UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
FORM 10-K
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/X/ | ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 |
For the fiscal year ended December 31, 20162019
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/ / | TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 |
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| For the transition period from ___________ to ___________ |
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Commission File Number | Exact name of registrant as specified in its charter, state of incorporation, address of principal executive offices, zip code telephone number | I.R.S. Employer Identification Number |
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1-16305 | PUGET ENERGY, INC. A Washington Corporation 10885355 110th Ave NE 4th Street, Suite 1200
Bellevue, Washington 98004-559198004 (425) 454-6363 | 91-1969407 |
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1-4393 | PUGET SOUND ENERGY, INC. A Washington Corporation 10885355 110th Ave NE 4th Street, Suite 1200
Bellevue, Washington 98004-559198004 (425) 454-6363 | 91-0374630 |
Securities registered pursuant to Section 12(b) of the Act: None
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Title of Each Class | | Trading Symbol | | Name of Each Exchange on Which Registered |
N/A | | N/A | | N/A |
Securities registered pursuant to Section 12(g) of the Act: None
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Title of Each Class | | Trading Symbol | | Name of Each Exchange on Which Registered |
N/A | | N/A | | N/A |
Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act.
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Puget Energy, Inc. | Yes | / / |
| No | /X/ |
| Puget Sound Energy, Inc. | Yes | / / |
| No | /X/ |
Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Act.
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Puget Energy, Inc. | Yes | / / |
| No | /X/ |
| Puget Sound Energy, Inc. | Yes | / / |
| No | /X/ |
Indicate by check mark whether the registrants: (1) have filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrants were required to file such reports), and (2) have been subject to such filing requirements for the past 90 days.
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Puget Energy, Inc. | Yes | /X/ |
| No | / / |
| Puget Sound Energy, Inc. | Yes | /X/ |
| No | / / |
Indicate by check mark whether the registrants have submitted electronically and posted on its corporate websites, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T during the preceding 12 months (or for such shorter period that the registrant was required to postsubmit such files).
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Puget Energy, Inc. | Yes | /X/ |
| No | / / |
| Puget Sound Energy, Inc. | Yes | /X/ |
| No | / / |
Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K is not contained herein, and will not be contained, to the best of registrant’s knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K. /X/
Indicate by check mark whether registrant is a large accelerated filer, an accelerated filer, or a non-accelerated filer. See definition of “accelerated filer and large accelerated filer” in Rule 12b-2 of the Exchange Act.
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Puget Energy, Inc. | Large accelerated filer | / / | Accelerated filer | / / | Non-accelerated filer | /X/ | Smaller reporting company | / / | Emerging growth company | / / |
Puget Sound Energy, Inc. | Large accelerated filer | / / | Accelerated filer | / / | Non-accelerated filer | /X/ | Smaller reporting company | / / | Emerging growth company | / / |
If an emerging growth company, indicate by check mark if the registrant has elected not to use the extended transition period for complying with any new or revised financial accounting standards provided pursuant to Section 13(a) of the Exchange Act. / /
Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Act).
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Puget Energy, Inc. | Yes | / / |
| No | /X/ |
| Puget Sound Energy, Inc. | Yes | / / |
| No | /X/ |
As of February 6, 2009, all of the outstanding shares of voting stock of Puget Energy, Inc. are held by Puget Equico LLC, an indirect wholly-owned subsidiary of Puget Holdings LLC.
All of the outstanding shares of voting stock of Puget Sound Energy, Inc. are held by Puget Energy, Inc.
This Report on Form 10-K is a combined report being filed separately by: Puget Energy, Inc. and Puget Sound Energy, Inc. Puget Sound Energy, Inc. makes no representation as to the information contained in this report relating to Puget Energy, Inc. and the subsidiaries of Puget Energy, Inc. other than Puget Sound Energy, Inc. and its subsidiaries.
INDEX
DEFINITIONS
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AFUDC | Allowance for Funds Used During Construction |
AOCI | Accumulated Other Comprehensive Income |
ARO | Asset Retirement and Environmental Obligations |
aMW | Average Megawatt |
ASC | Accounting Standards Codification |
ASU | Accounting Standards Update |
BPA | Bonneville Power Administration |
Colstrip | Colstrip, Montana coal-fired steam electric generation facility |
Dth | Dekatherm (one Dth is equal to one MMBtu) |
EBITDA | Earnings Before Interest, Tax, Depreciation and Amortization |
EPA | Environmental Protection Agency |
ERF | Expedited Rate Filing |
FASB | Financial Accounting Standards Board |
FERC | Federal Energy Regulatory Commission |
GAAP | Generally Accepted Accounting Principles |
GHG | Greenhouse Gases |
GRC | General Rate Case |
IRP | Integrated Resource Plan |
IRS | Internal Revenue Service |
ISDA | International Swaps and Derivatives Association |
JPUDkW | Jefferson County Public Utility District |
kW | Kilowatt (one kW equals one thousand watts) |
kWh | Kilowatt Hour (one kWh equals one thousand watt hours) |
LIBOR | London Interbank Offered Rate |
LNG | Liquefied Natural Gas |
LTI Plan | Long-Term Incentive Plan |
MMBtus | One Million British Thermal Units |
MW | Megawatt (one MW equals one thousand kW) |
MWh | Megawatt Hour (one MWh equals one thousand kWh) |
NAESB | North American Energy Standards Board |
NOAA | National Oceanic and Atmospheric Administration |
NPNS | Normal Purchase Normal Sale |
NWP | Northwest Pipeline, GPLLC |
NYSE | New York Stock Exchange |
OCI | Other Comprehensive Income |
PCA | Power Cost Adjustment |
PCORC | Power Cost Only Rate Case |
PGA | Purchased Gas Adjustment |
PSE | Puget Sound Energy, Inc. |
PTC | Production Tax Credit |
PUDs | Washington Public Utility Districts |
Puget Energy | Puget Energy, Inc. |
Puget Equico | Puget Equico, LLC |
Puget Holdings | Puget Holdings, LLC |
REC | Renewable Energy Credit |
REP | Residential Exchange Program |
SEC | United States Securities and Exchange Commission |
SERP | Supplemental Executive Retirement Plan |
TCJA | Tax Cuts and Jobs Act |
Washington Commission | Washington Utilities and Transportation Commission |
WSPP | WSPP, Inc. |
FORWARD-LOOKING STATEMENTS
Puget Energy Inc. (Puget Energy) and Puget Sound Energy, Inc. (PSE) include the following cautionary statements in this Form 10-K to make applicable and to take advantage of the safe harbor provisions of the Private Securities Litigation Reform Act of 1995 for any forward-looking statements made by or on behalf of Puget Energy or PSE. Puget Energy and PSE are collectively referred to herein as “the Company”. This report includes forward-looking statements, which are statements of expectations, beliefs, plans, objectives and assumptions of future events or performance. Words or phrases such as “anticipates,” “believes,” “continues,” “could,” “estimates,” “expects,” “future,” “intends,” “may,” “might,” “plans,” “potential,” “predicts,” “projects,” “should,” “will likely result,” “will continue” or similar expressions are intended to identify certain of these forward-looking statements and may be included in discussion of, among other things, our anticipated operating or financial performance, business plans and prospects, planned capital expenditures and other future expectations. In particular, these include statements relating to future actions, business plans and prospects, future performance expenses, the outcome of contingencies, such as legal proceedings, government regulation and financial results.
Forward-looking statements reflect current expectations and involve risks and uncertainties that could cause actual results or outcomes to differ materially from those expressed. There can be no assurance that Puget Energy’s and PSE’s expectations, beliefs or projections will be achieved or accomplished.
In addition to other factors and matters discussed elsewhere in this report, including the risks described in Item 1A, "Risk Factors", some important risks that could cause actual results or outcomes for Puget Energy and PSE to differ materially from past results and those discussed in the forward-looking statements include:
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• | Governmental policies and regulatory actions, including those of the Federal Energy Regulatory Commission (FERC) and the Washington Utilities and Transportation Commission (Washington Commission), that may affect our ability to recover costs and earn a reasonable return, including but not limited to disallowance or delays in the recovery of capital investments and operating costs and discretion over allowed return on investment; |
• | Changes in, adoption of and compliance with laws and regulations, including decisions and policies concerning the environment, climate change, greenhouse gas or other emissions or by products of electric generation (including coal ash or other substances), natural resources, and fish and wildlife (including the Endangered Species Act) as well as the risk of litigation arising from such matters, whether involving public or private claimants or regulatory investigative or enforcement measures; |
• | Changes in tax law, related regulations or differing interpretation, including as a result of the Tax Cuts and Jobs Act (TCJA), or enforcement of applicable law by the Internal Revenue ServiceServices (IRS) or other taxing jurisdiction and PSE's ability to recover costs in a timely manner arising from such changes; |
• | Inability to realize deferred tax assets and use Production Tax Creditsproduction tax credits (PTCs) due to insufficient future taxable income; |
• | Accidents or natural disasters, such as hurricanes, windstorms, earthquakes, floods, fires and landslides, and other acts of God, terrorism, asset-based or cyber-based attacks, flu pandemic or similar significant events, which can interrupt service and lead to lost revenue, cause temporary supply disruptions and/or price spikes in the cost of fuel and raw materials and impose extraordinary costs; |
• | Commodity price risks associated with procuring natural gas and power in wholesale markets from creditworthy counterparties; |
• | Wholesale market disruption, which may result in a deterioration of market liquidity, increase the risk of counterparty default, affect the regulatory and legislative process in unpredictable ways, negatively affect wholesale energy prices and/or impede PSE's ability to manage its energy portfolio risks and procure energy supply, affect the availability and access to capital and credit markets and/or impact delivery of energy to PSE from its suppliers; |
• | Financial difficulties of other energy companies and related events, which may affect the regulatory and legislative process in unpredictable ways, adversely affect the availability of and access to capital and credit markets and/or impact delivery of energy to PSE from its suppliers; |
• | The effect of wholesale market structures (including, but not limited to, regional market designs or transmission organizations) or other related federal initiatives; |
• | PSE electric or natural gas distribution system failure, blackouts or large curtailments of transmission systems (whether PSE's or others'), or failure of the interstate natural gas pipeline delivering to PSE's system, all of which can affect PSE's ability to deliver power or natural gas to its customers and generating facilities; |
• | Electric plant generation and transmission system outages, which can have an adverse impact on PSE's expenses with respect to repair costs, added costs to replace energy or higher costs associated with dispatching a more expensive generation resource; |
• | The ability to restart generation following a regional transmission disruption; |
• | The ability of a natural gas or electric plant to operate as intended; |
• | Changes in climate or weather conditions in the Pacific Northwest, which could have effects on customer usage and PSE's revenue and expenses; |
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• | Regional or national weather, which could impact PSE's ability to procure adequate supplies of natural gas, fuel or purchased power to serve its customers and the cost of procuring such supplies; |
• | Variable hydrological conditions, which can impact streamflow and PSE's ability to generate electricity from hydroelectric facilities; |
• | Variable wind conditions, which can impact PSE's ability to generate electricity from the wind facilities; |
• | The ability to renew contracts for electric and natural gas supply and the price of renewal; |
• | Industrial, commercial and residential growth and demographic patterns in the service territories of PSE; |
• | General economic conditions in the Pacific Northwest, which may impact customer consumption or affect PSE's accounts receivable; |
• | The loss of significant customers, changes in the business of significant customers or the condemnation of PSE's facilities as a result of municipalization or other government action or negotiated settlement, which may result in changes in demand for PSE's services; |
• | The failure of information systems or the failure to secure information system data, which may impact the operations and cost of PSE's customer service, generation, distribution and transmission; |
• | Opposition and social activism that may hinder PSE's ability to perform work or construct infrastructure; |
• | Capital market conditions, including changes in the availability of capital and interest rate fluctuations; |
• | Employee workforce factors, including strikes, work stoppages, availability of qualified employees or the loss of a key executive; |
• | The ability to obtain insurance coverage, the availability of insurance for certain specific losses, and the cost of such insurance; |
• | The ability to maintain effective internal controls over financial reporting and operational processes; |
• | Changes in Puget Energy's or PSE's credit ratings, which may have an adverse impact on the availability and cost of capital for Puget Energy or PSE generally; and |
• | Deteriorating values of the equity, fixed income and other markets which could significantly impact the value of investments of PSE's retirement plan, post-retirement medical benefit plan trusts and the funding of obligations thereunder. |
Any forward-looking statement speaks only as of the date on which such statement is made and, except as required by law, the Company undertakes no obligation to update any forward-looking statement to reflect events or circumstances after the date on which such statement is made or to reflect the occurrence of unanticipated events. New factors emerge from time to time and it is not possible for management to predict all such factors, nor can it assess the impact of any such factor on the business or the extent to which any factor, or combination of factors, may cause results to differ materially from those contained in any forward-looking statement. For further information, see the reports on Form 10-Q and current reports on Form 8-K.
PART I
ITEM 1. BUSINESS
General
Puget Energy is an energy services holding company incorporated in the state of Washington in 1999. Substantially, all of its operations are conducted through its regulated subsidiary, PSE,Puget Sound Energy, Inc. (PSE), a utility company. Puget Energy also hasa wholly-owned, non-regulated subsidiary, named Puget LNG, LLC (Puget LNG). Puget LNG,, which was formed on November 29,in 2016 and has the sole purpose of owning, developing and financing the non-regulated activity of a liquefied natural gas (LNG) facility at the Port of Tacoma, Washington.
Puget Energy is owned through a holding company structure by Puget Holdings, LLC (Puget Holdings). All of Puget Energy's common stock is indirectly owned by Puget Holdings, LLC (Puget Holdings). 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(BCI), the Alberta Investment Management Corporation. AllCorporation (AIMCo), Ontario Municipal Employee Retirement System (OMERS) and PGGM Vermogensbeheer B.V. The sale of previous owners', Macquarie Infrastructure Partners and Macquarie Capital Group Limited, shares to OMERS, PGGM Vermogensbeheer B.V., AIMCo and BCI was approved by various federal and state agencies, including that of the Washington Utilities and Transportation Commission (Washington Commission), and closed on April 17th, 2019. Puget Energy’s common stock is indirectly owned by Puget Holdings.Energy and PSE are collectively referred to herein as “the Company.”
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 and 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.
Customers and Revenue Overview
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 tables present the number of PSE customers and revenue by customer class for electric and natural gas as of December 31, 20162019, and 2015:2018:
| | | 2016 | 2015 | | 2016 | 2015 | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| December 31, | Percent | December 31, | Percent |
| December 31, | |
| December 31, | |
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Customer Count by Class | Electric | Change | Natural Gas | Change | Customer Count by Class | 2019 |
| 2018 |
| Percent |
| 2019 |
| 2018 |
| Percent |
(in thousands) | | (in thousands) | Electric | |
| Change |
| Natural Gas | |
| Change |
Residential | 992,959 |
| 976,583 |
| 1.7% | 756,330 |
| 742,494 |
| 1.9% | Residential | 1,033 | | | 1,018 | | | 1.5% | | | 788 | | | 778 | | | 1.2% | |
Commercial | 125,737 |
| 123,681 |
| 1.7 | 55,671 |
| 55,208 |
| 0.8 | Commercial | 130 | | | 129 | | | 1.0% | | | 57 | | | 56 | | | 0.5% | |
Industrial | 3,417 |
| 3,423 |
| (0.2) | 2,365 |
| 2,397 |
| (1.3) | Industrial | 3 | | | 3 | | | (0.7)% | | | 2 | | | 2 | | | (0.2)% | |
Other | 6,591 |
| 6,354 |
| 3.7 | 227 |
| 227 |
| — | Other | 8 | | | 7 | | | 6.6% | | | — | | | — | | | (3.4)% | |
Total1 | 1,128,704 |
| 1,110,041 |
| 1.7% | 814,593 |
| 800,326 |
| 1.8% | Total1 | 1,174 | | | 1,157 | | | 1.5% | | | 847 | | | 836 | | | 1.3% | |
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1
| At December 31, 2016, approximately 392,806 customers purchased both electricity and natural gas from PSE as compared to 386,100 at December 31, 2015. |
1At December 31, 2019, and 2018, approximately 409,820 and 404,540 customers purchased both electricity and natural gas from PSE, respectively.
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Revenue by Class | December 31, | Percent | December 31, | Percent | |
Retail Revenue by Class | | Retail Revenue by Class | 2019 | | 2018 |
| Percent |
| 2019 | | 2018 |
| Percent |
(Dollars in Thousands) | Electric | Change | Natural Gas | Change | (Dollars in Thousands) | Electric | |
| Change |
| Natural Gas | |
| Change |
Residential | $1,138,871 | $1,061,117 | 7.3% | $578,955 | $597,572 | (3.1)% | Residential | $ | 1,139,356 | | | $ | 1,147,260 | | | (0.7)% | | | $ | 613,617 | | | $ | 598,923 | | | 2.5% | |
Commercial | 872,057 | 867,786 | 0.5 | 235,695 | 268,044 | (12.1) | Commercial | 854,910 | | | 885,457 | | | (3.4)% | | | 236,059 | | | 239,552 | | | (1.5)% | |
Industrial | 113,469 | 114,223 | (0.7) | 19,643 | 22,420 | (12.4) | Industrial | 105,020 | | | 110,607 | | | (5.1)% | | | 16,322 | | | 18,198 | | | (10.3)% | |
Other | 30,982 | 30,359 | 2.1 | 20,322 | 18,666 | 8.9 | Other | 37,920 | | | 32,596 | | | 16.3% | | | 20,283 | | | 19,984 | | | 1.5% | |
Total | $2,155,379 | $2,073,485 | 9.2% | $854,615 | $906,702 | (18.7)% | Total | $ | 2,137,206 | | | $ | 2,175,920 | | | (1.8)% | | | $ | 886,281 | | | $ | 876,657 | | | 1.1% | |
PSE's revenues and associated expenses are not generated evenly throughout the year, primarily due to seasonal weather patterns, varying wholesale prices for electricity and the amount of hydroelectric energy supplies available to PSE, which make quarter-to-quarter comparisons difficult. Weather conditions in PSE's service territory have an impact on customer energy usage affectingand affect PSE's billed revenue and energy supply expenses. 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 also month to month within a season, primarily as result of weather conditions. PSE normally experiences its highest retail energy sales, and subsequently oftencorresponding higher power costs, during the winter heating season in the first and fourth quarters of the year and its lowest sales and subsequentlycorresponding lower power costs in the third quarter of the year. While fluctuations in weather conditions will continue to affect PSE's billed revenue and energy supply expenses from month to month, PSE's decoupling mechanisms for electric and natural gas operations are expected to normalize the impact of weather on operating revenue and net income. Under the decoupling mechanism, the Washington Commission allows PSE to record a monthly adjustment to its electric and natural gas operating revenues related to electric transmission and distribution, natural gas operations and general administrative costs from residential, commercial and industrial customers. For additional information, see Business, "Regulation and Rates" included in Item 1 of this report and Note 4, "Regulation and Rates" to the consolidated financial statements included in Item 8 of this report.
Capital Expenditures
The following tables present PSE's capital expenditures for the five-year period ended December 31, 2016,2019, and gross utility plant by category and percentages for the year endedas of December 31, 2016:2019:
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Utility Plant Additions/Retirements 5-Year Total | 2015 - 2019 | | | | |
(Dollars in Thousands) | Electric | | Natural Gas | | Common |
Additions | $ | 1,804,920 | | | $ | 1,083,353 | | | $ | 763,244 | |
Retirements | (826,478) | | | (112,983) | | | (204,220) | |
Net Utility Plant | $ | 978,442 | | | $ | 970,370 | | | $ | 559,024 | |
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Utility Plant Additions/Retirements 5-Year Total | 2012-2016 |
(Dollars in Thousands) | Electric | Natural Gas | Common |
Additions | $2,916,114 | $758,141 | $349,578 |
Retirements | (453,220) | (98,317) | (254,106) |
Net Utility Plant | $2,462,894 | $659,824 | $95,472 |
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Utility Plant Balance | December 31, 2019 | | | | | | | | | | |
(Dollars in Thousands) | Electric | | | | Natural Gas | | | | Common | | |
Distribution | $ | 4,187,582 | | | 39.2% | | | $ | 3,998,120 | | | 89.3% | | | $ | — | | | —% | |
Generation | 3,740,762 | | | 35.1 | | | 2,731 | | | 0.1 | | | — | | | — | |
Transmission | 1,571,186 | | | 14.7 | | | — | | | — | | | — | | | — | |
General Plant & Other | 1,171,798 | | | 11.0 | | | 477,197 | | | 10.7 | | | 1,121,568 | | | 100 | |
Total | $ | 10,671,328 | | | 100.0% | | | $ | 4,478,048 | | | 100.0% | | | $ | 1,121,568 | | | 100% | |
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Utility Plant Balance | December 31, 2016 |
(Dollars in Thousands) | Electric | Natural Gas | Common |
Distribution | $3,587,449 | 36.5% | $3,329,151 | 91.4% | $— | —% |
Generation | 4,118,431 | 42.0 | 6,737 | 0.2 | — | — |
Transmission | 1,420,334 | 14.5 | — | — | — | — |
General Plant & Other | 686,955 | 7.0 | 304,383 | 8.4 | 632,718 | 100.0 |
Total | $9,813,169 | 100.0% | $3,640,271 | 100.0% | $632,718 | 100.0% |
Employees
At December 31, 2016,2019, PSE had approximately 3,0003,130 full-time equivalent employees. Approximately 1,1001,020 PSE employees are represented by the International Brotherhood of Electrical Workers Union (IBEW) andor the United Association of Plumbers and Pipefitters (UA). The current contracts with the IBEW and the UA were both ratified effective December 2017, and will expire on March 31, 20172020, and September 30, 2017,2021, respectively.
Puget Energy does not have any employees. PSE's employees provide employment services to Puget Energy and charges for their related salaries and benefits at cost.
Puget Energy operates one reportable business segment referred to as the regulated utility segment. For more information on this segment, see Note 17, "Segment Information" to the consolidated financial statements included in item 8 of this report.
Corporate Location
PSE’s and Puget Energy's principal executive offices are located at 10885355 110th Ave NE, 4th Street, Suite 1200, Bellevue, Washington 98004 and the telephone number is (425) 454-6363.
Available Information
The Company’s reports on Form 10-K, quarterly reports on Form 10-Q, current reports on Form 8-K and amendments to 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. The Securities and Exchange Commission (SEC) maintains an internet site that contains reports, proxy and information required by Item 101(e) of Regulation S-K is incorporated herein by reference tostatements, and other information regarding issuers that file electronically with the material under “Additional Information” in Part III Item 10, "Directors, Executive OfficersSEC and Corporate Governance".information may also be obtained via the SEC Internet website at www.sec.gov.
Regulation and Rates
PSE is subject to the regulatory authority of: (i) the FERC with respect to the transmission of electricity, the sale of electricity at wholesale, accounting and certain other matters; and (ii) 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 North American Electric Reliability Corporation (NERC), the electric reliability organization certified by the FERC, whose standards are enforced by the Western Electricity Coordinating Council (WECC) in PSE’s operating territory.
2013 Expedited Rate Filing, Decoupling and Centralia Decision
PSE filed a settlement agreement with the Washington Commission on March 22, 2013. The agreement was intended to settle all issues regarding decoupling, a power purchase agreement with TransAlta Centralia and the Expedited Rate Filing (ERF) which includes the property tax tracker. The Washington Commission placed the ERF and decoupling filings under a common procedural schedule.
On June 25, 2013, the Washington Commission issued final orders resolving the amended decoupling petition, the ERF filing and the Petition for Reconsideration (related to the TransAlta Centralia power purchase agreement). Order No. 7 in the ERF/decoupling proceeding 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 and a capital structure that included 48.0% common equity with a return on equity (ROE) of 9.8%. This order also approved the property tax tracker discussed below and approved the amended decoupling and rate plan filing 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. In addition, the rate plan (K-Factor) increase allowed decoupling revenue per customer for the recovery of delivery system costs to subsequently increase by 3.0% for the electric customers and 2.2% for the natural gas customers on January 1 of each year, until the conclusion of PSE's next General Rate Case (GRC), which was to be filed before April 1, 2016 and was later extended to January 17, 2017, as discussed below. In the rate plan, increases are subject to a cap of 3.0% of the total revenue for customers.
Rate mechanisms include: (i) trackers that typically track specific costs during the previous 12-monthtwelve-month period and (ii) riders that project cost recovery during a forward looking 12-monthforward-looking twelve-month period. Both allow recovery of expenditures withoutoutside the lengthy process of a full GRC.general rate case (GRC).
The following table shows PSE’s rate filings for its trackers and riders and whether or not they are included in decoupling rates:
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Rate Filings | Electric |
| Natural Gas |
Baseline rates | Yes |
| Yes |
Annual rate plan increase | Yes | Yes |
Expedited rate filing rider | Yes |
| Yes |
Merger credit | No | No |
Power cost only rates mechanism | No |
| N/A |
Federal incentive tracker | No |
| N/A |
Low income rates tracker | No |
| No |
Pipeline cost recovery mechanism tracker | N/A |
| No |
Prior year decoupling deferral tracker | No |
| No |
Property tax tracker | No |
| No |
Renewable energy credit tracker | No |
| N/A |
Residential exchange credits tracker | No |
| N/A |
Conservation costs rider | No |
| No |
PGA rider | N/A |
| No |
General Rate Case Filing
On March 17, 2016, the Washington Commission approved a joint petition postponing the filing of PSE’s GRC until no later than January 17, 2017. As part of the petition, PSE agreed to update power costs on December 1, 2016 in conjunction with the Centralia PPA compliance filing. Additionally, PSE agreed to include in its GRC filing a plan for closure of coal fired steam electric generation facility in Colstrip, Montana (Colstrip) Units 1 and 2, of which PSE owns a 50% interest. Monthly allowed revenue per customer includes an automatic annual increase and will continue through December 2017 when new rates go into effect from PSE's 2017 GRC.
On January 13, 2017, PSE filed itsa GRC with the Washington Commission which proposed a weighted coston June 20, 2019, requesting an overall increase in electric and natural gas rates of capital of 7.74%6.9% and 7.9%, or 6.69% after-tax, and a capital structure of 48.5% in common equity withrespectively. PSE requested a return on equity of 9.8% with an overall rate of return of 7.62%. In addition to the traditional areas of focus (revenue requirements, cost allocation, rate design and cost of capital), the Company completed an attrition study and included a portion of the attrition revenue requirement in the overall request in order to address the expected regulatory lag in the rate year. Additionally, as the non-plant related excess deferred taxes that resulted from the Tax Cuts and Jobs Act (TCJA) remained outstanding from PSE’s Expedited Rate Filing (ERF) as discussed below, PSE requested in its GRC to pass back the amounts over four years.On September 17, 2019, PSE filed a supplemental filing in the GRC, which provided updates as discussed in our original filing, but did not impact the requested overall electric and natural gas rate increases, return on equity or overall rate of return as originally filed.On January 15, 2020, PSE filed rebuttal testimony which included a reduction to the requested return on equity to 9.5%, which decreased the rate of return to 7.48%.The requested combinedrate increase for both electric tariff changes would resultand natural gas remained at 6.9% and 7.9%, respectively. For both electric and
natural gas PSE did not originally request its full attrition adjustment; therefore, the decrease in return on equity led to a netreduction in the electric rate increase of $86.3only $1.5 million or 4.1%. The requested combinedand did not have an impact on the natural gas tariff changes would resultrate increase.
For further details regarding the 2019 GRC filing, see Note 4, "Regulations and Rates" to the consolidated financial statements included in a net decreaseItem 8 of $22.3 million, or 2.4%. The filing was subsequently suspended, which means thatthis report.
Expedited Rate Filing
On November 7, 2018, PSE filed an ERF with the final rates grantedWashington Commission. On January 22, 2019, all parties in the proceeding will goreached an agreement on settlement terms. The settlement agreement was filed on January 30, 2019. On February 21, 2019, the Washington Commission approved the settlement with one condition: PSE must pass back the deferred balance associated with the tax over-collection of $34.6 million from January 1, 2018, through April 30, 2018, over a one-year period which began May 1, 2019.
For further details regarding the 2018 ERF filing, see Note 4, "Regulations and Rates" to the consolidated financial statements included in Item 8 of this report.
Washington Commission Tax Deferral Filing
The TCJA was signed into effect no later thanlaw in December 13, 2017.
PSE’s GRC filing included As a result of this change, PSE re-measured its deferred tax balances under the required plannew corporate tax rate. PSE filed an accounting petition on December 29, 2017, requesting deferred accounting treatment for Colstrip Units 1the impacts of tax reform. The deferred accounting treatment results in the tax rate change being captured in the deferred income tax balance with an offset to the regulatory liability for deferred income taxes. Additionally, on March 30, 2018, PSE filed for a rate change for electric and 2 closures, see Item 3, "Legal Proceedings". Additionally, PSE’s filing contains requests for two new mechanisms to address regulatory lag. PSE has requested procedures for an ERF that can be used to update PSE’s delivery revenues on an expedited basis following a general rate case proceeding. PSE also requested approval to establish an electric CRM similar to its existing natural gas CRM which would allow PSEcustomers associated with TCJA to obtain accelerated cost recovery on specified electric reliability projects.reflect the decrease in the federal corporate income tax rate from 35% to 21%. Other outcomes associated with PSE’s tax deferral filing are discussed in the ERF and GRC disclosures.
Decoupling Filings
TheWhile fluctuations in weather conditions will continue to affect PSE's billed revenue and energy supply expenses from month to month, PSE's decoupling mechanisms assist in mitigating the impact of weather on operating revenue and net income. Since July 2013, the Washington Commission has allowed PSE to record a monthly adjustment to its electric and natural gas operating revenues related to electric transmission and distribution, natural gas operations and general administrative costs and beginning December 19, 2017, fixed production costs from most residential, commercial and industrial customers. This monthly adjustment mitigates the effects of abnormal weather, conservation impacts and changes in usage patterns per customer. As a result, these electric and natural gas delivery revenues will beare recovered on a per customer basis and electric fixed production energy costs are recovered on the basis of a fixed monthly amount regardless of actual consumption levels. The energy supply costs, which are part of the power cost adjustment (PCA) and purchased gas adjustment (PGA) mechanisms, are not included in the decoupling mechanism. TheTotal electric and natural gas revenue recorded under the decoupling mechanisms will be affected by customer growth and not actual consumption.consumption except for fixed production costs, which are held at the level of cost from the most recent rate proceeding and are not impacted by customer growth. Following each calendar year, PSE will recover from, or refund to, customers the difference between allowed decoupling revenue and the corresponding actual revenue during the following May to April time period. The allowedFor further details regarding decoupling revenue per customer forfilings, see Note 4, "Regulation and Rates" to the recoveryconsolidated financial statements included in Item 8 of delivery system costs will subsequently increase by 3.0% for the electric customers and 2.2% for the natural gas customers on January 1 of each year. The decoupling mechanism will end on December 31, 2017 unless the continuation of the requested mechanism is approved in PSE’s 2017 GRC which PSE filed on January 13, 2017. Decoupling over and under collections will still be collectible or refundable after December 31, 2017, even if the decoupling mechanism is not extended.this report.
Electric RateFilings
Power Cost Adjustment Mechanism
PSE currently has a PCA mechanism that provides for the deferral of power costs that vary from the “power cost baseline” level of power costs. The “power cost baseline” islevels are set, in part, based on normalized assumptions about weather and hydroelectric conditions. Excess power costs or savings are apportioned between PSE and its customers pursuant to the graduated scale set forth in the PCA mechanism and will trigger a surcharge or refund when the cumulative deferral trigger is reached.
The graduated scale that was applicable through December 31, 2016 was as follows:
|
| | |
Annual Power Cost Variability | Company’s Share | Customers' Share |
+/- $20 million | 100% | —% |
+/- $20 million - $40 million | 50 | 50 |
+/- $40 million - $120 million | 10 | 90 |
+/- $120 + million | 5 | 95 |
On August 7, 2015, the Washington Commission issued an order approving the settlement proposing changes to the PCA mechanism. The settlement agreement took effectEffective January 1, 2017, and will apply the following graduated scale:
|
| | | | | |
Annual Power Cost Variability | Company's Share | Customers’ Share |
Over or Under Collection: | Over | Under | Over | Under |
Over or Under Collected by up to $17 million | 100% | 100% | —% | —% |
Over or Under Collected by between $17 million - $40 million | 35 | 50 | 65 | 50 |
Over or Under Collected beyond $40 + million | 10 | 10 | 90 | 90 |
The settlement also resultedscale is used in the following changes to the PCA mechanism:
Reduction | | | | | | | | | | | | | | | | | | | | | | | |
| Company's Share | | |
| Customers’ Share | | |
Annual Power Cost Variability | Over |
| Under |
| Over |
| Under |
Over or Under Collected by up to $17 million | 100% |
| 100% |
| —% |
| —% |
Over or Under Collected by between $17 million - $40 million | 35 |
| 50 |
| 65 |
| 50 |
Over or Under Collected beyond $40 + million | 10 |
| 10 |
| 90 |
| 90 |
Power Cost Adjustment Clause Filing
The Power Cost Adjustment Clause filing reflects the transition fee as required by Section 12 of the Microsoft Special Contract.
Electric Conservation Rider
The electric conservation rider collects revenue to cover the costs incurred in providing services and programs for conservation. Rates change annually on May 1 to collect the annual budget that started the prior January and to true-up for actual compared to forecast conservation expenditures from the prior year, as well as actual compared to the cumulative deferral triggerforecasted load set in rates.
Electric Property Tax Tracker Mechanism
The purpose of the property tax tracker mechanism is to pass through the cost of all property taxes incurred by the Company. The mechanism was implemented in 2013 and removed property taxes from general rates and included those costs for surcharge or refund from $30.0 million to $20.0 million;
Removalrecovery in an adjusting tariff rate. After the implementation, the mechanism acts as a tracker rate schedule and collects the total amount of fixed production costsproperty taxes assessed. The tracker is adjusted each year in May based on that year's assessed property taxes and true-up from the PCA mechanism and placing them in the decoupling mechanism, assuming the decoupling mechanism continues after its review in the 2017 GRC. If decoupling was not to continue, those fixed production costs would be treated the same as other non-PCA costs unless permission to treat them in another manner is obtained from the Washington Commission. These fixed production costs include: (i) return and depreciation/amortization on fixed production assets and regulatory assets and liabilities; (ii) return on, depreciation, transmission expense and revenues on specific transmission assets; and (iii) hydro, other production and other power related expenses and O&M costs;prior year.
Suspension of the requirement that a GRC must be filed within three months after rates are approved in a Power Cost Only Rate Case (PCORC);
Agreement, for a five-year period, that PSE will not file a GRC or PCORC within six months of the date rates go into effect for a PCORC filing; and
Establishment of a five-year moratorium on changes to the PCA.
PSE had an annual PCA receivable during the year ended December 31, 2016, due to under recovering $1.0 million of power costs. This compares to an annual PCA receivable of $8.7 million for the year ended December 31, 2015. The change was driven by a decrease in actual costs.
