated Balance Sheets - September 30, 2015 and December 31, 2014			F-59
Consolidated Statements of Cash Flows - Nine Months Ended September 30, 2015 and 2014			F-61
Notes to Consolidated Financial Statements			F-62

 

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REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the Board of Directors and Shareholder of

Puget Energy, Inc.

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, 2014 and December 31, 2013, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2014 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. Also in our opinion, the Company maintained, in all material respects, effective internal control over financial reporting as of December 31, 2014, based on criteria established in Internal Control—Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO). The Company’s management is responsible 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 appearing under Item 9A. 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 in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audits 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. Our 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 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 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

Seattle, Washington

February 27, 2015

 

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PUGET ENERGY, INC.

CONSOLIDATED STATEMENTS OF INCOME

(Dollars in Thousands)

 

		Year Ended December 31,
		2014				2013				2012
Operating revenue:
Electric		$	2,083,797			$	2,156,920			$	2,128,230
Gas			1,012,859				1,028,357				1,086,095
Other			16,515				2,020				831
Total operating revenue			3,113,171				3,187,297				3,215,156
Operating expenses:
Energy costs:
Purchased electricity			514,087				541,905				622,288
Electric generation fuel			263,493				261,332				204,956
Residential exchange			(129,036	)			(81,053	)			(73,555	)
Purchased gas			458,691				488,201				538,612
Unrealized (gain) loss on derivative instruments, net			84,146				(102,744	)			(133,606	)
Utility operations and maintenance			550,146				529,939				512,765
Non-utility expense and other			13,109				(3,555	)			814
Depreciation			370,962				364,324				337,952
Amortization			(5,356	)			24,631				55,819
Conservation amortization			104,096				105,897				114,177
Taxes other than income taxes			310,982				303,260				319,399
Total operating expenses			2,535,320				2,432,137				2,499,621
Operating income (loss)			577,851				755,160				715,535
Other income (deductions):
Other income			24,038				38,693				49,069
Other expense			(7,457	)			(7,134	)			(11,770	)
Non-hedged interest rate swap expense			(3,915	)			2,420				(4,288	)
Interest charges:
AFUDC			5,611				11,261				22,216
Interest expense			(367,308	)			(392,264	)			(392,216	)
Income (loss) before income taxes			228,820				408,136				378,546
Income tax (benefit) expense			56,985				122,408				104,725
Net income (loss)		$	171,835			$	285,728			$	273,821

The accompanying notes are an integral part of the consolidated financial statements.

 

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PUGET ENERGY, INC.

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME

(Dollars in Thousands)

 

		Year Ended December 31,
		2014				2013				2012
Net income (loss)		$	171,835			$	285,728			$	273,821
Other comprehensive income (loss):
Net unrealized gain (loss) from pension and postretirement plans, net of tax of $(45,890), $41,773 and $(7,469), respectively			(85,224	)			77,579				(13,870	)
Reclassification of net unrealized (gain) loss on energy derivative instruments settled during the period, net of tax of $200, $20 and $200, respectively			372				37				371
Reclassification of net unrealized (gain) loss on interest rate swaps during the period, net of tax of $50, $1,577 and $6,234, respectively			94				2,928				11,577
Other comprehensive income (loss)			(84,758	)			80,544				(1,922	)
Comprehensive income (loss)		$	87,077			$	366,272			$	271,899

The accompanying notes are an integral part of the consolidated financial statements.

 

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PUGET ENERGY, INC.

CONSOLIDATED BALANCE SHEETS

(Dollars in Thousands)

ASSETS

 

		December 31,
		2014				2013
Utility plant (at original cost, including construction work in progress of $239,690 and $310,318, respectively):
Electric plant		$	7,135,206			$	7,019,853
Gas plant			2,680,067				2,528,629
Common plant			472,926				504,036
Less: Accumulated depreciation and amortization			(1,611,220	)			(1,373,178	)
Net utility plant			8,676,979				8,679,340
Other property and investments:
Goodwill			1,656,513				1,656,513
Other property and investments			91,139				100,332
Total other property and investments			1,747,652				1,756,845
Current assets:
Cash and cash equivalents			37,527				44,302
Restricted cash			32,863				7,171
Accounts receivable, net of allowance for doubtful accounts of $7,472 and $7,385, respectively			306,923				408,512
Unbilled revenue			168,039				219,884
Purchased gas adjustment receivable			21,073				—
Materials and supplies, at average cost			83,189				88,140
Fuel and gas inventory, at average cost			69,433				66,717
Unrealized gain on derivative instruments			21,178				18,867
Taxes			301				297
Prepaid expense and other			20,905				18,787
Power contract acquisition adjustment gain			43,843				48,509
Deferred income taxes			161,445				86,004
Total current assets			966,719				1,007,190
Other long-term and regulatory assets:
Regulatory asset for deferred income taxes			95,432				146,867
Power cost adjustment mechanism			4,623				—
Regulatory assets related to power contracts			29,816				33,753
Other regulatory assets			866,835				749,382
Unrealized gain on derivative instruments			3,170				7,733
Power contract acquisition adjustment gain			347,547				394,556
Other			96,275				130,909
Total other long-term and regulatory assets			1,443,698				1,463,200
Total assets		$	12,835,048			$	12,906,575

The accompanying notes are an integral part of the consolidated financial statements.

 

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PUGET ENERGY, INC.

CONSOLIDATED BALANCE SHEETS

(Dollars in Thousands)

CAPITALIZATION AND LIABILITIES

 

		December 31,
		2014				2013
Capitalization:
Common shareholder’s equity:
Common stock $0.01 par value, 1,000 shares authorized, 200 shares outstanding		$	—			$	—
Additional paid-in capital			3,308,957			$	3,308,957
Earnings reinvested in the business			271,414				323,007
Accumulated other comprehensive income (loss), net of tax			(37,043	)			47,715
Total common shareholder’s equity			3,543,328				3,679,679
Long-term debt:
First mortgage bonds and senior notes			3,189,412				3,351,412
Pollution control bonds			161,860				161,860
Junior subordinated notes			250,000				250,000
Long-term debt			1,699,000				1,699,000
Debt discount and other			(218,664	)			(229,796	)
Total long-term debt			5,081,608				5,232,476
Total capitalization			8,624,936				8,912,155
Current liabilities:
Accounts payable			307,578				296,681
Short-term debt			85,000				162,000
Current maturities of long-term debt			162,000				—
Purchased gas adjustment liability			—				5,938
Accrued expenses:
Taxes			107,782				109,559
Salaries and wages			40,970				38,491
Interest			78,914				79,303
Unrealized loss on derivative instruments			142,195				48,049
Power contract acquisition adjustment loss			3,593				3,937
Other			62,464				60,335
Total current liabilities			990,496				804,293
Other Long-term and regulatory liabilities:
Deferred income taxes			1,522,357				1,487,005
Unrealized loss on derivative instruments			62,913				38,162
Power Cost Adjustment Mechanism			—				5,345
Regulatory liabilities			633,471				689,060
Regulatory liabilities related to power contracts			391,389				443,065
Power contract acquisition adjustment loss			26,223				29,816
Other deferred credits			583,263				497,674
Total other long-term and regulatory liabilities			3,219,616				3,190,127
Commitments and contingencies (Note 15)
Total capitalization and liabilities		$	12,835,048			$	12,906,575

The accompanying notes are an integral part of the consolidated financial statements.

 

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PUGET ENERGY, INC.

CONSOLIDATED STATEMENTS OF COMMON SHAREHOLDER’S EQUITY

(Dollars in Thousands)

 

		Common Stock								Additional Paid-in Capital				Earnings Reinvested in the Business				Accumulated Other Comprehensive Income (Loss)				Total Equity
		Shares				Amount
Balance at December 31, 2011			200			$	—			$	3,308,957			$	22,873			$	(30,907	)		$	3,300,923
Net income (loss)			—				—				—				273,821				—				273,821
Common stock dividend			—				—				—				(88,594	)			—				(88,594	)
Other comprehensive income (loss)			—				—				—				—				(1,922	)			(1,922	)
Balance at December 31, 2012			200			$	—			$	3,308,957			$	208,100			$	(32,829	)		$	3,484,228
Net income (loss)			—				—				—				285,728				—				285,728
Common stock dividend			—				—				—				(170,821	)			—				(170,821	)
Other comprehensive income (loss)			—				—				—				—				80,544				80,544
Balance at December 31, 2013			200			$	—			$	3,308,957			$	323,007			$	47,715			$	3,679,679
Net income (loss)			—				—				—				171,835				—				171,835
Common stock dividend			—				—				—				(223,428	)			—				(223,428	)
Other comprehensive income (loss)			—				—				—				—				(84,758	)			(84,758	)
Balance at December 31, 2014			200			$	—			$	3,308,957			$	271,414			$	(37,043	)		$	3,543,328

The accompanying notes are an integral part of the consolidated financial statements.

 

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PUGET ENERGY, INC.

CONSOLIDATED STATEMENTS OF CASH FLOWS

(Dollars in Thousands)

 

		Year Ended December 31,
		2014				2013				2012
Operating activities:
Net income (loss)		$	171,835			$	285,728			$	273,821
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
Depreciation			370,962				364,324				337,952
Amortization			(5,356	)			24,631				55,819
Conservation amortization			104,096				105,897				114,177
Deferred income taxes and tax credits, net			56,984				122,409				100,457
Gain on land sales			(4,071	)			—				—
Net unrealized (gain) loss on derivative instruments			80,139				(106,540	)			(146,680	)
Derivative contracts classified as financing activities due to merger			16,349				34,250				92,681
AFUDC—equity			(7,002	)			(15,930	)			(25,469	)
Funding of pension liability			(18,000	)			(20,400	)			(22,800	)
Regulatory assets			(219,604	)			(122,549	)			(170,374	)
Regulatory liabilities			(8,730	)			50,025				14,054
Other long-term assets			(6,003	)			(24,877	)			(1,644	)
Other long-term liabilities			29,765				180,015				95,166
Change in certain current assets and liabilities:
Accounts receivable and unbilled revenue			153,434				(103,949	)			35,537
Materials and supplies			4,951				(5,787	)			(6,284	)
Fuel and gas inventory			(2,742	)			21,633				11,527
Taxes			(4	)			4,499				6,174
Prepayments and other			(2,136	)			(5,357	)			393
Purchased gas adjustment			(27,011	)			(26,649	)			6,647
Accounts payable			9,098				4,597				(25,963	)
Taxes payable			(1,777	)			13,936				4,896
Accrued expenses and other			6,605				(13,838	)			32,598
Net cash provided by operating activities			701,782				766,068				782,685
Investing activities:
Construction expenditures—excluding equity AFUDC			(493,130	)			(567,938	)			(859,791	)
Treasury grants received			107,876				—				205,261
Proceeds from disposition of assets			20,296				108,362				—
Restricted cash			(25,692	)			(3,471	)			483
Other			(4,512	)			(17,871	)			(38,923	)
Net cash used in investing activities			(395,162	)			(480,918	)			(692,970	)
Financing activities:
Change in short-term debt, net			(77,000	)			(26,578	)			148,437
Dividends paid			(223,428	)			(170,821	)			(88,594	)
Long-term notes and bonds issued			299,000				161,860				1,314,000
Redemption of bonds and notes			(299,000	)			(309,860	)			(1,273,000	)
Derivative contracts classified as financing activities due to merger			(16,349	)			(34,250	)			(92,681	)
Issuance cost of bonds and other			3,382				3,259				430
Net cash provided by (used in) financing activities			(313,395	)			(376,390	)			8,592
Net increase (decrease) in cash and cash equivalents			(6,775	)			(91,240	)			98,307
Cash and cash equivalents at beginning of period			44,302				135,542				37,235
Cash and cash equivalents at end of period		$	37,527			$	44,302			$	135,542
Supplemental cash flow information:
Cash payments for interest (net of capitalized interest)		$	349,402			$	334,041			$	318,305
Cash payments (refunds) for income taxes			—				(4,500	)			(1,898	)
Non-cash financing and investing activities:
Accounts payable for capital expenditures eliminated from cash flows		$	51,776			$	49,977			$	79,852

The accompanying notes are an integral part of the consolidated financial statements.

 

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COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(1) Summary of Significant Accounting Policies

Basis of Presentation

Puget Energy, Inc. (Puget Energy) is an energy services holding company that owns Puget Sound Energy, Inc. (PSE). PSE is a public utility incorporated in the state of Washington that furnishes electric and natural gas services in a territory covering 6,000 square miles, primarily in the Puget Sound region. In 2009, Puget Holdings LLC (Puget Holdings), owned by a consortium of long-term infrastructure investors, completed its merger with Puget Energy (the merger). As a result of the merger, all of Puget Energy’s common stock is indirectly owned by Puget Holdings. The acquisition of Puget Energy was accounted for in accordance with 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.

The consolidated financial statements of Puget Energy reflect the accounts of Puget Energy and its subsidiary, PSE. PSE’s consolidated financial statements include the accounts of PSE and its subsidiary. 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. PSE’s consolidated financial statements continue to be accounted for on 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 U.S. 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 revenue and expenses during the reporting period. Actual results could differ from those estimates.

PSE collected Washington State excise taxes (which are a component of general retail customer rates) and municipal taxes totaling $231.7 million, $243.9 million and $244.2 million for 2014, 2013 and 2012, respectively. The Company reports the collection of such taxes on a gross basis in operation revenue and as expense in taxes other than income taxes in the accompanying consolidated statements of income.

Beginning July 1, 2013, PSE’s electric and gas operations contain a revenue decoupling mechanism under which PSE’s actual energy delivery revenues related to electric transmission and distribution, gas operations and general administrative costs are compared with authorized revenues allowed under the mechanism. Any differences are deferred to a regulatory asset for under recovery or regulatory liability for over recovery. Revenues associated with power costs under the Power Cost Adjustment (PCA) mechanism and Purchased Gas Adjustment (PGA) rates are excluded from the decoupling mechanism.

Utility Plant

Puget Energy and PSE capitalize, at original cost, additions to utility plant, including renewals and betterments. Costs include indirect costs such as engineering, supervision, certain taxes, pension and other employee benefits and an Allowance for Funds Used During Construction (AFUDC). Replacements of minor items of property are included in maintenance expense. When the utility plant is retired and removed from service, the original cost of the property is charged to accumulated depreciation and costs associated with removal of the property, less salvage, are charged to the cost of removal regulatory liability.

Planned Major Maintenance

Planned major maintenance is an activity that typically occurs when PSE overhauls or substantially upgrades various systems and equipment on its natural gas fired combustion turbines on a scheduled basis. Costs related to planned major maintenance are deferred and amortized to the next scheduled major maintenance. This

 

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accounting method also follows the Washington Utilities and Transportation Commission (Washington Commission) regulatory treatment related to these generating facilities.

Non-Utility Property, Plant and Equipment

For 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 are expensed on a current basis. Gains and losses on assets sold or retired are reflected in earnings.

Depreciation and Amortization

For financial statement purposes, the Company provides for depreciation and amortization on a straight-line basis. Amortization is recorded for intangibles such as regulatory assets and liabilities, computer software and franchises. The depreciation of vehicles and equipment is allocated to the asset and expense accounts based on usage. The annual depreciation provision stated as a percent of a depreciable electric utility plant was 2.8%, 2.8% and 2.9% in 2014, 2013 and 2012, respectively; depreciable gas utility plant was 3.4%, 3.4% and 3.4% in 2014, 2013 and 2012, respectively; and depreciable common utility plant was 8.5%, 11.4% and 11.6% in 2014, 2013 and 2012, respectively. The decrease in depreciable common utility plant that occurred between 2014 and 2013 was primarily due to asset retirement. 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.

Goodwill

In 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 Company’s business or regulatory outlook, legal factors, a sale or disposition of a significant portion of a reporting unit or significant changes in the financial markets which could influence the Company’s access to capital and interest rates. Application of the goodwill impairment test requires judgment, including the identification of reporting units, assignment of assets and liabilities to reporting units, assignment of goodwill to reporting units and the determination of the fair value of the reporting units. Management has determined Puget Energy has only one reporting unit.

The goodwill recorded by Puget Energy represents the potential long-term return to the Company’s 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 would entail a full valuation of Puget Energy’s assets and liabilities and comparing the valuation to its carrying amounts, with the aggregate difference indicating the amount of impairment. Goodwill of a reporting unit is required to 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 test in 2014 using an October 1, 2014 measurement date. The fair value of Puget Energy’s reporting unit was estimated using both discounted cash flow and market approach. Such approaches are considered methodologies that market participants would use. This analysis requires significant judgments, including estimation of future cash flows, which is dependent on internal forecasts, estimation of long-term rate of growth for Puget Energy business, estimation of the useful life over which cash flows will occur, the selection of utility holding companies determined to be comparable to Puget

 

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Energy and determination of an appropriate weighted-average cost of capital or discount rate. The market approach estimates the fair value of the business based on market prices of stocks of comparable 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 was no indication of impairment of Puget Energy’s goodwill as of October 1, 2014. There were no known events or circumstances from the date of the assessment through December 31, 2014 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 time of purchase. The cash and cash equivalents balance at Puget Energy was $37.5 million and $44.3 million as of December 31, 2014 and 2013, respectively. The 2014 and 2013 balance consisted of cash equivalents, which are reported at cost and approximate fair value, and were $1.8 million and $2.6 million, respectively.

Materials and Supplies

Materials and supplies are used primarily 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. Puget Energy and PSE record these items at weighted-average cost.

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. Puget Energy and PSE record these items at the lower of cost or market value using the weighted-average cost method.

Regulatory Assets and Liabilities

PSE accounts for its regulated operations in accordance with ASC 980 “Regulated Operations” (ASC 980). ASC 980 requires PSE to defer certain costs that would otherwise be charged to expense, if it is probable that future rates will permit recovery of such costs. It similarly requires deferral of revenues or gains and losses that are expected to be returned to customers in the future. Accounting under ASC 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, PSE classifies regulatory assets and liabilities as long-term due to the length of the amortization. For further details regarding regulatory assets and liabilities, see Note 3.

Allowance for Funds 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.

 

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The AFUDC rates authorized by the Washington Commission for natural gas and electric utility plant additions based on the effective dates are as follows:

 

Effective Date		Washington Commission AFUDC Rates
July 1, 2013 - present			7.77	%
May 14, 2012 - June 30, 2013			7.80
April 8, 2010 - May 13, 2012			8.10

The Washington Commission authorized the Company to calculate AFUDC using its allowed rate of return. To the extent amounts calculated using this rate exceed the AFUDC calculated rate using the Federal Energy Regulatory Commission (FERC) formula, PSE capitalizes the excess as a deferred asset, crediting other income. The deferred asset is being amortized over the average useful life of PSE’s non-project electric utility plant which is approximately 30 years.

Revenue Recognition

Operating utility revenue is recognized when the basis of services is rendered, which includes estimated unbilled revenue, in accordance with ASC 605, “Revenue Recognition” (ASC 605). PSE’s estimate of unbilled revenue is based on a calculation using meter readings from its automated meter reading (AMR) system. The estimate calculates unbilled usage at the end of each month as the difference between the customer meter readings on the last day of the month and the last customer meter readings billed. The unbilled usage is then priced at published rates for each schedule to estimate the unbilled revenues by customer.

The non-utility subsidiary recognizes 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 (RECs) are deferred as a regulatory liability.

Beginning July 1, 2013, PSE’s electric and gas operations contain a revenue decoupling mechanism under which PSE’s actual energy delivery revenues related to electric transmission and distribution, gas operations and general administrative costs are compared with authorized revenues allowed under the mechanism. Any differences are deferred to a regulatory asset for under recovery or regulatory liability for over recovery. Revenues associated with power costs under the PCA mechanism and PGA rates are excluded from the decoupling mechanism. The decoupling mechanism reduces earnings volatility, but does not materially affect the timing of cash flow due to the timing difference between the recognition of decoupling revenue and resulting impacts on rates.

Allowance for Doubtful Accounts

Allowance for doubtful accounts are provided for electric and natural gas customer accounts based upon a historical experience rate of write-offs of energy accounts receivable along with information on future economic outlook. The allowance account is adjusted monthly for this experience rate. The allowance account is maintained until either receipt of payment or the likelihood of collection is considered remote at which time the allowance account and corresponding receivable balance are written off.

The Company’s allowance for doubtful accounts at December 31, 2014 and 2013 was $7.5 million and $7.4 million, respectively.

Self-Insurance

PSE is self-insured for storm damage and environmental contamination occurring on PSE-owned property. In addition, PSE is required to meet a deductible for a portion of the risk associated with comprehensive liability,

 

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workers’ compensation claims and catastrophic property losses other than those which are storm related. The Washington Commission has approved the deferral of certain uninsured qualifying storm damage costs that exceed $8.0 million which will be requested for collection in future rates. Additionally, costs may only be deferred if the outage meets the Institute of Electrical and Electronics Engineers (IEEE) outage criteria for system average interruption duration index.

Federal Income Taxes

For presentation in Puget Energy and PSE’s separate financial statements, income taxes are allocated to the subsidiaries on the basis of separate company computations of tax, modified by allocating certain consolidated group limitations which are attributed to the separate company. Taxes payable or receivable are settled with Puget Holdings.

Natural Gas Off-System Sales and Capacity Release

PSE 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, PSE 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. PSE 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, PSE nets the sales revenue and associated cost of sales for these transactions in purchased natural gas.

Non-Core Gas Sales

As part of the Company’s electric operations, PSE provides natural gas to its gas-fired generation facilities. The projected volume of natural gas for power is relative to the price of natural gas. Based on the market prices for natural gas, PSE may use the gas it has already purchased to generate power or PSE may sell the already purchased natural gas. The net proceeds from selling natural gas, previously purchased for power generation, are accounted for in other electric operating revenue and are included in the PCA mechanism.

Production Tax Credit

Production Tax Credits (PTCs) represent federal income tax incentives available to taxpayers that generate energy from qualifying renewable sources. PSE records the benefit of the PTCs as a regulatory liability until such time as PSE utilizes the tax credit on its tax return. Once utilized, PSE will pass the benefit to customers.

Accounting for Derivatives

ASC 815 requires that all contracts considered to be derivative instruments be recorded on the balance sheet at their fair value unless the contracts qualify for an exception. PSE enters into derivative contracts to manage its energy resource portfolio and interest rate exposure including forward physical and financial contracts and swaps. Some of PSE’s physical electric supply contracts qualify for the Normal Purchase Normal Sale (NPNS) exception to derivative accounting rules. PSE may enter into financial fixed price contracts to economically hedge the variability of certain index-based contracts. Those contracts that do not meet the NPNS 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 PGA mechanism.

 

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Puget Energy and PSE elected to de-designate all energy related derivative contracts previously recorded as cash flow hedges for the purpose of simplifying its financial reporting in 2009. The contracts that were de-designated related to physical electric supply contracts and natural gas swap contracts used to fix the price of natural gas for electric generation. For these contracts and for contracts initiated after such date, all mark-to-market adjustments are recognized through earnings. The amount previously recorded in accumulated OCI is transferred to earnings in the same period or periods during which the hedged transaction affects earnings or sooner if management determines that the forecasted transaction is probable of not occurring. As a result, the Company will continue to experience the earnings impact of these reversals from OCI in future periods. When these contracts are settled, the contract price becomes part of purchased electricity or electric generation fuel which becomes part of PSE’s PCA mechanism and the unrealized gain or loss is listed separately under energy costs, as it represents the non-rate treatment of energy costs.

The Company may enter into swap instruments or other financial derivative instruments to manage the interest rate risk associated with its long-term debt financing and debt instruments. As of December 31, 2014, Puget Energy has interest rate swap contracts outstanding related to its long-term debt. For additional information, see Note 9 Accounting for Derivative Instruments and Hedging Activities.

Fair Value Measurements of Derivatives

ASC 820, “Fair Value Measurements and Disclosures” (ASC 820), defines 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). 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 as it believes that the approach is used by market participants for these types of assets and liabilities. Accordingly, the Company utilizes valuation techniques that maximize the use of observable inputs and minimize the use of unobservable inputs.

The Company values 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 instruments are sensitive to market price fluctuations that can occur on a daily basis. For additional information, see Note 10 Fair Value Measurements.

Debt Related Costs

Debt premiums, discounts, expenses and amounts received or incurred to settle hedges are amortized over the life of the related 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 for PSE.

 

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Accumulated Other Comprehensive Income (Loss)

The following tables set forth the components of the Company’s accumulated other comprehensive income (loss) at:

 

Puget Energy		December 31,
(Dollars in Thousands)		2014				2013
Net unrealized loss on energy derivative instruments		$	(333	)		$	(705	)
Net unrealized loss on interest rate swaps			—				(94	)
Net unrealized loss and prior service cost on pension plans			(36,710	)			48,514
Total Puget Energy, net of tax		$	(37,043	)		$	47,715

 

Puget Sound Energy		December 31,
(Dollars in Thousands)		2014				2013
Net unrealized loss on energy derivative instruments		$	(686	)		$	(2,027	)
Net unrealized loss on treasury interest rate swaps			(5,990	)			(6,307	)
Net unrealized loss and prior service cost on pension plans			(164,281	)			(87,405	)
Total PSE, net of tax		$	(170,957	)		$	(95,739	)

(2) New Accounting Pronouncements

Income Statement

In May 2014, the FASB issued Accounting Standards Update (ASU) No. 2014-09, “Revenue from Contracts with Customers (Topic 606)”, that outlines a single comprehensive model for use in accounting for revenue arising from contracts with customers and supersedes most current revenue recognition guidance, including industry-specific guidance. The ASU is based on the principle that an entity should recognize revenue to depict the transfer of goods or services to customers in an amount that reflects the consideration to which the entity expects to be entitled in exchange for those goods or services. The ASU also requires additional disclosure about the nature, amount, timing and uncertainty of revenue and cash flows arising from customer contracts, including significant judgments and changes in judgments and assets recognized from costs incurred to fulfill a contract.

ASU 2014-09 is effective for fiscal years, and interim periods within those years, beginning after December 15, 2016. Early adoption of the ASU is not permitted. Entities have the option of using either a full retrospective or a modified retrospective approach for the adoption of the new standard. The Company initiated a steering committee and project team to evaluate the impact of this standard, update any policies and procedures that may be affected and implement the new revenue recognition guidance. At this time, the Company cannot determine the impact this standard will have on its consolidated financial statements.

Extraordinary and Unusual Items

In January 2015, the FASB issued ASU 2015-01, “Income Statement—Extraordinary and Unusual Items (Subtopic 225-20): Simplifying Income Statement Presentation by Eliminating the Concept of Extraordinary Items.” As part of FASB’s initiative to reduce complexity in accounting standards, it issued ASU 2015-01, which eliminates from GAAP the concept of extraordinary items. Currently, Subtopic 225-20 requires an entity to separately classify, present and disclose extraordinary events and transactions. ASU 2015-01 will align GAAP income statement presentation guidance with International Accounting Standards 1, Presentation of Financial Statements, which prohibits the presentation and disclosure of extraordinary items.

