ITEM 1. 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 February 6, 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, FSS Infrastructure Trust, the Canada Pension Plan Investment Board (CPPIB), 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, 2013 and 2012:
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At December 31, 2013 approximately 374,200 customers purchased both electricity and natural gas from PSE as compared to 383,600 at December 31, 2012. The decrease in combined customer accounts is related to a more refined measurement in 2013 due to the implementation of a new Customer Information System.
During 2013, PSE’s billed retail and transportation revenue from electric utility operations were derived 53.3% from residential customers, 40.2% from commercial customers, 5.2% from industrial customers and 1.3% from other customers. PSE’s billed retail revenue from natural gas utility operations were derived 66.9% from residential customers, 28.7% from commercial customers, 2.7% from industrial customers and 1.6%from transportation customers in 2013. During this period, the largest customer accounted for approximately 1.5% of PSE’s operating revenue.
PSE is affected by various seasonal weather patterns and therefore, utility revenue and associated expenses are not generated evenly during the year. Energy usage varies seasonally and monthly, primarily as a result of weather conditions. PSE experiences its highest retail energy sales in the first and fourth quarters of the year. Sales of electricity to wholesale customers also vary by quarter and year depending principally upon fundamental market factors and weather conditions. PSE has a Power Cost Adjustment (PCA) mechanism in retail electric rates to recover variations in electricity costs on a shared basis with customers. PSE also has a Purchased Gas Adjustment (PGA) mechanism in retail natural gas rates to recover variations in natural gas supply and transportation costs.
In the five-year period ended December 31, 2013, PSE’s gross electric utility plant additions were $3.9 billion and retirements were $385.9 million. In the same five-year period, PSE’s gross natural gas utility plant additions were $730.8 million and retirements were $115.8 million and PSE’s gross common utility plant additions were $430.4 million and retirements were $362.9
million. Gross electric utility plant at December 31, 2013 was approximately $9.3 billion, which consisted of 34.7% distribution, 42.5% generation, 12.5% transmission and 10.3% general plant and other. Gross natural gas utility plant at December 31, 2013 was approximately $3.1 billion, which consisted of 92.8% distribution and 7.2% general plant and other. Gross common utility general and intangible plant at December 31, 2013 was approximately $565.1 million.
Employees
At December 31, 2013, 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, 2014, 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 “Additional Information” in Item 10 Part III of this annual report.
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 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.
Expedited Rate Filing (ERF)
On February 4, 2013, PSE filed revised tariffs seeking to update its rates established in its base rate proceedings in May 2012 known as an Expedited Rate Filing (ERF). The ERF 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 valuation 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 its delivery-system costs and authority to record accounting entries associated with the mechanisms. After the petition and supporting testimony were filed, the Washington Commission held two technical conferences to allow interested stakeholders to further discuss the proposed decoupling mechanisms. PSE also responded to inquiries of interested stakeholders seeking additional information about the decoupling proposal.
On March 4, 2013, PSE and NWEC, taking this process into account, reached an agreement on certain modifications to the decoupling mechanisms and filed an amended petition and testimony in support of these modifications to the original decoupling proposal. The Washington Commission's regulatory staff (Commission Staff) filed testimony in support of the revised proposal on the same day. 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 general rate case process over the plan period. The rate plan includes predetermined annual increases (K factor) to PSE's allowed electric and gas revenue which are effective January of each year. Under this plan, PSE, with limited exceptions, would be allowed to file its next general rate case 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 PCA and 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% “soft cap” on rate increases. Any amount in excess of the soft cap will be added to the decoupling tracker in subsequent rate periods, subject to a 3.0% soft cap on rate increases in the subsequent year. In addition, PSE and the customers would have shared 50.0% each in any earnings in excess of the authorized rate of return of 7.77%. The customers share of the over earnings will be returned to customers over the subsequent 12 month period beginning May 1 of each year.
TransAlta Centralia Agreement
In 2012, PSE executed a power purchase agreement with TransAlta Centralia for the purchase of up to 380 Megawatt (MW) of coal transition power. PSE filed a petition for approval of the TransAlta Centralia agreement and recovery of related acquisition costs. The Washington Commission issued an order granting PSE's petition which contained conditions that left PSE with a level of uncertainty such that it could terminate the contract. PSE subsequently filed a Petition for Reconsideration of the order with the Washington Commission.
Washington Commission Decision
PSE filed a settlement agreement with the Washington Commission on March 22, 2013. The agreement was intended to settle all issues regarding decoupling, the power purchase agreement with TransAlta Centralia and the ERF which included the property tax tracker. The Washington Commission placed these filings under a common procedural schedule. On June 25, 2013, the Washington Commission issued three final orders resolving the amended decoupling petition, the ERF filing and the Petition for Reconsideration. Order No. 6 rejected the multi-party settlement agreement between PSE, NWEC and Commission Staff due to uncertainty regarding the legality of consolidating the three filings. Order No. 7 approved PSE's ERF filing with a small change to its cost of capital from 7.80% to 7.77% to update long term debt costs. This order also approved the property tax tracker discussed above. In addition, Order No. 7 approved the amended decoupling and rate plan filing as filed by PSE and NWEC on March 4, 2013 with the requirement that PSE update the underlying ERF rates for the change in cost of capital, and with the further condition that PSE and the customers will share 50.0% each in earnings in excess of the 7.77% authorized rate of return. Order No. 8 granted PSE's Petition for Reconsideration, clarifying certain portions of the Washington Commission's original order.
As approved, the ERF filing will produce an additional $30.7 million in annual electric revenue and reduce annual gas revenue by $2.0 million. 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. PSE's 2012 and 2013 property taxes that are not in current rates will be recovered in later years. The decoupling mechanisms will initially produce an additional $21.4 million in annual electric revenue and $10.8 million in annual gas revenue. 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.
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. 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 are scheduled for May 2014.
Electric Rate Case
On February 29, 2012, PSE filed proposed Federal Incentive Tracker 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 wind project (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 May 7, 2012, the Washington Commission issued its order in PSE's consolidated electric and natural gas general rate case filed in June 2011, approving a general rate increase for electric customers of $63.3 million or 3.2% annually, and an increase in natural gas rates of $13.4 million or 1.3% annually. The rate increases for electric and 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 January 31, 2013, the Washington Commission approved a rate change to 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 both grants to eligible customers over 11 months beginning February 1, 2013, including grant amortization pass-back of $34.6 million and interest pass-back of $23.8 million. This represents an overall average rate decrease of 2.76%.
On October 23, 2013, the Washington Commission approved an update on the Company's Power Cost Only Rate Case (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.
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 0.26%.
For additional information, see Note 3 to the consolidated financial statements included in Item 8 of this report.
Natural Gas Rate Case
On May 7, 2012, the Washington Commission issued its order in PSE's consolidated electric and natural gas general rate case filed in June 2011, approving a general rate increase for electric customers of $63.3 million or 3.2% annually, and an increase in natural gas rates of $13.4 million or 1.3% annually. The rate increases for electric and 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 overrecovery of commodity costs in the Company's PGA mechanism. The Washington 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, the difference being recognized as revenue sensitive taxes.
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. The rate adjustment has 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 30, 2013, the Washington Commission approved PSE's Pipeline Replacement Program Plan (PRPP) that would accelerate and enhance the safety of the natural gas system and ultimately reduce costs. Under the PRPP plan, PSE would be allowed to file a tariff revision to recover its costs associated with the acceleration of the replacement of natural gas pipelines with the Washington Commission.
For additional information, see Note 3 to the consolidated financial statements included in Item 8 of this report.
ELECTRIC UTILITY OPERATING STATISTICS
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National Oceanic and Atmospheric Administration (NOAA).
Average MW usage by customers divided by their maximum usage.
ELECTRIC SUPPLY
At December 31, 2013, PSE’s electric power resources, which include company-owned or controlled resources as well as those under long-term contract, had a total capacity of approximately 4,831 megawatts (MW). PSE’s historical peak load of approximately 4,912 MW occurred on December 10, 2009. In order to meet an extreme winter peak load, PSE may supplement its electric power resources with winter-peaking call options and other instruments that may include, but are not limited to, weather-related hedges. When it is more economical for PSE to purchase power than to operate its own generation facilities, PSE will purchase spot market energy.
The following table shows PSE’s electric energy supply resources and energy production for the years ended December 31, 2013 and 2012:
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Net of 37 MW in 2013 and 38 MW in 2012 capacity delivered to Canada pursuant to the provisions of a treaty between Canada and the United States and Canadian Entitlement Allocation agreements.
Power received from other utilities and firm contracts are classified between hydroelectric and other producers based on the character of the utility system used to supply the power or, if the power is supplied from a particular resource, the character of that resource.
Short-term wholesale purchases, net of resale, of 1,687,907 megawatt hours (MWh) and 1,389,934 MWh, account for 25.6% and 33.7% of energy production, for 2013 and 2012, respectively.
Company-Owned Electric Generation Resources
At December 31, 2013, PSE owns the following plants with an aggregate net generating capacity of 3,597 MW:
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Net Maximum Capacity is the capacity a unit can sustain over a specified period of time when not restricted by ambient conditions or deratings, less the losses associated with auxiliary loads.
The FERC jurisdictional facility was operated pursuant to 50-year license granted by the FERC in October 2008. The license provides protection and enhancements for fish and wildlife, water quality, recreation and cultural and historic resources.
The FERC jurisdictional facility was operated pursuant to 40-year license granted by the FERC in June 2004.
At December 31, 2013, Electron project output was limited to approximately 7 MW due to the condition of the flume that conveys water to the plant. This limitation is expected to continue into 2014.
Columbia River Electric Energy Supply Contracts
During 2013, approximately 15.1% of PSE’s energy requirement was obtained through long-term contracts with three Washington Public Utility Districts (PUDs) that own and operate hydroelectric projects on the Columbia River. PSE agrees to pay a share of the annual debt service, operating and maintenance costs and other expenses associated with each project in proportion to its share of projected output. PSE’s payments are not contingent upon the projects being operable.
As of December 31, 2013, PSE was entitled to purchase portions of the power output of the PUDs’ projects as set forth below:
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PSE’s share of power under the 2001 contract will decline over time as Grant County PUD’s load increases. PSE’s share of both the Priest Rapids and Wanapum developments was 0.8% at the end of 2013 and will not be less than 0.6% through 2052.
Other Electric Supply, Exchange and Transmission Contracts and Agreements
PSE purchases electric energy under long-term firm purchased power contracts with other utilities and marketers in the Western region. PSE is generally not obligated to make payments under these contracts unless power is delivered. PSE has seasonal energy and capacity exchange agreements with the Bonneville Power Administration (BPA) (for 45 aMW of capacity) and with Pacific Gas & Electric Company (for 300 MW of capacity).
Further, PSE has entered into multiple various-term transmission contracts with other utilities to integrate electric generation and contracted resources into PSE’s system. These transmission contracts require PSE to pay for transmission service based on the contracted MW level of demand, regardless of actual use.
Other transmission agreements provide actual capacity ownership or capacity ownership rights. PSE’s annual charges under these agreements are also based on contracted MW volumes. Capacity on these agreements that is not committed to serve PSE’s load is available for sale to third parties. PSE also purchases short-term transmission services from a variety of providers, including the BPA.
In 2013, PSE had 4,411 MW and 596 MW of total transmission demand contracted with the BPA and other utilities, respectively. PSE’s remaining transmission capacity needs are met via PSE owned transmission assets.
Natural Gas Supply for Electric Customers
PSE purchases natural gas supplies for its power portfolio to meet demand for its combustion turbine generators. Supplies range from long-term to daily agreements, as the demand for the turbines varies depending on market heat rates. Purchases are made from a diverse group of major and independent natural gas producers and marketers in the United States and Canada. PSE also enters into physical and financial fixed price derivative instruments to hedge the cost of natural gas. PSE utilizes natural gas storage capacity that is dedicated to and paid for by the power portfolio to facilitate increased natural gas supply reliability and intra-day dispatch of PSE’s gas-fired generation resources. During 2013, approximately 88.0% of natural gas for power purchased by PSE for power customers originated in British Columbia and 12.0% originated in the United States.
Integrated Resource Plans, Resource Acquisition and Development
PSE is required by Washington Commission regulations to file electric and natural gas Integrated Resource Plans (IRP) every two years with the next IRP scheduled to be filed by May 30, 2015. As part of the resource planning process, PSE filed an IRP in 2013. The 2013 IRP identified the following capacity needs:
The expected capacity needs reflect the mix of energy efficiency programs deemed cost effective in the 2013 IRP. In 2013, PSE renewed all the Mid-Columbia transmission available for renewal during the year to meet peak capacity needs.
As part of the 2013 PCORC, PSE sought approval for the Mid-C transmission renewals executed in 2013. As the Washington Commission approved all the Mid-C transmission renewals requested in the 2013 PCORC, PSE expects to have sufficient resources to meet its capacity needs over the next few years. On February 6, 2014, the Washington Commission formally accepted PSE's 2013 IRP filing and requested additional dialogue regarding PSE's interest in the Colstrip generation plant in Montana.
NATURAL GAS UTILITY OPERATING STATISTICS
NATURAL GAS SUPPLY FOR NATURAL GAS CUSTOMERS
PSE purchases a portfolio of natural gas supplies ranging from long-term firm to daily from a diverse group of major and independent natural gas producers and marketers in the United States and Canada. PSE also enters into physical and financial fixed-price derivative instruments to hedge the cost of natural gas to serve its customers. All of PSE’s natural gas supply is ultimately transported through the facilities of Northwest Pipeline LLC (NWP), the sole interstate pipeline delivering directly into PSE’s service territory. Accordingly, delivery of natural gas supply to PSE’s natural gas system is dependent upon the reliable operations of NWP.
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All peak firm gas supplies and storage are connected to PSE’s market with firm transportation capacity.
For baseload, peak management and supply reliability purposes, PSE supplements its firm natural gas supply portfolio by purchasing natural gas in off-peak periods, injecting it into underground storage facilities and withdrawing it during the peak winter heating season. Underground storage facilities at Jackson Prairie in western Washington and at Clay Basin in Utah are used for this purpose. Clay Basin withdrawals are used to supplement purchases from the U.S. Rocky Mountain supply region, while Jackson Prairie provides incremental peak-day resources utilizing firm storage redelivery transportation capacity. Jackson Prairie is also used for daily balancing of load requirements on PSE’s gas system. Peaking needs are also met by using PSE-owned natural gas held in PSE’s Liquefied Natural Gas (LNG) peaking facility located within its distribution system in Gig Harbor, Washington; and interrupting service to customers on interruptible service rates, if necessary.
PSE expects to meet its firm peak-day requirements for residential, commercial and industrial markets through its firm natural gas purchase contracts, firm transportation capacity, firm storage capacity and other firm peaking resources. PSE believes it will be able to acquire incremental firm natural gas supply and capacity to meet anticipated growth in the requirements of its firm customers for the foreseeable future.
During 2013, approximately 56.0% of natural gas supplies purchased by PSE for its gas customers originated in British Columbia, while 21.0% originated in Alberta and 23.0% originated in the United States. PSE’s firm natural gas supply portfolio has adequate flexibility in its transportation arrangements to enable it to achieve savings when there are regional price differentials between natural gas supply basins. The geographic mix of suppliers and daily, monthly and annual take requirements permit some degree of flexibility in managing natural gas supplies during off-peak periods to minimize costs. Natural gas is marketed outside PSE’s service territory (off-system sales) whenever on-system customer demand requirements permit and the resulting economics of these transactions are reflected in PSE’s natural gas customer tariff rates through the PGA mechanism.
Natural Gas Storage Capacity
PSE holds storage capacity in the Jackson Prairie and Clay Basin underground natural gas storage facilities adjacent to NWP’s pipeline to serve PSE’s natural gas customers. The Jackson Prairie facility is operated and one-third owned by PSE. The facility is used primarily for intermediate peaking purposes since it is able to deliver a large volume of natural gas over a relatively short
time period. Combined with capacity contracted from NWP’s one-third stake in Jackson Prairie, PSE has peak firm withdrawal capacity in excess of 454,000 Dekatherm (Dth) per day, which, after reduction for a portion temporarily released to the power portfolio and to a third party represents nearly 51.3% of PSE’s expected near-term peak-day requirement. PSE’s total firm storage capacity of the facility is approximately 9.8 million Dth. The location of the Jackson Prairie facility in PSE’s market area increases supply reliability and provides significant pipeline demand cost savings by reducing the amount of annual pipeline capacity required to meet peak-day natural gas requirements. The owned storage capacity at Jackson Prairie is now 8.5 million Dth.
Due to the recent expansion of Jackson Prairie storage withdrawal capacity and storage capacity, PSE’s natural gas storage resources are expected to exceed natural gas customer requirements for the next few years. Therefore, through March 2016, 50,000 Dth per day of natural gas storage withdrawal capacity and 500,000 Dth of natural gas storage capacity have been temporarily released at market rates to PSE’s power portfolio, increasing natural gas supply reliability and facilitating intra-day dispatch of PSE’s natural gas-fired generation resources. In addition, PSE has temporarily released approximately 6,000 Dth per day of Jackson Prairie Storage firm withdrawal capacity (and associated storage capacity) in exchange for temporary firm pipeline capacity on a constrained portion of NWP's system.
The Clay Basin storage facility is a supply area storage facility that is used primarily to reduce portfolio costs through supply management efforts that take advantage of market price volatility, and provides system reliability. PSE holds over 12.8 million Dth of Clay Basin storage capacity and approximately 107,000 Dth per day of firm withdrawal capacity under two long-term contracts with remaining terms of four and six years, respectively. PSE’s maximum firm withdrawal capacity and total storage capacity at Clay Basin, net of releases, is over 74,000 Dth per day and exceeds 8.8 million Dth, respectively.
LNG and Propane-Air Resources
LNG and propane-air resources provide firm natural gas supply on short notice for short periods of time. Due to their typically high cost and slow cycle times, these resources are normally utilized as a last resort supply source in extreme peak-demand periods, typically during the coldest hours or days. PSE contracts for LNG storage services of 241,700 Dth of PSE-owned gas at NWP’s Plymouth facility, at a maximum daily deliverability of 70,500 Dth. During 2013, PSE, working with NWP, determined that the pipeline redelivery to PSE from the Plymouth LNG facility can no longer be considered firm and reliable during peak conditions, therefore PSE has removed the Plymouth service from its firm portfolio. PSE is negotiating with other market participants to replace the Plymouth service with an alternate firm resource to accommodate expected future load growth. PSE owns and operates the Swarr vaporized propane-air station located in Renton, Washington which includes storage capacity for approximately 1.5 million gallons of propane. This propane-air injection facility is designed to deliver the equivalent of 10,000 Dth of natural gas per day for up to 12 days directly into PSE’s distribution system. PSE owns and operates an LNG peaking facility in Gig Harbor, Washington, with total capacity of 10,600 Dth, which is capable of delivering the equivalent of 2,500 Dth of natural gas per day.
Natural Gas Transportation Capacity
PSE currently holds firm transportation capacity on pipelines owned by NWP, Gas Transmission Northwest (GTN), Nova Gas Transmission (NOVA), Foothills Pipe Lines (Foothills) and Spectra's Westcoast Energy (Westcoast). GTN, NOVA, and Foothills are all TransCanada companies. PSE pays fixed monthly demand charges for the right, but not the obligation, to transport specified quantities of natural gas from receipt points to delivery points on such pipelines each day for the term or terms of the applicable agreements.
PSE holds approximately 523,000 Dth per day of capacity for its natural gas customers on NWP that provides firm year-round delivery to PSE’s service territory. In addition, PSE holds approximately 450,000 Dth per day of seasonal firm capacity on NWP to provide for delivery of natural gas stored in Jackson Prairie.
PSE has firm transportation capacity on NWP through various contracts that supply electric generating facilities with approximately 168,000 Dth per day. PSE participates in the pipeline capacity release market to achieve savings for PSE’s customers and has released certain segments of temporarily surplus firm capacity to third parties. PSE’s firm transportation capacity contracts with NWP have remaining terms ranging from one to 31 years. However, PSE has either the unilateral right to extend the contracts under the contracts’ current terms or the right of first refusal to extend such contracts under current FERC rules.
PSE’s firm transportation capacity for its natural gas customers on Westcoast’s pipeline is approximately 130,000 Dth per day under various contracts, with remaining terms of four to six years. PSE has other firm transportation capacity on Westcoast’s pipeline, which supplies the electric generating facilities, totaling approximately 106,000 Dth per day, with remaining terms of one to five years. PSE has firm transportation capacity on NOVA and Foothills pipelines, totaling approximately 80,000 Dth per day, with remaining terms of two to ten years. PSE has annual renewal rights on this capacity. PSE’s firm transportation capacity on the GTN pipeline, totaling approximately 90,000 Dth per day, has a remaining term of 10 years.
Capacity Release
The FERC regulates the release of firm pipeline and storage capacity for facilities which fall under its jurisdiction. Capacity releases allow shippers to temporarily or permanently relinquish unutilized capacity to recover all or a portion of the cost of such
capacity. The FERC allows capacity to be released through several methods including open bidding and pre-arrangement. PSE has acquired some firm pipeline and storage service through capacity release provisions to serve its growing service territory and electric generation portfolio. PSE also mitigates a portion of the demand charges related to unutilized storage and pipeline capacity through capacity release. Capacity release benefits derived from the natural gas customer portfolio are passed on to PSE’s natural gas customers through the PGA mechanism.
ENERGY EFFICIENCY
PSE is required under Washington state law to pursue feasible, achievable, and cost-effective electric conservation. 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 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 has received approval in 2013 from the Washington Commission for electric and gas decoupling mechanisms.
Since 1997 and 2012, PSE has recovered direct electric and gas energy efficiency (or conservation) expenditures, respectively, through a rider mechanism. The rider mechanism allows PSE to defer the efficiency expenditures and amortize them to expense as PSE collects the efficiency expenditures in rates over a one-year period. As a result of the rider mechanism, direct electric and natural gas energy efficiency expenditures are recovered.
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 (GHGs), and thus are also subject to any current or future GHG or climate change legislation or regulation. Colstrip 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.
Remediation of Contamination
PSE and its predecessors are responsible for environmental remediation at various contaminated sites. These include properties currently and formerly owned by PSE, as well as third party owned properties in which hazardous substances were generated or released. The primary cleanup laws 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, as well as, Polychlorinated Biphenyls (PCB) contaminated 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.
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 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. This would likely remove all existing use authorizations for PCBs in electrical and gas pipeline equipment. As proposed, the ANPRM would mandate a phase out of in-service PCBs through a phased process with full removal achieved by 2025.
The most recent extension indicates that the EPA will issue a final rule in July 2014. At this time, PSE cannot determine what the impacts of this ANPRM will have on its operations but will continue to work closely with the United Solid Waste Activities Group (USWAG) and the American Gas Association (AGA) to monitor developments and advocate for a reasonable approach that would be protective of the environment and cost effective.
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, as well as, other local siting and zoning ordinances. These requirements may potentially require mitigation of environmental impacts to the fullest extent possible 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 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. Recent, pending and potential future environmental law and regulations with the most significant potential impacts to PSE’s operations and costs are described below.
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.
The Tailoring Rule, which became effective January 2, 2011, sets permit levels for GHG emissions in two phases for power plants and other large stationary sources. The ruling limits the amount of GHG emissions a facility can emit by requiring installment of Best Available Control Technology (BACT). Phase I requires existing facilities that emit more than 100,000 tons of emissions per year to comply with the new BACT rules when air permits are renewed or when major modifications are made after January 2011. Phase II, effective July 2011, requires preconstruction permits using BACT for new projects that emit 100,000 tons of emissions per year or existing projects that make major modifications and that emit more than 75,000 tons per year. Currently the EPA has only released BACT guidance for coal technology. The EPA work to determine natural gas turbine BACT guidance is ongoing. Potential impacts on Colstrip are being evaluated and impacts to our gas fleet cannot yet be determined.
On March 27, 2012 EPA proposed a New Source Performance Standard (NSPS) to limit carbon dioxide from new fossil fuel-fired electric generation units. The proposed standard would only apply to new generating units. The EPA did not propose standards for existing fossil fuel power plants, nor did it indicate a timeline for proposing these in the future. The proposed output-based standard for new units is 1,000 pounds of carbon dioxide per MWh.
In June 2013, the EPA's directive contained the following: (a) issue a new proposal for NSPS for new fossil-fired electric generation units no later than September 20, 2013 and issue a final rule in a timely fashion after considering all public comments, as appropriate; (b) issue proposed carbon pollution standards, regulations, or guidelines, as appropriate, for modified, reconstructed, and existing power plants by no later than June 1, 2014; (c) issue final standards, regulations, or guidelines, as appropriate, for modified, reconstructed, and existing power plants by no later than June 1, 2015; and (d) include in the guidelines addressing
exiting power plants a requirement that States submit to the EPA the implementation plans required under section 111(d) of the Clean Air Act and its implementing regulations by no later than June 30, 2016.
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 2012 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.
EPA published the final Mercury and Air Toxics Standard (MATS) in February 2012. The MATS rule establishes numerical emissions limitations at coal-fired power plants for mercury (1.2 lb/TBtu), acid gases, certain toxic metals using a particulate matter surrogate (0.03 lb/MMBtu), sulfur dioxide, and nitrogen oxides. 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 a sieve tray in one of the six scrubbers and will install them in the remaining scrubbers at an estimated cost to PSE of $10.5 million. Testing of the scrubber 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) of Appeals on November 15, 2012. Discovery in the case has begun, and a prehearing conference took place in July 2013. The case has been bifurcated into separate liability and remedy trials set for March and August 2015, respectively. PSE is litigating the allegations set forth in the notices and cannot at this time predict the outcome of this matter.
Coal Combustion Residuals
On June 21, 2010, the EPA issued a proposed rulemaking for the “Identification and Listing of Special Wastes: Disposal of Coal Combustion Residuals (CCR) from Electric Utilities” which proposes different regulatory mechanisms to regulate coal ash. EPA does not have a schedule for issuing a final CCR regulation although a federal court is requiring the EPA to set a specific date for issuance of the final rule.
The EPA proposed three alternative regulations. Under the first two options, coal ash could be regulated as a solid waste under Subtitle D provisions of the Resource Conservation and Recovery Act (RCRA). This would give authority to the states to oversee a set of performance standards for handling and disposal. Coal ash would be listed as non-hazardous but utilities may not be allowed to continue wet handling and the continued use of surface impoundments could be phased out. One of these two options would require significantly less modifications to closed as well as in-use impoundments.
Under the third option, coal ash could be regulated as a hazardous waste under Subtitle C provisions of the RCRA, which would make coal ash subject to a comprehensive program of federally enforceable requirements for waste management and disposal. Regulation under Subtitle C would essentially require the phase-out of wet handling and surface impoundments. The EPA estimates over 500 surface impoundments would be affected by this ruling.
The impact to Colstrip operations and to PSE could range from minimal to significant. Due to the wide range in the options proposed by the EPA, PSE cannot determine the potential impacts with any more certainty at this time. PSE continues to monitor
the developments of the final rule and are advocating for a reasonable, non-hazardous approach that would be both protective of the environment and cost-effective.
EXECUTIVE OFFICERS OF THE REGISTRANTS
The executive officers of Puget Energy as of March 13, 2014 are listed below along with their business experience during the past five years. Officers of Puget Energy are elected for one-year terms.
The executive officers of PSE as of March 13, 2014 are listed below along with their business experience during the past five years. Officers of PSE are elected for one-year terms.
ITEM 1A.
ITEM 1A. RISK FACTORS
The following risk factors, in addition to other factors and matters discussed elsewhere in this report, should be carefully considered. The risks and uncertainties described below are not the only risks and uncertainties that Puget Energy and PSE may face. Additional risks and uncertainties not presently known or currently deemed immaterial also may impair PSE’s business operations. If any of the following risks actually occur, Puget Energy’s and PSE’s business, results of operations and financial conditions would suffer.
RISKS RELATING TO 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.
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, revenue 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.
PSE has additional risks associated with the Washington Commission approved stay out period, which doesn't allow for any general rate case filings to be filed earlier than April 1, 2015 without extraordinary circumstances.
PSE will have additional risks if PSE's costs are not within the pre-approved annual increases in allowed revenue per customer (3.3% for electric customers; 2.2% natural gas customers), as earnings will be below the authorized rate of return and due to the stay out period, PSE cannot file for general rate increases unless it is for emergency rate relief. If PSE earns above its authorized rate of return, PSE will need to share the excess earnings above the threshold of 7.77% with customers. The earnings test is done for each service (electric/natural gas) separately, so the risk would be if PSE over earns on one and under earns on the other service, PSE would still be obligated to share the earnings for that service exceeding the threshold (there is no offset for the service under earning).