Federal Incentive Tracker Tariff
The Federal Incentive Tracker Tariff passes through to customers the benefits associated with realizedthe wind-related treasury grants and PTCs.grants. The filing results in a credit back to customers for pass-back of treasury grant amortization and pass-through of interest and any related true-ups. The filing is adjusted annually for new Federalfederal benefits, actual versus forecast interest and to true-up for actual load being different than the forecasted load set in rates. Rates change annually on January 1. Additionally, this tracker is impacted by the TCJA previously discussed. Accordingly, PSE filed for a one-time rate change to be effective May 1, 2018, to recognize the decrease in the federal corporate income tax rate from 35% to 21%.
Residential Exchange Benefit
The residential exchange program passes through the residential exchange program benefits that PSE receives from the Bonneville Power Administration (BPA). Rates change biennially on October 1.
Power Cost Only Rate Case
A power cost rate case (PCORC) is 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 is not required to but historically has used an expedited six-month PCORC decision timeline rather than the statutory 11-month timeline for a GRC.
Electric Property Tax Tracker
Natural Gas Rate Filings
Natural Gas Cost Recovery Mechanism
The purpose of the property tax trackercost recovery mechanism (CRM) is to pass throughrecover capital costs related to projects included in PSE's pipe replacement program plan on file with the costWashington Commission with the intended effect of all property taxes incurred byenhancing the Company. The mechanism was implemented in 2013 and removed property taxes from general rates and included those costs for recovery in an adjusting tariff rate. Aftersafety of the implementation, the mechanism acts as a tracker rate schedule and collects the total amount of property taxes assessed. The tracker will be adjusted each year in May based on that year's assessed property taxes and true-ups to the rate from the prior year.
Electric Conservation Rider
The electric conservation rider collects revenue to cover the costs incurred in providing services and programs for conservation.natural gas distribution system. Rates change annually on May 1 to collect the annual budget that started the prior January and to true-up for actual compared to forecast conservation expenditures from the prior year as well as actual load being different than the forecasted load set in rates.November 1.
Natural Gas Rate Filings
Purchased Gas Adjustment
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 or payable balance in the PGA mechanism reflects an under recovery or over recovery, respectively, of natural gas cost through the PGA mechanism.
Cost Recovery Mechanism
The purpose Rates typically change annually on November 1, although out-of-cycle rate changes are allowed at other times of the CRM is to recover capital costs related to projects included in PSE's pipe replacement program plan on file with the Washington Commission with the intended effect of enhancing the safety of the natural gas distribution system.year if needed.
Natural Gas Property Tax Tracker Mechanism
The purpose of the property tax tracker mechanism is to pass through the cost of all property taxes incurred by the Company. The mechanism was implemented in 2013 and removed property taxes from general rates and included those costs for recovery in an adjusting tariff rate. After the implementation, the mechanism acts as a tracker rate schedule and collects the total amount of property taxes assessed. The tracker will beis adjusted each year in May based on that year's assessed property taxes.taxes and adjustments to the rate from the prior year.
Natural Gas Conservation Rider
The natural gas conservation rider collects revenue to cover the costs incurred in providing services and programs for conservation. Rates change annually on May 1 to collect the annual budget that started the prior January and to true-up for actual versuscompared to forecast conservation expenditures from the prior year, as well as actual load being different thancompared to the forecasted load set in rates.
For additional information on electric and natural gas rates, see Management's Discussion and Analysis, "Regulation and Rates" included in Item 7 of this report and Note 3, "Regulation and Rates" to the consolidated financial statements included in Item 8 of this report.
ELECTRIC UTILITY OPERATING STATISTICS
| | | Year Ended December 31, | | Year Ended December 31, | |
| 2016 | 2015 | 2014 | | 2019 | | 2018 | | 2017 |
Generation and purchased power, MWh | | Generation and purchased power, MWh | | | | | |
Company-controlled resources | 11,577,608 |
| 12,747,014 |
| 11,640,504 |
| Company-controlled resources | 13,420,043 | | | 11,168,286 | | | 10,825,778 | |
Contracted resources | 7,023,786 |
| 5,911,012 |
| 4,050,062 |
| Contracted resources | 6,752,261 | | | 7,654,872 | | 8,337,348 |
Non-firm energy purchased | 6,005,797 |
| 5,315,266 |
| 8,001,425 |
| Non-firm energy purchased | 5,707,102 | | | 6,490,602 | | 6,147,778 |
Total generation and purchased power | 24,607,191 |
| 23,973,292 |
| 23,691,991 |
| Total generation and purchased power | 25,879,406 | | | 25,313,760 | | | 25,310,904 | |
Less: losses and Company use | (1,547,619 | ) | (1,514,272 | ) | (1,724,501 | ) | Less: losses and Company use | (1,298,854) | | | (1,513,451) | | (1,568,599) |
Total energy sales, MWh | 23,059,572 |
| 22,459,020 |
| 21,967,490 |
| Total energy sales, MWh | 24,580,552 | | | 23,800,309 | | | 23,742,305 | |
Electric energy sales, MWh | |
| |
| |
| Electric energy sales, MWh | | | | | | |
Residential | 10,245,326 |
| 10,164,703 |
| 10,349,928 |
| Residential | 10,756,628 | | | 10,497,389 | | 10,931,999 |
Commercial | 8,895,950 |
| 8,999,068 |
| 8,900,863 |
| Commercial | 8,837,457 | | | 8,932,681 | | 9,089,842 |
Industrial | 1,223,214 |
| 1,257,958 |
| 1,226,588 |
| Industrial | 1,161,149 | | | 1,189,828 | | 1,214,818 |
Other customers | 90,753 |
| 94,847 |
| 98,499 |
| Other customers | 85,302 | | | 84,382 | | 87,230 |
Total energy sales to customers | 20,455,243 |
| 20,516,576 |
| 20,575,878 |
| Total energy sales to customers | 20,840,536 | | | 20,704,280 | | | 21,323,889 | |
Sales to other utilities and marketers | 2,604,329 |
| 1,942,444 |
| 1,391,612 |
| Sales to other utilities and marketers | 3,740,016 | | | 3,096,029 | | 2,418,416 |
Total energy sales, MWh | 23,059,572 |
| 22,459,020 |
| 21,967,490 |
| Total energy sales, MWh | 24,580,552 | | | 23,800,309 | | | 23,742,305 | |
Transportation, including unbilled | 2,085,574 |
| 2,012,827 |
| 2,099,219 |
| Transportation, including unbilled | 2,322,021 | | | 2,028,727 | | 2,001,244 |
Electric energy sales and transportation, MWh | 25,145,146 |
| 24,471,847 |
| 24,066,709 |
| Electric energy sales and transportation, MWh | 26,902,573 | | | 25,829,036 | | | 25,743,549 | |
Electric operating revenue by classes | | Electric operating revenue by classes | | | | | |
(Dollars in Thousands) | |
| |
| |
| (Dollars in Thousands) | | | | | |
Residential | $ | 1,138,871 |
| $ | 1,061,117 |
| $ | 1,003,205 |
| Residential | $ | 1,139,356 | | | $ | 1,147,260 | | | $ | 1,232,075 | |
Commercial | 872,057 |
| 867,786 |
| 824,778 |
| Commercial | 854,910 | | | 885,457 | | 892,360 |
Industrial | 113,469 |
| 114,223 |
| 107,750 |
| Industrial | 105,020 | | | 110,607 | | 112,817 |
Other customers | 20,045 |
| 20,216 |
| 19,707 |
| Other customers | 18,408 | | | 18,718 | | 19,729 |
Total operating revenue from customers | 2,144,442 |
| 2,063,342 |
| 1,955,440 |
| Total operating revenue from customers | 2,117,694 | | | 2,162,042 | | | 2,256,981 | |
Transportation, including unbilled | 10,937 |
| 10,143 |
| 9,502 |
| Transportation, including unbilled | 19,512 | | | 13,878 | | 12,584 |
Sales to other utilities and marketers | 50,124 |
| 46,666 |
| 41,680 |
| Sales to other utilities and marketers | 109,105 | | | 89,324 | | 53,789 |
Decoupling revenue | 29,968 |
| 13,630 |
| 25,735 |
| Decoupling revenue | 15,673 | | | 13,530 | | 9,975 |
Other decoupling revenue1 | (21,168 | ) | (16,634 | ) | 5,609 |
| Other decoupling revenue1 | (6,866) | | | (5,475) | | (27,706) |
Miscellaneous operating revenue | 24,189 |
| 11,321 |
| 45,831 |
| Miscellaneous operating revenue | 241,923 | | | 182,620 | | 115,040 |
Total electric operating revenue | $ | 2,238,492 |
| $ | 2,128,468 |
| $ | 2,083,797 |
| Total electric operating revenue | $ | 2,497,041 | | | $ | 2,455,919 | | | $ | 2,420,663 | |
Number of customers served (average): | |
| |
| |
| Number of customers served (average): | | | | | |
Residential | 984,739 |
| 970,830 |
| 960,708 |
| Residential | 1,025,024 | | | 1,010,574 | | 998,078 |
Commercial | 125,067 |
| 123,072 |
| 121,332 |
| Commercial | 129,944 | | | 128,845 | | 126,829 |
Industrial | 3,425 |
| 3,434 |
| 3,437 |
| Industrial | 3,328 | | | 3,362 | | 3,399 |
Other | 6,472 |
| 6,283 |
| 6,023 |
| Other | 7,323 | | | 6,992 | | 6,722 |
Transportation | 16 |
| 16 |
| 17 |
| Transportation | 80 | | | 16 | | 16 |
Total customers | 1,119,719 |
| 1,103,635 |
| 1,091,517 |
| Total customers | 1,165,699 | | | 1,149,789 | | | 1,135,044 | |
_______________
| |
1
| Includes decoupling cash collections, rate of return excess earnings, and decoupling 24-month revenue reserve. |
1.Includes decoupling cash collections, rate of return excess earnings, and decoupling 24-month revenue reserve.
ELECTRIC UTILITY OPERATING STATISTICS (Continued)
| | | Year Ended December 31, | | Year Ended December 31, | |
| 2016 | 2015 | 2014 | | 2019 | | 2018 | | 2017 |
Average kWh used per customer: | | Average kWh used per customer: | | | | | |
Residential | 10,404 |
| 10,470 |
| 10,773 |
| Residential | 10,494 | | | 10,388 | | | 10,953 | |
Commercial | 71,129 |
| 73,120 |
| 73,360 |
| Commercial | 68,010 | | 69,329 | | 71,670 |
Industrial | 357,143 |
| 366,324 |
| 356,877 |
| Industrial | 348,903 | | 353,905 | | 357,404 |
Other | 14,022 |
| 15,096 |
| 16,354 |
| Other | 11,649 | | 12,068 | | 12,977 |
Average revenue per customer: | | Average revenue per customer: | | | | | |
Residential | $ | 1,157 |
| $ | 1,093 |
| $ | 1,044 |
| Residential | $ | 1,112 | | | $ | 1,135 | | | $ | 1,234 | |
Commercial | 6,973 |
| 7,051 |
| 6,798 |
| Commercial | 6,579 | | 6,872 | | 7,036 |
Industrial | 33,130 |
| 33,262 |
| 31,350 |
| Industrial | 31,556 | | 32,899 | | 33,191 |
Other | 3,097 |
| 3,218 |
| 3,272 |
| Other | 2,514 | | 2,677 | | 2,935 |
Average retail revenue per kWh sold: | | Average retail revenue per kWh sold: | | | | | |
Residential | $ | 0.1112 |
| $ | 0.1044 |
| $ | 0.0969 |
| Residential | $ | 0.1059 | | | $ | 0.1093 | | | $ | 0.1127 | |
Commercial | 0.0980 |
| 0.0964 |
| 0.0927 |
| Commercial | 0.0967 | | 0.0991 | | 0.0982 |
Industrial | 0.0928 |
| 0.0908 |
| 0.0878 |
| Industrial | 0.0904 | | 0.0930 | | 0.0929 |
Other | 0.2209 |
| 0.2131 |
| 0.2001 |
| Other | 0.2158 | | 0.2218 | | 0.2262 |
Average retail revenue per kWh sold | $ | 0.1048 |
| $ | 0.1006 |
| $ | 0.0950 |
| Average retail revenue per kWh sold | $ | 0.1016 | | | $ | 0.1044 | | | $ | 0.1058 | |
Heating degree days | 3,823 |
| 3,800 |
| 3,829 |
| Heating degree days | 4,208 | | | 4,065 | | 4,584 |
Percent of normal - NOAA1 30-year average | 81.0 | % | 80.5 | % | 81.2 | % | |
Load factor2 | 56.2 | % | 56.2 | % | 52.3 | % | |
Percent of normal - NOAA2 30-year average | | Percent of normal - NOAA2 30-year average | 89.6 | % | | 86.2 | % | | 97.2 | % |
Load factor3 | | Load factor3 | 61.6 | % | | 64.2 | % | | 51.6 | % |
_______________
| |
1
| National Oceanic and Atmospheric Administration (NOAA). |
| |
2
| Average megawatt (aMW) usage by customers divided by their maximum usage. |
2.National Oceanic and Atmospheric Administration (NOAA).
3.Average megawatt (aMW) usage by customers divided by their maximum usage.
Electric Supply
At December 31, 2016,2019, 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 4,8444,733 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. When it is more economical for PSE to purchase power than to operate its own generation facilities, PSE will purchase spot market energy when sufficient transmission capacity is available.
The following table shows PSE’s electric energy supply resources and energy production for the years ended December 31, 20162019, and 2015:2018: | | | Peak Power Resources At December 31, | Energy Production At December 31, | |
` | | ` | Peak Power Resources At December 31, | | | Energy Production At December 31, | |
| 2016 | 2015 | 2016 | 2015 | | 2019 | | | 2018 | | | 2019 | | | 2018 | |
| MW | % | MW | % | MWh | % | MWh | % | | MW | | % | | MW | | % | | MWh | | % | | MWh | | % |
Purchased resources: | | Purchased resources: | | | | | | | | | | | | | | | | | | | |
Columbia River PUD contracts | 708 |
| 14.6 | % | 708 |
| 14.5 | % | 3,371,827 |
| 13.7 | % | 3,325,450 |
| 13.9 | % | |
Columbia River PUD contracts1 | | Columbia River PUD contracts1 | 687 | | | 14.5% | | | 674 | | 14.3% | | | 2,642,177 | | 10.2% | | | 3,468,702 | | 13.7% | |
Other hydroelectric | 79 |
| 1.6 |
| 85 |
| 1.7 |
| 365,670 |
| 1.5 |
| 179,057 |
| 0.7 |
| Other hydroelectric | 72 | | | 1.5 | | | 72 | | 1.5 | | | 272,653 | | 1.0 | | | 315,948 | | 1.2 | |
Other producers | 387 |
| 8.0 |
| 463 |
| 9.5 |
| 2,999,171 |
| 12.1 |
| 2,200,098 |
| 9.2 |
| Other producers | 285 | | | 6.0 | | | 284 | | 6.2 | | | 3,276,502 | | 12.7 | | | 3,406,627 | | 13.6 | |
Wind | 56 |
| 1.2 |
| 56 |
| 1.1 |
| 138,148 |
| 0.6 |
| 130,777 |
| 0.5 |
| Wind | 56 | | | 1.2 | | | 56 | | 1.2 | | | 123,368 | | 0.5 | | | 131,270 | | 0.5 | |
Short-term wholesale energy purchases | N/A |
| — |
| N/A |
| — |
| 6,154,767 |
| 25.0 |
| 5,390,896 |
| 22.5 |
| Short-term wholesale energy purchases | N/A | | | — | | | N/A | | N/A | | | 6,144,663 | | 23.7 | | | 6,822,927 | | 26.9 | |
Total purchased | 1,230 |
| 25.4 | % | 1,312 |
| 26.8 | % | 13,029,583 |
| 52.9 | % | 11,226,278 |
| 46.8 | % | Total purchased | 1,100 | | | 23.2% | | | 1,086 | | | 23.2% | | | 12,459,363 | | | 48.1% | | | 14,145,474 | | | 55.9% | |
Company-controlled resources: | |
| |
| |
| |
| |
| |
| |
| |
| Company-controlled resources: | | | | | | | | | | | | | | | | | | | |
Hydroelectric | 254 |
| 5.2 | % | 254 |
| 5.2 | % | 933,522 |
| 3.8 | % | 706,231 |
| 2.9 | % | Hydroelectric | 250 | | | 5.3% | | | 250 | | 5.3% | | | 712,727 | | 2.8% | | | 914,540 | | 3.6% | |
Coal | 677 |
| 14.0 |
| 677 |
| 13.9 |
| 4,529,179 |
| 18.4 |
| 4,495,032 |
| 18.8 |
| |
Coal3 | | Coal3 | 677 | | | 14.3 | | | 677 | | 14.4 | | | 4,347,639 | | 16.8 | | | 4,184,950 | | 16.5 | |
Natural gas/oil | 1,908 |
| 39.4 |
| 1,871 |
| 38.3 |
| 4,152,205 |
| 16.9 |
| 5,830,318 |
| 24.3 |
| Natural gas/oil | 1,931 | | | 40.8 | | | 1,908 | | 40.6 | | | 6,692,188 | | 25.9 | | | 4,152,359 | | 16.4 | |
Wind | 773 |
| 16.0 |
| 773 |
| 15.8 |
| 1,962,702 |
| 8.0 |
| 1,715,433 |
| 7.2 |
| Wind | 773 | | | 16.3 | | | 773 | | 16.5 | | | 1,667,489 | | 6.4 | | | 1,932,378 | | 7.6 | |
Other1 | 2 |
| — |
| — |
| — |
| — |
| — |
| — |
| — |
| |
Other2 | | Other2 | 2 | | | — | | | 2 | | — | | | — | | — | | | — | | — | |
Total company-controlled | 3,614 |
| 74.6 | % | 3,575 |
| 73.2 | % | 11,577,608 |
| 47.1 | % | 12,747,014 |
| 53.2 | % | Total company-controlled | 3,633 | | | 76.8% | | | 3,610 | | 76.8% | | | 13,420,043 | | 51.9% | | | 11,184,227 | | 44.1% | |
Total resources | 4,844 |
| 100.0 | % | 4,887 |
| 100.0 | % | 24,607,191 |
| 100.0 | % | 23,973,292 |
| 100.0 | % | Total resources | 4,733 | | | 100.0% | | | 4,696 | | | 100.0% | | | 25,879,406 | | | 100.0% | | | 25,329,701 | | | 100.0% | |
_______________
| |
1
| It is estimated that the Glacier Battery Storage has delivered approximately 250,000 Kilowatt Hour (kWh) since the end of September 2016. |
1.Net of 35 MW and 33 MW capacity delivered to Canada pursuant to the provisions of a treaty between Canada and the United States and Canadian Entitlement Allocation agreements as of December 31, 2019, and 2018, respectively.
2.It is estimated that the Glacier Battery Storage has delivered approximately 1,468.2 and 1,362.7 MWh as of December 31, 2019, and 2018, respectively.
3.In July 2016, PSE reached a settlement with the Sierra Club to retire Colstrip Units 1 and 2 no later than July 1, 2022. Colstrip Units 1 and 2, 307 MW Net Maximum Capacity were retired effective December 31, 2019.
Company–Owned Electric Generation Resources
At December 31, 2016,2019, PSE owns the following plants with an aggregate net generating capacity of 3,6143,633 MW: | | Plant Name | Plant Type | Net Maximum Capacity (MW)1 | Year Installed | Plant Name | | Plant Type | | Net Maximum Capacity (MW)1 | | Year Installed |
Colstrip Units 3 & 4 (25% interest) | Coal | 370 | 1984 & 1986 | Colstrip Units 3 & 4 (25% interest) | | Coal | | 370 | | 1984 & 1986 |
Colstrip Units 1 & 2 (50% interest)2 | Coal | 307 | 1975 & 1976 | Colstrip Units 1 & 2 (50% interest)2 | | Coal | | 307 | | 1975 & 1976 |
Mint Farm | Natural gas combined cycle | 297 | 2007; acquired 2008 | Mint Farm | | Natural gas combined cycle | | 320 | | 2007; acquired 2008; upgraded 2017 |
Goldendale | Natural gas combined cycle | 315 | 2004; acquired 2007; upgraded 2016 | Goldendale | | Natural gas combined cycle | | 315 | | 2004, acquired 2007, upgraded 2016 |
Frederickson Unit 1 (49.85% interest) | Natural gas combined cycle | 136 | 2002; added duct firing in 2005 | Frederickson Unit 1 (49.85% interest) | | Natural gas combined cycle | | 136 | | 2002; added duct firing 2005 |
Lower Snake River | Wind | 343 | 2012 | Lower Snake River | | Wind | | 343 | | 2012 |
Wild Horse | Wind | 273 | 2006 & 2009 | Wild Horse | | Wind | | 273 | | 2006 & 2009 |
Hopkins Ridge | Wind | 157 | 2005 & 2008 | Hopkins Ridge | | Wind | | 157 | | 2005 & 2008 |
Fredonia Units 1 & 2 | Dual-fuel combustion turbines | 207 | 1984 | Fredonia Units 1 & 2 | | Dual-fuel combustion turbines | | 207 | | 1984 |
Frederickson Units 1 & 2 | Dual-fuel combustion turbines | 149 | 1981 | Frederickson Units 1 & 2 | | Dual-fuel combustion turbines | | 149 | | 1981 |
Whitehorn Units 2 & 3 | Dual-fuel combustion turbines | 149 | 1981 | Whitehorn Units 2 & 3 | | Dual-fuel combustion turbines | | 149 | | 1981 |
Fredonia Units 3 & 4 | Dual-fuel combustion turbines | 107 | 2001 | Fredonia Units 3 & 4 | | Dual-fuel combustion turbines | | 107 | | 2001 |
Ferndale | Natural gas co-generation | 253 | 1994; acquired 2012 | Ferndale | | Natural gas co-generation | | 253 | | 1994; acquired 2012 |
Encogen | Natural gas co-generation | 165 | 1993; acquired 1999 | Encogen | | Natural gas co-generation | | 165 | | 1993; acquired 1999 |
Sumas | Natural gas co-generation | 127 | 1993; acquired 2008 | Sumas | | Natural gas co-generation | | 127 | | 1993; acquired 2008 |
Upper Baker River | Hydroelectric | 91 | 1959 | Upper Baker River | | Hydroelectric | | 91 | | 1959; unit 2 upgraded 1997 |
Lower Baker River | Hydroelectric | 109 | 1925; reconstructed 1960; upgraded 2001 and 2013 | Lower Baker River | | Hydroelectric | | 105 | | 1925: reconstructed 1960; upgraded 2001 and 2013 |
Snoqualmie Falls3 | Hydroelectric | 54 | 1898 to 1911 & 1957; rebuilt 2013 | Snoqualmie Falls3 | | Hydroelectric | | 54 | | 1898 to 1911 & 1957; rebuilt 2013 |
Crystal Mountain | Internal combustion | 3 | 1969 | Crystal Mountain | | Internal combustion | | 3 | | 1969 |
Glacier Battery Storage | Lithium Iron Phosphate | 2 | 2016 | Glacier Battery Storage | | Lithium Iron Phosphate | | 2 | | 2016 |
Total net capacity | | 3,614 | | |
Total Net Capacity | | Total Net Capacity | | | | 3,633 | | |
_______________
| |
1
| 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. |
| |
2 | In July 2016, PSE reached a settlement with the Sierra Club to retire Colstrip Units 1 and 2 no later than July 1, 2022. |
| |
3 | The FERC license authorizes the full 54.4 MW; however, the project's water right issued by the State Department of Ecology limits flow to 2,500 cubic feet and therefore output to 47.7MW. |
1.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.
2.In July 2016, PSE reached a settlement with the Sierra Club to retire Colstrip Units 1 and 2 no later than July 1, 2022. Colstrip Units 1 and 2 were retired effective December 31, 2019.
3.The FERC license authorizes the full 54.4 MW; however, the project's water right issued by the State Department of Ecology limits flow to 2,500 cubic feet and therefore output to 47.7MW.
Columbia River Electric Energy Supply Contracts
During 2016,2019, approximately 13.7%10.2% of PSE’s energy supply requirement was obtained through long-term contracts with three Washington Public Utility Districts (PUDs) that own and operate hydroelectric projects on the Columbia River (Mid-Columbia). 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, 2016, PSE was entitled to purchase portions2019, PSE's portion of the power output of the PUDs’ projects asare set forth below:
| | | | | | | | | | | | | | | | | | | | | | | |
| | | | | Company’s Annual Share (Approximate) | | |
Project | Contract Expiration Year | | License Expiration Year | | Percent of Output | | MW Capacity |
Chelan County PUD: | | | | | | | |
Rock Island Project | 2031 | | 2029 | | 25.0 | % | | 156 |
Rocky Reach Project | 2031 | | 2052 | | 25.0 | | | 325 |
Douglas County PUD: | | | | | | | |
Wells Project | 2028 | | 2052 | | 27.1 | | | 228 |
Grant County PUD: | | | | | | | |
Priest Rapids Development | 2052 | | 2052 | | 0.6 | | | 6 |
Wanapum Development | 2052 | | 2052 | | 0.6 | | | 7 |
Total | | | | | | | 722 |
|
| | | | | | |
| | | Company’s Annual Purchasable Amount (Approximate) |
Project | Contract Expiration Year | License Expiration Year | Percent of Output | MW Capacity |
Chelan County PUD: | | | | |
Rock Island Project | 2031 | 2029 | 25.0 | % | 156 |
|
Rocky Reach Project | 2031 | 2052 | 25.0 | % | 325 |
|
Douglas County PUD: | | | | |
Wells Project | 2018 | 2052 | 29.9 | % | 251 |
|
Grant County PUD: | | | | |
Priest Rapids Development | 2052 | 2052 | 0.6 | % | 8 |
|
Wanapum Development | 2052 | 2052 | 0.6 | % | 9 |
|
Total | | | |
| 749 |
|
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 44 aMW of capacity which expires on July 1, 2017 with no provision to renew this agreement. PSE will procure more capacity from Mid-Columbia to recover for this loss of capacity, if needed. PSE also has an agreement with Pacific Gas & Electric Company (PG&E) for 300 MW of seasonal capacity exchange which currently has no set expiration. PG&E filed for bankruptcy on January 29, 2019. As of December 31, 2019, there was no outstanding obligation due from PG&E related to the energy exchange contract, an agreement in place to supplement peak loads through the transmission of energy from PG&E to PSE in the winter months and from PSE to PG&E in the summer months. During and since emerging from its 2001-2004 bankruptcy proceedings, PG&E delivered on the energy exchange contract and has continued to meet the exchange contract through its current bankruptcy proceedings.
PSE began participating in the Energy Imbalance Market (EIM) operated by the California Independent System Operator on October 1, 2016. PSE has committed 450 MW of existing BPA transmission solely for the EIM market. Participation is expected to reducehas resulted in reduced costs for PSE customers enhanceof approximately $16.2 million per annum, enhanced system reliability, integrateintegration of variable energy resources, and leverage geographic diversity of electricity demand and generation resources. The calculated benefits represent the annual cost savings of the EIM dispatch compared with a counter-factual dispatch without the EIM. Benefits can take the form of cost savings or profits or their combination. Benefits include greenhouse gas (GHG) revenue, transfer revenues and flexible ramping revenues.
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 2016,2019, PSE had 4,6464,797 MW and 695595 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 electrical demand for its combustion turbine generators.through gas-fired generation. Supplies range from long-term to daily agreements, as the demand for the turbinesturbine fueling 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 financial hedges to manage the cost of natural gas. PSE utilizes natural gas storage capacity and transportation 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 natural gas-fired generation resources. During 2016, approximately 64.0% of natural gas purchased for the power portfolio originated in British Columbia, 20.0% in Alberta and 16.0% in the United States.
Integrated Resource Plans, Resource Acquisition and Development
PSE is required by Washington Commission regulations to file an electric and natural gas integrated resource plan (IRP) every two years. The 2015However, the governor signed HB 5116, the Clean Energy Transformation Act (CETA), into law on May 7, 2019. As a result, the 2019 IRP was suspended and a progress report was filed on November 30, 201515, 2019. Although the 2019 IRP process was suspended, a resource need was identified, but there was no final resource portfolio to identify cost effective conservation. Based on 2019 IRP resource need projections and identifiedconservation projections from the following2017 IRP, the capacity needs:shortfalls and surpluses are:
|
| | | | | |
| 2017 | 2018 | 2019 | 2020 | 2021 |
Projected MW shortfall/(surplus) | (28) | (43) | (44) | (71) | 275 |
| | | | | | | | | | | | | | | | | | | | | | | | | | |
| | 2020 | | 2021 | | 2022 | | 2023 |
Projected MW shortfall/(surplus) | | 539 | | 519 | | 462 | | 491 |
PSE projects its future energy needs will exceed current resources in its supply portfolio beginning in 2020 because of the retirement of Colstrip Units 1 and 2. Colstrip 1 and 2 were retired effective December 31, 2019, and decreased capacity by approximately 307 MW per year. The expected capacity needs reflect the mix of energy efficiency programs deemed cost effective in the 20152017 IRP. In 2015,As part of the CETA, PSE renewed allmust achieve sales with renewable or non-emitting resources of at least 80% by 2030 and 100% by 2045. The 2021 IRP will fully explore the Mid-Columbia transmission available for renewal duringimplementation of the year to meet peak capacity needs.
CETA. PSE projects that beginning in 2021 its future energy needs will exceed current resources in its supply portfolio. The IRP identifies declining regional surpluses, requiring replacement of supplies to meet projected demands. Therefore, PSE’s IRP sets forth a multi-part strategy of implementing energy efficiency programs andis currently pursuing additional renewable resources (primarily wind) and additional base load natural gas-fired generationresource acquisitions 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 wholesale market, subject to the sharing bands of the PCA mechanism, at a cost that could, in the absence of regulatory relief, increase its expenses and reduce earnings and cash flows. The IRP will be updated in 2017 and is expected to be filed July 15, 2017.current capacity shortfall projections.
NATURAL GAS UTILITY OPERATING STATISTICS
| | | | | | | | | | Year Ended December 31, | |
| Year Ended December 31, | | 2019 | | 2018 | | 2017 |
| 2016 | 2015 | 2014 | |
Natural gas operating revenue by classes (dollars in thousands): | | | | |
Natural gas operating revenue by classes (Dollars in Thousands): | | Natural gas operating revenue by classes (Dollars in Thousands): | | | | | |
Residential | $ | 578,955 |
| $ | 597,572 |
| $ | 644,055 |
| Residential | $ | 613,617 | | | $ | 598,923 | | | $ | 686,438 | |
Commercial firm | 213,138 |
| 239,849 |
| 252,235 |
| Commercial firm | 218,302 | | 219,390 | | 251,584 |
Industrial firm | 17,753 |
| 21,533 |
| 23,887 |
| Industrial firm | 15,698 | | 17,247 | | 20,077 |
Interruptible | 24,447 |
| 29,082 |
| 30,770 |
| Interruptible | 18,381 | | 21,113 | | 24,317 |
Total retail natural gas sales | 834,293 |
| 888,036 |
| 950,947 |
| Total retail natural gas sales | 865,998 | | | 856,673 | | | 982,416 | |
Transportation services | 20,322 |
| 18,666 |
| 17,069 |
| Transportation services | 20,283 | | 19,984 | | 21,718 |
Decoupling revenue | 52,114 |
| 51,981 |
| 29,116 |
| Decoupling revenue | 2,296 | | 6,115 | | 3,522 |
Other decoupling revenue1 | (28,761 | ) | (26,038 | ) | 2,208 |
| Other decoupling revenue1 | (29,737) | | (37,022) | | (22,862) |
Other | 12,542 |
| 14,904 |
| 13,520 |
| Other | 16,531 | | 4,998 | | 12,965 |
Total natural gas operating revenue | $ | 890,510 |
| $ | 947,549 |
| $ | 1,012,860 |
| Total natural gas operating revenue | $ | 875,371 | | | $ | 850,748 | | | $ | 997,759 | |
Number of customers served (average): | |
| |
| |
| Number of customers served (average): | | | | | |
Residential | 749,586 |
| 737,339 |
| 727,244 |
| Residential | 782,413 | | 772,130 | | 761,010 |
Commercial firm | 54,992 |
| 54,646 |
| 54,328 |
| Commercial firm | 56,113 | | 55,716 | | 55,372 |
Industrial firm | 2,371 |
| 2,378 |
| 2,383 |
| Industrial firm | 2,304 | | 2,308 | | 2,330 |
Interruptible | 410 |
| 429 |
| 449 |
| Interruptible | 367 | | 393 | | 398 |
Transportation | 227 |
| 221 |
| 208 |
| Transportation | 230 | | 234 | | 226 |
Total customers | 807,586 |
| 795,013 |
| 784,612 |
| Total customers | 841,427 | | | 830,781 | | | 819,336 | |
Natural gas volumes, therms (thousands): | |
| |
| |
| Natural gas volumes, therms (thousands): | | | | | |
Residential | 521,771 |
| 492,997 |
| 527,423 |
| Residential | 605,313 | | 571,265 | | 621,915 |
Commercial firm | 233,586 |
| 230,507 |
| 242,095 |
| Commercial firm | 277,639 | | 264,775 | | 279,656 |
Industrial firm | 22,783 |
| 23,777 |
| 26,481 |
| Industrial firm | 22,915 | | 23,890 | | 25,500 |
Interruptible | 49,533 |
| 43,931 |
| 46,113 |
| Interruptible | 45,176 | | 47,275 | | 49,249 |
Total retail natural gas volumes, therms | 827,673 |
| 791,212 |
| 842,112 |
| Total retail natural gas volumes, therms | 951,043 | | | 907,205 | | | 976,320 | |
Transportation volumes | 230,724 |
| 220,392 |
| 211,429 |
| Transportation volumes | 227,657 | | 230,735 | | 236,578 |
Total volumes | 1,058,397 |
| 1,011,604 |
| 1,053,541 |
| Total volumes | 1,178,700 | | | 1,137,940 | | | 1,212,898 | |
_______________
| |
1
| Includes decoupling cash collections, rate of return excess earnings, and decoupling 24-month revenue reserve. |
1.Includes decoupling cash collections, rate of return excess earnings, and decoupling 24-month revenue reserve.