ASU 2015-01 is effective for fiscal years, and interim periods within those fiscal years, beginning after December 15, 2015. The Company is permitted to apply amendments prospectively or retrospectively to all prior

 

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periods presented in the financial statements. Early adoption is permitted, provided that the guidance is applied from the beginning of the fiscal year of adoption. At this time, the Company doesn’t expect this standard to have a material effect on the Company’s financial position or results of operations.

(3) Regulation and Rates

Regulatory Assets and Liabilities

ASC 980 requires PSE to defer certain costs that would otherwise be charged to expense, if it is probable that future rates will permit recovery of such costs. It similarly requires deferral of revenues or gains and losses that are expected to be returned to customers in the future.

Below is a chart with the allowed return on the net regulatory assets and liabilities and the associated time periods:

 

Period		Rate of Return				After-Tax Return
July 1, 2013 - present			7.77	%			6.69	%
May 14, 2012 - June 30, 2013			7.80				6.71
April 8, 2010 - May 13, 2012			8.10				6.90

 

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The net regulatory assets and liabilities at December 31, 2014 and 2013 included the following:

 

Puget Sound Energy		Remaining Amortization Period				December 31,
(Dollars in Thousands)						2014				2013
PGA deferral of unrealized losses on derivative instruments				(a)		$	69,280			$	27,555
Chelan PUD contract initiation			16.8 Years				119,316				126,404
Storm damage costs electric			1 to 4 years				118,824				116,328
Environmental remediation				(a)			66,018				57,342
Baker Dam licensing operating and maintenance costs			44 years				61,577				57,270
Snoqualmie licensing operating and maintenance costs			30 years				9,202				10,881
Colstrip common property			9.5 years				6,764				7,479
Deferred income taxes				(a)			94,913				146,350
Deferred Washington Commission AFUDC			35 years				53,709				55,495
Energy conservation costs			1 to 2 years				42,374				35,987
Unamortized loss on reacquired debt			1 to 21.5 years				35,667				37,832
White River relicensing and other costs			17.9 years				26,685				28,190
Mint Farm ownership and operating costs			10.3 years				20,320				22,320
Investment in Bonneville Exchange power contract			2.5 years				8,816				12,343
Ferndale			4.8 years				19,232				22,811
Lower Snake River			1.3 to 22.3 years				86,275				92,924
Snoqualmie			3.8 years				6,798				8,009
Property tax tracker			Less than 2 years				32,253				22,134
PGA receivable			1 year				21,073				—
PCA mechanism				(a)			4,623				—
Electron unrecovered loss			4 years				14,008				—
Decoupling under-collection			Less than 2 years				55,363				—
Various other regulatory assets			Varies				14,312				8,078
Total PSE regulatory assets						$	987,402			$	895,732
Cost of removal				(b)		$	(313,088	)		$	(269,536	)
Production tax credits				(c)			(93,616	)			(93,618	)
PGA payable			1 year				—				(5,938	)
PCA mechanism				(a)			—				(5,345	)
Decoupling over-collection			Less than 2 years				(12,582	)			(20,535	)
Summit purchase option buy-out			5.8 years				(9,188	)			(10,763	)
Deferred gain on Jefferson County sale			Less than 1 year				(4,731	)			(60,844	)
Deferred credit on Biogas sale			1 year				(1,445	)			(10,908	)
Deferred credit on gas pipeline capacity			Varies up to 3.8 years				(3,564	)			(4,508	)
Renewable energy credits			1 year				(2,383	)			(5,820	)
Treasury grants			5 to 44 years				(180,496	)			(203,889	)
Deferral of treasury grant amortization			Less than 4 years				(8,197	)			—
Various other regulatory liabilities			Up to 4 years				(6,092	)			(5,755	)
Total PSE regulatory liabilities						$	(635,382	)		$	(697,459	)
PSE net regulatory assets (liabilities)						$	352,020			$	198,273

 

(a)	Amortization periods vary depending on timing of underlying transactions or awaiting regulatory approval in a future Washington Commission rate proceeding.

(b)	The balance is dependent upon the cost of removal of underlying assets and the life of utility plant.

(c)	Amortization will begin once PTCs are utilized by PSE on its tax return.

 

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Puget Energy		Remaining Amortization Period				December 31,
(Dollars in Thousands)						2014				2013
Total PSE regulatory assets				(a)		$	987,402			$	895,732
Puget Energy acquisition adjustments:
Regulatory assets related to power contracts			1 to 22 years				29,816				33,753
Various other regulatory assets			Varies				561				517
Total Puget Energy regulatory assets						$	1,017,779			$	930,002
Total PSE regulatory liabilities				(a)		$	(635,382	)		$	(697,459	)
Puget Energy acquisition adjustments:
Regulatory liabilities related to power contracts			1 to 37 years				(391,389	)			(443,065	)
Various other regulatory liabilities			Varies				(2,820	)			(2,884	)
Total Puget Energy regulatory liabilities						$	(1,029,591	)		$	(1,143,408	)
Puget Energy net regulatory asset (liabilities)						$	(11,812	)		$	(213,406	)

 

(a)	Puget Energy’s regulatory assets and liabilities include purchase accounting adjustments under ASC 805 as a result of the merger.

If the Company determines that it no longer meets the criteria for continued application of ASC 980, the Company would be required to write off its regulatory assets and liabilities related to those operations not meeting ASC 980 requirements. Discontinuation of ASC 980 could have a material impact on the Company’s financial statements.

In accordance with guidance provided by ASC 410, “Asset Retirement and Environmental Obligations,” PSE reclassified from accumulated depreciation to a regulatory liability $313.1 million and $269.5 million in 2014 and 2013, respectively, for the cost of removal of utility plant. These amounts are collected from PSE’s customers through depreciation rates.

Electric Regulation and Rates

Storm Damage Deferral Accounting

The Washington Commission issued a general rate case order that defined deferrable catastrophic/extraordinary losses and provided that costs in excess of $8.0 million annually may be deferred for qualifying storm damage costs that meet the modified IEEE outage criteria for system average interruption duration index. In 2014 and 2013, PSE incurred $29.7 million and $9.4 million, respectively, in storm-related electric transmission and distribution system restoration costs, of which $18.0 million was deferred in 2014 and no amount was deferred in 2013.

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 has used an expedited six-month PCORC decision timeline rather than the statutory 11-month timeline for a general rate case.

On October 23, 2013, the Washington Commission approved an update on the Company’s PCORC, effective November 1, 2013, which reflected decreases in the overall normalized power supply costs. This resulted in an estimated revenue decrease of $10.5 million or 0.5% annually.

 

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On November 3, 2014 the Washington Commission issued an order on the settlement of the PCORC which PSE filed on May 23, 2014. The original filing proposed a decrease of $9.6 million (or an average of approximately 0.5%) in the Company’s overall power supply costs. PSE filed joint testimony supporting a settlement stipulation. Customer rates decreased by approximately $19.4 million or 0.90% annually, as a result of the settlement, effective December 1, 2014.

Electric Rate Case

On April 24, 2014, the Washington Commission approved PSE’s request to change rates under its electric and natural gas decoupling mechanism, effective May 1, 2014. The rate change incorporated the effects of an increase to the allowed delivery revenue per customer as well as true-ups to the rate from the prior year. This represents a rate increase for electric of $10.6 million, or 0.5% annually, and a rate decrease for natural gas of $1.0 million, or 0.1% annually.

On April 24, 2014, the Washington Commission approved PSE’s request to change rates under its electric and natural gas property tax tracker mechanism, effective May 1, 2014. The rate change incorporated the effects of an increase in the amount of property taxes paid as well as true-ups to the rate from the prior year. This represents a rate increase for electric of $11.0 million, or 0.5% annually, and a rate increase for natural gas of $5.6 million, or 0.6% annually.

On April 24, 2014, the Washington Commission also approved PSE’s request to change rates under its electric and natural gas conservation riders, effective May 1, 2014. The rate change incorporated the effects of changes in the annual conservation budgets as well as true-ups to the rate from the prior year. The rate change represents a rate increase for electric of $12.2 million, or 0.5% annually, and a rate increase for natural gas of $0.3 million.

On November 3, 2014 the Washington Commission approved PSE’s 2014 PCORC. The original filing proposed a decrease of $9.6 million (or an average of approximately 0.5%) in the Company’s overall power supply costs with an effective date of December 1, 2014. PSE filed joint testimony supporting a settlement stipulation. Customer rates decreased by approximately $19.4 million or 0.90% as a result of the settlement, effective December 1, 2014.

On June 25, 2013, the Washington Commission approved PSE’s electric and natural gas decoupling mechanism and expedited rate filing (ERF) tariff filings, effective July 1, 2013. The estimated revenue impact of the decoupling mechanism for electric is an increase of $21.4 million, or 1.0% annually. The estimated revenue impact of the ERF filings for electric is an increase of $30.7 million, or 1.5% annually. In its order, the Washington Commission approved a weighted cost of capital of 7.8% and a capital structure that included 48.0% common equity with a return on equity of 9.8%. Subsequently, certain parties to this proceeding petitioned the Washington Commission to reconsider the order. On December 13, 2013, the Washington Commission approved the settlement agreements for rates effective January 1, 2014. These settlement agreements do not materially change the revenues originally approved in June 2013.

On July 24, 2013, the Public Counsel Division of the Washington State Attorney General’s Office (Public Counsel) and the Industrial Customers of Northwest Utilities (ICNU) each filed a petition in Thurston County Superior Court (the Court) seeking judicial reviews of various aspects of the Washington Commission’s ERF and decoupling mechanism final order. The parties’ petition argues that the order violates various procedural and substantive requirements of the Washington Administrative Procedure Act, and so requests that it be vacated and that the matter be remanded to the Washington Commission. Oral arguments regarding this matter were held on May 9, 2014. On June 25, 2014, the court issued a letter decision in which it affirmed the attrition adjustment (escalating factors referred to as the K-Factor) and the Washington Commission’s decision not to consider the case as a general rate case, but reversed and remanded the cost of equity for further adjudication consistent with

 

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the court’s decision. As a result, there will be evidentiary proceedings regarding Return on Equity (ROE) in February 2015 with an order anticipated in the first half of 2015.

On May 7, 2012, the Washington Commission issued its order in PSE’s electric general rate case filed in June 2011, approving a general rate increase for electric customers of $63.3 million or 3.2% annually. The rate increases for electric customers became effective May 14, 2012. In its order, the Washington Commission approved a weighted cost of capital of 7.8% and a capital structure that included 48.0% common equity with a return on equity of 9.8%. PSE’s requested treatment of the prepayments made to Bonneville Power Administration (BPA), filed in May 2010, was approved in the order. The final order rejected PSE’s proposed conservation savings adjustment. Finally, a new rate rider for RECs was proposed by settlement of electric parties and approved by the Washington Commission in the final order.

The following table sets forth electric rate adjustments approved by the Washington Commission and the corresponding impact on PSE’s revenue based on the effective dates:

 

Type of Rate Adjustment		Effective Date		Average Percentage Increase (Decrease) in Rates				Increase (Decrease) in Revenue (Dollars in Millions)
PCORC		December 1, 2014			(0.9	)%		$	(19.4	)
Conservation Rider		May 1, 2014			0.5	%			12.2
Decoupling Rate Filing		May 1, 2014			0.5				10.6
Property Tax Tracker		May 1, 2014			0.5				11.0
PCORC		November 1, 2013			0.5				10.5
Decoupling Rate Filing		July 1, 2013			1.0				21.4
Expedited Rate Filing		July 1, 2013			1.5				30.7
Electric General Rate Case		May 14, 2012			3.2				63.3

In addition, PSE will be increasing the allowed delivery revenue per customer under the decoupling filing by 3.0% for electric customers on January 1 of each year until the conclusion of PSE’s next general rate case.

Accounting Orders and Petitions

On November 27, 2013, the Washington Commission issued an order authorizing PSE to provide the net proceeds from the sale of natural gas supply produced from a landfill-gas recovery project in King County (Biogas) prior to October 31, 2013 as a bill credit to customers over a one-year period in its RECs adjusting price schedule which became effective January 1, 2014. Additionally, the Washington Commission order authorized that all net proceeds from Biogas produced after October 31, 2013 plus the internal labor needed to obtain the net proceeds is reflected as a PSE below-the-line item (i.e., not included in the revenues and expenses considered when setting electric customer rates) and excluded from utility operations.

PSE completed the sale of its electric infrastructure assets located in Jefferson County and the transition of electrical services in the county to JPUD on March 31, 2013. The proceeds from the sale exceeded the transferred assets’ net carrying value of $46.7 million resulting in a pre-tax gain of approximately $60.0 million. In its 2010 order on the subject, the Washington Commission stated that PSE must file an accounting and ratemaking petition with the Washington Commission to determine how this gain will be allocated between customers and shareholders. As a result, the gain was deferred and recorded as a regulatory liability pending the Washington Commission’s determination of the accounting and ratemaking treatment. On October 31, 2013, PSE filed an accounting petition for a Washington Commission order that would authorize PSE to retain the gain of $45.0 million and return $15.0 million to its remaining customers over a period of 48 months. On March 28, 2014, intervenors filed response testimonies containing their respective proposals for allocation of the gain, which included a proposal of up to $57.0 million to customers and $3.0 million to PSE. A final order was rendered on September 11, 2014 authorizing PSE to retain $7.5 million of the gain and return $52.7 million to customers. The

 

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customer portion is booked to a regulatory liability account in other current liabilities and accruing interest at PSE’s after-tax rate of return. PSE and the parties to the case filed a joint motion to amend the final order to allow for the customer portion to be paid to customers through a bill credit in the month of December 2014. The Commission granted the joint motion on October 1, 2014.

PCA Mechanism

In 2002, the Washington Commission approved a PCA mechanism that provides for a rate adjustment process if PSE’s costs to provide customers’ electricity vary from a baseline power cost rate established in a rate proceeding. 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.

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	%

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 (Treasury Grants) to taxpayers who place specified energy property in service provided certain conditions are met. Section 1603 precludes a recipient from claiming PTCs on property for which a grant is claimed.

PSE received two treasury grants with a total amount of $107.9 million, related to Baker and Snoqualmie hydro facilities. These grants have been accounted as a reduction to utility plant and will be amortized over the life of the plant based on the Washington Commission authorization.

The Wild Horse Wind Project (Wild Horse) expansion facility was placed into service on November 9, 2009. The capacity of the Wild Horse facility was expanded from 229 megawatts (MW) to 273 MW through the addition of wind turbines. In February 2010, the U.S. Treasury approved a Treasury Grant of $28.7 million. The 343 MW Lower Snake River facility was placed into service on February 29, 2012. In December 2012, the U.S. Treasury approved a Treasury Grant of $205.3 million.

On February 29, 2012, PSE filed proposed tariff revisions, with stated effective dates of April 1, 2012, and subsequently revised by filing on March 29, 2012 with stated effective dates of June 1, 2012, to pass-through $2.4 million in interest on the unamortized balance of the Wild Horse Expansion Treasury Grant. On June 26, 2012, the Washington Commission approved PSE’s methods and calculations and new rates became effective on July 3, 2012.

On January 31, 2013, the Washington Commission approved a rate change to the PSE’s Federal Incentive Tracker tariff, effective February 1, 2013, which incorporated the effects of the Treasury Grant related to the Lower Snake River wind generation project and keeping the ten year amortization period and inclusion of interest on the unamortized balance of the grants. The rate change passed through 11 months of amortization for

 

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both grants to eligible customers over 11 months beginning February 1, 2013. Of the total credit, $34.6 million represents the pass-back of grant amortization and $23.8 million represents the pass through of interest. This represents an overall average rate decrease of 2.8%.

On December 27, 2013, the Washington Commission approved the annual true-up and rate filing to the PSE’s Federal Incentive Tracker tariff, effective January 1, 2014. The true-up filing resulted in a total credit of $58.5 million to be passed back to eligible customers over the twelve months beginning January 1, 2014. Of the total credit, $37.8 million represents the pass-back of grant amortization and $20.6 million represents the pass through of interest, in addition to a minor true-up associated with the 2013 rate period. This filing represents an overall average rate increase of 0.3%.

Gas Regulation and Rates

Gas General Rate Cases and Other Filings Affecting Rates

On May 7, 2012, the Washington Commission issued its order in PSE’s natural gas general rate case filed in June 2011, approving a general rate increase for natural gas customers of $13.4 million, or 1.3% annually. The rate increases for natural gas customers became effective May 14, 2012. In its order, the Washington Commission approved a weighted cost of capital of 7.8% and a capital structure that included 48.0% common equity with a return on equity of 9.8%.

On June 1, 2012, PSE filed with the Washington Commission a petition seeking an Accounting Order authorizing PSE to change the existing natural gas conservation tracker mechanism into a rider mechanism to be consistent with the electric conservation program recovery. The accounting petition requested the ability to recover the costs associated with the Company’s current gas conservation programs via transfers from amounts deferred for the over-recovery of commodity costs in the Company’s PGA mechanism. The Commission granted PSE’s accounting petition on June 28, 2012. The approved accounting petition resulted in an increase to gas conservation revenues of $6.9 million and an increase to conservation amortization expense of $6.6 million.

On June 25, 2013, the Washington Commission approved PSE’s electric and natural gas decoupling mechanism and ERF tariff filings, effective July 1, 2013. The estimated revenue impact of the decoupling mechanism for natural gas is an increase of $10.8 million, or 1.1% annually. The estimated revenue impact of the ERF filings for natural gas is a decrease of $2.0 million, or a decrease of 0.2% annually. In its order, the Washington Commission approved a weighted cost of capital of 7.8% and a capital structure that included 48.0% common equity with a return on equity of 9.8%.

Subsequently, certain parties to this proceeding petitioned the Washington Commission to reconsider the order. On December 13, 2013, the Washington Commission approved a series of settlement agreements for rates effective January 1, 2014. These settlement agreements do not materially change the revenues originally approved in June 2013. As a result, certain high volume natural gas industrial customers rate schedules are excluded from the decoupling mechanism and will be subject to certain effects of abnormal weather, conservation impacts and changes in customer usage patterns.

On July 24, 2013, the Public Counsel Division of the Washington State Attorney General’s Office (Public Counsel) and the Industrial Customers of Northwest Utilities (ICNU) each filed a petition in Thurston County Superior Court (the Court) seeking judicial review of various aspects of the Washington Commission’s ERF and decoupling mechanism final order. The parties’ petition argues that the order violates various procedural and substantive requirements of the Washington Administrative Procedure Act, and so requests that it be vacated and that the matter be remanded to the Washington Commission. Oral arguments regarding this matter were held on May 9, 2014. On June 25, 2014, the court issued a letter decision in which it affirmed the attrition adjustment K-Factor and the Washington Commission’s decision not to consider the case as a general rate case, but reversed and remanded the cost of equity for further adjudication consistent with the court’s decision. As a result, there will be evidentiary proceedings regarding ROE in February 2015 with an order anticipated in the first half of 2015.

 

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Purchased Gas Adjustment

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. Changes in the PGA rates affect PSE’s revenue, but do not impact net operating income as the changes to revenue are offset by increased or decreased purchased gas and gas transportation costs.

On October 30, 2014, the Washington Commission approved the PGA natural gas tariff which proposed to reflect changes in wholesale gas and pipeline transportation costs and changes in deferral amortization rates. The impact of PGA rates is an annual revenue decrease of $23.3 million , or 2.5% annually, with no impact on net operating income.

On October 30, 2013, the Washington Commission approved PSE’s PGA natural gas tariff, effective on November 1, 2013, which reflected changes in wholesale gas and pipeline transportation costs and changes in deferral amortization rates. The estimated revenue impact of the approved change is an increase of $4.0 million, or 0.4% annually, with no impact on net operating income.

On October 31, 2012, the Washington Commission approved PSE’s PGA natural gas tariff filing and allowed the rates to go into effect on November 1, 2012 on a temporary basis subject to revision. The rates resulted in a decrease to the rates charged to customers under the PGA. On May 1, 2013, the Washington Commission approved the proposed rates and allowed them to be made permanent. The estimated revenue impact of the approved change is a decrease of $77.0 million, or 7.7% annually, with no impact on net operating income.

The following table sets forth natural gas rate adjustments that were approved by the Washington Commission and the corresponding impact to PSE’s annual revenue based on the effective dates:

 

Type of Rate Adjustment		Effective Date		Average Percentage Increase (Decrease) in Rates				Annual Increase (Decrease) in Revenue (Dollars in Millions)
Purchased Gas Adjustment		November 1, 2014			(2.5	)%		$	(23.3	)
Decoupling Rate Filing		May 1, 2014			(0.1	)			(1.0	)
Purchased Gas Adjustment		November 1, 2013			0.4				4.0
Decoupling Rate Filing		July 1, 2013			1.1				10.8
Expedited Rate Filing		July 1, 2013			(0.2	)			(2.0	)
Purchased Gas Adjustment		November 1, 2012			(7.7	)			(77.0	)
Natural Gas General Rate Case		May 14, 2012			1.3				13.4
Purchased Gas Adjustment		November 1, 2011			(4.3	)			(43.5	)
Natural Gas General Tariff Adjustment		April 1, 2011			1.8				19.0

In addition, PSE will be increasing the allowed delivery revenue per customer under the decoupling filing by 2.2% for natural gas customers on January 1 of each year until the conclusion of PSE’s next general rate case.

Environmental Remediation

The Company is subject to environmental laws and regulations by the federal, state and local authorities and is required to undertake certain environmental investigative and remedial efforts as a result of these laws and regulations. The Company has 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

 

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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. Per the guidance of ASC 450, “Contingencies,” the Company reviews its estimated future obligations and will record adjustments, if any, on a quarterly basis. Management believes it is probable and reasonably estimable that the impact of the potential outcomes of disputes with certain property owners and other potentially responsible parties will result in environmental remediation costs of $35.4 million for gas and $5.7 million for electric. The Company believes a significant portion of its past and future environmental remediation costs are recoverable from insurance companies, from third parties or from customers under a Washington Commission order. The Company is also subject to cost-sharing agreements with third parties regarding environmental remediation projects in Seattle, Washington and Bellingham, Washington. The Company has taken the lead for both projects. As of December 31, 2014, the Company’s share of future remediation costs is estimated to be approximately $25.2 million. The Company’s deferred electric environmental costs are $13.4 million, $12.3 million, and $10.9 million at December 31, 2014, 2013 and 2012, respectively, net of insurance proceeds. The Company’s deferred natural gas environmental costs are $52.6 million, $45.1 million, and $66.4 million at December 31, 2014, 2013 and 2012, respectively, net of insurance proceeds.

(4) 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, 2014, approximately $438.4 million of unrestricted retained earnings was available for the payment of dividends under the most restrictive mortgage indenture covenant.

Beginning February 6, 2009, pursuant to the terms of the Washington Commission merger order, PSE may not declare or pay dividends 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. Also, 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, or, if its credit ratings are below investment grade, PSE’s ratio of Adjusted Earnings Before Interest, Tax, Depreciation and Amortization (EBITDA) to interest expense for the most recently ended four fiscal quarter periods prior to such date is equal to or greater than 3 to one. The common equity ratio, calculated on a regulatory basis, was 47.7% at December 31, 2014, and the EBITDA to interest expense was 4.3 to one for the twelve months then ended.

PSE’s ability to pay dividends is also limited by the terms of its credit facilities, pursuant to which PSE is not permitted to pay dividends during any Event of Default (as defined in the facilities), or if the payment of dividends would result in an Event of Default, such as failure to comply with certain financial covenants.

Puget Energy’s ability to pay dividends is also limited by the merger order issued by the Washington Commission. 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 2 to one. Puget Energy’s EBITDA to interest expense was 3.1 to one for the twelve months ended December 31, 2014.

At December 31, 2014, the Company was in compliance with all applicable covenants, including those pertaining to the payment of dividends.

 

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(5) Utility Plant

 

		Estimated Useful Life (Years)		Puget Energy								Puget Sound Energy
Utility Plant				At December 31,								At December 31,
(Dollars In Thousands)				2014				2013				2014				2013
Electric, gas and common utility plant classified by prescribed accounts:
Distribution plant		10-50		$	4,748,988			$	4,448,451			$	6,417,551			$	6,127,732
Production plant		25-125			2,973,853				2,966,223				3,907,224				3,948,270
Transmission plant		45-65			1,189,296				1,043,605				1,306,009				1,162,929
General plant		5-35			481,116				504,965				553,130				599,156
Intangible plant (including capitalized software)		3-50			311,959				316,614				304,135				309,972
Plant acquisition adjustment		7-30			242,826				242,826				282,792				282,792
Underground storage		25-60			28,859				27,857				42,494				41,501
Liquefied natural gas storage		25-45			12,628				12,622				14,498				14,492
Plant held for future use		NA			54,996				28,742				55,148				28,895
Recoverable Cushion Gas		NA			8,655				8,655				8,655				8,655
Plant not classified		1-100			91,519				124,589				91,519				124,589
Grant		NA			(105,659	)			—				(105,659	)			—
Capital leases, net of accumulated amortization1		5			9,473				17,051				9,473				17,051
Less: accumulated provision for depreciation					(1,611,220	)			(1,373,178	)			(4,449,680	)			(4,297,012	)
Subtotal				$	8,437,289			$	8,369,022			$	8,437,289			$	8,369,022
Construction work in progress		NA			239,690				310,318				239,690				310,318
Net utility plant				$	8,676,979			$	8,679,340			$	8,676,979			$	8,679,340

 

 

1	Accumulated amortization of capital leases at Puget Energy was $28.4 million in 2014 and $20.8 million in 2013. Accumulated amortization of capital leases at PSE was $28.4 million in 2014 and $20.8 million in 2013.

Jointly owned generating plant service costs are included in utility plant service cost at the Company’s ownership share. 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, 2014. These amounts are also included in the Utility Plant table above.

 

Jointly Owned Generating Plants (Dollars in Thousands)		Energy Source (Fuel)		Company’s Ownership Share				Puget Energy’s Share								Puget Sound Energy’s Share
								Plant in Service at Cost				Accumulated Depreciation				Plant in Service at Cost				Accumulated Depreciation
Colstrip Units 1 & 2		Coal			50	%		$	158,516			$	(12,047	)		$	293,103			$	(146,635	)
Colstrip Units 3 & 4		Coal			25	%			234,787				(28,763	)			509,619				(303,594	)
Colstrip Units 1 – 4 Common Facilities1		Coal			various				83				(21	)			252				(189	)
Frederickson1		Gas			49.85	%			61,771				(5,750	)			70,719				(14,698	)
Jackson Prairie		Gas Storage			33.34	%			28,185				(4,099	)			42,494				(18,409	)

 

1	The Company’s ownership is 50% for Colstrip 1&2 and 25% for Colstrip Units 3 &4.

As of December 31, 2014, there are no new Asset Retirement Obligations (ARO) in 2014 and $0.4 million in 2013.