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 Company 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:
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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
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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:
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Increased prices for fuel and fuel transportation as existing contracts expire;
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Facility shutdowns due to a breakdown or failure of equipment or processes;
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Disruptions in the delivery of fuel and lack of adequate inventories;
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Labor disputes;
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Inability to comply with regulatory or permit requirements;
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Disruptions in the delivery of electricity;
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Operator error or safety related stoppages;
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New laws or regulations that necessitate significant investments in our plants;
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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;
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Terrorist or other attacks (both cyber-based and/or asset-based); and
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Catastrophic events such as fires, explosions, floods or acts of nature.
If PSE is unable to protect its information technology infrastructure and network against data corruption, cyber-based attacks or network security breaches, its operations could be disrupted.
PSE operates in a highly regulated industry that requires the continued operation of sophisticated information technology systems and network infrastructure. Despite its implementation of security measures, its technology systems may be vulnerable to disability, failures or unauthorized access due to hacking, viruses, acts of war or terrorism and other causes. If our technology systems were to fail or be breached and we were unable to recover in a timely manner, we 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 cyber-based attacks could disrupt our 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 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.
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 costs 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, including air and climate protection, 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.
With respect to endangered species laws, the listing or proposed listing of several species of salmon in the Pacific Northwest is causing a number of changes to the operations of hydroelectric generating facilities on Pacific Northwest rivers, including the Columbia river. These changes could reduce the amount, and increase the cost, of power generated by hydroelectric plants owned by PSE, or in which PSE has an interest, and increase the cost of the permitting process for these facilities.
Under current law, PSE is also generally responsible for any on-site liabilities associated with the environmental condition of the facilities that it currently owns or operates or has previously owned or operated. 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 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 EPA, together with efforts by Congress, have drawn greater attention to this issue at the federal, state and local level. While PSE cannot yet determine costs associated with these or future decisions or potential future legislation, there may be a significant impact on the cost of carbon-intensive coal generation, in particular.
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 revenue and income when weather conditions are milder in winter. In the event that the Company experiences unusually mild winters, results of operations and financial condition could be adversely affected for some classes of customers.
PSE may be adversely affected by extreme events in which PSE is not able to promptly respond and repair the electric and gas infrastructure system.
PSE must maintain an emergency planning and training program to allow PSE to quickly respond to extreme events. Without emergency planning, PSE is subject to availability of outside contractors during an extreme event which may impact the quality of service provided to PSE’s customers. In addition, a slow or ineffective 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.
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 2014 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 we experience a loss in the number of our customers due to municipalization or other related government action. When a town or city establishes its own municipal-owned utility, it acquires our assets and takes over the delivery of energy services that we provide. This 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 PUGET ENERGY AND PSE OPERATIONS
The Company's business is dependent on its ability to successfully access capital.
The Company 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 Puget Energy or PSE are unable to access capital on reasonable terms, their 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. Capital and credit market disruptions, a downgrade of Puget Energy's or PSE's credit rating or the imposition of restrictions on borrowings under their credit facilities in the event of a deterioration of financial ratios, may increase Puget Energy's and PSE’s cost of borrowing or adversely affect the ability to access one or more financial markets.
The amount of the Company's debt could adversely affect its liquidity and results of operations.
Puget Energy and PSE have short-term and long-term debt, and may incur additional debt (including secured debt) in the future. Puget Energy has access to a multi-year $800.0 million revolving credit facility, secured by substantially all of its assets, of which $299.0 million was outstanding as of December 31, 2013. PSE refinanced its credit facilities in February 2013 to two facilities with $1.0 billion in short-term borrowing capability, a five year contract, lower commitment fee rate, less restrictive covenants and an accordion feature that could, upon the banks' approval, increase the size of the facilities to $1.450 billion. In conjunction with the new PSE agreement, the Puget Energy agreement was reduced to a total of $800.0 million. In addition, Puget Energy has issued $1.4 billion in senior secured notes, whereas PSE, as of December 31, 2013 had approximately $3.8 billion outstanding under first mortgage bonds, pollution control bonds, senior notes and junior subordinated notes. The Company's debt level could have important effects on the business, including but not limited to:
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making it difficult to satisfy obligations under the debt agreements and increasing the risk of default on the debt obligations;
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making it difficult to fund non-debt service related operations of the business; and
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limit the Company's financial flexibility, including its 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 the ability to access capital and the ability to hedge in wholesale markets.
Although neither Puget Energy nor PSE has any rating downgrade provisions in its credit facilities that would accelerate the maturity dates of outstanding debt, a downgrade in the Companies’ credit ratings could adversely affect the ability to renew existing or obtain access to new credit facilities and could increase the cost of such facilities. For example, under Puget Energy’s and PSE’s 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.
The Company may be negatively affected by unfavorable changes in the tax laws or their interpretation.
Changes in tax law, related regulations or differing interpretation or enforcement of applicable law by the IRS or other taxing jurisdiction could have a material adverse impact on the Company’s financial statements. The tax law, related regulations and case law are inherently complex. The Company must make judgments and interpretations about the application of the law when determining the provision for taxes. Disputes over interpretations of tax laws may be settled with the taxing authority in examination, upon appeal or through litigation. The Company’s tax obligations include income, real estate, public utility, municipal, sales and use, business and occupation and employment-related taxes and ongoing appeals issues related to these
taxes. These judgments may include reserves for potential adverse outcomes regarding tax positions that may be subject to challenge by the taxing authorities.
Potential legislation and regulatory actions could increase the Company’s costs, reduce the Company’s revenue and cash flow, or otherwise alter the way the Company conducts business.
In July 2010, the Dodd-Frank Wall Street Reform and Consumer Protection Act (Dodd-Frank) was signed into law. Title VII of the Dodd-Frank law gave regulators including the Commodities Futures Trading Commission (CFTC) and the Securities Exchange Commission 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 the Company’s ability to enter into such transactions. The Dodd-Frank amended section 2(h) (7) of the Commodities Exchange Act to provide an elective exemption from the clearing requirements of Title VII of the Dodd-Frank Act 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. The Company has elected to employ the "End-User Exception" to clearing on its applicable treasury department transactions, and will likely employ the End-User Exception to clearing on commodities transactions after applicable final regulations for those transactions are adopted. The Company continues to evaluate the legislation and the CFTC’s implementation of it to determine its impact, if any, on the Company’s hedging program, results of operations and liquidity. The Company is aware that the Dodd-Frank rules will increase recordkeeping and certain administrative costs for applicable transactions, but will not know the full impact of the new legislation until the regulations are finalized and the Company's compliance systems are fully implemented.
RISKS RELATING TO PUGET ENERGY’S CORPORATE STRUCTURE
As a holding company, Puget Energy depends on PSE’s ability to pay dividends.
As a holding company with no significant operations of its own, the primary source of funds for the repayment of debt and other expenses, as well as payment of dividends to its shareholder, is cash dividends PSE pays to Puget Energy. PSE is a separate and distinct legal entity and has no obligation to pay any amounts to Puget Energy, whether by dividends, loans or other payments. The ability of PSE to pay dividends or make distributions to Puget Energy, and accordingly, Puget Energy’s ability to pay dividends or repay debt or other expenses, will depend on PSE’s earnings, capital requirements and general financial condition. If Puget Energy does not receive adequate distributions from PSE, it may not be able to meet its obligations or pay dividends.
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. In addition, 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 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 47.4% at December 31, 2013 and the EBITDA to interest expense was 4.4 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.
ITEM 1B.
ITEM 1B. UNRESOLVED STAFF COMMENTS
None.
ITEM 2.
ITEM 2. PROPERTIES
The principal electric generating plants and underground natural gas storage facilities owned by PSE are described under Item 1, Business - Electric Supply and Gas Supply. PSE owns its transmission and distribution facilities and various other properties. Substantially all properties of PSE are subject to the liens of PSE’s mortgage indentures. The Company’s corporate
headquarters is housed in a leased building located in Bellevue, Washington.
ITEM 3.
ITEM 3. LEGAL PROCEEDINGS
From time to time, the Company is involved in litigation relating to claims arising out of its operations in the normal course of business. The following is a description of legal proceedings that are material to PSE’s operations:
Residential Exchange
The Northwest Power Act, through the Residential Exchange Program (REP), provides access to the benefits of low-cost federal power for residential and small farm customers of regional utilities, including PSE. The program is administered by the BPA. Pursuant to agreements (including settlement agreements) between the BPA and PSE, the BPA has provided payments of REP benefits to PSE, which PSE has passed through to its residential and small farm customers in the form of electricity bill credits.
In 2007, the Ninth Circuit ruled that REP agreements of the BPA with PSE and a number of other investor-owned utilities were inconsistent with the Northwest Power Act. Since that time, those investor-owned utilities, including PSE, the BPA and other parties have been involved in ongoing litigation at the Ninth Circuit relating to the amount of REP benefits paid to utilities, including PSE, for the fiscal year 2002 through fiscal year 2011 period and the amount of REP benefits to be paid going forward.
In July 2011, the BPA, PSE and a number of other parties entered into a settlement agreement (2012 REP Settlement) that by its terms, if upheld in its entirety, would resolve the disputes between BPA and PSE regarding REP benefits paid for fiscal years 2002-2011 and determine REP benefits for fiscal years 2012-2028. In October 2011, certain other parties challenged BPA decisions with regard to its entering into the 2012 REP Settlement agreement. On October 28, 2013, the Ninth Circuit issued an order dismissing this challenge to this settlement. In light of the disposition of this challenge, the stay of the other pending Ninth Circuit litigation regarding REP benefits was lifted in January 2014. In the order lifting the stay, petitioners (unless they move to voluntarily dismiss their petitions) and intervenors (unless they move to voluntarily withdraw) were directed to file a statement explaining which issues, if any, remain pending. Such statements are due on or before April 1, 2014. PSE is unable to determine prior to April 1, if this other pending litigation will continue and, if so, what impact these proceedings may have on PSE. However, the Company believes it is unlikely that any unfavorable outcome would have a material adverse effect on PSE because REP benefits received by PSE are passed through directly to REP customers.
With the Ninth Circuit’s decision affirming the 2012 REP Settlement, PSE will receive approximately $57.0 million plus interests of REP payments owed under a 2008 agreement, which are in addition to scheduled monthly REP benefits received from BPA under the 2012 REP Settlement. These payments will be given back to PSE's residential and small farm customers through a higher residential exchange credit on their bills.
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 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 claims, 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. This lawsuit followed various Notices of Intent to Sue sent to Colstrip owners (including PSE) from the Sierra Club and the MEIC between July and December 2012. Discovery in the case has begun and a prehearing conference took place in July 2013. The case has been bifurcated into separate liability and remedy trials set for October 2014 and August 2015, respectively. PSE is litigating the allegations set forth in the notices and cannot at this time predict the outcome of this matter.
ITEM 4.
ITEM 4. MINE SAFETY DISCLOSURES
Not applicable.
PART II
ITEM 5.
ITEM 5. MARKET FOR REGISTRANT’S COMMON EQUITY, RELATED SHAREHOLDER MATTERS AND ISSUER PURCHASES OF EQUITY SECURITIES
All of the outstanding shares of Puget Energy’s common stock, the only class of common equity of Puget Energy, are held by its direct parent Puget Equico LLC (Puget Equico), which is an indirect wholly-owned subsidiary of Puget Holdings, and are not publicly traded. The outstanding shares of PSE’s common stock, the only class of common equity of PSE, are held by Puget Energy and are not publicly traded.
The payment of dividends on PSE common stock to Puget Energy is restricted by provisions of certain covenants applicable to long-term debt contained in PSE’s mortgage indentures in addition to terms of the Washington Commission merger order. Puget Energy’s ability to pay dividends is also limited by the merger order issued by the Washington Commission as well as by the terms of its credit facilities. For further discussion, see Item 1A, Risk Factors, Risks Relating to Puget Energy’s Corporate Structure and Item 7, Management’s Discussion and Analysis of Financial Condition and Results of Operations included in this report.
From time to time, when deemed advisable and permitted, each of PSE and Puget Energy pay dividends on its common stock. During 2013, 2012 and 2011, each of PSE paid dividends to its parent, Puget Energy, and Puget Energy paid dividends to its parent, Puget Equico, in the amounts shown in Puget Energy's and PSE's Consolidated Statements of Common Shareholder's Equity included in this report.
ITEM 6.
ITEM 6. SELECTED FINANCIAL DATA
The following tables show selected financial data. This information should be read in conjunction with the Management Discussion and Analysis and the audited consolidated financial statements and the related notes, included in Items 7 and 8 of this report, respectively.
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All of the operations of Puget Energy are conducted through its subsidiary PSE. “Predecessor” refers to the operations of Puget Energy and PSE prior to the consummation of the merger. “Successor” refers to the operations of Puget Energy and PSE subsequent to the merger. The merger was accounted for in accordance with Financial Accounting Standards Board (FASB) Accounting Standards Codification (ASC) 805.
ITEM 7.
ITEM 7. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS
The following discussion and analysis should be read in conjunction with the financial statements and related notes thereto included elsewhere in this report on Form 10-K. The discussion contains forward-looking statements that involve risks and uncertainties, such as Puget Energy and PSE 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 report. Except as required by law, neither Puget Energy nor PSE undertakes an obligation to revise any forward-looking statements in order to reflect events or circumstances that may subsequently arise. Readers are urged to carefully review and consider the various disclosures made in this report and in Puget Energy’s and PSE’s other reports filed with the United States Securities and Exchange Commission (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. In 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, 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. Puget Energy accounted for the merger as a business combination and all its assets and liabilities were recorded at fair value as of the merger date. PSE's basis of accounting continues to be on a historical basis and PSE's financial statements do not include any purchase accounting adjustments. Puget Energy and PSE are collectively referred to herein as “the Company.”
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. To meet customer growth, to replace expiring power contracts and to meet Washington state’s renewable energy portfolio standards, PSE is increasing energy efficiency programs to reduce the demand for additional energy generation and is pursuing additional renewable energy production resources (primarily wind) and base load natural gas-fired generation. 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.
The Company's strategy is to be a safe, dependable, and efficient utility. The Company has made a commitment to become world-class in safety for employees, customers and communities; provide exceptional customer service; support and enhance the professional development of the workforce; work with stakeholders to ensure timely and consistent regulatory support; and drive necessary changes to maintain the financial strength of the Company.
These investments and commitments related to utility infrastructure and customer service may give rise to expenditures, which 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 on going forward. The ERF also established a property tax tracker mechanism in which any difference between cash payments and property tax valuation accruals will be deferred and recovered in an annual filing. The ERF filing increased electric general rates by $30.7 million and reduced natural gas rates by $2.0 million on an annual basis beginning July 1, 2013.
The decoupling mechanism allows PSE to recovery costs on a per customer basis rather than on a consumption basis. Included in the decoupling petition was a rate plan that allowed PSE to earn its rate of return over the rate plan period. The rate plan included predetermined annual increases to PSE’s allowed electric and natural gas revenue. This plan, with limited exceptions (Power Cost Only Rate Cases (PCORC) or emergence rate relief), would require PSE not to file a general rate case no sooner than April 1,
2015 and no later than April 1, 2016. Upon implementation of the decoupling mechanism on July 1, 2013, electric and natural gas rates increased $21.4 million and $10.8 million, respectively, on an annual basis. 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 on each year, until the conclusion of PSE’s next general rate case.
In October 2013, PSE completed a PCORC filing which allows PSE to recovery certain generation investments and updates PSE’s overall normalized power supply costs. As a result, PSE decreased electric rates by $10.5 million, annually, effective November 1, 2013.
In October 2013, PSE received approval of its pipeline integrity program that would accelerate and enhance the safety of the natural gas system and ultimately reduce costs. Under the plan, PSE would be allowed to file a tariff revision to recover its costs associated with the acceleration of the replacement of natural gas pipelines with the Washington Commission.
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.
For the year ended December 31, 2013 as compared to the prior year, PSE’s net income was affected by the following four factors: (1) an increase in electric margin; (2) implementation of a property tax tracker mechanism which lowered property tax expense by reducing regulatory lag, thus matching expense with revenues; (3) reduction in amortization expenses primarily due to an increase in regulatory credit related to amortization of Treasury Grant; and (4) a decrease in unrealized gain in derivatives instruments for energy contracts.
Further detail on each of these primary drivers, as well as other factors affecting performance, is set forth in this “Overview” section, as well as in other sections of the Management's Discussion & Analysis.
NON-GAAP FINANCIAL MEASURES
The following discussion includes financial information prepared in accordance with U.S. Generally Accepted Accounting Principles (GAAP), as well as return on equity excluding unrealized loss on derivative instruments (net income plus unrealized loss on derivative instruments divided by average common equity) that is considered a “non-GAAP financial measure.” 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 return on equity excluding unrealized loss on derivative instruments is intended to supplement readers’ understanding of the Company’s operating performance. Return on equity excluding unrealized loss on derivative instrument is used by the Company to determine whether the Company is collecting the appropriate earnings from its customers to allow recovery of investor’s capital. The return on average of monthly averages (AMA) equity is not intended to represent the regulated return on equity. PSE's return on equity may not be comparable to other companies return on equity measures. Furthermore, this measure is not intended to replace return on equity (net income divided by average common equity) as determined in accordance with GAAP as an indicator of operating performance.
The following table presents PSE’s return on equity for 2013 and 2012:
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Equity adjustments are related to removing the impacts of accumulated other comprehensive income (OCI), subsidiary retained earnings and retained earnings of derivative instruments.
*
Not meaningful.
The Company’s 2013 return on equity, excluding derivative instruments, was 8.0%, which is lower than the authorized return on equity primarily due to the following:
•
Utility operations and maintenance expense was $15.6 million higher than the amount allowed in rates for the year ended December 31, 2013. The increase was driven by an increase in costs in electric production, administration and general expenses and customer service expense.
•
Depreciation expense was $36.4 million higher than the amount allowed in rates for the year ended December 31, 2013. The increase was primarily due to additional electric expenditures placed into service.
The Company’s 2012 return on equity, excluding derivative instruments, was 7.7%, which is lower than the authorized return on equity primarily due to the following:
•
Operating revenue was $124.2 million lower than the amount allowed in rates for the year ended December 31, 2012. However, margins increased $27.6 million due to significantly lower power costs.
•
Utility operations and maintenance expense was $18.7 million higher than the amount allowed in rates for the year ended December 31, 2012. The increase was driven by an increase in costs in electric production, administration and general expenses and customer service expense.
•
Depreciation expense was $38.2 million higher than the amount allowed in rates for the year ended December 31, 2012. The increase was primarily due to additional electric expenditures placed into service.
•
Utility rate making process has a delay between incurring expenses and their recovery in rate base. PSE increased ratebase by $416.7 million since its last general rate increase effective May 14, 2012.
Factors and Trends Affecting PSE’s Performance
PSE’s regulatory requirements and operational needs require the investment of substantial capital in 2013 and future years. Because PSE intends to seek recovery of such investments through the regulatory process, its financial results depend heavily upon favorable outcomes from that process. Further, PSE’s financial performance is heavily influenced by general economic conditions in its service territory, which affect customer growth and use-per-customer and thus utility sales, as well as by its customers’ conservation investments, which also tend to reduce energy sales. The principal business, economic and other factors that affect PSE’s operations and financial performance include:
Regulation of PSE Rates and Recovery of PSE Costs
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.
Expedited Rate Filing (ERF)
On February 4, 2013, PSE filed revised tariffs seeking to update its rates established in its base rate proceedings in May 2012 known as an Expedited Rate Filing (ERF). The ERF 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 valuation 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 its delivery-system costs and authority to record accounting entries associated with the mechanisms. After the petition and supporting testimony were filed, the Washington Commission held two technical conferences to allow interested stakeholders to further discuss the proposed decoupling mechanisms. PSE also responded to inquiries of interested stakeholders seeking additional information about the decoupling proposal.
On March 4, 2013, PSE and NWEC, taking this process into account, reached an agreement on certain modifications to the decoupling mechanisms and filed an amended petition and testimony in support of these modifications to the original decoupling proposal. The Washington Commission's regulatory staff (Commission Staff) filed testimony in support of the revised proposal on the same day. 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 general rate case process over the plan period. The rate plan includes predetermined annual increases (K factor) to PSE's allowed electric and gas revenue which are effective January of each year. Under this plan, PSE, with limited exceptions, would be allowed to file its next general rate case 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 PCA and 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% “soft cap” on rate increases. Any amount in excess of the soft cap will be added to the decoupling tracker in subsequent rate periods, subject to a 3.0% soft cap on rate increases in the subsequent year. In addition, PSE and the customers would have shared 50.0% each in any earnings in excess of the authorized rate of return of 7.77%. The customers share of the over earnings will be returned to customers over the subsequent 12 month period beginning May 1 of each year.
TransAlta Centralia Agreement
In 2012, PSE executed a power purchase agreement with TransAlta Centralia for the purchase of up to 380 Megawatt (MW) of coal transition power. PSE filed a petition for approval of the TransAlta Centralia agreement and recovery of related acquisition costs. The Washington Commission issued an order granting PSE's petition which contained conditions that left PSE with a level of uncertainty such that it could terminate the contract. PSE subsequently filed a Petition for Reconsideration of the order with the Washington Commission.
Washington Commission Decision
PSE filed a settlement agreement with the Washington Commission on March 22, 2013. The agreement was intended to settle all issues regarding decoupling, the power purchase agreement with TransAlta Centralia and the ERF which included the property tax tracker. The Washington Commission placed these filings under a common procedural schedule. On June 25, 2013, the Washington Commission issued three final orders resolving the amended decoupling petition, the ERF filing and the Petition for Reconsideration. Order No. 6 rejected the multi-party settlement agreement between PSE, NWEC and Commission Staff due to uncertainty regarding the legality of consolidating the three filings. Order No. 7 approved PSE's ERF filing with a small change to its cost of capital from 7.80% to 7.77% to update long term debt costs. This order also approved the property tax tracker discussed above. In addition, Order No. 7 approved the amended decoupling and rate plan filing as filed by PSE and NWEC on March 4, 2013 with the requirement that PSE update the underlying ERF rates for the change in cost of capital, and with the further condition that PSE and the customers will share 50.0% each in earnings in excess of the 7.77% authorized rate of return. Order No. 8 granted PSE's Petition for Reconsideration, clarifying certain portions of the Washington Commission's original order.
As approved, the ERF filing will produce an additional $30.7 million in annual electric revenue and reduce annual gas revenue by $2.0 million. 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. PSE's 2012 and 2013 property taxes that are not in current rates will be recovered in later years. The decoupling mechanisms will initially produce an additional $21.4 million in annual electric revenue and $10.8 million in annual gas revenue. 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.
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. 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 are scheduled for May 2014.
Electric Rates
PSE 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 is as follows:
PSE had a favorable PCA imbalance for the year ended December 31, 2013, which was $37.8 million below the “power cost baseline” level, $8.9 million of which was apportioned to customers. This compares to a favorable imbalance of $27.4 million for the year ended December 31, 2012, $3.7 million of which was apportioned to customers.
On February 29, 2012, PSE filed proposed Federal Incentive Tracker 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 May 7, 2012, the Washington Commission issued its order in PSE's consolidated electric and natural gas general rate case filed in June 2011, approving a general rate increase for electric customers of $63.3 million or 3.2% annually, and an increase in natural gas rates of $13.4 million or 1.3% annually. The rate increases for electric and 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 January 31, 2013, the Washington Commission approved a rate change to 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 both grants to eligible customers over 11 months beginning February 1, 2013, including grant amortization pass-back of $34.6 million and interest pass-back of $23.8 million. This represents an overall average rate decrease of 2.76%.
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.
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 0.26%.
For additional information, see Note 3 to the consolidated financial statements included in Item 8 of this report.
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 underrecovery of natural gas cost through rates.
On May 7, 2012, the Washington Commission issued its order in PSE's consolidated electric and natural gas general rate case filed in June 2011, approving a general rate increase for electric customers of $63.3 million or 3.2% annually, and an increase in natural gas rates of $13.4 million or 1.3% annually. The rate increases for electric and 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 Washington 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, the difference being recognized as revenue sensitive taxes.
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. The rate adjustment has 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 30, 2013, the Washington Commission approved PSE's Pipeline Replacement Program Plan (PRPP) that would accelerate and enhance the safety of the natural gas system and ultimately reduce costs. Under the PRPP plan, PSE would be allowed to file a tariff revision to recover its costs associated with the acceleration of the replacement of natural gas pipelines with the Washington Commission.
For additional information, see Note 3 to the consolidated financial statements included in Item 8 of this report.
Weather Conditions. Weather conditions in PSE's service territory have a significant 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 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 usage by its residential electric customers in the twelve months ended December 31, 2013, 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 twelve months ended December 31, 2013 was 53.89 degrees, or 1.90 degrees warmer than the same period in the prior year, and 1.25 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 new decoupling mechanisms that went into effect on July 1, 2013 for electric and gas operations will greatly 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 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 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 bill or refund the difference between allowed decoupling revenue and the corresponding actual revenue to affected customers during the following May to April time period.
Effective January 1, 2014, certain high volume natural gas industrial customers rate schedules are excluded from the decoupling mechanism. As a result, PSE will be subject to certain effects of abnormal weather, conservation impacts and changes in customer usage patterns for these customers.
Customer Demand. PSE expects the number of natural gas customers to grow at rates slightly above the number 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.
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 expire in 2018 and Puget Energy's senior secured credit facility expires in 2017. (See discussion on credit facilities in the section entitled “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 byproducts 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, and on measures including, but not limited to, resource planning, remediation, monitoring, pollution control equipment and emissions-related abatement and fees in order to comply with these regulatory requirements.
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 towns or cities 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. As noted in PSE's IRP filed with the Washington Commission, PSE projects that beginning in 2017, its future energy needs will exceed current resources in its supply portfolio. The IRP identifies reductions in contractual supplies of energy and capacity available under certain long-term power purchase agreements, requiring replacement of supplies to meet projected demands. Therefore, PSE’s IRP sets forth a multi-part strategy of implementing energy efficiency programs and pursuing additional renewable resources (primarily wind) and additional base load natural gas-fired generation to meet the growing needs of its customers. If PSE 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.
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 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. 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.
PSE owns a 25% share of Colstrip Unit 4 coal fired plant in eastern Montana. PSE's share of the unit's net maximum capacity is 185.0 MWs. On July 1, 2013, Colstrip Unit 4 was tripped off-line. Upon inspection of the unit, significant damage was observed to the generator which required repairs to the stator, core and rotor. The unit was returned to service in February 2014. PSE's share of the repair costs, which are capital expenditures, was $8.0 million. The repair costs for the plant are covered by insurance and are subject to PSE's share of the deductible of $0.6 million. In addition, power costs increased approximately $14.0 million in 2013. The power costs are subject to the PCA mechanism sharing bands, of which PSE's share of the cost increase was $7.0 million.
Grant County PUD Purchase Power Contract. On February 27, 2014, Grant County PUD discovered a sixty-five foot long, two inch wide crack in a spillway pier at its Wanapum Development Project. PSE is party to a purchased power contract with Grant County PUD, pursuant to which PSE takes 0.8% of the output from the project and pays a proportional share of the operating cost of the project. Grant County PUD has lowered the reservoir level 26 feet below normal for the foreseeable future which also impacts the operations of Chelan County PUD Rock Island Project which is upstream from Wanapum Development Project. An engineering assessment of the crack repairs and water flow protocols are in the early stages of development and it is not possible to predict crack repair nor replacement power costs, if any, at this time. Any additional power cost increases are subject to the Company’s PCA mechanism sharing bands.
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 Credit (REC)s 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 audited consolidated financial statements and the related notes included elsewhere in this document. The following discussion provides the significant items that impacted PSE’s results of operations for the years ended December 31, 2013 and 2012. Set forth below are the consolidated financial results of PSE for the years ended December 31, 2013, 2012 and 2011:
_____________
*
Not meaningful.
Non-GAAP Financial Measures - Electric and Gas Margins
The following discussion includes financial information prepared in accordance with GAAP, as well as two other financial measures, electric margin and gas margin, that are considered “non-GAAP financial measures.” Generally, a non-GAAP financial measure is a numerical measure of a company’s financial performance, financial position or cash flows that exclude (or include) amounts that are included in (or excluded from) the most directly comparable measure calculated and presented in accordance with GAAP. The presentation of electric margin and gas margin is intended to supplement an understanding of PSE’s operating performance. Electric margin and 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 gas margin measures may not be comparable to other companies’ electric margin and gas margin measures. Furthermore, these measures are not intended to replace operating income as determined in accordance with GAAP as an indicator of operating performance.