NATURAL GAS UTILITY OPERATING STATISTICS (Continued)
| | | | | | | | | | | | | | | | | |
| Year Ended December 31, | | | | |
| 2019 | | 2018 | | 2017 |
Working natural gas volumes in storage at year end, therms (thousands): | | | | | |
Jackson Prairie | 82,892 | | 76,348 | | 86,051 |
Clay Basin | 77,532 | | 74,420 | | 45,854 |
| | | | | |
Average therms used per customer: | | | | | |
Residential | 774 | | | 740 | | | 817 | |
Commercial firm | 4,948 | | 4,752 | | 5,050 |
Industrial firm | 9,946 | | 10,351 | | 10,944 |
Interruptible | 123,095 | | 120,293 | | 123,742 |
Transportation | 989,813 | | 986,045 | | 1,046,806 |
Average revenue per customer: | | | | | |
Residential | $ | 784 | | | $ | 776 | | | $ | 902 | |
Commercial firm | 3,890 | | 3,938 | | 4,544 |
Industrial firm | 6,813 | | 7,473 | | 8,617 |
Interruptible | 50,084 | | 53,724 | | 61,098 |
Transportation | 88,187 | | 85,400 | | 96,099 |
Average revenue per therm sold: | | | | | |
Residential | $ | 1.014 | | | $ | 1.048 | | | $ | 1.104 | |
Commercial firm | 0.786 | | 0.829 | | 0.900 |
Industrial firm | 0.685 | | 0.722 | | 0.787 |
Interruptible | 0.407 | | 0.447 | | 0.494 |
Average retail revenue per therm sold | $ | 0.911 | | | $ | 0.944 | | | $ | 1.006 | |
Transportation | 0.089 | | 0.087 | | 0.092 |
Heating degree days | 4,208 | | | 4,065 | | 4,584 |
Percent of normal - NOAA 30-year average | 89.6 | % | | 86.2 | % | | 97.2 | % |
|
| | | | | | | | | |
| Year Ended December 31, |
| 2016 | 2015 | 2014 |
Working natural gas volumes in storage at year end, therms (thousands): | |
| |
| |
|
Jackson Prairie | 86,374 |
| 78,337 |
| 81,889 |
|
Clay Basin | 63,136 |
| 54,199 |
| 29,719 |
|
Plymouth | 2,162 |
| 1,828 |
| 2,206 |
|
Average therms used per customer: | | | |
|
Residential | 696 |
| 669 |
| 725 |
|
Commercial firm | 4,248 |
| 4,218 |
| 4,456 |
|
Industrial firm | 9,609 |
| 9,999 |
| 11,112 |
|
Interruptible | 120,812 |
| 102,403 |
| 102,701 |
|
Transportation | 1,016,406 |
| 997,249 |
| 1,016,486 |
|
Average revenue per customer: | |
| |
| |
|
Residential | $ | 772 |
| $ | 810 |
| $ | 886 |
|
Commercial firm | 3,876 |
| 4,389 |
| 4,643 |
|
Industrial firm | 7,488 |
| 9,055 |
| 10,024 |
|
Interruptible | 59,626 |
| 67,791 |
| 68,530 |
|
Transportation | 89,524 |
| 84,460 |
| 82,063 |
|
Average revenue per therm sold: | |
| |
| |
|
Residential | $ | 1.110 |
| $ | 1.212 |
| $ | 1.221 |
|
Commercial firm | 0.912 |
| 1.041 |
| 1.042 |
|
Industrial firm | 0.779 |
| 0.906 |
| 0.902 |
|
Interruptible | 0.494 |
| 0.662 |
| 0.667 |
|
Average retail revenue per therm sold | 1.008 |
| 1.122 |
| 1.129 |
|
Transportation | 0.088 |
| 0.085 |
| 0.081 |
|
Heating degree days | 3,823 |
| 3,800 |
| 3,829 |
|
Percent of normal - NOAA 30-year average | 81.0 | % | 80.5 | % | 81.2 | % |
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 (British Columbia and Alberta). PSE also enters into physical and financial hedges to manage volatility in the cost of natural gas. All of PSE’s natural gas supply is ultimately transported through the facilities of Northwest Pipeline, GPLLC (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.
|
| | | | | | | | |
| At December 31, |
| 2016 | 2015 |
Peak Firm Natural Gas Supply | Dth per Day | % | Dth per Day | % |
Purchased natural gas supply: | | | | |
British Columbia | 290,200 |
| 30.7 | % | 210,000 |
| 23.4 | % |
Alberta | 76,500 |
| 8.1 |
| 110,000 |
| 12.2 |
|
United States | 115,600 |
| 12.2 |
| 118,100 |
| 13.1 |
|
Total purchased natural gas supply | 482,300 |
| 51.0 |
| 438,100 |
| 48.7 |
|
Purchased storage capacity: | | | | |
Jackson Prairie | 48,400 |
| 5.1 |
| 48,400 |
| 5.4 |
|
Clay Basin | 64,100 |
| 6.8 |
| 61,600 |
| 6.8 |
|
Total purchased storage capacity | 112,500 |
| 11.9 |
| 110,000 |
| 12.2 |
|
Owned storage capacity: | | |
| |
| |
|
Jackson Prairie | 348,700 |
| 36.9 |
| 348,700 |
| 38.8 |
|
Propane and LNG | 2,500 |
| 0.3 |
| 2,500 |
| 0.3 |
|
Total owned storage capacity | 351,200 |
| 37.1 |
| 351,200 |
| 39.1 |
|
Total peak firm natural gas supply1 | 946,000 |
| 100.0 | % | 899,300 |
| 100.0 | % |
Other and commitments with third parties | (5,700 | ) | * |
| (6,200 | ) | * |
|
Total net peak firm natural gas supply | 940,300 |
| * |
| 893,100 |
| * |
|
_______________
| |
1
| All peak firm natural gas supplies and storage are connected to PSE’s market with firm transportation capacity. |
| |
* | Not meaningful and/or applicable. |
For base load, peak management and supply reliability purposes, PSE supplements its firm natural gas supply portfolio by purchasing natural gas in periods of lower demand, injecting it into underground storage facilities and withdrawing it during the peak winter heating season.periods of high demand or reduced supply. 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 natural gas system. Peaking needs are also met by using PSE-owned natural gas held in PSE’s LNG peaking facility located within its distribution system in Gig Harbor, Washington; as well as 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 transportation capacity to meet anticipated growth in the requirements of its firm customers for the foreseeable future.
During 2016, approximately 56.0% of natural gas purchased by PSE for its natural gas customers originated in British Columbia, 21.0% originated in Alberta and 23.0% 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 periods of lower demand to minimize costs. Natural gas is marketed outside of PSE’s service territory (off-system sales) to optimize resources when on-system customer demand requirements permit and market economics are favorable; 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, and is used primarily for intermediate peaking purposes due to its ability to deliver a large volume of natural gas in a short time period. Combined with capacity contracted from NWP’s one-third stake in Jackson Prairie, PSE holds firm withdrawal capacity in excess of 453,800 Dekatherm (Dth) per day, and over 9.8 million Dth of storage capacity at the Jackson Prairie facility. Of this total, PSE holdsdesignates 397,100 Dth per day of the firm withdrawal capacity and over 9.2 million Dth of storage capacity designated to serve natural gas customers, which represents nearly 42% of PSE's expected near-term peak-day requirement.customers. 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.
Of the remaining Jackson Prairie storage capacity, 56,700 Dth per day of firm withdrawal capacity and 641,000640,600 Dth of storage capacity is currently designated 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 6,100 Dth per day of firm withdrawal capacity and 178,500 of Dth of storage capacity to a third party, 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 provides operational flexibility and price protection. PSE holds over 12.9 million Dth of Clay Basin storage capacity and approximately 107,000107,400 Dth per day of firm withdrawal capacity under two long-term contracts with remaining terms of one and three years and has rights to extend such agreements. PSE has temporarily released a portion of its Clay Basin storage services to third parties, and its net storage capacity and maximum firm withdrawal capacity at Clay Basin is 8.9 million Dth and over 74,000 Dth per day, 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.
During 2014, PSE working with NWP determined that the pipeline redelivery service to PSE from NWP’s Plymouth LNG facility could no longer be considered firm during peak conditions. Asholds a result, PSE terminated the service agreement effective October 31, 2015 and removed the resource from its natural gas firm portfolio. In 2015, PSE and NWP negotiated a new contract for Plymouth LNG service for PSE’s generation fleet, which provides for LNG storage services of 241,700 Dth of PSE-owned natural gas at Plymouth, with a maximum daily deliverability of 70,500 Dth.Dth for use of the PSE will usegeneration fleet. PSE uses the Plymouth contract as an alternate supply source for natural gas required to serve PSE’s generation fleet during peak periods on a daily or intra-day basis. In addition,
PSE acquiredholds 15,000 Dth/day of firm pipeline capacity from Plymouth for the generation fleet. The balance of the LNG capacity will beis delivered using firm NWP pipeline transportation service previously acquired to serve PSE’s generation fleet.
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 vaporized propane-air injection facility delivers the thermal equivalent of 10,000 Dth of natural gas per day for up to 12 days directly into PSE’s distribution system,system; however, it is temporarily not in-serviceout-of-service pending planned environmental safety, efficiency and reliability upgrades. 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.
Puget LNG LLC
In August 2015, PSE filed a proposal with the Washington Commission to develop a LNG facility at the Port of Tacoma. The Tacoma LNG facility will provide peak-shaving services to PSE’s natural gas customers, and will provide LNG as fuel to transportation customers, particularly in the marine market. Following a mediation process and the filing of a settlement stipulation by PSE and all parties, the Washington Commission issued an order on October 31, 2016 that allowed PSE’s parent company, Puget Energy, to create a wholly-owned subsidiary, named Puget LNG LLC (Puget LNG). Puget LNG, which was formed on November 29, 2016, will have the sole purpose of owning, developing and financing the non-regulated activity of the Tacoma LNG facility. Puget LNG has entered into one fuel supply agreement with a maritime customer, and is marketing the facility’s expected output to other potential customers.Facility
Currently under construction at the Port of Tacoma, the Tacoma LNG facility is expected to be operational in 2019.2021. In January 2018, the Puget Sound Clean Air Agency (PSCAA) determined a Supplemental Environmental Impact Statement (SEIS) was necessary in order to rule on the air quality permit for the facility. As a result of requiring a SEIS, PSCAA's timing and decision on the air quality permit delayed the Company's construction schedule. In December 2019, PSCAA issued the air quality permit for the facility, a decision which has been appealed to the Washington Pollution Control Hearings Board by each of the Puyallup Tribe of Indians and nonprofit law firm Earthjustice. When completed, the Tacoma LNG facility is designed to provide peak-shaving services to PSE’s natural gas customers, and provide LNG as fuel to transportation customers, particularly in the marine market. Pursuant to the Washington Commission’s order, Puget LNGPSE will be allocated 57%43.0% of the capital and operating costs, consistent with the regulated portion of the Tacoma LNG facility, and PSEPuget LNG will be allocated the remaining 43%57.0% of the capital and operating costs. The portion of the Tacoma LNG facility allocated to PSE will be subject to regulation by the Washington Commission.
Natural Gas Transportation Capacity
PSE currently holds firm transportation capacity on pipelines owned by Cascade Natural Gas Company (CNGC), NWP, Gas Transmission Northwest (GTN), Nova Gas Transmission (NOVA), Foothills Pipe Lines (Foothills) and Spectra'sEnbridge Westcoast Energy (Westcoast). GTN, NOVA, and Foothills are all TransCanadaTC Energy Corporation 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 543,000542,900 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 447,000447,100 Dth per day of seasonal firm capacity on NWP to provide for delivery of natural gas stored at Jackson Prairie.Prairie to natural gas customers. PSE holds approximately 218,000217,900 Dth per day of firm transportation capacity on NWP to supply natural gas to its electric generating facilities. In addition, PSE holds over 34,00034,200 Dth per day of seasonal firm capacity on NWP to provide for delivery of natural gas stored in Jackson Prairie for its electric generating facilities. PSE’s firm transportation capacity contracts with NWP have remaining terms ranging from twoone to 2825 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 132,000135,800 Dth per day under various contracts, with remaining terms of twofour to foursix years. PSE has other firm transportation capacity on Westcoast’s pipeline, which supplies the electric generating facilities, totaling 86,00088,400 Dth per day, with remaining terms of twofour to foursix years and an option for PSE to renew its rights under the Westcoast contract. PSE has firm transportation capacity for its natural gas customers on NOVA and Foothills pipelines, each totaling approximately 80,00079,000 Dth per day, with remaining terms of twofour to sevensix years and an option for PSE to renew its rights on the capacity on NOVA and Foothills pipelines. PSE has other firm transportation capacity on NOVA and Foothills pipelines, which supplies the electric generating facilities, each totaling approximately 41,000 Dth per day, with remaining termsterm of four to seven years. PSE’s firm transportation capacity for its natural gas customers on the GTN pipeline, totaling over 77,000 Dth per day, has awith remaining term of sevenfour years and PSE has a first right-of-refusal to extend such contracts under current FERC rules. PSE has other firm transportation capacity on GTN pipeline, which supplies the electric generating facilities, totaling 41,00040,600 Dth per day, with remaining terms of one to four years. PSE holds 259,000 decatherms per day of firm capacity on CNGC to sevenconnect generating facilities to the pipeline grid with remaining terms of one to two 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 all available electric conservation that is cost-effective, reliable and feasible. PSE offers programs designed to help new and existing residential, commercial and industrial customers use energy efficiently. PSE uses a variety of mechanisms including cost-effective financial incentives, information and technical services to enable customers to make energy efficient choices with respect to building design, equipment and building systems, appliance purchases and operating practices. PSE recovers the actual costs of its electric and natural gas energy efficiency programs through rider mechanisms. However, the rider mechanisms do not provide assistance with gross margin erosion associated with reduced energy sales. To address this issue, PSE received approval in 20132017 from the Washington Commission for continuation of electric and natural gas decoupling mechanisms, which mitigates gross margin erosion resulting from the Company's energy efficiency efforts.
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. See below for the primary areas of environmental law that have the potential to most significantly impact PSE’s operations and costs.
Air and Climate Change Protection
PSE owns numerous thermal generation facilities, including natural gas plants and an ownership percentage of Colstrip. All of these facilities are governed by the Clean Air Act (CAA), and all have CAA Title V operating permits, which must be renewed every five years. This renewal process could result in additional costs to the plants. PSE continues to monitor the permit renewal process to determine the corresponding potential impact to the plants. These facilities also emit greenhouse gases (GHG), and
thus are also subject to any current or future GHG or climate change legislation or regulation. The Colstrip plant represents PSE’s most significant source of GHG emissions.
Species Protection
PSE owns hydroelectric plants, wind farms and numerous miles of above ground electric distribution and transmission lines which can be impacted by laws related to species protection. A number of species of fish have been listed as threatened or endangered under the Endangered Species Act (ESA), which influences hydroelectric operations, and may affect PSE operations, potentially representing cost exposure and operational constraints. Similarly, there are a number of avian and terrestrial species that have been listed as threatened or endangered under the ESA or are protected by the Migratory Bird Treaty Act or the Bald and Golden Eagle Protection 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
PSE and its predecessors are responsible for environmental remediation at various sites. These include properties currently and formerly owned by PSE (or its predecessors), as well as third-party owned properties where hazardous substances were allegedly generated, transported or released. The primary cleanup laws to which PSE is subject include the Comprehensive Environmental Response, Compensation and Liability Act (federal) and, in Washington, the Model Toxics Control Act (state). PSE is also subject to applicable remediation laws in the state of Montana for its ownership interest in Colstrip. These laws may hold liable any current or past owner or operator of a contaminated site, as well as any generator, transporter, arranger, or disposer of regulated substances.
Hazardous and Solid Waste and PCB Handling and Disposal
Related to certain operations, including power generation and transmission and distribution maintenance, PSE must handle and dispose of certain hazardous and solid wastes. These actions are regulated by the Solid Waste Disposal Act, as amended by the Resource Conservation and Recovery Act (federal), the Toxic Substances Control Act (federal) and hazardous or dangerous waste regulations (state) that impose complex requirements on handling and disposing of regulated substances.
Water Protection
PSE facilities that discharge wastewater or storm water or store bulk petroleum products are governed by the Clean Water Act (federal and state) which includes the Oil Pollution Act amendments. This includes most generation facilities (and all of 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.
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 twelve-month average, was first confirmed in January 2011, and PSE continues to meet the requirement.
Further, Colstrip met the Mercury and Air Toxics Standard (MATS) limits for mercury and acid gases as of April 2017.
Siting New Facilities
In siting new generation, transmission, distribution or other related facilities in Washington, PSE is subject to the State Environmental Policy Act, and may be subject to the federal National Environmental Policy Act, if there is a federal nexus, in addition to other possible local siting and zoning ordinances. These requirements may potentially require mitigation of environmental impacts as well as other measures that can add significant cost to new facilities.
Recent and Future Environmental Law and Regulation
Recent and future environmental laws and regulations may be imposed at a federal, state or local level and may have a significant impact on the cost of PSE operations. PSE monitors legislative and regulatory developments for environmental issues with the potential to alter the operation and cost of our generation plants, transmission and distribution system, and other assets. Described below are the recent, pending and potential future environmental law and regulations with the most significant potential impacts to PSE’s operations and costs.
Climate Change and Greenhouse Gas Emissions
PSE recognizes the growing concern that increased atmospheric concentrations of GHG contributetakes seriously environmental stewardship, implementing both short-term measures and long-term strategies designed to climate change. PSE believes that climate change is an important issue that requires careful analysismanage greenhouse gas emissions in a scientifically sound and considered responses. As climate policy continues to evolve at theresponsible fashion. The Company has worked closely with federal, state and federal levels,local governments on deep decarbonization, and the reduction and mitigation of greenhouse gases. As a result, the Company intends and expects be net zero methane emissions by 2022, coal free by 2025 and its electric system will be carbon neutral by 2030. The Company is also helping Washington State address greenhouse gas emissions from the transportation sector by investing in electric vehicles, as well as the development of liquefied natural gas for maritime and commercial transportation. PSE also remains involvedmindful of our customers' expectation of reliable, affordable service. The Company considers the cost of the decarbonization efforts to date, as well as future efforts in state, regionalits IRP process, and federal policymaking activities. PSE will continue to monitor the development of anyengage in 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.greenhouse gas policy development.
PSE's Greenhouse Gas Emission Reporting
PSE is required to submit, on an annual basis, a report of its GHG emissions to the state of Washington Department of Ecology 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 environmental protection agency (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 20152017 were 11.910.2 million metric tons of carbon dioxide equivalents. Approximately 41.49%43.7% of PSE’s total GHG emissions (approximately 5.04.5 million metric tons) are associated with PSE’s ownership and contractual interests in Colstrip. While Colstrip remains a significant portion(with the closure of PSE’sUnits 1&2 effective December 31, 2019, PSE expects an approximately 45% reduction in Colstrip GHG emissions, Colstrip is an important part of the existing diversified portfolio PSE owns and/or operates for its customers. Consequently,emissions). 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.
Federal Greenhouse Gas RulesRules: New and Existing Power Plants
On August 3,October 23, 2015, the EPA announcedpublished a final rule regarding New Source Performance Standard (NSPS) for the control of carbon dioxide (CO2) from new power plants that burn fossil fuels under section 111(b) of the Clean Air Act. The rule was published on October 23, 2015, and separates standards for new power plants fueled by natural gas and coal. New natural
gas power plants can emit no more than 1,000 lbs. of CO2/megawatt hour (MWh) which is achievable with the latest combined cycle technology. New coal power plants can emit no more than 1,400 lbs. of CO2/MWh, which is less stringent than the draft rule. The standard for coal plants would not specifically requireMWh. Carbon Dioxide Capture and Sequestration (CCS) but CCS was reaffirmed by the EPA in this rule as the “best system of emission reductions” (BSER). These 111(b)
On December 20, 2018, the EPA published a proposed rule that would revise the NSPS for greenhouse gas emissions from new, modified, and reconstructed fossil fuel-fired power plants. The Proposed Rule, would revise the emissions standards for new, modified, and reconstructed fossil fuel-fired electric utility steam generating units that are implemented byeither utility boilers or integrated gasification combined cycle (IGCC) units based on the states, but states have limited flexibility to alterAgency’s proposed revised Best System of Emission Reduction (BSER). The EPA is not proposing any changes nor reopening the standards set byof performance for newly constructed or reconstructed stationary combustion turbines.. For large units, the EPA.
BSER is proposed to be super-critical steam conditions, and if revised, the emission rate will be 1,900 pounds of CO2 per megawatt-hour on a gross output basis (lb. CO2/MWh-gross). For small units, the BSER is proposed to be subcritical steam conditions, and if revised, the emission rate will be 2,000 lbs. of CO2/MWh-gross. The EPA announcedproposes to replace the final ruleCCS BSER determination with a BSER for 111(d),newly constructed coal-fired units based on the most efficient demonstrated steam cycle in combination with the best operating practices. The primary reason for this proposed revision is the high costs and limited geographic availability of CCS.
In June 2014, the EPA issued a proposed Clean Power Plan (CPP) rule on August 3, 2015under Section 111(d) of the Clean Air Act designed to regulate GHG emissions from existing power plants. The proposed rule includes state-specific goals and guidelines for states to develop plans for meeting these goals. The EPA published it ona final rule in October 23, 2015. The rule included several changes fromIn March 2017, then EPA Administrator, Scott Pruitt, signed a notice of withdrawal of the draft rule. Specifically,proposed CPP federal plan and model trading rules and, in October 2017, the EPA excluded energy efficiencyproposed to repeal the CPP rule.
In August 2018, the EPA proposed the Affordable Clean Energy (ACE) rule, pursuant to Section 111(d) of the Clean Air Act.. The ACE rule was finalized in June 2019, and establishes emission guidelines for states to develop plans to address greenhouse gas emissions from one of four "building blocks" identified in the draft rule, leaving just three building blocks (i) increased efficiency for coal plants, (ii) greater utilization of natural gas plantsexisting coal-fired plants. Compliance plans under ACE are due July 2020, and (iii) increased renewable sources. Incompliance generally required by July 2024. PSE is evaluating the final ACE rule to determine its impact on operations pending the EPA provided more flexibility in achieving interim goals by phasing in the reduction and giving states the option to set their own interim compliance glide path and pushing the start of compliance to 2022. The EPA also adjusted the 2012 baseline to address hydroelectricity variability and provided specific CO2 mass targets by year for each state.
States have broad flexibility to pick a rate-based or mass-based approach and can design compliance options and decide how to allocate credits and whether to allow trading. The EPA also gave states the option of seeking additional time, if necessary, to formulate a state plan. States must submit something within one year but can request up to an additional two years for development of a state plan. Thus, states must submit a plan for implementing CO2 reductions to the EPA one to three years following issuanceoutcome of the final rule.proposed Colstrip sale to NorthWestern Energy.
Washington Clean Air Rule
The Clean Air Rule (CAR)CAR was adopted onin September 15, 2016, in Washington State and attempts to reduce greenhouse gas emissions from “covered entities” located within Washington State. Included under the new rule are large manufacturers, petroleum producers and natural gas utilities, including PSE. The CAR sets a cap on emissions associated with covered entities, which decreases over time approximately 5%5.0% every three years. Entities must reduce their carbon emissions, or purchase emission reduction units (ERUs), as defined under the rule, from others.
CAR covers natural gas distributors and subjects them to an emissions reduction pathway based on the indirect emissions of their customers. CAR regulates the emissions of natural gas utilities' 1.2 million customers across the state, adding to the cost of natural gas for homes and businesses, which may increase costs to PSE customers.
OnIn September 27, 2016, PSE, along with Avista Corporation, Cascade Natural Gas Corporation and NW Natural, filed an actiona lawsuit in the U.S. District Court for the Eastern District of Washington challenging the CAR. OnIn September 30, 2016, the four companies filed a similar challenge to the CAR in Thurston County Superior Court. While awaitingIn March 2018, the outcomeThurston County Superior Court invalidated the CAR. The Department of Ecology appealed the Superior Court decision in May 2018. As a result of the appeal, direct review to the Washington State Supreme Court was granted and oral argument was held on March 16, 2019. In January 2020, the Washington Supreme Court affirmed that CAR is not valid for “indirect emitters” meaning it does not apply to the sale of natural gas for use by customers. The court ruled, however, that the rule can be severed and is valid for direct emitters including electric utilities with permitted air emission sources, but remanded the case back to the Thurston County to determine which parts of the rule survive. Meanwhile, the federal court litigation has been held in abeyance pending litigation,resolution of the Company has undertaken stepsstate case.
Washington Clean Energy Transition Act
In May 2019, Washington State passed the 100 Percent Clean Electric Bill that supports Washington's clean energy economy and transitioning to comply with the first compliance perioda clean, affordable, and reliable energy future. The Clean Energy Transition Act requires all electric utilities to eliminate coal-fired generation from their allocation of CAR, which beganelectricity by December 31, 2025; to be carbon-neutral by January 1, 2017.
Mercury Emissions
Mercury control equipment has been installed at Colstrip2030, through a combination of non-emitting electric generation, renewable generation, and/or alternative compliance options; and has operated at a levelmakes it the state policy that, meetsby 2045, 100% of electric generation and retail electricity sales will come from renewable or non-emitting resources. Clean Energy Implementation plans are required every four years from each investor-owned utility (IOU) and must propose interim targets for meeting the current Montana requirement. Compliance, based on a rolling 12-month average, was first confirmed in January 2011,2045 standard between 2030 and PSE continues2045, and lay out an actionable plan that they intend to pursue to meet the requirement.standard. The Washington Commission may approve, reject, or recommend alterations to an IOU’s plan.
In order to meet these requirements, the Act clarifies the Washington Commission’s authority to consider and implement performance and incentive- based regulation, multi-year rate plans, and other flexible regulatory mechanisms where appropriate. The Act mandates that the Washington Commission accelerate depreciation schedules for coal-fired resources, including transmission lines, to December 31, 2025, or to allow IOUs to recover costs in rates for earlier closure of those
facilities. IOUs will be allowed to earn a rate of return on certain Power Purchase Agreements (PPA's) and 36 months deferred accounting treatment for clean energy projects (including PPAs) identified in the utility’s clean energy implementation plan.
IOUs are considered to be in compliance when the cost of meeting the standard or an interim target within the four-year period between plans equals a 2% increase in the weather adjusted sales revenue to customers from the previous year. If relying on the cost cap exemption, IOUs must demonstrate that they have maximized investments in renewable resources and non-emitting generation prior to using alternative compliance measures.
The EPA publishedlaw requires additional rulemaking by several Washington agencies for its measures to be enacted and PSE is unable to predict outcomes at this time. The Company intends to seek recovery of any costs associated with the final Mercury and Air Toxics Standard (MATS) in February 2012. Generating units were given three years, until April 2015, to comply with MATS and could receive up to a 1-year extension from state permitting authorities if necessary forclean energy legislation through the installation of controls. Colstrip met the MATS limits for mercury and acid gases as of April 2016.regulatory process.
Regional Haze Rule
On June 15, 2005,In January 2017, the EPA issued the Clean Air Visibility ruleprovided revisions 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 and 4, but Units 1 and 2 will need to upgrade pollution controls to meet new sulfur dioxide and nitrogen oxide limits. The Sierra Club filed an appeal of the FIP with the United States Court of Appeals for the Ninth Circuit (Ninth Circuit) on November 15, 2012 and PPL Montana also filed an appeal as the Colstrip operator.
The case was heard on May 15, 2014 in Seattle, Washington, and the final decision by the Ninth Circuit was issued June 9, 2015. The Ninth Circuit Court of Appeals reviewed the EPA’s first phase requirements for Colstrip and found that the EPA had not adequately justified the need for two of the control technologies and remanded these two issues back to the EPA. The EPA informally indicated that it will wait until the next Regional Haze planning period to reissue a FIP.
The ruling in no way affects the future planning periods for the Regional Haze program or the glide path for the Company. The current EPA assessment is that the state of Montana will require significant emission reductions to meet the natural visibility goal by 2064Rule which means additional emission reductions will be necessary in future 10-year planning periods, beginningwere published in the 2018-2028 periods, and there is risk and uncertainty regarding potential costs.
In July 2016, the EPA proposed to delayFederal Register. Among other things, these revisions delayed new Regional Haze review from 2018 to 2021, and that proposal is currently awaiting approval, however, the end date will remain 2028. In January 2018, the meantime, Montana has indicatedEPA announced that they planit would revisit certain aspects of these revisions and PSE is unable to work on and submit a State Implementation Planpredict the outcome. Challenges to the 2017 Regional Haze Revision Rule are pending in abeyance in the U.S. Court of Appeals for the second planning period.D.C. Circuit, pending resolution of EPA’s reconsideration of the rule.
Coal Combustion Residuals
OnIn April 17, 2015, the EPA published a final rule, effective October 19, 2015, thatwhich regulates Coal Combustion Residuals (CCR)(CCR's) under the Resource Conservation and Recovery Act, (RCRA), Subtitle D. The CCR rule is self-implementing at a federal level or can be taken over by a state. The rule addresses the risks from coal ash disposal, such as leaking of contaminants into ground water, blowing of contaminants into the air as dust, and the catastrophic failure of coal ash containment structures by establishing technical design, operation and maintenance, closure and post closure care requirements for CCR landfills and surface impoundments, and corrective action requirements for any related leakage. The rule also sets forth recordkeeping and reporting requirements, including posting specific information related to CCR surface impoundments and landfills to publicly-accessible websites. The EPA published another rule, which became effective on October 4, 2016, extending certain compliance deadlines contained in the original CCR rule.
The initial rule was self-implementing to be enforced by citizen lawsuits rather than the EPA. On December 16, 2016, President Obama signed legislation amending RCRA to allow a state to take over the CCR program. Under the amendment, if a state does not seek approval of a permit program or if the EPA denies a state application, the EPA would be required to adopt a permit program in lieu of the current self-implementing rule, as long as Congress grants the funding for the EPA to do so. This would not eliminate the threat of citizen lawsuits but could provide more certainty regarding interpretations and ultimate compliance. If no permit program is in effect in a state, the CCR rule will remain self-implementing.
The CCR rule requires significant changes to the Company's Colstrip operations and those changes were reviewed by the Company and the plant operator in the second quarter of 2015. PSE had previously recognized a legal obligation under the EPA rules to dispose of coal ash material at Colstrip in 2003. Due to the CCR rule, additional disposal costs were added to the Asset Retirement and Environmental Obligations (ARO). In 2018, the D.C. Circuit Court of Appeals overturned certain provisions of the CCR rule in 2018 and remanded some of its provisions back to the EPA.As a result of that decision and certain other developments, EPA has is working on developing new rules regarding CCR, including a new proposed date of August 31, 2020, for facilities to stop placing coal ash into unlined surface impoundments.In addition, the EPA has stated that it will soon propose a federal permitting program for coal ash disposal units.
PCB Handling and Disposal
In April 2010, the EPA issued an Advanced Notice of Proposed Rulemaking (ANPRM) soliciting information on a broad range of questions concerning inventory, management, use, and disposal of polychlorinated biphenyl (PCB) containing equipment. The EPA is using this ANPRMAdvanced Notice of Proposed Rulemaking to seek data to better evaluate whether to initiate a rulemaking process geared toward a mandatory phase-out of all PCBs.
The rule was scheduled to be published in July 2015, but due to the number of comments received by the EPA, the rule has undergone multiple extensions and revisions. According toIt was anticipated that the EPA, the notice of proposed rulemaking is projected torule would be published in November 2017. However, in January 2017, the Trump Administration published the Executive Order on Reducing Regulation and Controlling Regulatory Costs directive which placed the rulemaking on indefinite hold. At this point, PSE cannot determine what impacts this rulemaking will have on its operations, if any, but will continue to work closely with the Utility Solid Waste Activities Group (USWAG) and the American Gas Association (AGA) to monitor developments.
Executive Officers of the Registrants
The executive officers of Puget Energy as of March 2, 2017February 21, 2020, are listed below along with their business experience during the past five years. Officers of Puget Energy are elected for one-year terms.
|
| | | | | | | | | | | | | |
Name | Age
| Age |
| Offices |
K. J. HarrisM. E. Kipp | 52
| 52 |
| President since August 2019; Chief Executive Officer since January 2020. President and Chief Executive Officer since March 2011at El Paso Electric from May 2017 to August 2019; Chief Executive Officer at El Paso Electric from December 2015 to May 2017; President at El Paso Electric from September 2014 to December 2015; Senior Vice President, General Counsel and Chief Compliance Officer at El Paso Electric from June 2010 to September 2014. |
D. A. Doyle | 58
| 61 |
| Senior Vice President and Chief Financial Officer since November 2011 |
S. R. Secrist | 55
| 58 |
| Senior Vice President, General Counsel and Chief Ethics and Compliance Officer since January 2014; Vice President, General Counsel and Chief Ethics and Compliance Officer January 2011-January 2014 |
M. R. MarceliaS. J. King | 48
| 36 |
| Controller and Principal Accounting Officer since May 2016; Director of Tax January 2005November 2, 2017. Senior Manager at PricewaterhouseCoopers LLP (PwC), a public accounting firm, July 2016 - MayNovember 2017; Manager at PwC July 2013 - July 2016 |
The executive officers of PSE as of March 2, 2017February 21, 2020, are listed below along with their business experience during the past five years. Officers of PSE are elected for one-year terms.
|
| | | | | | | | | | | | | |
Name | Age
| Age |
| Offices |
K. J. HarrisM. E. Kipp | 52
| 52 |
| President since August 2019; Chief Executive Officer since January 2020. President and Chief Executive Officer since March 2011at El Paso Electric from May 2017 to August 2019; Chief Executive Officer at El Paso Electric from December 2015 to May 2017; President at El Paso Electric from September 2014 to December 2015; Senior Vice President, General Counsel and Chief Compliance Officer at El Paso Electric from June 2010 to September 2014. |
D. A. Doyle | 58
| 61 |
| Senior Vice President and Chief Financial Officer since November 2011 |
P. K. Bussey | 60 |
| Senior Vice President and Chief Customer Officer since March 2012. Prior to PSE, he was President and Chief Executive Officer of Seattle Metropolitan Chamber May 2009 – March 2012 |
B. K. Gilbertson | 53
| 56 |
| Senior Vice President, Operations since March 2015; Vice President, Operations March 2013 – February 2015; Vice President, Operations Services February 2011 – February 20132015 |
M. D. Mellies | 56
| 59 |
| Senior Vice President and Chief Administrative Officer since February 2011 |
D. E. Mills |
| 62 |
| Senior Vice President, Policy and Energy Supply since February 2018; Senior Vice President, Energy Operations January 2017 - February 2018; Vice President, Energy Operations January 2016 - January 2017; Vice President, Energy Supply Operations January 2012 - January 2015 |
S. R. Secrist | 55
| 58 |
| Senior Vice President, General Counsel and Chief Ethics and Compliance Officer since January 2014; Vice President, General Counsel and Chief Ethics and Compliance Officer January 2011-January 2014 |
M. R. MarceliaS. J. King | 48
| 36 |
| Controller and Principal Accounting Officer since May 2016; Director of Tax January 2005November 2, 2017. Senior Manager at PwC July 2016 - MayNovember 2017; Manager at PwC July 2013 - July 2016 |
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 REGULATORY AND RATE-MAKING PROCEDURES
PSE's regulated utility business is subject to various federal and state regulations. PSE's regulatory risks include, but are not limited to, the items discussed below.