 

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The following table describes all changes to the Company’s ARO liability:

 

		At December 31,
(Dollars in Thousands)		2014				2013
Asset retirement obligation at beginning of period		$	48,687			$	45,496
New asset retirement obligation recognized in the period			—				350
Liability settled in the period			(602	)			(1,188	)
Revisions in estimated cash flows			(480	)			2,769
Accretion expense			1,304				1,260
Asset retirement obligation at end of period		$	48,909			$	48,687

The Company has identified the following obligations, as defined by ASC 410, “Asset Retirement and Environmental Obligations,” which were not recognized because the liability for these assets cannot be reasonably estimated at December 31, 2014 due to:

 

•

A legal obligation under Federal Dangerous Waste Regulations to dispose of asbestos-containing material in facilities that are not scheduled for remodeling, demolition or sales. The disposal cost related to these facilities could not be measured since the retirement date is indeterminable; therefore, the liability cannot be reasonably estimated;

 

•

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;

 

•

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.

 

•

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;

 

•

An obligation to pay decommissioning costs at the end of utility service franchise agreements to restore the surface of the franchise area. The decommissioning costs related to facilities at the franchise area could not be measured since the decommissioning date is indeterminable; therefore, the liability cannot be reasonably estimated; and

 

•

A potential legal obligation may arise upon the expiration of an existing FERC hydropower license if FERC orders the project to be decommissioned, although PSE contends that FERC does not have such authority. Given the value of ongoing generation, flood control and other benefits provided by these projects, PSE believes that the potential for decommissioning is remote and cannot be reasonably estimated.

 

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(6) Long-Term Debt

 

(Dollars in Thousands)								At December 31,
Series		Type		Due				2014				2013
Puget Sound Energy:
7.350%		First Mortgage Bond			2015			$	10,000			$	10,000
7.360%		First Mortgage Bond			2015				2,000				2,000
5.197%		Senior Secured Note			2015				150,000				150,000
6.750%		Senior Secured Note			2016				250,000				250,000
5.500%		Promissory Note1			2017				2,412				2,412
6.740%		Senior Secured Note			2018				200,000				200,000
7.150%		First Mortgage Bond			2025				15,000				15,000
7.200%		First Mortgage Bond			2025				2,000				2,000
7.020%		Senior Secured Note			2027				300,000				300,000
7.000%		Senior Secured Note			2029				100,000				100,000
3.900%		Pollution Control Bond			2031				138,460				138,460
4.000%		Pollution Control Bond			2031				23,400				23,400
5.483%		Senior Secured Note			2035				250,000				250,000
6.724%		Senior Secured Note			2036				250,000				250,000
6.274%		Senior Secured Note			2037				300,000				300,000
5.757%		Senior Secured Note			2039				350,000				350,000
5.795%		Senior Secured Note			2040				325,000				325,000
5.764%		Senior Secured Note			2040				250,000				250,000
4.434%		Senior Secured Note			2041				250,000				250,000
5.638%		Senior Secured Note			2041				300,000				300,000
4.700%		Senior Secured Note			2051				45,000				45,000
6.974%		Junior Subordinated Note			2067				250,000				250,000
		Unamortized discount on senior notes							(13	)			(14	)
PSE long-term debt								$	3,763,259			$	3,763,258
Puget Energy:
		Fair value adjustment of PSE long-term debt						$	(218,619	)		$	(229,746	)
		Credit Facility			2017				—				299,000
		Term-Loan			2016				100,000				—
		Term-Loan			2017				100,000				—
		Term-Loan			2016				99,000				—
6.500%		Senior Secured Note			2020				450,000				450,000
6.000%		Senior Secured Note			2021				500,000				500,000
5.625%		Senior Secured Note			2022				450,000				450,000
		Unamortized discount on senior notes							(32	)			(36	)
Total Puget Energy long-term debt								$	5,243,608			$	5,232,476

 

1	Puget Western, Inc., a wholly owned subsidiary of PSE, Promissory Note.

PSE’s senior secured notes will cease to be secured by the pledged first mortgage bonds on the date that all of the first mortgage bonds issued and outstanding under the electric or natural gas utility mortgage indenture have been retired. As of December 31, 2014, the latest maturity date of the first mortgage bonds, other than pledged first mortgage bonds, is December 22, 2025.

 

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Puget Sound Energy Long-Term Debt

PSE has in effect a shelf registration statement under which it may issue, from time to time, up to $800 million aggregate principal amount of senior notes secured by pledged first mortgage bonds. The Company remains subject to the restrictions of PSE’s indentures and credit agreements on the amount of first mortgage bonds that PSE may issue.

Substantially all utility properties owned by PSE 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 exceed certain minimums as defined in the indentures. At December 31, 2014, the earnings available for interest exceeded the required amount.

Puget Sound Energy Pollution Control Bonds

PSE has two series of Pollution Control Bonds (the Bonds) outstanding. Amounts outstanding were borrowed from the City of Forsyth, Montana who obtained the funds from the sale of Customized Pollution Control Refunding Bonds issued to finance pollution control facilities at Colstrip Units 3 & 4.

In May 2013, PSE refinanced $161.9 million of the Bonds to a lower weighted average interest rate from 5.01% to 3.91%. The Bonds will mature on March 1, 2031. On or after March 1, 2023, the Company may elect to call the bonds at a redemption price of 100% of the principal amount thereof, without premium, plus accrued interest, if any, to the redemption date. Due to the refinance of the Bonds, Puget Energy wrote off $18.0 million of fair value related to the Bonds that were redeemed to interest expense.

Each series of the Bonds is collateralized by a pledge of PSE’s first mortgage bonds, the terms of which match those of the Bonds. No payment is due with respect to the related series of first mortgage bonds so long as payment is made on the Bonds.

Puget Energy Long-Term Debt

At the time of the merger in 2009, Puget Energy entered into a $1.225 billion five-year term-loan and a $1.0 billion five-year capital expenditure credit facility for funding capital expenditures. In February 2012, Puget Energy entered into a $1.0 billion five-year revolving senior secured credit facility and the 2009 term loan and capital expenditure facilities were terminated. Concurrent with the closing of the new PSE credit facilities in February 2013, the Company reduced the size of Puget Energy’s credit facility to $800.0 million. The Puget Energy revolving senior secured credit facility also has an accordion feature that, upon the banks’ approval, would increase the size of the facility to $1.3 billion. In April 2014, the Company completed an amendment to the senior secured credit facility, extending the maturity from February 2017 to April 2018, updating the fee structure, eliminating a financial covenant and updating or clarifying the definitions of other terms and conditions of the facility. All other terms and conditions of that facility remain unchanged from when it was committed in 2012. As a revolving facility, amounts borrowed may be repaid without a reduction in the size of the facility.

The Puget Energy revolving senior secured credit facility contains usual and customary affirmative and negative covenants. The agreement also contains a financial covenant based on the Maximum Leverage Ratio, as defined in the agreement governing the senior secured credit facility.

In June 2014, Puget Energy entered into three bilateral term loans, with two and three year maturities, which in total, equal $299 million. The proceeds of the term loans were used to pay off the outstanding Puget Energy revolving credit facility balance, which subsequently allows the Company to carry the debt with lower interest expense. All other terms, conditions and covenants are consistent with each other and the credit facility agreement, with the exception of maturity and price.

 

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Long-Term Debt Maturities

The principal amounts of long-term debt maturities for the next five years and thereafter are as follows:

 

(Dollars in Thousands)		2015				2016				2017				2018				2019				Thereafter				Total
Maturities of:
PSE long-term debt		$	162,000			$	250,000			$	2,412			$	200,000			$	—			$	3,148,860			$	3,763,272
Puget Energy long-term debt			—				199,000				100,000				—				—				1,400,000				1,699,000
Puget Energy long-term debt		$	162,000			$	449,000			$	102,412			$	200,000			$	—			$	4,548,860			$	5,462,272

Financial Covenants

Puget Energy’s credit facility contains a financial covenant related to maximum leverage. As of December 31, 2014, the Company is in compliance with its long-term debt financial covenants.

(7) Liquidity Facilities and Other Financing Arrangements

As of December 31, 2014 and 2013, PSE had $85.0 million and $162.0 million in short-term debt outstanding, respectively, exclusive of the demand promissory note with Puget Energy. Outside of the consolidation of PSE’s short-term debt, Puget Energy had no short-term debt outstanding in either year as borrowings under its credit facilities are classified as long-term. PSE’s weighted-average interest rate on short-term debt, including borrowing rate, commitment fees and the amortization of debt issuance costs, during 2014 and 2013 was 4.05% and 3.93%, respectively. As of December 31, 2014, PSE and Puget Energy had several committed credit facilities that are described below.

Puget Sound Energy Credit Facilities

PSE has two unsecured revolving credit facilities which provide, in aggregate, $1.0 billion of short-term liquidity needs. These facilities consist of a $650.0 million revolving liquidity facility (which includes a liquidity letter of credit facility and a swingline facility) to be used for general corporate purposes, including a backstop to the Company’s commercial paper program and a $350.0 million revolving energy hedging facility (which includes an energy hedging letter of credit facility). The $650.0 million liquidity facility includes a swingline feature allowing same day availability on borrowings up to $75.0 million. The credit facilities also have an accordion feature which, upon the banks’ approval, would increase the total size of these facilities to $1.450 billion.

In April 2014, the Company completed a one-year extension on both of the liquidity and hedging facilities, extending the maturity from February 2018 to April 2019, and updating or clarifying the definitions of other terms and conditions of the facilities from when they were committed in 2013. The credit agreements are syndicated among numerous lenders and contain usual and customary affirmative and negative covenants that, among other things, place limitations on PSE’s ability to transact with affiliates, make asset dispositions and investments or permit liens to exist. The credit agreements also contain a financial covenant of total debt to total capitalization of 65% or less. PSE certifies its compliance with such covenants to participating banks each quarter. As of December 31, 2014, PSE was in compliance with all applicable covenant ratios.

The credit agreements provide PSE with the ability to borrow at different interest rate options. The credit agreements allow PSE to borrow at the bank’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. PSE must pay a commitment fee on the unused portion of the credit facilities. The spreads and the commitment fee depend on PSE’s credit ratings. As of the date of this report, the spread to the LIBOR is 1.25% and the commitment fee is 0.175%.

 

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As of December 31, 2014, no amounts were drawn and outstanding under PSE’s liquidity facility. No amounts were drawn and outstanding under the $350.0 million energy hedging facility. No letters of credit were outstanding under either facility, and $85.0 million was outstanding under the commercial paper program. Outside of the credit agreements, PSE had a $4.2 million letter of credit in support of a long-term transmission contract and a $1.0 million letter of credit in support of natural gas purchases in Canada.

Demand Promissory Note

In 2006, PSE entered into a revolving credit facility with Puget Energy, in the form of a credit agreement and a Demand Promissory Note (Note) pursuant to which 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 lower of the weighted-average interest rates of PSE’s outstanding commercial paper interest rate or PSE’s senior unsecured revolving credit facility. Absent such borrowings, interest is charged at one-month LIBOR plus 0.25%. At December 31, 2014, the outstanding balance of the Note was $28.9 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 Facility

At December 31, 2014, Puget Energy maintained an $800.0 million revolving senior secured credit facility. In April, 2014, the Company completed an amendment to the senior secured credit facility, extending the maturity from February 2017 to April 2018, updating the fee structure, eliminating a financial covenant and updating or clarifying the definitions of other terms and conditions of the facility. The Puget Energy revolving senior secured credit facility also has an accordion feature which, upon the banks’ approval, would increase the size of the facility to $1.3 billion.

The revolving senior secured credit facility provides Puget Energy the ability to borrow at different interest rate options and includes variable fee levels. Interest rates may be based on the bank’s prime rate or LIBOR plus a spread based on Puget Energy’s credit ratings. Puget Energy must pay a commitment fee on the unused portion of the facility. As of December 31, 2014, there was no amount drawn and outstanding under the facility. As a result of Puget Energy’s credit rating upgrade in 2014, the spread over LIBOR was 1.75% and the commitment fee was 0.28% as of the date of this report. Puget Energy entered into interest rate swap contracts to manage the interest rate risk associated with the credit facility or similar variable rate debt.

The revolving senior secured credit facility contains usual and customary affirmative and negative covenants. The agreement also contains a Maximum Leverage Ratio financial covenant as defined in the agreement governing the senior secured credit facility. As of December 31, 2014, Puget Energy was in compliance with all applicable covenants.

(8) Leases

PSE leases buildings and assets under operating leases. Certain leases contain purchase options, renewal options and escalation provisions. Operating lease expenses net of sublease receipts were:

 

(Dollars in Thousands)
At December 31,
2014		$	30,737
2013			29,392
2012			29,661

 

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Payments received for the subleases of properties were immaterial for each of the years ended 2014, 2013 and 2012. Future minimum lease payments for non-cancelable leases net of sublease receipts are:

 

(Dollars in Thousands)
At December 31,		Operating				Capital
2015		$	17,677			$	8,160
2016			21,454				2,178
2017			22,179				—
2018			20,423				—
2019			15,180				—
Thereafter			120,791				—
Total minimum lease payments		$	217,704			$	10,338

(9) Accounting for Derivative Instruments and Hedging Activities

PSE employs various energy portfolio optimization strategies, but is not in the business of assuming risk for the purpose of realizing speculative trading revenue. The nature of serving regulated electric customers with its 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 and PSE’s related hedging strategies are focused on reducing costs and risks where feasible, thus reducing volatility in costs in the portfolio. In order to manage its exposure to the variability in future cash flows for forecasted energy transactions, PSE utilizes a programmatic hedging strategy which extends out three years. 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 forward physical electric and natural gas purchase and sale agreements, fixed-for-floating swap contracts, and commodity call/put options. The forward physical electric agreements are both fixed and variable (at index), while the physical natural gas contracts are variable. To fix the price of wholesale electricity and natural gas, PSE may enter into fixed-for-floating swap (financial) contracts with various counterparties. PSE also utilizes natural gas call and put options as an additional hedging instrument to increase the hedging portfolio’s flexibility to react to commodity price fluctuations.

The Company manages its interest rate risk through the issuance of mostly fixed-rate debt with varied maturities. The Company utilizes internal cash from operations, borrowings under its commercial paper program, and its credit facilities to meet short-term funding needs. The Company may enter into swap instruments or other financial hedge instruments to manage the interest rate risk associated with these debts. As of December 31, 2014, Puget Energy had two interest rate swap contracts outstanding which extend to January 2017. PSE did not have any outstanding interest rate swap instruments.

The following table presents the volumes, fair values and locations of the Company’s derivative instruments recorded on the balance sheets:

 

Puget Energy and Puget Sound Energy		Year Ended December 31,
(Dollars in Thousands)		Volumes (millions)								Assets1								Liabilities2
		2014				2013				2014				2013				2014				2013
Interest rate swap derivatives3		$	450.0			$	450.0			$	—			$	—			$	9,073			$	13,223
Electric portfolio derivatives			*				*				4,822				18,479				107,228				37,312
Natural gas derivatives (MMBtus)4			360.4				423.5				19,526				8,121				88,807				35,676
Total derivative contracts										$	24,348			$	26,600			$	205,108			$	86,211
Current										$	21,178			$	18,867			$	142,195			$	48,049
Long-term											3,170				7,733				62,913				38,162
Total derivative contracts										$	24,348			$	26,600			$	205,108			$	86,211

 

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1	Balance sheet location: Current and Long-term Unrealized gain on derivative instruments.

2	Balance sheet location: Current and Long-term Unrealized loss on derivative instruments.

3	Interest rate swap contracts are only held at Puget Energy.

4

PSE had a net derivative liability and an offsetting regulatory asset of $69.3 million at December 31, 2014 and $27.6 million at December 31, 2013 related to 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 deferred in accordance with ASC 980, due to the PGA mechanism.

*	Electric portfolio derivatives consist of electric generation fuel of 140.2 million One Million British Thermal Units (MMBtus) and purchased electricity of 5.4 million Megawatt Hours (MWhs) at December 31, 2014 and 145.6 million MMBtus and 8.6 million MWhs at December 31, 2013.

For further details regarding the fair value of derivative instruments, see Note 10.

It is the Company’s policy to record all derivative transactions on a gross basis at the contract level, without offsetting assets or liabilities. The Company generally enters into transactions using the following master agreements: WSPP, Inc. (WSPP) agreements which standardize physical power contracts; ISDA agreements which standardize financial gas and electric contracts; and NAESB agreements which standardize physical gas contracts. The Company believes that such agreements reduce credit risk exposure because such agreements provide for the netting and offsetting of monthly payments as well as right of set-off in the event of counterparty default. The set-off provision can be used as a final settlement of accounts which extinguishes the mutual debts owed between the parties in exchange for a new net amount.

The following tables present the potential effect of netting arrangements, including rights of set-off associated with the Company’s derivative assets and liabilities:

 

Puget Energy and Puget Sound Energy
At December 31, 2014
(Dollars in Thousands)		Gross Amounts Recognized in the Statement of Financial Position1				Gross Amounts Offset in the Statement of Financial Position				Net of Amounts Presented in the Statement of Financial Position				Gross Amounts Not Offset in the Statement of Financial Position								Net Amount
														Commodity Contracts				Cash Collateral Received/Posted
Assets
Energy Derivative Contracts		$	24,348			$	—			$	24,348			$	(23,066	)		$	—			$	1,282
Liabilities
Energy Derivative Contracts		$	196,035			$	—			$	196,035			$	(23,066	)		$	(20	)		$	172,949
Interest Rate Swaps2		$	9,073			$	—			$	9,073			$	—			$	—			$	9,073

 

Puget Energy and Puget Sound Energy
At December 31, 2013
(Dollars in Thousands)		Gross Amounts Recognized in the Statement of Financial Position1				Gross Amounts Offset in the Statement of Financial Position				Net of Amounts Presented in the Statement of Financial Position				Gross Amounts Not Offset in the Statement of Financial Position								Net Amount
														Commodity Contracts				Cash Collateral Received/Posted
Assets
Energy Derivative Contracts		$	26,600			$	—			$	26,600			$	(19,491	)		$	—			$	7,109
Liabilities
Energy Derivative Contracts		$	72,988			$	—			$	72,988			$	(19,491	)		$	—			$	53,497
Interest Rate Swaps2		$	13,223			$	—			$	13,223			$	—			$	—			$	13,223

 

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1.	All Derivative Contract deals are executed under ISDA, NAESB and WSPP Master Netting Agreements with Right of Offset.

2	Interest Rate Swap Contracts are only held at Puget Energy.

Due to the merger in 2009, Puget Energy recorded all derivative contracts at fair value as either assets or liabilities. Certain contracts meeting the criteria defined in ASC 815 were subsequently designated as NPNS or cash flow hedges, thereby causing differences in the derivative unrealized gains/losses to be recorded through earnings between Puget Energy and PSE. These differences will occur through February 2015.

The following tables present the effect and locations of the Company’s derivatives not designated as hedging instruments, recorded on the statements of income:

 

Puget Energy				Year Ended December 31,
(Dollars in Thousands)		Location		2014				2013				2012
Interest rate contracts:		Other deductions		$	(3,915	)		$	2,420			$	(4,288	)
		Interest expense			500				(5,904	)			(29,727	)
Commodity contracts:
Electric derivatives		Unrealized gain (loss) on derivative instruments, net1			(84,146	)			102,744				131,407
		Electric generation fuel			6,511				(27,008	)			(66,762	)
		Purchased electricity			(4,212	)			(38,299	)			(138,551	)
Total gain (loss) recognized in income on derivatives				$	(85,262	)		$	33,953			$	(107,921	)

 

1	For 2012, the amount differs from the amount stated in the statement of income as it does not include amortization related to contracts that were recorded at fair value at the time of the February 2009 merger and subsequently designated as NPNS of $2.2 million for the year ended December 31, 2012.

 

Puget Sound Energy				Year Ended December 31,
(Dollars in Thousands)		Location		2014				2013				2012
Commodity contracts:
Electric derivatives		Unrealized gain (loss) on derivative instruments, net		$	(85,636	)		$	98,880			$	119,120
		Electric generation fuel			6,511				(27,008	)			(66,762	)
		Purchased electricity			(4,212	)			(38,299	)			(138,551	)
Total gain (loss) recognized in income on derivatives				$	(83,337	)		$	33,573			$	(86,193	)

The unrealized gain or loss on derivative contracts is reported in the statement of cash flows under the operating activities section. However, at the time of the merger in 2009, all derivative contracts at Puget Energy were assessed to identify contracts that have a “more than an insignificant” fair value. If the fair value was greater than 10% of the notional value, the contract was deemed as having a financing element. For those contracts, the cash inflows (outflows) are presented in the financing activities section of the statement of cash flows. For the years ended December 31, 2014, 2013 and 2012, cash outflows related to financing activities of $16.3 million, $34.3 million and $92.7 million, respectively, were reported on Puget Energy’s statement of cash flows.

For derivative instruments previously designated as cash flow hedges (including both commodity and interest rate swap contracts), the effective portion of the gain or loss on the derivative was recorded as a

 

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component of OCI, and then is reclassified into earnings in the same period(s) during which the hedged transaction affects earnings.

Puget Energy and PSE expect $0.5 million and $1.1 million of losses, respectively, in accumulated OCI will be reclassified into earnings within the next twelve months. The Company does not attempt cash flow hedging for any new transactions and records all mark-to-market adjustments through earnings.

The following tables present the Company’s pre-tax gain (loss) on derivatives that were previously in a cash flow hedge relationship, and subsequently reclassified out of accumulated OCI into income:

 

Puget Energy				Year Ended December 31,
(Dollars in Thousands)		Location		2014				2013				2012
Interest rate contracts:		Interest expense		$	(144	)		$	(4,505	)		$	(17,811	)
Commodity contracts:
Electric derivatives		Electric generation fuel			—				—				100
		Purchased electricity			(572	)			(57	)			(671	)
Total				$	(716	)		$	(4,562	)		$	(18,382	)

 

Puget Sound Energy				Year Ended December 31,
(Dollars in Thousands)		Location		2014				2013				2012
Interest rate contracts:		Interest expense		$	(488	)		$	(488	)		$	(488	)
Commodity contracts:
Electric derivatives		Electric generation fuel			—				—				97
		Purchased electricity			(2,063	)			(3,922	)			(12,955	)
Total				$	(2,551	)		$	(4,410	)		$	(13,346	)

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 credit analysis, exposure measurement, exposure monitoring and exposure mitigation.

The Company monitors counterparties that have significant swings in credit default swap rates, have credit rating changes by external rating agencies, have changes in ownership or are experiencing financial distress. 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 exposure 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, 2014, approximately 99.3% 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 0.7% are either rated below investment grade or not rated by rating agencies. The Company assesses credit risk internally for counterparties that are not rated.

As the Company generally enters into transactions using the WSPP, ISDA and NAESB master agreements, it believes that such agreements reduce credit risk exposure because they provide for the netting and offsetting of monthly payments and, in the event of counterparty default, termination payments.

The Company computes credit reserves at a master agreement level by counterparty (i.e., WSPP, ISDA, or NAESB). The Company considers external credit ratings and market factors, such as credit default swaps and

 

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bond spreads, in the 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 Standard & Poor’s 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 determined by weighting the fair value and contract tenors for all deals for each counterparty to derive 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. The Company calculates a non-performance risk on its derivative liabilities by using its estimated incremental borrowing rate over the risk-free rate. Credit reserves are netted against unrealized gain (loss) positions. As of December 31, 2014, the Company 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 quarter. The majority of the Company’s derivative contracts are with financial institutions and other utilities operating within the Western Electricity Coordinating Council. As of December 31, 2014, PSE has posted a $1.0 million letter of credit as a condition of transacting on a physical energy exchange and clearinghouse in Canada. PSE did not trigger any collateral requirements with any of its counterparties nor were any of PSE’s counterparties required to post collateral resulting from credit rating downgrades.

The table below presents the fair value of the overall contractual contingent liability positions for the Company’s derivative activity at December 31, 2014:

 

Puget Energy and Puget Sound Energy
Contingent Feature (Dollars in Thousands)		Fair Value1 Liability				Posted Collateral				Contingent Collateral
Credit rating2		$	(37,398	)		$	—			$	37,398
Requested credit for adequate assurance			(66,468	)			—				—
Forward value of contract3			(2,490	)			—				—
Total		$	(106,356	)		$	—			$	37,398

 

1	Represents the derivative fair value of contracts with contingent features for counterparties in net derivative liability positions. Excludes NPNS, accounts payable and accounts receivable.

2	Failure by PSE to maintain an investment grade credit rating from each of the major credit rating agencies provides counterparties a contractual right to demand collateral.

3	Collateral requirements may vary, based on changes in the forward value of underlying transactions relative to contractually defined collateral thresholds.

(10) Fair Value Measurements

ASC 820 established a fair value hierarchy that prioritizes the inputs used to measure fair value. The hierarchy categorizes the inputs into three levels with the highest priority given to unadjusted quoted prices in active markets for identical assets or liabilities (Level 1 measurement) and the lowest priority given to unobservable inputs (Level 3 measurement). The three levels of the fair value hierarchy are as follows:

Level 1—Quoted prices are available in active markets for identical assets or liabilities as of the reporting date. Level 1 primarily consists of financial instruments such as exchange-traded derivatives and listed equities. Equity securities that are also classified as cash equivalents are considered Level 1 if there are unadjusted quoted prices in active markets for identical assets or liabilities.

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 reporting date. Level 2 includes those financial instruments that

 

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are valued using models or other valuation methodologies. 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 have little or no observability as of the reporting date. These inputs may be used with internally developed methodologies that result in management’s best estimate of fair value.

Financial assets and liabilities measured at fair value are classified in their entirety in the appropriate fair value hierarchy based on the lowest level of input that is significant to the fair value measurement. The Company’s assessment of the significance of a particular input to the fair value measurement requires judgment, and may affect the valuation of fair value assets and liabilities and their placement within the fair value hierarchy. The Company primarily determines fair value measurements classified as Level 2 or Level 3 using a combination of the income and market valuation approaches. The process of determining the fair values is the responsibility of the derivative accounting department which reports to the Controller and Principal Accounting Officer. Inputs used to estimate the fair value of forwards, swaps and options include market-price curves; contract terms and prices; credit-risk adjustments; and discount factors. Additionally, for options, the Black-Scholes option valuation model and implied market volatility curves are used. Inputs used to estimate fair value in industry-standard models are categorized as Level 2 inputs because substantially all assumptions and inputs are observable in active markets throughout the full term of the instruments. On a daily basis, the Company obtains quoted forward prices for the electric and natural gas markets from an independent external pricing service. For interest rate swaps, the Company obtains monthly mark-to-market values from an independent external pricing service for LIBOR forward rates, which is a significant input. Some of the inputs of the interest rate swap valuations, which are less significant, include the credit standing of the counterparties, assumptions for time value and the impact of the Company’s nonperformance risk of its liabilities. The Company classifies cash and cash equivalents, and restricted cash as Level 1 financial instruments due to cash being at stated value, and cash equivalents at quoted market prices.