Electric Margin
The following table displays the details of PSE’s electric margin changes from periods 2012 to 2013 and periods 2011 to 2012. 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.
______________
As reported on PSE’s Consolidated Statement of Income.
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 increased $60.2 million and $127.6 million for the years ended December 31, 2013 and December 31, 2012, respectively. Following is a discussion of significant items that impact electric operating revenue and electric energy costs which are included in electric margin:
2013 compared to 2012
Electric Operating Revenue
Electric operating revenues increased $28.7 million, or 1.3%, to $2,156.9 million from $2,128.2 million for the year ended December 31, 2013 as compared to the same period in 2012. Operating revenue increased $28.7 million primarily due to higher sales to other utilities and marketers of $30.7 million and higher miscellaneous other operating revenue of $23.4 million offset by decoupling revenue over-collection of $15.0 million and lower electric retail sales of $9.4 million. These items are discussed in detail below.
Electric retail sales decreased $9.4 million, or 0.4%, to $2,091.0 million from $2,100.4 million for the year ended December 31, 2013 as compared to the same period in 2012. Electric retail sales decreased due to a net revenue decrease of $16.4 million primarily due to PSE's Federal Incentive Tracker tariff which passes through to customers the benefits of federal income tax incentives with no impact on earnings. The offset is recorded in amortization expense and federal tax expense. The rate decrease was offset by the electric rate increase of 3.2% effective May 14, 2012, the expedited rate filing and the decoupling rate increase of 2.5% which became effective July 1, 2013 and various other pass-through tariff items that have no impact on earnings. The decrease was offset by a net revenue increase of $6.9 million due to higher retail electricity usage of 69,719 MWhs, or 0.3%, primarily due to higher usage by its commercial and industrial electric customers for the year ended December 31, 2013 as compared to the same period in 2012.
Sales to other utilities and marketers increased $30.7 million for the year ended December 31, 2013 as compared to the same period in 2012. The increase was primarily due to an increase in wholesale electricity prices which increased revenue by $25.7 million and an increase in sales volume of 297,973 MWhs, or 21.4% which increased revenue $5.1 million.
Decoupling revenue resulted in an over-collection of $15.0 million for the year ended December 31, 2013 due to higher volumetric revenues over the decoupled revenues per customer under the decoupling mechanism effective July 1, 2013. The offset is recorded in regulatory liability which will be passed back to customers through a rate filing beginning May 1, 2014 over a 12-month period.
Other electric operating revenue increased $23.4 million for the year ended December 31, 2013 as compared to the same period in 2012. For the year ended December 31, 2013, other electric operating revenues increased primarily due to lower losses on non-core gas sales of $16.0 million and higher transmission revenue of $7.1 million.
Electric Energy Costs
Purchased electricity expense decreased $80.4 million, or 12.9%, for the year ended December 31, 2013 as compared to the same period in 2012. The decrease in purchased electricity expense for the year ended December 31, 2013 was primarily the result of a $102.4 million decrease in long-term firm purchases and market purchases. This decrease was partially offset by an increase of $9.4 million due to a market price offset and increase of $7.7 million in transmission expense for the year ended December 31, 2013 as compared to the same period in 2012.
To meet customer demand, PSE economically dispatches resources in its power supply portfolio such as fossil-fuel generation, owned and contracted hydroelectric capacity and energy and long-term contracted power. However, depending principally upon availability of hydroelectric energy, plant availability, fuel prices and/or changing load as a result of weather, PSE may sell surplus power or purchase deficit power in the wholesale market. PSE manages its regulated power portfolio through short-term and intermediate-term off-system physical purchases and sales as well as through other risk management techniques.
Electric generation fuel expense increased $56.4 million, or 27.5%, for the year ended December 31, 2013 as compared to the same period in 2012. The increase was primarily due to a $48.3 million increase in fuel expense at PSE's combustion turbine facilities primarily resulting from an increase in electric generation at combustion turbine facilities of 2,735,066 MWhs, or 104.4%, as compared to the same period in 2012. Also contributing to the increase was a $9.8 million increase in fuel expense at PSE's Colstrip Unit 1 & 2 primarily due to the two plants which were taken offline in 2012 for maintenance for an extended period and reintroduced into production when it was more economical to generate energy at a later point in time. The increase was offset by a decrease of $1.7 million in fuel expense at Colstrip Unit 3 & 4 primarily due to Unit 4, which was shut down for repair and maintenance starting July 2013. Unit 4 returned to service in February 2014.
Residential exchange credits decreased $7.5 million, or 10.2%, for the year ended December 31, 2013 as compared to the same period in 2012 as a result of lower electric residential and farm customer sales volumes associated with the BPA REP. The REP credit is a pass-through tariff item with a corresponding credit in electric operating revenue, with no impact on net income.
2012 compared to 2011
Electric Operating Revenue
Electric operating revenues decreased $19.0 million, or 0.9%, to $2,128.2 million from $2,147.2 million for the year ended December 31, 2012 as compared to the same period in 2011. Operating revenue decreased $19.0 million primarily due to lower electric retail sales of $23.5 million and lower sales to other utilities and marketers of $22.0 million offset by higher miscellaneous other operating revenue of $27.0 million. These items are discussed in detail below.
Electric retail sales decreased $23.5 million, or 1.1%, to $2,100.4 million from $2,123.9 million for the year ended December 31, 2012 as compared to the same period in 2011. Electric retail sales decreased due to a $35.3 million decrease in retail electricity usage of 357,640 MWhs, or 1.7%, primarily due to warmer temperatures in PSE’s service territory during the year ended December 31, 2012 as compared to the same period in the prior year. The actual average temperature during the year ended December 31, 2012 was 52.0 degrees, or 1.3 degrees warmer than the same period in 2011. Although the average temperature during the year ended December 31, 2012 was warmer than the same period in the prior year, the average temperature was 0.7 degrees cooler
when compared to the historical average. Partially offsetting the decrease was an $11.8 million net increase in retail sales due to the electric rate increase effective May 14, 2012 and various pass-through tariff items that have no impact to earnings. The net increase included tariff items, such as the suspension of REC credits in 2011 which contributed an increase of $14.8 million in electric retail sales for the year ended December 31, 2012. The REC credit to customers is offset in other electric operating revenue with no impact to earnings. PSE's customers received credits effective November 1, 2010 through April 30, 2011.
Sales to other utilities and marketers decreased $22.0 million for the year ended December 31, 2012 as compared to the same period in 2011. The decrease was primarily due to a reduction in sales volume of 421,394 MWhs, or 23.3% which decreased revenue $10.6 million and a decline in wholesale electricity prices which decreased revenue by $11.4 million.
Other electric operating revenue increased $27.0 million for the year ended December 31, 2012 as compared to the same period in 2011. For the year ended December 31, 2012, other electric operating revenues increased primarily due to lower losses on non-core gas sales of $37.1 million and a reduction to revenue offsets which contributed increases of $80.3 million in revenue related to PTCs, which are deferred until PSE utilizes the tax credit on its tax return. Partially offsetting the increase is a decrease in REC revenue of $93.5 million. As discussed above, REC revenue is an offset of the REC credit provided to PSE’s customers in electric retail sales with no impact to earnings.
Electric Energy Costs
Purchased electricity expense decreased $149.7 million, or 19.4%, for the year ended December 31, 2012 as compared to the same period in 2011. The decrease in purchased electricity expense for the year ended December 31, 2012 was primarily the result of a decrease of $182.6 million related to the expiration of long-term firm purchase contracts that were replaced with market price power and wind generation. In addition, a decrease of $6.2 million was due to a decrease in the overrecovery of power costs, which is shared with customers in accordance with the PCA mechanism, for the year ended December 31, 2012 as compared to the year ended December 31, 2011. Partially offsetting this decrease was a $25.1 million increase related to energy purchase agreements and $8.4 million in additional costs recognized in order to offset the deferral of variable costs related to the Lower Snake River project prior to the inclusion of the plant in rates.
To meet customer demand, PSE economically dispatches resources in its power supply portfolio such as fossil-fuel generation, owned and contracted hydroelectric capacity and energy and long-term contracted power. However, depending principally upon availability of hydroelectric energy, plant availability, fuel prices and/or changing load as a result of weather, PSE may sell surplus power or purchase deficit power in the wholesale market. PSE manages its regulated power portfolio through short-term and intermediate-term off-system physical purchases and sales as well as through other risk management techniques.
Electric generation fuel expense increased $5.5 million, or 2.7%, for the year ended December 31, 2012 as compared to the same period in 2011. The increase was primarily due to increased generation from PSE's combustion turbine facilities due to the decrease in hydroelectric and wind generation of 904,423 MWhs, or 11.9%, and the decrease in electric generation at the Colstrip facility of 401,059 MWhs, or 9.5% as compared to the same period in 2011. As a result of lower wholesale gas prices it was more economical to generate gas fired electricity from PSE's combustion turbine facilities resulting in an increase in natural gas costs of $8.2 million as compared to the same period in 2011. Offsetting the increase was $2.7 million decrease due to the reduction in Colstrip facility's generation. The decrease in electric generation at the Colstrip facility was primarily due to two coal plants that were taken offline for maintenance and reintroduced at a later point in time into production as other sources of electric generation were considered more economical.
Residential exchange credits decreased $2.4 million, or 3.4%, for the year ended December 31, 2012 as compared to the same period in 2011 as a result of lower electric residential and farm customer sales volumes associated with the BPA REP. 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
The following table displays the details of PSE’s natural gas margin changes from 2012 to 2013 and 2011 to 2012. 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.
___________________
As reported on PSE’s Consolidated Statement of Income.
Gas margin does not include any allocation for amortization/depreciation expense or electric generation operations and maintenance expense.
*
Percent change not applicable or meaningful.
Natural gas margin decreased $7.3 million for the year ended December 31, 2013 and increased $0.7 million for the year ended December 31, 2012. Following is a discussion of significant items that impact gas operating revenue and gas energy costs which are included in natural gas margin:
2013 compared to 2012
Gas Operating Revenue
Gas operating revenue decreased $57.7 million, or 5.3%, to $1,028.4 million from $1,086.1 million for the year ended December 31, 2013 as compared to the same period in 2012. The decrease in gas operating revenue of $57.7 million was due primarily to lower natural gas retail sales revenue of $53.9 million as a result of lower natural gas costs. These items are discussed in detail below.
Natural gas retail sales revenue decreased $53.9 million, or 5.1%, to $1,003.3 million from $1,057.2 million for the year ended December 31, 2013 as compared to the same period in 2012. The decrease in natural gas retail sales for the year ended December 31, 2013 as compared to the same period in 2012 was primarily due to a net $56.0 million decrease mostly related to the PGA rate decrease effective November 1, 2012. The PGA mechanism passes through to customers increases or decreases in the natural gas supply portion of the natural gas service rates based upon changes in the price of natural gas purchased from producers and wholesale marketers or changes in natural gas pipeline transportation costs. PSE's net income is not affected by changes under the PGA mechanism. Also contributing was a decrease of $6.9 million related to gas conservation revenues as a result of an approved accounting petition authorizing PSE to recover the costs associated with the Company's 2012 gas conservation programs via transfers from amounts deferred for the over-recovery of commodity costs in the Company's PGA commodity account. This had no impact on earnings as conservation expense increased by the same amount. Partially offsetting these decreases was an increase of 7.7 million in therm sales, or 0.9%, that resulted in a $9.0 million revenue increase.
Decoupling revenue resulted in an over-collection of $5.2 million for the year ended December 31, 2013 due to higher volumetric revenues over the decoupled revenues per customer under the decoupling mechanism effective July 1, 2013. The offset is recorded in regulatory liability which will be passed back to customers through a rate filing beginning May 1, 2014 over a 12-month period.
Gas Energy Costs
Purchased gas expense decreased $50.4 million, or 9.4%, for the year ended December 31, 2013 as compared to the same period in 2012. The decrease was primarily due to lower natural gas costs reflected in PGA rates which were effective November
1, 2012. Partially offsetting the decrease was an increase in customer usage of 0.9% for the year ended December 31, 2013 as compared to the same period in 2012.
The PGA mechanism provides the rates used to determine natural gas costs based on customer usage. The rate decrease was the result of decreasing costs of wholesale natural gas. The PGA mechanism allows PSE to recover expected natural gas supply and transportation costs and defer, as a receivable or liability, any natural gas supply and transportation costs that exceed or fall short of this expected 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 underrecovery of natural gas cost through rates. A payable balance reflects overrecovery of natural gas cost through rates. The PGA mechanism payable balance at December 31, 2013 was $5.9 million, which will be recovered from customers through a future PGA rate filing.
2012 compared to 2011
Gas Operating Revenue
Gas operating revenue decreased $82.8 million, or 7.1%, to $1,086.1 million from $1,168.9 million for the year ended December 31, 2012 as compared to the same period in 2011. The decrease in gas operating revenue of $82.8 million was due primarily to lower natural gas retail sales revenue of $82.4 million due to lower natural gas costs. These items are discussed in detail below.
Natural gas retail sales revenue decreased $82.4 million, or 7.2%, to $1,057.2 million from $1,139.6 million for the year ended December 31, 2012 as compared to the same period in 2011. The decrease in natural gas retail sales for the year ended December 31, 2012 as compared to the same period in 2011 was primarily due to a decrease of 50.8 million in therm sales, or 5.3%, due to warmer temperatures that resulted in a $60.6 million revenue decrease. The actual average temperature during the year ended December 31, 2012 was 52.0 degrees, or 1.3 degrees warmer than the same period in the prior year. Although the average temperature during the year ended December 31, 2012 was warmer than the same period in the prior year, the temperature was 0.7 degrees cooler when compared to the historical average. Contributing to the decrease was a net $28.5 million decrease related to the PGA rate decreases effective November 1, 2011 and November 1, 2012. The PGA rate decreases were offset by the gas rate increases effective April 1, 2011 and May 14, 2012. Partially offsetting these decreases was a $6.9 million increase in retail sales related to gas conservation revenues with no impact to earnings. The PGA mechanism passes through to customers increases or decreases in the natural gas supply portion of the natural gas service rates based upon changes in the price of natural gas purchased from producers and wholesale marketers or changes in natural gas pipeline transportation costs. PSE's net income is not affected by changes under the PGA mechanism.
Gas Energy Costs
Purchased gas expense decreased $83.5 million, or 13.4%, for the year ended December 31, 2012 as compared to the same period in 2011. The decrease was primarily due to lower natural gas costs reflected in PGA rates which were effective November 1, 2011 and November 1, 2012. Also contributing to the expense decrease was a reduction in customer usage of 5.3% as a result of warmer temperatures for the year ended December 31, 2012, as compared to the same period in 2011.
The PGA mechanism provides the rates used to determine natural gas costs based on customer usage. The rate decrease was the result of decreasing costs of wholesale natural gas. The PGA mechanism allows PSE to recover expected natural gas supply and transportation costs and defer, as a receivable or liability, any natural gas supply and transportation costs that exceed or fall short of this expected 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 underrecovery of natural gas cost through rates. A payable balance reflects overrecovery of natural gas cost through rates. The PGA mechanism payable balance at December 31, 2012 was $32.6 million, which will be recovered from customers through a future PGA rate filing.
2013 compared to 2012
Other Operating Expenses
Net unrealized gain on derivative instruments decreased $20.2 million, or 17.0%, for the year ended December 31, 2013 as compared to the same period in 2012. The decrease was due to a decline in the settlement of contracts with unrealized losses from previous periods totaling $128.1 million, partially offset by an increase in gains due to changes in price totaling $107.9 million. Average 3-year forward prices of wholesale electricity and natural gas increased by 9.4% and 1.1%, respectively, for the year ended December 31, 2013.
Utility operations and maintenance expense increased $17.2 million, or 3.3%, for the year ended December 31, 2013 as compared to the same period in 2012. The increase was primarily driven by increases of $7.3 million in administration and general expenses, $4.3 million in electric transmission and distribution expenses, and $4.1 million in low income assistance program expenses for year ended December 31, 2013.
Depreciation expense increased $26.4 million, or 7.8%, for the year ended December 31, 2013 as compared to the same period in 2012. The increase was primarily due to additional capital expenditures placed into service, net of retirements, such as the Lower Snake River (LSR) wind generation facility which began commercial operations on February 29, 2012, Snoqualmie Falls Plant and the Baker hydroelectric generating facility additions which went into service in 2013.
Amortization expense decreased $31.2 million, or 55.9%, for the year ended December 31, 2013 as compared to the same period in 2012. The decrease was primarily due to an increase in regulatory credit related to amortization of Treasury Grants of $39.8 million. Partially offsetting the decrease was an $8.2 million increase in computer software system amortization for the year ended December 31, 2013 related to a new Customer Information System.
Conservation amortization decreased $8.3 million, or 7.3%, for the year ended December 31, 2013 as compared to the same period in 2012. The decrease was primarily due to a reduction of $11.1 million in gas conservation amortization for the year ended December 31, 2013. During the second quarter of 2012, an approved accounting petition authorized PSE to recover the costs associated with the Company's 2012 gas conservation programs via transfers from amounts deferred for the over-recovery commodity costs in the Company's PGA commodity account. Conservation amortization is a pass-through tariff item with no impact on earnings. The decrease was offset by an increase of $2.8 million in electric conservation amortization for the year ended December 31, 2013.
Taxes other than income taxes decreased $16.1 million, or 5.1%, for the year ended December 31, 2013 as compared to the same period in 2012. The decrease was primarily due to a reduction of $22.1 million in property taxes associated with the tracker mechanism approved in June 2013, and $4.7 million related to Montana property tax refund for the year ended December 31, 2013 as compared to the same period in 2012.
Other Income, Interest Expense and Income Tax Expense
Other income decreased $10.4 million, or 21.1%, for the year ended December 31, 2013 as compared to the same period in 2012. The decrease for the year ended December 31, 2013, was primarily due to decreases of $9.5 million in AFUDC equity income, and $1.1 million in interest and dividend income.
Interest expense increased $25.3 million, or 11.3%, for the year ended December 31, 2013 as compared to the same period in 2012. The increase was primarily due to an increase of $19.6 million in interest expense associated with LSR Treasury Grant regulatory liability and a decrease of $11.0 million related to the debt component of AFUDC primarily due to the decrease in average construction work in process. The increase was partially offset by a decrease of $3.5 million in debt issuance cost amortization for the increase primarily because PSE adjusted its revolving credit facilities in February 2013.
Income tax expense increased $11.6 million, or 7.8%, for the year ended December 31, 2013 as compared to the same period in 2012. The increase was primarily related to higher pre-tax income.
Once PSE becomes taxable, it will use its tax net operating loss carryforward to reduce the need for tax payments. PSE currently projects that it will use its tax net operating losses over the next couple of years, under current tax laws. Once the tax net operating losses are utilized, PSE will begin utilizing its production tax credit carryforward. See Note 13, Income Taxes, for further details.
2012 compared to 2011
Other Operating Expenses
Net unrealized gain on derivative instruments increased by $173.3 million to a net gain of $119.1 million for the year ended December 31, 2012 as compared to a loss of $54.1 million during the same period in 2011. The net gain is primarily due to the settlement of contracts with unrealized losses from previous periods which resulted in gains. These gains are offset by losses due to declining natural gas and wholesale electricity prices. Forward prices of electricity and natural gas decreased by 9.0% and 6.3%, respectively, for the year ended December 31, 2012.
Utility operations and maintenance expense increased $14.8 million, or 3.0%, for the year ended December 31, 2012 as compared to the same period in 2011. The increase was primarily driven by increases in customer service expenses of $3.2 million, $2.6 million in administration and general expenses and $7.4 million in electric transmission and distribution expenses for year ended December 31, 2012. The increase in electric transmission and distribution expense was due primarily to the January storm. Additionally, PSE deferred approximately $60.4 million in transmission and distribution expenses related to the January 2012 winter storm as a regulatory asset for future recovery.
Depreciation expense increased $38.4 million, or 12.8%, for the year ended December 31, 2012 as compared to the same period in 2011. The increase was primarily due to additional capital expenditures placed into service, net of retirements, such as the Lower Snake River wind generation facility.
Amortization expense decreased $16.6 million, or 22.9%, for the year ended December 31, 2012 as compared to the same period in 2011. The decrease was primarily due to reductions of $3.5 million for the year ended December 31, 2012 related to the Goldendale electric generating facility (Goldendale) thermal facility deferred costs being fully amortized in 2011 and $3.8
million decrease in common plant amortization. Additionally, a $9.4 million decrease for the year ended December 31, 2012 was due to the Lower Snake River wind generation facility.
Conservation amortization increased $6.5 million, or 6.1%, for the year ended December 31, 2012 as compared to the same period in 2011. The increase was due to an approved accounting petition authorizing PSE to recover costs associated with the Company's current 2012 gas conservation programs via transfers from amounts deferred for the over-recovery commodity costs in the Company's PGA commodity account. Conservation amortization is a pass-through tariff item with no impact on earnings.
Other Income, Interest Expense and Income Tax Expense
Other income decreased $9.0 million, or 15.5%, for the year ended December 31, 2012 as compared to the same period in 2011. The decrease for the year ended December 31, 2012, was primarily due to decreases of $10.2 million in AFUDC equity income, $15.9 million in regulatory interest, and $3.0 million of miscellaneous items. Partially offsetting the decrease for the year ended December 31, 2012 is an increase due to the carrying costs associated with the Lower Snake River wind generating facility accruing interest income of $20.3 million, as authorized by the Washington Commission.
Other Expense increased $6.4 million, or 118.8%, for the year ended December 31, 2012 as compared to the same period in 2011. The increase was primarily due to a $2.4 million increase related to customer credits resulting from the outages due to the January 2012 winter storm and $2.5 million related to civic affiliated activities.
Interest expense increased $23.3 million, or 11.6%, for the year ended December 31, 2012 as compared to the same period in 2011. The increase was primarily due to an increase in long term debt which contributed $11.3 million for the year ended December 31, 2012. Also contributing to the increase is a $7.7 million decrease in debt component of AFUDC and a $3.8 million increase in other interest for the year ended December 31, 2012.
Income tax expense increased $71.2 million, or 91.1%, for the year ended December 31, 2012 as compared to the same period in 2011. The increase was primarily related to higher pre-tax income.
Puget Energy
All the operations of Puget Energy are conducted through its subsidiary PSE. Puget Energy’s net income for the years ended December 31, 2013, 2012 and 2011 was as follows:
_____________
Puget Energy’s interest expense includes elimination adjustments of intercompany interest on short-term debt.
*
Percent change not applicable or meaningful.
2013 compared to 2012
Summary Results of Operations
Puget Energy’s net income for 2013 was $285.7 million with operating revenue of $3,187.3 million as compared to net income of $273.8 million with operating revenue of $3,215.2 million for 2012. The following are significant factors that impacted Puget Energy’s net income which are not included in PSE’s discussion:
Net unrealized gain on derivative instruments decreased $10.6 million for the year ended December 31, 2013 as compared to the same period in 2012, due to the effects of purchase accounting on derivative contracts in other comprehensive income of $8.4 million and the fair value amortization of Normal Purchase Normal Sale (NPNS) derivative contracts of $2.2 million.
Income related to non-utility expense and other increased $6.6 million for the year ended December 31, 2013 as compared to the same period in 2012, due primarily to pension expense.
Income related to unhedged interest rate swap increased $6.7 million to an income of $2.4 million for the year ended December 31, 2013 from an expense of $4.3 million, as compared to the same period in 2012. Due to swap balance reductions in February and May, 2012, the interest rate swap expense decreased by $19.0 million for the year ended December 31, 2013 as compared to the same period in 2012. Additionally, mark-to-market gains on non-hedging interest rate derivative decreased by $12.3 million.
Interest expense decreased $14.3 million for the year ended December 31, 2013 as compared to the same period in 2012. The decrease was primarily due to a decrease of $20.8 million in interest expense related to hedged interest rate swap contracts, a write-off of the unamortized issuance costs of $13.2 million for the three months ended March 31, 2012, related to the retirement of a five-year term loan, a decrease of $5.8 million in interest expense related to Puget Energy's revolving senior secured credit facility as its balance was reduced by $135.0 million in 2013, and an increase of $3.0 million in mark-to-market gains on hedged interest rate swap contracts. The decrease was partially offset by a write off of the unamortized fair value adjustment and debt issuance cost of $18.0 million related to PSE's Pollution Control Bonds, and an increase of $11.5 million in interest expense related to the senior secured notes of $450.0 million issued on June 15, 2012.
Income tax benefit decreased $6.1 million for the year ended December 31, 2013 as compared to the same period in 2012, due primarily to a lower pre-tax loss.
2012 compared to 2011
Summary Results of Operations
Puget Energy’s net income for 2012 was $273.8 million with operating revenue of $3,215.2 million as compared to net income of $123.3 million with operating revenue of $3,318.8 million for 2011. The following are significant factors that impacted Puget Energy’s net income which are not included in PSE’s discussion:
Net unrealized gain on derivative instruments decreased $28.2 million for the year ended December 31, 2012 as compared to the same period in 2011, due to the effects of purchase accounting on derivative contracts in other comprehensive income of $18.7 million and the fair value amortization of NPNS derivative contracts of $9.5 million.
Non-utility expense and other costs increased $7.5 million for the year ended December 31, 2012 as compared to the same period in 2011, due primarily to pension expense.
Unhedged interest rate derivative expense decreased $24.3 million for the year ended December 31, 2012 as compared to the same period in 2011. The decrease was primarily due to a gain of $10.4 million related to the mark-to-market on the outstanding interest rate swaps. Additionally, in February and May, 2012 the outstanding interest rate swap balances were reduced by $277.4 million and $550 million, respectively; resulting in a decrease of $13.9 million in interest expense.
CAPITAL RESOURCES AND LIQUIDITY
Capital Requirements
Contractual Obligations and Commercial Commitments
The following are PSE’s and Puget Energy’s aggregate contractual obligations as of December 31, 2013:
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Energy purchase contracts were entered into as part of PSE’s obligation to serve retail electric and natural gas customers’ energy requirements. As a result, costs are generally recovered either through base retail rates or adjustments to retail rates as part of the power and natural gas cost adjustment mechanisms.
For individual long-term debt maturities, see Note 6 to the consolidated financial statements included in Item 8 of this report. For Puget Energy the amount above excludes the fair value adjustments related to the merger.
As of December 31, 2013, PSE has a revolving credit facility with Puget Energy in the form of a promissory note to borrow up to $30.0 million of which $29.6 million was drawn.
As of December 31, 2013, PSE had credit facilities totaling $1.0 billion and no amount had been drawn. These facilities consisted of $650.0 million to fund operating expenses and $350.0 million 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 new 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 December 31, 2013, one letter of credit totaling $3.0 million in support of contracts was outstanding under the facility, and $162.0 million was outstanding under the commercial paper program. A $1.0 million letter of credit was issued under PSE's $350.0 million facility supporting energy hedging. PSE’s $3.0 million letter of credit in support of a long-term transmission contract and $1.0 million letter of credit in support of energy hedging are considered to be outside of the credit agreement.
Represents operational agreements, settlements and other contractual obligations with respect to generation, transmission and distribution facilities. These costs are generally recovered through base retail rates.
For additional information, see Note 8 to the consolidated financial statements included in Item 8 of this report.
Pension and other benefit expected contributions represent PSE’s estimated cash contributions to the pension plan through 2023.
As of December 31, 2013, Puget Energy had incurred a $299.0 million draw under its $800.0 million Puget Energy senior secured revolving credit facility.
The following are PSE’s and Puget Energy’s aggregate availability under commercial commitments as of December 31, 2013:
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As of December 31, 2013, PSE had credit facilities totaling $1.0 billion and no amount had been drawn. These facilities consisted of $650.0 million to fund operating expenses and $350.0 million 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 new 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 December 31, 2013, one letter of credit totaling $3.0 million in support of contracts was outstanding under the facility, and $162.0 million was outstanding under the commercial paper program. A $1.0 million letter of credit was issued under PSE's $350.0 million facility supporting energy hedging. PSE’s $3.0 million letter of credit in support of a long-term transmission contract and $1.0 million letter of credit in support of energy hedging are considered to be outside of the credit agreement.