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 isare 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. In addition, proceedings with the Washington Commission typically involve multiple stakeholder parties, including consumer advocacy groups and various consumers of energy, who have differing concerns but who have the common objective of limiting rate increases or decreasing rates. 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 costs during a particular test year, adjusted for certain normalizing adjustments. Power costs on the other hand, are normalized for market, weather and hydrological conditions projected to occur during the applicable rate year, the ensuing 12-monthtwelve-month period after rates become effective. The Washington Commission determines the rates PSE may charge to its natural gas customers based on historic costs during a particular test year. Natural gas costs are adjusted through the PGA mechanism, as discussed previously. If in a specific year PSE’s costs are higher than the amounts used by the Washington Commission to determine the rates, revenue may not be sufficient to permit PSE to earn its allowed return or to cover its costs. In addition, the Washington Commission has the authority to determine 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 is currently subject to a Washington Commission order that requires PSE to share its excess earnings above the authorized rate of return with customers. The Washington Commission previously approved an electric and natural gas decoupling mechanism for the recovery of its delivery-system and fixed production costs, along with an ERF, a rate plan and an earnings sharing mechanism that requires PSE and its customers to share in any earnings in excess of the authorized rate of return of 7.77% during the term of the rate plan.7.60%. The earnings test is done for each service (electric/natural gas) separately, so PSE would be obligated to share the earnings for one service exceeding the threshold,authorized rate of return, even if the other service did not meetexceed the earnings test. The decoupling mechanism will end on December 31, 2017 unless the continuationauthorized rate of the mechanism is approved in PSE's GRC which was filed on January 13, 2017.return.
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 and will trigger a surcharge or refund when the cumulative deferral trigger is reached. As a result, if power costs are significantly higher than the baseline rate, PSE’s expenses could significantly increase.
RISKS RELATING TO PSE’s OPERATION
PSE’s cash flow and earnings could be adversely affected by potential high prices and volatile markets for purchased power, 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 PSE's 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 energy supply needs and/or purchases in wholesale markets of high volumes of energy at prices above the amount recovered in retail rates due to:
•Below normal levels of generation by PSE-owned hydroelectric resources due to low streamflow conditions or precipitation;
•Extended outages of any of PSE-owned generating facilities or the transmission lines that deliver energy to load centers, or the effects of large-scale natural disasters on a substantial portion of distribution infrastructure; and
•Failure of a counterparty to deliver capacity or energy purchased by PSE.
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-firedwind-powered generating facilities. Operation of electric generating facilities involves risks that can adversely affect energy output and efficiency levels or increase expenditures, including:
•Facility shutdowns due to a breakdown or failure of equipment or processes;
•Volatility in prices for fuel and fuel transportation;
•Disruptions in the delivery of fuel and lack of adequate inventories;
•Regulatory compliance obligations and related costs, including any required environmental remediation, and any new laws and regulations that necessitate significant investments in our generating facilities;
•Labor disputes;
•Operator error or safety related stoppages;
•Terrorist or other attacks (both cyber-based and/or asset-based); and
•Catastrophic events such as fires, explosions or acts of nature.
If PSE is unableCyber-attacks, including cyber-terrorism or other information technology security breaches, or information technology failures may disrupt business operations, increase costs, lead to protect its physical assets from terrorist attacks or itsthe disclosure of confidential information and damage PSE's reputation. Security breaches of PSE's information technology infrastructure, including cyber-attacks and network againstcyber-terrorism, or other failures of PSE's information technology infrastructure could lead to disruptions of PSE's production and distribution operations, and otherwise adversely impact PSE's ability to safely and effectively operate electric and natural gas systems and serve customers. In addition, an attack on or failure of information technology systems could result in the unauthorized release of customer, employee or Company data corruption, cyber-based attacksthat is crucial to PSE's operational security or networkcould adversely affect PSE's ability to deliver and collect on customer bills. Such security breaches itsof PSE's information technology infrastructure could adversely affect our operations and business reputation, diminish customer confidence, subject PSE to financial liability or increased regulation, expose PSE to fines or material legal claims and liability and adversely affect our financial results. PSE has implemented preventive, detective and remediation measures to manage these risks, and maintains cyber risk insurance to mitigate the effects of these events. Nevertheless, these may not effectively protect all of PSE's systems all of the time. To the extent that the occurrence of any of these cyber-events is not fully covered by insurance, it could be disrupted. Despiteadversely affect PSE’s financial condition and results of operations.
Natural disasters and catastrophic events, including terrorist acts, may adversely affect PSE's implementation of security measures, its physicalbusiness. Events such as fires, earthquakes, explosions, floods, tornadoes, terrorist acts, and other similar occurrences, could damage PSE's operational assets, including utility facilities, information technology infrastructure, distributed generation assets and technology systemspipeline assets. Such events could likewise damage the operational assets of PSE's suppliers or customers. These events could disrupt PSE's ability to meet customer requirements, significantly increase PSE's response costs, and significantly decrease PSE's revenues. Unanticipated events or a combination of events, failure in resources needed to respond to events, or a slow or inadequate response to events may be vulnerable to disability, failures or unauthorized access due to hacking, viruses, acts of war or terrorism and other causes. If the technology systems were to fail or be breached and PSE were unable to recover in a timely manner, PSE may be unable to fulfill critical business functions and sensitive, confidential and other data could be compromised, which could have a materialan adverse effectimpact on its results ofPSE's operations, financial condition, and cash flows. In addition, these physical asset or cyber-based attacks could disrupt its ability to produce or distribute some portionresults of our energy productsoperations. The availability of insurance covering catastrophic events, sabotage and could affect the reliability or operability of the electric and natural gas systems. As a result, PSE endeavors to maintain vigilant security programs and procedures to protect against the continuous threat of physical asset and cyber-based attacks, and as a result, PSEterrorism may be required to expend significant dollarslimited or may result in higher deductibles, higher premiums, and other resources to protect against existing and ensuing threats.more restrictive policy terms.
PSE is subject to the commodity price, delivery and credit risks associated with the energy markets. In connection with matching PSE's energy needs and available 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 for delivery of energy supply or contractually required payments related to PSE's energy supply portfolio. 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.
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 incurrenceoccurrence of associated liabilities could adversely
affect PSE’s results of operations. PSE’s operations are subject to extensive federal, state and local laws and regulations relating to environmental issues, including air emissions and climate change, endangered species protection, remediation of contamination, avian protection, waste handling and disposal, decommissioning, water protection and siting new facilities. To fulfill these legal requirements, PSE must spend significant sums of money to comply with these 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.PSE financially. In addition, PSE may not be able to recover all of its costs for such expenditures through electric and natural gas rates, in a timely manner, at current levels in the future.
Under current law, PSE is also generally responsible for any on-site liabilities associated with the environmental condition of the facilities that it currently owns or operates or has previously owned or operated. The incurrenceoccurrence of a material environmental liability or 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 GHG legislation, including an emission performance standard provisionCETA, and PSE anticipates full compliance with these requirements.
PSE's inability to adequately develop or acquire the necessary infrastructure to comply with new and emerging laws and regulations could have a material adverse impact on our business and results of operations. Potential changes in regulatory standards, impacts of new and existing laws and regulations, including environmental laws and regulations, and the EPA set CO2 emission standardsneed to obtain various regulatory approvals create uncertainty surrounding our energy resource portfolio. The current abundance of low, stably priced natural gas, together with specific state goals. environmental, regulatory, and other concerns surrounding coal-fired generation resources, fossil fuel infrastructure bans, and energy resource portfolio requirements, including those related to renewables development and energy efficiency measures, create strategic challenges as to the appropriate generation portfolio and fuel diversification mix.
In expressing concerns about the environmental and climate-related impacts from continued extraction, transportation, delivery and combustion of fossil fuels, environmental advocacy groups and other third parties have in recent years undertaken greater efforts to oppose the permitting and construction of fossil fuel infrastructure projects. These efforts may increase in scope and frequency depending on a number of variables, including the future course of Municipal, State and Federal environmental regulation and the increasing financial resources devoted to these opposition activities. PSE cannot predict the effect that any such opposition may have on our ability to develop and construct fossil fuel infrastructure projects in the future.
PSE's operating results fluctuate on a seasonal and quarterly basis and can be impacted by various impacts of climate change. 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, its results of operations and financial condition could be adversely affected. PSE's hydroelectric resources are also dependent on snow conditions in the Pacific Northwest.
PSE may be adversely affected by extreme events in which PSE is not able to promptly respond, repair and restart the electric and natural 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 and also require significant expenditures by PSE. 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 depends on an agingits work force and third party vendors to perform certain important services and may be negatively affected by its inability to attract and retain professional and technical employees or the unavailability of vendors. PSE is subject to workforce factors, including but not limited to an aging workforce, loss or retirement of key personnel and availability of qualified personnel. 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. Also, the costs associated with attracting and retaining qualified employees could reduce earnings and cash flows.
PSE continues to be concerned about the availability and aging of skilled workers for special complex utility functions. PSE also hires third party vendors to perform a variety of normal business functions, such as power plant maintenance, data warehousing and management, electric transmission, electric and natural 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 natural gas and electric service and accordingly PSE’s results of operations.
Potential municipalization 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 in PSE's service territory establishes its own municipal-owned utility, it acquires PSE's assets and takes over the delivery of energy services that PSE provides. Although PSE is compensated in connection with the town or city's acquisition of its assets, any such loss of customers and related revenue could negatively affect PSE's future financial condition.
Technological developments may have an adverse impact on PSE's financial condition. 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.
Coal Combustion Residuals
In April 2015, the EPA published a final rule, effective October 2015, which regulates Coal Combustion Residuals (CCR's) under the Resource Conservation and Recovery Act, Subtitle D. The CCR rule is self-implementing at a federal level or can be taken over by a state. The rule addresses the risks from coal ash disposal, such as leaking of contaminants into ground water, blowing of contaminants into the air as dust, and the catastrophic failure of coal ash containment structures by establishing technical design, operation and maintenance, closure and post closure care requirements for CCR landfills and surface impoundments, and corrective action requirements for any related leakage. The rule also sets forth recordkeeping and reporting requirements, including posting specific information related to CCR surface impoundments and landfills to publicly-accessible websites.
The CCR rule requires significant changes to the Company's Colstrip operations and those changes were reviewed by the Company and the plant operator in the second quarter of 2015. PSE had previously recognized a legal obligation under the EPA rules to dispose of coal ash material at Colstrip in 2003. Due to the CCR rule, additional disposal costs were added to the Asset Retirement and Environmental Obligations (ARO). In 2018, the D.C. Circuit Court of Appeals overturned certain provisions of the CCR rule in 2018 and remanded some of its provisions back to the EPA.As a result of that decision and certain other developments, EPA has is working on developing new rules regarding CCR, including a new proposed date of August 31, 2020, for facilities to stop placing coal ash into unlined surface impoundments.In addition, the EPA has stated that it will soon propose a federal permitting program for coal ash disposal units.
PCB Handling and Disposal
In April 2010, the EPA issued an Advanced Notice of Proposed Rulemaking soliciting information on a broad range of questions concerning inventory, management, use, and disposal of polychlorinated biphenyl (PCB) containing equipment. The EPA is using this Advanced Notice of Proposed Rulemaking to seek data to better evaluate whether to initiate a rulemaking process geared toward a mandatory phase-out of all PCBs.
The rule was scheduled to be published in July 2015, but due to the number of comments received by the EPA, the rule has undergone multiple extensions and revisions. It was anticipated that the rule would be published in November 2017. However, in January 2017, the Trump Administration published the Executive Order on Reducing Regulation and Controlling Regulatory Costs directive which placed the rulemaking on indefinite hold. At this point, PSE cannot determine what impacts this rulemaking will have on its operations, if any, but will continue to work closely with the Utility Solid Waste Activities Group and the American Gas Association (AGA) to monitor developments.
Executive Officers of the Registrants
The executive officers of Puget Energy as of February 21, 2020, are listed below along with their business experience during the past five years. Officers of Puget Energy are elected for one-year terms.
| | | | | | | | | | | | | | |
Name |
| Age |
| Offices |
M. E. Kipp |
| 52 |
| President since August 2019; Chief Executive Officer since January 2020. President and Chief Executive Officer at El Paso Electric from May 2017 to August 2019; Chief Executive Officer at El Paso Electric from December 2015 to May 2017; President at El Paso Electric from September 2014 to December 2015; Senior Vice President, General Counsel and Chief Compliance Officer at El Paso Electric from June 2010 to September 2014. |
D. A. Doyle |
| 61 |
| Senior Vice President and Chief Financial Officer since November 2011 |
S. R. Secrist |
| 58 |
| Senior Vice President, General Counsel and Chief Ethics and Compliance Officer since January 2014 |
S. J. King |
| 36 |
| Controller and Principal Accounting Officer since November 2, 2017. Senior Manager at PricewaterhouseCoopers LLP (PwC), a public accounting firm, July 2016 - November 2017; Manager at PwC July 2013 - July 2016 |
The executive officers of PSE as of February 21, 2020, are listed below along with their business experience during the past five years. Officers of PSE are elected for one-year terms.
| | | | | | | | | | | | | | |
Name |
| Age |
| Offices |
M. E. Kipp |
| 52 |
| President since August 2019; Chief Executive Officer since January 2020. President and Chief Executive Officer at El Paso Electric from May 2017 to August 2019; Chief Executive Officer at El Paso Electric from December 2015 to May 2017; President at El Paso Electric from September 2014 to December 2015; Senior Vice President, General Counsel and Chief Compliance Officer at El Paso Electric from June 2010 to September 2014. |
D. A. Doyle |
| 61 |
| Senior Vice President and Chief Financial Officer since November 2011 |
B. K. Gilbertson |
| 56 |
| Senior Vice President, Operations since March 2015; Vice President, Operations March 2013 – February 2015 |
M. D. Mellies |
| 59 |
| Senior Vice President and Chief Administrative Officer since February 2011 |
D. E. Mills |
| 62 |
| Senior Vice President, Policy and Energy Supply since February 2018; Senior Vice President, Energy Operations January 2017 - February 2018; Vice President, Energy Operations January 2016 - January 2017; Vice President, Energy Supply Operations January 2012 - January 2015 |
S. R. Secrist |
| 58 |
| Senior Vice President, General Counsel and Chief Ethics and Compliance Officer since January 2014 |
S. J. King |
| 36 |
| Controller and Principal Accounting Officer since November 2, 2017. Senior Manager at PwC July 2016 - November 2017; Manager at PwC July 2013 - July 2016 |
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 PUGET ENERGY'SPSE’s REGULATORY AND PSE'S FINANCINGRATE-MAKING PROCEDURES
The Company'sPSE's regulated utility business is dependentsubject to various federal and state regulations. PSE's regulatory risks include, but are not limited to, the items discussed below.
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 are 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. In addition, proceedings with the Washington Commission typically involve multiple stakeholder parties, including consumer advocacy groups and various consumers of energy, who have differing concerns but who have the common objective of limiting rate increases or decreasing rates. 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 costs during a particular test year, adjusted for certain normalizing adjustments. Power costs on the other hand, are normalized for market, weather and hydrological conditions projected to occur during the applicable rate year, the ensuing twelve-month period after rates become effective. The Washington Commission determines the rates PSE may charge to its natural gas customers based on historic costs during a particular test year. Natural gas costs are adjusted through the PGA mechanism, as discussed previously. If in a specific year PSE’s costs are higher than the amounts used by the Washington Commission to determine the rates, revenue may not be sufficient to permit PSE to earn its allowed return or to cover its costs. In addition, the Washington Commission has the authority to determine 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 is currently subject to a Washington Commission order that requires PSE to share its excess earnings above the authorized rate of return with customers. The Washington Commission previously approved an electric and natural gas decoupling mechanism for the recovery of its delivery-system and fixed production costs, along with a rate plan and earnings sharing mechanism that requires PSE and its customers to share in any earnings in excess of the authorized rate of return of 7.60%. The earnings test is done for each service (electric/natural gas) separately, so PSE would be obligated to share the earnings for one service exceeding the authorized rate of return, even if the other service did not exceed the authorized rate of return.
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 and will trigger a surcharge or refund when the cumulative deferral trigger is reached. As a result, if power costs are significantly higher than the baseline rate, PSE’s expenses could significantly increase.
RISKS RELATING TO PSE’s OPERATION
PSE’s cash flow and earnings could be adversely affected by potential high prices and volatile markets for purchased power, 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 PSE's 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 energy supply needs and/or purchases in wholesale markets of high volumes of energy at prices above the amount recovered in retail rates due to:
•Below normal levels of generation by PSE-owned hydroelectric resources due to low streamflow conditions or precipitation;
•Extended outages of any of PSE-owned generating facilities or the transmission lines that deliver energy to load centers, or the effects of large-scale natural disasters on a substantial portion of distribution infrastructure; and
•Failure of a counterparty to deliver capacity or energy purchased by PSE.
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, and wind-powered generating facilities. Operation of electric generating facilities involves risks that can adversely affect energy output and efficiency levels or increase expenditures, including:
•Facility shutdowns due to a breakdown or failure of equipment or processes;
•Volatility in prices for fuel and fuel transportation;
•Disruptions in the delivery of fuel and lack of adequate inventories;
•Regulatory compliance obligations and related costs, including any required environmental remediation, and any new laws and regulations that necessitate significant investments in our generating facilities;
•Labor disputes;
•Operator error or safety related stoppages;
•Terrorist or other attacks (both cyber-based and/or asset-based); and
•Catastrophic events such as fires, explosions or acts of nature.
Cyber-attacks, including cyber-terrorism or other information technology security breaches, or information technology failures may disrupt business operations, increase costs, lead to the disclosure of confidential information and damage PSE's reputation. Security breaches of PSE's information technology infrastructure, including cyber-attacks and cyber-terrorism, or other failures of PSE's information technology infrastructure could lead to disruptions of PSE's production and distribution operations, and otherwise adversely impact PSE's ability to successfully access capital. Thesafely and effectively operate electric and natural gas systems and serve customers. In addition, an attack on or failure of information technology systems could result in the unauthorized release of customer, employee or Company reliesdata that is crucial to PSE's operational security or could adversely affect PSE's ability to deliver and collect on accesscustomer bills. Such security breaches of PSE's information technology infrastructure could adversely affect our operations and business reputation, diminish customer confidence, subject PSE to internally generated funds, bank borrowings through multi-year committed credit facilitiesfinancial liability or increased regulation, expose PSE to fines or material legal claims and short-term money marketsliability and adversely affect our financial results. PSE has implemented preventive, detective and remediation measures to manage these risks, and maintains cyber risk insurance to mitigate the effects of these events. Nevertheless, these may not effectively protect all of PSE's systems all of the time. To the extent that the occurrence of any of these cyber-events is not fully covered by insurance, it could adversely affect PSE’s financial condition and results of operations.
Natural disasters and catastrophic events, including terrorist acts, may adversely affect PSE's business. Events such as sources of liquidity and longer-term debt markets to fund PSE's utility construction programfires, earthquakes, explosions, floods, tornadoes, terrorist acts, and other capital expenditure requirementssimilar occurrences, could damage PSE's operational assets, including utility facilities, information technology infrastructure, distributed generation assets and pipeline assets. Such events could likewise damage the operational assets of PSE. If Puget EnergyPSE's suppliers or PSE are unable to access capital on reasonable terms, theircustomers. These events could disrupt PSE's ability to pursue improvementsmeet customer requirements, significantly increase PSE's response costs, and significantly decrease PSE's revenues. Unanticipated events or acquisitions, including generating capacity, whicha combination of events, failure in resources needed to respond to events, or a slow or inadequate response to events may have an adverse impact on PSE's operations, financial condition, and results of operations. The availability of insurance covering catastrophic events, sabotage and terrorism may be necessarylimited or may result in higher deductibles, higher premiums, and more restrictive policy terms.
PSE is subject to the commodity price, delivery and credit risks associated with the energy markets. In connection with matching PSE's energy needs and available 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 for future growth,delivery of energy supply or contractually required payments related to PSE's energy supply portfolio. 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. CapitalAlthough 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.
Costs of compliance with environmental, climate change and credit market disruptions, a downgradeendangered species laws are significant and the costs of Puget Energy's or PSE's credit rating orcompliance with new and emerging laws and regulations and the impositionoccurrence 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 debtassociated liabilities could adversely
affect its liquidity andPSE’s results of operations. Puget EnergyPSE’s operations are subject to extensive federal, state and local laws and regulations relating to environmental issues, including air emissions and climate change, endangered species protection, remediation of contamination, avian protection, waste handling and disposal, decommissioning, water protection and siting new facilities. To fulfill these legal requirements, PSE have short-termmust spend significant sums of money to comply with these measures including resource planning, remediation, monitoring, analysis, mitigation measures, pollution control equipment and long-term debt,emissions related abatement and fees. New environmental laws and regulations affecting PSE’s operations may incur additional debt (including secured debt) in the future. Puget Energy has accessbe adopted, and new interpretations of existing laws and regulations could be adopted or become applicable to a multi-year $800.0 million revolving credit facility, securedPSE or its facilities. Compliance with these or other future regulations could require significant expenditures by substantiallyPSE and adversely affect PSE financially. In addition, PSE may not be able to recover all of its assets, which hascosts for such expenditures through electric and natural gas rates, in a maturity date of April 15, 2018. There was $12.5 million outstanding undertimely manner, at current levels in the facility as of December 31, 2016. Puget Energy's credit facility includes an accordion feature that could, uponfuture.
Under current law, PSE is also generally responsible for any on-site liabilities associated with the banks' approval, increase the size of the facility to $1.3 billion. PSE also has two credit facilities, which provide PSE with access to $1.0 billion in short-term borrowing capability, and include an accordion feature that could, upon the banks' approval, increase the sizeenvironmental condition of the facilities to $1.5 billion.that it currently owns or operates or has previously owned or operated. The two PSE credit facilities matureoccurrence of a material environmental liability or new regulations governing such liability could result in substantial future costs and have a material adverse effect on April 15, 2019. AsPSE’s results of December 31, 2016, no amounts were drawn and outstanding under the PSE credit facilities. In addition, Puget Energy has issued $1.8 billion in senior secured notes, whereas PSE, as of December 31, 2016, 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:
Making it difficult to satisfy obligations under the debt agreements and increasing the risk of default on the debt obligations;
Making it difficult to fund non-debt service related operations of the business; and
Limiting 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, the ability to hedge in wholesale markets and the ability to pay dividends. 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 marketscondition. Specific to requestclimate change, Washington State has adopted both renewable portfolio standards and GHG legislation, including CETA, and PSE anticipates full compliance with these requirements.
PSE's inability to post a letter of creditadequately develop or other collateral, make cash prepayments, obtain a guarantee agreement or provide other mutually agreeable security, all of which would expose PSEacquire the necessary infrastructure to additional costs.
PSE may not declare or make any dividend distribution unless on the date of distribution PSE’s corporate credit/issuer rating is investment grade, or if its credit ratings are below investment grade, PSE’s ratio of earnings before interest, tax, depreciationcomply with new 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 3.0 to 1.0.
The Company may be negatively affected by unfavorable changes in the taxemerging laws or their interpretation. The Company’s tax obligations include income, real estate, public utility, municipal, sales and use, business and occupation and employment-related taxes and ongoing audits related to these taxes. Changes in tax law, related regulations or differing interpretation or enforcement of applicable law by the IRS or other taxing jurisdiction could have a material adverse impact on the Company’s financial statements. The tax law, related regulationsour business and case law are inherently complex. The Company must make judgments and interpretations about the applicationresults of the law when determining the provision for taxes. These judgments may include
reserves for potential adverse outcomes regarding tax positions that may be subject to challenge by the taxing authorities. Disputes over interpretations of tax laws may be settled with the taxing authority in examination, upon appeal or through litigation.
In connection with the change in administration in Washington, D.C., there may be a higher likelihood of substantiveoperations. Potential changes in federal law or regulation, including changes toregulatory standards, impacts of new and existing laws and regulations, governing corporate tax,including environmental protection, healthcare,laws and regulations, and the need to obtain various regulatory approvals create uncertainty surrounding our energy resource portfolio. The current abundance of low, stably priced natural gas, together with environmental, regulatory, and other areas, any of which could affect PSE's operations or financial results. However, at this time PSE is unableconcerns surrounding coal-fired generation resources, fossil fuel infrastructure bans, and energy resource portfolio requirements, including those related to speculaterenewables development and energy efficiency measures, create strategic challenges as to the likely impactappropriate generation portfolio and fuel diversification mix.
In expressing concerns about the environmental and climate-related impacts from continued extraction, transportation, delivery and combustion of fossil fuels, environmental advocacy groups and other third parties have in recent years undertaken greater efforts to oppose the permitting and construction of fossil fuel infrastructure projects. These efforts may increase in scope and frequency depending on a number of variables, including the future course of Municipal, State and Federal environmental regulation and the increasing financial resources devoted to these opposition activities. PSE cannot predict the effect that any such changes. opposition may have on our ability to develop and construct fossil fuel infrastructure projects in the future.
Poor performance of pensionPSE's operating results fluctuate on a seasonal 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. Changes in demographics, including increased numbers of retirements or changes in life expectancy assumptions, may also increase PSE's funding requirements related to the pension plans. Any contributions to PSE’s plans in 2017 and beyond as well as the timing of the recovery of such contributions in GRCs could impact PSE’s cash flow and liquidity.
Potential legal proceedings and claims could increase the Company’s costs, reduce the Company’s revenue and cash flow, or otherwise alter the way the Company conducts business. The Company is, from time to time, subject to various legal proceedings and claims, either asserted or unasserted. Any such claims, whether with or without merit, could be time-consuming and expensive to defend and could divert management’s attention and resources. While management believes the Company has reasonable and prudent insurance coverage and accrues loss contingencies for all known matters that are probablequarterly basis and can be reasonably estimated, the Company cannot assure that the outcomeimpacted by various impacts of all current or future litigation will notclimate change. PSE's business is seasonal and weather patterns can have a material adverse effectimpact 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 and/orexperiences unusually mild winters, its results of operations.operations and financial condition could be adversely affected. PSE's hydroelectric resources are also dependent on snow conditions in the Pacific Northwest.
RISKS RELATING TO PUGET ENERGY'S CORPORATE STRUCTURE
Puget Energy's ability to pay dividendsPSE may be limited. 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.adversely affected by extreme events in which 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’spromptly respond, repair and restart the electric and natural gas mortgage indentures.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 and also require significant expenditures by PSE. In addition, beginning February 6, 2009, pursuanta 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 depends on its work force and third party vendors to perform certain important services and may be negatively affected by its inability to attract and retain professional and technical employees or the termsunavailability of the Washington Commission merger order, vendors. PSE mayis subject to workforce factors, including but not declarelimited to loss 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's ability to declare or make any distribution is limited by its' corporate credit/issuer ratingretirement of key personnel and EBITDA to interest ratio, as previously discussed above. The common equity ratio, calculated on a regulatory basis, was 47.9% at December 31, 2016 and the EBITDA to interest expense was 5.2 to 1.0 for the 12 months ended.
availability of qualified personnel. PSE’s ability to pay dividendsimplement 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. Also, the costs associated with attracting and retaining qualified employees could reduce earnings and cash flows.
PSE continues to be concerned about the availability of skilled workers for special complex utility functions. PSE also limited by the termshires third party vendors to perform a variety 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,normal business functions, such as failure to comply withpower plant maintenance, data warehousing and management, electric transmission, electric and natural gas distribution construction and maintenance, certain financial covenants.billing and
Challenges relating to the constructionmetering processes, call center overflow and credit and collections. The unavailability of skilled workers or future operationunavailability of the Tacoma LNG facilitysuch vendors could adversely affect the Company’s operations. PSEquality and Puget Energy’s subsidiary, Puget LNG, currently are constructing the Tacoma LNG facility at the Portcost of Tacoma, a jointly owned facility intended to provide peak-shaving services to PSE’s natural gas and electric service and accordingly PSE’s results of operations.
Potential municipalization 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 in PSE's service territory establishes its own municipal-owned utility, it acquires PSE's assets and takes over the delivery of energy services that PSE provides. Although PSE is compensated in connection with the town or city's acquisition of its assets, any such loss of customers and related revenue could negatively affect PSE's future financial condition.
Technological developments may have an adverse impact on PSE's financial condition. Advances in power generation, energy efficiency and other alternative energy technologies, such as solar generation, could lead to provide LNG as fuel primarily tomore wide-spread use of these technologies, thereby reducing customer demand for the maritime market. Puget LNG has entered into one fuel supply agreement with a maritime customer, and is marketing the facility’s expected output to other potential customers. Scheduled to be completed in 2019, delays in the facility’s construction and operation or in its ability to timely deliver fuel to customers could expose Puget LNG to damages under one or more fuel supply contracts,energy supplied by PSE which could unfavorablynegatively impact Puget Energy’s return on investment.PSE's revenue and financial condition.
ITEM 1B. UNRESOLVED STAFF COMMENTS
None.
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 Natural 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. LEGAL PROCEEDINGS
From time to time, the Company is involved in litigation or legislative rulemaking proceedings relating to its operations in the normal course of business. The following is a description of pending proceedings that are material to PSE’s operations:
Colstrip
PSE has a 50% ownership interest in Colstrip Units 1 and 2, and a 25% interest in Colstrip Units 3 and 4. On March 6, 2013, the Sierra Club and the Montana Environmental Information Center filed a Clean Air Act citizen suit against all Colstrip owners in the U.S. District Court, District of Montana. Based on a second amended complaint filed in August 2014, the plaintiffs' lawsuit alleged violations of permitting requirements under the New Source Review/Prevention of Significant Deterioration program of the Clean Air Act arising from projects (plaintiffs initially claimed seventy-three projects, but this was reduced to two projects before trial in May 2016) undertaken at Colstrip during the time period from 2001 to 2012. On July 12, 2016, PSE reached a settlement with the Sierra Club to dismiss all of the Clean Air Act allegations against the Colstrip Generating Station, which was approved by the court on September 6, 2016. As part of the settlement, PSE agreed, along with Talen Energy (the owner of the other 50% interest in Colstrip Units 1 and 2), to retire the two oldest units (Units 1 and 2) at Colstrip in eastern Montana by no later than July 1, 2022. PSE expects that the Washington Commission will allow full recovery in rates of the net book value (NBV) at retirement and related decommissioning costs consistent with prior precedents. As a result, PSE has reclassified $176.8 million from a plant asset to a regulatory asset, which represents the expected NBV at retirement of Colstrip Units 1 and 2, based on the expected shutdown date of July 1, 2022. Colstrip Units 3 and 4, which are newer and more efficient, are not affected by the settlement, and allegations in the lawsuit against Colstrip Units 3 and 4 were dismissed as part of the settlement. While PSE has estimated the asset retirement obligation (ARO) for Colstrip Units 1 and 2, the full scope of decommissioning activities and costs are unknown and will vary from the estimates that are available at this time.
Greenwood
On March 9, 2016, a natural gas explosion occurred in the Greenwood neighborhood of Seattle, WA, damaging multiple structures. The Washington Commission Staff completed its investigation of the incident and filed a complaint September 20, 2016, seeking from PSE $3.2 million in fines. As a result, the Washington Commission will initiate a hearing before making a final determination. As of December 31, 2016, PSE has accrued $3.2 million for the fine.
Coal Combustion Residuals
OnIn April 17, 2015, the EPA published a final rule, effective October 19, 2015, thatwhich regulates CCR'sCoal Combustion Residuals (CCR's) under the RCRA,Resource Conservation and Recovery Act, Subtitle D. The EPA issued anotherCCR rule effective October 4, 2016, extending certain compliance deadlines under the CCR rule.is self-implementing at a federal level or can be taken over by a state. The CCR rule addresses the risks from coal ash disposal, such as leaking of contaminants into ground water, blowing of contaminants into the air as dust, and the catastrophic failure of coal ash containment structures by establishing technical design, operation and maintenance, closure and post closure care requirements for CCR landfills and surface impoundments, and corrective action requirements for any related leakage. The rule also sets forth recordkeeping and reporting requirements, including posting specific information related to CCR surface impoundments and landfills to publicly-accessible websites.
The initial rule was self-implementing to be enforced by citizen lawsuits rather than the EPA. On December 16, 2016, President Obama signed legislation amending RCRA to allow a state to take over the CCR program. Under the amendment, if a state does not seek approval of a permit program or if the EPA denies a state application, the EPA would be required to adopt a permit program
in lieu of the current self-implementing rule, as long as Congress grants the funding for the EPA to do so. This would not eliminate the threat of citizen lawsuits, but could provide more certainty regarding interpretations and ultimate compliance. If no permit program is in effect in a state, the CCR rule will remain self-implementing.
The CCR rule requires significant changes to the Company's Colstrip operations and those changes were reviewed by the Company and the plant operator in the second quarter of 2015. PSE had previously recognized a legal obligation under the EPA rules to dispose of coal ash material at Colstrip in 2003. Due to the CCR rule, additional disposal costs were added to the ARO.Asset Retirement and Environmental Obligations (ARO). In 2018, the D.C. Circuit Court of Appeals overturned certain provisions of the CCR rule in 2018 and remanded some of its provisions back to the EPA.As a result of that decision and certain other developments, EPA has is working on developing new rules regarding CCR, including a new proposed date of August 31, 2020, for facilities to stop placing coal ash into unlined surface impoundments.In addition, the EPA has stated that it will soon propose a federal permitting program for coal ash disposal units.
Clean Air Act 111(d)/EPA Clean Power PlanPCB Handling and Disposal
In June 2014,April 2010, the EPA issued an Advanced Notice of Proposed Rulemaking soliciting information on a proposed Clean Power Plan rule under Section 111(d)broad range of the Clean Air Act designed to regulate GHG emissions from existing power plants. The proposed rule includes state-specific goalsquestions concerning inventory, management, use, and guidelines for states to develop plans for meeting these goals. PSE filed comments on this rule in December 2014.disposal of polychlorinated biphenyl (PCB) containing equipment. The EPA publishedis using this Advanced Notice of Proposed Rulemaking to seek data to better evaluate whether to initiate a final rule on October 23, 2015. rulemaking process geared toward a mandatory phase-out of all PCBs.
The rule is being challenged by other states and parties, and the Supreme Court granted a stay of the rule on February 9, 2016 until the litigation is resolved. PSE began review of the final rule and is working with key stakeholderswas scheduled to be published in preparation for implementation;July 2015, but due to the stay, many states, including Montana have put off all discussionnumber of implementation.comments received by the EPA, the rule has undergone multiple extensions and revisions. It was anticipated that the rule would be published in November 2017. However, Washington has moved forward with its own Clean Air Rule.in January 2017, the Trump Administration published the Executive Order on Reducing Regulation and Controlling Regulatory Costs directive which placed the rulemaking on indefinite hold. At this point, PSE cannot yet determine howwhat impacts this rulemaking will have on its operations, if any, but will continue to work closely with the final ruleUtility Solid Waste Activities Group and the American Gas Association (AGA) to monitor developments.