The Company considers its electric, natural gas and interest rate swap contracts as Level 2 derivative instruments as such contracts are commonly traded as over-the-counter forwards with indirectly observable price quotes. Management’s assessment was based on the trading activity in real-time and forward electric and natural gas markets. Each quarter, the Company confirms the validity of pricing-service quoted prices (e.g., Level 2 in the fair value hierarchy) used to value commodity contracts with the actual prices of commodity contracts entered into during the most recent quarter. However, certain energy derivative instruments with maturity dates falling outside the range of observable price quotes are classified as Level 3 in the fair value hierarchy.

 

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Assets and Liabilities with Estimated Fair Value

The following table presents the carrying value for cash, cash equivalents, restricted cash, notes receivable and short-term debt by level, within the fair value hierarchy. The carrying values below are representative of fair values due to the short-term nature of these financial instruments.

 

Puget Energy		Carrying / Fair Value												Carrying / Fair Value
		At December 31, 2014												At December 31, 2013
(Dollars in Thousands)		Level 1				Level 2				Total				Level 1				Level 2				Total
Assets:
Cash and Cash Equivalents		$	37,527			$	—			$	37,527			$	44,302			$	—			$	44,302
Restricted Cash			32,863				—				32,863				7,171				—				7,171
Notes Receivable and Other			—				53,503				53,503				—				53,449				53,449
Total assets		$	70,390			$	53,503			$	123,893			$	51,473			$	53,449			$	104,922
Liabilities:
Short-term debt		$	85,000			$	—			$	85,000			$	162,000			$	—			$	162,000
Total liabilities		$	85,000			$	—			$	85,000			$	162,000			$	—			$	162,000

 

Puget Sound Energy		Carrying / Fair Value												Carrying / Fair Value
		At December 31, 2014												At December 31, 2013
(Dollars in Thousands)		Level 1				Level 2				Total				Level 1				Level 2				Total
Assets:
Cash and Cash Equivalents		$	37,466			$	—			$	37,466			$	44,111			$	—			$	44,111
Restricted Cash			32,863				—				32,863				7,171				—				7,171
Notes Receivable and Other			—				53,503				53,503				—				53,449				53,449
Total assets		$	70,329			$	53,503			$	123,832			$	51,282			$	53,449			$	104,731
Liabilities:
Short-term debt		$	85,000			$	—			$	85,000			$	162,000			$	—			$	162,000
Short-term debt owed to parent			—				28,933				28,933				—				29,598				29,598
Total liabilities		$	85,000			$	28,933			$	113,933			$	162,000			$	29,598			$	191,598

The fair value of the junior subordinated and long-term notes were estimated using the discounted cash flow method with U.S. Treasury yields and Company credit spreads as inputs, interpolating to the maturity date of each issue. Carrying values and estimated fair values were as follows:

 

Puget Energy						December 31, 2014								December 31, 2013
(Dollars in Thousands)		Level				Carrying Value				Fair Value				Carrying Value				Fair Value
Liabilities:
Junior subordinated notes			2			$	250,000			$	276,235			$	250,000			$	269,366
Long-term debt (fixed-rate), net of discount			2				4,694,608				6,083,554				4,683,476				5,594,314
Long-term debt (variable-rate)			2				299,000				299,000				299,000				299,000
Total						$	5,243,608			$	6,658,789			$	5,232,476			$	6,162,680

 

Puget Sound Energy						December 31, 2014								December 31, 2013
(Dollars in Thousands)		Level				Carrying Value				Fair Value				Carrying Value				Fair Value
Liabilities:
Junior subordinated notes			2			$	250,000			$	276,235			$	250,000			$	269,366
Long-term debt (fixed-rate), net of discount			2				3,513,259				4,437,473				3,513,258				4,038,455
Total						$	3,763,259			$	4,713,708			$	3,763,258			$	4,307,821

 

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Assets and Liabilities Measured at Fair Value on a Recurring Basis

The following tables present the Company’s financial assets and liabilities by level, within the fair value hierarchy, that were accounted for at fair value on a recurring basis and the reconciliation of the changes in the fair value of Level 3 derivatives in the fair value hierarchy:

 

Puget Energy		Fair Value At December 31, 2014												Fair Value At December 31, 2013
(Dollars in Thousands)		Level 2				Level 3				Total				Level 2				Level 3				Total
Interest rate derivative instruments		$	9,073			$	—			$	9,073			$	13,223			$	—			$	13,223
Total derivative liabilities		$	9,073			$	—			$	9,073			$	13,223			$	—			$	13,223

 

Puget Energy and Puget Sound Energy		Fair Value At December 31, 2014												Fair Value At December 31, 2013
(Dollars in Thousands)		Level 2				Level 3				Total				Level 2				Level 3				Total
Assets:
Electric derivative instruments		$	1,654			$	3,168			$	4,822			$	14,661			$	3,818			$	18,479
Natural gas derivative instruments			18,064				1,462				19,526				5,448				2,673				8,121
Total assets		$	19,718			$	4,630			$	24,348			$	20,109			$	6,491			$	26,600
Liabilities:
Electric derivative instruments		$	91,998			$	15,230			$	107,228			$	18,073			$	19,239			$	37,312
Natural gas derivative instruments			85,305				3,502				88,807				32,642				3,034				35,676
Total liabilities		$	177,303			$	18,732			$	196,035			$	50,715			$	22,273			$	72,988

 

Puget Energy and Puget Sound Energy		Year Ended December 31,
Level 3 Roll-Forward Net (Liability)		2014												2013												2012
(Dollars in Thousands)		Electric				Gas				Total				Electric				Gas				Total				Electric				Gas				Total
Balance at beginning of period		$	(15,421	)		$	(361	)		$	(15,782	)		$	(33,924	)		$	(1,602	)		$	(35,526	)		$	(90,311	)		$	(5,041	)		$	(95,352	)
Changes during period
Realized and unrealized energy derivatives:
Included in earnings1			(5,537	)			—				(5,537	)			(10,491	)			—				(10,491	)			(21,362	)			—				(21,362	)
Included in regulatory assets / liabilities			—				1,630				1,630				—				(945	)			(945	)			—				(1,937	)			(1,937	)
Settlements2			1,036				(1,534	)			(498	)			11,609				(754	)			10,855				59,133				969				60,102
Transferred into Level 3			5,155				(585	)			4,570				(7,799	)			—				(7,799	)			(55,548	)			(297	)			(55,845	)
Transferred out of Level 3			2,705				(1,190	)			1,515				25,184				2,940				28,124				74,164				4,704				78,868
Balance at end of period		$	(12,062	)		$	(2,040	)		$	(14,102	)		$	(15,421	)		$	(361	)		$	(15,782	)		$	(33,924	)		$	(1,602	)		$	(35,526	)

 

1

Income Statement location: Unrealized (gain) loss on derivative instruments, net. Includes unrealized gains (losses) on derivatives still held in position as of the reporting date for electric derivatives of $(9.6) million, $(13.4) million, and $(15.2) million for the years ended December 31, 2014, 2013 and 2012, respectively.

2	The Company had no purchases, sales or issuances during the reported periods.

Realized gains and losses on energy derivatives for Level 3 recurring items are included in energy costs in the Company’s consolidated statements of income under purchased electricity, electric generation fuel or purchased natural gas when settled. Unrealized gains and losses on energy derivatives for Level 3 recurring items are included in net unrealized (gain) loss on derivative instruments in the Company’s consolidated statements of income.

 

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In order to determine which assets and liabilities are classified as Level 3, the Company receives market data from its independent external pricing service defining the tenor of observable market quotes. To the extent any of the Company’s commodity contracts extend beyond what is considered observable as defined by its independent pricing service, the contracts are classified as Level 3. The actual tenor of what the independent pricing service defines as observable is subject to change depending on market conditions. Therefore, as the market changes, the same contract may be designated Level 3 one month and Level 2 the next, and vice versa. The changes of fair value classification into or out of Level 3 are recognized each month, and reported in the Level 3 Roll-forward table above. The Company did not have any transfers between Level 2 and Level 1 during the years ended December 31, 2014 and 2013. The Company does periodically transact at locations, or market price points, that are illiquid or for which no prices are available from the independent pricing service. In such circumstances the Company uses a more liquid price point and performs a 15-month regression against the illiquid locations to serve as a proxy for market prices. Such transactions are classified as Level 3. The Company does not use internally developed models to make adjustments to significant unobservable pricing inputs.

The only significant unobservable input into the fair value measurement of the Company’s Level 3 assets and liabilities is the forward price for electric and natural gas contracts. Below are the forward price ranges for the Company’s commodity contracts, as of December 31, 2014:

 

(Dollars in Thousands)

Fair Value

Valuation Technique

Unobservable Input

Range

Weighted Average

Derivative Instrument

Assets1

Liabilities1

Low

High

Electric

$

3,168

$

15,230

Discounted cash flow

Power Prices

$21.79 per MWh

$35.46 per MWh

$32.89 per MWh

Natural gas

$

1,462

$

3,502

Discounted cash flow

Natural Gas Prices

$3.11 per MMBtu

$3.83 per MMBtu

$3.28 per MMBtu

 

1	The valuation techniques, unobservable inputs and ranges are the same for asset and liability positions.

The significant unobservable inputs listed above would have a direct impact on the fair values of the above instruments if they were adjusted. Consequently significant increases or decreases in the forward prices of electricity or natural gas in isolation would result in a significantly higher or lower fair value for Level 3 assets and liabilities. Generally, interrelationships exist between market prices of natural gas and power. As such, an increase in natural gas pricing would potentially have a similar impact on forward power markets. At December 31, 2014, a hypothetical 10% increase or decrease in market prices of natural gas and electricity would change the fair value of the Company’s derivative portfolio, classified as Level 3 within the fair value hierarchy, by $3.9 million.

Long-Lived Assets Measured at Fair Value on a Nonrecurring Basis

At the time of merger, Puget Energy recorded the fair value of its intangible assets in accordance with ASC 360, “Property, Plant, and Equipment,” (ASC 360). 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 non-performance 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 is amortized as the contracts settle.

ASC 360 requires long-lived assets to be tested for impairment on an annual basis, and upon the occurrence of any events or circumstances that would be more likely than not to reduce the fair value of the long-lived assets below their carrying value. One such triggering event is a significant decrease in the forward market prices of power.

At December 31, 2014, Puget Energy completed a valuation and impairment test of its purchased power contracts classified as intangible assets. The valuation indicated a fair value of $437.6 million with an

 

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impairment to the Wells hydro contract. As of December 31, 2014, the carrying value for this contract was $65.3 million and its fair value on a discounted basis was $62.1 million, thereby requiring a write-down of $3.2 million to this intangible asset with a corresponding reduction in the regulatory liability.

Below are significant unobservable inputs used in estimating the impaired long term power purchase contract’s fair value on December 31, 2014:

 

Valuation Technique		Unobservable Input		Low		High		Average
Discounted cash flow		Power prices		$19.30 per MWh		$37.06 per MWh		$29.53 per MWh
Discounted cash flow		Power contract costs (in thousands)		$3,015 per qtr		$4,783 per qtr		$4,469 per qtr

At June 30, 2013, Puget Energy completed a valuation and impairment test of its purchased power contracts classified as intangible assets. The valuation indicated a fair value of $484.1 million with an impairment to the Priest Rapids Reasonable Portion intangible asset contract. As of June 30, 2013, the carrying value for this intangible asset contract was $47.1 million and its fair value on a discounted basis was determined to be an asset of $33.6 million, thereby requiring a write-down of $13.5 million to the intangible asset with a corresponding reduction in the regulatory liability.

Below are significant unobservable inputs used in estimating the impaired long term power purchase contract’s fair value on June 30, 2013:

 

Valuation Technique		Unobservable Input		Low		High		Average
Discounted cash flow		Power prices		$30.85 per MWh		$65.35 per MWh		$48.47 per MWh
Discounted cash flow		Power contract costs (in thousands)		$389 per yr		$6,845 per yr		$4,110 per yr

The valuations were measured using the income approach. Significant inputs included forward electricity prices and power contract pricing which provided future net cash flow estimates which are classified as Level 3 within the fair value hierarchy. A less significant input is the discount rate reflective of PSE’s cost of capital used in the valuation.

(11) Employee Investment Plans

The Company’s Investment Plan is a qualified employee 401(k) plan, under which employee salary deferrals and after-tax contributions are used to purchase several different investment fund options. PSE’s contributions to the employee Investment Plan were $14.9 million, $14.6 million and $14.5 million for the years 2014, 2013, and 2012, respectively. The employee Investment Plan eligibility requirements are set forth in the plan documents.

Non-represented employees and United Association of Journeymen and Apprentices of the Plumbing and Pipefitting Industry (UA) represented employees hired before January 1, 2014, and International Brotherhood of Electrical Workers Local Union 77 (IBEW) represented employees hired before December 12, 2014, have the following company contributions:

 

•

For employees under the Cash Balance retirement plan formula, PSE will match 100% of an employee’s contribution up to 6% of plan compensation each paycheck, and will make an additional year-end contribution equal to 1% of base pay.

 

•

For employees grandfathered under the Final Average Earning retirement plan formula, PSE will match 55% of an employee’s contribution up to 6% of plan compensation each paycheck.

 

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UA-represented employees hired on or after January 1, 2014 will have access to the 401k Plan. Non-represented employees hired on or after January 1, 2014, and IBEW-represented employees hired on or after December 12, 2014, will have access to the 401(k) plan and will choose how they want to accumulate funds for retirement, with two contribution sources from PSE:

 

•

401(k) Company Matching: New non-represented, UA-represented and IBEW-represented employees will receive company match each paycheck based on a new schedule-100% match on the first 3% of pay contributed and 50% match on the next 3% of pay contributed. An employee who contributes 6% of pay will receive 4.5% of pay in company match. Company matching will be immediately vested.

 

•

Company Contribution: New UA-represented employees will receive an annual company contribution of 4% of eligible pay placed in the Cash Balance retirement plan. New non-represented and IBEW-represented employees will receive an annual company contribution of 4% of eligible pay, placed either in the Investment Plan 401(k) plan or in PSE’s Retirement Plan (Cash Balance retirement plan). New non-represented and IBEW-represented employees will make a one-time election within 30 days of hire and direct that PSE put the 4% contribution either into the 401(k) plan or into an account in the Cash Balance retirement plan. The Company’s 4% contribution will vest after three years of service.

(12) Retirement Benefits

PSE has a defined benefit pension plan covering substantially all PSE employees. Pension benefits earned are a function of age, salary, years of service and, in the case of employees in the cash balance formula plan, the applicable annual interest crediting rates. Beginning in 2014, all new UA employees and those new non-represented employees who elect to accumulate the Company contribution in the Cash Balance pension, (effective January 1, 2014) and all new IBEW (effective December 12, 2014), will receive annual pay credits of 4% each year. They will also receive interest credits like other participants in the Cash Balance pension, which are at least 1% per quarter. When a newly-hired employee with a vested Cash Balance benefit leaves PSE, he or she will have annuity and lump sum options for distribution, with annuities calculated according to the Pension Protection Act. Those who select the lump sum option will receive their current cash balance amount. Participation by continuing employees in the Cash Balance pension plan is not affected. PSE also maintains a non-qualified Supplemental Executive Retirement Plan (SERP) for its key senior management employees.

In addition to providing pension benefits, PSE provides group health care and life insurance benefits for certain retired employees. These benefits are provided principally through an insurance company. The insurance premiums, paid primarily by retirees, are based on the benefits provided during the year.

The 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. Such purchase accounting adjustments associated with the re-measurement of the retirement plans are recorded at Puget Energy.

 

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The following tables summarize the Company’s change in benefit obligation, change in plan assets and amounts recognized in the Statements of Financial Position for the years ended December 31, 2014 and 2013:

 

Puget Energy and Puget Sound Energy		Qualified Pension Benefits								SERP Pension Benefits								Other Benefits
(Dollars in Thousands)		2014				2013				2014				2013				2014				2013
Change in benefit obligation:
Benefit obligation at beginning of period		$	573,317			$	616,290			$	47,279			$	51,795			$	14,939			$	17,672
Service cost			17,437				19,285				1,042				1,498				112				134
Interest cost			28,039				24,754				2,310				2,045				684				664
Amendment			—				—				—				478				—				—
Actuarial loss (gain)			104,618				(48,559	)			7,162				(1,687	)			1,108				(2,240	)
Benefits paid			(33,217	)			(38,453	)			(1,938	)			(6,850	)			(1,424	)			(1,536	)
Medicare part D subsidy received			—				—				—				—				269				245
Benefit obligation at end of period		$	690,194			$	573,317			$	55,855			$	47,279			$	15,688			$	14,939

 

Puget Energy and Puget Sound Energy		Qualified Pension Benefits								SERP Pension Benefits								Other Benefits
(Dollars in Thousands)		2014				2013				2014				2013				2014				2013
Change in plan assets:
Fair value of plan assets at beginning of period		$	615,721			$	531,183			$	—			$	—			$	8,774			$	7,541
Actual return on plan assets			25,669				102,591				—				—				522				1,861
Employer contribution			18,000				20,400				1,938				6,850				488				908
Benefits paid			(33,217	)			(38,453	)			(1,938	)			(6,850	)			(1,424	)			(1,536	)
Fair value of plan assets at end of period		$	626,173			$	615,721			$	—			$	—			$	8,360			$	8,774
Funded status at end of period		$	(64,021	)		$	42,404			$	(55,855	)		$	(47,279	)		$	(7,328	)		$	(6,165	)

 

Puget Energy and Puget Sound Energy		Qualified Pension Benefits								SERP Pension Benefits								Other Benefits
(Dollars in Thousands)		2014				2013				2014				2013				2014				2013
Amounts recognized in Statement of Financial Position consist of:
Noncurrent assets		$	—			$	42,404			$	—			$	—			$	—			$	—
Current liabilities			—				—				(4,386	)			(3,981	)			(355	)			(421	)
Noncurrent liabilities			(64,021	)			—				(51,469	)			(43,298	)			(6,973	)			(5,744	)
Net assets (liabilities)		$	(64,021	)		$	42,404			$	(55,855	)		$	(47,279	)		$	(7,328	)		$	(6,165	)

 

Puget Energy and Puget Sound Energy		Qualified Pension Benefits								SERP Pension Benefits								Other Benefits
(Dollars in Thousands)		2014				2013				2014				2013				2014				2013
Pension Plans with an Accumulated Benefit Obligation in excess of Plan Assets:
Project benefit obligation		$	690,194			$	573,317			$	55,855			$	47,279			$	15,688			$	14,939
Accumulated benefit obligation			681,745				566,689				50,137				40,892				15,553				14,794
Fair value of plan assets		$	626,173			$	615,721			$	—			$	—			$	8,360			$	8,774

 

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The following tables summarize Puget Energy and Puget Sound Energy’s pension benefit amounts recognized in Accumulated Other Comprehensive income for the years ended December 31, 2014 and 2013:

 

Puget Energy		Qualified Pension Benefits								SERP Pension Benefits								Other Benefits
(Dollars in Thousands)		2014				2013				2014				2013				2014				2013
Amounts recognized in Accumulated Other Comprehensive Income consist of:
Net loss (gain)		$	55,471			$	(65,943	)		$	15,918			$	9,670			$	(1,457	)		$	(2,972	)
Prior service cost (credit)			(13,782	)			(15,762	)			331				373				—				—
Total		$	41,689			$	(81,705	)		$	16,249			$	10,043			$	(1,457	)		$	(2,972	)

 

Puget Sound Energy		Qualified Pension Benefits								SERP Pension Benefits								Other Benefits
(Dollars in Thousands)		2014				2013				2014				2013				2014				2013
Amounts recognized in Accumulated Other Comprehensive Income consist of:
Net loss (gain)		$	247,331			$	138,324			$	19,751			$	14,050			$	(3,733	)		$	(5,556	)
Prior service cost (credit)			(10,952	)			(12,525	)			339				383				3				6
Total		$	236,379			$	125,799			$	20,090			$	14,433			$	(3,730	)		$	(5,550	)

The following tables summarize Puget Energy’s and Puget Sound Energy’s net periodic benefit cost for the years ended December 31, 2014, 2013 and 2012:

 

Puget Energy		Qualified Pension Benefits												SERP Pension Benefits												Other Benefits
(Dollars in Thousands)		2014				2013				2012				2014				2013				2012				2014				2013				2012
Components of net periodic benefit cost:
Service cost		$	17,437			$	19,285			$	16,926			$	1,042			$	1,498			$	1,073			$	112			$	134			$	139
Interest cost			28,039				24,754				25,986				2,310				2,045				2,152				684				664				751
Expected return on plan assets			(42,464	)			(39,095	)			(36,203	)			—				—				—				(535	)			(436	)			(435	)
Amortization of prior service cost (credit)			(1,980	)			(1,980	)			(1,980	)			42				(17	)			—				—				—				—
Amortization of net loss			—				2,889				768				913				1,461				702				(393	)			69				53
Net periodic benefit cost		$	1,032			$	5,853			$	5,497			$	4,307			$	4,987			$	3,927			$	(132	)		$	431			$	508

 

Puget Sound Energy		Qualified Pension Benefits												SERP Pension Benefits												Other Benefits
(Dollars in Thousands)		2014				2013				2012				2014				2013				2012				2014				2013				2012
Components of net periodic benefit cost:
Service cost		$	17,437			$	19,285			$	16,926			$	1,042			$	1,498			$	1,073			$	112			$	134			$	139
Interest cost			28,039				24,753				25,986				2,310				2,045				2,152				684				664				751
Expected return on plan assets			(43,252	)			(40,685	)			(41,533	)			—				—				—				(535	)			(436	)			(435	)
Amortization of prior service cost (credit)			(1,573	)			(1,573	)			(1,573	)			44				(16	)			293				3				30				35
Amortization of net loss (gain)			13,195				20,612				15,015				1,461				2,191				1,432				(702	)			(284	)			(245	)
Amortization of transition obligation			—				—				—				—				—				—				—				—				50
Net periodic benefit cost		$	13,846			$	22,392			$	14,821			$	4,857			$	5,718			$	4,950			$	(438	)		$	108			$	295

 

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The following tables summarize Puget Energy’s and Puget Sound Energy’s benefit obligations recognized in other comprehensive income for the years ended December 31, 2014 and 2013:

 

Puget Energy		Qualified Pension Benefits								SERP Pension Benefits								Other Benefits
(Dollars in Thousands)		2014				2013				2014				2013				2014				2013
Other changes (pre-tax) in plan assets and benefit obligations recognized in other comprehensive income:
Net loss (gain)		$	121,413			$	(112,055	)		$	7,162			$	(1,687	)		$	1,121			$	(3,665	)
Amortization of net loss (gain)			—				(2,889	)			(913	)			(1,461	)			394				(70	)
Prior service credit			—				—				—				478				—				—
Amortization of prior service credit			1,980				1,980				(42	)			17				—				—
Total change in other comprehensive income for year		$	123,393			$	(112,964	)		$	6,207			$	(2,653	)		$	1,515			$	(3,735	)

 

Puget Sound Energy		Qualified Pension Benefit								SERP Pension Benefits								Other Benefits
(Dollars in Thousands)		2014				2013				2014				2013				2014				2013
Other changes (pre-tax) in plan assets and benefit obligations recognized in other comprehensive income:
Net loss (gain)		$	122,202			$	(110,465	)		$	7,162			$	(1,687	)		$	1,121			$	(3,665	)
Amortization of net (loss) gain			(13,195	)			(20,612	)			(1,461	)			(2,191	)			702				284
Prior service cost (credit)			—				—				—				477				—				—
Amortization of prior service cost (credit)			1,573				1,573				(44	)			16				(3	)			(30	)
Amortization of transition obligation			—				—				—				—				—				—
Total change in other comprehensive income for year		$	110,580			$	(129,504	)		$	5,657			$	(3,385	)		$	1,820			$	(3,411	)

The estimated prior service cost (credit) for the pension plans that will be amortized from accumulated OCI into net periodic benefit cost in 2015 by Puget Energy is $3.9 million. The estimated net (loss) gain for the SERP that will be amortized from accumulated OCI into net periodic benefit cost in 2015 is $1.6 million. The estimated prior service cost (credit) for the SERP that will be amortized from accumulated OCI into net periodic benefit cost in 2015 is 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 2015 are immaterial.

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 2015 by Puget Sound Energy are $20.5 million and $1.6 million, respectively. 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 2015 are $2.1 million. The estimated prior service cost (credit) for the SERP that will be amortized from accumulated OCI into net periodic benefit cost in 2015 is immaterial. The estimated net (loss) gain for the other postretirement plan that will be amortized from accumulated OCI into net periodic benefit cost in 2015 is $0.3 million and prior service cost (credit) and transition (obligation) asset for the other postretirement plans are immaterial.

The aggregate expected contributions by the Company to fund the qualified pension plan, SERP and the other postretirement plans for the year ending December 31, 2015 are expected to be at least $18.0 million, $4.4 million and $0.5 million, respectively.

 

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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
		2014				2013				2012				2014				2013				2012				2014				2013				2012
Benefit Obligation Assumptions
Discount rate1			4.25	%			5.10	%			4.15	%			4.25	%			5.10	%			4.15	%			4.25	%			5.10	%			4.15	%
Rate of compensation increase			4.50	%			4.50	%			4.50	%			4.50	%			4.50	%			4.50	%			4.50	%			4.50	%			4.50	%
Medical trend rate			—				—				—				—				—				—				5.70	%			6.80	%			7.50	%
Benefit Cost Assumptions
Discount rate			5.10	%			4.15	%			4.75	%			5.10	%			4.15	%			4.75	%			5.10	%			4.15	%			4.75	%
Rate of plan assets			7.75	%			7.75	%			7.75	%			—				—				—				7.00	%			6.90	%			7.50	%
Rate of compensation increase			4.50	%			4.50	%			4.50	%			4.50	%			4.50	%			4.50	%			4.50	%			4.50	%			4.50	%
Medical trend rate			—				—				—				—				—				—				6.70	%			8.20	%			7.50	%

 

1	The Company calculates the present value of the pension liability using a discount rate of 4.25% which represents the single-rate equivalent of the AA rated corporate bond yield curve.

The assumed medical inflation rate used to determine benefit obligations is 6.70% in 2015 grading down to 4.30% in 2016. A 1.0% change in the assumed medical inflation rate would have the following effects:

 

		2014								2013
(Dollars in Thousands)		1% Increase				1% Decrease				1% Increase				1% Decrease
Effect on post-retirement benefit obligation		$	47			$	(47	)		$	66			$	(66	)
Effect on service and interest cost components			2				(2	)			3				(3	)

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.

 

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Plan Benefits

The expected total benefits to be paid under the next five years and the aggregate total to be paid for the five years thereafter are as follows:

 

(Dollars in Thousands)		2015				2016				2017				2018				2019				2020-2024
Qualified Pension total benefits		$	41,100			$	41,400			$	42,100			$	43,300			$	43,900			$	237,300
SERP Pension total benefits		$	4,386			$	2,595				1,940				5,346				5,811				18,759
Other Benefits total with Medicare Part D subsidy		$	1,080			$	1,136			$	1,113			$	1,085			$	1,062			$	5,935
Other Benefits total without Medicare Part D subsidy		$	1,429			$	1,414			$	1,398			$	1,380			$	1,362			$	6,340

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	%			31	%			40	%
Domestic small cap equity			0	%			9	%			15	%
Non-U.S. equity			10	%			25	%			30	%
Fixed income			15	%			25	%			30	%
Real estate			0	%			0	%			10	%
Absolute return			5	%			10	%			15	%
Cash			0	%			0	%			5	%

Plan Fair Value Measurements

ASC 715, “Compensation—Retirement Benefits” (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.