As of December 31, 2013, PSE had a revolving credit facility with Puget Energy in the form of a promissory note to borrow up to $30.0 million of which $29.6 million was drawn.
As of December 31, 2013, Puget Energy had incurred a $299.0 million draw under its $800.0 million Puget Energy revolving senior secured credit facility. The Puget Energy revolving credit facility also has an accordion feature that, upon the banks' approval, would increase the size of the facility to $1.3 billion. All other terms and conditions of that facility remain unchanged.
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 AFUDC, totaled $567.9 million in 2013. Presently planned utility construction expenditures, excluding equity AFUDC, are as follows:
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 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 exceeds 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 year ended December 31, 2013 increased by $37.8 million from $797.9 million to $835.7 million during 2013. The increase in cash flow was primarily the result of the following increases:
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An increase related to other long term liabilities of $76.2 million.
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In 2013, there was approximately $9.5 million of storm costs compared to $71.5 million of cash outflow for costs related to the January 2012 winter storm which increased cashflow.
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An increase related to regulatory liabilities of $36.0 million, primarily due to over collection of the decoupling mechanism and renewable gas sales.
The increase in cash generated from operating activities in 2013 described above was primarily offset by cash decreases of $120.7 million reduction in cash collections and a $33.3 million decrease in gas purchase adjustment.
In addition, non cash items increased approximately $36.1 million related to the fair value adjustment of derivative instruments and deferred income taxes; this was partially offset by a decrease in items such as depreciation and amortization, of approximately $13.1 million.
Puget Energy
Cash generated from operations for the year ended December 31, 2013 was $765.9 million, a decrease of $16.8 million from the $782.7 million generated during the year ended December 31, 2012. The net decrease was offset by a $37.8 million increase from the cash provided by the operating activities of PSE as previously discussed. As a result of the merger with Puget Holdings in February 2009, $34.2 million in derivative settlement payments were reclassified to financing activities for the year ended December 31, 2013 as compared to $92.7 million during the same period in 2012, resulting in a decrease in operating cash flows of $58.4 million. This decrease was due to a decline in the number of contracts settled during 2013 as compared to the prior period. These contracts represent proceeds received from derivative instruments that included financing elements at the merger date.
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.
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.
As of December 31, 2013 and 2012, PSE had $162.0 million and $181.0 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 2013 and 2012 was 3.93%, and 6.49%, respectively. As of December 31, 2013, PSE and Puget Energy had several committed credit facilities that are described below.
Puget Sound Energy Credit Facilities
On February 4, 2013, PSE entered into two new unsecured revolving credit facilities and terminated its previous three credit facilities. The new credit facilities 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 new credit facilities also have an accordion feature that, upon the banks' approval, would increase the total size of these facilities to $1.450 billion.
The credit agreements for these two replacement credit facilities contain similar terms and conditions and are syndicated among numerous lenders and mature in February 2018. The credit agreements contain usual and customary affirmative and negative covenants that, among other things, place limitations on PSE's ability to incur additional indebtedness and liens, issue equity, pay dividends, transact with affiliates and make asset dispositions and investments. 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, 2013, PSE was in compliance with all applicable covenants as noted above.
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 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 December 31, 2013, no amount was drawn and outstanding under PSE’s $650.0 million liquidity facility. One letter of credit in the amount of $3.0 million in support of contracts was outstanding under the facility, and $162.0 million was outstanding under the commercial paper program. One letter of credit in the amount of $1.0 million was outstanding under the $350.0 million facility supporting energy hedging.
Demand Promissory Note. On June 1, 2006, PSE entered into a revolving credit facility with 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, 2013, the outstanding balance of the Note was $29.6 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, 2013, Puget Energy maintained an $800.0 million five-year revolving senior secured credit facility. The Puget Energy revolving senior secured credit facility also has an accordion feature that, upon the bank’s approval, would increase the size of the facility to $1.3 billion.
The five-year revolving senior secured credit facility contains usual and customary affirmative and negative covenants. The agreement also contains two financial covenants based on the following ratios: Group Funds From Operations (FFO) Coverage Ratio and Maximum Leverage Ratio, as defined in the agreement governing the senior secured credit facility. As of December 31, 2013, Puget Energy was in compliance with all applicable covenants as noted above.
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, 2013, $299.0 million was drawn and outstanding under the facility, the spread over LIBOR was 1.75% and the commitment fee was 0.30%. Puget Energy entered into interest rate swap contracts to manage the interest rate risk associated with the credit facility (see Note 7 and the "Interest Rate Risk" section in Item 3).
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, 2013, approximately $469.6 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 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 47.4% at December 31, 2013 and the EBITDA to interest expense was 4.4 to one 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.
Puget Energy’s ability to pay dividends is also limited by the merger order issued by the Washington Commission as well as by the terms of its credit facility. 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. At December 31, 2013, the EBITDA to interest expense was 2.9 to one for the 12 months then ended.
At December 31, 2013, 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, at December 31, 2013, PSE could issue:
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Approximately $1.8 billion of additional first mortgage bonds under PSE’s electric mortgage indenture based on approximately $2.9 billion of electric bondable property available for issuance, subject to an interest coverage ratio limitation of 2.0 times net earnings available for interest (as defined in the electric utility mortgage), which PSE exceeded at December 31, 2013; and
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Approximately $319.0 million of additional first mortgage bonds under PSE’s natural gas mortgage indenture based on approximately $531.7 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 December 31, 2013.
At December 31, 2013, PSE had approximately $6.9 billion in electric and natural gas ratebase to support the interest coverage ratio limitation test for net earnings available for interest.
Upon approval of the merger in 2009, 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 December 31, 2013.
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, 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.
On May 23, 2013, PSE refinanced $161.9 million of its Pollution Control Revenue Refunding 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.
Other
Critical Accounting Policies And Estimates
The preparation of financial statements in conformity with GAAP requires that management apply accounting policies and make estimates and assumptions that affect results of operations and the reported amounts of assets and liabilities in the financial statements. The following accounting policies represent those that management believes are particularly important to the financial statements and that require the use of estimates, assumptions and judgment to describe matters that are inherently uncertain.
Revenue Recognition. Operating utility revenue is recognized when the basis of service is rendered, which includes estimated unbilled revenue. 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.
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.
Regulatory Accounting. As a regulated entity of the Washington Commission and the FERC, PSE prepares its financial statements in accordance with the provisions of ASC 980, “Regulated Operations” (ASC 980). The application of ASC 980 results in differences in the timing and recognition of certain revenue and expenses in comparison with businesses in other industries. The rates that are charged by PSE to its customers are based on cost base regulation reviewed and approved by the Washington Commission and the FERC. Under the authority of these commissions, PSE has recorded certain regulatory assets and liabilities at December 31, 2013 in the amount of $895.7 million and $697.5 million, respectively, and regulatory assets and liabilities at December 31, 2012 of $936.2 million and $628.9 million, respectively. Such amounts are amortized through a corresponding liability or asset account, respectively, with no impact to earnings. PSE expects to fully recover its regulatory assets and liabilities through its rates. If future recovery of costs ceases to be probable, PSE would be required to write off these regulatory assets and liabilities. In addition, if PSE determines that it no longer meets the criteria for continued application of ASC 980, PSE could be required to write off its regulatory assets and liabilities related to those operations not meeting ASC 980 requirements.
Also encompassed by regulatory accounting and subject to ASC 980 are the PCA and PGA mechanisms. The PCA and PGA mechanisms mitigate the impact of commodity price volatility upon the Company and are approved by the Washington Commission. The PCA mechanism provides for a sharing of costs that vary from baseline rates over a graduated scale. For further discussion regarding the PCA mechanism, see Electric Regulation and Rates within Item 1. Business - Regulation and Rates of this report. The increases and decreases in the cost of natural gas supply are reflected in customers' bills through the PGA
mechanism. PSE expects to fully recover these regulatory assets through its rates. However, both mechanisms are subject to regulatory review and approval by the Washington Commission on a periodic basis.
Goodwill. On February 6, 2009, Puget Holdings completed its merger with Puget Energy. Puget Energy remeasured the carrying amount of all its assets and liabilities to fair value, which resulted in 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 most recent annual impairment test as of October 1, 2013. The fair value of Puget Energy’s reporting unit was estimated using the weighted-averages from an income valuation method, or discounted cash flow method, and a market valuation approach. These valuations required significant judgments, including: (1) estimation of future cash flows, which is dependent on internal forecasts, (2) estimation of the long-term rate of growth for Puget Energy’s business, (3) estimation of the useful life over which cash flows will occur, (4) the selection of utility holding companies determined to be comparable to Puget Energy, and (5) the determination of an appropriate weighted-average cost of capital or discount rate.
Management estimated the fair value of Puget Energy’s equity to be approximately $4.3 billion at the October 1, 2013 measurement date for the annual test of goodwill impairment. The carrying value of Puget Energy’s equity was approximately $3.5 billion with the excess of the fair value over the carrying value representing 21.0% or $743.0 million.
The income approach and the market approach valuations resulted in Puget Energy equity values of $4.2 billion and $4.4 billion, respectively. The result of the income approach was very sensitive to long-term cash flow growth rates applicable to periods beyond management’s five-year business plan and financial forecast period and the weighted-average cost of capital assumptions of 2.7% and 7.0%, respectively.
The following table summarizes the results of the income valuation method:
Derivatives. ASC 815, “Derivatives and Hedging” (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. The Company 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 NPNS exception to derivative accounting rules. Generally, NPNS applies to contracts with creditworthy counterparties, for which physical delivery is probable and in quantities that will be used in the normal course of business. Power purchases designated as NPNS must meet additional criteria to determine if the transaction is within PSE’s forecasted load requirements and if the counterparty owns or controls energy resources within the western region to allow for physical delivery of the energy. PSE may enter into financial fixed 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. Natural gas derivative contracts qualify for deferral under ASC 980 due to the PGA mechanism.
On July 1, 2009, Puget Energy and PSE elected to de-designate all energy related derivative contracts previously recorded as cash flow hedges for the purpose of simplifying their financial reporting. 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 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.
PSE values derivative instruments based on daily quoted prices from an independent external pricing service. The Company regularly confirms the validity of pricing service quoted prices (e.g. Level 2 in the fair value hierarchy) used to value commodity contracts to the actual prices of commodity contracts entered into during the most recent quarter. When external quoted market prices are not available for derivative contracts, PSE uses a valuation model that uses volatility assumptions relating to future energy prices based on specific energy markets and utilizes externally available forward market price curves. All derivative instruments are sensitive to market price fluctuations that can occur on a daily basis. The Company is focused on commodity price exposure and risks associated with volumetric variability in the natural gas and electric portfolios. It is not engaged in the business of assuming risk for the purpose of speculative trading. The Company economically hedges open natural gas and electric positions to reduce both the portfolio risk and the volatility risk in prices. The exposure position is determined by using a probabilistic risk system that models 250 simulations of how the Company’s natural gas and power portfolios will perform under various weather, hydrological and unit performance conditions.
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, 2013, Puget Energy had interest rate swap contracts outstanding related to its long-term debt. For additional information, see Item 7A
ITEM 7A. 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 is focused on the commodity price exposure and risks associated with volumetric variability in the natural gas and electric portfolios and related effects noted above. It is not engaged in the business of assuming risk for the purpose of speculative trading. PSE hedges open gas and electric positions to reduce both the portfolio risk and the volatility risk in prices. The exposure position is determined by using a probabilistic risk system that models 250 simulations of how PSE’s natural gas and power portfolios will perform under various weather, hydroelectric and unit performance conditions. The objectives of the hedging strategy are to:
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Ensure physical energy supplies are available to reliably and cost-effectively serve retail load;
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Manage the energy portfolio prudently to serve retail load at overall least cost and limit undesired impacts on PSE’s customers and shareholders;
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Reduce power costs by extracting the value of PSE’s assets; and
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Meet the credit, liquidity, financing, tax and accounting requirements of PSE.
ASC 815 requires a significant amount of disclosure regarding PSE’s derivative activities and the nature of their impact on PSE’s financial position, financial performance and cash flows. The information in this Item 7A should serve as an accompaniment to Management's Discussion and Analysis and Note 9 to the consolidated financial statements included in Items 7 and 8 of this report, respectively.
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. 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 with investment grade counterparties that do not require collateral calls on the contracts. 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.
On July 1, 2009, the Company elected to de-designate all energy related derivative contracts previously recorded as cash flow hedges for the purpose of simplifying its financial reporting. The contracts that were de-designated related to physical electric supply contracts and natural gas swap contracts to fix the price of natural gas for electric generation. For these contracts 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(s) 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.
The following table presents the fair value of the Company’s energy derivatives instruments that do not meet the NPNS exception:
For further details regarding both the fair value of derivative instruments and the impacts such instruments have on current period earnings and OCI (for cash flow hedges), see Notes 9 and 10 to the consolidated financial statements.
At December 31, 2013, the Company had total assets of $8.1 million and total liabilities of $35.7 million related to derivative contracts used to hedge the supply and cost of natural gas to serve natural gas customers. All fair value adjustments of derivatives relating to the natural gas business have been reclassified to a deferred account in accordance with ASC 980, "Regulated Operations", due to the PGA mechanism. All increases and decreases in the cost of natural gas supply are passed on to customers with the PGA mechanism. As the gains and losses on the hedges are realized in future periods, they will be recorded as natural gas costs under the PGA mechanism.
A hypothetical 10.0% increase or decrease in market prices of natural gas and electricity would change the fair value of the Company’s derivative contracts by $43.1 million, with an after-tax impact of $28.0 million.
The change in fair value of the Company’s outstanding energy derivative instruments from December 31, 2012 through December 31, 2013 is summarized in the table below:
The fair value of the Company’s outstanding derivative instruments at December 31, 2013, based on pricing source and the period during which the instrument will mature, is summarized below:
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Prices provided by external pricing service, which utilizes broker quotes and pricing models.
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.
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, 2013, PSE held approximately $1.1 billion in standby letters of credit or limited parental guarantees, and had 20 counterparties with unlimited parental guarantees, in support of various electric and natural gas transactions.
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. As of December 31, 2013, approximately 67.0% of PSE’s energy and natural gas portfolio exposure, including NPNS transactions, is with counterparties that are rated at least investment grade by the major rating agencies while 33.0% are either rated below investment grade or are not rated by rating agencies. PSE assesses credit risk internally for counterparties that are not rated.
PSE has entered into commodity master arrangements with its counterparties to mitigate credit exposure to those counterparties. PSE generally enters into the following master arrangements: (1) WSPP, Inc. (WSPP) agreements which standardize physical power contracts; (2) International Swaps and Derivatives Association (ISDA) agreements which standardize financial gas and electric contracts; and (3) North American Energy Standards Board (NAESB) agreements which standardize physical gas contracts. PSE 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. PSE monitors counterparties that are experiencing financial problems, have significant swings in credit default swap rates, have credit rating
changes by external rating agencies or have changes in ownership. Counterparty credit risk impacts PSE’s decisions on derivative accounting treatment. A counterparty may have a deterioration of credit below investment grade, potentially indicating that it is no longer probable that it will fulfill its obligations under a contract (e.g., make a physical delivery upon the contract's maturity). ASC 815 specifies the requirements for derivative contracts to qualify for the NPNS scope exception. When performance is no longer probable, PSE records the fair value of the contract on the balance sheet with the corresponding amount recorded in the statements of income. Accumulated OCI of the cash flow hedge is also impacted by a counterparty’s deterioration of credit under ASC 815 guidelines. If a forecasted transaction associated with the cash flow hedge is probable of not occurring, PSE will reclassify the amounts deferred in accumulated OCI into earnings.
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 used 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, 2013, 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, 2013, 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.
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:
For further details regarding Puget Energy and Puget Sound Energy debt instruments, see Notes 6 and 10 under Item 8.
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
All other schedules have been omitted because of the absence of the conditions under which they are required, or because the information required is included in the consolidated financial statements or the notes thereto.
Financial statements of PSE’s subsidiary are not filed herewith inasmuch as the assets, revenue, earnings and earnings reinvested in the business of the subsidiary are not material in relation to those of the Company.
REPORT OF MANAGEMENT AND STATEMENT OF RESPONSIBILITY
PUGET ENERGY, INC.
AND
PUGET SOUND ENERGY, INC.
Puget Energy, Inc. and Puget Sound Energy, Inc. (the Company) management assumes accountability for maintaining compliance with our established financial accounting policies and for reporting our results with objectivity and integrity. The Company believes it is essential for investors and other users of the consolidated financial statements to have confidence that the financial information we provide is timely, complete, relevant and accurate. Management is also responsible to present fairly Puget Energy’s and Puget Sound Energy’s consolidated financial statements, prepared in accordance with GAAP.
Management, with oversight of the Board of Directors, established and maintains a strong ethical climate under the guidance of our Corporate Ethics and Compliance Program so that our affairs are conducted to high standards of proper personal and corporate conduct. Management also established an internal control system that provides reasonable assurance as to the integrity and accuracy of the consolidated financial statements. These policies and practices reflect corporate governance initiatives designed to ensure the integrity and independence of our financial reporting processes including:
•
Our Board has adopted clear corporate governance guidelines.
•
With the exception of the President and Chief Executive Officer, the Board members are independent of management.
•
All members of our key Board committees - the Audit Committee, the Compensation and Leadership Development Committee and the Governance and Public Affairs Committee - are independent of management.
•
The non-management members of our Board meet regularly without the presence of Puget Energy and Puget Sound Energy management.
•
The Charters of our Board committees clearly establish their respective roles and responsibilities.
•
The Company has adopted a Corporate Ethics and Compliance Code with a hotline (through an independent third party) available to all employees, and our Audit Committee has procedures in place for the anonymous submission of employee complaints on accounting, internal accounting controls or auditing matters. The Compliance Program is led by the Chief Ethics and Compliance Officer of the Company.
•
Our internal audit control function maintains critical oversight over the key areas of our business and financial processes and controls, and reports directly to our Board Audit Committee.
Management is confident that the internal control structure is operating effectively and will allow the Company to meet the requirements under Section 404 of the Sarbanes-Oxley Act of 2002.
PricewaterhouseCoopers LLP, our independent registered public accounting firm, reports directly to the Audit Committee of the Board of Directors. PricewaterhouseCoopers LLP’s accompanying report on our consolidated financial statements is based on its audit conducted in accordance with auditing standards prescribed by the Public Company Accounting Oversight Board, including a review of our internal control structure for purposes of designing their audit procedures. Our independent registered accounting firm has reported on the effectiveness of our internal control over financial reporting as required under Section 404 of the Sarbanes-Oxley Act of 2002.
We are committed to improving shareholder value and accept our fiduciary oversight responsibilities. We are dedicated to ensuring that our high standards of financial accounting and reporting as well as our underlying system of internal controls are maintained. Our culture demands integrity and we have confidence in our processes, our internal controls and our people, who are objective in their responsibilities and who operate under a high level of ethical standards.
/s/ Kimberly J. Harris
/s/ Daniel A. Doyle
/s/ Michael J. Stranik
Kimberly J. Harris
Daniel A. Doyle
Michael J. Stranik
President and Chief Executive Officer
Senior Vice President
and Chief Financial Officer
Controller and Principal
Accounting Officer
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, 2013 and 2012, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2013 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, 2013, based on criteria established in Internal Control - Integrated Framework (1992) 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 on 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
March 13, 2014
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
To the Board of Directors and Shareholder of
Puget Sound 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 Sound Energy, Inc. and its subsidiaries at December 31, 2013 and 2012, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2013 in conformity with accounting principles generally accepted in the United States of America. In addition, in our opinion, the financial statement schedule listed in the accompanying index presents fairly, in all material respects, the information set forth therein when read in conjunction with the related consolidated financial statements. Also in our opinion, the Company maintained, in all material respects, effective internal control over financial reporting as of December 31, 2013, based on criteria established in Internal Control - Integrated Framework (1992) 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 schedule, 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 on Financial Reporting appearing under Item 9A. Our responsibility is to express opinions on these financial statements, on the financial statement schedule, 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
March 13, 2014
PUGET ENERGY, INC.
CONSOLIDATED STATEMENTS OF INCOME
(Dollars in Thousands)
The accompanying notes are an integral part of the consolidated financial statements.
PUGET ENERGY, INC.
CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME
(Dollars in Thousands)
The accompanying notes are an integral part of the consolidated financial statements.
PUGET ENERGY, INC.
CONSOLIDATED BALANCE SHEETS
(Dollars in Thousands)
ASSETS
The accompanying notes are an integral part of the consolidated financial statements.
PUGET ENERGY, INC.
CONSOLIDATED BALANCE SHEETS
(Dollars in Thousands)
CAPITALIZATION AND LIABILITIES
The accompanying notes are an integral part of the consolidated financial statements.
PUGET ENERGY, INC.
CONSOLIDATED STATEMENTS OF COMMON SHAREHOLDER’S EQUITY
(Dollars in Thousands)
The accompanying notes are an integral part of the consolidated financial statements.
PUGET ENERGY, INC.
CONSOLIDATED STATEMENTS OF CASH FLOWS
(Dollars in Thousands)
The accompanying notes are an integral part of the consolidated financial statements.
PUGET SOUND ENERGY, INC.
CONSOLIDATED STATEMENTS OF INCOME
(Dollars in Thousands)
The accompanying notes are an integral part of the consolidated financial statements.
PUGET SOUND ENERGY, INC.
CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME
(Dollars in Thousands)
The accompanying notes are an integral part of the consolidated financial statements.
PUGET SOUND ENERGY, INC.
CONSOLIDATED BALANCE SHEETS
(Dollars in Thousands)
ASSETS
The accompanying notes are an integral part of the consolidated financial statements.
PUGET SOUND ENERGY, INC.
CONSOLIDATED BALANCE SHEETS
(Dollars in Thousands)
CAPITALIZATION AND LIABILITIES
The accompanying notes are an integral part of the consolidated financial statements.
PUGET SOUND ENERGY, INC.
CONSOLIDATED STATEMENTS OF COMMON SHAREHOLDER’S EQUITY
(Dollars in Thousands)
The accompanying notes are an integral part of the consolidated financial statements.
PUGET SOUND ENERGY, INC.
CONSOLIDATED STATEMENTS OF CASH FLOWS
(Dollars in Thousands)
The accompanying notes are an integral part of the consolidated financial statements.
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. On February 6, 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.
Certain prior year amounts have been corrected to conform to the current year presentation. In addition, at December 31, 2013, PSE revised 2012 credit balances in customer’s accounts receivable to accounts payable in the amount of $33.7 million in order to correct errors included in the December 31, 2012 balances. The Company believes these amounts are not material to the financial statements.
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, in excess of $0.5 million, are deferred and amortized to the next scheduled major maintenance. This 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%, 2.9% and 2.7% in 2013, 2012 and 2011, respectively; depreciable gas utility plant was 3.4%, 3.4% and 3.5% in 2013, 2012 and 2011, respectively; and depreciable common utility plant was 11.4%, 11.6% and 11.3% in 2013, 2012 and 2011, respectively. Depreciation on other property, plant and equipment is calculated primarily on a straight-line basis over the useful lives of the assets. The cost of removal is collected from PSE’s customers through depreciation expense and any excess is recorded as a regulatory liability.
Goodwill
On February 6, 2009, Puget Holdings completed its merger with Puget Energy. Puget Energy remeasured the carrying amount of all its assets and liabilities to fair value, which resulted in 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 2013 using an October 1, 2013 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 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, 2013. There were no events or circumstances from the date of the assessment through December 31, 2013 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 $44.3 million and $135.5 million as of December 31, 2013 and 2012, respectively. The 2013 and 2012 balance consisted of cash equivalents, which are reported at cost and approximate fair value, and were $2.6 million and $107.6 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 assets or liabilities due to the length of the amortization. The exception is the Purchased Gas Adjustment (PGA) which can be a current asset or current liability.
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.
The AFUDC rates authorized by the Washington Commission for natural gas and electric utility plant additions based on the effective dates are as follows:
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.
Non-utility subsidiaries recognize revenue when services are performed or upon the sale of assets. Revenue from retail sales is billed based on tariff rates approved by the Washington Commission. Sales of Renewable Energy Credits (RECs) are deferred as a regulatory liability.
PSE collected Washington State excise taxes (which are a component of general retail customer rates) and municipal taxes totaling $243.9 million, $244.2 million and $252.5 million for 2013, 2012 and 2011, 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.
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 PGA rates are excluded from the decoupling mechanism.
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, 2013 and 2012 was $7.4 million and $9.9 million, respectively.
Self-Insurance
PSE currently has no insurance coverage for storm damage and recent environmental contamination occurring on PSE-owned property. PSE is self-insured for a portion of the risk associated with comprehensive liability, workers’ compensation claims and catastrophic property losses other than those which are storm related. The Washington Commission has approved the deferral of certain uninsured 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. Prior to July 1, 2010, PSE passed the benefit of the PTCs to customers as the benefits were generated. After July 1, 2010, 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.
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 other comprehensive income (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.
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, 2013, 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). However, as permitted under ASC 820, the Company utilizes a mid-market pricing convention (the mid-point price between bid and ask prices) as a practical expedient for valuing the majority of its assets and liabilities measured and reported at fair value. The Company utilizes market data or assumptions that market participants would use in pricing the asset or liability, including assumptions about risk and the risks inherent in the inputs to the valuation technique. These inputs can be readily observable, market corroborated or generally unobservable. The Company primarily applies the market approach for recurring fair value measurements 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.
Statements of Cash Flows
The Company has refinancing transactions that do not result in an actual exchange of cash. For these transactions, the Company evaluates if the non-exchange of cash is for convenience purposes and if so, the Company considers the transaction as if it had constructively received and disbursed the cash and presents the transaction as gross on the financing section of the statements of cash flows.
PSE funds cash dividends to pay the shareholder of Puget Energy.
The following non-cash investing and financing activities have occurred at the Company:
•
PSE did not incur any capital lease obligations in 2013 or 2012. PSE incurred capital lease obligations of $37.9 million for AMR modules and network in 2011.
The Company revised its Consolidated Statement of Cash Flows due to an immaterial error. Revisions were made in the second quarter ended June 30, 2013 on the Company's Consolidated Statement of Cash Flows to reflect energy efficiency expenditures as operating cash outflows instead of investing cash outflows. The Company determined energy efficiency expenditures should have been classified as operating activities instead of investing activities. These revisions decreased net cash provided by operating activities and decreased net cash used by investing activities. The revision does not affect the net change in cash and cash equivalents for any of the periods, and has no effect on the Company's Consolidated Statements of Income, Consolidated Statements of Comprehensive Income, Consolidated Balance Sheets, and Consolidated Statement of Common Shareholder's Equity. The Company has evaluated the effects of these errors and concluded that none of them are material to any of the Company's previously issued quarterly or annual Financial Statements. Nevertheless, the Company has elected to revise the Consolidated Statement of Cash Flows in this report to correct for the effect of these errors and properly reflect the revised values.
The amounts on prior period Consolidated Statements of Cash Flows that have been revised are summarized below:
Accumulated Other Comprehensive Income (Loss)
The following tables set forth the components of the Company’s accumulated other comprehensive income (loss) at:
(2) New Accounting Pronouncements
Balance Sheet
In December 2011, the FASB issued ASU 2011-11, Balance Sheet (Topic 210) (ASU 2011-11). ASU 2011-11, as amended by ASU 2013-01, Clarifying the Scope of Disclosures about Offsetting Assets and Liabilities, enhances disclosure requirements about the nature of an entity's right to offset and related arrangements associated with its derivative instruments. ASU 2011-11 requires the disclosure of the gross amounts subject to rights of set-off, amounts offset in accordance with the accounting standards followed, and the related net exposure.
ASU 2011-11, as amended, is effective for fiscal years, and interim periods within those years, beginning on or after January 1, 2013. Retrospective application of the disclosures is required for all periods presented within the financial statements. These disclosure requirements are the only impact on the Company’s consolidated financial statements. The Company adopted the Accounting Standards Update (ASU) requirements as disclosed in Note 9 - Accounting for Derivative Instruments and Hedging Activities.
Comprehensive Income
In February 2013, the FASB issued ASU 2013-02, Comprehensive Income (Topic 220): Reporting of Amounts Reclassified Out of Accumulated Other Comprehensive Income (ASU 2013-02), to improve the transparency of reporting reclassifications out of accumulated other comprehensive income. ASU 2013-02 requires an entity to present (either on the face of the statement where net income is presented or in the notes) the effects on the line items of net income of significant amounts reclassified out of accumulated other comprehensive income but only if the item reclassified is required under U.S. GAAP to be reclassified to net income in its entirety in the same reporting period. ASU 2013-02 also requires an entity to cross-reference to other disclosures currently required under U.S. GAAP for other reclassification items (that are not required under U.S. GAAP) to be reclassified directly to net income in their entirety in the same reporting period. This would be the case when a portion of the amount reclassified out of accumulated other comprehensive income is initially transferred to a balance sheet account instead of directly to income or expense.