Executive Officers of the Registrants
The executive officers of Puget Energy as of February 21, 2020, are listed below along with their business experience during the past five years. Officers of Puget Energy are elected for one-year terms.
| | | | | | | | | | | | | | |
Name |
| Age |
| Offices |
M. E. Kipp |
| 52 |
| President since August 2019; Chief Executive Officer since January 2020. President and Chief Executive Officer at El Paso Electric from May 2017 to August 2019; Chief Executive Officer at El Paso Electric from December 2015 to May 2017; President at El Paso Electric from September 2014 to December 2015; Senior Vice President, General Counsel and Chief Compliance Officer at El Paso Electric from June 2010 to September 2014. |
D. A. Doyle |
| 61 |
| Senior Vice President and Chief Financial Officer since November 2011 |
S. R. Secrist |
| 58 |
| Senior Vice President, General Counsel and Chief Ethics and Compliance Officer since January 2014 |
S. J. King |
| 36 |
| Controller and Principal Accounting Officer since November 2, 2017. Senior Manager at PricewaterhouseCoopers LLP (PwC), a public accounting firm, July 2016 - November 2017; Manager at PwC July 2013 - July 2016 |
The executive officers of PSE as of February 21, 2020, are listed below along with their business experience during the past five years. Officers of PSE are elected for one-year terms.
| | | | | | | | | | | | | | |
Name |
| Age |
| Offices |
M. E. Kipp |
| 52 |
| President since August 2019; Chief Executive Officer since January 2020. President and Chief Executive Officer at El Paso Electric from May 2017 to August 2019; Chief Executive Officer at El Paso Electric from December 2015 to May 2017; President at El Paso Electric from September 2014 to December 2015; Senior Vice President, General Counsel and Chief Compliance Officer at El Paso Electric from June 2010 to September 2014. |
D. A. Doyle |
| 61 |
| Senior Vice President and Chief Financial Officer since November 2011 |
B. K. Gilbertson |
| 56 |
| Senior Vice President, Operations since March 2015; Vice President, Operations March 2013 – February 2015 |
M. D. Mellies |
| 59 |
| Senior Vice President and Chief Administrative Officer since February 2011 |
D. E. Mills |
| 62 |
| Senior Vice President, Policy and Energy Supply since February 2018; Senior Vice President, Energy Operations January 2017 - February 2018; Vice President, Energy Operations January 2016 - January 2017; Vice President, Energy Supply Operations January 2012 - January 2015 |
S. R. Secrist |
| 58 |
| Senior Vice President, General Counsel and Chief Ethics and Compliance Officer since January 2014 |
S. J. King |
| 36 |
| Controller and Principal Accounting Officer since November 2, 2017. Senior Manager at PwC July 2016 - November 2017; Manager at PwC July 2013 - July 2016 |
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 REGULATORY AND RATE-MAKING PROCEDURES
PSE's regulated utility business is subject to various federal and state regulations. PSE's regulatory risks include, but are not limited to, the items discussed below.
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 are 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. In addition, proceedings with the Washington Commission typically involve multiple stakeholder parties, including consumer advocacy groups and various consumers of energy, who have differing concerns but who have the common objective of limiting rate increases or decreasing rates. 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 costs during a particular test year, adjusted for certain normalizing adjustments. Power costs on the other hand, are normalized for market, weather and hydrological conditions projected to occur during the applicable rate year, the ensuing twelve-month period after rates become effective. The Washington Commission determines the rates PSE may charge to its natural gas customers based on historic costs during a particular test year. Natural gas costs are adjusted through the PGA mechanism, as discussed previously. If in a specific year PSE’s costs are higher than the amounts used by the Washington Commission to determine the rates, revenue may not be sufficient to permit PSE to earn its allowed return or to cover its costs. In addition, the Washington Commission has the authority to determine 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 is currently subject to a Washington Commission order that requires PSE to share its excess earnings above the authorized rate of return with customers. The Washington Commission previously approved an electric and natural gas decoupling mechanism for the recovery of its delivery-system and fixed production costs, along with a rate plan and earnings sharing mechanism that requires PSE and its customers to share in any earnings in excess of the authorized rate of return of 7.60%. The earnings test is done for each service (electric/natural gas) separately, so PSE would be obligated to share the earnings for one service exceeding the authorized rate of return, even if the other service did not exceed the authorized rate of return.
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 and will trigger a surcharge or refund when the cumulative deferral trigger is reached. As a result, if power costs are significantly higher than the baseline rate, PSE’s expenses could significantly increase.
RISKS RELATING TO PSE’s OPERATION
PSE’s cash flow and earnings could be adversely affected by potential high prices and volatile markets for purchased power, 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 PSE's 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 energy supply needs and/or purchases in wholesale markets of high volumes of energy at prices above the amount recovered in retail rates due to:
•Below normal levels of generation by PSE-owned hydroelectric resources due to low streamflow conditions or precipitation;
•Extended outages of any of PSE-owned generating facilities or the transmission lines that deliver energy to load centers, or the effects of large-scale natural disasters on a substantial portion of distribution infrastructure; and
•Failure of a counterparty to deliver capacity or energy purchased by PSE.
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, and wind-powered generating facilities. Operation of electric generating facilities involves risks that can adversely affect energy output and efficiency levels or increase expenditures, including:
•Facility shutdowns due to a breakdown or failure of equipment or processes;
•Volatility in prices for fuel and fuel transportation;
•Disruptions in the delivery of fuel and lack of adequate inventories;
•Regulatory compliance obligations and related costs, including any required environmental remediation, and any new laws and regulations that necessitate significant investments in our generating facilities;
•Labor disputes;
•Operator error or safety related stoppages;
•Terrorist or other attacks (both cyber-based and/or asset-based); and
•Catastrophic events such as fires, explosions or acts of nature.
Cyber-attacks, including cyber-terrorism or other information technology security breaches, or information technology failures may disrupt business operations, increase costs, lead to the disclosure of confidential information and damage PSE's reputation. Security breaches of PSE's information technology infrastructure, including cyber-attacks and cyber-terrorism, or other failures of PSE's information technology infrastructure could lead to disruptions of PSE's production and distribution operations, and otherwise adversely impact PSE's ability to safely and effectively operate electric and natural gas systems and serve customers. In addition, an attack on or failure of information technology systems could result in the unauthorized release of customer, employee or Company data that is crucial to PSE's operational security or could adversely affect PSE's ability to deliver and collect on customer bills. Such security breaches of PSE's information technology infrastructure could adversely affect our operations and business reputation, diminish customer confidence, subject PSE to financial liability or increased regulation, expose PSE to fines or material legal claims and liability and adversely affect our financial results. PSE has implemented preventive, detective and remediation measures to manage these risks, and maintains cyber risk insurance to mitigate the effects of these events. Nevertheless, these may not effectively protect all of PSE's systems all of the time. To the extent that the occurrence of any of these cyber-events is not fully covered by insurance, it could adversely affect PSE’s financial condition and results of operations.
Natural disasters and catastrophic events, including terrorist acts, may adversely affect PSE's business. Events such as fires, earthquakes, explosions, floods, tornadoes, terrorist acts, and other similar occurrences, could damage PSE's operational assets, including utility facilities, information technology infrastructure, distributed generation assets and pipeline assets. Such events could likewise damage the operational assets of PSE's suppliers or customers. These events could disrupt PSE's ability to meet customer requirements, significantly increase PSE's response costs, and significantly decrease PSE's revenues. Unanticipated events or a combination of events, failure in resources needed to respond to events, or a slow or inadequate response to events may have an adverse impact on PSE's operations, financial condition, and results of operations. The availability of insurance covering catastrophic events, sabotage and terrorism may be limited or may result in higher deductibles, higher premiums, and more restrictive policy terms.
PSE is subject to the commodity price, delivery and credit risks associated with the energy markets. In connection with matching PSE's energy needs and available 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 for delivery of energy supply or contractually required payments related to PSE's energy supply portfolio. 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.
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 occurrence of associated liabilities could adversely
affect PSE’s results of operations. PSE’s operations are subject to extensive federal, state and local laws and regulations relating to environmental issues, including air emissions and climate change, endangered species protection, remediation of contamination, avian protection, waste handling and disposal, decommissioning, water protection and siting new facilities. To fulfill these legal requirements, PSE must spend significant sums of money to comply with these 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 financially. In addition, PSE may not be able to recover all of its costs for such expenditures through electric and natural gas rates, in a timely manner, at current levels in the future.
Under current law, PSE is also generally responsible for any on-site liabilities associated with the environmental condition of the facilities that it currently owns or operates or has previously owned or operated. The occurrence of a material environmental liability or 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 GHG legislation, including CETA, and PSE anticipates full compliance with these requirements.
PSE's inability to adequately develop or acquire the necessary infrastructure to comply with new and emerging laws and regulations could have a material adverse impact on our business and results of operations. Potential changes in regulatory standards, impacts of new and existing laws and regulations, including environmental laws and regulations, and the need to obtain various regulatory approvals create uncertainty surrounding our energy resource portfolio. The current abundance of low, stably priced natural gas, together with environmental, regulatory, and other concerns surrounding coal-fired generation resources, fossil fuel infrastructure bans, and energy resource portfolio requirements, including those related to renewables development and energy efficiency measures, create strategic challenges as to the appropriate generation portfolio and fuel diversification mix.
In expressing concerns about the environmental and climate-related impacts from continued extraction, transportation, delivery and combustion of fossil fuels, environmental advocacy groups and other third parties have in recent years undertaken greater efforts to oppose the permitting and construction of fossil fuel infrastructure projects. These efforts may increase in scope and frequency depending on a number of variables, including the future course of Municipal, State and Federal environmental regulation and the increasing financial resources devoted to these opposition activities. PSE cannot predict the effect that any such opposition may have on our ability to develop and construct fossil fuel infrastructure projects in the future.
PSE's operating results fluctuate on a seasonal and quarterly basis and can be impacted by various impacts of climate change. 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, its results of operations and financial condition could be adversely affected. PSE's hydroelectric resources are also dependent on snow conditions in the Pacific Northwest.
PSE may be adversely affected by extreme events in which PSE is not able to promptly respond, repair and restart the electric and natural 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 and also require significant expenditures by PSE. 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 depends on its work force and third party vendors to perform certain important services and may be negatively affected by its inability to attract and retain professional and technical employees or the unavailability of vendors. PSE is subject to workforce factors, including but not limited to loss or retirement of key personnel and availability of qualified personnel. 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. Also, the costs associated with attracting and retaining qualified employees could reduce earnings and cash flows.
PSE continues to be concerned about the availability of skilled workers for special complex utility functions. PSE also hires third party vendors to perform a variety of normal business functions, such as power plant maintenance, data warehousing and management, electric transmission, electric and natural 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 natural gas and electric service and accordingly PSE’s results of operations.
Potential municipalization 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 in PSE's service territory establishes its own municipal-owned utility, it acquires PSE's assets and takes over the delivery of energy services that PSE provides. Although PSE is compensated in connection with the town or city's acquisition of its assets, any such loss of customers and related revenue could negatively affect PSE's future financial condition.
Technological developments may have an adverse impact on PSE's financial condition. 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'S AND PSE'S FINANCING
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 necessary for future growth, 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 states where the Clean Power Planevent 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 been stayed,access to a multi-year $800.0 million revolving credit facility, secured by substantially all of its assets, which has a maturity date of October 25, 2023. There was $24.1 million outstanding under the facility as of December 31, 2019. Puget Energy's credit facility includes an expansion feature that could, upon the banks' approval, increase the size of the facility to $1.3 billion. In October 2018, Puget Energy entered into a 3-year $150 million term loan agreement with a small group of banks. Subsequently, in April 2019, the amount of the loan was increased to $174.0 million. Separately, Puget Energy entered into a 3 year, $210.0 million term loan agreement with a small group of banks in September 2019. PSE also has a separate credit facility, which provides PSE with access to $800.0 million in short-term borrowing capability, and includes an expansion feature that could, upon the banks' approval, increase the size of the facility to $1.4 billion. The PSE credit facility matures on October 25, 2023. As of December 31, 2019, no amounts were drawn and outstanding under the PSE credit facility. In addition, Puget Energy has issued $1.8 billion in senior secured notes, whereas PSE, as of December 31, 2019, had approximately $4.4 billion outstanding under first mortgage bonds, pollution control bonds and senior notes. The Company's debt level could have important effects on the business, including but not limited to:
•Making it difficult to satisfy obligations under the debt agreements and increasing the risk of default on the debt obligations;
•Making it difficult to fund non-debt service related operations of the business; and
•Limiting 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, the ability to hedge in wholesale markets and the ability to pay dividends. 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.
PSE may not declare or make any dividend distribution unless on the date of distribution PSE’s corporate credit/issuer rating is investment grade, or if its credit ratings are below investment grade, PSE’s ratio of earnings before interest, tax, depreciation and amortization (EBITDA) to interest expense for the most recently ended four fiscal quarter periods prior to such date is equal to or greater than 3.0 to 1.0.
Changes in the method for determining LIBOR and the potential replacement of LIBOR may affect our credit facilities and the interest rates on such borrowings. LIBOR, the London interbank offered rate, is the basic rate of interest used in lending between banks on the London interbank market and is widely used as a reference for setting the interest rate on loans globally. Puget Energy and PSE’s credit facilities allow Puget Energy or PSE, respectively to borrow at the bank's prime rate or to make floating rate advances at LIBOR plus a spread that is based upon Puget Energy’s or PSE's credit rating, respectively.
On July 27, 2017, the United Kingdom’s Financial Conduct Authority, which regulates LIBOR announced that it intends to phase out LIBOR by the end of 2021. It is unclear if at all. that time LIBOR will cease to exist or if new methods of calculating LIBOR will be established such that it continues to exist after 2021. If the method for calculation of LIBOR changes, if LIBOR is no longer available or if lenders have increased costs due to changes in LIBOR, Puget Energy or PSE may suffer from potential increases in interest rates on any borrowings. Further, Puget Energy or PSE may need to renegotiate our credit facilities that utilize LIBOR as a factor in determining the interest rate to replace LIBOR with the new standard that is established.
The Company may be negatively affected by unfavorable changes in the tax laws or their interpretation. The Company’s tax obligations include income, real estate, public utility, municipal, sales and use, business and occupation and employment-related taxes and ongoing audits related to these taxes. Changes in tax law, related regulations or differing interpretation or enforcement of applicable law by the IRS or other taxing jurisdiction could have a material adverse impact on 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. These judgments may include reserves for potential impactsadverse outcomes regarding tax positions that may be subject to challenge by the taxing authorities. Disputes over interpretations of tax laws may be settled with the taxing authority in examination, upon appeal or through litigation.
In particular, the Tax Cuts and Jobs Act which was enacted in December 2017 introduced significant permanent and temporary changes to the federal tax code. These changes include a tax rate change from 35.0% to 21.0%, the exclusion of utility businesses from claiming bonus depreciation, the limitation of interest deductibility by non-utility businesses, in addition to numerous other changes.
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 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. Changes in demographics, including increased numbers of retirements or changes in life expectancy assumptions, may also increase PSE's funding requirements related to the pension plans. Any contributions to PSE’s plans in 2020 and beyond as well as the timing of the recovery of such contributions in GRCs could impact PSE’s cash flow and liquidity.
Potential legal proceedings and claims could increase the Company’s costs, reduce the Company’s revenue and cash flow, or otherwise alter the way the Company conducts business. The Company is, from time to time, subject to various legal proceedings and claims. Any such claims, whether with or without merit, could be time-consuming and expensive to defend and could divert management’s attention and resources. While management believes the Company has reasonable and prudent insurance coverage and accrues loss contingencies for all known matters that are probable and can be reasonably estimated, the Company cannot assure that the outcome of all current or future litigation will not have a material adverse effect on the Company and/or its results of operations.
RISKS RELATING TO PUGET ENERGY'S CORPORATE STRUCTURE
Puget Energy's ability to pay dividends may be limited. 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 2009, pursuant to the terms of the Washington Clean Air Rule are described, below.
Washington Clean Air Rule
The CAR was adoptedCommission merger order, PSE may not declare or pay dividends if PSE’s common equity ratio calculated on September 15, 2016 in Washington State and attempts to reduce greenhouse gas emissions from “covered entities” located within Washington State. Included under the new rule are large manufacturers, petroleum producers and natural gas utilities, including PSE. CAR sets a cap on emissions associated with covered entities, which decreases over time approximately 5% every three years. Entities must reduce their carbon emissions,regulatory basis is 44.0% or purchase emission reduction units (ERUs), as defined under the rule, from others.
CAR covers natural gas distributors and subjects them to an emissions reduction pathway based on the indirect emissions of their customers. CAR regulates the emissions of natural gas utilities' 1.2 million customers across the state, addingbelow, except to the costextent a lower equity ratio is ordered by the Washington Commission. Also, pursuant to the merger order, PSE's ability to declare or make any distribution is limited by its' corporate credit/issuer rating and EBITDA to interest ratio, as previously discussed above. The common equity ratio, calculated on a regulatory basis, was 48.4% at December 31, 2019, and the EBITDA to interest expense was 5.3 to 1.0 for the twelve-months ended December 31, 2019.
PSE’s ability to pay dividends is also limited by the terms of natural gas for homes and businesses,its credit facilities, pursuant to which may increase costsPSE is not permitted to PSE customers.
On September 27, 2016, PSE, along with Avista Corporation, Cascade Natural Gas Corporation and NW Natural, filed an actionpay dividends during any Event of Default (as defined in the U.S. District Court forfacilities), or if the Eastern Districtpayment of Washington challenging CAR. On September 30, 2016, the four companies filed a similar challenge to CARdividends would result in Thurston County Superior Court. While awaiting the outcomean Event of the pending litigation, the Company has undertaken stepsDefault, such as failure to comply with certain financial covenants.
Challenges relating to the first compliance periodconstruction or future operation of CAR,the Tacoma LNG facility could adversely affect the Company’s operations. PSE and Puget Energy’s subsidiary, Puget LNG, currently are constructing the Tacoma LNG facility at the Port of Tacoma, a jointly owned facility intended to provide peak-shaving services to PSE’s natural gas customers, and to provide LNG as fuel primarily to the maritime market. Puget LNG has entered into one fuel supply agreement with a maritime customer, and is marketing the facility’s expected output to other potential customers. Scheduled to be completed in 2021, delays in the facility’s construction and operation or in its ability to timely deliver fuel to customers could expose Puget LNG to damages under one or more fuel supply contracts, which begins Januarycould unfavorably impact Puget Energy’s return on investment.
ITEM 1B. UNRESOLVED STAFF COMMENTS
None.
ITEM 2. PROPERTIES
The principal electric generating plants and underground natural gas storage facilities owned by PSE are described under Item 1, 2017.Business – Electric Supply and Natural 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. LEGAL PROCEEDINGS
For more information on litigation or legislative rulemaking proceedings, see Item 1, "Business, Recent and Future Environmental Law and Regulation", and Note 14,15, "Litigation" to the consolidated financial statements included in Item 8 of this report.
ITEM 4. MINE SAFETY DISCLOSURES
Not applicable.
PART II
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, PSE and Puget Energy pay dividends on its common stock. During 2016, 20152019, 2018, and 2014,2017, 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 Form 10-K.
ITEM 6. SELECTED FINANCIAL DATA
The following tables show selected financial data. This information should be read in conjunction with the audited consolidated financial statements and the related notes found in Item 8, "Financial Statements and Supplementary Data" along with the information included in ItemsItem 7, "Management's Discussion and Analysis of Financial Condition and Results of Operation" and Item 8, "Financial Statements and Supplementary Data" of this Form 10-K, respectively.10-K.
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
Puget Energy | | | | | | | | | |
Summary of Operations | Year Ended December 31, | | | | | | | | |
(Dollars in Thousands) | 2019 | | 2018 | | 2017 | | 2016 | | 2015 |
Operating revenue | $ | 3,401,130 | | | $ | 3,346,496 | | | $ | 3,460,276 | | | $ | 3,164,301 | | | $ | 3,092,700 | |
Operating income | 519,008 | | | 554,058 | | | 739,106 | | | 765,474 | | | 671,925 | |
Net income | 210,708 | | | 235,622 | | | 175,194 | | | 312,899 | | | 241,179 | |
| | | | | | | | | | | | | | |
Total assets at year-end | $ | 14,659,863 | | | $ | 14,098,861 | | | $ | 13,690,789 | | | $ | 13,266,380 | | | $ | 12,814,254 | |
Long-term debt | 5,920,325 | | | 5,672,491 | | | 5,207,929 | | | 5,104,073 | | | 5,077,518 | |
Junior subordinated notes | — | | | — | | | 250,000 | | | 250,000 | | | 250,000 | |
Finance lease obligations | 1,480 | | | 1,315 | | | 1,129 | | | 645 | | | 378 | |
Operating lease obligations | 190,189 | | | — | | | — | | | — | | | — | |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
Puget Sound Energy | | | | | | | | | |
Summary of Operations | Year Ended December 31, | | | | | | | | |
(Dollars in Thousands) | 2019 | | 2018 | | 2017 | | 2016 | | 2015 |
Operating revenue | $ | 3,401,130 | | | $ | 3,346,496 | | | $ | 3,460,276 | | | $ | 3,164,618 | | | $ | 3,093,258 | |
Operating income | 522,615 | | | 557,136 | | | 740,595 | | | 770,552 | | | 656,138 | |
Net income | 292,924 | | | 317,162 | | | 320,054 | | | 380,581 | | | 304,189 | |
| | | | | | | | | | | | | | |
Total assets at year-end | $ | 12,625,045 | | | $ | 12,097,523 | | | $ | 11,731,706 | | | $ | 11,297,080 | | | $ | 10,799,513 | |
Long-term debt | 4,336,142 | | | 3,894,860 | | | 3,499,911 | | | 3,497,298 | | | 3,494,362 | |
Junior subordinated notes | — | | | — | | | 250,000 | | | 250,000 | | | 250,000 | |
Finance lease obligations | 1,480 | | | 1,315 | | | 1,129 | | | 645 | | | 378 | |
Operating lease obligations | 190,189 | | | — | | | — | | | — | | | — | |
|
| | | | | | | | | | | | | | | |
Puget Energy | | | | | |
Summary of Operations | Year Ended December 31, |
(Dollars in Thousands) | 2016 | 2015 | 2014 | 2013 | 2012 |
Operating revenue | $ | 3,164,301 |
| $ | 3,092,700 |
| $ | 3,113,171 |
| $ | 3,187,297 |
| $ | 3,215,156 |
|
Operating income | 785,384 |
| 671,925 |
| 577,851 |
| 755,160 |
| 715,535 |
|
Net income | 312,899 |
| 241,179 |
| 171,835 |
| 285,728 |
| 273,821 |
|
| | | | | |
Total assets at year end | $ | 13,266,380 |
| $ | 12,814,254 |
| $ | 12,673,603 |
| $ | 12,820,571 |
| $ | 12,781,838 |
|
Long-term debt | 5,104,073 |
| 5,077,518 |
| 4,831,608 |
| 4,982,476 |
| 5,083,200 |
|
Junior subordinated notes | 250,000 |
| 250,000 |
| 250,000 |
| 250,000 |
| 250,000 |
|
Capital lease obligations | 645 |
| 378 |
| 9,473 |
| 17,051 |
| 24,629 |
|
|
| | | | | | | | | | | | | | | |
Puget Sound Energy | | | | | |
Summary of Operations | Year Ended December 31, |
(Dollars in Thousands) | 2016 | 2015 | 2014 | 2013 | 2012 |
Operating revenue | $ | 3,164,618 |
| $ | 3,093,258 |
| $ | 3,116,123 |
| $ | 3,187,335 |
| $ | 3,216,259 |
|
Operating income | 774,993 |
| 656,138 |
| 568,693 |
| 735,574 |
| 692,989 |
|
Net income | 380,581 |
| 304,189 |
| 236,614 |
| 356,129 |
| 356,170 |
|
| | | | | |
Total assets at year end | $ | 11,297,080 |
| $ | 10,799,513 |
| $ | 10,581,415 |
| $ | 10,667,830 |
| $ | 10,559,956 |
|
Long-term debt | 3,497,298 |
| 3,494,362 |
| 3,351,259 |
| 3,513,258 |
| 3,513,258 |
|
Junior subordinated notes | 250,000 |
| 250,000 |
| 250,000 |
| 250,000 |
| 250,000 |
|
Capital lease obligations | 645 |
| 378 |
| 9,473 |
| 17,051 |
| 24,629 |
|
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, Inc. (Puget Energy) and Puget Sound Energy, Inc. (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 anany 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 StatesU.S. 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 substantially all of its operations are conducted through its subsidiary PSE, a regulated electric and natural gas utility company. PSE is the largest electric and natural gas utility in the state of Washington, primarily engaged in the business of electric transmission, distribution and generation and natural gas distribution. Puget Energy's business strategy is to generate stable cash flows by offering reliable electric and natural gas service in a cost-effective manner through PSE. Puget Energy also has a wholly-owned non-regulated subsidiary, named Puget LNG, LLC (Puget LNG). Puget LNG was formed on November 29, 2016, and, which has the sole purpose of owning, developing and financing the non-regulated activity of the Tacoma LNGliquefied natural gas (LNG) facility, currently under construction. All of Puget Energy's common stock is indirectly owned by Puget Holdings, LLC (Puget Holdings). 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(BCI), the Alberta Investment Management Corporation.Corporation (AIMCo), Ontario Municipal Employee Retirement System (OMERS) and PGGM Vermogensbeheer B.V. The sale of previous owners', Macquarie Infrastructure Partners and Macquarie Capital Group Limited, shares to OMERS, PGGM Vermogensbeheer B.V., AIMCo and BCI was approved by various federal and state agencies, including that of the Washington Utilities and Transportation Commission (Washington Commission), and closed on April 17, 2019. 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. PSE continually balances its load requirements, generation resources, purchase power agreements, and market purchases to meet customer demand. The Company's external financing requirements principally reflect the cash needs of its construction program, its schedule of maturing debt and certain operational needs. PSE requires access to bank and capital markets to meet its financing needs.
Factors affecting PSE's performance are set forth in this “Overview” section, as well as in other sections of the Management's Discussion and 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 (ROE) excluding unrealized gains and losses on derivative instruments (net income plus unrealized losses and/or minus unrealized gains 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 includes adjustments that result in a departure from GAAP presentation. The Company believes that its return on average of monthly averages (AMA) equity, also a non-GAAP
measure, is a more suitable metric for comparing ROE across years and is a more accurate metric for assessing and evaluating ROE performance against the Company's authorized regulated ROE. The AMA equity is not intended to represent the regulated equity. PSE's ROE may not be comparable to other companies' ROE measures. Furthermore, this measure is not intended to replace ROE (net(GAAP net income divided by GAAP average common equity) as determined in accordance with GAAP as an indicator of operating performance.
The following table presents PSE’s ROE, its return on AMA equity and it'sits authorized regulated ROE for 20162019 and 2015:2018:
| | | 2016 | 2015 | | 2019 | | | 2018 | |
(Dollars in Thousands) | Earnings | Average Common Equity | Return on Equity | Earnings | Average Common Equity | Return on Equity | (Dollars in Thousands) | Earnings | | Average Common Equity | | Return on Equity | | Earnings | | Average Common Equity | | Return on Equity |
Return on equity | $380,581 | $3,426,620 | 11.1% | $304,189 | $3,320,861 | 9.2% | Return on equity | $292,924 | | | $3,878,302 | | | 7.6% | | | $317,162 | | $3,654,524 | | 8.7% | |
Less/Plus: Unrealized gains and losses on derivative instruments, after-tax | (54,467) | — | * | (8,247) | — | * | Less/Plus: Unrealized gains and losses on derivative instruments, after-tax | 2,823 | | — | | * | | | (32,913) | | — | | * | |
Less: Equity adjustments1 | — | 177,196 | * | — | 228,267 | * | |
Less/Plus: Equity adjustments1 | | Less/Plus: Equity adjustments1 | — | | 179,517 | | * | | | — | | 179,852 | | * | |
Plus: Impact of average of monthly average (AMA) | — | 57,212 | * | — | 34,585 | * | Plus: Impact of average of monthly average (AMA) | — | | (48,247) | | * | | | — | | 18,075 | | * | |
Return on AMA equity | $326,114 | $3,661,028 | 8.9% | $295,942 | $3,583,713 | 8.3% | Return on AMA equity | $295,747 | | | $4,009,572 | | | 7.4% | | | $284,249 | | | $3,852,451 | | | 7.4% | |
Authorized regulated return on equity | * | 9.8% | * | 9.8% | |
Authorized regulated return on equity2 | | Authorized regulated return on equity2 | | | | | 9.5% | | | | | | | 9.5% | |
_______________
| |
1
| Equity adjustments are related to removing the impacts of accumulated other comprehensive income (AOCI), subsidiary retained earnings, retained earnings of derivative instruments, and decoupling 24-month revenue reserve. |
| |
*
| Not meaningful and/or applicable. |
1.Equity adjustments are related to removing the impacts of accumulated other comprehensive income (AOCI), subsidiary retained earnings, retained earnings of derivative instruments, and decoupling 24-month revenue reserve.
2.The authorized regulated return on equity rate is 9.5% effective December 19, 2017, per the approved general rate case (GRC).
*Not meaningful and/or applicable.
The Company’s 20162019 return on AMA equity was 8.9%7.4%, which is lower than the authorized regulated ROE primarily due to the following:
•Regulated equity (rate base time'smultiplied by equity percent) was $360.0$351.6 million lower than AMA equity for the year ended December 31, 2016. The variance was primarily driven by the impact on rate base of the deferred tax liability for utility, plant and equipment.2019. The impact on ROE for this variance was 1.0%negative 0.8%. The variance was primarily driven by investment in items that do not earn a return or earn a return that is less than the authorized ROE. Such items include investment in construction work in progress and growth in rate base since the last general rate case (GRC).
•Depreciation expense was $10.5$90.7 million higher than the amount allowed in rates on a pre-tax basis for the year ended December 31, 2016.2019, for an impact on ROE of negative 2.3%.
Partially offsetting the above was net revenue from below the line activities which totaled $4.3 million.
The Company’s 20152018 return on AMA equity was 8.3%7.4%, which is lower than the authorized regulated ROE primarily due to the following:
•Regulated equity (rate base time'smultiplied by equity percent) was $256.0$379.9 million lower than AMA equity for the year ended December 31, 2015. The variance was primarily driven by the unanticipated impacts on rate base of the deferred tax liability for utility, plant and equipment and lower than anticipated capital spending due to slower than anticipated growth in PSE’s service territory.2018. The impact on ROE for this variance was 1.1%negative 0.9%. The variance was primarily driven by investment in items that do not earn a return or earn a return that is less than the authorized ROE. Such items include investment in construction work in progress and growth in rate base since the last GRC.
Utility margins were $6.1 million lower than allowed in rates for the year ended December 31, 2015 due to the impacts of warmer than normal weather conditions.
•Depreciation expense was $5.2$50.7 million higher than the amount allowed in rates on a pre-tax basis for the year ended December 31, 2015.2018, for an impact on ROE of negative 1.3%.
Factors and Trends Affecting PSE’s Performance
PSE’s ongoing regulatory requirements and operational needs necessitated the investment of substantial capital in 20162019 and will continue to do so in 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. The principal business, economic and other factors that affect PSE’s operations and financial performance include:
•The rates PSE is allowed to charge for its services;
•PSE’s ability to recover power costs that are included in rates which are based on volume;
•Weather conditions, including the impact of temperature on customer load; the impact of extreme weather events on budgeted maintenance costs; meteorological conditions such as snow-pack, affecting hydrological conditions;stream-flow and wind-speed which affect power generation, supply and price;
•The effects of climate change, including changes in the environment that may affect energy costs or consumption, increase the Company’s costs, or adversely affect its operations;
•Regulatory decisions allowing PSE to recover purchased power and fuel costs, on a timely basis;
•PSE’s ability to supply electricity and natural gas, either through company-owned generation, purchase power contracts or by procuring natural gas or electricity in wholesale markets;
•Equal sharing between PSE and its customers of earnings which exceed PSE's authorized rate of return;return (ROR);
•Availability and access to capital and the cost of capital;
•Regulatory compliance costs, including those related to new and developing federal regulations of electric system reliability, state regulations of natural gas pipelines and federal, state and local environmental laws and regulations;
•Wholesale commodity prices of electricity and natural gas;
•Increasing capital expenditures with additional depreciation and amortization;
Bonus depreciation•Failure to complete capital projects on schedule and within budget or the impactabandonment of capital projects, either of which could result in the Company’s inability to recover project costs;
•Tax reform, the effect of lower tax rates, and regulatory treatment of excess deferred tax balances on rate base;base and customer rates;
•General economic conditions in PSE's service territory and its effects on customer growth and use-per-customer; and
•Federal, state, and local taxes.taxes;
•Employee workforce factors, including potential strikes, work stoppages, transitions in senior management, and loss or retirement of key personnel and availability of qualified personnel
•The effectiveness of PSE’s risk management policies and procedures; •Cyber security attacks, data security breaches, or other malicious acts that cause damage to the Company’s generation and transmission facilities or information technology systems, or result in the release of confidential customer, employee, or Company information;
•Acts of war or terrorism.
Regulation of PSE Rates and Recovery of PSE Costs
PSE's regulatory requirements and operational needs require the investment of substantial capital in 2019 and future years. As PSE intends to seek recovery of these investments through the regulatory process, its financial results depend heavily upon outcomes from that process. The rates that PSE is allowed to charge for its services influence its financial condition, results of operations and liquidity. PSE is highly regulated and the rates that it charges its retail customers are approved by the Washington Commission. The Washington Commission has traditionally required 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 general cost increases over time due to the combined effects of regulatory lag and attrition. Accordingly,Absent a resolution for the impact of lag and attrition, the Company will need to seek rate relief through a rate case on a regular and frequent basis in the foreseeable future. In addition, the Washington Commission determines whether the Company's expenses and capital investments are reasonable and prudent for the provision of cost effective,cost-effective, reliable and safe electric and natural gas service. If the Washington Commission determines that an operating expense ora capital investment doesis not meet the reasonable andor prudent, standards, the costs (including return on any resulting rate base) related to such operating expense or capital investment may be disallowed, partially or entirely, and not recovered in rates.
During 2013, PSE completed an ERF, which was a limited scope rate proceeding, and established a decoupling mechanism for natural gas operations and electric transmission, distribution and administrative costs. The ERF proceeding established baseline rates on which the decoupling mechanism will operate during the rate plan period. The ERF also established a property tax tracker mechanism in which any difference between amounts in rates and property tax payments will be deferred and recovered in an annual filing based on the annual cash payments for the year.
The decoupling mechanism allows PSE to recover costs on a per customer basis rather than on a consumption basis. Included in the decoupling petition was a rate plan that allows PSE an opportunity to earn its authorized rate of return without the need for another GRC process during the rate plan period. The rate plan included predetermined annual increases to PSE’s allowed electric and natural gas revenue. This plan required PSE to file a GRC no later than April 1, 2016 which date was later extended by the Washington Commission to January 17, 2017.