ASC 820 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.

 

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The following table sets forth by level, within the fair value hierarchy, the qualified pension plan as of December 31, 2014 and 2013:

 

		Recurring Fair Value Measures As of December 31, 2014																Recurring Fair Value Measures As of December 31, 2013
(Dollars in Thousands)		Level 1				Level 2				Level 3				Total				Level 1				Level 2				Level 3				Total
Assets:
Equities:
Non-US equity1		$	71,026			$	74,131			$	—			$	145,157			$	76,188			$	78,816			$	—			$	155,004
Domestic large cap equity2			134,765				68,336				—				203,101				157,874				35,851				—				193,725
Domestic small cap equity3			59,657				—				—				59,657				62,867				—				—				62,867
Total equities			265,448				142,467				—				407,915				296,929				114,667				—				411,596
Tactical asset allocation4			—				—				—				—				—				—				—				—
Fixed income securities5			72,331				67,182				—				139,513				135,007				—				—				135,007
Absolute return6			—				—				65,251				65,251				—				—				62,278				62,278
Cash and cash equivalents7			12,650				—				—				12,650				—				7,054				—				7,054
Subtotal		$	350,429			$	209,649			$	65,251			$	625,329			$	431,936			$	121,721			$	62,278			$	615,935
Net (payable) receivable			—				—				—				844				—				—				—				(417	)
Accrued income			—				—				—				—				—				—				—				203
Total assets														$	626,173															$	615,721

 

1

Non—US Equity investments are comprised of a (1) mutual fund; and a (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, 2014. 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, 2014.

2

Domestic large cap equity investments are comprised of (1) common stock, and a (2) commingled fund. Investments in common stock are valued using quoted market prices multiplied by the number of shares owned as of December 31, 2014. 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, 2014.

3

Domestic small cap equity investments are comprised of (1) common stock and a (2) mutual fund. The investments in common stock are valued using quoted market prices multiplied by the number of shares owned as of December 31, 2014. The investment in the mutual fund is valued using quoted market prices multiplied by the number of shares owned as of December 31, 2014.

4	The tactical asset allocation investment is comprised 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. The investment in the mutual fund is valued using quoted market prices multiplied by the number of shares owned as of December 31, 2014.

6

As of December 31, 2014 absolute return investments consist of two partnerships. The partnerships are valued using the financial reports as of December 31, 2014. These investments are a Level 3 under ASC 820 because the significant valuation inputs are primarily internal to the partnerships with little third party involvement.

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, 2014. The money market fund invests primarily in commercial paper, notes, repurchase agreements, and other evidences of indebtedness which are payable on demand or short-term in nature.

 

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Level 3 Roll-Forward

The following table sets forth a reconciliation of changes in the fair value of the plan’s Level 3 assets:

 

		As of December 31, 2014												As of December 31, 2013
(Dollars in Thousands)		Partnership				Mutual Funds				Total				Partnership				Mutual Funds				Total
Balance at beginning of year		$	62,278			$	—			$	62,278			$	55,614			$	—			$	55,614
Additional investments			—				—				—				—				—				—
Distributions			—				—				—				—				—				—
Realized losses on distributions			—				—				—				—				—				—
Unrealized gains relating to instruments still held at the reporting date			2,973				—				2,973				6,664				—				6,664
Transferred out of level 31			—				—				—				—				—				—
Balance at end of year		$	65,251			$	—			$	65,251			$	62,278			$	—			$	62,278

 

1	The plan had no transfers between level 2 and level 1 during the years ended December 31, 2014 or 2013.

The following table sets forth by level, within the fair value hierarchy, the Other Benefits plan assets which consist of insurance benefits for retired employees, at fair value:

 

		Recurring Fair Value Measures As of December 31, 2014												Recurring Fair Value Measures As of December 31, 2013
(Dollars in Thousands)		Level 1				Level 2				Total				Level 1				Level 2				Total
Assets:
Mutual fund1		$	8,301			$	—			$	8,301			$	8,703			$	—			$	8,703
Cash equivalents2			59				—				59				—				71				71
Total assets		$	8,360			$	—			$	8,360			$	8,703			$	71			$	8,774

 

1

This is a publicly traded balanced mutual fund. The fund 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, 2014.

2

This is a money market fund. The money market fund investments are valued at the net asset value per share of $1.00 per unit as of December 31, 2014. The money market fund invests primarily in commercial paper, notes, repurchase agreements, and other evidences of indebtedness which are payable on demand or short-term in nature.

(13) Income Taxes

The details of income tax (benefit) expense are as follows:

 

Puget Energy		Year Ended December 31,
(Dollars in Thousands)		2014				2013				2012
Charged to operating expenses:
Current:
Federal		$	—			$	—			$	4,268
State			—				—				—
Deferred:
Federal			57,152				122,559				100,701
State			(167	)			(151	)			(244	)
Total income tax expense		$	56,985			$	122,408			$	104,725

 

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Puget Sound Energy		Year Ended December 31,
(Dollars in Thousands)		2014				2013				2012
Charged to operating expenses:
Current:
Federal		$	—			$	—			$	4,268
State			—				—				—
Deferred:
Federal			89,342				160,886				145,040
State			—				—				—
Total income tax expense		$	89,342			$	160,886			$	149,308

The following reconciliation compares pre-tax book income at the federal statutory rate of 35.0% to the actual income tax expense in the Statements of Income:

 

Puget Energy		Year Ended December 31,
(Dollars in Thousands)		2014				2013				2012
Income taxes at the statutory rate		$	80,087			$	142,847			$	132,491
Increase (decrease):
Production tax credit			(23,073	)			(22,414	)			(22,188	)
AFUDC excluded from taxable income			(3,790	)			(9,406	)			(16,543	)
Capitalized interest			2,947				7,294				9,757
Utility plant differences			7,090				9,527				8,674
Treasury grant amortization			(8,808	)			(7,651	)			(1,007	)
Tenaska gas contract			—				1				(4,687	)
Other—net			2,532				2,210				(1,772	)
Total income tax expense		$	56,985			$	122,408			$	104,725
Effective tax rate			24.9	%			30.0	%			27.7	%

 

Puget Sound Energy		Year Ended December 31,
(Dollars in Thousands)		2014				2013				2012
Income taxes at the statutory rate		$	114,084			$	180,955			$	176,917
Increase (decrease):
Production tax credit			(23,073	)			(22,414	)			(22,188	)
AFUDC excluded from taxable income			(3,790	)			(9,406	)			(16,543	)
Capitalized interest			2,947				7,294				9,757
Utility plant differences			7,090				9,527				8,674
Treasury grant amortization			(8,808	)			(7,651	)			(1,007	)
Tenaska gas contract			—				1				(4,687	)
Other—net			892				2,580				(1,615	)
Total income tax expense		$	89,342			$	160,886			$	149,308
Effective tax rate			27.4	%			31.1	%			29.5	%

 

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The Company’s deferred tax liability at December 31, 2014 and 2013 is composed of amounts related to the following types of temporary differences:

 

Puget Energy		At December 31,
(Dollars in Thousands)		2014				2013
Utility plant and equipment		$	1,720,730			$	1,625,107
Regulatory asset for income taxes			95,432				146,867
Fair value of debt instruments			73,606				76,991
Other deferred tax liabilities			200,124				202,189
Subtotal deferred tax liabilities			2,089,892				2,051,154
Net operating loss carryforward			(417,684	)			(374,606	)
Production tax credit carryforward			(158,604	)			(135,531	)
Regulatory liability on production tax credit			(84,344	)			(71,880	)
Fair value of derivative instruments			(36,227	)			(7,166	)
Other deferred tax assets			(32,121	)			(60,970	)
Subtotal deferred tax assets			(728,980	)			(650,153	)
Total		$	1,360,912			$	1,401,001

 

Puget Sound Energy		At December 31,
(Dollars In Thousands)		2014				2013
Utility plant and equipment		$	1,720,730			$	1,625,107
Regulatory asset for income taxes			94,913				146,350
Other deferred tax liabilities			171,380				131,977
Subtotal deferred tax liabilities			1,987,023				1,903,434
Net operating loss carryforward			(181,514	)			(173,068	)
Production tax credit carryforward			(158,604	)			(135,531	)
Regulatory liability on production tax credit			(84,344	)			(71,880	)
Fair value of derivative instruments			(39,067	)			(9,988	)
Other deferred tax assets			(82,084	)			(69,175	)
Subtotal deferred tax assets			(545,613	)			(459,642	)
Total		$	1,441,410			$	1,443,792

The above amounts have been classified in the Consolidated Balance Sheets as follows:

 

Puget Energy		At December 31
(Dollars in Thousands)		2014				2013
Current deferred taxes		$	(161,445	)		$	(86,004	)
Non-current deferred taxes			1,522,357				1,487,005
Total		$	1,360,912			$	1,401,001

 

Puget Sound Energy		At December 31
(Dollars in Thousands)		2014				2013
Current deferred taxes		$	(208,447	)		$	(141,058	)
Non-current deferred taxes			1,649,857				1,584,850
Total		$	1,441,410			$	1,443,792

The Company calculates its deferred tax assets and liabilities under ASC 740, “Income Taxes” (ASC 740). ASC 740 requires recording deferred tax balances, at the currently enacted tax rate, on assets and liabilities

 

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that are reported differently for income tax purposes than for financial reporting purposes. The utilization of deferred tax assets requires sufficient taxable income in future years. ASC 740 requires a valuation allowance on deferred tax assets when it is more likely than not that the deferred tax assets will not be realized. The Company’s PTC carryforwards expire from 2026 through 2034. The Company’s net operating loss carryforwards expire from 2029 through 2034.

For ratemaking purposes, deferred taxes are not provided for certain temporary differences. PSE has established a regulatory asset for income taxes recoverable through future rates related to those temporary differences for which no deferred taxes have been provided, based on prior and expected future ratemaking treatment.

The Company accounts for uncertain tax position under ASC 740, which clarifies the accounting for uncertainty in income taxes recognized in the financial statements. 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 challenge by the taxing authorities and taken by management to the court of last resort. 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.

As of December 31, 2014 and 2013, the Company had no material unrecognized tax benefits. As a result, no interest or penalties were accrued for unrecognized tax benefits during the year.

For ASC 740 purposes, the Company has open tax years from 2010 through 2014. The Company classifies interest as interest expense and penalties as other expense in the financial statements.

(14) Litigation

Colstrip

PSE has a 50% ownership interest in Colstrip Units 1 and 2, and a 25% interest in Colstrip Units 3 and 4. On March 6, 2013, Sierra Club and Montana Environmental Information Center (MEIC) filed a Clean Air Act citizen suit against all Colstrip owners (including PSE) alleging numerous claims for relief, most of which relate to alleged prevention of significant deterioration (PSD) violations. One claim relates to the alleged failure to update the Title V permit to reflect the major modifications alleged in the first thirty-six claim, another claim alleges that the previous Title V compliance certifications have been incomplete because they did not address the alleged major modifications, and the last claim alleges opacity violations since 2007. The lawsuit was filed in U.S. District of Montana, Billings Division, requesting injunctive relief and civil penalties, including a request that the owners remediate environmental damage and that $100,000 of the civil penalties be used for beneficial mitigation projects. Discovery in the case is ongoing, and it has been bifurcated into separate liability and remedy trials. The liability trial is currently set for November 2015, and a date for the remedy trial has yet to be determined. PSE is litigating the allegations set forth in the notices, and as such, it is not reasonably possible to estimate the outcome of this matter.

Other Proceedings

The Company is also involved in litigation relating to claims arising out of its operations in the normal course of business. The Company has recorded reserves of $1.7 million and $1.4 million relating to these claims as of December 31, 2014 and 2013, respectively.

(15) Commitments and Contingencies

For the year ended December 31, 2014, approximately 14.9% of the Company’s energy output was obtained at an average cost of approximately $0.021 per Kilowatt Hour (kWh) through long-term contracts with three of

 

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the Washington Public Utility Districts (PUDs) that 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; therefore, PSE is required to make the payments even if power is not 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 contract lives.

The Company’s expenses under these PUD contracts were as follows for the years ended December 31:

 

(Dollars in Thousands)		2014				2013				2012
PUD contract costs		$	69,661			$	63,365			$	70,188

As of December 31, 2014, the Company purchased portions of the power output of the PUDs’ projects as set forth in the following table:

 

						Company’s Current Share of
(Dollars in Thousands)		Contract Expiration				Percent of Output				Megawatt Capacity				Estimated 2015 Costs				2015 Debt Service Costs				Interest included in 2015 Debt Service Costs				Debt Outstanding
Chelan County PUD:
Rock Island Project			2031				25.0	%			156			$	29,854			$	11,009			$	6,174			$	98,191
Rocky Reach Project			2031				25.0	%			325				27,583				8,245				3,343				53,299
Douglas County PUD:
Wells Project			2018				29.9	%			251				17,277				9,383				2,597				64,931
Grant County PUD:
Priest Rapids Development			2052				0.6	%			8				3,689				2,087				1,245				19,828
Wanapum Development			2052				0.6	%			9				3,689				2,087				1,245				19,828
Total											749			$	82,092			$	32,811			$	14,604			$	256,077

The following table summarizes the Company’s estimated payment obligations for power purchases from the Columbia River projects, contracts with other utilities and contracts with non-utilities. These contracts have varying terms and may include escalation and termination provisions.

 

(Dollars in Thousands)		2015				2016				2017				2018				2019				Thereafter				Total
Columbia River projects		$	73,023			$	75,360			$	74,851			$	65,981			$	53,837			$	644,666			$	987,718
Other utilities			16,136				18,884				11,823				1,257				890				—				48,990
Non-utility contracts			117,372				153,863				199,056				204,292				209,699				1,354,191				2,238,473
Total		$	206,531			$	248,107			$	285,730			$	271,530			$	264,426			$	1,998,857			$	3,275,181

Total purchased power contracts provided the Company with approximately 12.1 million, 10.7 million and 6.1 million MWhs of firm energy at a cost of approximately $401.4 million, $348.7 million and $203.1 million for the years 2014, 2013 and 2012, respectively.

The Company has natural gas-fired generation facility obligations for natural gas supply amounting to an estimated $63.6 million in 2015. Longer term agreements for natural gas supply amount to an estimated $286.7 million for 2016 through 2019.

 

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PSE enters into short-term energy supply contracts to meet its core customer needs. These contracts are sometimes classified as NPNS, however in most cases recorded at fair value in accordance with ASC 815. Commitments under these contracts are $105.8 million, $32.4 million and $6.5 million in 2015, 2016 and 2017, respectively.

Natural Gas Supply Obligations

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. The transportation and storage contracts, which have remaining terms from less than one year to 30 years, provide that the Company must pay a fixed demand charge each month, regardless of actual usage. The Company contracts for 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 to ensure service to PSE’s customers and generation requirements. The Company incurred demand charges in 2014 for firm transportation service and firm storage and peaking service of $155.0 million and $6.6 million, respectively. The demand charge for firm natural gas supply was immaterial in 2014. The Company incurred demand charges in 2014 for firm transportation and firm storage service for the natural gas supply for its combustion turbines in the amount of $35.7 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 the FERC and NEB (National Energy Board) currently authorized rates, which are subject to change.

 

Demand Charge Obligations (Dollars in Thousands)		2015				2016				2017				2018				2019				Thereafter				Total
Firm transportation service		$	154,121			$	147,424			$	144,751			$	131,484			$	112,249			$	373,958			$	1,063,987
Firm storage service			6,528				5,337				5,209				1,407				1,535				1,258				21,274
Total		$	160,649			$	152,761			$	149,960			$	132,891			$	113,784			$	375,216			$	1,085,261

Service Contracts

The following table summarizes the Company’s estimated obligations for service contracts through the terms of its existing contracts.

 

Service Contract Obligations (Dollars in Thousands)		2015				2016				2017				2018				2019				Thereafter				Total
Energy production service contracts		$	32,979			$	15,650			$	5,558			$	4,064			$	2,372			$	23,443			$	84,066
Automated meter reading system			25,402				16,081				13,362				13,996				14,602				51,986				135,429
Total		$	58,381			$	31,731			$	18,920			$	18,060			$	16,974			$	75,429			$	219,495

Other Contingencies

For information regarding PSE’s environmental remediation obligations, see Note 3 Regulation and Rates.

(16) Related Party Transactions

On October 10, 2014, U.S. Bancorp announced the appointment of Kimberly Harris to its board of directors effective October 20, 2014. Ms. Harris is the president and chief executive officer of both Puget Energy and PSE. U.S. Bancorp is the parent company of U.S. Bank N.A., which directly or through its subsidiaries or affiliates provides credit, banking, investment and trust services to both Puget Energy and PSE. For the year

 

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ended December 31, 2014, Puget Energy and PSE paid a total of approximately $1.0 million in fees and interest to U.S. Bank N.A. and its subsidiaries or affiliates.

In 2006, PSE entered into a revolving credit facility with Puget Energy in the form of a Demand Promissory Note (Note). At December 31, 2014 and 2013, the outstanding balance of the Note was $28.9 million and $29.6 million, respectively, and the interest rate was 0.391% and 0.325%, respectively. (See Note 7).

(17) Segment Information

Puget Energy operates one reportable business segment referred to as the regulated utility segment. 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. In managing the business, management reviews the consolidated financial statements for Puget Energy and PSE during the year.

(18) Accumulated Other Comprehensive Income (Loss)

The following tables present the changes in the Company’s accumulated other comprehensive income (loss) (AOCI) by component for the years ended December 31, 2014, 2013 and 2012, respectively.

 

Puget Energy Changes in AOCI, net of tax (Dollars in Thousands)		Net unrealized gain (loss) and prior service cost on pension plans				Net unrealized gain (loss) on energy derivative instruments				Net unrealized gain (loss) on interest rate swaps				Total
Balance at December 31, 2011		$	(15,195	)		$	(1,113	)		$	(14,599	)		$	(30,907	)
Other comprehensive income (loss) before reclassifications			(13,574	)			—				—				(13,574	)
Amounts reclassified from accumulated other comprehensive income (loss), net of tax			(296	)			371				11,577				11,652
Net current-period other comprehensive income (loss)			(13,870	)			371				11,577				(1,922	)
Balance at December 31, 2012		$	(29,065	)		$	(742	)		$	(3,022	)		$	(32,829	)
Other comprehensive income (loss) before reclassifications			76,004				—				—				76,004
Amounts reclassified from accumulated other comprehensive income (loss), net of tax			1,575				37				2,928				4,540
Net current-period other comprehensive income (loss)			77,579				37				2,928				80,544
Balance at December 31, 2013		$	48,514			$	(705	)		$	(94	)		$	47,715
Other comprehensive income (loss) before reclassifications			(84,301	)			—				—				(84,301	)
Amounts reclassified from accumulated other comprehensive income (loss), net of tax			(923	)			372				94				(457	)
Net current-period other comprehensive income (loss)			(85,224	)			372				94				(84,758	)
Balance at December 31, 2014		$	(36,710	)		$	(333	)		$	—			$	(37,043	)

 

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Puget Sound Energy Changes in AOCI, net of tax (Dollars in Thousands)		Net unrealized gain (loss) and prior service cost on pension plans				Net unrealized gain (loss) on energy derivative instruments				Net unrealized gain (loss) on treasury interest rate swaps				Total
Balance at December 31, 2011		$	(168,704	)		$	(12,934	)		$	(6,941	)		$	(188,579	)
Other comprehensive income (loss) before reclassifications			(17,049	)			—				—				(17,049	)
Amounts reclassified from accumulated other comprehensive income (loss), net of tax			9,755				8,358				317				18,430
Net current-period other comprehensive income (loss)			(7,294	)			8,358				317				1,381
Balance at December 31, 2012		$	(175,998	)		$	(4,576	)		$	(6,624	)		$	(187,198	)
Other comprehensive income (loss) before reclassifications			74,969				—				—				74,969
Amounts reclassified from accumulated other comprehensive income (loss), net of tax			13,624				2,549				317				16,490
Net current-period other comprehensive income (loss)			88,593				2,549				317				91,459
Balance at December 31, 2013		$	(87,405	)		$	(2,027	)		$	(6,307	)		$	(95,739	)
Other comprehensive income (loss) before reclassifications			(84,955	)			—				—				(84,955	)
Amounts reclassified from accumulated other comprehensive income (loss), net of tax			8,079				1,341				317				9,737
Net current-period other comprehensive income (loss)			(76,876	)			1,341				317				(75,218	)
Balance at December 31, 2014		$	(164,281	)		$	(686	)		$	(5,990	)		$	(170,957	)

Details about these reclassifications out of accumulated other comprehensive income (loss) for the years ended December 31, 2014, 2013 and 2012, respectively, are as follows:

 

Puget Energy (Dollars in Thousands) Details about accumulated other comprehensive income (loss) components		Affected line item in the statement where net income (loss) is presented		Amount reclassified from accumulated other comprehensive income (loss)
				2014				2013				2012
Net unrealized gain (loss) and prior service cost on pension plans:
Amortization of prior service cost		(a)			1,938				1,997				1,980
Amortization of net gain (loss)		(a)			(519	)			(4,420	)			(1,524	)
		Total before tax			1,419				(2,423	)			456
		Tax (expense) or benefit			(496	)			848				(160	)
		Net of Tax		$	923			$	(1,575	)		$	296
Net unrealized gain (loss) on energy derivative instruments:
Commodity contracts: Electric derivatives		Electric generation fuel			—				—				100
		Purchased electricity			(572	)			(57	)			(671	)
		Total before tax			(572	)			(57	)			(571	)
		Tax (expense) or benefit			200				20				200
		Net of Tax		$	(372	)		$	(37	)		$	(371	)
Net unrealized gain (loss) on interest rate swaps:
Interest rate contracts		Interest expense		$	(144	)		$	(4,505	)		$	(17,811	)
		Tax (expense) or benefit			50				1,577				6,234
		Net of Tax		$	(94	)		$	(2,928	)		$	(11,577	)
Total reclassification for the period		Net of Tax		$	457			$	(4,540	)		$	(11,652	)

 

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(a)	These accumulated other comprehensive income components are included in the computation of net periodic pension cost (see Note 12 for additional details).

 

Puget Sound Energy (Dollars in Thousands) Details about accumulated other comprehensive income (loss) components		Affected line item in the statement where net income (loss) is presented		Amount reclassified from accumulated other comprehensive income (loss)
				2014				2013				2012
Net unrealized gain (loss) and prior service cost on pension plans:
Amortization of prior service cost		(a)		$	1,526			$	1,559			$	1,245
Amortization of net gain (loss)		(a)			(13,954	)			(22,519	)			(16,203	)
Amortization of transition obligation		(a)			—				—				(50	)
		Total before tax			(12,428	)			(20,960	)			(15,008	)
		Tax (expense) or benefit			4,349				7,336				5,253
		Net of tax		$	(8,079	)		$	(13,624	)		$	(9,755	)
Net unrealized gain (loss) on energy derivative instruments:
Commodity contracts:
Electric derivatives		Electric generation fuel			—				—				97
		Purchased electricity			(2,063	)			(3,922	)			(12,955	)
		Total before tax			(2,063	)			(3,922	)			(12,858	)
		Tax (expense) or benefit			722				1,373				4,500
		Net of Tax		$	(1,341	)		$	(2,549	)		$	(8,358	)
Net unrealized gain (loss) on treasury interest rate swaps:
Interest rate contracts		Interest expense			(488	)			(488	)			(488	)
		Tax (expense) or benefit			171				171				171
		Net of Tax		$	(317	)		$	(317	)		$	(317	)
Total reclassification for the period		Net of Tax		$	(9,737	)		$	(16,490	)		$	(18,430	)

 

(a)	These accumulated other comprehensive income components are included in the computation of net periodic pension cost (see Note 12 for additional details).

 

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PUGET ENERGY, INC.

CONSOLIDATED STATEMENTS OF INCOME

(Dollars in Thousands)

(Unaudited)

 

		Three Months Ended September 30,								Nine Months Ended September 30,
		2015				2014				2015				2014
Operating revenue:
Electric		$	482,786			$	468,530			$	1,526,029			$	1,577,663
Natural gas			119,582				121,402				653,385				692,780
Other			3,365				3,783				11,495				11,563
Total operating revenue			605,733				593,715				2,190,909				2,282,006
Operating expenses:
Energy costs:
Purchased electricity			97,694				67,984				355,645				363,769
Electric generation fuel			76,863				92,510				180,531				202,741
Residential exchange			(19,530	)			(30,963	)			(92,297	)			(84,587	)
Purchased natural gas			46,436				42,550				282,334				310,128
Unrealized (gain) loss on derivative instruments, net			5,588				32,648				(6,339	)			7,714
Utility operations and maintenance			131,208				132,109				400,355				411,068
Non-utility expense and other			1,573				2,911				7,106				8,627
Depreciation and amortization			107,759				105,905				314,348				312,821
Conservation amortization			24,224				23,047				78,389				74,554
Taxes other than income taxes			64,030				59,945				228,942				228,534
Total operating expenses			535,845				528,646				1,749,014				1,835,369
Operating income (loss)			69,888				65,069				441,895				446,637
Other income (deductions):
Other income			4,732				10,956				14,770				19,817
Other expense			(1,621	)			(1,806	)			(4,843	)			(5,032	)
Non-hedged interest rate swap (expense) income			(1,156	)			(323	)			(4,571	)			(2,430	)
Interest charges:
AFUDC			2,102				1,474				5,262				4,189
Interest expense			(88,753	)			(93,258	)			(267,484	)			(275,685	)
Income (loss) before income taxes			(14,808	)			(17,888	)			185,029				187,496
Income tax (benefit) expense			(6,880	)			(4,930	)			51,665				51,749
Net income (loss)		$	(7,928	)		$	(12,958	)		$	133,364			$	135,747

The accompanying notes are an integral part of the financial statements.

 

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PUGET ENERGY, INC.

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME

(Dollars in Thousands)

(Unaudited)

 

		Three Months Ended September 30,								Nine Months Ended September 30,
		2015				2014				2015				2014
Net income (loss)		$	(7,928	)		$	(12,958	)		$	133,364			$	135,747
Other comprehensive income (loss):
Net unrealized gain (loss) from pension and postretirement plans, net of tax of $303, $(169), $1,303 and $(703), respectively			562				(314	)			2,418				(1,306	)
Reclassification of net unrealized (gain) loss on energy derivative instruments settled during the period, net of tax of $0, $0, $179 and $187, respectively			—				—				333				347
Reclassification of net unrealized (gain) loss on interest rate swaps during the period, net of tax of $0, $0, $0 and $50, respectively			—				—				—				94
Other comprehensive income (loss)			562				(314	)			2,751				(865	)
Comprehensive income (loss)		$	(7,366	)		$	(13,272	)		$	136,115			$	134,882

The accompanying notes are an integral part of the financial statements.