ASU 2013-02 is effective for reporting periods beginning after December 15, 2012, for public companies and is effective for reporting periods beginning after December 15, 2013, for private companies. Other than additional disclosures or a change in the presentation on the statement of comprehensive income when necessary, ASU 2013-02 does not impact the Company's consolidated results of operations, cash flows or financial position. The Company adopted the ASU requirements as disclosed in Note 18 - Accumulated Other Comprehensive Income (Loss).
(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:
The net regulatory assets and liabilities at December 31, 2013 and 2012 included the following:
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(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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(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 $269.5 million and $239.2 million in 2013 and 2012, 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 2013 and 2012, PSE incurred $9.5 million and $71.5 million, respectively, in storm-related electric transmission and distribution system restoration costs, of which no amount was deferred in 2013 and $60.4 million was deferred in 2012.
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.
Electric Rate Case
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 7.77% 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 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 are scheduled for May 2014.
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:
In addition, PSE will be increasing the allowed delivery revenue per customer under the ERF 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 Renewable Energy Credits 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 Jefferson County Public Utility District (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 until the Washington Commission determines the accounting and ratemaking treatment. On October 31, 2013, PSE filed an accounting petition for a Washington Commission order that authorizes PSE to retain the gain of $45.0 million and return $15.0 million to its remaining customers over a period of 48 months. Intervenors testimony is scheduled to be filed in March, 2014. For federal income tax purposes, the Company will elect to treat the transaction as an involuntary conversion under the Internal Revenue Code which allows for deferral of the tax gain if PSE acquires qualified replacement property by December 31, 2015. Based on PSE's current construction program projection, it anticipates meeting this requirement through such purchases by that date.
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:
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.
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 December 30, 2010, the Washington Commission approved revisions to PSE’s Federal Incentive Tracker tariff, effective January 1, 2011. The rate schedule passed-through $5.5 million of the $28.7 million Wild Horse Expansion Treasury Grant in 2011. The order authorized PSE to pass back one-tenth of the Treasury Grant on an annual basis and included 23 months of Treasury Grant amortization to customers from February 2010 through December 2011, which represented the month the Treasury Grant funds were received through the end of the period over which the rates will be set. This represents an overall average rate reduction of 0.3%, with no impact to net income.
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 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 2.76%.
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 0.26%.
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 7.77% 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 are scheduled for May 2014.
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 income as the changes to revenue are offset by increased or decreased purchased gas and gas transportation costs.
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.
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.
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:
In addition, PSE will be increasing the allowed delivery revenue per customer under the ERF 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 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 adjusts loss reserves quarterly. 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 ranging from $31.3 million to $49.5 million for gas and from $9.1 million to $27.4 million for electric. The Company does not consider any amounts within those ranges as being a better estimate and has therefore accrued $31.3 million and $9.1 million for gas and electric, respectively. 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 a cost-sharing agreement with a third party regarding an environmental remediation project in Seattle, Washington. The Company has taken the lead for completing the project. As of December 31, 2013, the Company’s share of remediation costs is estimated to be approximately $19.4 million. For the year ended December 31, 2013, the Company incurred deferred electric and natural gas environmental costs of $12.3 million and $45.1 million, net of insurance proceeds, respectively.
(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, 2013, approximately $469.6 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 47.4% at December 31, 2013 and the EBITDA to interest expense was 4.4 to one 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.
Puget Energy’s ability to pay dividends is also limited by the merger order issued by the Washington Commission as well as by the terms of its credit facilities. 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. At December 31, 2013, the EBITDA to interest expense was 2.9 to one for the 12 months then ended.
At December 31, 2013, the Company was in compliance with all applicable covenants, including those pertaining to the payment of dividends.
(5) Utility Plant
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Accumulated amortization of capital leases at Puget Energy was $20.8 million in 2013 and $13.3 million in 2012. Accumulated amortization of capital leases at PSE was $20.8 million in 2013 and $13.3 million in 2012.
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, 2013. These amounts are also included in the Utility Plant table above.
The Company recognized new Asset Retirement Obligations (ARO) of $0.4 million and $7.7 million in 2013 and 2012, respectively.
The following table describes all changes to the Company’s ARO liability:
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, 2013 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;
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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;
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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
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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.
(6) Long-Term Debt
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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, 2013, the latest maturity date of the first mortgage bonds, other than pledged first mortgage bonds, is December 22, 2025.
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, 2013, 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.
On May 23, 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
On June 15, 2012, Puget Energy issued $450.0 million of senior secured notes. Proceeds from the note offering were used to pay down $425.0 million of the revolving $859.0 million senior secured credit facility balance resulting in an outstanding balance of $434.0 million as of December 31, 2012. In 2013, an additional paydown of the senior secured credit facility resulted in a remaining balance at of $299.0 million at December 31, 2013.
At the time of the merger in February 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. On February 10, 2012, Puget Energy entered into a $1.0 billion five-year revolving senior secured credit facility. 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. 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. Initial borrowings under this facility were used to repay debt outstanding under the term loan and capital expenditure credit facility and those agreements were terminated.
The Puget Energy revolving senior secured credit facility contains usual and customary affirmative and negative covenants. The agreement also contains two financial covenants based on the following ratios: Group Funds From Operations (FFO) Coverage Ratio and Maximum Leverage Ratio, as defined in the agreement governing the senior secured credit facility.
Long-Term Debt Maturities
The principal amounts of long-term debt maturities for the next five years and thereafter are as follows:
Financial Covenants
Puget Energy's credit facility contains financial covenants related to group FFO coverage and maximum leverage. As of December 31, 2013, the Company is in compliance with its long-term debt financial covenants.
(7) Liquidity Facilities and Other Financing Arrangements
As of December 31, 2013 and 2012, PSE had $162.0 million and $181.0 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 2013 and 2012 was 3.93% and 6.49%, respectively. As of December 31, 2013, PSE and Puget Energy had several committed credit facilities that are described below.
Puget Sound Energy Credit Facilities
On February 4, 2013, PSE entered into two new credit facilities and terminated its previous three credit facilities. The new credit facilities 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 new credit facilities also have an accordion feature that, upon the banks' approval, would increase the total size of these facilities to $1.450 billion.
The credit agreements for these two replacement credit facilities contain similar terms and conditions, are syndicated among numerous lenders and mature in February 2018. The credit agreements contain usual and customary affirmative and negative covenants, that among other things, place limitations on PSE's ability to incur additional indebtedness and liens, issue equity, pay dividends, transact with affiliates and make asset dispositions and investments. 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, 2013, PSE was in compliance with all applicable covenants.
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 Offer 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 December 31, 2013, no amount was drawn and outstanding under PSE’s $650.0 million liquidity facility. A letter of credit in the amount of $3.0 million in support of contracts was outstanding under the facility, and $162.0 million was outstanding under the commercial paper program. A letter of credit in the amount of $1.0 million was outstanding under the $350.0 million facility supporting energy hedging.
Demand Promissory Note On June 1, 2006, PSE entered into a revolving credit facility with 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, 2013, the outstanding balance of the Note was $29.6 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, 2013, Puget Energy maintained an $800.0 million five-year revolving senior secured credit facility. 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.
The five-year revolving senior secured credit facility contains usual and customary affirmative and negative covenants. The agreement also contains two financial covenants based on the following ratios: Group Funds From Operations (FFO) Coverage Ratio and Maximum Leverage Ratio, as defined in the agreement governing the senior secured credit facility. As of December 31, 2013, Puget Energy was in compliance with all applicable covenants.
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 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. At December 31, 2013, $299.0 million was drawn and outstanding under the facility, the spread over LIBOR was 1.75% and the commitment fee was 0.30%. Puget Energy entered into interest rate swap contracts to manage the interest rate risk associated with the credit facility.
(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:
Payments received for the subleases of properties were immaterial for each of the years ended 2013, 2012 and 2011.
Future minimum lease payments for non-cancelable leases net of sublease receipts are:
(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 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 with investment grade counterparties that do not require collateral calls on the contracts. 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, 2013, 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:
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Balance sheet location: Current and Long-term Unrealized gain on derivative instruments.
Balance sheet location: Current and Long-term Unrealized loss on derivative instruments.
Interest rate swap contracts are only held at Puget Energy.
PSE had a net derivative liability and an offsetting regulatory asset of $27.6 million at December 31, 2013 and $96.0 million at December 31, 2012 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.
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Electric portfolio derivatives consist of electric generation fuel of 145.6 million One Million British Thermal Units (MMBtus) and purchased electricity of 8.6 million MWhs at December 31, 2013 and 129.7 million MMBtus and 10.7 million MWhs at December 31, 2012.
For further details regarding the fair value of derivative instruments, see Note 10.
ASU 2013-01 requires disclosure of both gross and net information for recognized derivative assets and liabilities. 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 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:
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1.
All Derivative Contract deals are executed under ISDA, NAESB and WSPP Master Netting Agreements with Right of Offset.
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:
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For 2012 and 2011, the amounts differ from the amounts stated in the statements of income as they do 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 and $11.7 million for the year ended December 31, 2011.
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, 2013, 2012 and 2011, cash outflows related to financing activities of $34.3 million, $92.7 million and $182.7 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 component of OCI, and then is reclassified into earnings in the same period(s) during which the hedged transaction affects earnings. During 2013, Puget Energy reclassified $0.7 million in losses from accumulated OCI into earnings. This was the result of paying down $135.0 million on Puget Energy's revolving senior secured credit facility, thus causing the related forecasted transactions (i.e., future interest payments associated with the debt pay down) to become remote of occurring.
Puget Energy and PSE expect $0.7 million and $2.1 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:
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, 2013, approximately 99.9% of the Company's energy portfolio exposure, excluding NPNS transactions, is with counterparties that are rated at least investment grade by the major rating agencies and 0.1% are either rated below investment grade or 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 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 used 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 recorded as contra accounts to unrealized gain (loss) positions. As of December 31, 2013, 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, 2013, 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, 2013:
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Represents the derivative fair value of contracts with contingent features for counterparties in net derivative liability positions. Excludes NPNS, accounts payable and accounts receivable.
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.
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 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.
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.
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:
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:
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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 $(13.4) million, $(15.2) million, and $(55.2) million for the years ended December 31, 2013, 2012 and 2011, respectively.
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 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, 2013 and 2012. 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 purchased commodity contracts, as of December 31, 2013:
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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, 2013, 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 $7.0 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 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.
The valuation was 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.
Below are significant unobservable inputs used in estimating the long-term power purchase contracts' fair value of $484.1 million on June 30, 2013:
During 2012, Puget Energy completed valuation and impairment testing of its purchased power contracts classified as intangible assets. At March 31, 2012, the Wells Hydro intangible asset contract had a carrying value of $113.3 million and a fair value on a discounted basis of $96.7 million, thereby requiring a write-down of $16.6 million of this intangible asset and a corresponding reduction in the regulatory liability. Additionally, at December 31, 2012, the Rock Island intangible asset contract had a carrying value of $7.6 million and its fair value on a discounted basis was determined to be a liability of $10.2 million, thereby requiring a complete write-off of this intangible asset and a corresponding reduction in the regulatory liability.
Below are significant unobservable inputs used in estimating the long-term power purchase contracts' fair value on March 31, 2012 and December 31, 2012:
(11) Employee Investment Plans
The Company's existing plan is a qualified employee Investment Plan 401(k) plan, under which employee salary deferrals and after-tax contributions are used to purchase several different investment fund options. For employees under the Cash Balance retirement plan formula, PSE will match 100% of an employee's contribution up to 6% of plan compensation, 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. PSE’s contributions to the employee Investment Plan were $14.6 million, $14.5 million and $13.5 million for the years 2013, 2012, and 2011, respectively. The employee Investment Plan eligibility requirements are set forth in the plan documents.
Beginning January 1, 2014 employees hired as of this date 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:
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401(k) Company Matching: new non-represented and United Association of Plumbers and Pipefitters (UA) 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.
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Company Contribution: 401(k) or pension plan. New non-represented employees will receive an annual company contribution of 4% of eligible pay, placed either in the Investment Plan 401(k) plan or an account in PSE’s Retirement Plan (Cash Balance pension plan). New 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 pension plan. The Company’s 4% contribution will vest after three years of employment.
(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 January 1, 2014, all new UA employees and those new non-represented employees who elect to accumulate the Company contribution in the Cash Balance pension, 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.
In addition to providing pension benefits, PSE provides group health care and life insurance benefits for certain retired employees. PSE also maintains a non-qualified Supplemental Executive Retirement Plan (SERP) for its key senior management 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 remeasurement of the retirement plans are recorded at Puget Energy.
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, 2013 and 2012:
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, 2013 and 2012:
The following tables summarize Puget Energy's and Puget Sound Energy's net periodic benefit cost for the years ended December 31, 2013, 2012 and 2011:
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, 2013 and 2012:
The estimated prior service cost/(credit) for the pension plans that will be amortized from accumulated OCI into net periodic benefit cost in 2014 by Puget Energy is $2.0 million. The estimated net (loss)/gain for the SERP that will be amortized from accumulated OCI into net periodic benefit cost in 2014 is $(0.9) million. The estimated prior service cost/(credit) for the SERP that will be amortized from accumulated OCI into net periodic benefit cost in 2014 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 2014 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 2014 by Puget Sound Energy are $(13.0) 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 2014 are $(1.5) million. The estimated prior service cost/(credit) for the SERP that will be amortized from accumulated OCI into net periodic benefit cost in 2014 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 2014 is $0.6 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 retirement plan, SERP and the other postretirement plans for the year ending December 31, 2014 are expected to be at least $12.0 million, $4.0 million and $0.4 million, respectively.
Assumptions
In accounting for pension and other benefit obligations and costs under the plans, the following weighted-average actuarial assumptions were used by the Company:
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The Company calculates the present value of the pension liability using a discount rate of 5.10% 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 8.20% in 2014 grading down to 4.30% in 2015. A 1.0% change in the assumed medical inflation rate would have the following effects:
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.
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:
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:
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.
The following table sets forth by level, within the fair value hierarchy, the qualified pension plan as of December 31, 2013 and 2012:
_________________
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, 2013. 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, 2013.
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, 2013. 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, 2013.
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, 2013. The investment in the mutual fund is valued using quoted market prices multiplied by the number of shares owned as of December 31, 2013.
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.
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, 2013.
As of December 31, 2013 absolute return investments consist of two partnerships. The partnerships are valued using the financial reports as of December 31, 2013. 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.
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, 2013. 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.
Level 3 Roll-Forward
The following table sets forth a reconciliation of changes in the fair value of the plan’s Level 3 assets:
_________________
The plan had no transfers between level 2 and level 1 during the years ended December 31, 2013 or 2012.
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:
_______________
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, 2013.
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, 2013. 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:
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:
The Company’s deferred tax liability at December 31, 2013 and 2012 is composed of amounts related to the following types of temporary differences:
The above amounts have been classified in the Consolidated Balance Sheets as follows:
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 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 2033. The Company’s net operating loss carryforwards expire from 2029 through 2033.
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, 2013 and 2012, 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 2013. The Company classifies interest as interest expense and penalties as other expense in the financial statements.
(14) Litigation
Residential Exchange
The Northwest Power Act, through the Residential Exchange Program (REP), provides access to the benefits of low-cost federal power for residential and small farm customers of regional utilities, including PSE. The program is administered by the BPA. Pursuant to agreements (including settlement agreements) between the BPA and PSE, the BPA has provided payments of REP benefits to PSE, which PSE has passed through to its residential and small farm customers in the form of electricity bill credits.
In 2007, the United States Court of Appeals for the Ninth Circuit (Ninth Circuit) ruled that REP agreements of the BPA with PSE and a number of other investor-owned utilities were inconsistent with the Northwest Power Act. Since that time, those investor-owned utilities, including PSE, the BPA and other parties have been involved in ongoing litigation at the Ninth Circuit relating to the amount of REP benefits paid to utilities, including PSE, for the fiscal year 2002 through fiscal year 2011 period and the amount of REP benefits to be paid going forward.
In July 2011, the BPA, PSE and a number of other parties entered into a settlement agreement (2012 REP Settlement) that by its terms, if upheld in its entirety, would resolve the disputes between BPA and PSE regarding REP benefits paid for fiscal years 2002-2011 and determine REP benefits for fiscal years 2012-2028. In October 2011, certain other parties challenged BPA decisions with regard to its entering into the 2012 REP Settlement agreement. On October 28, 2013, the Ninth Circuit issued an order dismissing this challenge to this settlement. In light of the disposition of this challenge, the stay of the other pending Ninth Circuit litigation regarding REP benefits was lifted in January 2014. In the order lifting the stay, petitioners (unless they move to voluntarily dismiss their petitions) and intervenors (unless they move to voluntarily withdraw) were directed to file a statement explaining which issues, if any, remain pending. Such statements are due on or before April 1, 2014. PSE is unable to determine prior to April 1, if this other pending litigation will continue and, if so, what impact these proceedings may have on PSE. However, the Company believes it is unlikely that any unfavorable outcome would have a material adverse effect on PSE because REP benefits received by PSE are passed through directly to REP customers.
With the Ninth Circuit’s decision affirming the 2012 REP Settlement, PSE will receive approximately $57.0 million plus interests of REP payments owed under a 2008 agreement, which are in addition to scheduled monthly REP benefits received from BPA under the 2012 REP Settlement. These payments will be given back to PSE's residential and small farm customers through a higher residential exchange credit on their bills.
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 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 36 claims, 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. This lawsuit followed various Notices of Intent to Sue sent to Colstrip owners (including PSE) from the Sierra Club and the MEIC between
July and December 2012. Discovery in the case has begun, and a prehearing conference took place in July 2013. The case has been bifurcated into separate liability and remedy trials set for March and August 2015, respectively. PSE is litigating the allegations set forth in the notices and cannot at this time predict 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 $1.4 million and $3.4 million relating to these claims as of December 31, 2013 and 2012, respectively.
(15) Commitments and Contingencies
For the year ended December 31, 2013, approximately 15.1% of the Company’s energy output was obtained at an average cost of approximately $0.018 per kilowatt hour (kWh) through long-term contracts with three of 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:
As of December 31, 2013, the Company purchased portions of the power output of the PUDs' projects as set forth in the following table:
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.
Total purchased power contracts provided the Company with approximately 10.7 million, 6.1 million and 8.5 million megawatt hours (MWh) of firm energy at a cost of approximately $348.7 million, $203.1 million and $391.8 million for the years 2013, 2012 and 2011, respectively.
The Company has natural gas-fired generation facility obligations for natural gas supply amounting to an estimated $118.6 million in 2014. Longer term agreements for natural gas supply amount to an estimated $318.1 million for 2015 through 2030.
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 $32.5 million, $10.8 million and $2.7 million in 2014, 2015 and 2016, 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. Many of these contracts, which have remaining terms from less than one year to 31 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 2013 for firm transportation service and firm storage and peaking service of $160.8 million and $6.6 million, respectively. The demand charge for firm natural gas supply was immaterial in 2013. The Company incurred demand charges in 2013 for firm transportation and firm storage service for the natural gas supply for its combustion turbines in the amount of $39.5 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.
Service Contracts
The following table summarizes the Company’s estimated obligations for service contracts through the terms of its existing contracts.
_______________
Energy production service contracts include operations and maintenance contracts on Mint Farm, Wild Horse, Goldendale, Hopkins Ridge, Frederickson 1, Ferndale and Lower Snake River facilities.
Automated meter reading system contractual obligation is the service component of the Landis and Gyr contract.
For information regarding PSE's environmental remediation obligations, see Note 3 Regulation and Rates.
(16) Related Party Transactions
On June 1, 2006, PSE entered into a revolving credit facility with Puget Energy in the form of a Demand Promissory Note (Note). Through the Note, PSE may borrow up to $30.0 million from Puget Energy, subject to approval by Puget Energy. Under the terms of the Note, PSE pays interest on the outstanding borrowings based on the lowest of the weighted-average interest rate of 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, 2013 and 2012, the outstanding balance of the Note was $29.6 million and $29.6 million, respectively, and the interest rate was 0.325% and 0.5%, respectively. The outstanding balance and the related interest under the Note are eliminated by Puget Energy upon consolidation of PSE’s financial statements. The $30.0 million credit facility with Puget Energy was unaffected by the merger.
On June 3, 2011, Puget Energy issued $500.0 million of senior secured notes. Macquarie Capital (USA) Inc. acted as a co-manager and underwriter of this issue. Net proceeds of $484.0 million from these notes were used to repay a portion of the outstanding $782.0 million term-loan. Puget Energy’s term-loan and credit facility for funding capital expenditures both were originally scheduled to mature in February 2014, and were syndicated among numerous committed banks and other financial institutions. One of these banks was Macquarie Bank Limited. On February 10, 2012, Puget Energy terminated the term loan and capital expenditure facility and replaced them with a $1.0 billion revolving credit facility. There are no related parties with commitments under the $1.0 billion revolving credit facility. Concurrent with the borrowings under the term loan and capital expenditure credit agreements, Puget Energy entered into several interest rate swap instruments to hedge volatility associated with these two loans. Two of the swap instruments were entered into with Macquarie Bank Limited with a total notional amount of $444.9 million. On June 3, 2011, Puget Energy settled one of the swaps with a notional amount of $77.4 million. On February 9, 2012, Puget Energy amended and reduced the remaining swap instrument by $67.5 million. On June 18, 2012, Puget Energy terminated and settled the remaining $300.0 million of the swap instrument with Macquarie Bank Limited.
(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, 2013, 2012 and 2011, respectively.
Details about these reclassifications out of accumulated other comprehensive income (loss) for the years ended December 31, 2013, 2012 and 2011, respectively, are as follows:
__________
(a)
These accumulated other comprehensive income components are included in the computation of net periodic pension cost (see Note 12 for additional details).
__________
(a)
These accumulated other comprehensive income components are included in the computation of net periodic pension cost (see Note 12 for additional details).
SUPPLEMENTAL QUARTERLY FINANCIAL DATA
The following unaudited amounts, in the opinion of the Company, include all adjustments (consisting of normal recurring adjustments) necessary for a fair statement of the results of operations for the interim periods. Quarterly amounts vary during the year due to the seasonal nature of the utility business.
SCHEDULE I: CONDENSED FINANCIAL INFORMATION OF PUGET ENERGY
Puget Energy
Condensed Statements of Income and Comprehensive Income (Loss)
(Dollars in Thousands)
See accompanying notes to the consolidated financial statements.
Puget Energy
Condensed Balance Sheets
(Dollars in Thousands)
_______________
Eliminated in consolidation.
See accompanying notes to the consolidated financial statements.
Puget Energy
Condensed Statements of Cash Flows
(Dollars in Thousands)
See accompanying notes to the consolidated financial statements.
NOTES TO CONDENSED FINANCIAL STATEMENTS
(1) Basis of Presentation
Puget Energy, Inc. (Puget Energy) is an energy services holding company that conducts substantially all of its business operations through its subsidiary. These condensed financial statements and related footnotes have been prepared in accordance with Rule 12-04, Schedule I of Regulation S-X. These financial statements, in which Puget Energy’s subsidiary has been included using the equity method, should be read in conjunction with the consolidated financial statements and notes thereto of Puget Energy included in Part II, Item 8 of this Form 10-K. Puget Energy owns 100% of the common stock of all its subsidiaries.
Equity earnings of subsidiary included earnings from PSE of $356.1 million, $356.2 million and $204.1 million for the years ended December 31, 2013, 2012 and 2011, respectively, and business combination accounting adjustments under ASC 805 recorded at Puget Energy for PSE of $(4.4) million, $9.4 million and $24.2 million for the years ended December 31, 2013, 2012 and 2011, respectively. Investment in subsidiaries includes Puget Energy business combination accounting adjustments under ASC 805 that are recorded at Puget Energy.
The Company has revised its condensed statements of net income and comprehensive income (loss) for the years ended December 31, 2012 and 2011 for errors in recording comprehensive income of PSE. The Company also revised its condensed statements of cash flows which resulted in adjustments between cash provided by operating activities and cash used investing activities to reflect payments made on unhedged interest rate swap agreements that were previously classified as an operating activity. These adjustments are not considered material, individually or in the aggregate, to the previously issued condensed statements of income and comprehensive income (loss) and condensed statements of cash flows. The table below illustrates the effects of these adjustments on the condensed statements of income and comprehensive income (loss) and condensed statement of cash flows for those line items affected.
(2) Debt
For information concerning Puget Energy’s long-term debt obligations, see Note 6, Long-Term Debt, to the consolidated financial statements of Puget Energy.
(3) Commitments and Contingencies
For information concerning Puget Energy’s material contingencies and guarantees, see Note 15, Commitments and Contingencies, to the consolidated financial statements of Puget Energy.
SCHEDULE II: VALUATION AND QUALIFYING ACCOUNTS AND RESERVES
ITEM 9.
ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE
None.
ITEM 9A.
ITEM 9A. CONTROLS AND PROCEDURES
Puget Energy
Evaluation of Disclosure Controls and Procedures
Under the supervision and with the participation of Puget Energy’s management, including the President and Chief Executive Officer and Senior Vice President and Chief Financial Officer, Puget Energy has evaluated the effectiveness of its disclosure controls and procedures (as defined in Rule 13a-15(e) under the Securities Exchange Act of 1934) as of December 31, 2013, the end of the period covered by this report. Based upon that evaluation, the President and Chief Executive Officer and Senior Vice President and Chief Financial Officer of Puget Energy concluded that these disclosure controls and procedures are effective.
Changes in Internal Control Over Financial Reporting
There have been no changes in Puget Energy’s internal control over financial reporting during the year ended December 31, 2013 that have materially affected, or are reasonably likely to materially affect, Puget Energy’s internal control over financial reporting.
Management’s Report on Internal Control Over Financial Reporting
Puget Energy’s management is responsible for establishing and maintaining adequate internal control over financial reporting (as defined in Rule 13a-15(f) under the Securities Exchange Act of 1934). Under the supervision and with the participation of Puget Energy’s President and Chief Executive Officer and Senior Vice President and Chief Financial Officer, Puget Energy’s management assessed the effectiveness of internal control over financial reporting based on the framework in Internal Control - Integrated Framework (1992) issued by the Committee of Sponsoring Organizations of the Treadway Commission. Based on the assessment, Puget Energy’s management concluded that its internal control over financial reporting was effective as of December 31, 2013.
Puget Energy’s effectiveness of internal control over financial reporting as of December 31, 2013 has been audited by PricewaterhouseCoopers LLP, an independent registered public accounting firm, as stated in their report which is included herein.
Puget Sound Energy
Evaluation of Disclosure Controls and Procedures
Under the supervision and with the participation of PSE’s management, including the President and Chief Executive Officer and Senior Vice President and Chief Financial Officer, PSE has evaluated the effectiveness of its disclosure controls and procedures (as defined in Rule 13a-15(e) under the Securities Exchange Act of 1934) as of December 31, 2013, the end of the period covered by this report. Based upon that evaluation, the President and Chief Executive Officer and Senior Vice President and Chief Financial Officer of PSE concluded that these disclosure controls and procedures are effective.
Changes in Internal Control Over Financial Reporting
There have been no changes in PSE’s internal control over financial reporting during the year ended December 31, 2013 that have materially affected, or are reasonably likely to materially affect, PSE’s internal control over financial reporting.
Management’s Report on Internal Control Over Financial Reporting
PSE’s management is responsible for establishing and maintaining adequate internal control over financial reporting (as defined in Rule 13a-15(f) under the Securities Exchange Act of 1934). Under the supervision and with the participation of PSE’s President and Chief Executive Officer and Senior Vice President and Chief Financial Officer, Puget Sound Energy’s management assessed the effectiveness of internal control over financial reporting based on the framework in Internal Control - Integrated Framework (1992) issued by the Committee of Sponsoring Organizations of the Treadway Commission. Based on the assessment, PSE’s management concluded that its internal control over financial reporting was effective as of December 31, 2013.
PSE’s effectiveness of internal control over financial reporting as of December 31, 2013 has been audited by PricewaterhouseCoopers LLP, an independent registered public accounting firm, as stated in their report which is included herein.
ITEM 9B.
ITEM 9B. OTHER INFORMATION
None.