Washington state law also requires PSE to pursue electric conservation that is cost-effective, reliable and feasible. PSE’s mandate to pursue electric conservation initiatives may have a negative impact on the electric business financial performance due to lost margins from lower sales volumes as variable power costs are not part of the decoupling mechanism. Although not specified by Washington state law, the Washington Commission also sets natural gas conservation achievement standards for
PSE. The effects of achieving these standards will, however, have only a slight negative impact on natural gas business financial performance due to the natural gas business being almost fully decoupled.
General Rate Case Filing
On March 17, 2016, the Washington Commission approved a joint petition postponing the filing of PSE’s GRC until no later than January 17, 2017. As part of the petition, PSE agreed to update power costs on December 1, 2016 in conjunction with the
Centralia PPA compliance filing. Additionally, PSE agreed to include in its GRC filing a plan for closure of coal fired steam electric generation facility in ColstripColstrip Units 1 and 2, of which PSE owns a 50% interest. Monthly allowed revenue per customer includes an automatic annual increase and will continue through December 2017 when new rates go into effect from PSE's 2017 GRC.
On January 13, 2017, PSE filed itsa GRC with the Washington Commission which proposed a weighted coston June 20, 2019, requesting an overall increase in electric and natural gas rates of capital of 7.74%, or 6.69% after-tax,6.9% and a capital structure of 48.5% in common equity with7.9% respectively. PSE requested a return on equity of 9.8% with an overall rate of return of 7.62%. The requested combined electric tariff changes would result inIn addition to the traditional areas of focus (revenue requirements, cost allocation, rate design and cost of capital), the Company completed an attrition study and included a net increaseportion of $86.3 million, or 4.1%. The requested combined natural gas tariff changes would result in a net decrease of $22.3 million, or 2.4%. The filing was subsequently suspended, which means that the final rates grantedattrition revenue requirement in the proceeding will go into effect no later than December 13, 2017.
PSE’s GRC filing included the required plan for Colstrip Units 1 and 2 closures, see Item 3, "Legal Proceedings". PSE also requested that the Washington Commission offset the regulatory liabilities for PTCs and Grants against the future cost of Colstrip shutdown and remediationoverall request in order to prevent futureaddress the expected regulatory lag in the rate increasesyear. Additionally, as the non-plant related excess deferred taxes that resulted from the Tax Cuts and Jobs Act (TCJA) remained outstanding from PSE’s Expedited Rate Filing (ERF) as discussed below, PSE requested in its GRC to customers. Additionally, PSE’spass back the amounts over four years.On September 17, 2019, PSE filed a supplemental filing contains requests for two new mechanisms to address regulatory lag. PSE hasin the GRC, which provided updates as discussed in our original filing, but did not impact the requested procedures for an ERF that can be used to update PSE’s delivery revenues on an expedited basis following a general rate case proceeding. PSE also requested approval to establish an electric CRM similar to its existing natural gas CRM which would allow PSE to obtain accelerated cost recovery on specified electric reliability projects.
Decoupling Filings
While fluctuations in weather conditions will continue to affect PSE's billed revenue and energy supply expenses from month to month, PSE's decoupling mechanisms are expected to mitigate the impact of weather on operating revenue and net income. The Washington Commission has allowed PSE to record a monthly adjustment to itsoverall electric and natural gas operating revenues relatedrate increases, return on equity or overall rate of return as originally filed.On January 15, 2020, PSE filed rebuttal testimony which included a reduction to electric transmission and distribution, natural gas operations and general administrative costs from residential, commercial and industrial customersthe requested return on equity to mitigate9.5%, which decreased the effectsrate of weather, conservation impacts and changes in usage patterns per customer. As a result, thesereturn to 7.48%.The requested rate increase for both electric and natural gas remained at 6.9% and 7.9%, respectively. For both electric and natural gas PSE did not originally request its full attrition adjustment; therefore, the decrease in return on equity led to a reduction in the electric rate increase of only $1.5 million and did not have an impact on the natural gas rate increase.
For further details regarding the 2019 GRC filing, see Note 4, "Regulations and Rates" to the consolidated financial statements included in Item 8 of this report.
Expedited Rate Filing
On November 7, 2018, PSE filed an ERF with the Washington Commission. On January 22, 2019, all parties in the proceeding reached an agreement on settlement terms. The settlement agreement was filed on January 30, 2019. On February 21, 2019, the Commission approved the settlement with one condition. The settlement requires that PSE pass back the deferred balance associated with the tax over-collection of $34.6 million from January 1, 2018, through April 30, 2018, over a one-year period which began May 1, 2019.
For further details regarding the 2018 ERF filing, see Note 4, "Regulations and Rates" to the consolidated financial statements included in Item 8 of this report.
Washington Commission Tax Deferral Filing
The TCJA was signed into law in December 2017. As a result of this change, PSE re-measured its deferred tax balances under the new corporate tax rate. PSE filed an accounting petition on December 29, 2017, requesting deferred accounting treatment for the impacts of tax reform. The deferred accounting treatment results in the tax rate change being captured in the deferred income tax balance with an offset to the regulatory liability for deferred income taxes. Additionally, on March 30, 2018, PSE filed for a rate change for electric and natural gas customers associated with TCJA to reflect the decrease in the federal corporate income tax rate from 35% to 21%. Other outcomes associated with PSE’s tax deferral filing are discussed in the ERF and GRC disclosures.
The Washington Commission approved the following PSE requests to change rates to reflect the new corporate tax rates:
| | | | | | | | | | | | | | | | | |
Effective Date | | | Average Percentage Increase (Decrease) in Rates |
| Increase (Decrease) in Revenue (Dollars in Millions) |
Electric: | | |
|
|
|
May 1, 2018 |
| | (3.4)% |
| $(72.9) | |
Natural Gas: |
|
|
|
|
|
May 1, 2018 |
| | (2.7) |
| (23.6) |
Decoupling Filings
On December 5, 2017, the Washington Commission approved PSE’s request within the 2017 GRC to extend the decoupling mechanism with some changes to the methodology that took effect on December 19, 2017. Electric and natural gas delivery revenues will continue to be recovered on a per customer basis regardlessand electric fixed production energy costs will now be decoupled and recovered on the basis of actual consumption levels. Thea fixed monthly amount. Approved revenue per customer costs can only be changed in a GRC or ERF. Approved electric fixed production energy supply costs which are part of the PCA and PGA mechanisms, are not includedcan also be changed in a power cost only rate case (PCORC).
Other changes to the decoupling mechanism. The revenue recorded undermethodology approved by the Washington Commission include regrouping of electric and natural gas non-residential customers and the exclusion of certain electric schedules from the decoupling mechanismsmechanism going forward. The rate cap, which limits the amount of previously deferred revenues PSE can collect in its annual filings, increased from 3.0% to 5.0% for natural gas customers but will be affected by customer growth and not actual consumption. Following each calendar year, PSE will recover from, or refund to, customers the difference between allowed decoupling revenue and the corresponding actual revenue during the following May to April time period.remain at 3.0% for electric customers. The decoupling mechanism will end on December 31, 2017 unless the continuation of the requestedis to be reviewed again in PSE's first GRC filed in or after 2021, or in a separate proceeding, if appropriate. PSE’s decoupling mechanism is approved in PSE’s 2017 GRC which PSE filed on January 13, 2017. Decoupling overover- and underunder- collections will still be collectible or refundable after December 31, 2017,this effective date even if the decoupling mechanism is not extended.
On April 28, 2016,February 21, 2019, the Washington Commission approved the multi-party settlement agreement which was filed within PSE’s request to change rates under itsERF filing. As part of this settlement agreement, electric and natural gas decoupling mechanisms, effective May 1, 2016. The overallallowed delivery revenue per customer was updated to reflect changes represent a rate increase forin the approved revenue requirement. For electric, customers of $20.8 million, or 1.0%, annually, and a rate increase for natural gas customers of $25.4 million, or 2.8%, annually. In addition, PSE exceeded the earnings test threshold for both its electric and natural gas businesses in 2016 and 2015. As a result, PSE recorded a reduction in electric decoupling deferral and revenue of $11.2 million and $16.3 million, respectively, and a reduction in natural gas deferral and revenue of $2.1 million and $9.2 million, respectively. This was reflected as a reductionthere were no changes to the electric and natural gas rate increases noted above. As noted earlier, the Company is also limited to a 3.0% annual decoupling related capallowed fixed power cost revenue. The changes took effect on increases in total revenue. This limitation was triggered for the natural gas residential rate class. The resulting amount of deferral that was not included in the 2016 rate increase is $28.7 million for natural gas revenue that was accrued throughMarch 1, 2019.
On December 31, 2015. This amount may be included in customer rates beginning in May 2017, subject to subsequent application of the earnings test and the 3.0% cap on decoupling related rate increases.
Due to the 3.0% cap on annual decoupling increases noted above and the growing size of decoupling deferrals,2019, PSE performed an analysis as of December 31, 2016 to determine if electric and natural gas decoupling revenue deferrals would be collected from customers within 24 months of December 31, 2016.the annual period, per ASC 980. If not, for GAAP purposes only, PSE would need to record a reserve against the decoupling revenue and a corresponding regulatory asset balance. Once the reserve is probable of collection within 24 months from the end of the annual period, the reserve can be recognized as decoupling revenue. The analysis indicated $19.6that all of electric and natural gas deferred revenue will be collected within 24 months of the annual period; therefore, no adjustment was booked to 2019 decoupling revenue.
The Washington Commission approved the following PSE requests to change rates for prior deferrals under its electric and natural gas decoupling mechanisms:
| | | | | | | | | | | | | | |
Effective Date |
| Average Percentage Increase (Decrease) in Rates |
| Increase (Decrease) in Revenue (Dollars in Millions)1 |
Electric: |
|
|
|
|
May 1, 2019 | | 0.9% | | | $20.6 | |
May 1, 2018 |
| (1.1) | |
| (25.2) | |
May 1, 2017 |
| 2.0 |
| 41.9 |
Natural Gas: |
|
|
|
|
May 1, 2019 | | (5.3)% | | | $(45.9) | |
May 1, 2018 |
| 1.7 | |
| 15.9 | |
May 1, 2017 |
| 2.4 |
| 22.4 |
___________________
1.There were no excess earnings offsetting the increase in revenue for either electric or natural gas effective May 1, 2019, The increase in revenue is net of reductions from excess earnings of $10.0 million for electric and $1.3$4.9 million for natural gas effective May 1, 2018, and $11.9 million for electric and $2.2 million for natural gas effective May 1, 2017.
Electric Rates
Power Cost Adjustment Mechanism
PSE currently has a power cost adjustment (PCA) mechanism that provides for the deferral of power costs that 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 savings are apportioned between PSE and its customers pursuant to the graduated scale set forth in the PCA mechanism and will trigger a surcharge or refund when the cumulative deferral trigger is reached.
Effective January 1, 2017, the following graduated scale is used in the PCA mechanism:
| | | | | | | | | | | | | | | | | | | | | | | | | | |
| Company’s Share | | | |
| Customers' Share | | |
Annual Power Cost Variability | Over | | Under | |
| Over | | Under |
Over or Under Collected by up to $17 million | 100 | % | | 100 | % | |
| — | % | | — | % |
Over or Under Collected by between $17 million - $40 million | 35 | | 50 |
|
| 65 | | 50 |
Over or Under Collected beyond $40 + million | 10 | | 10 |
|
| 90 | | 90 |
In September 2016, PSE filed an accounting petition with the Washington Commission which requested deferral of the variances, either positive or negative, between the fixed costs previously recovered in the PCA and the revenue received to cover the allowed fixed costs. The deferral period requested was January 1, 2017, through December 31, 2017, when rates were to go into effect from PSE's 2017 GRC. In November 2016, the Washington Commission issued Order No. 01 approving PSE’s accounting petition. With the final determination in PSE’s GRC, this deferral ceased with the rate effective date of December 19, 2017.
For the year ended December 31, 2019, in its PCA mechanism, PSE under recovered its allowable costs by $67.2 million of which $36.0 million was apportioned to customers. This compares to an under recovery of allowable costs of $3.5 million for the year ended December 31, 2018, of which no amounts were apportioned to customers. Power costs have been higher than the allowed base line in 2019 which has led to an increase in the PCA deferral causing a higher under-collection compared to the prior year. Actual power costs were higher than baseline rates in 2018 also but by a narrower margin, resulting in lower under-collection. Power prices increased during 2019 as compared to the prior year due to: (i) Cold weather in February and early March, which drove regional loads and demand for power up; (ii) Westcoast pipeline capacity limitations, which contributed to higher natural gas and power prices; (iii) An outage on a transmission line, which contributed to a liquidity crisis at Mid-C and resulted in high market power prices; and (iv) The relative prices of natural gas and electric decouplingpower, which reduced the supply of natural gas-fired generation and increased the demand for market power, increasing prices.
Power Cost Adjustment Clause Filing
PSE updated its rates under Schedule 95 its Power Cost Adjustment Clause tariff to reflect the transition fee as required by Section 12 of the Microsoft Special Contract.
The following table sets forth power cost adjustment clause filing approved by the Washington Commission and the corresponding expected annual impact on PSE’s revenue respectively, will not be collected within 24 months. Therefore, PSE did not recognize this portionbased on the effective dates:
| | | | | | | | | | | | | | |
Effective Date |
| Average Percentage Increase (Decrease) in Rates |
| Increase (Decrease) in Revenue (Dollars in Millions) |
May 1, 2019 | | (1.2)% | | | $(24.9) | |
Electric Conservation Rider
The following table sets forth conservation rider rate adjustments approved by the Washington Commission and the corresponding expected annual impact on PSE’s revenue based on the effective dates:
| | | | | | | | | | | | | | |
Effective Date |
| Average Percentage Increase (Decrease) in Rates |
| Increase (Decrease) in Revenue (Dollars in Millions) |
May 1, 2019 | | (0.9)% | | | $(17.5) | |
May 1, 2018 |
| (0.8) | |
| (18.0) | |
May 1, 2017 |
| 0.7 |
| 16.5 |
Electric Property Tax Tracker Mechanism
The following table sets forth property tax tracker mechanism rate adjustments approved by the Washington Commission and the corresponding expected annual impact on PSE’s revenue based on the effective dates:
| | | | | | | | | | | | | | |
Effective Date |
| Average Percentage Increase (Decrease) in Rates |
| Increase (Decrease) in Revenue (Dollars in Millions) |
May 1, 2019 | | (0.2)% | | | $(5.1) | |
May 1, 2018 |
| (0.1) | |
| (1.3) | |
May 1, 2017 |
| (0.04) |
| (0.9) |
Federal Incentive Tracker Tariff
The following table sets forth the federal incentive tracker tariff revenue requirement approved by the Washington Commission and the corresponding expected annual impact on PSE’s revenue based on the effective dates:
| | | | | | | | | | | | | | |
Effective Date |
| Average Percentage Increase (Decrease) in Rates from prior year |
| Total credit to be passed back to eligible customers (Dollars in Millions) |
January 1, 2020 | | (0.04)% | | | $(37.8) | |
January 1, 2019 |
| 0.1 | |
| (38.7) | |
May 1, 2018 |
| 0.4 |
| (40.1) |
January 1, 2018 |
| 0.2 |
| (48.2) |
January 1, 2017 |
| 0.3 |
| (51.7) |
Residential Exchange Benefit
The following table sets forth residential exchange benefit adjustments approved by the Washington Commission and the corresponding expected annual impact on PSE’s revenue based on the effective dates:
| | | | | | | | | | | | | | |
Effective Date |
| Average Percentage Increase (Decrease) in Rates |
| Total credit to be passed back to eligible customers (Dollars in Millions) |
October 12, 2019 | | 0.01% | | | $(81.8) | |
October 1, 2017 |
| (0.6) | |
| (80.8) | |
Natural Gas Rates
Natural Gas Cost Recovery Mechanism
The following table sets forth CRM rate adjustments approved by the Washington Commission and the corresponding impact on PSE’s revenue based on the effective dates:
| | | | | | | | | | | | | | |
Effective Date |
| Average Percentage Increase (Decrease) in Rates |
| Increase (Decrease) in Revenue (Dollars in Millions) |
November 1, 2019 | | 0.8% | | | $7.0 | |
November 1, 2018 |
| 0.5 | |
| 5.0 | |
November 1, 2017 |
| 0.5 |
| 4.9 |
Purchased Gas Adjustment
On April 25, 2019, the Washington Commission approved PSE’s request for an out-of-cycle change to purchased gas adjustment (PGA) rates with the rate change taking effect May 1, 2019. The out-of-cycle PGA filing was needed to begin amortizing a large PGA commodity deferral balance that had grown due to higher than projected commodity costs during the 2018/19 winter. These higher than projected commodity costs were primarily due to an October 9, 2018, rupture and subsequent explosion on Westcoast Pipeline which is one of decoupling revenue. However, once it is determinedthe major pipelines feeding PSE’s distribution system. The pipeline was repaired in October 2018, however supply capacity on the pipeline was limited over the 2018/19 winter leading to be collectible within 24 months, ithigher prices. February weather was also much colder than normal which also increased the demand for natural gas. The amortization period will be recognized.from May 2019 through April 2020.
On October 24, 2019, the Washington Commission approved PSE’s request for November 2019 PGA rates, with the rate change taking effect on November 1, 2019. As part of that filing, PSE requested PGA rates increase annual revenue by $17.8 million, while the new tracker rates increased by annual revenue of $100.6 million; this was in addition to continuing the collection on the remaining balance of $54.0 million from the out-of-cycle PGA. The tracker rates include deferral balances for the three separate amounts: (i) $114.4 million of under collected commodity balances deferred in February and March; (ii) a $10.8 million balance of over-collected commodity costs for the 2018 PGA, and (iii) a $4.1 million remaining balance from the $54.7 million credit to customers, caused by the 2017 over-collection, established in the 2018 tracker. The high commodity deferral balances for winter months through March 2019 were the result of three noteworthy events last winter experienced by PSE: the Enbridge pipeline rupture, unusually low temperatures in February and March, and a compressor failure in February at the Jackson Prairie storage facility. Additionally, to reduce customer impact, as part of the approved PGA filing, PSE will be collecting $114.4 million commodity deferrals and related interest over a two year period, instead of the historic one year period, from November 2019 through October 2021.
The following table sets forth the PGA rate adjustments approved by the Washington Commission and the corresponding expected annual impact on PSE’s revenue based on the effective dates:
| | | | | | | | | | | | | | |
Effective Date |
| Average Percentage Increase (Decrease) in Rates |
| Increase (Decrease) in Revenue (Dollars in Millions) |
November 1, 2019 | | 13.4% | | | $118.3 | |
May 1, 2019 | | 6.3 | | | 54.0 |
November 1, 2018 |
| (10.9) | |
| (98.4) | |
November 1, 2017 |
| (3.3) |
| (30.8) |
Natural Gas Property Tax Tracker Mechanism
The following table sets forth property tax tracker mechanism rate adjustments approved by the Washington Commission and the corresponding impact on PSE’s revenue based on the effective dates:
| | | | | | | | | | | | | | |
Effective Date |
| Average Percentage Increase (Decrease) in Rates |
| Increase (Decrease) in Revenue (Dollars in Millions) |
May 1, 2019 | | (0.2)% | | | $(1.6) | |
May 1, 2018 |
| (0.2) | |
| (2.2) | |
May 1, 2017 |
| (0.1) |
| (1.1) |
Natural Gas Conservation Rider
The following table sets forth conservation rider rate adjustments approved by the Washington Commission and the corresponding annual impact on PSE’s revenue based on the effective dates:
| | | | | | | | | | | | | | |
Effective Date |
| Average Percentage Increase (Decrease) in Rates |
| Increase (Decrease) in Revenue (Dollars in Millions) |
May 1, 2019 | | 0.1% | | | $1.1 | |
May 1, 2017 |
| (0.1) | |
| (1.0) | |
Other Proceedings
Microsoft Special Contract
Following discussions between PSE, the Microsoft Corporation, and others, and after completing a negotiated regulatory process, the Washington Commission issued an order in July 2017 approving a special contract between PSE and Microsoft have beenrelating to retail access for Microsoft loads currently being served under PSE’s electric Schedule 40. The special contract includes the following conditions: (i) Microsoft must exceed Washington State’s current renewable portfolio standards, (ii) the remainder of power sold to Microsoft must be carbon free, (iii) there will be no reduction in conversationsMicrosoft's funding of PSE’s conservation programs, (iv) Microsoft paid a transition fee that was a straight pass-through to develop a mechanism to provide open accesscustomers and (v) Microsoft will fund enhanced low-income support. Microsoft began taking service to satisfy sustainability objectives. To that end, PSE filed a tariff that has strong limitationsunder the special contract on April 1, 2019, after meeting the eligibility including a stranded cost amount that Microsoft would be required to pay in order to keep all other customers whole. The proposed tariff is currently suspended whilerequirements under the Washington Commission undertakes discovery.special contract.
Voluntary Long-Term Renewable Energy
OnEffective September 28, 2016, the Washington Commission approved PSE's tariff revision to create an additional voluntary renewable energy product, effective September 30, 2016.product. This will provideprovides customers with energy choiceselectric generation resource options to help them meet their sustainability goals. Incremental costs of the program will be allocated to the voluntary participants of the program as is the case with PSE’s existing Green Power programs. PSE will initially offeroffered this service, Green Direct, to larger customers (aggregated annual loads greater than 10,000,000 kWh)10,000 MWh) and government customers.
Electric Rates
Power Cost Adjustment Mechanism
PSE The initial resource option offered under this rate schedule is a new wind generation facility with the capacity of approximately 136.8 MW currently has a PCA mechanism that provides for the deferral of power costs that 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 savings are apportioned between PSE and its customers pursuant to the graduated scale set forthunder construction in the PCA mechanismregion by a developer under contract to PSE. The project is fully subscribed and is expected to begin generating power in 2020. Twenty-one customers will trigger a surcharge or refund whenreceive the cumulative deferral trigger is reached.
The graduated scale that was applicable through December 31, 2016 was as follows:
|
| | |
Annual Power Cost Variability | Company’s Share | Customers' Share |
+/- $20 million | 100% | —% |
+/- $20 million - $40 million | 50 | 50 |
+/- $40 million - $120 million | 10 | 90 |
+/- $120 + million | 5 | 95 |
On August 7, 2015, the Washington Commission issued an order approving the settlement proposing changes to the PCA mechanism. The settlement agreement took effect January 1, 2017 and will apply the following scale:
|
| | | | |
Annual Power Cost Variability | Company's Share | Customers’ Share |
Over or Under Collection: | Over | Under | Over | Under |
Over or Under Collected by up to $17 million | 100% | 100% | —% | —% |
Over or Under Collected by between $17 million - $40 million | 35 | 50 | 65 | 50 |
Over or Under Collected beyond $40 + million | 10 | 10 | 90 | 90 |
The settlement also resulted in the following changes to the PCA mechanism:
Reduction to the cumulative deferral trigger for surcharge or refund from $30.0 million to $20.0 million;
Removal of fixed production costs from the PCA mechanism and placing them in the decoupling mechanism, assuming the decoupling mechanism continues after its review in the 2017 GRC. If decoupling was not to continue, those fixed production costs would be treated the same as other non-PCA costs unless permission to treat them in another manner is obtained from the Washington Commission. These fixed production costs include: (i) return and depreciation/amortization on fixed production assets and regulatory assets and liabilities; (ii) return on, depreciation, transmission expense and revenues on specific transmission assets; and (iii) hydro, other production and other power related expenses and O&M costs;
Suspensionanticipated output of the requirement that a GRC must be filed within three months after rates are approved in a PCORC;project.
Agreement, for a five-year period, that PSE will not file a GRC or PCORC within six months of the date rates go into effect for a PCORC filing; and
Establishment of a five-year moratorium on changes to the PCA.
Pursuant to the PCA Settlement approved on August 7, 2015, effective January 1, 2017, PSE's fixed costs are no longer tracked in PSE's PCA mechanism. Accordingly, on September 30, 2016, PSE filed an accounting petition with the Washington Commission which requests deferral of the variances, either positive or negative, between the fixed costs previously recovered in the PCA and the revenue received to cover the allowed fixed costs. The deferral period requested is January 1, 2017 through December 31, 2017 when rates are in effect from PSE's next GRC. The Commission issued Order No. 01 on November 10, 2016 approving PSE’s accounting petition.
PSE had an annual PCA receivable during the year ended December 31, 2016, due to under recovering $1.0 million of power costs. This compares to an annual PCA receivable of $8.7 million for the year ended December 31, 2015. The change was driven by a decrease in actual costs.
Federal Incentive Tracker Tariff
On December 22, 2016,In July 2018, the Washington Commission approved a second phase of the annual true-upGreen Direct product. The phase 2 offering will be a blend of the phase 1 wind and rate filing to PSE's Federal Incentive Tracker Tariff, with an effective date of January 1, 2017. The true-up filing resulted in a total credit of $51.7 millionsolar project to be passed backbuilt in Washington. Phase 1 customers will receive wind through 2020; and then are expected to eligiblereceive the blended energy in 2021. An additional twenty customers over the twelve months beginning January 1, 2017. The total credit includes $38.1 million which represents the pass-back of grant amortization and $13.6 million represents the passwill start receiving energy through of interest, in addition to a minor true-up associated with the 2016 rate period. This filing represents an overall average rate increase of 0.3% annually.
Power Cost Update Compliance Filing
On September 30, 2016, PSE filed with the Washington Commission the update to power costs under Schedule 95, which was allowed for under Order No. 04 in the 2014 PCORC, and required under the joint petition filed March 9, 2016, seeking to postpone the filing of PSE’s GRC. The filing requested a reduction in Schedule 95 rates of $37.3 million or an overall rate decrease of 1.7% annually. A corresponding reduction in the PCA Mechanism Baseline Rate used to track the PCA imbalance for sharing was also requested in this filing. PSE’s rate filing became effective on December 1, 2016 by operation of law.
Electric Property Tax Tracker Mechanism
On April 28, 2016, the Washington Commission approved PSE's request to change rates under its electric property tax tracker mechanism, effective May 1, 2016. The approved rate change incorporates the effects of an increase to property taxes paid as well as true-ups to the rate from the prior year. This represents a rate increase for electric customers of $5.7 million, or 0.3% annually.
Electric Conservation Rider
On March 1, 2017, PSE filed with the Washington Commission the annual filing to change rates under its electric conservation rider mechanism, effective May 1, 2017. The proposed rate filing requests estimated program year expenditures as well as a true up for actual costs and collections for the conservation program for the prior period which would result in a rate increase for electric customers of $16.5 million, or 0.7% annually.
On April 28, 2016, the Washington Commission approved PSE's request to implement changes to rates under its electric conservation rider mechanism, effective May 1, 2016. The approved rate change incorporates estimated program year expenditures as well as a true up for actual costs and collections for the conservation program for the prior period. This represents a rate decrease for electric customers of $11.7 million, or 0.5% annually.
Natural Gas Rates
Purchased Gas Adjustment
On October 27, 2016, the Washington Commission approved PSE's PGA natural gas tariff filing with an effective date of November 1, 2016, which reflects changes in wholesale gas and pipeline transportation costs and changes in deferral amortization rates. The impact to the PGA rates is an annual revenue decrease of $4.1 million, or 0.4% annually, with no impact on net operating income.
Cost Recovery Mechanism
On October 27, 2016, the Washington Commission approved PSE's CRM natural gas tariff filing with an effective date of November 1, 2016. The purpose of this filing is to recover capital costs related to enhancing the safetyphase 2 of the natural gas distribution system. The impact to the CRM rates is an annual revenue increase of $5.6 million, or 0.6% annually.program, likely by 2021.
Natural Gas Property Tax Tracker Mechanism
On April 28, 2016, the Washington Commission approved PSE's request to change rates under its natural gas property tax tracker mechanism, effective May 1, 2016. This represents a rate increase for natural gas customers of $3.5 million or 0.4% annually.
Natural Gas Conservation Rider
On March 1, 2017, PSE filed with the Washington Commission the annual filing to change rates under its natural gas conservation rider mechanism, effective May 1, 2017. The proposed rate filing requests estimated program year expenditures as well as a true up for actual costs and collections for the conservation program for the prior period which would result in a rate decrease for natural gas customers of $1.0 million, or 0.1% annually.
On April 28, 2016, the Washington Commission approved PSE's request to implement changes to rates under its natural gas conservation rider mechanism, effective May 1, 2016. The approved rate change reflects estimated program year expenditures as well as a true up for actual costs and collections for the conservation program for the prior period. This represents a rate increase for natural gas customers of $2.9 million, or 0.3% annually.
For additional information, see Business, "Regulation and Rates" included in Item 1 of this report and Note 3,4, "Regulation and Rates" to the consolidated financial statements included in Item 8 of this report.
Access to Debt Capital
PSE relies on access to bank borrowings and short-term money markets as sources of liquidity and longer-term capital markets to fund its utility construction program, to meet maturing debt obligations and other capital expenditure requirements not satisfied by cash flow from its operations or equity investment from its parent, Puget Energy. Neither Puget Energy nor PSE have any debt outstanding whose maturity would accelerate upon a credit rating downgrade. However, a ratings downgrade could adversely affect the Company's ability to renew existing, or obtain access to new credit facilities and could increase the cost of such facilities. For example, under Puget Energy's and PSE's credit facilities, the borrowing costs increase as their respective credit ratings decline due to increases in credit spreads and commitment fees. If PSE is unable to access debt capital on reasonable terms, its ability to pursue improvements or acquisitions, including generating capacity, which may be relied on for future growth and to otherwise implement its strategy, could be adversely affected. PSE monitors the credit environment and expects to continue to be able to access the capital markets to meet its short-term and long-term borrowing needs. PSE's credit facilities mature in 2019 and Puget Energy's senior secured credit facility matures in 2018. See discussion on credit facilities in Part II in Item 7, “Financing Program - Puget Sound Energy - Credit Facilities and Puget Energy - Credit Facility".
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, natural gas pipeline system safety and energy market transparency, among other areas. Environmental laws and regulations related to air and water quality, including climate change and endangered species protection, waste handling and disposal (including generation by-products such as coal ash), remediation of contamination and siting new facilities also impact the Company's operations. PSE must spend a significant amountsamount of resources to fulfill requirements set by regulatory agencies, many of which have greatly expanded mandates on measures including but not limited to, resource planning, remediation, monitoring, pollution control equipment and emissions-related abatement and fees.
Compliance with these or other future regulations, such as those pertaining to climate change, 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 generally 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 competition from public utility districts and municipalities that want to establish their own municipal-owned utility, as a result of which PSE may lose a number of customers in its service territory. Further,customers. PSE also faces increasing competition for sales to its retail customers. Alternativecustomers through alternative methods of electric energy generation, including solar and other self-generation methods, compete with PSE for sales to existing electric retail customers.methods. 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.
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, 20162019, and 2015. Set forth below are the consolidated financial results of PSE for the years ended December 31, 2016, 2015 and 2014.2018.
Non-GAAP Financial Measures – Electric and Natural Gas Margins
The following discussion includes financial information prepared in accordance with GAAP, as well as two other financial measures, electric margin and natural gas margin, that are considered “non-GAAP financial measures.” Generally, a non-GAAP financial measure is a numerical measure of a company’s financial performance, financial position or cash flows that includes adjustments that result in a departure from GAAP presentation. The presentation of electric margin and natural gas margin is intended to supplement an understanding of PSE’s operating performance. Electric margin and natural gas margin are used by PSE to determine whether PSE is collecting the appropriate amount of revenue from its customers in order to maintain electric and natural gas margins to ultimately provide adequate recovery of operating costs, including interest and equity returns. PSE’s electric margin and natural gas margin measures may not be comparable to other companies’ electric margin and natural gas margin measures. Furthermore, these measures are not intended to replace operating income as determined in accordance with GAAP as an indicator of operating performance.
Electric Margin
Electric margin represents electric sales to retail and transportation customers less the cost of generating and purchasing electric energy sold to customers, including transmission costs to bring electric energy to PSE’s service territory.
The following tablechart displays the details ofchanges in PSE’s electric margin changes from periods 2016for the years ended December 31, 2018, to 2015December 31, 2019:
_______________ *Includes decoupling cash collections, rate of return excess earnings, and periods 2015 to 2014:decoupling 24-month revenue reserve.
|
| | | | | | | | | | | | | | | |
Electric Margin | Year Ended December 31, | Dollar Change | Year Ended December 31, | Dollar Change |
(Dollars in Thousands) | 2016 | 2015 | 2014 |
Electric operating revenue: | | | | | |
Residential sales | $ | 1,138,871 |
| $ | 1,061,117 |
| $ | 77,754 |
| $ | 1,003,205 |
| $ | 57,912 |
|
Commercial sales | 872,057 |
| 867,786 |
| 4,271 |
| 824,778 |
| 43,008 |
|
Industrial sales | 113,469 |
| 114,223 |
| (754 | ) | 107,750 |
| 6,473 |
|
Other retail sales | 20,045 |
| 20,216 |
| (171 | ) | 19,707 |
| 509 |
|
Total retail sales | 2,144,442 |
| 2,063,342 |
| 81,100 |
| 1,955,440 |
| 107,902 |
|
Transportation sales | 10,937 |
| 10,143 |
| 794 |
| 9,502 |
| 641 |
|
Sales to other utilities and marketers | 50,124 |
| 46,666 |
| 3,458 |
| 41,680 |
| 4,986 |
|
Decoupling revenue | 29,968 |
| 13,630 |
| 16,338 |
| 25,735 |
| (12,105 | ) |
Other decoupling revenue1 | (21,168 | ) | (16,634 | ) | (4,534 | ) | 5,609 |
| (22,243 | ) |
Other | 24,189 |
| 11,321 |
| 12,868 |
| 45,831 |
| (34,510 | ) |
Total electric operating revenues2 | 2,238,492 |
| 2,128,468 |
| 110,024 |
| 2,083,797 |
| 44,671 |
|
Minus power costs: | |
| |
| |
| |
| |
|
Purchased electricity2 | (531,596 | ) | (499,522 | ) | (32,074 | ) | (514,087 | ) | 14,565 |
|
Electric generation fuel2 | (215,331 | ) | (249,907 | ) | 34,576 |
| (263,493 | ) | 13,586 |
|
Residential exchange2 | 69,824 |
| 112,473 |
| (42,649 | ) | 129,036 |
| (16,563 | ) |
Total electric power costs | (677,103 | ) | (636,956 | ) | (40,147 | ) | (648,544 | ) | 11,588 |
|
Electric margin3 | $ | 1,561,389 |
| $ | 1,491,512 |
| $ | 69,877 |
| $ | 1,435,253 |
| $ | 56,259 |
|
| | | | | |
Electric Energy Sales | | | | | |
MWh | | | | | |
Residential sales | 10,245,326 |
| 10,164,703 |
| 80,623 |
| 10,349,928 |
| (185,225 | ) |
Commercial sales | 8,895,950 |
| 8,999,068 |
| (103,118 | ) | 8,900,863 |
| 98,205 |
|
Industrial sales | 1,223,214 |
| 1,257,958 |
| (34,744 | ) | 1,226,588 |
| 31,370 |
|
Other retail sales | 90,753 |
| 94,847 |
| (4,094 | ) | 98,499 |
| (3,652 | ) |
Total energy sales to customers | 20,455,243 |
| 20,516,576 |
| (61,333 | ) | 20,575,878 |
| (59.302 | ) |
_______________
| |
1
| Includes decoupling cash collections, rate of return excess earnings, and decoupling 24-month revenue reserve. |
| |
2
| As reported on PSE’s Consolidated Statement of Income. |
| |
3
| Electric margin does not include any allocation for amortization/depreciation expense or electric generation operation and maintenance expense. |
20162018 compared to 20152019
Electric Operating Revenue
Electric operating revenues increased $110.0$41.2 million primarily due to higher residentialincreased transportation and other revenue of $65.0 million, sales to other utilities and marketers of $77.8$19.8 million increased deferredand decoupling revenue of $16.3$2.1 million; partially offset by lower retail sales of $44.3 million and other electric operatingdecoupling revenue of $12.9$1.4 million. These items are discussed in detail below:
•Electric retail sales increased $81.1 decreased $44.3 million due to increases in rates and residential exchange credits of $86.4 million which was partially offset by $5.6 million due to lower retail electricity usage for non-residential customers.