 

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PUGET ENERGY, INC.

CONSOLIDATED BALANCE SHEETS

(Dollars in Thousands)

ASSETS

 

		(Unaudited)
		September 30, 2015				December 31, 2014
Utility plant (at original cost, including construction work in progress of $353,388 and $239,690, respectively):
Electric plant		$	7,352,382			$	7,135,206
Natural gas plant			2,805,551				2,680,067
Common plant			481,184				472,926
Less: Accumulated depreciation and amortization			(1,804,201	)			(1,611,220	)
Net utility plant			8,834,916				8,676,979
Other property and investments:
Goodwill			1,656,513				1,656,513
Other property and investments			87,410				91,139
Total other property and investments			1,743,923				1,747,652
Current assets:
Cash and cash equivalents			20,200				37,527
Restricted cash			7,036				32,863
Accounts receivable, net of allowance for doubtful accounts of $11,488 and $7,472, respectively			245,344				306,923
Unbilled revenue			127,620				168,039
Purchased gas adjustment receivable			—				21,073
Materials and supplies, at average cost			84,489				83,189
Fuel and gas inventory, at average cost			68,360				69,433
Unrealized gain on derivative instruments			18,771				21,178
Taxes			31				301
Prepaid expense and other			39,306				20,905
Power contract acquisition adjustment gain			40,348				43,843
Deferred income taxes			162,336				161,445
Total current assets			813,841				966,719
Other long-term and regulatory assets:
Regulatory asset for deferred income taxes			71,499				95,432
Power cost adjustment mechanism			4,717				4,623
Regulatory assets related to power contracts			26,843				29,816
Other regulatory assets			893,869				866,835
Unrealized gain on derivative instruments			3,309				3,170
Power contract acquisition adjustment gain			300,325				347,547
Other			95,978				96,275
Total other long-term and regulatory assets			1,396,540				1,443,698
Total assets		$	12,789,220			$	12,835,048

The accompanying notes are an integral part of the financial statements.

 

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PUGET ENERGY, INC.

CONSOLIDATED BALANCE SHEETS

(Dollars in Thousands)

CAPITALIZATION AND LIABILITIES

 

		(Unaudited)
		September 30, 2015				December 31, 2014
Capitalization:
Common shareholder’s equity:
Common stock $0.01 par value, 1,000 shares authorized, 200 shares outstanding		$	—			$	—
Additional paid-in capital			3,308,957				3,308,957
Earnings reinvested in the business			212,188				271,414
Accumulated other comprehensive income (loss), net of tax			(34,292	)			(37,043	)
Total common shareholder’s equity			3,486,853				3,543,328
Long-term debt:
First mortgage bonds and senior notes			3,364,412				3,189,412
Pollution control bonds			161,860				161,860
Junior subordinated notes			250,000				250,000
Long-term debt			1,800,000				1,699,000
Debt discount and other			(212,555	)			(218,664	)
Total long-term debt			5,363,717				5,081,608
Total capitalization			8,850,570				8,624,936
Current liabilities:
Accounts payable			233,582				307,578
Short-term debt			79,500				85,000
Current maturities of long-term debt			—				162,000
Purchased gas adjustment liability			8,347				—
Accrued expenses:
Taxes			80,055				107,782
Salaries and wages			36,161				40,970
Interest			78,011				78,914
Unrealized loss on derivative instruments			133,061				142,195
Power contract acquisition adjustment loss			3,624				3,593
Other			57,509				62,464
Total current liabilities			709,850				990,496
Other long-term and regulatory liabilities:
Deferred income taxes			1,552,461				1,522,357
Unrealized loss on derivative instruments			55,602				62,913
Regulatory liabilities			637,195				633,471
Regulatory liabilities related to power contracts			340,673				391,389
Power contract acquisition adjustment loss			23,219				26,223
Other deferred credits			619,650				583,263
Total other long-term and regulatory liabilities			3,228,800				3,219,616
Commitments and contingencies (Note 8)
Total capitalization and liabilities		$	12,789,220			$	12,835,048

The accompanying notes are an integral part of the financial statements.

 

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PUGET ENERGY, INC.

CONSOLIDATED STATEMENTS OF CASH FLOWS

(Dollars in Thousands)

(Unaudited)

 

		Nine Months Ended September 30,
		2015				2014
Operating activities:
Net income (loss)		$	133,364			$	135,747
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
Depreciation and amortization			314,348				312,821
Conservation amortization			78,389				74,554
Deferred income taxes and tax credits, net			51,664				51,749
Net unrealized (gain) loss on derivative instruments			(7,789	)			4,194
Derivative contracts classified as financing activities due to merger			8,045				8,026
AFUDC—Equity			(6,490	)			(5,257	)
Funding of pension liability			(13,500	)			(9,000	)
Regulatory assets			(140,958	)			(115,710	)
Regulatory liabilities			26,070				(6,907	)
Other long-term assets			21,042				(5,287	)
Other long-term liabilities			(2,570	)			36,822
Change in certain current assets and liabilities:
Accounts receivable and unbilled revenue			101,998				274,463
Materials and supplies			(1,300	)			4,735
Fuel and gas inventory			255				(10,032	)
Taxes			270				297
Prepayments and other			(18,399	)			(14,433	)
Purchased gas adjustment			29,420				(38,331	)
Accounts payable			(65,736	)			(54,197	)
Taxes payable			(27,727	)			(27,737	)
Accrued expenses and other			(14,400	)			(11,350	)
Net cash provided by (used in) operating activities			465,996				605,167
Investing activities:
Construction expenditures—excluding equity AFUDC			(419,389	)			(343,619	)
Treasury grants received			—				107,876
Restricted cash			25,827				(47,080	)
Other			2,902				(18,439	)
Net cash provided by (used in) investing activities			(390,660	)			(301,262	)
Financing activities:
Change in short-term debt, net			(5,500	)			(142,864	)
Dividends paid			(192,590	)			(179,614	)
Long-term notes and bonds issued			825,000				299,000
Redemption of bonds and notes			(711,000	)			(299,000	)
Derivative contracts classified as financing activities due to merger			(8,045	)			(8,026	)
Issuance cost of bonds and other			(528	)			8,767
Net cash provided by (used in) financing activities			(92,663	)			(321,737	)
Net increase (decrease) in cash and cash equivalents			(17,327	)			(17,832	)
Cash and cash equivalents at beginning of period			37,527				44,302
Cash and cash equivalents at end of period		$	20,200			$	26,470
Supplemental cash flow information:
Cash payments for interest (net of capitalized interest)		$	252,251			$	263,921
Cash payments (refunds) for income taxes			—				—
Non-cash financing and investing activities:
Accounts payable for capital expenditures eliminated from cash flows		$	43,522			$	61,112

The accompanying notes are an integral part of the financial statements.

 

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COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(1) Summary of Consolidation Policy

Basis of Presentation

Puget Energy is an energy services holding company that owns PSE. PSE is a public utility incorporated in the state of Washington that furnishes electric and natural gas services in a territory covering approximately 6,000 square miles, primarily in the Puget Sound region. Puget Energy is an indirect wholly-owned subsidiary of Puget Holdings (Puget Holdings LLC).

The consolidated financial statements of Puget Energy reflect the accounts of Puget Energy and its subsidiary, PSE. PSE’s consolidated financial statements include the accounts of PSE and its subsidiary, Puget Western, Inc. Puget Energy and PSE are collectively referred to herein as “the Company.” The consolidated financial statements are presented after elimination of intercompany transactions. PSE’s consolidated financial statements continue to be accounted for on a historical basis and do not include any purchase accounting adjustments.

The consolidated financial statements contained in this Form 10-Q are unaudited. In the respective opinions of the management of Puget Energy and PSE, all adjustments necessary for a fair statement of the results for the interim periods have been reflected and were of a normal recurring nature. These consolidated financial statements should be read in conjunction with the audited financial statements (and the Combined Notes thereto) included in the combined Puget Energy and PSE Annual Report on Form 10-K for the year ended December 31, 2014.

The preparation of financial statements in conformity with U.S. 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 revenue and expenses during the reporting period. Actual results could differ from those estimates.

PSE collected Washington State excise taxes (which are a component of general retail customer rates) and municipal taxes totaling $47.6 million and $167.5 million for the three and nine months ended September 30, 2015, respectively, and $43.6 million and $172.1 million for the three and nine months ended September 30, 2014, respectively. The Company reports the collection of such taxes on a gross basis in operating revenue and as expense in taxes other than income taxes in the accompanying consolidated statements of income.

PSE’s electric and gas operations contain a revenue decoupling mechanism under which PSE’s actual energy delivery revenues related to electric transmission and distribution, gas operations and general administrative costs are compared with authorized revenues allowed under the mechanism. Any differences in revenue are deferred to a regulatory asset for under recovery or regulatory liability for over recovery under alternative revenue recognition. To record revenues under this program, the Company must be able to collect the revenue within 24 months based on alternative revenue recognition guidance. Decoupled rate increases are effective May 1 of each year subject to a 3.0% cap of total revenue for decoupled rate schedules. Any excess revenue above 3.0% will be included in the following year’s decoupled rate. The Company will be able to recognize revenue deferred below the 3.0% cap of total revenue for decoupled rate schedules. For revenue deferrals exceeding the annual 3.0% rate cap of total revenue for decoupled rate schedules, the Company will need to review the excess amount for its ability to be collected within 24 months. If the excess amount cannot be collected within 24 months, for GAAP purposes only, the Company will not record any decoupling revenue until it is within the 24 months of collection. Revenues associated with energy costs under the Power Cost Adjustment (PCA) mechanism and Purchased Gas Adjustment (PGA) mechanism are excluded from the decoupling mechanism.

 

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(2) New Accounting Pronouncements

Revenue Recognition

In May 2014, the Financial Accounting Standards Board (FASB) issued Accounting Standards Update (ASU) No. 2014-09, “Revenue from Contracts with Customers (Topic 606)”, which outlines a single comprehensive model for use in accounting for revenue arising from contracts with customers and supersedes most current revenue recognition guidance, including industry-specific guidance. The ASU is based on the principle that an entity should recognize revenue to depict the transfer of goods or services to customers in an amount that reflects the consideration to which the entity expects to be entitled in exchange for those goods or services. The ASU also requires additional disclosure about the nature, amount, timing and uncertainty of revenue and cash flows arising from customer contracts, including significant judgments and changes in judgments and assets recognized from costs incurred to fulfill a contract.

In August 2015, the FASB issued ASU 2015-14, “Revenue from Contracts with Customers (Topic 606): Deferral of the Effective Date,” deferring the effective date for ASU 2014-09 to fiscal years, and interim periods within those fiscal years, beginning after December 15, 2017. In addition to the FASB’s deferral decision, FASB provided reporting entities with an option to adopt ASU 2014-09 for the fiscal years, and interim periods within those fiscal years, beginning after December 15, 2016, the original effective date. The Company plans to adopt ASU 2014-09 according to the original effective date. Reporting entities also have the option of using either a full retrospective or a modified retrospective approach for the adoption of the new standard. The Company initiated a steering committee and project team to evaluate the impact of this standard, update any policies and procedures that may be affected and implement the new revenue recognition guidance. At this time, the Company cannot determine the impact this standard will have on its consolidated financial statements.

Consolidation—Variable Interest Entities

In February 2015, the FASB issued ASU 2015-02, “Consolidation (Topic 810): Amendments to the Consolidation Analysis.” ASU 2015-02 affects how a reporting entity determines if it has a variable interest in the legal entity being evaluated for consolidation. Specifically, this amendment eliminates three of the six criteria used for determining whether fees paid by a legal entity to a decision maker represent a variable interest entity. As a result, certain fees paid by legal entities to decision makers that required consolidation of the legal entities may no longer require consolidation under ASU 2015-02.

ASU 2015-02 is effective for fiscal years, and interim periods within those fiscal years, beginning after December 15, 2015. Early adoption is permitted, including adoption in an interim period. Currently, the Company does not have any fee arrangements described under this new amendment with any legal entities. As such, the Company does not expect this guidance to have a material impact on our results of operations or financial position.

Debt Issuance Costs

In April 2015, the FASB issued ASU 2015-03, “Interest-Imputation of Interest (Subtopic 835-30): Simplifying the Presentation of Debt Issuance Costs.” ASU 2015-03 requires debt issuance costs related to a recognized debt liability be presented in the balance sheet as a direct deduction from the carrying amount of the debt liability, consistent with the presentation of a debt discount. This new guidance affects only the presentation of debt issuance costs and not the recognition and measurement of debt issuance costs. ASU 2015-03 is to be applied on a retrospective basis, wherein the balance sheet of each individual period presented should be adjusted to reflect the period-specific effects of applying the new guidance.

In August 2015, the FASB issued ASU 2015-15, “Interest-Imputation of Interest (Subtopic 835-30): Presentation and Subsequent Measurement of Debt Issuance Costs Associated with Line-of-Credit Arrangement.” In accordance with the SEC Staff Announcement at the June 18, 2015 Emerging Issues Task

 

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Force (EITF) meeting about debt issuance costs, ASU 2015-15 amended the accounting guidance updated by ASU 2015-03 to allow reporting entities the option to defer and present debt issuance costs related to line-of-credit arrangements as an asset and subsequently amortize the deferred debt issuance costs ratably over the term of the line-of-credit arrangement.

ASU 2015-03 and ASU 2015-15 are effective for financial statements issued for fiscal years beginning after December 15, 2015, and interim periods within those fiscal years. Early adoption of the amendments is permitted for financial statements that have not been previously issued. The Company plans to adopt the amendments during the first quarter of fiscal year 2016. The amount of unamortized debt issuance costs as of September 30, 2015 and December 31, 2014 totaled $39.6 million and $35.7 million, respectively.

Internal-Use Software

In April 2015, the FASB issued ASU 2015-05, “Intangibles-Goodwill and Other-Internal-Use Software (Subtopic 350-40): Customer’s Accounting for Fees Paid in a Cloud Computing Arrangement.” ASU 2015-05 requires a customer in a cloud computing arrangement to follow internal-use software guidance if both of the following criteria are met: the customer has the contractual right to take possession of the software at any time during the cloud computing arrangement and can feasibly run the software on its own hardware. If the customer does not meet both criteria, the cloud computing arrangement is considered a service contract and separate accounting for a license would not be permitted.

ASU 2015-05 is effective for annual reporting periods, including interim periods within those annual reporting periods, beginning after December 15, 2015. Early adoption is permitted. The Company plans to adopt ASU 2015-05 during the first quarter of fiscal year 2016 and is in the process of evaluating the potential impacts, if any, of this new guidance on its financial statements.

Fair Value Measurement

In May 2015, the FASB issued ASU 2015-07, “Fair Value Measurement (Topic 820): Disclosures for Investments in Certain Entities that Calculate Net Asset Value per Share (or Its Equivalent),” which removes the requirement to categorize within the fair value hierarchy all investments for which their fair value is measured using the net asset value per share practical expedient. This ASU also removes the requirement to make certain disclosures for all investments that are eligible to be measured at fair value using the net asset value per share practical expedient. Instead, those disclosures will be limited to investments for which the Company has elected to measure the fair value using that practical expedient.

ASU 2015-07 is effective for annual reporting periods, and interim periods within those reporting periods, beginning after December 15, 2015 and requires reporting entities to apply this ASU retrospectively to all periods presented. Early adoption is permitted. The Company plans to adopt ASU 2015-07 during the first quarter of fiscal year 2016. At this time, the Company cannot determine the impact this standard will have on its consolidated financial statements.

Inventory

In July 2015, the FASB issued ASU 2015-11, “Inventory (Topic 330): Simplifying the Measurement of Inventory.” ASU 2015-11 requires inventory within scope of this Topic 330 to be measured at the lower of cost and net realizable value. This amendment does not apply to inventory that is measured using last-in, first-out (LIFO) or the retail inventory method. This amendment applies to all other inventory, including inventory measured using first-in, first-out (FIFO) or average cost.

The new accounting guidance is effective for annual reporting periods, and interim periods within those annual reporting periods, beginning after December 15, 2016 with early adoption permitted. At this time, the Company cannot determine the impact this standard will have on its consolidated financial statements. The Company plans to adopt ASU 2015-11 during the first quarter of fiscal year 2017.

 

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Retirement Benefits

In July 2015, the FASB issued ASU 2015-12, “Plan Accounting: Defined Benefit Pension Plans (Topic 960), Defined Contribution Pension Plans (Topic 962), and Health and Welfare Benefit Plans (Topic 965).” ASU 2015-12 is made up of three parts: Part I, Fully Benefit-Responsive Investment Contracts (Part I); Part II, Plan Investment Disclosures (Part II); and Part III, Measurement Date Practical Expedient (Part III).

Part I requires fully benefit-responsive contracts to be measured, presented and disclosed only at contract value. Part II requires both participant-directed and nonparticipant-directed investments of employee benefit plans be grouped only by general type, and removes the requirement to include the disclosure of (i) the investment strategy of an investment measured using the net asset value per share practical expedient and is part of a fund that files a U.S. Department of Labor Form 5500; and (ii) the net appreciation or depreciation for investments by general type. Part III provides entities that have a fiscal year-end that does not coincide with a month-end a practical expedient to permit plans to measure investments and investment-related accounts as of a month-end date that is closest to the plan’s fiscal year-end.

All three parts are effective for fiscal years beginning after December 15, 2015, and early adoption is permitted for each part. Parts I and II must be applied retrospectively for all financial statements presented. The amendments in Part III must be applied prospectively. The Company plans to adopt ASU 2015-12 during the first quarter of fiscal year 2016 and is in the process of evaluating the potential impacts, if any, of this new guidance on its financial statements.

Derivatives and Hedging

In August 2015, the FASB Issues ASU 2015-13, “Derivatives and Hedging (Topic 815): Application of the Normal Purchases and Normal Sales Scope Exception to Certain Electricity Contracts within Nodal Energy Markets.” ASU 2015-13 allows certain reporting entities that enter into derivative contracts for the purchase or sale of electricity on a forward basis and arrange for transmission through a nodal energy market, to designate those contracts as normal purchase or normal sale contracts, if the physical delivery criterion is met. This designation removes the Accounting Standards Codification (ASC) Topic 815, Derivatives and Hedging, requirement to measure those derivative contracts at fair value.

This amendment was effective upon issuance, and if elected, the guidance must be applied prospectively. The Company does not expect this guidance to have a material impact on our results of operations or financial position.

(3) Accounting for Derivative Instruments and Hedging Activities

PSE employs various energy portfolio optimization strategies, but is not in the business of assuming risk for the purpose of realizing speculative trading revenue. The nature of serving regulated electric customers with its 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 and PSE’s related hedging strategies are focused on reducing costs and risks where feasible, thus reducing volatility in costs in the portfolio. In order to manage its exposure to the variability in future cash flows for forecasted energy transactions, PSE utilizes a programmatic hedging strategy which extends out three years. 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 forward physical electric and natural gas purchase and sale agreements, fixed-for-floating swap contracts, and commodity call/put options. The forward physical electric agreements are both fixed and variable (at index), while the physical natural gas agreements are variable. To fix the price of wholesale electricity and natural gas, PSE may enter into fixed-for-floating swap (financial) contracts with various counterparties. PSE also utilizes natural gas call and put options as an additional hedging instrument to increase the hedging portfolio’s flexibility to react to commodity price fluctuations.

 

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The Company manages its interest rate risk through the issuance of mostly fixed-rate debt with varied maturities. The Company utilizes internal cash from operations, borrowings under its commercial paper program and its credit facilities to meet short-term funding needs. The Company may enter into swap instruments or other financial hedge instruments to manage the interest rate risk associated with these debts. As of September 30, 2015, Puget Energy had two interest rate swap contracts outstanding which extend to January 2017. As of the date of this report, these swap instruments are no longer hedging any variable interest rate debt. Management continues to monitor the economics of terminating the swaps, and unless the economics of terminating the swaps become more favorable, management intends to let them expire naturally in January 2017. PSE did not have any outstanding interest rate swap instruments.

The following table presents the volumes, fair values and locations of the Company’s derivative instruments recorded on the balance sheets:

 

Puget Energy and Puget Sound Energy
		September 30, 2015												December 31, 2014
(Dollars in Thousands)		Volumes				Assets1				Liabilities2				Volumes				Assets1				Liabilities2
Interest rate swap derivatives3		$	450 million			$	—			$	7,622			$	450 million			$	—			$	9,073
Electric portfolio derivatives			*				15,916				111,472				*				4,822				107,228
Natural gas derivatives (MMBtus)4			345.6 million				6,164				69,569				360.4 million				19,526				88,807
Total derivative contracts						$	22,080			$	188,663							$	24,348			$	205,108
Current						$	18,771			$	133,061							$	21,178			$	142,195
Long-term							3,309				55,602								3,170				62,913
Total derivative contracts						$	22,080			$	188,663							$	24,348			$	205,108

 

1	Balance sheet locations: Current and Long-term Unrealized gain on derivative instruments.

2	Balance sheet locations: Current and Long-term Unrealized loss on derivative instruments.

3	Interest rate swap contracts are only held at Puget Energy.

4

All fair value adjustments on derivatives relating to the natural gas business have been deferred in accordance with ASC 980, “Regulated Operations,” due to the PGA mechanism. The net derivative asset or liability and offsetting regulatory liability or asset are related to contracts used to economically hedge the cost of physical gas purchased to serve natural gas customers.

*	Electric portfolio derivatives consist of electric generation fuel of 175.1 million One Million British Thermal Units (MMBtu) and purchased electricity of 1.1 million Megawatt Hours (MWhs) at September 30, 2015, and 140.2 million MMBtus and 5.4 million MWhs at December 31, 2014.

For further details regarding the fair value of derivative instruments, see Note 4.

It is the Company’s policy to record all derivative transactions on a gross basis at the contract level, without offsetting assets or liabilities. The Company generally enters into transactions using the following master agreements: WSPP, Inc. (WSPP) agreements, which standardize physical power contracts; International Swaps and Derivatives Association (ISDA) agreements, which standardize financial gas and electric contracts; and North American Energy Standards Board (NAESB) agreements, which standardize physical gas contracts. The Company believes that such agreements reduce credit risk exposure because such agreements provide for the netting and offsetting of monthly payments as well as the right of set-off in the event of counterparty default. The set-off provision can be used as a final settlement of accounts which extinguishes the mutual debts owed between the parties in exchange for a new net amount.

 

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The following tables present the potential effect of netting arrangements, including rights of set-off associated with the Company’s derivative assets and liabilities:

 

Puget Energy and Puget Sound Energy
September 30, 2015
(Dollars in Thousands)		Gross Amount Recognized in the Statement of Financial Position1				Gross Amounts Offset in the Statement of Financial Position				Net of Amounts Presented in the Statement of Financial Position				Gross Amounts Not Offset in the Statement of Financial Position								Net Amount
														Commodity Contracts				Cash Collateral Received/Posted
Assets:
Energy derivative contracts		$	22,080			$	—			$	22,080			$	(18,416	)		$	—			$	3,664
Liabilities:
Energy derivative contracts			181,041				—				181,041				(18,416	)			—				162,625
Interest rate swaps2			7,622				—				7,622				—				—				7,622

 

Puget Energy and Puget Sound Energy
December 31, 2014
(Dollars in Thousands)		Gross Amount Recognized in the Statement of Financial Position1				Gross Amounts Offset in the Statement of Financial Position				Net of Amounts Presented in the Statement of Financial Position				Gross Amounts Not Offset in the Statement of Financial Position								Net Amount
														Commodity Contracts				Cash Collateral Received/Posted
Assets:
Energy derivative contracts		$	24,348			$	—			$	24,348			$	(23,066	)		$	—			$	1,282
Liabilities:
Energy derivative contracts			196,035				—				196,035				(23,066	)			(20	)			172,949
Interest rate swaps2			9,073				—				9,073				—				—				9,073

 

1	All derivative contract deals are executed under ISDA, NAESB and WSPP master netting agreements with right of set-off.

2	Interest rate swap contracts are only held at Puget Energy.

The following tables present the effect and locations of the Company’s derivatives not designated as hedging instruments, recorded on the statements of income:

 

Puget Energy				Three Months Ended September 30,								Nine Months Ended September 30,
(Dollars in Thousands)		Location		2015				2014				2015				2014
Interest rate contracts:		Non-hedged interest rate swap (expense) income		$	(1,156	)		$	(323	)		$	(4,571	)		$	(2,430	)
		Interest expense			—				1,241				560				398
Commodity contracts:
Electric derivatives		Unrealized gain (loss) on derivative instruments, net1			(5,588	)			(32,648	)			6,339				(7,714	)
		Electric generation fuel			(11,768	)			(420	)			(27,512	)			8,271
		Purchased electricity			(8,344	)			972				(34,489	)			2,687
Total gain (loss) recognized in income on derivatives				$	(26,856	)		$	(31,178	)		$	(59,673	)		$	1,212

 

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Puget Sound Energy				Three Months Ended September 30,								Nine Months Ended September 30,
(Dollars in Thousands)		Location		2015				2014				2015				2014
Commodity contracts:
Electric derivatives		Unrealized gain (loss) on derivative instruments, net1		$	(5,588	)		$	(32,648	)		$	5,795			$	(8,284	)
		Electric generation fuel			(11,768	)			(420	)			(27,512	)			8,271
		Purchased electricity			(8,344	)			972				(34,489	)			2,687
Total gain (loss) recognized in income on derivatives				$	(25,700	)		$	(32,096	)		$	(56,206	)		$	2,674

 

1

Differences between Puget Energy and PSE for the nine months ending September 30, 2015 and September 30, 2014 are due to certain derivative contracts recorded at fair value in 2009 and subsequently designated as Normal Purchase Normal Sale (NPNS) or cash flow hedges. These differences occurred through February 2015.

The unrealized gain or loss on derivative contracts is reported in the statement of cash flows under the operating activities section. However, due to purchase accounting requirements, all derivative contracts at Puget Energy were assessed to identify contracts that have a “more than an insignificant” fair value. If the fair value was greater than 10% of the notional value, the contract was deemed as having a financing element. For those contracts, the cash inflows (outflows) are presented in the financing activities section of the statement of cash flows. For the nine months ended September 30, 2015 and 2014, cash outflows related to financing activities of $8.0 million, for both periods, were reported on the Puget Energy statement of cash flows.

For derivative instruments previously designated as cash flow hedges (including both commodity contracts and interest rate swaps), the effective portion of the gain or loss on the derivative was recorded as a component of Other Comprehensive Income (OCI), and then reclassified into earnings in the same period(s) during which the hedged transaction affected earnings. As of March 31, 2015, all gains or losses on purchased electricity derivatives recorded in OCI have been reclassified into earnings. The Company does not attempt cash flow hedging for any new transactions and records all mark-to-market adjustments through earnings.