PART III
ITEM 10.
ITEM 10. DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE
Board of Directors
As of March 13, 2014, twelve directors constitute Puget Energy’s Board of Directors and thirteen directors currently constitute PSE’s Board of Directors, as set forth below. The directors are selected in accordance with the Amended and Restated Bylaws of each of Puget Energy and PSE, pursuant to which, the investor-owners of Puget Holdings (the indirect parent company of both Puget Energy and PSE) are entitled to select individuals to serve on the boards of Puget Energy and PSE.
William Ayer, age 59, is a director on the boards of both Puget Energy and PSE. For over 30 years, Mr. Ayer served in a variety of leadership positions at Alaska Air Group, the parent company of Alaska Airlines and Horizon Air, most recently until 2013 as Chairman. Until May 2012, as the Chief Executive Officer of Alaska Airlines, Mr. Ayer led the nation’s seventh-largest
airline with 9,600 employees. He also oversaw regional carrier Horizon Air and its 3,200 employees. Mr. Ayer is also a member of the board of directors of the Museum of Flight and Angel Flight West and serves on the University of Washington’s Board of Regents and the NextGen Advisory Committee. Mr. Ayer’s experience running a successful company recognized nationally for its award-winning customer service and operational performance, coupled with his community involvement in the western Washington region, are among the qualifications and attributes that led to the conclusion that he should serve on the Puget Energy and PSE boards.
Andrew Chapman, age 58, has been a director on the boards of both Puget Energy and PSE since February 2009. Mr. Chapman is currently a Managing Director in the Macquarie Capital Funds division of the Macquarie Group, which position he has held since 2006. Prior to joining the Macquarie Group, Mr. Chapman was Vice President - Strategy & Regulation for American Water from 2005 to 2006 and Regional Managing Director from 2003 to 2004. Mr. Chapman served as a director on the boards of Duquesne Light Holdings, Inc. and Duquesne Light Company from 2009 to 2013. Mr. Chapman represents the Company’s Macquarie affiliated investors on the boards, in accordance with the terms of the Puget Energy and PSE bylaws, and brings to his service many years of experience in the operational and financial management challenges specific to regulated utilities.
Melanie Dressel, age 61, is a director on the boards of both Puget Energy and PSE, which positions she has held since December 2011. Ms. Dressel is currently President and Chief Executive Officer of Columbia Bank and its parent company, Columbia Banking System, Inc., of Tacoma, Washington, which positions she has held since 2000 and 2003, respectively. An independent director not affiliated with any of the Company’s investors, Ms. Dressel’s leadership skills, financial experience and many ties to civic and community groups in the Company’s service territory are among the reasons for her appointment to the Puget Energy and PSE boards.
Daniel Fetter, age 37, is a director on the boards of both Puget Energy and PSE, which positions he has held since August 2, 2012. Mr. Fetter is currently the Senior Principal, Private Infrastructure with Canada Pension Plan Investment Board (CPPIB), which position he has held since 2009. Prior to that, Mr. Fetter served as both a Principal (from 2007 to 2009) and Associate (from 2006 to 2007) at CPP Investment Board. Mr. Fetter is currently on the Board of Directors of Arqiva, a communications infrastructure and media services company, which position he has held since 2009. Mr. Fetter serves on the boards of Puget Energy and PSE as a representative of CPPIB's ownership interests, pursuant to the terms of the Puget Energy and PSE bylaws, and brings to this service his skills in financial management of infrastructure providers.
Kimberly Harris, age 49, is a director on the boards of both Puget Energy and PSE, which positions she has held since March 1, 2011. Ms. Harris has also been President and Chief Executive Officer since March 1, 2011. Prior to that time, Ms. Harris served as President from July 2010 through February 2011. Ms. Harris also served as Executive Vice President and Chief Resource Officer from May 2007 until July 2010, and was Senior Vice President Regulatory Policy and Energy Efficiency from 2005 until May 2007.
Benjamin Hawkins, age 39, has been a director on the boards of both Puget Energy and PSE since May 21, 2010. Mr. Hawkins is currently a Director of Infrastructure & Timber Investments for Alberta Investment Management Corporation (AimCo), which position he has held since 2012. Mr. Hawkins also served as Principal of Infrastructure Investments of AimCo from November 2008 until June 2011, and Portfolio Manager of Infrastructure Investments from May of 2007 until November 2008. Prior to joining AimCo, Mr. Hawkins held various positions with EPCOR Utilities, a Canadian power and water utility company. Mr. Hawkins serves on the boards as a representative of AimCo’s ownership interest in the Company, pursuant to the terms of the Puget Energy and PSE bylaws, and brings to this service his skills in financial oversight of utilities.
Alan James, age 60, has been a director on the boards of both Puget Energy and PSE since February 2009, as a representative of the Company’s Macquarie affiliated investors consistent with the Puget Energy and PSE bylaws. Mr. James is currently the Chairman and Senior Managing Director of Macquarie Capital (USA) Inc. based in New York where he specializes in providing M&A advice and capital raising solutions to the utility, power and renewable sectors in North America, which position he has held since 2005. Prior to that time, Mr. James was Managing Director and Head, Investment Banking Australia and New Zealand at Citigroup from 2002 to 2005 and held various positions with Deutsche Bank AG in Australia and Europe from 1993 to 2002 specializing in the energy sector. Mr. James provides the boards the benefit of his broad experience with the financial needs and operational and regulatory challenges of infrastructure providers.
Christopher Leslie, age 49, has been a director on the boards of both Puget Energy and PSE since February 2009, as a representative of the Company’s Macquarie affiliated investors consistent with the Puget Energy and PSE bylaws. Mr. Leslie is currently an Executive Director of Macquarie Group Limited, which position he has held since 2005, President of Macquarie Infrastructure and Real Assets Inc., and since 2006 Chief Executive Officer of Macquarie Infrastructure Partners Inc. Mr. Leslie served as a director on the boards of Duquesne Light Holdings, Inc. and Duquesne Light Company in 2009 and 2010. In addition
to his management and banking skills, Mr. Leslie provides the Puget Energy and PSE boards the benefit of his experience with electric utilities, gas distribution systems and other aspects of the infrastructure sector.
David MacMillan, age 61, has been a director on the boards of both Puget Energy and PSE since November 6, 2012. Mr. MacMillan currently is a non-executive director of Viridian Group Ltd., an energy company based in Northern Ireland, and serves on the boards of Potentia Solar Inc. and Eagle Creek Renewable Energy, LLC. He has also served as managing director and senior advisor to Good Energies Capital (now named Bregal Energy), a New York-based private equity fund focused on the renewable energy sector, which positions he held from 2007 to 2010, non-executive director of Ontario Power Generation (from 2004 to 2012) and Intergen (from 2006 to 2008). Mr. MacMillan serves on the boards of Puget Energy and PSE as a representative of CPPIB's ownership interests, pursuant to the terms of the Puget Energy and PSE bylaws, and brings to this service his skills in project finance and experience with managing the capital requirements of energy companies.
Mary McWilliams, age 65, has been a director on the boards of both Puget Energy and PSE since March 1, 2011. Ms. McWilliams is currently the Executive Director at Washington Health Alliance, which position she has held since 2008. She also served as President and Chief Executive Officer at Regence BlueShield from 2000 to 2008. In addition, Ms. McWilliams serves as a Board member of the Seattle Branch of the Federal Reserve Bank of San Francisco. Ms. McWilliams’s significant experience managing consumer-focused organizations with challenging regulatory and compliance regimes, as well as her extensive knowledge of the western Washington economy generally, are some of the reasons that led to her appointment to the Puget Energy and PSE boards on behalf of the CPPIB.
Drew Murphy, age 53, has been a director on the boards of both Puget Energy and PSE since May 8, 2013. Mr. Murphy is currently a Senior Managing Director at Macquarie Infrastructure and Real Assets Inc. (“MIRA”), which position he has held since January 2013. Prior to joining MIRA, Mr. Murphy was an Executive Vice President of NRG Energy, Inc., a power and energy company, from December 2006 through November 2012 and served in several roles during that time, including head of the Strategy and M&A team (from August 2011 to November 2012), President of NRG’s Northeast Region (from February 2009 to July 2011) and General Counsel (from December 2006 to February 2009). Mr. Murphy is a director on the boards of Duquesne Light Holdings, Inc. and Duquesne Light Company. Mr. Murphy serves on the boards of Puget Energy and PSE as a representative of the Company's Macquarie affiliated investors consistent with the Puget Energy and PSE bylaws, and provides the Puget Energy and PSE boards the benefit of his experience managing and overseeing the legal, regulatory and operational affairs of regulated utilities.
Herbert Simon, age 70, is a director on the board of PSE, on which he has served since March 2006. Mr. Simon has been a member of Simon Johnson, L.L.C. (real estate and venture capital projects investment company located in Tacoma, Washington) and its predecessor company since 1985. In addition, Mr. Simon serves as a Regent at the University of Washington and as a Board member of Acre, the real estate committee for the University of Washington. Mr. Simon previously served on the Advisory Boards of the University of Washington at Tacoma and its Institute of Technology. An independent director not affiliated with any of the Company’s investors, Mr. Simon’s long-standing involvement with the commercial, educational, political and philanthropic leadership of western Washington are among the qualifications supporting his appointment to the PSE board.
Christopher Trumpy, age 59, has been a director on the boards of both Puget Energy and PSE since January 12, 2010. Mr. Trumpy is currently a consultant at Circle Square Solutions, which position he has held since 2013. He served as the Chairman of the Pacific Carbon Trust from 2008 to 2013. He also served as Chairman of the British Columbia Investment Management Corporation (or bcIMC) from 2000 to 2008. In addition, Mr. Trumpy served as Deputy Minister at Ministries of Finance, Environment and Provincial Revenue from 1998 to 2009. Mr. Trumpy represents the ownership stake in the Company of bcIMC, in accordance with the terms of the Puget Energy and PSE bylaws, and provides the boards the benefit of his significant leadership roles in government and policy-making, among other attributes.
Executive Officers
The information required by this item with respect to Puget Energy and PSE is incorporated herein by reference to the material under “Executive Officers of the Registrants” in Part I of this report.
Audit Committee
The Puget Energy and PSE Boards of Directors have both established an Audit Committee. Directors Andrew Chapman, Melanie Dressel, Benjamin Hawkins, David MacMillan and Drew Murphy are the members of the Audit Committee. The Board has determined that Andrew Chapman meets the definition of “Audit Committee Financial Expert” under United States Securities and Exchange Commission (SEC) rules. Puget Energy and PSE currently do not have any outstanding stock listed on a national securities exchange and, therefore, there are no independence standards applicable to either company in connection with the independence of its Audit Committee members.
Changes to the Procedures by which Shareholders may recommend Nominees to the Board of Directors
Following the closing of the merger, members of the Boards of Directors of Puget Energy and PSE are nominated and elected in accordance with the provisions of their respective Amended and Restated Bylaws.
Code of Ethics
Puget Energy and PSE have adopted a Corporate Ethics and Compliance Code applicable to all directors, officers and employees and a Code of Ethics applicable to the Chief Executive Officer and senior financial officers, which are available on the website www.pugetenergy.com. If any material provisions of the Corporate Ethics and Compliance Code or the Code of Ethics are waived for the Chief Executive Officer or senior financial officers, or if any substantive changes are made to either code as they relate to any director or executive officer, we will disclose that fact on our website within four business days. In addition, any other material amendments of these codes will be disclosed.
Additional Information
The Company’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. Information may also be obtained via the SEC Internet website at www.sec.gov.
Communications with the Board
Interested parties may communicate with an individual director or the Board of Directors as a group via U.S. Postal mail directed to: Chairman of the Board of Directors, c/o Corporate Secretary, Puget Energy, Inc., P.O. Box 97034, PSE-12, Bellevue, Washington 98009-9734. Please clearly specify in each communication the applicable addressee or addressees you wish to contact. All such communications will be forwarded to the intended director or Board as a whole, as applicable.
ITEM 11.
ITEM 11. EXECUTIVE COMPENSATION
Puget Energy
Puget Sound Energy
Executive Compensation
Compensation and Leadership Development Committee Interlocks and Insider Participation
The members of the Compensation and Leadership Development Committee (referred to as the Committee) of the Boards of Directors (referred to as the Board) of Puget Energy and PSE (referred to as the Company) are named in the Compensation and Leadership Development Committee Report. No members of the Committee were officers or employees of the Company or any of its subsidiaries during 2013, were formerly Company officers or had any relationship otherwise requiring disclosure. Each member meets the independence requirements of the SEC and the New York Stock Exchange (NYSE).
Compensation Discussion and Analysis
This section provides information about the compensation program for the Company’s Named Executive Officers who are included in the Summary Compensation Table. For 2013, the Company’s Named Executive Officers and titles were:
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Kimberly J. Harris, President and Chief Executive Officer (CEO);
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Daniel A. Doyle, Senior Vice President and Chief Financial Officer (CFO);
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Paul M. Wiegand, Senior Vice President, Energy Operations;
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Marla D. Mellies, Senior Vice President, Chief Administrative Officer; and
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Steve R. Secrist, Vice President, General Counsel, Chief Ethics and Compliance Officer.
This section also includes a discussion and analysis of the overall objectives of our compensation program and each element of compensation the Company provides.
Compensation Program Objectives
The Company’s executive compensation program has two main objectives:
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Support sustained Company performance by attracting, retaining and motivating talented people to run the business.
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Align compensation payment levels with achievement of Company goals.
The Committee is responsible for developing and monitoring an executive compensation program and philosophy that achieves the foregoing objectives. In performing its duties, the Committee obtains information and advice on various aspects of its executive compensation program from its independent executive compensation consultant, Frederic W. Cook & Co., Inc. (Cook & Co.). The Committee recommends to the full Board for approval both the salary level for our CEO, based on information provided by Cook & Co., and the salary levels for the other executives, based on recommendations from our CEO. The Committee also recommends to the Board for its approval the annual and long-term incentive compensation plans for the executives, the setting of performance goals and the determination of awards under those plans.
In 2013, the Committee used the following strategies to achieve the objectives of our executive compensation program:
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Design and deliver a competitive total pay opportunity. To attract, retain and motivate a talented executive team, the Committee believes that total pay opportunity should be competitive with similar companies so that new executives will want to join the Company and current executives will be retained. As described below in the discussion of Compensation Program Elements (Review of Pay Element Competitiveness), the Committee annually compares executive compensation to external market data from similar companies in our industry and targets base salary and total direct compensation (which is base salary plus annual and long-term incentive compensation) to the 50th percentile of this comparator group. The Committee also recognizes the importance of providing retirement income. Executives choose to work for the Company as opposed to a variety of other alternative organizations, and one financial goal of employees is to provide a secure future for themselves and their families. The Committee reviews the design of retirement programs provided by our comparator group and provides benefits that are commensurate with this group.
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Place a significant portion of each executive’s total compensation at risk to align executive compensation with Company financial and operating performance. Under its “pay for performance” philosophy, the Committee works to design and deliver an incentive compensation program that supports the Company’s business direction as approved by the Board and aligns executive interests with those of investors and customers. The Committee believes that a significant portion of each executive’s compensation should be “at risk” and rewarded solely for meeting and exceeding target levels of annual and long-term performance goals. By establishing goals, monitoring results, and rewarding achievement of goals, the Company focuses executives on actions that will improve the Company and enhance investor value, while also retaining key talent. The Committee annually evaluates the performance factors and targets for our annual and long-term incentive programs and considers adjustments as appropriate to meet the objectives of our executive compensation program. As described under “Risk Assessment,” the Company’s policies and practices surrounding incentive pay are structured in a manner to mitigate the risk that employees would seek to take untoward risks in an attempt to increase incentive results.
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Oversee the Company’s succession planning process to ensure that executive leadership continues uninterrupted by executive retirements or other personnel changes. The CEO leads the talent reviews for leadership succession planning through meetings and discussions with her executive team. Each executive conducts talent reviews of senior employees that report to him or her and who have high potential for assuming greater responsibility in the Company. Utilizing evaluations and assessments, the Committee and the Board annually review these assessments of executive readiness, the plans for development of the Company’s key executives, and progress made on these succession plans. The Committee and the Board directly participate in discussion of succession plans for the position of CEO.
Compensation Program Elements
The Company’s compensation program encompasses a mix of base salary, annual and long-term incentive compensation, retirement programs, health and welfare benefits and a limited number of perquisites. The Company also provides certain post-termination and change in control benefits to executives who were employed by the Company prior to March 2009. Since the Company is not publicly listed and does not grant equity awards to its executives, it relies on a mix of non-equity compensation elements to achieve its compensation objectives.
The total compensation package is designed to provide participants with appropriate incentives that are competitive with the comparator group and is also designed to achieve current operational performance and customer service goals as well as the long-term objective of enhancing investor value. The Company does not have a specific policy regarding the mix of compensation elements, although long-term incentive programs are designed to comprise the largest portion of each executive’s incentive pay. The Company arrives at a mix of pay by setting each compensation element relative to market comparators. The Company delivered cash compensation to the Named Executive Officers in 2013 through base salary to provide liquidity for the executives and through incentive programs to focus performance on important Company goals and to increase the alignment with investors. The Committee annually reviews total compensation opportunity and actual total compensation received over the prior years by each executive officer in the form of a tally sheet. This review helps inform the Committee’s decisions on program designs by allowing the Committee to review overall pay received in relation to Company results.
Review of Pay Element Competitiveness
To help inform the Committee’s recommendations on base salary, annual incentive programs and long-term incentive programs, management prepares comprehensive compensation surveys for review by the Committee and Cook & Co. The surveys summarize data provided by the Towers Watson 2012 Energy Services survey for a selection of utility and other companies that are most similar in scope and size to PSE. For purposes of 2013 compensation, Cook & Co. also suggested minor changes to the comparator peer group. Thirteen of the seventeen companies listed below are the same as used in 2012. Of the five companies not used in 2013, two companies had been acquired and one was publicly owned and not viewed as a comparator by Cook & Co. Cook & Co. recommended excluding two others and adding four new companies that were all included in the Towers Watson 2012 Energy Services survey. Based on the recommendation of Cook & Co. for the review of compensation pay levels and practices in 2013, we included the following utility companies in our comparator group that were all of similar scope (generally $1.5 billion - $6.0 billion revenue and $4.0 billion - $15.0 billion asset size) and also participated in the Towers Watson 2012 Energy Services survey:
Base pay and total direct compensation are targeted to the 50th percentile of the industry comparator group assuming the Company’s performance goals are achieved at target. If Company performance results are below expectations, total direct compensation is lower than this targeted level. If Company performance significantly exceeds target, total cash compensation can approach or exceed the 75th percentile of the industry comparator group.
Individual pay adjustments are reviewed to see how they position the executive in relation to the 50th percentile of market pay, while also considering the executive’s recent performance and experience level. The Company may choose to pay an executive above or below the 50th percentile of market pay when that individual has a role with greater or lesser responsibility than the best comparison job or when our executive’s experience and performance exceed those typically found in the market. In addition to the foregoing survey data, the Committee generally also received advice from Cook & Co. in connection with 2013 compensation decisions.
Base Salary
We recognize that it is necessary to provide executives with a fixed amount of total compensation that is delivered each month and provides a balance to other pay elements that are at risk. Base salaries are generally targeted at the 50th percentile of the comparator group and are reviewed annually by the Committee on an individual basis using as a guideline, the 50th percentile salary levels of our comparator group, as well as internal pay equity among our executives. Actual salaries vary by individual and depend on additional factors, such as an individual’s expertise, level of performance achievement, level of experience and level of contribution relative to others in the organization.
Base Salary Adjustments
The Committee reviewed the base salaries of the Named Executive Officers in early 2013 and recommended base salary adjustments to the Board. The Board approved the Committee’s recommendation to increase executive salaries, and base salaries for 2013 generally remained at the 50th percentile of market among the comparator group. Effective March 1, 2013, the Board increased the base salary of Ms. Harris, President and CEO, from $820,000 to $875,000. In establishing the salary amount for Ms. Harris, the Committee recommended and the Board approved a base salary that continued to be below the 50th percentile of market among the comparator group, reflecting Ms. Harris's length of tenure as President and CEO of the Company. The salary increase percentages approved by the Board for the other Named Executive Officers were in a range of 2% to 5%, similar to salary increases for other non-represented employees.
Incentive Compensation (Annual and Long-Term)
Our annual and long-term incentive plans help focus executives on the priorities of our investors and customers and reward performance that meets or exceeds pre-established goals. The Company’s annual incentive plan rewards employees for the Company’s performance on Service Quality Indices (SQIs), employee safety and EBITDA. SQIs were developed in collaboration with the Company’s regulator, the Washington Commission, and provide customers with a report card on the Company’s customer service and reliability. The Company's Long Term Incentive Plan (LTI Plan) rewards employees for the Company's performance on Total Return and Return on Equity (ROE). Total Return reflects the annual change in the value of the Company plus any distributions made to investors. The performance measures of EBITDA, Total Return, and ROE are all indicators of economic return to our investors, and their accomplishment indicates to our customers that the Company has the financial strength needed for long-term sustainability.
2013 Annual Incentive Compensation
All PSE employees, including the Named Executive Officers, are eligible to participate in an annual incentive program referred to as the “Goals and Incentive Plan.” The plan is designed to provide financial incentives for achieving desired annual operating results, measured by EBITDA, while also meeting the Company’s service quality commitment to customers and an employee safety measure. EBITDA was selected as a performance goal because it provides a financial measure of cash flows generated from the Company’s annual operating performance.
For 2013, the Company’s service quality commitment was measured by performance against 9 SQIs covering three broad categories, set forth below. These are the same SQIs for which the Company is accountable to the Washington Commission. The Company's annual report to the Washington Commission and our customers describes each SQI, how it is measured, the Company’s required level of achievement, and performance results. The Company’s service quality report cards are available at http://www.PSE.com/PerformanceReportCards.
The SQIs for 2013 were the same as in 2012 and were as follows:
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Customer Satisfaction (3 SQIs)
- Customer satisfaction with the telephone access center and gas field services and number of Washington Commission complaints
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Customer Service (2 SQIs)
- Calls answered “live” and on-time appointments
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Safety and Reliability (4 SQIs)
- Gas emergency response, electric emergency response, non-storm outage frequency and non-storm outage duration
In 2013, to continue emphasizing the Company's commitment to employee safety, the Company included a safety performance measure in the annual incentive plan funding. The employee safety measure functions similarly to the 9 SQIs in determining the funding of the annual incentive plan. That is, if the safety measure is not achieved, annual incentive funding will be decreased by 10%, in the same way as a missed SQI. The safety performance measure contains five targets which must all be satisfied for the safety measure to be treated as met. The five targets for 2013 were:
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Office Supervisors receive appropriate safety and health training. The completion rate for this target is no less than 95%.
•All new employees receive applicable safety and health orientation. The target is no less than 95% for all new hires.
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Increase Employee health by having employees complete health awareness training. The completion rate of this target is no less than 95%.
•The Company Total Incident Case Rate (TICR) not to exceed a rate of 1.40 in 2013.
•The Company Lost Workday Case Rate (LWCR) not to exceed a rate of 0.29 in 2013.
In 2013, the annual incentive funding table required achievement of 10 out of 10 customer service and safety measures (all 9 SQIs and achievement of the safety measure) and target EBITDA performance for 100% funding of the plan. Eight of the nine SQIs were met. The one SQI which was not met, Calls Answered within 30 seconds, had been affected by the Company’s implementation of a new customer service computer system. The Board of Directors approved considering the Calls Answered SQI met for incentive purposes. The Safety measure met on four out of five parts, but because all five were not met, it was not passed. In total, 9 out of 10 customer service and safety measures were met or deemed met.
Funding levels at maximum, target, and threshold are shown in the table below.
The Committee can adjust EBITDA used in the annual incentive calculation to exclude nonrecurring items that are outside the normal course of business for the year, but did not exclude any items for 2013. Individual awards may be adjusted upward or downward based on a subjective evaluation of an executive officer’s performance against individual and team goals. Individual goals were developed from the overall corporate goals for 2013, set forth below:
2013 Corporate Goals
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Be well, get ready, stay safe - Make PSE a safe place to work. Increase employee health, wellness and emergency preparedness. Make our community a safe place by increasing awareness of emergency preparedness and investing in pipeline safety and reliability.
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Drive value, drive growth - Give customers better reliability, more choices and greater value. Improve dependability, and offer customers more choices to manage their accounts and services. Drive growth and revenue through new services and products for our customers.
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Go big - Small steps won’t get us where we need to be. We are all accountable for continuously improving our processes to achieve our five-year plan by banishing waste, eliminating inefficiencies and focusing on the price of our service.
2013 Annual Incentive Plan Results
Achievement of the corporate goals for 2013 was at target for EBITDA, and near target for SQI and safety achievement. PSE EBITDA was $1,155.6 million, and SQI and safety achievement was 9 out of 10, leading to a funding level for 2013 of 90.36% under the annual incentive plan.
For 2013, individual target incentive levels for this plan varied by executive officer as a percentage of 2013 base salary as shown in the table below, based on the individual executive’s level of responsibility within the Company. Target annual incentive opportunities as a percentage of base salary for participating executives remained unchanged from 2012 levels except for Ms. Harris. The Board approved an increase in 2013 target award for Ms. Harris. The maximum incentive for exceptional performance in this plan is twice the target incentive. As described above, an executive’s individual award amount can be increased or decreased based on a subjective assessment by the CEO (or the Board in the case of the CEO) of the executive’s individual and team performance results. After considering performance on individual and team goals, which were determined to be met or exceeded by each executive, small adjustments were made by the CEO for individual performance of the Named Executive Officers below CEO in 2013 and the following amounts were approved by the Board and paid at the amounts as shown below. The adjustments for individual performance did not materially change amounts from the formula amount of 90.36% of target. The Committee similarly recommended an award amount for the CEO which included a small adjustment for individual performance in 2013 and to recognize that the Company met 2013 annual incentive goals. The Board approved the amounts shown below, which were paid in March 2014.
Long-Term Incentive Compensation
Long-term incentive compensation opportunities are designed to be competitive with market practices, reward long-term performance and promote retention. Prior to completion of our merger in February 2009, executives received equity awards under the Puget Energy 2005 LTI Plan in the form of performance shares and performance-based restricted stock. Following our merger, the Company has continued the basic design of the pre-merger LTI Plan, including retention of three-year performance cycles that begin each year. Since the Company no longer grants equity awards to its employees, LTI Plan awards are now denominated in units and are settled in cash if threshold performance measures are met.
The Committee determines the number of LTI Plan units granted to each executive by evaluating the actual payment and forecast target payment of long-term incentive awards of our market comparator group for comparable levels of responsibility. The Committee generally does not consider previously granted awards or the level of accrued value from prior or other programs when granting annual incentive awards or making new LTI Plan grants. Each year’s grant is primarily viewed in the context of the compensation opportunity needed to maintain the Company’s competitive position relative to the comparator group.
The total amount payable for a performance cycle is calculated at the end of the performance cycle based on the actual level of achievement of the performance measures as well as the per unit dollar value at the end of the performance cycle. Unit value is measured at the Puget Holdings level and is re-calculated each year in the performance period based on the change in Total Return for the prior year as measured by an independent auditing firm. Executives generally must be employed on the payment date to receive a cash payment under the LTI Plan, except in the event of retirement at normal retirement age or approved early retirement, disability or death.
The tables and points below summarize the performance measures and design of the LTI Plan grants for the performance cycles indicated below.
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*
CEO grants for 2011-2013 are split 30% SQI Component and 70% Total Return Component.
**
Total Return Component is determined based on a combination of Total Return and 3-year average SQI results.
Long-Term Incentive Plan Performance Measures for 2012-2014 and 2013-2015
As described above, the LTI Plan structure from 2009 through 2011 maintained the basic design which had been in place prior to the Company's merger in 2009. Effective with the 2012-2014 LTI Plan grants, the Board approved certain modifications to the performance measures under the LTI Plan. Pursuant to these modifications, SQI achievement was removed as a performance measure in favor of a new performance measure, Return on Equity (ROE). Total Return remains a key performance measure under the 2012-2014 and 2013-2015 performance cycles, consistent with prior performance cycles under the LTI Plan. SQI achievement was removed to make the plan easier to understand and to remove the duplication of awards based on SQI performance, since SQI performance is already a performance measure under the annual incentive plan. As a result of the modifications, both LTI Plan performance measures for the 2012-2014 and 2013-2015 performance cycles are financial in nature and each is weighted 50%. With the implementation of solely financial performance measures, the President and CEO position receives grants of LTI Plan units with a 50%/50% split between Total Return and ROE, like all other LTI Plan participants.