Decoupling revenue increased $16.3 million due to the allowed decoupled revenues per customer as compared to volumetric revenues in 2016 compared to 2015.
Other electric operating revenue increased $12.9 million primarily due to a reduction of amortization of PTC deferral credits of $10.1 million and non-core gas sales of $6.8 million.
Electric Power Costs
Electric power costs decreased $40.1 million primarily due to a decrease of $42.6$60.7 million in rates partially offset by an increase in retail electricity usage of residential exchange credits,0.7%, or $16.4 million, compared to the prior year. The additional usage was due to an increase of $32.1residential sales and other retail sales of 2.5% and 1.1%, respectively, which was driven by an increase in heating degree days of 3.5% compared to 2018 and an increase in retail customers of 1.4%. See Management's Discussion and Analysis, "Regulation and Rates" included in Item 7 of this report for rate changes.
•Sales to other utilities and marketers increased $19.8 million due to a 20.8% increase in sales volume and a 1.0% increase in price. During the 1st quarter of 2019, wholesale prices increased 115.7% due to spot power prices at Mid-Columbia that increased to an 18-year high largely driven by record-breaking natural gas prices and there was increase in volumes from an additional 111.8% of combustion turbine (CT) generation or an additional 61.2% CT generation at year to date as a result of favorable heat rates and increased demand for wholesale market power.
•Decoupling revenue increased $2.1 million, primarily attributable to an $8.5 million increase in PCA fixed cost deferral revenues. In the current year, actual PCA revenues declined significantly as a result of lower rates, offset in
part by increased usage as noted above in the retail revenue section. This resulted in current year under collection, as compared to prior year over collection. This increase was partially offset by a $6.3 million decrease in delivery deferral revenues, attributable to a decline in allowed revenues year over year as a result of lower allowed rate per customer.
•Other decoupling revenue decreased $1.4 million, primarily related to earnings in excess of allowed ROR. In 2018, $10.1 million of purchase electricity costs,earnings in excess of allowed ROR was passed back to customers, as compared to only $3.5 million in the current year. This decrease of $6.6 million was partially offset by an increase of $4.4 million attributable to lower current period amortization of prior year under collection in 2019 than in 2018. In addition, there was a $1.7 million increase related to GAAP alternative revenue program recognition guidelines. In 2018, there was $0.8 million of revenue that was not anticipated to be collected within 24 months, and therefore was deferred. This amount was recognized in the first quarter of 2019, when the alternative revenue program revenue recognition guidelines were met.
•Transportation and other revenue increased $65.0 million primarily due to an increase in net wholesale natural gas sales of $34.8 million, and an increase in tax reform deferrals for revenue subject to refunds of $38.9 million, partially offset by a decrease in production tax credit (PTC) deferral revenue of $34.5$14.9 million for the re-purpose of the PTCs The increase in net wholesale non-core natural gas sales was due to an approximately 28% increase in the average price of the non-core natural gas sold year ended December 31, 2019, compared to year ended December 31, 2018, offset by a 17% decrease in sales volume. Also contributing to the increase in the net amount was an $18.3 million decrease in the cost of the natural gas sold due to the 17% decrease in sales volume, offset by a 6% increase in the average cost of the natural gas sold which was driven by an increase in the average price of non-core natural gas purchases. The higher natural gas prices occurred in late 2018 and peaked in early 2019 and were due to the effects of the late 2018 Enbridge pipeline rupture which led to a decrease in natural gas supply and higher than expected demand due to cold weather during that time.
Electric Power Costs
Electric power costs increased $90.7 million primarily due to an increase of $78.7 million of electric generation fuel expense.costs and $13.8 million of purchased electricity costs. These items are discussed in detail below:
•Purchased electricity expense increased $32.1$13.8 million primarily due to a $42.3 million15.9% increase in long-term firm and market power purchases, $10.0 million increase in PURPA purchases,wholesale prices partially offset by $26.3 million related to reduceda 11.9% decrease in wholesale electricity purchases. The decrease in purchases was primarily driven by a decrease in hydro purchases at Mid-Columbia of power.
Electric generation fuel expense decreased $34.5 million primarily23.7%, due to lower natural gas prices and burn volumes for ourunfavorable hydro conditions, driving an increase in combustion turbine generation, plants.
which decreased the need to purchase additional wholesale power.Residential exchange credits decreased $42.6 million resulting from lower Residential Exchange Program (REP) credits associated with the BPA REP settlement. The REP credit tariff was lowered effective October 1, 2015. The REP credit is a pass-through tariff item with a corresponding credit in electric operating revenue, with no impact on net income.
The Northwest Power Act, through the 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.
2015 compared to 2014
•Electric Operating Revenue
Electric operating revenuesgeneration fuel expense increased $44.7 million primarily due to higher residential sales of $57.9 million, higher commercial sales of $43.0 million, partially offset by decreased deferred decoupling revenue and other decoupling revenue of $12.1 million and $22.2 million, respectively and other electric operating revenue of $34.5 million. These items are discussed in detail below:
Electric retail sales increased $107.9 million due to increases in rates of $113.5 million due primarily to additional $49.1 million credit provided to customers on Jefferson County Public Utility District (JPUD) gain in 2014, $17.0 million of additional Residential Exchange credits, and $12.9 million additional Renewable Energy Credit (REC) credits in 2014, which was partially offset by $5.6 million due to lower retail electricity usage.
Decoupling revenue resulted in a decrease of $12.1 million due to the allowed decoupled revenues per customer as compared to volumetric revenues in 2015 compared to 2014.
Other decoupling revenue decreased $22.2 million due to $12.8 million recovery from customers and $9.4 million related to over earnings sharing band of the decoupling mechanism.
Other electric operating revenue decreased $34.5$78.7 million primarily due to a reduction of non-core natural gas sales of $23.8$63.0 million and biogas revenues of $10.1 million.
Electric Power Costs
Electric powerincrease in combustion turbine generation costs increased $11.6 million primarily due todriven by an increase in generation of $14.6 million61.2% as a result of purchasefavorable heat rates, unfavorable wholesale electricity costs, an increaseprices, reduced hydro purchases of $13.6 million23.7% and reduced hydro and wind generation of electric generation fuel costs22.0% and 13.7%, respectively. This was partially offset by a decrease in cost per kWh generated of $16.6 million8.7%,
For additional information on prior years, please see discussion in Item 7, "Non-GAAP Financial Measures - Electric Margin" of residential exchange credits. The following items are discussed in detail:Form 10-K for period ended December 31, 2018.
Purchased electricity expense decreased $14.6 million primarily due to a $27.4 million decrease in long-term firm and market power purchases, partially offset by $10.1 million related to the PCA customer portion in 2014.
Electric generation fuel expense decreased $13.6 million primarily due to lower natural gas prices for our combustion turbine generation plants.
Residential exchange credits decreased $16.6 million resulting from lower REP credits associated with the BPA REP settlement. The REP credit tariff was lowered effective October 1, 2015. The REP credit is a pass-through tariff item with a corresponding credit in electric operating revenue, with no impact on net income.
Natural Gas Margin
Natural gas margin is natural gas sales to retail and transportation customers less the cost of natural gas purchased, including transportation costs to bring natural gas to PSE’s service territory. The PGA mechanism passes through to customers increases or decreases in the natural gas supply portion of the natural gas service rates to customers 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 margin or net income is not affected by changes under the PGA mechanism because overover- and underunder- recoveries of natural gas costs included in baseline PGA rates are deferred and either refunded or collected from customers, respectively, in future periods.
The following table and discussion highlights significant items that impact natural gas operating revenue and natural gas energy costs which are includedchart displays the changes in PSE’s natural gas margin for the years ended December 31, 2016, 2015 and 2014:2018, to December 31, 2019:
|
| | | | | | | | | | | | | | | |
Natural Gas Margin | Year Ended December 31, | Dollar Change | Year Ended December 31, | Dollar Change |
(Dollars in Thousands) | 2016 | 2015 | 2014 |
Natural gas operating revenue: | | | | | |
Residential sales | $ | 578,955 |
| $ | 597,572 |
| $ | (18,617 | ) | $ | 644,055 |
| $ | (46,483 | ) |
Commercial sales | 235,695 |
| 268,044 |
| (32,349 | ) | 281,526 |
| (13,482 | ) |
Industrial sales | 19,643 |
| 22,420 |
| (2,777 | ) | 25,366 |
| (2,946 | ) |
Total retail sales | 834,293 |
| 888,036 |
| (53,743 | ) | 950,947 |
| (62,911 | ) |
Transportation sales | 20,322 |
| 18,666 |
| 1,656 |
| 17,069 |
| 1,597 |
|
Decoupling revenue | 52,114 |
| 51,981 |
| 133 |
| 29,116 |
| 22,865 |
|
Other decoupling revenue1 | (28,761 | ) | (26,038 | ) | (2,723 | ) | 2,208 |
| (28,246 | ) |
Other | 12,542 |
| 14,904 |
| (2,362 | ) | 13,520 |
| 1,384 |
|
Total natural gas operating revenues2 | 890,510 |
| 947,549 |
| (57,039 | ) | 1,012,860 |
| (65,311 | ) |
Minus purchased gas costs2 | (313,954 | ) | (403,310 | ) | 89,356 |
| (458,691 | ) | 55,381 |
|
Natural gas margin3 | $ | 576,556 |
| $ | 544,239 |
| $ | 32,317 |
| $ | 554,169 |
| $ | (9,930 | ) |
| | | | | |
Natural Gas Volumes | | | | | |
(Therms in Thousands) | | | | | |
Residential | 521,771 |
| 492,997 |
| 28,774 |
| 527,423 |
| (34,426 | ) |
Commercial firm | 233,586 |
| 230,507 |
| 3,079 |
| 242,095 |
| (11,588 | ) |
Industrial firm | 22,783 |
| 23,777 |
| (994 | ) | 26,481 |
| (2,704 | ) |
Interruptible | 49,533 |
| 43,931 |
| 5,602 |
| 46,113 |
| (2,182 | ) |
Total retail natural gas volumes, therms | 827,673 |
| 791,212 |
| 36,461 |
| 842,112 |
| (50,900 | ) |
Transportation volumes | 230,724 |
| 220,392 |
| 10,332 |
| 211,429 |
| 8,963 |
|
Total natural gas volumes | 1,058,397 |
| 1,011,604 |
| 46,793 |
| 1,053,541 |
| (41,937 | ) |
_______________
| |
1
| Includes decoupling cash collections, rate of return excess earnings, and decoupling 24-month revenue reserve. |
| |
2
| As reported on PSE’s Consolidated Statement of Income. |
| |
3
| Natural gas margin does not include any allocation for amortization/depreciation expense or natural gas operations and maintenance expense. |
* Includes decoupling cash collections, rate of return excess earnings, and decoupling 24-month revenue reserve.
20162018 compared to 20152019
Natural Gas Operating Revenue
Natural gas operating revenuedecreased $57.0 increased $24.6 million primarily due to lowerhigher retail sales of $9.3 million, increased transportation and other revenue of $11.9 million and increased other decoupling revenue of $7.3 million; partially offset by a decrease in decoupling revenue of $3.8 million. These items are discussed in the following details:
•Natural gas retail sales increased $9.3 million due to an increase in natural gas load of 4.8%, or $44.7 million in natural gas sales, which was partially offset by a decrease in rates of $35.4 million. Natural gas load increased primarily due to the year over year increase in usage for residential and commercial firm customers of 6.0% and 4.9%, respectively. These increases were driven by a 3.5% increase in heating degree days as well as a 1.3% increase in natural gas customers. See Management's Discussion and Analysis, "Regulation and Rates" included in Item 7 of this report for rate changes.
•Decoupling revenue decreased $3.8 million. This is primarily attributable to higher natural gas usage, as noted above in the retail sales revenue section. This resulted in actual natural gas revenues being closer to allowed natural gas revenues in the current year as compared to the prior year.
•Other decoupling revenue increased $7.3 million, primarily due to a $12.0 million decrease in current year amortization of $53.7prior year under collection, due to lower amortization rates. This was offset in part by activity related to earnings in excess of allowed ROR. In 2018, the prior year's estimate of earnings in excess of allowed ROR was trued up to match actual earnings in excess of allowed ROR by a favorable $3.4 million. In 2019, there was no prior year estimate of earnings in excess of allowed ROR to require true up. Also in 2018, earnings in excess of allowed ROR of $3.5 million was passed back to customers. In the current year, only $2.2 million was passed-back to customers.
•Transportation and other revenue increased $11.9 million primarily due to tax reform deferrals for revenue subject to refund of $15.4 million.
Natural Gas Energy Costs
Purchased natural gas expense decreased $5.7 million due to a decrease of $90.6 million related to the PGA rate reduction, partially offset by an increase of $41.0 million in gas sales due to higher therms sold. Commercial and residential customers contributed $32.3 and $18.6 million of the net change, respectively.
Natural Gas Energy Costs
Purchased natural gas expense decreased $89.4 million due to lower natural gas costs included in PGA rates which was partially offset by an increase in natural gas usage of 4.6%4.8%.
2015 compared to 2014
For additional information on prior years, please see discussion in Item 7, "Non-GAAP Financial Measures - Natural Gas Operating RevenueMargin" of Form 10-K for period ended December 31, 2018.
Natural gas operating revenue decreased $65.3 million due primarily to lower natural gas retail sales revenue of $62.9 million as a result of lower natural gas therm sales, PGA rate reduction and partially offset by decoupling revenue. These items are discussed in detail below.
Natural gas retail sales revenue decreased $62.9 million primarily due to a decrease of $57.5 million in natural gas sales due to lower therms sold and $5.4 million due to the PGA rate reduction.49
Decoupling revenue resulted in an increase of $22.9 million due to lower volumetric revenues compared to the allowed decoupled revenues per customer.
Other Decoupling revenue decreased $28.2 million due to return of over earnings sharing band of the decoupling mechanism of $10.5 million, 24-month exceeding the collection period for decoupling of $10.0 million and collection from customers of $7.8 million.
Natural Gas Energy Costs
Purchased natural gas expense decreased $55.4 million due to lower natural gas costs reflected in PGA rates and by a decrease in usage of 6.0%.
Other Operating Expenses and Other Income (Deductions)
The following tablechart displays the details of PSE's other operating expenses and other income (deductions) from periods 2016for the years ended December 31, 2018, to 2015 and periods 2015 to 2014:December 31, 2019:
|
| | | | | | | | | | | | | | | |
Puget Sound Energy | Year Ended December 31, | Dollar Change | Year Ended December 31, | Dollar Change |
(Dollars in Thousands) | 2016 | 2015 | 2014 |
Operating expenses: | |
| |
| |
| |
| |
|
Net unrealized (gain) loss on derivative instruments | $ | (83,795 | ) | $ | (12,688 | ) | $ | (71,107 | ) | $ | 85,636 |
| $ | (98,324 | ) |
Utility operations and maintenance | 568,492 |
| 530,720 |
| 37,772 |
| 550,146 |
| (19,426 | ) |
Non-utility expense and other | 37,859 |
| 26,618 |
| 11,241 |
| 23,729 |
| 2,889 |
|
Depreciation and amortization | 439,579 |
| 420,807 |
| 18,772 |
| 365,606 |
| 55,201 |
|
Conservation amortization | 107,784 |
| 110,866 |
| (3,082 | ) | 104,096 |
| 6,770 |
|
Taxes other than income taxes | 328,649 |
| 320,531 |
| 8,118 |
| 310,982 |
| 9,549 |
|
Other income (deductions): | | | | | |
Other income | 25,537 |
| 20,711 |
| 4,826 |
| 24,036 |
| (3,325 | ) |
Other expense | (10,923 | ) | (6,764 | ) | (4,159 | ) | (7,457 | ) | 693 |
|
Interest expense, net of AFUDC | (233,679 | ) | (239,996 | ) | 6,317 |
| (259,316 | ) | 19,320 |
|
Income tax expense | 175,347 |
| 125,900 |
| 49,447 |
| 89,342 |
| 36,558 |
|
20162018 compared to 20152019
Other Operating Expenses
•Net unrealized (gain) loss on derivative instruments increased $71.1 decreased $45.2 million to a gainnet loss of $83.8 million. The net gain in 2016 was comprised$3.6 million for the year ended December 31, 2019. One of a gain of $62.3 millionthe drivers for the change is related to the net settlements of electric and natural gas trades previously recorded as $36.4 million in gains and $15.4 million in losses, respectively. The other driver is related to the change in the weighted average forward prices for powerelectric and natural gas. Specifically, electric price decreased 16.7% resulting in a $2.6 million loss for electric. Natural gas derivative instrumentsunrealized losses of $21.6 million were due to a higher cost basis of forward trades due to high natural gas prices in late 2018 and early 2019 and a $21.5decrease in forward prices at December 31, 2019.
•Utility operations and maintenance expense decreased $6.0 million gain related to electricity derivative instruments. This compares to a gain of $22.0 million related to electricity derivative instruments and a loss of $9.3 million related to natural gas for power derivative instruments, respectively, during the prior year. The gain was primarily due to increasesa decrease in natural gasthe following: (i) bad debt expense of $5.4 million due to an improved collection process, (ii) underground cable maintenance expense of $2.5 million, (iii) leak surveys expense of $2.3 million due to reliability strategic initiatives, and wholesale electricity forward prices.
Utility operations and maintenance(iv) rent expense increased $37.8of $1.7 million primarily drivendue to facility consolidations; partially offset by (i)(v) an increase in hardware and software maintenance costs of $15.7$7.5 million of administrative and general expense, primarily due to an increase in outside services employedIT projects..
•Non-utility and other expense decreased $7.0 million primarily due to a decrease in biogas gas purchase expense of $7.4$5.6 million and a decrease in non-qualified pension plan costs of $1.9 million; partially offset by an increase in the long-term incentive plan accrual of electric maintenance expense of $3.2$1.4 million and an increase of administrative and general salary expense of $2.9 million; (ii) $10.7 million of natural gas operation expense primarily due to an increase in distribution operationlong-term incentive plan awards in 2019.
•Depreciation and maintenanceamortization expense decreased $25.2 million primarily driven by: (i) a decrease in amortization of PTC regulatory liability of $15.4 million in 2019 as compared to 2018, (ii) a decrease of $21.7 million in common amortization due the deferral treatment of IT amortization effective May 1, 2019, as submitted to the Washington Commission, (iii) a decrease of $11.0 million for mains and servicesamortization of $6.2the Microsoft transition fee set in rates by a Washington Commission order, (iv) a decrease in amortization driven by the deferral treatment of $12.7 million for meter assets effective April 1, 2019, as submitted to increase system reliability; (iii) $7.6the Washington Commission, (v) a decrease in conservation
amortization of $15.1 million of operations and maintenance expense at our generation plants and (iv) $5.4 million of electric distribution maintenance overhead line expense;due to lower rates in 2019 as compared to 2018; partially offset by (v) $4.6(vi) an increase in common amortization of $33.8 million in meter reading expense.
Depreciation and amortizationdriven by net additions of $88.3 million of software; (vii) electric depreciation expense increased $18.8$10.2 million primarily due to $16.5net asset additions to distribution of $212.5 million ofand (viii) an increase in natural gas depreciation expense of $7.3 million primarily due to net asset additions to distribution of $173.9 million of natural gas distribution assets, $148.5 million of electric distribution assets and $90.6 million of electric transmission assets.
$214.5 million.•Taxes other than income taxes increased $8.1 decreased $2.7 million primarily due to an increasedecreases in electric property taxes of $6.0 million from an increase in load, electric state excise taxes of $2.9 million and municipal taxes of $2.9$2.4 million due to increased revenue, partially offset by, as well as a decrease of $2.7 million in natural gas municipal taxes and $2.1 million in natural gas state excise taxes duerelated to decreased revenue.
the property tax tracker.
Other Income, Interest Expense and Income Tax Expense
Interest •Other income/expense decreased $6.3$10.1 million primarily due toas a result of an increase in other income of $7.9 million and a decrease in other expenses of $3.8$2.1 million. Primarily contributing to the increase was an increase of $6.6 million of PGA interest income. Additionally, there was an increase in interest on long-term debt and $1.7 million related toWashington Commission allowance for funds used during construction (AFUDC) debt.
of $3.9 million due to a $31.8 million increase in eligible construction work in progress in 2019 as compared to 2018.Income tax•Interest expense increased $49.4$11.3 million primarily driven by a higher pre-tax income and a decrease in PTCs generated.related to PSE's issuance of $450.0 million of senior notes at an interest rate of 3.25%. For additional information, see Note 13,7, "Long-Term Debt" to the consolidated financial statements included in Item 8 of this report.
•Income tax expense decreased $11.6 million primarily driven by $7.5 million attributable to a decrease in pre-tax income and $4.0 million to attributable to permanent and flow through items. For further details, see Note 14, "Income Taxes" to the consolidated financial statements included in Item 8 of this report.
2015 compared to 2014
OtherFor additional information on prior years, please see discussion in Item 7, "Other Operating Expenses
Net unrealized (gain) loss on derivative instruments increased $98.3 million to a gain of $12.7 million. The net gain in 2015 was comprised of a gain of $22.3 million related to electricity derivative instruments and a $9.3 million loss related to PSE's natural gas derivative instruments for power. This compares to a loss of $42.3 million related to PSE's natural gas for power derivative instruments and a loss of $43.3 million related to electricity derivative instruments, respectively, during the prior year. The gain was primarily due to decreases in natural gas and wholesale electricity forward prices.
Utility operations and maintenance expense decreased $19.4 million primarily driven by a decrease of $8.3 million in bad debts expense and $7.0 million in meter reading expenses.
Depreciation and amortization expense increased $55.2 million primarily due to $43.6 million of electric amortization expense from $46.9 million of regulatory credits related to the JPUD gain on sale returned to customers and a net increase of $3.1 million of Electron sale loss amortization, partially offset by a decrease of $5.7 million in PTC deferral. Natural gas depreciation also increased in the amount of $5.3 million, mainly due to new additions.
Conservation amortization increased $6.8 million primarily due to an increase of $6.2 million in conservation rider rate annual adjustments.
Taxes other than income taxes increased $9.5 million primarily due to an increase in property taxes of $5.7 million, state excise taxes of $4.3 million and municipal taxes of $2.4 million.
Other Income Interest Expense and Income Tax Expense(Deductions)" of Form 10-K for period ended December 31, 2018.
Other income decreased $3.3 million primarily due to PSE's share of the JPUD gain of $7.5 million in 2014, which was partially offset by an increase in AFUDC equity income of $2.3 million and an increase in interest and dividend income of $1.4 million.51
Interest expense decreased $19.3 million primarily due to a decrease of $12.0 million in regulatory liability interest expense, a reduction of $3.5 million of interest on long term debt, and an increase of $2.0 million of AFUDC debt.
Income tax expense increased $36.6 million primarily driven by a higher pre-tax income.
Puget Energy
Substantially all the operations of Puget Energy are conducted through its regulated subsidiary, PSE. Puget Energy’s net incomeresults of operation for the years ended December 31, 2016, 20152018, and 2014 wasDecember 31, 2019, were as follows:
|
| | | | | | | | | | | | | | | |
Benefit/(Expense) | Year Ended December 31, | Dollar Change | Year Ended December 31, | Dollar Change |
(Dollars in Thousands) | 2016 | 2015 | 2014 |
PSE net income | $ | 380,581 |
| $ | 304,189 |
| $ | 76,392 |
| $ | 236,614 |
| $ | 67,575 |
|
Other operating revenue and income | (316 | ) | (558 | ) | 242 |
| (2,949 | ) | 2,391 |
|
Net unrealized gain on derivative instruments | — |
| 544 |
| (544 | ) | 1,491 |
| (947 | ) |
Non-utility expense and other | 10,710 |
| 15,801 |
| (5,091 | ) | 10,620 |
| 5,181 |
|
Non-hedged interest rate swap expense | (1,062 | ) | (3,796 | ) | 2,734 |
| (3,915 | ) | 119 |
|
Interest expense 1 | (112,156 | ) | (109,125 | ) | (3,031 | ) | (102,382 | ) | (6,743 | ) |
Income tax benefit (expense) | 35,142 |
| 34,124 |
| 1,018 |
| 32,356 |
| 1,768 |
|
Puget Energy net income | $ | 312,899 |
| $ | 241,179 |
| $ | 71,720 |
| $ | 171,835 |
| $ | 69,344 |
|
_______________
| |
1
| Puget Energy’s interest expense includes elimination adjustments of intercompany interest on short-term debt. |
20162018 compared to 20152019
Summary Results of Operations
Puget Energy’s net income increaseddecreased by $71.7$24.9 million, which is primarily attributable to a decrease in PSE's net income increase of $76.4$24.2 million. The following are significant factors that impacted Puget Energy’s net income which are not included
For additional information on prior years, please see discussion in PSE’s discussion:
Non-utility expense and other decreased $5.1 million primarily due to legal outside services of $2.8 million, qualified pension expense of $1.2 million.
2015 compared to 2014
Item 7, "PE Summary Results of OperationsOperation" of Form 10-K for period ended December 31, 2018.
Puget Energy’s net income increased by $69.3 million, which is primarily attributable to PSE's net income increase of $67.6 million. The following are significant factors that impacted Puget Energy’s net income which are not included in PSE’s discussion:
Non-utility expense and other increased $5.2 million primarily due to higher pension expense related to the qualified pension plan.52
Interest expense increased $6.7 million primarily due to interest expense on the long-term senior secured notes issued in 2015.
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, 2016:2019:
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Payments Due Per Period | | | | | | | | |
(Dollars in Thousands) | Total | | 2020 | | 2021-2022 | | 2023-2024 | | Thereafter |
Contractual obligations: | | | | | | | | | |
Energy purchase obligations1 | $ | 6,355,478 | | | $ | 1,033,400 | | | $ | 1,574,582 | | | $ | 1,339,851 | | | $ | 2,407,645 | |
Long-term debt including interest2 | 8,874,206 | | | 229,109 | | | 453,394 | | | 453,394 | | | 7,738,309 | |
Short-term debt including interest | 176,000 | | | 176,000 | | | — | | | — | | | — | |
Service contract obligations | 615,117 | | | 72,445 | | | 149,517 | | | 155,189 | | | 237,966 | |
Non-cancelable operating leases3 | 269,398 | | | 22,500 | | | 44,383 | | | 42,105 | | | 160,410 | |
PSE finance leases3 | 1,528 | | | 643 | | | 787 | | | 98 | | | — | |
Pension and other benefits funding and payments | 82,967 | | | 41,659 | | | 8,316 | | | 10,495 | | | 22,497 | |
Total PSE contractual cash obligations | 16,374,694 | | | 1,575,756 | | | 2,230,979 | | | 2,001,132 | | | 10,566,827 | |
Long-term debt including interest2 | 2,428,548 | | | 547,880 | | | 1,422,008 | | | 53,300 | | | 405,360 | |
Total Puget Energy contractual cash obligations | $ | 18,803,242 | | | $ | 2,123,636 | | | $ | 3,652,987 | | | $ | 2,054,432 | | | $ | 10,972,187 | |
|
| | | | | | | | | | | | | | | |
| Payments Due Per Period |
(Dollars in Thousands) | Total | 2017 | 2018 - 2019 | 2020 - 2021 | Thereafter |
Contractual obligations: | | | | | |
Energy purchase obligations1 | $ | 6,147,014 |
| $ | 1,041,888 |
| $ | 1,532,971 |
| $ | 1,227,542 |
| $ | 2,344,613 |
|
Long-term debt including interest2 | 8,561,749 |
| 220,061 |
| 614,432 |
| 408,338 |
| 7,318,918 |
|
Short-term debt including interest | 245,775 |
| 245,775 |
| — |
| — |
| — |
|
Service contract obligations | 596,660 |
| 49,748 |
| 100,694 |
| 124,720 |
| 321,498 |
|
Non-cancelable operating leases3 | 187,161 |
| 22,212 |
| 37,912 |
| 24,644 |
| 102,393 |
|
PSE capital leases3 | 666 |
| 296 |
| 370 |
| — |
| — |
|
Pension and other benefits funding and payments | 71,401 |
| 20,236 |
| 10,944 |
| 6,178 |
| 34,043 |
|
Total PSE contractual cash obligations | 15,810,426 |
| 1,600,216 |
| 2,297,323 |
| 1,791,422 |
| 10,121,465 |
|
Long-term debt including interest2 | 2,330,495 |
| 99,242 |
| 210,805 |
| 1,107,765 |
| 912,683 |
|
Total Puget Energy contractual cash obligations | $ | 18,140,921 |
| $ | 1,699,458 |
| $ | 2,508,128 |
| $ | 2,899,187 |
| $ | 11,034,148 |
|
_______________
| |
1____________________
| Energy purchase contracts were entered into as part of PSE’s obligation to serve retail electric and natural gas customers’ energy requirements. As a result, costs are generally recovered either through base retail rates or adjustments to retail rates as part of the power and natural gas cost adjustment mechanisms. |
| |
2
| For individual long-term debt maturities, see Note 6, "Long-Term Debt," 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. |
| |
3
| For additional information, see Note 8, "Leases," to the consolidated financial statements included in Item 8 of this report. |
1.Energy purchase contracts were entered into as part of PSE’s obligation to serve retail electric and natural gas customers’ energy requirements. As a result, costs are generally recovered either through base retail rates or adjustments to retail rates as part of the power and natural gas cost adjustment mechanisms.
2.For individual long-term debt maturities, see Note 7, "Long-Term Debt," 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.
3.For additional information, see Note 9, "Leases" to the consolidated financial statements included in Item 8 of this report.
The following are PSE’s and Puget Energy’s aggregate availability under commercial commitments as of December 31, 2016:2019:
| | | Amount of Available Commitments Expiration Per Period | | Amount of Available Commitments Expiration Per Period | |
(Dollars in Thousands) | Total |
| 2017 |
| 2018 - 2019 |
| 2020 - 2021 |
| Thereafter |
| (Dollars in Thousands) | Total | | 2020 | | 2021-2022 | | 2022-2023 | | Thereafter |
Commercial commitments: | | | | Commercial commitments: | | | | | | | | | |
PSE working capital facility1 | $ | 650,000 |
| $ | — |
| $ | 650,000 |
| $ | — |
| $ | — |
| |
PSE energy hedging facility1 | 350,000 |
| — |
| 350,000 |
| — |
| — |
| |
PSE revolving credit facility1 | | PSE revolving credit facility1 | $800,000 | | | $— | | | $— | | | $800,000 | | | $— | |
Inter-company short-term debt2 | 30,000 |
| — |
| — |
| — |
| 30,000 |
| Inter-company short-term debt2 | 30,000 | | | — | | | — | | | — | | | 30,000 | |
Total PSE commercial commitments | 1,030,000 |
| — |
| 1,000,000 |
| — |
| 30,000 |
| Total PSE commercial commitments | 830,000 | | | — | | | — | | | 800,000 | | | 30,000 | |
Puget Energy revolving credit facility3 | 800,000 |
| — |
| 800,000 |
| — |
| — |
| Puget Energy revolving credit facility3 | 775,900 | | | — | | | — | | | 775,900 | | | — | |
Less: Inter-company short-term debt elimination2 | (30,000 | ) | — |
| — |
| — |
| (30,000 | ) | Less: Inter-company short-term debt elimination2 | (30,000) | | | — | | | — | | | — | | | (30,000) | |
Total Puget Energy commercial commitments | $ | 1,800,000 |
| $ | — |
| $ | 1,800,000 |
| $ | — |
| $ | — |
| Total Puget Energy commercial commitments | $1,575,900 | | | $— | | | $— | | | $1,575,900 | | | $— | |
_______________
| |
1
| As of December 31, 2016, PSE had two credit facilities which provide, in the aggregate, $1.0 billion of short-term liquidity needs, and which will mature in April 2019. These facilities consisted of a $650.0 million revolving liquidity facility to be used for general corporate purposes, including a backstop to the Company's commercial paper program, and a $350.0 million energy hedging facility. The $650.0 million liquidity facility includes a swingline feature allowing same day availability on borrowings up to $75.0 million. The credit facilities also have an accordion feature that, upon the banks' approval, would increase the total size of these facilities to $1.5 billion. As of December 31, 2016, no loans or letters of credit were outstanding under the PSE energy hedging facility, no loans or letters of credit were outstanding under the PSE liquidity facility and $245.8 million was outstanding under the commercial paper program. The credit agreements are syndicated among numerous lenders. Outside of the credit agreements, PSE has a $3.5 million letter of credit in support of a long-term transmission contract and a $1.0 million letter of credit in support of natural gas purchases in Canada. |
| |
2
| As of December 31, 2016, PSE had a revolving credit facility with Puget Energy in the form of a promissory note to borrow up to $30.0 million.
|
| |
3
| As of December 31, 2016, Puget Energy had a revolving senior secured credit facility totaling $800.0 million, which matures in April 2018. The revolving senior secured credit facility is syndicated among numerous lenders. The 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. As of December 31, 2016, there was $12.5 million drawn and outstanding under the Puget Energy credit facility.
|
1.As of December 31, 2019, PSE had a credit facility which provides $800.0 million of short-term liquidity needs and includes a backstop to the Company's commercial paper program. The credit facility matures in October 2023. The credit facility also includes a swingline feature allowing same day availability on borrowings up to $75.0 million and an expansion feature that, upon the banks' approval, would increase the total size of the facility to $1.4 billion. As of December 31, 2019, no loans or letters of credit were outstanding under the credit facility and $176.0 million was outstanding under the commercial paper program. The credit agreement is syndicated among numerous lenders. Outside of the credit agreement, PSE has a $2.8 million letter of credit in support of a long-term transmission contract and a $1.0 million letter of credit in support of natural gas purchases in Canada.
2.As of December 31, 2019, PSE had a revolving credit facility with Puget Energy in the form of a promissory note to borrow up to $30.0 million.