The following tables present the Company’s pre-tax gain (loss) of derivatives that were previously in a cash flow hedge relationship, and subsequently reclassified out of Accumulated Other Comprehensive Income (AOCI) into income:

 

Puget Energy				Three Months Ended September 30,								Nine Months Ended September 30,
(Dollars in Thousands)		Location		2015				2014				2015				2014
Interest rate contracts:		Interest expense		$	—			$	—			$	—			$	(144	)
Commodity contracts:
Electric derivatives		Purchased electricity			—				—				(512	)			(534	)
Total				$	—			$	—			$	(512	)		$	(678	)

 

Puget Sound Energy				Three Months Ended September 30,								Nine Months Ended September 30,
(Dollars in Thousands)		Location		2015				2014				2015				2014
Interest rate contracts:		Interest expense1		$	(122	)		$	(122	)		$	(366	)		$	(366	)
Commodity contracts:
Electric derivatives		Purchased electricity			—				—				(1,055	)			(1,104	)
Total				$	(122	)		$	(122	)		$	(1,421	)		$	(1,470	)

 

1	Within the next twelve months, $0.5 million of losses in AOCI will be reclassified into earnings.

 

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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 credit analysis, exposure measurement, exposure monitoring and exposure mitigation.

The Company monitors counterparties that have significant swings in credit default swap rates, have credit rating changes by external rating agencies, have changes in ownership or are experiencing financial distress. 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 exposure with one or more counterparties. If such counterparties fail to perform their obligations under one or more agreements, the Company could suffer a material financial loss. However, as of September 30, 2015, approximately 99.8% of the Company’s energy portfolio exposure, excluding NPNS transactions, is with counterparties that are rated at least investment grade by rating agencies and 0.2% are either rated below investment grade or not rated by rating agencies. The Company assesses credit risk internally for counterparties that are not rated by the major rating agencies.

The Company computes credit reserves at a master agreement level by counterparty. The Company considers external credit ratings and market factors, such as credit default swaps and bond spreads, in the 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 Standard & Poor’s 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 determined by weighting the fair value and contract tenors for all deals for each counterparty to derive 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. The Company calculates a non-performance risk on its derivative liabilities by using its estimated incremental borrowing rate over the risk-free rate. Credit reserves are netted against the unrealized gain (loss) positions. As of September 30, 2015, the Company was in a net liability position with many of its counterparties, so the default factors of counterparties did not have a significant impact on reserves for the period. The majority of the Company’s derivative contracts are with financial institutions and other utilities operating within the Western Electricity Coordinating Council. As of September 30, 2015, PSE has posted a $1.0 million letter of credit as a condition of transacting on a physical energy exchange and clearinghouse in Canada. PSE did not trigger any collateral requirements with any of its counterparties during the quarter ended September 30, 2015, nor were any of PSE’s counterparties required to post collateral resulting from credit rating downgrades.

The table below presents the fair value of the overall contractual contingent liability positions for the Company’s derivative activity at September 30, 2015:

 

Puget Energy and Puget Sound Energy (Dollars in Thousands) Contingent Feature
		Fair Value1 Liability				Posted Collateral				Contingent Collateral
Credit rating2		$	27,360			$	—			$	27,360
Requested credit for adequate assurance			66,785				—				—
Forward value of contract3			—				—				—
Total		$	94,145			$	—			$	27,360

 

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1	Represents the derivative fair value of contracts with contingent features for counterparties in net derivative liability positions. Excludes NPNS, accounts payable and accounts receivable.

2	Failure by PSE to maintain an investment grade credit rating from each of the major credit rating agencies provides counterparties a contractual right to demand collateral.

3	Collateral requirements may vary, based on changes in the forward value of underlying transactions relative to contractually defined collateral thresholds.

(4) Fair Value Measurements

ASC 820 established a fair value hierarchy that prioritizes the inputs used to measure fair value. The hierarchy categorizes the inputs into three levels with the highest priority given to unadjusted quoted prices in active markets for identical assets or liabilities (Level 1 measurement) and the lowest priority given to unobservable inputs (Level 3 measurement). The three levels of the fair value hierarchy are as follows:

Level 1—Quoted prices are available in active markets for identical assets or liabilities as of the reporting date. Level 1 primarily consists of financial instruments such as exchange-traded derivatives and listed equities. Equity securities that are also classified as cash equivalents are considered Level 1 if there are unadjusted quoted prices in active markets for identical assets or liabilities.

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 reporting date. Level 2 includes those financial instruments that are valued using models or other valuation methodologies. 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 have little or no observability as of the reporting date. These inputs may be used with internally developed methodologies that result in management’s best estimate of fair value.

Financial assets and liabilities measured at fair value are classified in their entirety in the appropriate fair value hierarchy based on the lowest level of input that is significant to the fair value measurement. The Company’s assessment of the significance of a particular input to the fair value measurement requires judgment, and may affect the valuation of fair value assets and liabilities and their placement within the fair value hierarchy. The Company primarily determines fair value measurements classified as Level 2 or Level 3 using a combination of the income and market valuation approaches. The process of determining the fair values is the responsibility of the derivative accounting department which reports to the Controller and Principal Accounting Officer. Inputs used to estimate the fair value of forwards, swaps and options include market-price curves, contract terms and prices, credit-risk adjustments, and discount factors. Additionally, for options, the Black-Scholes option valuation model and implied market volatility curves are used. Inputs used to estimate fair value in industry-standard models are categorized as Level 2 inputs as substantially all assumptions and inputs are observable in active markets throughout the full term of the instruments. On a daily basis, the Company obtains quoted forward prices for the electric and natural gas markets from an independent external pricing service. For interest rate swaps, the Company obtains monthly market values from an independent external pricing service using London Interbank Offered Rate (LIBOR) forward rates, which is a significant input. Some of the inputs of the interest rate swap valuations, which are less significant, include the credit standing of the counterparties, assumptions for time value and the impact of the Company’s nonperformance risk of its liabilities. The Company classifies cash and cash equivalents, and restricted cash as Level 1 financial instruments due to cash being at stated value, and cash equivalents at quoted market prices.

The Company considers its electric, natural gas and interest rate swap contracts as Level 2 derivative instruments as such contracts are commonly traded as over-the-counter forwards with indirectly observable price quotes. However, certain energy derivative instruments with maturity dates falling outside the range of observable price quotes are classified as Level 3 in the fair value hierarchy. Management’s assessment is based

 

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on the trading activity in real-time and forward electric and natural gas markets. Each quarter, the Company confirms the validity of pricing-service quoted prices used to value Level 2 commodity contracts with the actual prices of commodity contracts entered into during the most recent quarter.

Assets and Liabilities with Estimated Fair Value

The following table presents the carrying value for cash, cash equivalents, restricted cash, notes receivable and short-term debt by fair value hierarchy level. The carrying values below are representative of fair values due to the short-term nature of these financial instruments.

 

Puget Energy		Carrying / Fair Value At September 30, 2015												Carrying / Fair Value At December 31, 2014
(Dollars in Thousands)		Level 1				Level 2				Total				Level 1				Level 2				Total
Assets:
Cash and cash equivalents		$	20,200			$	—			$	20,200			$	37,527			$	—			$	37,527
Restricted cash			7,036				—				7,036				32,863				—				32,863
Notes receivable and other investments			—				50,294				50,294				—				53,503				53,503
Total assets		$	27,236			$	50,294			$	77,530			$	70,390			$	53,503			$	123,893
Liabilities:
Short-term debt		$	79,500			$	—			$	79,500			$	85,000			$	—			$	85,000
Total liabilities		$	79,500			$	—			$	79,500			$	85,000			$	—			$	85,000

 

Puget Sound Energy		Carrying / Fair Value At September 30, 2015												Carrying / Fair Value At December 31, 2014
(Dollars in Thousands)		Level 1				Level 2				Total				Level 1				Level 2				Total
Assets:
Cash and cash equivalents		$	19,419			$	—			$	19,419			$	37,466			$	—			$	37,466
Restricted cash			7,036				—				7,036				32,863				—				32,863
Notes receivable and other investments			—				50,294				50,294				—				53,503				53,503
Total assets		$	26,455			$	50,294			$	76,749			$	70,329			$	53,503			$	123,832
Liabilities:
Short-term debt		$	79,500			$	—			$	79,500			$	85,000			$	—			$	85,000
Short-term debt owed to parent			—				—				—				—				28,933				28,933
Total liabilities		$	79,500			$	—			$	79,500			$	85,000			$	28,933			$	113,933

 

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The fair value of the junior subordinated and long-term notes was estimated using the discounted cash flow method with the U.S. Treasury yields and the Company’s credit spreads as inputs, interpolating to the maturity date of each issue. Carrying values and estimated fair values were as follows:

 

Puget Energy		September 30, 2015												December 31, 2014
(Dollars in Thousands)		Level				Carrying Value				Fair Value				Carrying Value				Fair Value
Liabilities:
Junior subordinated notes			2			$	250,000			$	269,915			$	250,000			$	276,235
Long-term debt (fixed-rate), net of discount			2				5,113,717				6,364,901				4,694,608				6,083,554
Long-term debt (variable-rate)			2				—				—				299,000				299,000
Total liabilities						$	5,363,717			$	6,634,816			$	5,243,608			$	6,658,789
Puget Sound Energy		September 30, 2015												December 31, 2014
(Dollars in Thousands)		Level				Carrying Value				Fair Value				Carrying Value				Fair Value
Liabilities:
Junior subordinated notes			2			$	250,000			$	269,915			$	250,000			$	276,235
Long-term debt (fixed-rate), net of discount			2				3,524,369				4,358,964				3,513,259				4,437,473
Total liabilities						$	3,774,369			$	4,628,879			$	3,763,259			$	4,713,708

Assets and Liabilities Measured at Fair Value on a Recurring Basis

The following tables present the Company’s financial assets and liabilities by level, within the fair value hierarchy, that were accounted for at fair value on a recurring basis:

 

Puget Energy		Fair Value At September 30, 2015												Fair Value At December 31, 2014
(Dollars in Thousands)		Level 2				Level 3				Total				Level 2				Level 3				Total
Liabilities:
Interest rate derivative instruments		$	7,622			$	—			$	7,622			$	9,073			$	—			$	9,073
Total liabilities		$	7,622			$	—			$	7,622			$	9,073			$	—			$	9,073

 

Puget Energy and Puget Sound Energy		Fair Value At September 30, 2015												Fair Value At December 31, 2014
(Dollars in Thousands)		Level 2				Level 3				Total				Level 2				Level 3				Total
Assets:
Electric derivative instruments		$	9,369			$	6,547			$	15,916			$	1,654			$	3,168			$	4,822
Natural gas derivative instruments			3,535				2,629				6,164				18,064				1,462				19,526
Total assets		$	12,904			$	9,176			$	22,080			$	19,718			$	4,630			$	24,348
Liabilities:
Electric derivative instruments		$	92,483			$	18,989			$	111,472			$	91,998			$	15,230			$	107,228
Natural gas derivative instruments			66,560				3,009				69,569				85,305				3,502				88,807
Total liabilities		$	159,043			$	21,998			$	181,041			$	177,303			$	18,732			$	196,035

 

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The following table presents the Company’s reconciliation of the changes in the fair value of Level 3 derivatives in the fair value hierarchy:

 

Puget Energy and Puget Sound Energy		Three Months Ended September 30,
(Dollars in Thousands)		2015												2014
Level 3 Roll-Forward Net Asset/(Liability)		Electric				Natural Gas				Total				Electric				Natural Gas				Total
Balance at beginning of period		$	(15,370	)		$	823			$	(14,547	)		$	(4,693	)		$	(273	)		$	(4,966	)
Changes during period:
Realized and unrealized energy derivatives:
Included in earnings1			(1,403	)			—				(1,403	)			(3,116	)			—				(3,116	)
Included in regulatory assets / liabilities			—				1,295				1,295				—				(725	)			(725	)
Settlements3			1,017				(2,122	)			(1,105	)			(965	)			(680	)			(1,645	)
Transferred into Level 3			—				—				—				2,055				—				2,055
Transferred out of Level 3			3,314				(376	)			2,938				(6,488	)			(60	)			(6,548	)
Balance at end of period		$	(12,442	)		$	(380	)		$	(12,822	)		$	(13,207	)		$	(1,738	)		$	(14,945	)

 

Puget Energy and Puget Sound Energy		Nine Months Ended September 30,
(Dollars in Thousands)		2015												2014
Level 3 Roll-Forward Net Asset/(Liability)		Electric				Natural Gas				Total				Electric				Natural Gas				Total
Balance at beginning of period		$	(12,061	)		$	(2,039	)		$	(14,100	)		$	(15,421	)		$	(361	)		$	(15,782	)
Changes during period:
Realized and unrealized energy derivatives:
Included in earnings2			(10,505	)			—				(10,505	)			1,939				—				1,939
Included in regulatory assets / liabilities			—				4,233				4,233				—				1,654				1,654
Settlements3			1,182				(2,420	)			(1,238	)			1,114				(1,256	)			(142	)
Transferred into Level 3			(787	)			—				(787	)			5,155				(585	)			4,570
Transferred out of Level 3			9,729				(154	)			9,575				(5,994	)			(1,190	)			(7,184	)
Balance at end of period		$	(12,442	)		$	(380	)		$	(12,822	)		$	(13,207	)		$	(1,738	)		$	(14,945	)

 

1

Income Statement locations: Unrealized (gain) loss on derivative instruments, net. Includes unrealized gains (losses) on derivatives still held in position as of the reporting date for electric derivatives of $(1.5) million and $(3.3) million for the three months ended September 30, 2015 and 2014, respectively.

2

Income Statement locations: Unrealized (gain) loss on derivative instruments, net. Includes unrealized gains (losses) on derivatives still held in position as of the reporting date for electric derivatives of $(10.4) million and $(3.3) million for the nine months ended September 30, 2015 and 2014, respectively.

3	The Company had no purchases, sales or issuances during the reported periods.

Realized gains and losses on energy derivatives for Level 3 recurring items are included in energy costs in the Company’s consolidated statements of income under purchased electricity, electric generation fuel or purchased natural gas when settled. Unrealized gains and losses on energy derivatives for Level 3 recurring items are included in net unrealized (gain) loss on derivative instruments in the Company’s consolidated statements of income.

In order to determine which assets and liabilities are classified as Level 3, the Company receives market data from its independent external pricing service defining the tenor of observable market quotes. To the extent any of the Company’s commodity contracts extend beyond what is considered observable as defined by its independent pricing service, the contracts are classified as Level 3. The actual tenor of what the independent pricing service defines as observable is subject to change depending on market conditions. Therefore, as the

 

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market changes, the same contract may be designated Level 3 one month and Level 2 the next, and vice versa. The changes of fair value classification into or out of Level 3 are recognized each month, and reported in the Level 3 Roll-Forward table above. The Company did not have any transfers between Level 2 and Level 1 during the reported periods. The Company does periodically transact at locations, or market price points, that are illiquid or for which no prices are available from the independent pricing service. In such circumstances, the Company uses a more liquid price point and performs a 15-month regression against the illiquid locations to serve as a proxy for market prices. Such transactions are classified as Level 3. The Company does not use internally developed models to make adjustments to significant unobservable pricing inputs.

The only significant unobservable input into the fair value measurement of the Company’s Level 3 assets and liabilities is the forward price for electric and natural gas contracts. The following table presents the forward price ranges for the Company’s Level 3 commodity contracts as of September 30, 2015:

 

Fair Value

Valuation Technique

Unobservable Input

Range

Weighted Average

(Dollars in Thousands)

Assets1

Liabilities1

Low

High

Electric

$

6,547

$

18,989

Discounted cash flow

Power Prices

$13.39 per MWh

$30.06 per MWh

$24.05 per MWh

Natural gas

$

2,629

$

3,009

Discounted cash flow

Natural Gas Prices

$1.56 per MMBtu

$3.13 per MMBtu

$2.40 per MMBtu

 

1	The valuation techniques, unobservable inputs and ranges are the same for asset and liability positions.

The following table presents the forward price ranges for the Company’s Level 3 commodity contracts as of December 31, 2014:

 

Fair Value

Valuation Technique

Unobservable Input

Range

Weighted Average

(Dollars in Thousands)

Assets1

Liabilities1

Low

High

Electric

$

3,168

$

15,230

Discounted cash flow

Power Prices

$21.79 per MWh

$35.46 per MWh

$32.89 per MWh

Natural gas

$

1,462

$

3,502

Discounted cash flow

Natural Gas Prices

$3.11 per MMBtu

$3.83 per MMBtu

$3.28 per MMBtu

 

1	The valuation techniques, unobservable inputs and ranges are the same for asset and liability positions.

The significant unobservable inputs listed above would have a direct impact on the fair values of the above instruments if they were adjusted. Consequently, significant increases or decreases in the forward prices of electricity or natural gas in isolation would result in a significantly higher or lower fair value for Level 3 assets and liabilities. Generally, interrelationships exist between market prices of natural gas and power. As such, an increase in natural gas pricing would potentially have a similar impact on forward power markets. At September 30, 2015 and December 31, 2014, a hypothetical 10% increase or decrease in market prices of natural gas and electricity would change the fair value of the Company’s derivative portfolio, classified as Level 3 within the fair value hierarchy, by $0.3 million and $3.9 million, respectively.

Long-Lived Assets Measured at Fair Value on a Nonrecurring Basis

Puget Energy records fair value of its intangible assets in accordance with ASC 360, “Property, Plant, and Equipment,” (ASC 360). 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 non-performance 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 is amortized as the contracts settle.

 

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ASC 360 requires long-lived assets to be tested for impairment on an annual basis, and upon the occurrence of any events or circumstances that would be more likely than not to reduce the fair value of the long-lived assets below their carrying value. One such triggering event is a significant decrease in the forward market prices of power.

At September 30, 2015, Puget Energy completed a valuation and impairment test of its purchased power contracts classified as intangible assets. The valuation indicated an impairment to the Wells hydro contract. As of September 30, 2015, the carrying value for this contract was $42.4 million and its fair value on a discounted basis was $35.7 million, thereby requiring a write-down of $6.7 million to this intangible asset with a corresponding reduction in the regulatory liability. The forward market prices of power for the duration of the Wells hydro contract decreased on average 11% from March 31, 2015 to September 30, 2015, which caused the impairments.

Below are significant unobservable inputs used in valuing the impaired long-term purchased power contract on September 30, 2015:

 

Valuation Technique		Unobservable Input		Low		High		Average
Discounted cash flow		Power prices		$18.38 per MWh		$27.92 per MWh		$24.88 per MWh
Discounted cash flow		Power contract costs (in thousands)		$4,100 per qtr.		$4,659 per qtr.		$4,388 per qtr.

(5) Retirement Benefits

PSE has a defined benefit pension plan (Qualified Pension Benefits) covering the largest portion of PSE employees. Pension benefits earned are a function of age, salary, years of service and, in the case of employees in the cash balance formula plan, the applicable annual interest crediting rates. Starting with January 1, 2014 all newly hired non-represented employees, United Association of Journeymen and Apprentices of the Plumbing and Pipe Fitting Industry employees, and International Brotherhood of Electrical Workers Local Union 77 hired on or after December 12, 2014 who elect to accumulate the Company contribution in the cash balance formula portion of the pension plan, will receive annual pay credits of 4% each year. They will also receive interest credits like other participants in the cash balance pension formula of the pension plan, which are at least 1% per quarter. When an employee with a vested cash balance formula benefit leaves PSE, he or she will have annuity and lump sum options for distribution. Those who select the lump sum option will receive their current cash balance amount. PSE also maintains a non-qualified Supplemental Executive Retirement Plan (SERP) for its key senior management employees.

In addition to providing pension benefits, PSE provides legacy group health care and life insurance benefits (Other Benefits) for certain retired employees. These benefits are provided principally through an insurance company. The insurance premiums, paid primarily by retirees, are based on the benefits provided during the prior year.

Puget Energy records purchase accounting adjustments associated with the re-measurement of the retirement plans.

 

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The following tables summarize the Company’s net periodic benefit cost for the three and nine months ended September 30, 2015 and 2014:

 

Puget Energy		Qualified Pension Benefits								SERP Pension Benefits								Other Benefits
		Three Months Ended September 30,
(Dollars in Thousands)		2015				2014				2015				2014				2015				2014
Components of net periodic benefit cost:
Service cost		$	5,322			$	4,359			$	277			$	261			$	28			$	28
Interest cost			7,022				7,010				570				577				156				171
Expected return on plan assets			(11,260	)			(10,616	)			—				—				(133	)			(134	)
Amortization of prior service cost			(495	)			(495	)			11				12				—				—
Amortization of net loss (gain)			972				—				410				228				(33	)			(228	)
Net periodic benefit cost		$	1,561			$	258			$	1,268			$	1,078			$	18			$	(163	)

 

Puget Energy		Qualified Pension Benefits								SERP Pension Benefits								Other Benefits
		Nine Months Ended September 30,
(Dollars in Thousands)		2015				2014				2015				2014				2015				2014
Components of net periodic benefit cost:
Service cost		$	15,966			$	13,077			$	831			$	782			$	84			$	84
Interest cost			21,066				21,030				1,710				1,732				467				513
Expected return on plan assets			(33,779	)			(31,848	)			—				—				(399	)			(401	)
Amortization of prior service cost			(1,485	)			(1,485	)			33				33				—				—
Amortization of net loss (gain)			2,915				—				1,230				684				(99	)			(296	)
Net periodic benefit cost		$	4,683			$	774			$	3,804			$	3,231			$	53			$	(100	)

 

Puget Sound Energy		Qualified Pension Benefits								SERP Pension Benefits								Other Benefits
		Three Months Ended September 30,
(Dollars in Thousands)		2015				2014				2015				2014				2015				2014
Components of net periodic benefit cost:
Service cost		$	5,322			$	4,359			$	277			$	261			$	28			$	28
Interest cost			7,022				7,010				570				577				156				171
Expected return on plan assets			(11,366	)			(10,813	)			—				—				(133	)			(134	)
Amortization of prior service cost			(393	)			(393	)			11				11				—				1
Amortization of net loss (gain)			5,139				3,298				530				365				(101	)			(175	)
Net periodic benefit cost		$	5,724			$	3,461			$	1,388			$	1,214			$	(50	)		$	(109	)

 

Puget Sound Energy		Qualified Pension Benefits								SERP Pension Benefits								Other Benefits
		Nine Months Ended September 30,
(Dollars in Thousands)		2015				2014				2015				2014				2015				2014
Components of net periodic benefit cost:
Service cost		$	15,966			$	13,077			$	831			$	782			$	84			$	84
Interest cost			21,066				21,030				1,710				1,732				467				513
Expected return on plan assets			(34,097	)			(32,439	)			—				—				(399	)			(401	)
Amortization of prior service cost			(1,179	)			(1,179	)			33				33				2				3
Amortization of net loss (gain)			15,416				9,895				1,590				1,095				(304	)			(527	)
Net periodic benefit cost		$	17,172			$	10,384			$	4,164			$	3,642			$	(150	)		$	(328	)

 

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The following table summarizes the Company’s change in benefit obligation for the periods ended September 30, 2015 and December 31, 2014:

 

Puget Energy and Puget Sound Energy		Qualified Pension Benefits								SERP Pension Benefits								Other Benefits
(Dollars in Thousands)		Nine Months Ended September 30, 2015				Year Ended December 31, 2014				Nine Months Ended September 30, 2015				Year Ended December 31, 2014				Nine Months Ended September 30, 2015				Year Ended December 31, 2014
Change in benefit obligation:
Benefit obligation at beginning of period		$	690,194			$	573,317			$	55,855			$	47,279			$	15,688			$	14,939
Service cost			15,966				17,437				831				1,042				84				112
Interest cost			21,066				28,039				1,710				2,310				467				684
Actuarial loss (gain)			(588	)			104,618				—				7,162				(540	)			1,108
Benefits paid			(41,804	)			(33,217	)			(3,026	)			(1,938	)			(1,045	)			(1,424	)
Medicare part D subsidy received			—				—				—				—				221				269
Benefit obligation at end of period		$	684,834			$	690,194			$	55,370			$	55,855			$	14,875			$	15,688

The aggregate expected contributions by the Company to fund the qualified pension plan, SERP and the other postretirement plans for the year ending December 31, 2015 are expected to be at least $18.0 million, $4.4 million and $0.4 million, respectively. During the three months ended September 30, 2015, the Company contributed $4.5 million, $0.5 million, and $0.1 million to fund the qualified pension plan, SERP and other postretirement plan, respectively. During the nine months ended September 30, 2015, the Company contributed $13.5 million, $3.0 million, and $0.5 million to fund the qualified pension plan, SERP and other postretirement plan, respectively.

(6) Regulation and Rates

On June 25, 2013, the Washington Commission approved PSE’s electric and natural gas decoupling mechanism and expedited rate filing (ERF) tariff filings, effective July 1, 2013. The allowed decoupling revenue per customer for the recovery of delivery system costs will subsequently increase by 3.0% for the electric customers and 2.2% for the gas customers on January 1 of each year, until the conclusion of PSE’s next general rate case (GRC). Rate increases are subject to a cap of 3.0% of total revenue for customers.

The ERF filings also provided for the collection of property taxes through a property tax tracker mechanism. The property tax rate tracker will initially produce no incremental revenue, but is intended to reduce regulatory lag associated with the recovery of future increases in property tax expenses.

On July 24, 2013, the Public Counsel Division of the Washington State Attorney General’s Office (Public Counsel) and the Industrial Customers of Northwest Utilities each filed a petition in Thurston County Superior Court (the Court) seeking judicial reviews of various aspects of the Washington Commission’s ERF and decoupling mechanism final order. In its order, the Washington Commission approved a weighted cost of capital of 7.77% and a capital structure that included 48.0% common equity with a return on equity of 9.8%. Following an appeal and remand, the Washington Commission issued a final order on remand on June 29, 2015, in which it found that 9.8% is a reasonable return on equity for PSE for the term of the rate plan, taking decoupling and other relevant factors into account.

On April 24, 2014, the Washington Commission approved PSE’s request to change rates under its electric and natural gas decoupling mechanism, effective May 1, 2014. The rate change incorporated the effects of an

 

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increase to the allowed delivery revenue per customer as well as true-ups to the rate from the prior year. This represents a rate increase for electric customers of $10.6 million, or 0.5% annually, and a rate decrease for natural gas customers of $1.0 million, or 0.1% annually.

On April 24, 2014, the Washington Commission approved PSE’s request to change rates under its electric and natural gas property tax tracker mechanism, effective May 1, 2014. The rate change incorporated the effects of an increase in the amount of property taxes paid as well as true-ups to the rate from the prior year. This represents a rate increase for electric customers of $11.0 million, or 0.5% annually, and a rate increase for natural gas customers of $5.6 million, or 0.6% annually.

On April 24, 2014, the Washington Commission also approved PSE’s request to change rates under its electric and natural gas conservation riders, effective May 1, 2014. The rate change incorporated the effects of changes in the annual conservation budgets as well as true-ups to the rate from the prior year. The rate change represents a rate increase for electric customers of $12.2 million, or 0.6% annually, and a rate increase for natural gas customers of $0.3 million.