Target LTI Plan awards for the 2013-2015 performance cycle were calculated based on a percentage of an executive's annual base salary, taking into account the executive's level of responsibility within the Company. Target LTI Plan awards for the 2013-2015 performance cycle were 170% of base salary for Ms. Harris; 95% for Mr. Doyle, Mr. Wiegand and Ms. Mellies; and 50% for Mr. Secrist, which percentages were unchanged from amounts established for the 2012-2014 performance cycle. The total number of LTI Plan units granted to a Named Executive Officer for the 2013-2015 performance cycle is equal to the applicable percentage of salary (converted to dollars) divided by the per unit value at the beginning of the performance cycle, which was $36.32. The maximum incentive payable if exceptional performance is achieved on both performance measures for the LTI Plan is twice the target LTI Plan award. Details of the number of units granted and expected value can be found in the “2013 Grants of Plan-Based Awards” table below.
Long Term Incentive Plan Performance Measures for 2011-2013
With respect to the 2011-2013 performance cycle, except for the CEO, 50% of each grant of LTI Plan units is allocated to achievement of SQIs only (SQI component) and 50% is allocated to achievement of a combination of SQIs and Total Return (Total Return component). The CEO’s LTI Plan units are allocated 30% to the SQI component and 70% to the Total Return component to place additional weight on financial measures, consistent with our comparator group companies. The total number of LTI Plan units granted to a Named Executive Officer is equal to the applicable percentage of salary (converted to dollars) divided by the per unit value at the beginning of the performance cycle. For the 2011-2013 performance cycle, the initial per unit value was $33.80. The total amount payable for a performance cycle is calculated at the end of the performance cycle based on the actual level of achievement of SQIs and Total Return as well as the per unit dollar value at the end of the performance cycle. For any award to be earned in the 2011-2013 performance cycle, average SQI results must meet or exceed 80% accomplishment of the applicable SQIs.
The table below shows the percentage of LTI Plan target awards that could be earned based on three-year average SQI achievement.
The table below shows the percentage of LTI Plan target awards under the Total Return Component that could be earned based on three-year performance. Percentages will be interpolated if performance falls between the values shown below.
SQI Component (50%):
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A target number of units were granted under this component at the beginning of the three-year performance cycle that will be paid in cash to the participant if the Company achieves the targeted level of 80% of SQIs during the performance cycle. The actual award is paid at target level if an average of at least 80% of SQIs are satisfied during the performance cycle, but is not paid if the average is below 80%. If targeted SQI performance is met, the amount payable is equal to the product of the target number of units granted under this component and the per unit value at the end of the performance cycle.
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If 80% of SQIs are met during the performance cycle, but the Total Return threshold of 10% is not met, the SQI component will still be paid at target.
Total Return Component (50%):
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A target number of units were granted under this component at the beginning of a three-year performance cycle that will be paid in cash to the participant if the Company achieves the targeted level of Total Return and SQI performance during the three-year performance cycle. The actual award paid is based on Company performance relative to target, subject to a minimum threshold level of performance of 10% for Total Return (based on average Total Return over the performance cycle) and average SQI achievement of 80%.
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The LTI Plan unit value is determined annually by applying the Total Return for each year to the prior year’s unit price.
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At the completion of the performance cycle, if the Total Return component is paid, the participant receives a cash payment equal to the number of units earned under this component based on performance during the performance cycle multiplied by the unit price at the end of the performance cycle.
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If the Total Return component exceeds 10% annualized 3-year return, but the SQI threshold is not met, the Total Return component will not be paid.
LTI Plan Performance of Outstanding Performance Cycles: Payouts for 2011-2013 Performance Cycle
2013-2015 Performance Cycle:
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Award calculation is based on the full three-year performance cycle, so no award payment calculations will be made until after 2015.
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Performance on the Total Return component during 2013 was above the three-year average threshold needed for payment but below the target level.
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Performance on the ROE component for 2013 was below the target level but above the threshold level. This result will be one of the three annual ROE results averaged at the end of the performance cycle.
2012-2014 Performance Cycle:
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Award calculation is based on the full three-year performance cycle, so no award payment calculations will be made until after 2014.
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Performance on the Total Return component through 2012 and 2013 was below the three-year average threshold needed for payment.
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Performance on the ROE component for 2012 was above the target level and for 2013 was below the target level. Through two years, the overall result on the ROE component is above the threshold level but below the target level.
2011-2013 Performance Cycle:
The 2011-2013 performance cycle has now ended and had the performance described below. Amounts payable as a result
of award vesting are shown in the table below.
•
Performance on the SQI component of the grant was 9 out of 9 in 2011, 10/10 for 2012, and 9 out of 10 for 2013 for a combined three-year result of 97%, which qualified for payment of the SQI component based on the target number of units granted to a Named Executive Officer.
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Performance on the Total Return component for the combined three-year average was a compounded annual rate of 5.6%, below the three-year average threshold needed for payment.
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Target LTI Plan Incentive is a percentage of 2011 base salary when the grants were made in 2011.
2011-2013 actual LTI Plan amount payable is unit price $39.77 multiplied by SQI Component units. The Total Return Component Units did not meet minimum performance threshold for payment.
Retirement Plans - SERP and Retirement Plan
The Company maintains the Supplemental Executive Retirement Plan (SERP) to attract and retain executives by providing a benefit that is coordinated with the tax-qualified Retirement Plan for Employees of Puget Sound Energy, Inc. (Retirement Plan). Without the addition of the SERP, these executives would receive lower percentages of replacement income during retirement than other employees. All the Named Executive Officers participate in the SERP. The Committee reviewed the SERP plan during 2012 with input from Cook & Co. and modified the plan design to ensure alignment with competitive practices and with the retention goals of the program. The plan changes were effective January 1, 2013 and include a requirement that new participants reach age 55 while employed by the Company (or its affiliates) in order to vest in accrued benefits (in addition to existing vesting requirements) and a revision to the calculation of highest average earnings to require the use of three consecutive
years of eligible compensation in the last ten years of service. The plan changes do not increase the expected cost of the SERP program, and in certain instances are expected to decrease program costs. Additional information regarding the SERP and the Retirement Plan is shown in the “2013 Pension Benefits” table.
Deferred Compensation Plan
The Named Executive Officers are eligible to participate in the Deferred Compensation Plan for Key Employees (Deferred Compensation Plan). The Deferred Compensation Plan provides eligible executives an opportunity to defer up to 100% of base salary, annual incentive bonuses and earned LTI Plan awards, plus receive additional Company contributions made by PSE into an account that has three investment tracking fund choices. The funds mirror performance in major asset classes of bonds, stocks, and an interest crediting fund that changes rates quarterly. The Deferred Compensation Plan is intended to allow the executives to defer current income, without being limited by the Internal Revenue Code contribution limitations for 401(k) plans and therefore have a deferral opportunity similar to other employees as a percentage of eligible compensation. The Company contributions are also intended to restore benefits not available to executives under PSE’s tax-qualified plans due to Internal Revenue Code limitations on compensation and benefits applicable to those plans. Additional information regarding the Deferred Compensation Plan is shown in the “2013 Nonqualified Deferred Compensation” table.
Post-Termination Benefits
Effective March 30, 2009, the Company entered into Executive Employment Agreements with the Named Executive Officers, except Mr. Doyle (who was not then employed by the Company), and Mr. Secrist (who was not then an officer), which amended and restated then existing Amended and Restated Change of Control Agreements between the Company and each of the executives. The Executive Employment Agreements provided for an employment period of two years following the completion of a merger and otherwise generally provide benefits similar to those under the previous Change of Control Agreements. Since the 2009 merger, the Company has ceased entering into these agreements with new executive officers.
The Committee periodically reviews existing change in control and severance arrangements for the comparator group. Based on this information, the Committee believes that the current arrangements generally provide benefits that are similar to those of the comparator group for longer tenured executives, but is not extending them to newly hired executives.
The “Potential Payments Upon Termination or Change in Control” section describes the current post-termination arrangements with the Named Executive Officers as well as other plans and arrangements that would provide benefits on termination of employment or a change in control, and the estimated potential incremental payments upon a termination of employment or change in control based on an assumed termination or change in control date of December 31, 2013.
Other Compensation
In addition to base salary and annual and long-term incentive award opportunities, the Company also provides the Named Executive Officers with benefits and limited perquisites targeted to competitive practices. The Company may provide payments upon hiring a new executive to help offset the executive’s relocation expenses, a practice needed to attract qualified candidates from other areas of the country. The current executives participate in the same group health and welfare plans as other employees. Company vice presidents and above, including the Named Executive Officers, are eligible for additional disability and life insurance benefits. The executives are also eligible to receive reimbursement for financial planning, tax preparation, legal services, business club memberships and executive physicals up to an annual limit. The reimbursement for financial planning, tax preparation and legal services is provided to allow executives to concentrate on their business responsibilities. Business club memberships are provided to allow access for business meetings and business events at club facilities and executives are required to reimburse the Company for individual use of club facilities. These perquisites generally do not make up a significant portion of executive compensation and did not exceed $10,000 in total for each Named Executive Officer in 2013.
Relationship among Compensation Elements
A number of compensation elements increase in absolute dollar value as a result of increases to other elements. Base salary increases translate into higher dollar value incentive opportunity for annual and long-term incentives, because each plan operates with a target level award set as a percentage of base salary. Base salary increases also increase the level of retirement benefits, as do actual annual incentive plan payments. Some key compensation elements are excluded from consideration when determining other elements of pay. Retirement benefits exclude LTI Plan payments in the calculation of qualified retirement (pension and 401(k)) and SERP benefits.
Impact of Accounting Treatment of Compensation
The accounting treatment of compensation generally has not been a factor in determining the amounts of compensation for our executive officers. However, the Company considers the accounting impact of various program designs to balance the potential cost to the Company with the benefit/value to the executive.
Risk Assessment
A portion of each executive’s total direct compensation is variable, at risk and tied to the Company’s financial and operational performance to motivate and reward executives for achievement of Company goals. The Company’s variable pay program helps focus executives on interests important to the Company and its investors and customers and creates a record of their results. In structuring its incentive programs, the Company also strives to balance and moderate risk to the Company from such programs: individual award opportunities are defined and subject to limits, goal funding is based on collective company performance, annual incentive awards are balanced by long-term incentive awards that measure performance over three years, performance targets are based on management’s operating plan (which includes providing good customer service), and all incentive awards to individual executives are subject to discretionary review by management, the Committee and/or the Board. As a result, the Committee and the Board believe that the programs’ design do not have risks that are reasonably likely to have a material adverse effect on the Company and also provide appropriate incentive opportunities for executives to achieve Company goals that support the interests of our investors and customers.
Compensation and Leadership Development Committee Report
The Board delegates responsibility to the Compensation and Leadership Development Committee to establish and oversee the Company’s executive compensation program. Each member of the Committee served during all of 2013, except as noted below.
The Committee members listed below have reviewed and discussed the “Compensation Discussion and Analysis” with the Company’s management. Based on this review and discussion, the Committee recommended to the Board, and the Board has approved, that the “Compensation Discussion and Analysis” be included in the Company’s Annual Report on Form 10-K for the year ended December 31, 2013 for filing with the SEC.
Compensation and Leadership
Development Committee of
Puget Energy, Inc.
Puget Sound Energy, Inc.
Christopher Trumpy, Chair
Melanie Dressel, committee member as of July 2013
Daniel Fetter
Christopher Leslie
Mary McWilliams
Herbert B. Simon (PSE Only)
SUMMARY COMPENSATION TABLE
The following information is furnished for the year ended December 31, 2013 (and for prior years where applicable) with respect to the Named Executive Officers during 2013. The positions listed below are at Puget Energy and PSE, except that Mr. Wiegand and Ms. Mellies are executives of PSE only. Positions listed are those held by the Named Executive Officers as of December 31, 2013. Salary and incentive compensation includes amounts deferred at the executive’s election.
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For 2013, reflects annual cash incentive compensation paid under the 2013 Goals and Incentive Plan and cash incentive compensation paid under the LTI Plan for the 2011-2013 performance cycle. Cash incentive amounts were paid in early 2014 or deferred at the executive's election. The 2013 Goals and Incentive Plan and the LTI Plan are described in further detail under “Compensation Discussion and Analysis,” including the individual amounts paid to each Named Executive Officer in early 2014.
Reflects the aggregate increase in the actuarial present value of the executive’s accumulated benefit under all pension plans during the year. The amounts are determined using interest rate and mortality rate assumptions consistent with those used in the Company’s financial statements and include amounts which the executive may not currently be entitled to receive because such amounts are not vested. Information regarding these pension plans is set forth in further detail under “2013 Pension Benefits.” The change in pension value amounts for 2013 are: Ms. Harris, $1,462,607; Mr. Doyle, $269,754; Mr. Wiegand, $384,082; Ms. Mellies, $205,027; and Mr. Secrist, $304,051. Also included in this column are the portions of Deferred Compensation Plan earnings that are considered above market. These amounts for 2013 are: Ms. Harris, $3,007; Mr. Doyle, $0; Mr. Wiegand, $3,387.32; Ms. Mellies, $420.93; and Mr. Secrist $0. See the “2013 Nonqualified Deferred Compensation” table for all Deferred Compensation Plan earnings.
All Other Compensation for 2013 is shown in detail in the table below.
Ms. Harris was promoted to President and CEO from President on March 1, 2011.
Mr. Doyle joined PSE and Puget Energy as Senior Vice President and Chief Financial Officer on November 28, 2011.
Mr. Wiegand has worked at PSE since June 1977.
Ms. Mellies has worked at PSE since October 2005.
Mr. Secrist has worked at PSE since May 1989.
Detail of All Other Compensation
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After an initial reimbursement up to $7,500, annual reimbursement for financial planning, tax planning, and/or legal planning, up to a maximum of $5,000 for Ms. Harris and $2,500 for the other Named Executive Officers. This column also includes club use which is primarily for business purposes, but Company club expense is included when the executive is also able to use the club for personal use. Expenses for personal club use are directly paid by the executive, not PSE.
Includes Company contributions during 2013 to PSE’s Investment Plan (a tax qualified 401(k) plan) and the Deferred Compensation Plan. Company 401(k) contributions are as follows: Ms. Harris, $17,800; Mr. Doyle, 17,800; Mr. Wiegand, 15,971.51; Ms. Mellies, $17,800; and Mr. Secrist, 15,826.93. Company contributions to the Deferred Compensation Plan are as follows: Ms. Harris, $0; Mr. Doyle, $27,432.08; Mr. Wiegand, $13,390; Ms. Mellies, $8,435.70; and Mr. Secrist $0.
Reflects the value of imputed income for life insurance and Company paid premiums on supplemental disability insurance.
2013 Grants of Plan-Based Awards
The following table presents information regarding 2013 grants of non-equity annual incentive awards and LTI Plan awards, including, as applicable, the range of potential payouts for the awards.
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As described in the “Compensation Discussion and Analysis,” the 2013 Goals and Incentive Plan had dual funding triggers in 2013 of $1,040 million EBITDA and SQI performance of 6/10. Payment would be $0 if either trigger is not met. The threshold estimate assumes $1,040 million EBITDA and SQI/Safety measure performance at 6/10. The target estimate assumes $1.155 million EBITDA and SQI/Safety measure performance at 10/10. The maximum estimate assumes $1,559 million EBITDA or higher and SQI/Safety measure performance at 10/10.
As described in the “Compensation Discussion and Analysis,” LTI Plan grants were allocated between a Total Return component and an ROE component. Payments are calculated based on Total Return at Puget Holdings, the average three-year performance of ROE and the unit value at the end of the performance cycle.
2013 Pension Benefits
The Company and its affiliates maintain two pension plans: the Retirement Plan and the SERP. The following table provides information for each of the Named Executive Officers regarding the actuarial present value of the executive’s accumulated benefit and years of credited service under the Retirement Plan and the SERP. The present value of accumulated benefits was determined using interest rate and mortality rate assumptions consistent with those used in the Company’s financial statements. Each of the Named Executive Officers participates in both plans.
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The amounts reported in this column for each executive were calculated assuming no future service or pay increases. Present values were calculated assuming no pre-retirement mortality or termination. The values under the Retirement Plan and the SERP are the actuarial present values as of December 31, 2013 of the benefits earned as of that date and payable at normal retirement age (age 65 for the Retirement Plan and age 62 for the SERP). Future cash balance interest credits are 4.0% for 2013 and are assumed to be 4.0% through 2017, and 5.0% annually thereafter. The discount assumption is 5.10%, and the post-retirement mortality assumption is based on the 2014 417(e) unisex mortality table. Annuity benefits are converted to lump sum amounts at retirement based on assumed future 417(e) segment rates of % 1.37%, 4.05%, and 5.06% (the 24 month average of the underlying rates as of September 2013). These assumptions are consistent with the ones used for the Retirement Plan and the SERP for financial reporting purposes for 2013. In order to determine the change in pension values for the Summary Compensation Table, the values of the Retirement Plan and the SERP benefits were also calculated as of December 31, 2012 for the benefits earned as of that date using the assumptions used for financial reporting purposes for 2012. These assumptions included assumed cash balance interest credits of 4.0% for 2013 a discount assumption of 4.15% and post-retirement mortality assumption based on the 2013 417(e) unisex mortality table. Annuity benefits were converted to lump sum amounts at retirement based on assumed future 417(e) segment rates of 1.75%, 4.62% and 5.72% (the 24 month average of the underlying rates as of September 2012). Other assumptions used to determine the value as of December 31, 2012 were the same as those used for December 31, 2013.
As described in footnote 1 above, the amounts reported for the SERP in this column are actuarial present values, calculated using the actuarial assumptions used for financial reporting purposes. These assumptions are different from those used to calculate the actual amount of benefit payments under the SERP (see text below for a discussion of the actuarial assumptions used to calculate actual payment amounts). The following table shows the estimated lump sum amount that would be paid under the SERP to each SERP-eligible Named Executive Officer at age 62 (without discounting to the present), calculated as if such Named Executive Officer had terminated employment on December 31, 2013. Each SERP-eligible Named Executive Officer (except Mr. Doyle) was vested in his or her SERP benefits as of December 31, 2013.
Retirement Plan
Under the Retirement Plan, the Company's eligible salaried employees, including the Named Executive Officers, accrue benefits in accordance with a cash balance formula, beginning on the later of their date of hire or March 1, 1997. Under this formula, for each calendar year after 1996, age-weighted pay credits are allocated to a bookkeeping account (a Cash Balance Account) for each participant. The pay credits range from 3% to 8% of eligible compensation. Non-represented and UA-represented employees hired on or after January 1, 2014 will receive pay credits equal to 4%, which non-represented employees may choose to contribute to the Retirement Plan or to the Investment Plan. Eligible compensation generally includes base salary and bonuses (other than bonuses paid under the LTI Plan and signing, retention and similar bonuses), up to the limit imposed by the Internal Revenue Code. For 2013, the limit was $255,000. For 2014, the limit is $260,000. In addition, as of March 1, 1997, the Cash Balance Account of each participant who was participating in the Retirement Plan on March 1, 1997 was credited with an amount based on the actuarial present value of that participant’s accrued benefit, as of February 28, 1997, under the Retirement Plan’s previous formula. Amounts in the Cash Balance Accounts are also credited with interest. The interest crediting rate is 4% per year or such higher amount as PSE may determine. For 2013 and 2014, the annual interest crediting rate was 4%.
A participant’s Retirement Plan benefit generally vests upon the earlier of the participant’s completion of three years of active service with Puget Energy, PSE or their affiliates or attainment of age 65 (the Retirement Plan’s normal retirement age) while employed by the Company or one of its affiliates. Normal retirement benefit payments begin to a vested participant as of the first day of the month following the later of the participant’s termination of employment or attainment of age 65. However, a vested participant may elect to have his or her benefit under the Retirement Plan paid, or commence to be paid, as of the first day of any month commencing after the date on which his or her employment with Puget Energy, PSE and their affiliates terminates. If benefit payments commence prior to the participant’s attainment of age 65, then the amount of the monthly payments will be reduced for early commencement to reflect the fact that payments will be made over a longer period of time. This reduction is subsidized - that is, it is less than a pure actuarial reduction. The amount of this reduction is, on average, 0.30% for each of the first 60 months, 0.33% for each of the second 60 months, 0.23% for each of the third 60 months and 0.17% for each of the fourth 60 months that the payment commencement date precedes the participant’s 65th birthday. Further reductions apply for each additional month that the payment commencement date precedes the participant’s 65th birthday. As of December 31, 2013, all the Named Executive Officers, except Mr. Doyle, were vested in their benefits under the Retirement Plan and, hence, would be eligible to commence benefit payments upon termination.
The normal form of benefit payment for unmarried participants is a straight life annuity providing monthly payments for the remainder of the participant’s life, with no death benefits. The straight life annuity payable on or after the participant's normal retirement age is actuarially equivalent to the balance in the participant’s Cash Balance Account as of the date of distribution. For married participants, the normal form of benefit payment is an actuarially equivalent joint and 50% survivor annuity with a “pop-up” feature providing reduced monthly payments (as compared to the straight life annuity) for the remainder of the participant’s life and, upon the participant’s death, monthly payments to the participant’s surviving spouse for the remainder of the spouse’s life in an amount equal to 50% of the amount being paid to the participant. Under the pop-up feature, if the participant’s spouse predeceases the participant, the participant’s monthly payments increase to the level that would have been provided under the straight life annuity. In addition, the Retirement Plan provides several other annuity payment options and a lump sum payment option that can be elected by participants. All payment options are actuarially equivalent to the straight life annuity. However, in no event will the amount of the lump sum payment be less than the balance in the participant’s Cash Balance Account as of the date of distribution (in some instances the amount of the lump sum distribution may be greater than the balance in the Cash Balance Account due to differences in the mortality table and interest rates used to calculate actuarial equivalency).
If a participant in the cash balance portion of the Retirement Plan dies while employed by the Company or any of its affiliates, then his or her Retirement Plan benefit will be immediately vested. If a vested participant dies before his or her Retirement Plan benefit is paid, or commences to be paid, then the participant’s Retirement Plan benefit will be paid to his or her beneficiary(ies). If a participant dies after his or her Retirement Plan benefit has commenced to be paid, then any death benefit will be governed by the form of payment elected by the participant.
Supplemental Executive Retirement Plan
The SERP provides a benefit to participating Named Executive Officers that supplements the retirement income provided to the executives by the Retirement Plan. All the Named Executive Officers participate in the SERP. As described in the “Compensation Discussion and Analysis,” the Company modified certain features of the SERP, effective January 1, 2013, to ensure alignment with competitive practices and with the retention goals of the plan. The plan changes do not increase the expected cost of the SERP program, and in certain instances are expected to decrease program costs. The plan changes include an additional vesting requirement for new participants to attain age 55 prior to vesting and a modified calculation of highest average earnings for all participants. The changes are reflected below in the description of SERP benefit calculations. The changes apply to existing and prospective SERP participants unless otherwise noted. For an existing participant, the change requiring consecutive years in the highest average earnings definition could result in a lower SERP benefit amount if high earnings years are not consecutive,
compared to the benefit amount calculated under plan terms prior to January 1, 2013. On an ongoing basis, as new participants join the program, the plan changes will lead to reduced aggregate costs attributable to SERP.
A participating Named Executive Officer’s SERP benefit generally vests upon the executive’s completion of five years of participation in the SERP and attainment of age 55 while employed by the Company or any of its affiliates. All the participating Named Executive Officers, except Mr. Doyle, are vested in their SERP benefits. SERP participants as of December 31, 2013, who had not yet attained age 55 at that date, including Ms. Harris, Ms. Mellies, and Mr. Secrist, have been exempted from the age 55 vesting requirement. The Board added a special vesting requirement for Ms. Harris to continue Company service through December 31, 2016 in order to vest additional SERP benefit value after December 31, 2012.
The monthly benefit payable under the SERP to a vested executive (calculated in the form of a straight life annuity payable for the executive’s lifetime commencing at the later of the executive’s date of termination or attainment of age 62) is equal to (1) below minus the sum of (2) and (3) below:
(1)
One-twelfth (1/12) of the executive’s highest average earnings times the executive’s years of credited service (not in excess of 15) times 3-1/3%. For purposes of the SERP, “highest average earnings” means the average of the executive’s highest three consecutive calendar years of earnings. The three consecutive calendar years must be among the last ten calendar years completed by the executive prior to his or her termination. Prior to December 31, 2012, a participant's highest average earnings was not required to be calculated based on a three consecutive year basis. Executives participating in the SERP as of December 31, 2012 will have their highest average earnings on that date preserved as a minimum value for highest average earnings in the future. “Earnings” for this purpose include base salary and annual bonus, but do not include long-term incentive compensation. An executive will receive one “year of credited service” for each consecutive 12-month period he or she is employed by the Company or its affiliates. If an executive becomes entitled to disability benefits under PSE’s long-term disability plan, then the executive’s highest average earnings will be determined as of the date the executive became disabled, but the executive will continue to accrue years of credited service until he or she begins to receive SERP benefits.
(2)
The monthly amount payable (or that would be payable) under the Retirement Plan to the executive in the form of a straight life annuity commencing as of the first day of the month following the later of the executive’s date of termination or attainment of age 62, including amounts previously paid or segregated pursuant to a qualified domestic relations order.
(3)
The actuarially equivalent monthly amount payable (or that would be payable) to the executive as of the first day of the month following the later of the executive’s date of termination or attainment of age 62 from any pension-type rollover accounts within the Deferred Compensation Plan (including the annual cash balance restoration account). These accounts are described in more detail in the “2013 Nonqualified Deferred Compensation” section.
Normal retirement benefits under the SERP generally are paid or commence to be paid within 90 days following the later of the Named Executive Officer’s termination of employment or attainment of age 62. Except as provided below, SERP benefits are normally paid in a lump sum that is equal to the actuarial present value of the monthly straight life annuity benefit. In lieu of the normal form of payment, an executive may elect to receive his or her SERP benefit in the form of monthly installment payments over a period of two to 20 years, in a straight life annuity or in a joint and survivor annuity with a 100%, 75%, 50% or 25% survivor benefit. All payment options are actuarially equivalent to the straight life annuity. Mr. Wiegand is the only Named Executive Officers eligible for early retirement benefit payments under the SERP as of December 31, 2013.
If a participating Named Executive Officer dies while employed by Puget Energy, PSE or any of their affiliates or after becoming vested in his or her SERP benefit, but before his or her SERP benefit has commenced to be paid, then the executive’s surviving spouse will receive a lump sum benefit equal to the actuarial equivalent of the survivor benefit such spouse would have received under the joint and 50% survivor annuity option. This amount will be calculated assuming the executive would have commenced benefit payments in that form on the first day of the month following the later of his or her death or attainment of age 62, with any applicable reductions for early commencement if the executive dies before age 62. If the executive is not married, then no death benefit will be paid. If an executive dies after his or her SERP benefit has commenced to be paid, then any death benefit will be governed by the form of payment elected by the executive.
2013 Nonqualified Deferred Compensation
The following table provides information for each of the Named Executive Officers regarding aggregate executive and Company contributions and aggregate earnings for 2013 and year-end account balances under the Deferred Compensation Plan.
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The amount in this column reflects elective deferrals by the executive of salary, annual incentive compensation or LTI Plan awards paid in 2013. Deferred salary amounts are: Ms. Harris, $0; Mr. Doyle, $23,359.50; Mr. Wiegand, $18,315.99; Ms. Mellies, $7,883.64; and Mr. Secrist, $0. Deferred incentive compensation amounts are: Ms. Harris, $0; Mr. Doyle, $1,872.58; Mr. Wiegand, $0; Ms. Mellies, $0; and Mr. Secrist $0. The amounts are also included in the applicable column of the Summary Compensation Table for 2013.
The amount reported in this column reflects contributions by PSE consisting of the annual investment plan restoration amount and annual cash balance restoration amount described below. These amounts are also included in the total amounts shown in the All Other Compensation column of the Summary Compensation Table for 2013.
The amount in this column for each executive reflects the change in value of investment tracking funds. Above market earnings on these amounts are included in the Change in Pension Value and Nonqualified Deferred Compensation Earnings column of the Summary Compensation Table for 2013.
Of the amounts in this column, the amounts in the table below have also been reported in the Summary Compensation Table for 2013, 2012, and 2011.
Deferred Compensation Plan
The Named Executive Officers are eligible to participate in the Deferred Compensation Plan and may defer up to 100% of base salary, annual incentive compensation and LTI Plan payments. In addition, each year, executives are eligible to receive Company contributions under the Deferred Compensation Plan to restore benefits not available to them under the Company's tax-qualified plans due to limitations imposed by the Internal Revenue Code. The annual investment plan restoration amount equals the additional matching and any other employer contribution under the 401(k) plan that would have been credited to an electing executive’s 401(k) plan account if the Internal Revenue Code limitations were not in place and if deferrals under the Deferred Compensation Plan were instead made to the 401(k) plan. The annual cash balance restoration amount equals the actuarial equivalent of any reductions in an executive’s accrued benefit under the Retirement Plan due to Internal Revenue Code limitations or as a result of deferrals under the Deferred Compensation Plan. An executive must generally be employed on the last day of the year to receive these Company contributions, unless he or she retires or dies during the year in which case the Company will contribute a prorated amount.
The Named Executive Officers choose how to credit deferred amounts among three investment tracking funds. The tracking funds mirror performance in major asset classes of bonds, stocks, and a money market index. For deferrals prior to 2012, an interest crediting fund was available. The tracking funds differ from the investment funds offered in the 401(k) plan. The 2013 calendar year returns of these tracking funds were:
The Named Executive Officers may change how deferrals are allocated to the tracking funds at any time. Changes generally become effective as of the first trading day of the following calendar quarter.
The Named Executive Officers generally may choose how and when to receive payments under the Deferred Compensation Plan. There are three types of in-service withdrawals. First, an executive may choose an interim payment of deferred amounts by designating a plan year for payment at the time of his or her deferral election. The interim payment is made in a lump sum within 60 days after the last day of the designated plan year, which must be at least two years following the plan year of the deferral. Second, an in-service withdrawal may also be made to an executive upon a qualifying hardship event and demonstrated need. Third, only with respect to amounts deferred and vested prior to 2005, the executive may elect an in-service withdrawal for any reason by paying a 10% penalty. Payments upon termination of employment depend on whether the executive is then eligible for retirement. If the executive's termination occurs prior to his or her retirement date (generally the earlier of attaining age 62 or age 55 with five years of credited service), the executive will receive a lump sum payment of his or her account balance. If the executive’s termination occurs after his or her retirement date, the executive may choose to receive payments in a lump sum or via one of several installment options (fixed amount, specified amount, annual or monthly installments, of up to 20 years). Mr. Wiegand is the only Named Executive Officer currently retirement eligible under the Deferred Compensation Plan.
Potential Payments Upon Termination or Change in Control
The Estimated Potential Incremental Payments Upon Termination or Change in Control table below reflects the estimated amount of incremental compensation payable to each of the Named Executive Officers in the event of (i) an involuntary termination without cause or by the executive for good reason not in connection with a change in control; (ii) a change in control; (iii) an involuntary termination without cause or for good reason in connection with a change in control; (iv) retirement; (v) disability; or (vi) death.
Certain Company benefit plans provide incremental benefits or payments in the event of certain terminations of employment. In addition, each Named Executive Officer, other than Mr. Doyle and Mr. Secrist, entered into an Executive Employment Agreement with the Company in March 2009, which provides for benefits or payments upon certain terminations of employment from the Company following the 2009 merger or a subsequent change in control. The only benefit payable to the Named Executive Officers solely upon a change in control is accelerated vesting of LTI Plan awards, described below.
Disability and Life Insurance Plans
If a Named Executive Officer’s employment terminates due to disability or death, the executive or his or her estate will receive benefits under the PSE disability plan or life insurance plan available generally to all salaried employees. These disability and life insurance amounts are not reflected in the table below. The Named Executive Officer is also eligible to receive supplemental disability and life insurance. The supplemental monthly disability coverage is 65% of monthly base salary and target annual incentive pay, reduced by (i) amounts receivable under the PSE disability plan generally available to salaried employees and (ii) certain other income benefits. The supplemental life insurance benefit is provided at two times base salary and target annual incentive bonus if the executive dies while employed by PSE with a reduction for amounts payable under the applicable group life insurance policy.
LTI Plan Awards
If a Named Executive Officer’s employment terminates due to disability or death, the executive or his or her estate will be paid a pro-rata portion of LTI Plan awards that were granted in a prior year. In the case of retirement at normal retirement age or approved early retirement, pro-rata LTI Plan awards will be paid in the first quarter following the year of retirement, based on performance through the prior year. In the event of a change in control, outstanding LTI Plan awards will be paid at the higher of (i) target performance or (ii) actual performance achieved during the performance cycle ending with the fiscal quarter that precedes the change of control.
Employment Agreements with Named Executive Officers
In March 2009, PSE entered into Executive Employment Agreements (Employment Agreements) with each of the Named Executive Officers except Mr. Doyle and Mr. Secrist (collectively, individual parties to such Employment Agreements, the Covered Executives), the terms of which are the same for all the Covered Executives and which amended and restated then existing Amended and Restated Change of Control Agreements between the Company and each of the Covered Executives. The Employment Agreements provide for an employment period of two years following completion of a merger, and generally provides benefits similar to those provided under the previous Change of Control Agreements. In the event of a termination of employment within two years of a change in control (a Covered Termination), a Covered Executive is eligible to receive the payments described below. A change in control generally means a person (or group of persons) (with certain exceptions set forth in the Employment
Agreements) acquires (i) beneficial ownership of more than 55% of the total combined voting power of the Company’s securities outstanding immediately after such acquisition (other than through a registered public offering) or (ii) all or substantially all of the Company’s assets.
Payments upon Involuntary Termination without Cause or for Good Reason
If a Covered Executive’s employment is terminated without cause by the Company or is terminated by the Covered Executive for good reason within two years of a change in control, the Covered Executive is eligible to receive the following compensation and benefits:
•
Three times the sum of annual base salary and annual incentive bonus for the year in which termination occurs;
•
Pro-rated annual incentive bonus for the year in which termination occurs (Annual Bonus). Since this amount was earned for 2013, no amount is shown in the table below;
•
Supplemental retirement benefit equal to the difference between (x) the actuarial equivalent of the amount the Covered Executive would have received under the Retirement Plan and the SERP had his or her employment continued until the end of two years following the change in control, and (y) the actuarial equivalent of the amount the Covered Executive actually receives or is entitled to receive under the Retirement Plan and SERP; and
•
Continued group medical, dental, disability and life insurance benefits to the Covered Executive and his or her family. Benefits will be paid by the Company while the Covered Executive is eligible for COBRA and thereafter by reimbursement of payments made by the Covered Executive for such coverage (including related tax amounts), except that if the Covered Executive becomes re-employed with another employer and is eligible to receive medical or other welfare benefits under another employer-provided plan, the medical and other welfare benefits under the Employment Agreement will become secondary to those provided by the other employer (the foregoing benefit is referred to as Health and Welfare Benefit Continuation).
Under the Employment Agreements, “cause” and “good reason” have the following meanings:
Cause generally means (i) the willful and continued failure by the Covered Executive to substantially perform the Covered Executive’s duties with the Company (other than any such failure resulting from incapacity due to physical or mental illness) for a period of 30 days after written notice of demand for substantial performance has been delivered to the Covered Executive or (ii) the Covered Executive’s willfully engaging in gross misconduct materially and demonstrably injurious to the Company, as determined by the Board after notice to the executive and opportunity for a hearing. No act or failure to act on the Covered Executive’s part is considered “willful” unless the Covered Executive has acted or failed to act with an absence of good faith and without a reasonable belief that the Covered Executive’s action or failure to act was in the best interests of the Company.
Good Reason generally means (i) the assignment of the Covered Executive to a non-officer position with the Company, which the parties agree would constitute a material reduction in the Covered Executive’s authority, duties or responsibilities; (ii) a material diminution in the Covered Executive’s total compensation opportunities under the Employment Agreement; (iii) the Company’s requiring the Covered Executive to be based at any location that represents a material change from the Covered Executive’s location in the Seattle/Bellevue metropolitan area, unless the Covered Executive consents to the relocation; or (iv) a material breach of the Employment Agreement by the Company, provided that, in any of the foregoing, the Company has not remedied the alleged violation(s) within 60 days of notice from the Covered Executive.
Payments upon Retirement, Disability or Death
In the event of a Covered Termination due to voluntary retirement after having attained age 55 with a minimum of five years of service to the Company, a pro-rated Annual Bonus is payable to the Covered Executive. The bonus is payable at the time the Covered Executive otherwise would have received the payment had employment continued, based on the Company’s actual achievement of performance goals.
In the event of a Covered Termination due to disability or death, the Covered Executive is eligible to receive the following compensation and benefits:
•
Pro-rated Annual Bonus; and
•
Health and Welfare Benefit Continuation.
In addition, upon termination for any of the foregoing reasons, other than by reason of retirement, the Covered Executive is eligible to receive the perquisite of financial planning.
Except as otherwise described above, payments of salary and bonus will be paid after the date of termination, subject to the Covered Executive’s timely execution of a general waiver and release of claims.
The Employment Agreements also contain noncompetition and anti-solicitation provisions that restrict the Covered Executive for twelve months after termination from, respectively, engaging in activities related to selling or distributing electric power or natural gas in Washington or soliciting others to leave the Company or causing them to be hired from the Company by another entity. The Employment Agreements contain a non-disparagement clause and a confidentiality clause pursuant to which the Covered Executives must keep confidential all secret or confidential information, knowledge or data relating to the Company and its affiliates obtained during their employment. The Covered Executives may not disclose any such information, knowledge or data after their respective terminations of employment unless PSE consents in writing or as required by law.
If any payments paid or payable in connection with a change in control while the Company's stock is not traded on an established securities market or otherwise immediately before such change in control, then the Covered Executive will agree to execute a waiver of any “excess parachute payments” (within the meaning of Section 280G of the Internal Revenue Code), provided that the Company agrees to seek, but is not required to obtain, shareholder approval of the amount payable in connection with termination of employment, in which case the waived amounts will be restored to the Covered Executive.
Estimated Potential Incremental Payments Upon Termination or Change in Control
The amounts shown in the table below assume that the termination of employment of a Named Executive Officer or a change in control was effective as of December 31, 2012. The amounts below are estimates of the incremental amounts that would be paid out to the Named Executive Officer upon a termination of employment or a change in control. Actual amounts payable can only be determined at the time of a termination of employment or a change in control.
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SERP values are shown as the estimated incremental value that the Named Executive Officer would receive at age 62 as a result of the termination event shown in the column, relative to the vested benefit as of December 31, 2013. These values are based on interest rate and mortality rate assumptions consistent with those used in the Company’s financial statements.
Benefits (continuation) reflects the value of continued medical, dental, disability and life insurance benefits as well as financial planning benefit in the amount of $5,000 for Ms. Harris and $2,500 for all the other Named Executive Officers eligible for benefits continuation.
Director Compensation for Fiscal Year 2013
The following table sets forth information regarding compensation paid by the Company to the directors named in the table who received compensation from the Company in 2013 for service as directors. We refer to these directors as nonemployee directors. Directors who are employed by the Company or by the Company’s investor-owners are not paid separately for their service and thus are not named in the table below. The directors who are employed by the Company’s investor-owners are: Andrew Chapman, Daniel Fetter, Benjamin Hawkins, Alan James, Alan Kadic (who resigned in August 2012), Christopher Leslie, David
MacMillan, John McMahon, and Mark Wiseman (who resigned in November, 2012). Kimberly Harris is employed by the Company and also serves as a director.
As described in further detail below, the Company’s nonemployee director compensation program in 2013 consisted of quarterly retainer cash fees of $20,000. Additional quarterly retainer amounts associated with serving as Chair of the Board, chairing Board committees, serving on the Audit Committee and meeting fees were also paid in cash.
_______________
Represents earnings accrued on deferred compensation considered to be above market.
Nonemployee Director Compensation Program
The 2013 nonemployee director compensation program is based on the principles that the level of nonemployee director compensation should be based on Board and committee responsibilities and should be competitive with comparable companies.
The 2013 compensation program for nonemployee directors was as follows:
•
A base cash quarterly retainer fee of $20,000;
•
$1,600 for attendance at each in-person Board and committee meeting; and
•
$800 for each telephonic meeting lasting 60 minutes or less, and $1,600 for each telephonic meeting lasting more than 60 minutes.
In 2013, nonemployee directors were paid the following additional cash quarterly retainer fees:
•
Independent Board Chairman, $10,000;
•
Chair of the Governance and Public Affairs Committees, $1,500;
•
Chair of the Audit Committee, $2,500; and
•
Each member of the Audit Committee other than the chair, $1,000.
Nonemployee directors were reimbursed for actual travel and out-of-pocket expenses incurred in connection with their services.
Nonemployee directors are eligible to participate in the Company’s matching gift program on the same terms as all Puget Energy employees. Under this program, the Company matches up to a total of $300 a year in contributions by a director to non-profit organizations that have Internal Revenue Service (IRS) 501(c)(3) tax exempt status and are located in and served the people of PSE’s service territory in Washington State.
Deferral of Compensation
Nonemployee directors may choose to elect to defer all or a part of their cash fees under the Company’s Deferred Compensation Plan for Nonemployee Directors. Nonemployee directors may allocate these deferrals into one or more “measurement funds,” which include an interest crediting fund, an equity index fund and a bond index fund. Nonemployee directors are permitted to make changes in measurement fund allocations quarterly. None of the independent board members deferred any director fees during 2013.
ITEM 12.
ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED SHAREHOLDER MATTERS
Security Ownership of Directors, Executive Officers and Certain Beneficial Owners
The following tables show the number of shares of common stock beneficially owned as of December 31, 2013 by each person or group that we know owns more than 5.0% of Puget Energy’s and PSE’s common stock. No director, executive officer or executive officer named in the Summary Compensation Table in Item 11 of Part III of this report owns any of the outstanding shares of common stock of Puget Energy or PSE. Puget Equico and its affiliates beneficially own 100.0% of the outstanding common stock of Puget Energy. Puget Energy holds 100.0% of the outstanding common stock of PSE. Percentage of beneficial ownership is based on 200 shares of Puget Energy common stock and 85,903,791 shares of Puget Sound Energy common stock outstanding as of December 31, 2013.
Beneficial Ownership Table of Puget Energy and PSE
_______________
1.
Information presented above and in this footnote is based on Amendment No. 2 to Schedule 13D/A filed on February 13, 2009 (the Schedule 13D) by Puget Equico LLC (Puget Equico), Puget Intermediate Holdings Inc. (Puget Intermediate), Puget Holdings (Puget Holdings and together with Puget Intermediate, the Parent Entities), Macquarie Infrastructure Partners I (formerly MIP Padua Holdings GP) (MIP), Macquarie Infrastructure Partners II (formerly MIP Washington Holdings, L.P.) (MIP II), FSS Infrastructure Trust (formerly Macquarie-FSS Infrastructure Trust) (FIT), Padua MG Holdings LLC (PMGH) Canada Pension Plan Investment Board (USRE II) Inc. (CPPIB), 6860141 Canada Inc. as trustee for British Columbia Investment Management Corporation (bcIMC), PIP2PX (Pad) Ltd. (PIP2PX) and PIP2GV (Pad) Ltd. (PIP2GV and together with MIP, MIP II, FIT, PMGH, CPPIB, bcIMC and PIP2PX, the Investors). Puget Equico is a wholly-owned subsidiary of Puget Intermediate, Puget Intermediate is a wholly-owned subsidiary of Puget Holdings and the Investors are the direct or indirect owners of Puget Holdings. The Parent Entities and the Investors are the direct or indirect owners of Puget Equico. Although the Parent Entities and the Investors do not own any shares of Puget Energy directly, Puget Equico, the Parent Entities and the Investors may be deemed to be members of a “group,” within the meaning of Section 13(d)(3) of the Securities Exchange Act of 1934, as amended. Accordingly, each such entity may be deemed to beneficially own the 200 shares of Puget Energy common stock owned by Puget Equico. Such shares of common stock constitute 100.0% of the issued and outstanding shares of common stock of Puget Energy. Under Section 13(d)(3) of the Exchange Act and based on the number of shares outstanding, Puget Equico, the Parent Entities and the Investors may be deemed to have shared power to vote and shared power to dispose of such shares of Puget Energy common stock that may be beneficially owned by Puget Equico. However, each of Puget Equico, the Parent Entities and the Investors expressly disclaims beneficial ownership of such shares of common stock other than those shares held directly by such entity. According to the Schedule 13D, as of February 13, 2009:
•
The address of the principal office of Puget Holdings, Puget Intermediate and Puget Equico is the PSE Building, 10885 NE 4th Street, Bellevue, WA 98009.
•
The address of the principal office of MIP and MIP II is 125 West 55th Street, Level 22, New York, NY 10019.
•
The address of the principal office of FIT is Level 21, 83 Clarence Street, Sydney, Australia NSW 2000.
•
The address of the principal office of PMGH is 125 West 55th Street, Level 22, New York, NY 10019.
•
The address of the principal office of CPPIB is One Queen Street East, Suite 2600, P.O. Box 101, Toronto, Ontario, Canada M5C 2W5.
•
The address of the principal office of bcIMC is Sawmill Point, Suite 301-2940 Jutland Road, Victoria, British Columbia, Canada V8T 5K6.
•
The address of the principal office of PIP2PX and PIP2GV is 1100, 10830 Jasper Avenue, Edmonton, Alberta, Canada T5J 2B3.
2.
Pursuant to that certain Pledge Agreement dated as of May 10, 2010, as amended on February 10, 2012, made by Puget Equico to JPMorgan Chase Bank, N.A., as administrative agent, the outstanding stock of Puget Energy held by Puget Equico was pledged by Puget Equico to secure the obligations of Puget Energy under (a) the Credit Agreement dated as of February 10, 2012 among Puget Energy., JPMorgan Chase Bank, N.A., as administrative agent, the other agents party thereto, and the lenders party thereto and (b) the senior secured notes issued on December 6, 2010, June 3, 2011 and June 15, 2012.
3.
Pursuant to that certain Borrower's Security Agreement dated as of May 10, 2010, as amended on February 10, 2012, the outstanding stock of PSE held by Puget Energy was pledged by Puget Energy to secure its obligations under (a) the Credit Agreement dated as of February 10, 2012 among Puget Energy as Borrower, JPMorgan Chase Bank, N.A., as administrative agent, the other agents party thereto, and the lenders party thereto and (b) the senior secured notes issued on December 6, 2010, June 3, 2011 and June 15, 2012.
ITEM 13.
ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS, AND DIRECTOR INDEPENDENCE
Transactions with Related Persons
Our Boards of Directors have adopted a written policy for the review and approval or ratification of related person transactions. Under the policy, our directors and executive officers are expected to disclose to our Chief Compliance Officer the material facts of any transaction that could be considered a related person transaction promptly upon gaining knowledge of the transaction. A related person transaction is generally defined as any transaction required to be disclosed under Item 404(a) of Regulation S-K, the SEC’s related person transaction disclosure rule.
Any transaction reported to the Chief Compliance Officer will be reviewed according to the following procedures:
•
If the Chief Compliance Officer determines that disclosure of the transaction is not required under the SEC’s related person transaction disclosure rule, the transaction will be deemed approved and will be reported to the Audit Committee.
•
If disclosure is required, the Chief Compliance Officer will submit the transaction to the Chair of the Audit Committee who will review and, if authorized, will determine whether to approve or ratify the transaction. The Chair is authorized to approve or ratify any related person transaction involving an aggregate amount of less than $1.0 million or when it would be impracticable to wait for the next Audit Committee meeting to review the transaction.
•
If the transaction is outside the Chair’s authority, the Chair will submit the transaction to the Audit Committee for review and approval or ratification.
When determining whether to approve or ratify a related person transaction, the Chair of the Audit Committee or the Audit Committee, as applicable, will review relevant facts regarding the related person transaction, including:
•
The extent of the related person’s interest in the transaction;
•
Whether the terms are comparable to those generally available in arms’ length transactions; and
•
Whether the related person transaction is consistent with the best interests of the Company.
If any related person transaction is not approved or ratified, the Committee may take such action as it may deem necessary or desirable in the best interests of the Company and its shareholders.
Kimberly Harris, the President and Chief Executive Officer, and a director of Puget Energy and PSE, is married to Kyle Branum, a principal at the law firm Riddell Williams P.S., one of PSE’s primary law firms for nearly 50 years. In 2013, Riddell Williams was paid $1.39 million for legal services provided to PSE and Mr. Branum is among the lawyers at Riddell Williams who provided such legal services. This work was performed under the supervision of PSE's General Counsel and the compensation arrangements were comparable to other regional law firms providing legal services to PSE.
Puget Energy is party to interest rate swap agreements, negotiated under the ISDA (“ISDA agreements”), with various parties, including Macquarie Bank Limited. Affiliates of Macquarie Bank Limited indirectly own an equity interest in PSE. The ISDA agreements were the product of arms' length negotiations between Puget Energy and the various counterparties, including Macquarie Bank Limited, and contain terms and conditions similar to those of other master swap agreements with unrelated third parties.
Board of Directors and Corporate Governance
Independence of the Board
The Boards of Puget Energy and PSE have reviewed the relationships between Puget Energy and PSE (and their respective subsidiaries) and each of their respective directors. Based on this review, the Boards have determined that of the members constituting the Boards, William Ayer (member of the Boards of both Puget Energy and PSE), Mary McWilliams (member of the Boards of both Puget Energy and PSE), Melanie Dressel (member of the Boards of both Puget Energy and PSE), and Herbert Simon (member of the Board of PSE) are independent under the NYSE corporate governance listing standards and also meet the definition of an “Independent Director” under the Company’s Amended and Restated Bylaws. Under the Amended and Restated Bylaws of Puget Energy and PSE, an Independent Director is a director who: (a) shall not be a member of Puget Holdings (referred to as a Holdings Member) or an affiliate of any Holdings Member (including by way of being a member, stockholder, director, manager, partner, officer or employee of any such member), (b) shall not be an officer or employee of PSE, (c) shall be a resident of the state of Washington, and (d) if and to the extent required with respect to any specific director, shall meet such other qualifications as may be required by any applicable regulatory authority for an independent director or manager. The Company’s definition of “Independent Director” is available in the Corporate Governance Guidelines at www.pugetenergy.com.
In making these independence determinations, the Boards have established a categorical standard that a director’s independence is not impaired solely as a result of the director, or a company for which the director or an immediate family member of the director serves as an executive officer, making payments to PSE for power or natural gas provided by PSE at rates fixed in conformity with law or governmental authority, unless such payments would automatically disqualify the director under the NYSE’s corporate governance listing standards. The Board has also established a categorical standard that a director’s independence is not impaired if a director is a director, employee or executive officer of another company that makes payments to or receives payments from Puget Energy, PSE or any of their affiliates, for property or services in an amount which is less than the greater of $1.0 million or one percent of such other company’s consolidated gross revenue, determined for the most recent fiscal year. These categorical standards will not apply, however, to the extent that Puget Energy or PSE would be required to disclose an arrangement as a related person transaction pursuant to Item 404 of Regulation S-K.
The Boards considered all relationships between its directors and Puget Energy and PSE (and their respective subsidiaries), including some that are not required to be disclosed in this report as related-person transactions. Messrs. Ayer and Simon, Ms. McWilliams and Ms. Dressel serve as directors or officers of, or otherwise have a financial interest in, entities that make payments to PSE for energy services provided to those entities at tariff rates established by the Washington Commission. These transactions fall within the first categorical independence standard described above. In addition, PSE has entered into transactions with entities for whom Mr. Simon and Mr. Ayer serve as a director, or in which they otherwise have a financial interest, that involve amounts that are less than the greater of $1.0 million or 1% of those entities’ consolidated gross revenue. These transactions fall within the second categorical standard described above. Because these relationships either fall within the Board’s categorical independence standards or involve an amount that is not material to the Company or the other entity, the Boards have concluded that none of these relationships impair the independence of the applicable directors.
Executive Sessions
Non-management directors meet in executive session on a regular basis, generally on the same date as each scheduled Board meeting. Mr. Ayer, who is not a member of management, presides over the executive sessions. Interested parties may communicate with the non-management directors of the Board through the procedures described in Item 10 of Part III of this annual report under the section “Communications with the Board.”
ITEM 14.
ITEM 14. PRINCIPAL ACCOUNTANT FEES AND SERVICES
The aggregate fees billed by PricewaterhouseCoopers LLP, the Company’s independent registered public accounting firm, for the years ended December 31 were as follows:
_______________
For professional services rendered for the audit of Puget Energy’s and PSE’s annual financial statements and reviews of financial statements included in the Company’s Forms 10-Q. The 2013 fees are estimated and include an aggregate amount of $1.3 million billed to Puget Energy and $1.2 million to PSE through December 2013.
Consists of work performed in connection with registration statements and other regulatory audits.
Consists of tax consulting and tax return reviews.
The Audit Committee of the Company has adopted policies for the pre-approval of all audit and non-audit services provided by the Company’s independent registered public accounting firm. The policies are designed to ensure that the provision of these services does not impair the firm’s independence. Under the policies, unless a type of service to be provided by the independent registered public accounting firm has received general pre-approval, it will require specific pre-approval by an Audit Committee. In addition, any proposed services exceeding pre-approved cost levels will require specific pre-approval by an Audit Committee.
The annual audit services engagement terms and fees, as well as any changes in terms, conditions and fees relating to the engagement, are subject to specific pre-approval by the Audit Committee. In addition, on an annual basis, the Audit Committee grants general pre-approval for specific categories of audit, audit-related, tax and other services, within specified fee levels, that may be provided by the independent registered public accounting firm. With respect to each proposed pre-approved service, the
independent registered public accounting firm is required to provide detailed back-up documentation to the Audit Committee regarding the specific services to be provided. Under the policies, the Audit Committee may delegate pre-approval authority to one or more of their members. The member or members to whom such authority is delegated shall report any pre-approval decision to the Audit Committee at its next scheduled meeting. The Audit Committee does not delegate responsibilities to pre-approve services performed by the independent registered public accounting firm to management.
For 2013 and 2012, all audit and non-audit services were pre-approved.
PART IV
ITEM 15.
ITEM 15. EXHIBITS AND FINANCIAL STATEMENT SCHEDULES
a)
Documents filed as part of this report:
1)
Financial Statements.
2)
Financial Statement Schedules. Financial Statement Schedules of the Company, as required for the years ended December 31, 2013, 2012 and 2011, consist of the following:
I.
Condensed Financial Information of Puget Energy
II.
Valuation of Qualifying Accounts and Reserves
3)
Exhibits
SIGNATURES
Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, each registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.
Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of each registrant and in the capacities and on the dates indicated.
Signature
Title
Date
(Puget Energy and PSE unless otherwise noted)
/s/ Kimberly J. Harris
President and
March 13, 2014
(Kimberly J. Harris)
Chief Executive Officer
/s/ Daniel A. Doyle
Senior Vice President and
(Daniel A. Doyle)
Chief Financial Officer
/s/ Michael J. Stranik
Controller and Principal Accounting Officer
(Michael J. Stranik)
/s/ William S. Ayer
Chairman and Director
(William S. Ayer)
/s/ Andrew Chapman
Director
(Andrew Chapman)
/s/ Melanie Dressel
Director
(Melanie Dressel)
Director
(Daniel Fetter)
/s/ Benjamin Hawkins
Director
(Benjamin Hawkins)
Director
(Alan W. James)
/s/ Christopher J. Leslie
Director
(Christopher J. Leslie)
/s/ David MacMillan
Director
(David MacMillan)
/s/ Drew Murphy
Director
(Drew Murphy)
/s/ Mary O. McWilliams
Director
(Mary O. McWilliams)
/s/ Christopher Trumpy
Director
(Christopher Trumpy)
/s/ Herbert B. Simon
Director of PSE only
(Herbert B. Simon)
EXHIBIT INDEX
Certain of the following exhibits are filed herewith. Certain other of the following exhibits have heretofore been filed with the United States Securities and Exchange Commission (SEC) and are incorporated herein by reference.
______________________
*
Filed herewith.
**
Management contract, compensating plan or arrangement.
***
In accordance with Rule 406T of Regulation S-T, the XBRL information in Exhibit 101 to this annual report on Form 10-K shall not be deemed to be “filed” for purposes of Section 18 of the Securities Exchange Act of 1934, as amended (Exchange Act), or otherwise subject to the liability of that section, and shall not be incorporated by reference into any registration statement or other document filed under the Securities Act of 1933, as amended, or the Exchange Act, except as shall be expressly set forth by specific reference in such filing.