On October 30, 2014, the Washington Commission approved the PGA natural gas tariff which proposed to reflect changes in wholesale gas and pipeline transportation costs and changes in deferral amortization rates. The impact of PGA rates is an annual revenue increase of $23.3 million, or 2.5%, with no impact on net operating income.

On November 3, 2014, the Washington Commission issued an order approving the settlement of the power cost only rate case (PCORC) which was filed on May 23, 2014. The original filing proposed a decrease of $9.6 million (or an average of approximately 0.5%) in the Company’s overall power supply costs. PSE filed joint testimony supporting a settlement stipulation. Customer rates decreased by approximately $19.4 million, or 0.9% annually, as a result of the settlement, effective December 1, 2014.

On March 26, 2015, PSE filed a request with the Washington Commission to change rates under its electric and natural gas property tax tracker mechanism, effective May 1, 2015. PSE filed a substitute filing with the Washington Commission on April 15, 2015 for the electric property tax tracker mechanism. The proposed rate change incorporates the effects of an increase to property taxes paid, as well as true-ups to the rate from the prior year. This represents a rate increase for electric customers of $6.5 million, or 0.3% annually. PSE made a subsequent substitute natural gas filing with the Washington Commission on May 1, 2015, which changed the rate effective date to June 1, 2015, and represented a rate decrease for natural gas customers of $2.3 million, or 0.2% annually.

On August 7, 2015 the Washington Commission issued an order approving the settlement proposing changes to the PCA mechanism. The settlement agreement will not take effect until January 1, 2017. Key components of the settlement will include the following changes to the PCA mechanism:

 

		Company’s Share								Customers’ Share
Annual Power Cost Variability		Over				Under				Over				Under
+/- $17 million			100	%			100	%			—	%			—	%
+/- $17 million—$40 million			35				50				65				50
+/- $40+ million			10				10				90				90

 

•

Reducing the cumulative deferral trigger for surcharge or refund from $30.0 million to $20.0 million;

 

•

Removing fixed production costs from the PCA mechanism and placing them in the decoupling mechanism if the decoupling mechanism continues as part of the next GRC;

 

•

Suspending the requirement that a GRC must be filed within three months after rates are approved in a PCORC, and agreeing, for a five-year period, that PSE will not file a GRC or PCORC within six months of the date that rates go into effect for a PCORC filing; and

 

•

Establishing a five-year moratorium on changes to the PCA/PCORC.

 

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On April 22, 2015, the Washington Commission approved PSE’s request to change rates under its electric and natural gas decoupling mechanism, effective May 1, 2015. As part of this filing, PSE also requested to change the methodology of how decoupling deferrals are calculated going forward and adjust deferrals calculated in 2014. The change was done to ensure that the amortization of prior years’ accumulated decoupling deferrals were not included in the calculation of the current year decoupling deferrals. The effect of the methodology change was a reduction of approximately $12.0 million previously recognized revenue from May through December of 2014. The overall changes represent a rate increase for electric customers of $53.8 million, or 2.6% annually, and a rate increase for natural gas customers of $22.0 million, or 2.1% annually, effective May 1, 2015. In addition, PSE exceeded the earnings test threshold for its natural gas business in 2014. As a result, PSE recorded a reduction in natural gas decoupling deferral and revenue of $1.3 million. This was reflected as a reduction to the natural gas rate increases noted above. As noted earlier, the Company is also limited to a 3.0% annual decoupling related cap on increases in total revenue. This limitation was triggered for certain rate classes. The resulting amount of deferral that was not included in the 2015 rate increase is $1.9 million for electric revenue and $8.2 million for natural gas revenue that was accrued through December 31, 2014. These amounts may be included in customer rates beginning in May 2016, subject to subsequent application of the earnings test and the 3.0% cap on decoupling related rate increases.

On September 18, 2015, PSE filed the PGA natural gas tariff which proposed to reflect changes in wholesale gas and pipeline transportation costs and changes in deferral amortization rates. The impact of PGA rates is an annual revenue decrease of $185.9 million, or 17.4%, with no impact on net operating income.

(7) Asset Retirement Obligation

The Company has recorded liabilities for steam generation sites, combustion turbine generation sites, combined cycle generation sites, wind generation sites, distribution and transmission poles, gas mains, and leased facilities where disposal is governed by ASC 410 “Asset Retirement and Environmental Obligations (ARO)”.

On April 17, 2015, the U.S. Environmental Protection Agency (EPA) published a final rule, effective October 19, 2015, that regulates Coal Combustion Residuals (CCR) under the Resource Conservation and Recovery Act, Subtitle D. The CCR rule addresses the risks from coal ash disposal, such as leaking of contaminants into ground water, blowing of contaminants into the air as dust, and the catastrophic failure of coal ash surface impoundments by establishing technical requirements for CCR landfills and surface impoundments. The rule also sets out recordkeeping and reporting requirements including requirements to post specific information to a publicly-accessible website.

The CCR rule requires significant changes to the Company’s Colstrip operations and those changes were reviewed by the Company and the plant operator in the second quarter of 2015. PSE had previously recognized a legal obligation under the EPA rules to dispose of coal ash material at Colstrip, in 2003. Due to the CCR rule, additional disposal costs were added to the ARO.

The actual ARO costs related to the CCR rule requirements may vary substantially from the estimates used to record the increased obligation due to uncertainty about the compliance strategies that will be used and the preliminary nature of available data used to estimate costs. We will continue to gather additional data and coordinate with the plant operator to make decisions about compliance strategies and the timing of closure activities. As additional information becomes available, the Company will update the ARO obligation for these changes, which could be material.

 

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The following table describes the changes to the Company’s ARO for the nine months ended September 30, 2015:

 

Puget Sound Energy
Changes in ARO (Dollars in Thousands)
Balance at December 31, 2014		$	48,909
New asset retirement obligation recognized in the period			34,534
Liability adjustments			(3,696	)
Revisions in estimated cash flows			450
Accretion expense			1,220
Balance at September 30, 2015		$	81,417

(8) Contingencies

Colstrip

PSE has a 50% ownership interest in Colstrip Units 1 and 2, and a 25% interest in Colstrip Units 3 and 4. On March 6, 2013, the Sierra Club and the Montana Environmental Information Center filed a Clean Air Act citizen suit against all Colstrip owners in the U.S. District Court, District of Montana. Based on a second amended complaint filed in August 2014, plaintiffs’ lawsuit currently alleges violations of permitting requirements under the New Source Review program of the Clean Air Act and the Montana State Implementation Plan arising from seven projects undertaken at Colstrip during 2001-2012. Plaintiffs have since indicated that they do not intend to pursue three of the seven projects, leaving a total of four projects remaining. The lawsuit claims that, for each project, the Colstrip plant should have obtained a permit and installed pollution control equipment at Colstrip. The Plaintiffs’ complaint also seeks civil penalties and other appropriate relief. The case has been bifurcated into separate liability and remedy trials. The liability trial is currently set for March 2016, and a date for the remedy trial has yet to be determined. PSE is litigating the allegations set forth in the complaint, and as such, it is not reasonably possible to estimate the outcome of this matter.

Other Proceedings

The Company is also involved in litigation relating to claims arising out of its operations in the normal course of business. The Company has recorded reserves of $0.4 million and $1.7 million relating to these claims as of September 30, 2015 and December 31, 2014, respectively.

(9) Accumulated Other Comprehensive Income (Loss)

The following tables present the changes in the Company’s AOCI (loss) by component for the three and nine months ended September 30, 2015:

 

Puget Energy Changes in AOCI, net of tax (Dollars in Thousands)		Net unrealized gain (loss) and prior service cost on pension plans				Net unrealized gain (loss) on energy derivative instruments				Total
Balance at June 30, 2015		$	(34,854	)		$	—			$	(34,854	)
Other comprehensive income (loss) before reclassifications			—				—				—
Amounts reclassified from accumulated other comprehensive income (loss), net of tax			562				—				562
Net current-period other comprehensive income (loss)			562				—				562
Balance at September 30, 2015		$	(34,292	)		$	—			$	(34,292	)

 

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Puget Energy Changes in AOCI, net of tax (Dollars in Thousands)		Net unrealized gain (loss) and prior service cost on pension plans				Net unrealized gain (loss) on energy derivative instruments				Total
Balance at December 31, 2014		$	(36,710	)		$	(333	)		$	(37,043	)
Other comprehensive income (loss) before reclassifications			696				—				696
Amounts reclassified from accumulated other comprehensive income (loss), net of tax			1,722				333				2,055
Net current-period other comprehensive income (loss)			2,418				333				2,751
Balance at September 30, 2015		$	(34,292	)		$	—			$	(34,292	)

 

Puget Sound Energy Changes in AOCI, net of tax (Dollars in Thousands)		Net unrealized gain (loss) and prior service cost on pension plans				Net unrealized gain (loss) on energy derivative instruments				Net unrealized gain (loss) on treasury interest rate swaps				Total
Balance at June 30, 2015		$	(156,806	)		$	—			$	(5,832	)		$	(162,638	)
Other comprehensive income (loss) before reclassifications			—				—				—				—
Amounts reclassified from accumulated other comprehensive income (loss), net of tax			3,370				—				79				3,449
Net current-period other comprehensive income (loss)			3,370				—				79				3,449
Balance at September 30, 2015		$	(153,436	)		$	—			$	(5,753	)		$	(159,189	)

 

Puget Sound Energy Changes in AOCI, net of tax (Dollars in Thousands)		Net unrealized gain (loss) and prior service cost on pension plans				Net unrealized gain (loss) on energy derivative instruments				Net unrealized gain (loss) on treasury interest rate swaps				Total
Balance at December 31, 2014		$	(164,281	)		$	(686	)		$	(5,990	)		$	(170,957	)
Other comprehensive income (loss) before reclassifications			712				—				—				712
Amounts reclassified from accumulated other comprehensive income (loss), net of tax			10,133				686				237				11,056
Net current-period other comprehensive income (loss)			10,845				686				237				11,768
Balance at September 30, 2015		$	(153,436	)		$	—			$	(5,753	)		$	(159,189	)

 

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Details about these reclassifications out of AOCI for the three and nine months ended September 30, 2015, and 2014, are as follows:

 

Puget Energy (Dollars in Thousands) Details about accumulated other comprehensive income (loss) components		Affected line item in the statement where net income (loss) is presented		Three Months Ended September 30,								Nine Months Ended September 30,
				2015				2014				2015				2014
				Amount reclassified from accumulated other comprehensive income (loss)
Net unrealized gain (loss) and prior service cost on pension plans:
Amortization of prior service cost		(a)		$	484			$	483			$	1,452			$	1,452
Amortization of net gain (loss)		(a)			(1,349	)			—				(5,172	)			(388	)
		Total before tax			(865	)			483				(3,720	)			1,064
		Tax (expense) or benefit			303				(169	)			1,302				(703	)
		Net of Tax		$	(562	)		$	314			$	(2,418	)		$	361
Net unrealized gain (loss) on energy derivative instruments:
Commodity contracts: electric derivatives		Purchased electricity			—				—				(512	)			(534	)
		Tax (expense) or benefit			—				—				179				187
		Net of Tax		$	—			$	—			$	(333	)		$	(347	)
Net unrealized gain (loss) on interest rate swaps:
Interest rate contracts		Interest expense			—				—				—				(144	)
		Tax (expense) or benefit			—				—				—				50
		Net of Tax		$	—			$	—			$	—			$	(94	)
Total reclassification for the period		Net of Tax		$	(562	)		$	314			$	(2,751	)		$	(80	)

 

(a)	These AOCI components are included in the computation of net periodic pension cost (see Note 5 for additional details).

 

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Puget Sound Energy (Dollars in Thousands) Details about accumulated other comprehensive income (loss) components		Affected line item in the statement where net income (loss) is presented		Three Months Ended September 30,								Nine Months Ended September 30,
				2015				2014				2015				2014
				Amount reclassified from accumulated other comprehensive income (loss)
Net unrealized gain (loss) and prior service cost on pension plans:
Amortization of prior service cost		(a)		$	383			$	381			$	1,145			$	1,143
Amortization of net gain (loss)		(a)			(5,568	)			(3,488	)			(17,830	)			(10,463	)
		Total before tax			(5,185	)			(3,107	)			(16,685	)			(9,320	)
		Tax (expense) or benefit			1,815				1,227				5,840				3,070
		Net of Tax		$	(3,370	)		$	(1,880	)		$	(10,845	)		$	(6,250	)
Net unrealized gain (loss) on energy derivative instruments:
Commodity contracts: electric derivatives		Purchased electricity			—				—				(1,055	)			(1,104	)
		Tax (expense) or benefit			—				—				369				386
		Net of Tax		$	—			$	—			$	(686	)		$	(718	)
Net unrealized gain (loss) on treasury interest rate swaps:
Interest rate contracts		Interest expense			(122	)			(122	)			(366	)			(366	)
		Tax (expense) or benefit			43				43				129				129
		Net of Tax		$	(79	)		$	(79	)		$	(237	)		$	(237	)
Total reclassification for the period		Net of Tax		$	(3,449	)		$	(1,959	)		$	(11,768	)		$	(7,205	)

 

(a)	These AOCI components are included in the computation of net periodic pension cost (see Note 5 for additional details).

(10) Other

Long-Term Debt

On May 26, 2015, PSE issued $425.0 million of senior notes secured by first mortgage bonds. The notes mature in May 2045 and have an interest rate of 4.30%, which is payable semi-annually in May and November. Net proceeds of the issuance were used to fund the early retirement, including accrued interest and make-whole call premiums, of PSE’s $150.0 million 5.197% senior notes maturing in October 2015 and PSE’s $250.0 million 6.75% senior notes maturing in January 2016.

On May 12, 2015, Puget Energy issued $400.0 million of senior secured notes. The notes mature in May 2025 and have an interest rate of 3.65%, which is payable semi-annually in May and November. Net proceeds of the issuance were used to repay $299.1 million principal amount outstanding under Puget Energy’s term loans, as well as accrued interest, and to fund a special dividend to shareholders of approximately $96.7 million.

Related Party Transactions

Scott Armstrong serves on the Board of Directors of the Company, and is the president and Chief Executive Officer of Group Health Cooperative (Group Health). Group Health provides coverage to over 600,000 residents in Washington and Northern Idaho. Certain employees of PSE elect Group Health as their medical provider and as a result, PSE paid Group Health a total of $14.8 million and $17.7 million for medical coverage for the nine months ended September 30, 2015, and the year ended December 31, 2014, respectively.

 

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Puget Energy, Inc.

OFFER TO EXCHANGE ITS

3.650% Senior Secured Notes due 2025

that have been registered under the

Securities Act of 1933, as amended

for any and all of its outstanding

3.650% Senior Secured Notes due 2025

that were issued and sold in a transaction

exempt from registration

under the Securities Act of 1933, as amended

 

 

P R O S P E C T U S

 

 

 

November 23, 2015

 

 

 

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PART II

INFORMATION NOT REQUIRED IN PROSPECTUS

Item 20. Indemnification of Directors and Officers

Sections 23B.08.500 through 23B.08.600 of the Washington Business Corporation Act (the “WBCA”) authorize a court to award, or a corporation to grant, indemnification to directors and officers on terms sufficiently broad to permit indemnification under certain circumstances for liabilities arising under the Securities Act of 1933, as amended. Article 8 of Puget Energy’s amended and restated articles of incorporation and Article VII of Puget Energy’s amended and restated bylaws provide for indemnification of Puget Energy’s directors and officers to the maximum extent permitted by Washington law, except for (i) acts or omissions of such person finally adjudged to be intentional misconduct or a knowing violation of law by the person, (ii) conduct finally adjudged to be in violation of Section 23B.08.310 of the WBCA, or (iii) any transaction with respect to which it was finally adjudged that the person received a benefit in money, property, or services to which such person was not legally entitled.

Section 23B.08.320 of the WBCA authorizes a corporation to eliminate or limit a director’s personal liability to the corporation or its shareholders for monetary damages for conduct as a director, except in certain circumstances involving intentional misconduct, knowing violations of law or illegal corporate loans or distributions, or any transaction from which the director personally receives a benefit in money, property or services to which the director is not legally entitled. Article 9 of Puget Energy’s amended and restated articles of incorporation contain provisions implementing, to the fullest extent permitted by Washington law, such limitations on a director’s liability to Puget Energy and its shareholders.

Officers and directors of Puget Energy are covered by insurance (with certain exceptions and certain limitations) that indemnifies them against losses and liabilities arising from certain alleged “wrongful acts,” including alleged errors or misstatements, or certain other alleged wrongful acts or omissions constituting neglect or breach of duty.

Item 21. Exhibits and Financial Statement Schedules

(a)

Exhibits

Reference is made to the Exhibit Index starting on page E-1.

Item 21. Undertakings

The undersigned Registrants hereby undertake:

(1) To file, during any period in which offers or sales are being made, a post-effective amendment to this registration statement:

(i) to include any prospectus required by Section 10(a)(3) of the Securities Act of 1933;

(ii) to reflect in the prospectus any facts or events arising after the effective date of the registration statement (or the most recent post-effective amendment thereof) which, individually or in the aggregate, represent a fundamental change in the information set forth in the registration statement. Notwithstanding the foregoing, any increase or decrease in volume of securities offered (if the total dollar value of securities offered would not exceed that which was registered) and any deviation from the low or high end of the estimated maximum offering range may be reflected in the form of prospectus filed with the Commission pursuant to Rule 424(b) if, in the aggregate, the changes in volume and price represent no more than a 20 percent change in the maximum aggregate offering price set forth in the “Calculation of Registration Fee” table in the effective registration statement; and

 

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(iii) to include any material information with respect to the plan of distribution not previously disclosed in the registration statement or any material change to such information in the registration statement.

(2) That, for the purpose of determining any liability under the Securities Act of 1933, each such post-effective amendment shall be deemed to be a new registration statement relating to the securities offered therein, and the offering of such securities at that time shall be deemed to be this initial bona fide offering thereof.

(3) To remove from registration by means of a post-effective amendment any of the securities being registered which remain unsold at the termination of the offering.

(4) That, for the purpose of determining liability under the Securities Act of 1933 to any purchaser, each prospectus filed pursuant to Rule 424(b) as part of a registration statement relating to an offering, other than registration statements relying on Rule 430B or other than prospectuses filed in reliance on Rule 430A, shall be deemed to be part of and included in the registration statement as of the date it is first used after effectiveness. Provided, however, that no statement made in a registration statement or prospectus that is part of the registration statement or made in a document incorporated or deemed incorporated by reference into the registration statement or prospectus that is part of the registration statement will, as to a purchaser with a time of contract of sale prior to such first use, supersede or modify any statement that was made in the registration statement or prospectus that was part of the registration statement or made in any such document immediately prior to such date of first use.

(5) That, for the purpose of determining liability of the registrant under the Securities Act of 1933 to any purchaser in the initial distribution of the securities, the undersigned Registrant undertakes that in a primary offering of securities of the undersigned Registrant pursuant to this registration statement, regardless of the underwriting method used to sell the securities to the purchaser, if the securities are offered or sold to such purchaser by means of any of the following communications, the undersigned Registrant will be a seller to the purchaser and will be considered to offer or sell such securities to such purchaser:

(i) Any preliminary prospectus or prospectus of the undersigned Registrant relating to the offering required to be filed pursuant to Rule 424;

(ii) Any free writing prospectus relating to the offering prepared by or on behalf of the undersigned Registrant or used or referred to by the undersigned Registrant;

(iii) The portion of any other free writing prospectus relating to the offering containing material information about the undersigned Registrant or its securities provided by or on behalf of the undersigned Registrant; and

(iv) Any other communication that is an offer in the offering made by the undersigned Registrant to the purchaser.

(6) Insofar as indemnification for liabilities arising under the Securities Act of 1933 may be permitted to directors, officers and controlling persons of the Registrants pursuant to the foregoing provisions, or otherwise, the Registrants have been advised that in the opinion of the Securities and Exchange Commission such indemnification is against public policy as expressed in the Securities Act of 1933 and is, therefore, unenforceable. In the event that a claim for indemnification against such liabilities (other than the payment by the Registrants of expenses incurred or paid by a director, officer or controlling person of the Registrants in the successful defense of any action, suit or proceeding) is asserted by such director, officer or controlling person in connection with the securities being registered, the Registrants will, unless in the opinion of its counsel the matter has been settled by controlling precedent, submit to a court of appropriate jurisdiction the question whether such indemnification by it is against public policy as expressed in the Securities Act of 1933 and will be governed by the final adjudication of such issue.

(7) To respond to requests for information that is incorporated by reference into the prospectus pursuant to Item 4, 10(b), 11, or 13 of this form, within one business day of receipt of such request, and to send the incorporated documents by first class mail or other equally prompt means. This includes information

 

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contained in documents filed subsequent to the effective date of the registration statement through the date of responding to the request.

(8) To supply by means of a post-effective amendment all information concerning a transaction, and the company being acquired involved therein, that was not the subject of and included in the registration statement when it became effective.

 

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SIGNATURES

Pursuant to the requirements of the Securities Act of 1933, the registrant has duly caused this Amendment No. 1 to Registration Statement to be signed on its behalf by the undersigned, thereunto duly authorized, in the City of Bellevue, State of Washington, on the 20^th day of November, 2015.

 

Pursuant to the requirements of the Securities Act of 1933, this Amendment No. 1 to Registration Statement has been signed by the following persons in the capacities indicated below on November 20, 2015.

 

Signature		Title
* Kimberly J. Harris		President and Chief Executive Officer (Principal Executive Officer)
/s/ Daniel A. Doyle Daniel A. Doyle		Senior Vice President and Chief Financial Officer (Principal Financial Officer)
* Michael J. Stranik		Controller and Principal Accounting Officer
* Andrew Chapman		Director
* Melanie J. Dressel		Chairman and Director
* Daniel Fetter		Director

 

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Signature		Title
* Steven Hooper		Director
* Alan W. James		Director
* Christopher J. Leslie		Director
* David MacMillan		Director
* Paul McMillan		Director
* Mary O. McWilliams		Director
* Chris Trumpy		Director

 

*By:		/s/ Daniel A. Doyle
		Daniel A. Doyle
		Attorney-in-Fact

 

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EXHIBIT INDEX

 

Exhibit Number		Description
2.1		Agreement and Plan of Merger, dated October 25, 2007, by and among Puget Energy, Inc., Padua Holdings LLC, Padua Intermediate Holdings Inc. and Padua Merger Sub Inc. (incorporated herein by reference to Exhibit 2.1 to Puget Energy’s Current Report on Form 8-K, dated October 25, 2007, Commission File No. 1-16305).
3.1		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).
3.2		Amended and Restated Bylaws of Puget Energy dated February 6, 2009 (incorporated herein by reference to Exhibit 3.3 to Puget Energy’s Current Report on Form 8-K, dated February 6, 2009, Commission File No. 1-16305).
4.1		Indenture dated December 6, 2010 (incorporated herein by reference to Exhibit 4.1 to Puget Energy’s Current Report on Form 8-K, dated December 1, 2010, Commission File No. 1-16305).
4.2		First Supplemental Indenture dated December 6, 2010 (incorporated herein by reference to Exhibit 4.2 to Puget Energy’s Current Report on Form 8-K, dated December 1, 2010, Commission File No. 1-16305).
4.3		Second Supplemental Indenture dated June 3, 2011 (incorporated herein by reference to Exhibit 4.1 to Puget Energy’s Current Report on Form 8-K, dated June 6, 2011, Commission File No. 1-16305).
4.3		Third Supplemental Indenture dated June 15, 2012 (incorporated herein by reference to Exhibit 4.1 to Puget Energy’s Current Report on Form 8-K, dated June 15, 2012, Commission File No. 1-16305).
4.4		Fourth Supplemental Indenture dated May 12, 2015 incorporated herein by reference to Exhibit 4.1 to Puget Energy’s Current Report on Form 8-K, dated May 13, 2015, Commission File No. 1-16305).
4.4		Registration Rights Agreement, dated as of May 12, 2015, among Puget Energy, Barclays Capital Inc., Merrill Lynch, Pierce, Fenner & Smith Incorporated and Mizuho Securities USA Inc., as representatives of the several initial purchasers party thereto (incorporated herein by reference to Exhibit 4.5 to Puget Energy’s Current Report on Form 8-K, dated May 13, 2015, Commission File No. 1-16305).
4.5		Form of Puget Energy, Inc. 3.650% Exchange Note due 2025 E1—(incorporated herein by reference to Exhibit 4.5 to Puget Energy’s Registration Statement on Form S-4 filed on November 6, 2015).
5.1		Opinion of Perkins Coie LLP as to legality of the Exchange Notes issued by Puget Energy, Inc E2—(incorporated herein by reference to Exhibit 5.1 to Puget Energy’s Registration Statement on Form S-4 filed on November 6, 2015).
12.1		Computation of ratio of earnings to fixed charges (incorporated herein by reference to Exhibit 12.1 to Puget Energy’s Quarterly Report on Form 10-Q for the period ended September 30, 2015, Commission File No. 1-16305).
21.1		List of Subsidiaries of Registrant (incorporated herein by reference Exhibit 21.1 to Puget Energy’s Annual Report on Form 10-K for the period ended December 31, 2014, Commission File No. 1-16305).
23.1		Consent of Independent Registered Public Accounting Firm.

 

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Exhibit Number		Description
23.2		Consent of Perkins Coie LLP (included in Exhibit 5.1) E3—(incorporated herein by reference to Exhibit 23.2 to Puget Energy’s Registration Statement on Form S-4 filed on November 6, 2015).
24.1		Power of Attorney (contained on the signature pages hereto) E4—(incorporated herein by reference to Exhibit 24.1 to Puget Energy’s Registration Statement on Form S-4 filed on November 6, 2015).
25.1		Form T-1 Statement of Eligibility of Wells Fargo Bank, National Association to act as Trustee under the Indenture relating to Puget Energy’s 3.650% Senior Secured Notes due 2025 E5—(incorporated herein by reference to Exhibit 25.1 to Puget Energy’s Registration Statement on Form S-4 filed on November 6, 2015).
99.1		Form Letter of Transmittal E6—(incorporated herein by reference to Exhibit 99.1 to Puget Energy’s Registration Statement on Form S-4 filed on November 6, 2015).
99.2		Form of Notice of Guaranteed Delivery E7—(incorporated herein by reference to Exhibit 99.2 to Puget Energy’s Registration Statement on Form S-4 filed on November 6, 2015).
99.3		Form of Letter to DTC Participants E8—(incorporated herein by reference to Exhibit 99.3 to Puget Energy’s Registration Statement on Form S-4 filed on November 6, 2015).
99.4		Form of Letter to Clients E9—(incorporated herein by reference to Exhibit 99.4 to Puget Energy’s Registration Statement on Form S-4 filed on November 6, 2015).
101.INS		XBRL Instance Document.
101.SCH		XBRL Taxonomy Extension Schema Document.
101.CAL		XBRL Taxonomy Extension Calculation Linkbase Document.
101.DEF		XBRL Taxonomy Extension Definition Linkbase Document.
101.LAB		XBRL Taxonomy Extension Label Linkbase Document.
101.PRE		XBRL Taxonomy Extension Presentation Linkbase Document.

 

 

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