3.As of December 31, 2019, Puget Energy had a revolving senior secured credit facility totaling $800.0 million, which matures in October 2023. The revolving senior secured credit facility is syndicated among numerous lenders. The revolving senior secured credit facility also has an expansion feature that, upon the banks' approval, would increase the size of the facility to $1.3 billion. As of December 31, 2019, there was $24.1 million drawn and outstanding under the Puget Energy credit facility.
Off-Balance Sheet Arrangements
As of December 31, 2016,2019, the Company had no off-balance sheet arrangements that have or are reasonably likely to have a material effect on the Company's financial condition.
Utility Construction Program
PSE’s construction programs for generating facilities, the electric transmission system, the natural gas and electric distribution systems and the Tacoma LNG facility are designed to meet regulatory requirements and customer growth and to support reliable energy delivery. Construction expenditures, excluding equity AFUDC, totaled $681.1$919.3 million in 2016.2019. Presently planned utility construction expenditures, excluding equity AFUDC, are as follows:
| | | | | | | | | | | | | | | | | |
Capital Expenditure Projections | | | | | |
(Dollars in Millions) | 2020 | | 2021 | | 2022 |
Total energy delivery, technology and facilities expenditures | $965.5 | | | $1,031.1 | | | $1,023.7 | |
|
| | | | | | | | | |
Capital Expenditure Projections | | | |
(Dollars in Thousands) | 2017 |
| 2018 |
| 2019 |
|
Total energy delivery, technology and facilities expenditures | $ | 1,092,000 |
| $ | 972,000 |
| $ | 809,000 |
|
The program is subject to change based upon general business, economic and regulatory conditions. Utility construction expenditures and any new generation resource expenditures are typicallymay be funded from a combination of sources, which may include cash from operations, short-term debt, long-term debt and/or equity. PSE’s utility construction programplanned capital expenditures periodically can and domay result in a level of spending that will exceed its cash flow generated from operations. As a result, execution of PSE’s utility construction programstrategy is dependent in part on continued access to capital markets.
Capital Resources
Cash from Operations
| | | | | | | | | | | | | | | | | |
Puget Sound Energy | Year Ended December 31, | | | | |
(Dollars in Thousands) | 2019 | | 2018 | | Change |
Net income | $ | 292,924 | | | | $ | 317,162 | | | | $ | (24,238) | |
Non-cash items1 | 677,261 | | | | 670,632 | | | | 6,629 | |
Changes in cash flow resulting from working capital2 | (107,355) | | | | 80,541 | | | | (187,896) | |
Regulatory assets and liabilities | (79,173) | | | | (71,348) | | | | (7,825) | |
Purchased gas adjustment | (132,766) | | | — | | | (132,766) | |
Other non-current assets and liabilities3 | (26,967) | | | | (1,083) | | | | (25,884) | |
Net cash provided by operating activities | $ | 623,924 | | | | $ | 995,904 | | | | $ | (371,980) | |
2016_______________
1.Non-cash items include depreciation, amortization, deferred income taxes, net unrealized (gain) loss on derivative instruments, AFUDC-equity, production tax credits and miscellaneous non-cash items.
2.Changes in working capital include receivables, unbilled revenue, materials/supplies, fuel/gas inventory, income taxes, prepayments, purchased gas adjustments, accounts payable and accrued expenses.
3.Other non-current assets and liabilities include funding of pension liability.
Year Ended December 31, 2019, compared to 20152018
Puget Sound Energy
Cash generated from operations for the year ended December 31, 2016 increased2019, decreased by $80.1$372.0 million, including $76.4 million froma net income.income decrease of $24.2 million. The following are significant factors that impacted PSE's cash flows from operations:
The increase in cash•Cash flow adjustments resulting from accounts receivable and unbilled revenue was the resultnon-cash items increased $6.6 million primarily due to a $45.2 million change from a net unrealized gain on derivative instruments of $41.7 million to a net unrealized loss on derivative instruments of $3.6 million, as well as a decrease of $29.2 million from $66.5 million in 2015 to $37.4 million in 2016. The reduction in accounts receivable resulted from implementation of an improved collections strategy in 2016. Unbilled revenue primarily decreased due to an increase in load; allowing for billing of prior year accrued revenue.
The increase in cash flow from deferred income taxes andproduction tax credits monetization of $48.9$15.4 million, offset by decreases in depreciation and amortization of $10.1 million, conservation amortization of $15.1 million, amortization of TCJA related income tax expense over-collection of $19.7 million and deferred taxes of $10.5 million. For further discussion, see "Other Operating Expenses" in Item 7, Management's Discussion and Analysis and Note 14, "Income Taxes" in Item 8.
•Cash flows resulting from $125.9changes in working capital decreased $187.9 million in 2015 to $174.8 million in 2016 was primarily due to increased additionscash outflow in accounts payable by $233.8 million, which was mainly due to plantpayment of significant power and natural gas costs accrued as of December 31, 2018, that were paid in 2016.2019. In addition, cash outflows associated with taxes payable increased by $18.9 million. These increased cash outflows are partially offset by increased cash inflows as
results of decreased balance in short-term purchased gas adjustment receivables of $35.9 million and accrued expenses of $23.5 million.
•Cash flows resulting from regulatory assets and liabilities decreased $7.8 million primarily caused by an increase in the PCA mechanism due to actual power costs being above power baseline costs. For further details, see "Electric Margin" in Item 7, Management's Discussion and Analysis.
•Cash flow resulting from purchased gas adjustment (long-term) decreased $132.8 million caused by actual natural gas costs being above natural gas baseline rates in the PGA mechanism. For further details, see "Natural Gas Margin" in Item 7, Management's Discussion and Analysis.
•Cash flow resulting from changes in other non-current assets and liabilities decreased $25.9 million primarily due to an decrease in cash flow frompension liability offset with other changes in long-term assets and liabilities.
| | | | | | | | | | | | | | | | | |
Puget Energy | Year Ended December 31, | | | | |
(Dollars in Thousands) | 2019 | | 2018 | | Change |
Net income | $ | (82,216) | | | $ | (81,540) | | | $ | (676) | |
Non-cash items1 | (2,381) | | | (519) | | | (1,862) | |
Changes in cash flow resulting from working capital2 | (4,800) | | | 4,558 | | | (9,358) | |
Regulatory assets and liabilities | (60) | | | — | | | (60) | |
Other non-current assets and liabilities3 | (7,131) | | | (14,222) | | | 7,091 | |
Net cash provided by operating activities | $ | (96,588) | | | $ | (91,723) | | | $ | (4,865) | |
______________
1.Non-cash items include depreciation, amortization, deferred income taxes, net unrealized (gain) loss on derivative instruments, was the resultAFUDC-equity, production tax credits and other miscellaneous non-cash items.
2.Changes in working capital include receivables, unbilled revenue, materials/supplies, fuel/gas inventory, income taxes, prepayments, purchased gas adjustments, accounts payable and accrued expenses.
3.Other non-current assets and liabilities include funding of an increase in net unrealized gain of $71.1 million from $12.7 million in 2015pension liability.
Year Ended December 31, 2019, compared to $83.8 million in 2016. The net gain in 2016 was comprised of a gain of $62.3 million related to natural gas for power derivative instruments and a $21.5 million gain related to electricity derivative instruments. This compares to a gain of $22.0 million related to electricity derivative instruments and a loss of $9.3 million related to natural gas for power derivative instruments, respectively, during the prior year. The gain was primarily due to increases in natural gas and wholesale electricity forward prices.2018
Puget Energy
Cash generated from operations for the year ended December 31, 2016 increased2019, decreased by $80.1$4.9 million compared to the same period in 2015.2018. The net difference was primarily impacted by the increasedecrease from cash flow provided by the operating activities of PSE, as previously discussed. The remaining variance is explained below:
•Non-cash items decreased $1.9 million primarily due to changes in deferred taxes of $1.5 million.
•Changes in cash flow resulting from working capital decreased $9.4 million primarily due to amounts owed to PSE related to Puget LNG and that are eliminated at consolidated PE. •Other non-current assets and liabilities increased $7.1 million primarily due to change of the valuation of pension liability compared to the prior year.
Financing Program
The Company’s external financing requirements principally reflect the cash needs of its construction program, its schedule of maturing debt and certain operational needs. The Company anticipates refinancing the redemption of bonds or other long-term borrowings with its credit facilities and/or the issuance of new long-term debt. Access to funds depends upon factors such as Puget Energy’s and PSE’s credit ratings, prevailing interest rates and investor receptivity to investing in the utility industry, Puget Energy
and PSE. The Company believes it has sufficient liquidity through its credit facilities and access to capital markets to fund its needs over the next twelve months.
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, 2016 and 2015, PSE had $245.8 million and $159.0 million in short-term debt outstanding, respectively. Outside of the consolidation of PSE’s short-term debt,For information on Puget Energy had no short-termand PSE dividends, long-term debt outstanding in either year as borrowings under itsand credit facilities, are classified as long-term. PSE’s weighted-average interest rate on short-term debt, including borrowing rate, commitment feessee Note 5, “Dividend Payment Restrictions, Note 7, “Long-term Debt” and the amortization of debt issuance costs, during 2016Note 8, “Liquidity Facilities and 2015 was 3.21%, and 4.24%, respectively. As of December 31, 2016, PSE and Puget Energy had several committed credit facilities that are described below.
Puget Sound Energy
Credit Facilities
PSE has two unsecured revolving credit facilities which provide, in aggregate, $1.0 billion of short-term liquidity needs. These facilities consist of a $650.0 million revolving liquidity facility (which includes a liquidity letter of credit facility and a swingline facility) to be used for general corporate purposes, including a backstopOther Financing Arrangements” to the Company's commercial paper program and a $350.0 million revolving energy hedging facility (which includes an energy hedging letter of credit facility). The $650.0 million liquidity facility includes a swingline feature allowing same day availability on borrowings up to $75.0 million. The credit facilities also have an accordion feature which, upon the banks' approval, would increase the total size of these facilities to $1.5 billion. These unsecured revolving credit facilities matureconsolidated financial statements included in April 2019.
The credit agreements are syndicated among numerous lenders and contain usual and customary affirmative and negative covenants that, among other things, place limitations on PSE's ability to transact with affiliates, make asset dispositions and investments or permit liens to exist. The credit agreements also contain a financial covenant of total debt to total capitalization of 65% or less. PSE certifies its compliance with such covenants to participating banks each quarter. As of December 31, 2016, PSE was in compliance with all applicable covenant ratios.
The credit agreements provide PSE with the ability to borrow at different interest rate options. The credit agreements allow PSE to borrow at the bank's prime rate or to make floating rate advances at 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 dateItem 8 of this report, the spread to the LIBOR is 1.75% and the commitment fee is 0.275%.report.
As of December 31, 2016, no amounts were drawn and outstanding under PSE's $650.0 million liquidity facility. No letters of credit were outstanding under either facility, and $245.8 million was outstanding under the commercial paper program. Outside of the credit agreements, PSE had a $3.5 million letter of credit in support of a long-term transmission contract and a $1.0 million letter of credit in support of natural gas purchases in Canada.
Demand Promissory Note
In 2006, PSE entered into a revolving credit facility with Puget Energy, in the form of a credit agreement and a Demand Promissory Note (Note) pursuant to which PSE may borrow up to $30.0 million from Puget Energy subject to approval by Puget Energy. Under the terms of the Note, PSE pays interest on the outstanding borrowings based on the lower of the weighted-average interest rates of PSE’s outstanding commercial paper interest rate or PSE’s senior unsecured revolving credit facility. Absent such borrowings, interest is charged at one-month LIBOR plus 0.25%. On June 30, 2015, PSE repaid in full the $28.9 million outstanding balance under the Note.
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, 2016,2019, PSE could issue:
•Approximately $2.5$2.0 billion of additional first mortgage bonds under PSE’s electric mortgage indenture based on approximately $4.1$3.3 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, 2016;2019; and
•Approximately $485.0$739.0 million of additional first mortgage bonds under PSE’s natural gas mortgage indenture based on approximately $808.3 million$1.2 billion of natural gas bondable property available for issuance, subject to a combined natural gas
and electric interest coverage test of 1.75 times net earnings available for interest and a natural 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, 2016.
2019
At December 31, 2016,2019, PSE had approximately $6.9$7.8 billion in electric and natural gas rate base to support the interest coverage ratio limitation test for net earnings available for interest.
Shelf Registrations and Long-Term Debt Activity
On November 21, 2016, PSE filed a shelf registration statement under which it may issue, as of the date of this report, up to $800.0 million aggregate principal amount of senior notes secured by first mortgage bonds. The shelf registration will expire in November 2019.
On May 26, 2015, PSE issued $425.0 million of senior notes secured by first mortgage bonds. The notes mature in May 2045 and have an interest rate of 4.30%, which is payable semi-annually in May and November. Net proceeds of the issuance were used to fund the early retirement, including accrued interest and make-whole call premiums, of the Company's $150.0 million 5.197% senior notes maturing in October 2015 and the Company's $250.0 million 6.75% senior notes maturing in January 2016.
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, 2016, approximately $532.9 million of unrestricted retained earnings was available for the payment of dividends under the most restrictive mortgage indenture covenant.
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 1.0. The common equity ratio, calculated on a regulatory basis, was 47.9% at December 31, 2016 and the EBITDA to interest expense was 5.2 to 1.0 for the 12 months ended December 31, 2016.
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
Credit Facility
At December 31, 2016, Puget Energy maintained an $800.0 million revolving senior secured credit facility, which matures in April 2018. The Puget Energy revolving senior secured credit facility also has an accordion feature which, upon the banks' approval, would increase the size of the facility to $1.3 billion.
The revolving senior secured credit facility provides Puget Energy the ability to borrow at different interest rate options and includes variable fee levels. Interest rates may be based on the bank's prime rate or LIBOR, plus a spread based on Puget Energy's credit ratings. Puget Energy must pay a commitment fee on the unused portion of the facility. As of December 31, 2016, there was $12.5 million drawn and outstanding under the facility. As of the date of this report, the spread over LIBOR was 1.75% and the commitment fee was 0.275% as of the date of this report. Puget Energy entered into interest rate swap contracts to manage the interest rate risk associated with the credit facility or similar variable rate debt. For additional information, see Part II Item 7A, "Interest Rate Risk".
The revolving senior secured credit facility contains usual and customary affirmative and negative covenants. The agreement also contains a maximum leverage ratio financial covenant as defined in the agreement governing the senior secured credit facility. As of December 31, 2016, Puget Energy was in compliance with all applicable covenants.
Long-Term Debt Activity
In May 2015, Puget Energy issued $400.0 million of senior secured notes in a private placement. The notes mature in May 2025 and have an interest rate of 3.65%, which is payable semi-annually in May and November. Net proceeds of the issuance were used to repay outstanding Puget Energy indebtedness and to fund a special dividend to shareholders. In November 2015, Puget Energy exchanged $400.0 million of its 3.65% senior secured notes that were originally issued in the May 2015 private placement for registered notes of the same amount.
Dividend Payment Restrictions
Puget Energy’s ability to pay dividends is also limited by the merger order issued by the Washington Commission. Pursuant to the merger order, Puget Energy may not declare or make a distribution unless on such date Puget Energy’s ratio of consolidated EBITDA to consolidated interest expense for the four most recently ended fiscal quarters prior to such date is equal to or greater than 2 to 1.0. Puget Energy's EBITDA to interest expense was 3.5 to 1.0 for the 12 months ended December 31, 2016.
At December 31, 2016, the Company was in compliance with all applicable covenants, including those pertaining to the payment of dividends.
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. TheManagement believes 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 during the month less unbilled revenues recorded in the prior month. The "current" month unbilled usage is then priced at published rates for each schedule to estimate the unbilled revenues by customer.
Beginning July 1, 2013, certainCertain revenues from PSE's electric and natural gas operations are subject to a revenue decoupling mechanism under which PSE's actual energy delivery revenues related to electric transmission and distribution, natural gas operations and general administrative costs are compared with authorized revenues allowed under the mechanism. The mechanism mitigates volatility in revenue due to weather and gross margin erosion related to energy efficiency. Any differences are deferred to a regulatory asset for under recovery or a regulatory liability for over recovery. Revenues associated with power costs under the PCA mechanism and PGA rates are excluded from the decoupling mechanism.
As defined by Accounting Standards Codification (ASC) 980, “Regulated Operations” (ASC 980), the decoupling mechanism is an alternative revenue program that allows billings to be adjusted for the effects of weather abnormalities, conservation efforts or other various external factors. PSE adjusts these billings in the future in response to these effects to collect additional revenues provided under the decoupling mechanism. Once billing of additional revenues under the decoupling mechanism is permitted, the additional revenue can be recognized when the following criteria specified by ASC 980 are met: (i) the program is established by an order from the Washington Commission that allows for automatic adjustment of future rates, (ii) the amount of additional revenues for the period is objectively determinable and is probable of recovery and (iii) the additional revenues will be collected within 24 months following the end of the annual period in which they are recognized. PSE meets the criteria to recognize revenue under the decoupling mechanism. However, for GAAP purposes only, theThe Company will not record any decoupling revenue that is expected to take longer than 24 months to collect following the end of the annual period in which the revenues would have otherwise been recognized. Once determined to be collectible within 24 months, any previously non-recorded amounts will be recorded.
For further discussion regarding revenue recognition, see Note 3, "Revenue", to the consolidated financial statements included in Item 8 of this report.
Regulatory Accounting
As a regulated entity of the Washington Commission and FERC, PSE prepares its financial statements in accordance with the provisions of 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 FERC. Under the authority of these commissions, PSE has recorded certain regulatory assets and liabilities at December 31, 20162019, in the amount of $1,113.2$847.5 million and $653.3$1,676.6 million, respectively, and regulatory assets and liabilities at December 31, 20152018, of $971.5$788.2 million and $663.7$1,722.5 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 Item 1, "Business – RegulationManagement's Discussion and Analysis, "Regulation and Rates". included in Item 7 of this report. The increases and decreases in the cost of natural gas supply are reflected in customers'customer bills through the PGA mechanism. PSE expects to fully recoverrecover/refund these regulatory assetsbalances through its rates. However, both mechanisms are subject to regulatory review and approval by the Washington Commission on a periodic basis.
Goodwill
In 2009, Puget Holdings completed its merger with Puget Energy. Puget Energy remeasured the carrying amount of all its assets and liabilities to fair value, which resulted in recognition of approximately $1.7 billion in goodwill. ASC 350, “Intangibles - Goodwill and Other,” (ASC 350) requires that goodwill be tested for impairment at the reporting unit level on an annual basis and between annual tests if an event occurs or circumstances change that would more likely than not reduce the fair value of a reporting unit below its carrying value. These events or circumstances could include a significant change in the Company’s business or regulatory outlook, legal factors, a sale or disposition of a significant portion of a reporting unit or significant changes in the financial markets which could influence the Company’s access to capital and interest rates. Application of the goodwill impairment test requires judgment, including the identification of reporting units, assignment of assets and liabilities to reporting units, assignment of goodwill to reporting units and the determination of the fair value of the reporting units. Management has determined Puget Energy has only one reporting unit.
The goodwill recorded by Puget Energy represents the potential long-term return to the Company’s investors. Goodwill is tested for impairment annually using a two-step process. The first step compares the carrying amount of the reporting unit with its fair value, with a carrying value higher than fair value indicating potential impairment. If the first step test fails, the second step is performed. This would entail a full valuation of Puget Energy’s assets and liabilities and comparing the valuation to its carrying amounts, with the aggregate difference indicating the amount of impairment. Goodwill of a reporting unit is required to be tested for impairment on an interim basis if an event occurs or circumstances change that would cause the fair value of a reporting unit to fall below its carrying amount.
Puget Energy conducted its most recent annual impairment test as of October 1, 2016. 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: (i) estimation of future cash flows, which is dependent on internal forecasts, (ii) estimation of the long-term rate of growth for Puget Energy’s business, (iii) estimation of the useful life over which cash flows will occur, (iv) the selection of utility holding companies determined to be comparable to Puget Energy, and (v) 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 $5.2 billion at the October 1, 2016 measurement date for the annual test of goodwill impairment. The carrying value of Puget Energy’s equity was approximately $3.6 billion with the excess of the fair value over the carrying value representing 43.0% or $1.6 billion.
The income approach and the market approach valuations each resulted in Puget Energy equity values of $5.2 billion. 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 2.6% and 5.7%, respectively.
The following table summarizes the results of the income valuation method, using the long-term growth rate and weighted average cost of capital:
|
| | | | | | | | | | | | | | | | | | |
Equity Value Sensitivity Table | |
(Dollars in Billions) | |
Weighted-Average Cost of Capital Rate | Long-Term Growth Rate |
| 2.4 | % | 2.5 | % | 2.6 | % | 2.7 | % | 2.8 | % | 2.9 | % |
5.9% | $ | 3.5 |
| $ | 3.8 |
| $ | 4.1 |
| $ | 4.5 |
| $ | 4.8 |
| $ | 5.2 |
|
5.7 | 4.4 |
| 4.8 |
| 5.2 |
| 5.6 |
| 6.0 |
| 6.4 |
|
5.4 | 5.5 |
| 5.9 |
| 6.4 |
| 6.8 |
| 7.3 |
| 7.9 |
|
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 normal purchase normal sale (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.
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 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.
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. ItPSE 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, 2016, Puget Energy had interest rate swap contracts outstanding originally related to its long-term debt. For additional information, see Item 7A, "Quantitative and Qualitative Disclosures about Market Risk" and Note 9,10, "Accounting for Derivative Instruments and Hedging Activities" and Note 10,11, "Fair Value Measurements" to the consolidated financial statements included in Item 8 of this report.
Fair Value
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 this 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. For further discussion on market risk, see Item 7A, "Quantitative and Qualitative Disclosures about Market Risk".
Pension and Other Postretirement Benefits
PSE has a qualified defined benefit pension plan covering substantially all employees of PSE. PSE recognized qualified pension expense of $14.5 million, $22.9$12.6 million and $13.8$13.2 million for the years ended December 31, 2016, 20152019, and 2014,2018, respectively. Of these amounts, approximately 55.5%, 58.5%49.0% and 61.5%49.4% were included in utility operations and maintenance expense in 2016, 20152019 and 2014,2018, respectively, and the remaining amounts were capitalized. For the years ended December 31, 20162019, and 2015,2018, Puget Energy recognized incremental qualified pension income of $15.5$12.1 million and $16.7$13.1 million, respectively. In 2017,2020, it is expected that PSE and Puget Energy will recognize pension expense of $12.7$16.2 million and incremental qualified pension income of $14.0$11.1 million, respectively.
PSE has a Supplemental Executive Retirement Plan (SERP). PSE recognized pension and other postretirement benefit expenses of $4.8 million, $5.6$5.4 million and $4.9$5.1 million for the years ended December 31, 2016, 20152019, and 2014,2018, respectively. For the years ended December 31, 20162019, and 2015,2018, Puget Energy recognized incremental income of $0.4 million and $0.5 million, respectively. In 2017,2020, it is expected that PSE and Puget Energy will recognize pension expense of $4.8$5.4 million and incremental pension income of $0.5$0.3 million, respectively.
PSE also has other limited postretirement benefit plans. PSE recognized income of $0.5 million $0.2 million and $0.4$0.5 million for the years ended December 31, 2016, 20152019, and 2014,2018, respectively. For the years ended December 31, 20162019, and 2015,2018, Puget Energy recognized incremental expense of $0.2 million each year. In 2017,2020, it is expected that PSE and Puget Energy will recognize incomeexpense of $0.6$0.1 million and incremental expense of $0.2$0.1 million, respectively.
The Company’s pension and other postretirement benefits income or expense depend on several factors and assumptions, including plan design, timing and amount of cash contributions to the plan, earnings on plan assets, discount rate, expected long-term rate of return, mortality and health care cost trends. Changes in any of these factors or assumptions will affect the amount of income or expense that the Company records in its financial statements in future years and its projected benefit obligation. The Company has selected an expected return on plan assets based on a historical analysis of rates of return and the Company’s investment mix, market conditions, inflation and other factors. The Company’s accounting policy for calculating the market-related value of assets is based on a five-year smoothing of asset gains or 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. During 2016,2019, the Company made cash contributions of $24.0$18.0 million to the qualified defined benefitpension plan. Management is closely monitoring the funding status of its qualified pension plan given the recent volatility of the financial markets.plan. At December 31, 20162019, and 2015,2018, the Company’s qualified pension plan was $32.3$21.3 million underfunded and $44.2$37.4 million underfunded as measured under GAAP, or 95.0%97.3% and 93.1%94.5% funded, respectively. As of January 1, 2017,2020, the plan's estimated funded ratio, as calculated under guidelines from The Pension Protection Act of 2006 and considering temporary interest rate relief measures approved by Congress, was more than 100%. The aggregate expected contributions and payments by the Company to fund the pension plan, SERP and other postretirement plans for the year ending December 31, 20172020, are expected to be at least $18.0 million, $1.9$22.6 million and $0.3$0.1 million, respectively.
The discount rate used in accounting for pension and other benefit obligations decreased from 4.65%4.40% in 20152018 to 4.50%3.35% in 2016.2019. The discount rate used in accounting for pension and other benefit expense increased from 4.25%was 4.40% in 2015 to 4.65% in 2016.both 2018 and 2019. The rate of return on plan assets for qualified pension benefits decreased was 7.50% in 2016 remained unchanged at the 2015 level, or 7.75%.both 2018 and 2019. The rate of return on plan assets for other benefits was 7.0% in 2016both 2018 and 2015 was 6.75% and 7.00%, respectively.2019.
The following tables reflect the estimated sensitivity associated with a change in certain significant actuarial assumptions (each assumption change is presented mutually exclusive of other assumption changes):
| | Puget Energy and Puget Sound Energy | Change in Assumption | Impact on Projected Benefit Obligation Increase /(Decrease) | Puget Energy and Puget Sound Energy | Change in Assumption |
| Impact on Projected Benefit Obligation Increase /(Decrease) | |
(Dollars in Thousands) | | Pension Benefits | SERP | Other Benefits | (Dollars in Thousands) |
|
| Pension Benefits | | SERP |
| Other Benefits |
Increase in discount rate | 50 basis points | $ | (35,198 | ) | $ | (1,959 | ) | $ | (535 | ) | Increase in discount rate | 50 basis points |
| $ | (44,028) | |
| $ | (1,440) | |
| $ | (528) | |
Decrease in discount rate | 50 basis points | 38,965 |
| 2,091 |
| 584 |
| Decrease in discount rate | 50 basis points |
| 48,863 | | | 1,536 | |
| 576 | |
| | | | | | | | | | | | | | | | | | | | | | | |
Puget Energy | Change in Assumption |
| Impact on 2019 Pension Expense Increase /(Decrease) | | | | |
(Dollars in Thousands) |
|
| Pension Benefits | | SERP |
| Other Benefits |
Increase in discount rate | 50 basis points |
| $ | (3,170) | | | $ | (126) | |
| $ | 7 | |
Decrease in discount rate | 50 basis points |
| 3,479 | | | 137 | |
| (24) | |
Increase in return on plan assets | 50 basis points |
| $ | (3,498) | | | * |
| $ | (28) | |
Decrease in return on plan assets | 50 basis points |
| 3,498 | | | * |
| 28 | |
|
| | | | | | | | | | |
Puget Energy | Change in Assumption | Impact on 2016 Pension Expense Increase /(Decrease) |
(Dollars in Thousands) | | Pension Benefits | SERP | Other Benefits |
Increase in discount rate | 50 basis points | $ | 221 |
| $ | (139 | ) | $ | (51 | ) |
Decrease in discount rate | 50 basis points | 2,562 |
| 144 |
| 51 |
|
Increase in return on plan assets | 50 basis points | (3,008 | ) | * |
| (33 | ) |
Decrease in return on plan assets | 50 basis points | 3,008 |
| * |
| 33 |
|
| | Puget Sound Energy | Change in Assumption | Impact on 2016 Pension Expense Increase /(Decrease) | Puget Sound Energy | Change in Assumption |
| Impact on 2019 Pension Expense Increase /(Decrease) | |
(Dollars in Thousands) | | Pension Benefits | SERP | Other Benefits | (Dollars in Thousands) |
|
| Pension Benefits |
| SERP |
| Other Benefits |
Increase in discount rate | 50 basis points | $ | (2,732 | ) | $ | (139 | ) | $ | (50 | ) | Increase in discount rate | 50 basis points |
| $ | (3,717) | |
| $ | (128) | |
| $ | 8 | |
Decrease in discount rate | 50 basis points | 2,954 |
| 144 |
| 52 |
| Decrease in discount rate | 50 basis points |
| 3,478 | |
| 138 | |
| (7) | |
Increase in return on plan assets | 50 basis points | (3,020 | ) | * |
| (33 | ) | Increase in return on plan assets | 50 basis points |
| $ | (3,499) | |
| * |
| $ | (28) | |
Decrease in return on plan assets | 50 basis points | 3,020 |
| * |
| 33 |
| Decrease in return on plan assets | 50 basis points |
| 3,499 | |
| * |
| 28 | |
_______________
| |
*
| * Calculation not applicable. |
Recently Adopted Accounting Pronouncements
For the discussion of recently adopted accounting pronouncements, see Note 2,, "New Accounting Pronouncements" to the consolidated financial statements included in Item 8 of this report.
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's objective is to minimize 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. PSE hedges open natural gas and electric positions to reduce both the portfolio risk and the volatility risk in prices.
PSE's energy risk portfolio management function monitors and manages these risks using analytical models and tools including 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. Based on the analytics from all of its models and tools, PSE enters into forward physical electric and natural gas purchase and sale agreements, fixed-for-floating swap contracts, and commodity call/put options to manage its electric and natural gas portfolio risks. The forward physical electric and natural gas contracts are both fixed and variable (at index). To fix the price of wholesale electricity and natural gas, PSE may enter into fixed-for-floating swap (financial) contracts. PSE also utilizes natural gas call and put options as an additional hedging instrument to increase the hedging portfolio's flexibility to react to commodity price fluctuations.fluctuations while also allowing for participation in low price commodity markets.
The following table presents the fair value of the Company’s energy derivatives instruments, recorded on the balance sheets:
| | | | | | | | | | | | | | | | | | | | | | | |
Puget Energy and Puget Sound Energy | December 31, 2019 | | | | December 31, 2018 | | |
(Dollars in Thousands) | Assets | | Liabilities | | Assets | | Liabilities |
Electric portfolio: | | | | | | | |
Current | $ | 15,399 | | | $ | 9,273 | | | $ | 32,041 | | | $ | 22,804 | |
Long-term | 4,534 | | | 8,231 | | | 1,246 | | | 4,480 | |
Total Electric Portfolio | 19,933 | | | 17,504 | | | 33,287 | | | 27,284 | |
Natural gas portfolio: | | | | | | | | | | | |
Current | $ | 8,227 | | | $ | 4,155 | | | $ | 14,466 | | | $ | 23,857 | |
Long-term | 3,148 | | | 4,462 | | | 1,266 | | | 6,615 | |
Total Natural Gas Portfolio | 11,375 | | | 8,617 | | | 15,732 | | | 30,472 | |
Total derivatives | $ | 31,308 | | | $ | 26,121 | | | $ | 49,019 | | | $ | 57,756 | |
|
| | | | | | | | | | | | |
Puget Energy and Puget Sound Energy | December 31, 2016 | December 31, 2015 |
(Dollars in Thousands) | Assets | Liabilities | Assets | Liabilities |
Electric portfolio: | | | | |
Current | $ | 30,596 |
| $ | 30,997 |
| $ | 19,051 |
| $ | 81,453 |
|
Long-term | 5,864 |
| 10,332 |
| 4,392 |
| 30,653 |
|
Total electric derivatives | 36,460 |
| 41,329 |
| 23,443 |
| 112,106 |
|
Natural Gas portfolio: | |
| |
| |
| |
|
Current | 23,745 |
| 13,172 |
| 5,367 |
| 49,967 |
|
Long-term | 2,874 |
| 5,929 |
| 833 |
| 17,123 |
|
Total natural gas derivatives | 26,619 |
| 19,101 |
| 6,200 |
| 67,090 |
|
Total energy derivatives | $ | 63,079 |
| $ | 60,430 |
| $ | 29,643 |
| $ | 179,196 |
|
At December 31, 2016,2019, the Company had total assets of $63.1$31.3 million and total liabilities of $60.4$26.1 million related to derivative contracts used to hedge the supply and cost of electricity and natural gas to serve PSE customers. As the gains and losses in the electric portfolio are realized, they will be recorded as either purchased power costs or electric generation fuel costs under the PCA mechanism. Any fair value adjustments relating to the natural gas business have been deferred in accordance with ASC 980, due to the PGA mechanism, which passes the cost of natural gas supply to customers. As the gains and losses on the hedges are realized in future periods, they will be recorded as natural gas costs under the PGA mechanism.
A hypothetical 10.0% increase or decrease in market prices of natural gas and electricity would change the fair value of the Company’s derivative contracts by $20.6$30.1 million.
The change in fair value of the Company’s outstanding energy derivative instruments from December 31, 20152018, through December 31, 20162019, is summarized in the table below:
| | | | | |
Puget Energy and Puget Sound Energy | |
Energy Derivative Contracts Gain (Loss) | |
(Dollars in Thousands) | December 31, 2019 |
Fair value of contracts outstanding at December 31, 2018 | $ | (8,737) | |
Contracts realized or otherwise settled during 2019 | (67,161) | |
Change in fair value of derivatives | 81,084 | |
Fair value of contracts outstanding at December 31, 2019 | $ | 5,186 | |
|
| | | |
Puget Energy and Puget Sound Energy Energy Derivative Contracts Asset (Liability) | |
(Dollars in Thousands) | |
Fair value of contracts outstanding at December 31, 2015 | $ | (149,553 | ) |
Contracts realized or otherwise settled during 2016 | 113,284 |
|
Change in fair value of derivatives | 38,918 |
|
Fair value of contracts outstanding at December 31, 2016 | $ | 2,649 |
|
The fair value of the Company’s outstanding derivative instruments at December 31, 2016,2019, based on pricing source and the period during which the instrument will mature, is summarized below:
| | Puget Energy and Puget Sound Energy Source of Fair Value | | Puget Energy and Puget Sound Energy Source of Fair Value | Fair Value of Contracts by Settlement Year | |
Fair Value of Contracts by Settlement Year | |
(Dollars in Thousands) | 2017 | 2018-2019 | 2020-2021 | Thereafter | Total | (Dollars in Thousands) | 2020 | | | 2021-2022 | | 2023-2024 | | Thereafter | | Total |
Prices provided by external sources1 | $ | 5,381 |
| $ | (3,840 | ) | $ | (488 | ) | $ | — |
| $ | 1,053 |
| Prices provided by external sources1 | $ | 9,784 | | | $ | (564) | | | $ | (1,937) | | | $ | — | | | $ | 7,283 | |
Prices based on internal models and valuation methods | 4,791 |
| (1,674 | ) | (1,521 | ) | — |
| 1,596 |
| Prices based on internal models and valuation methods | 413 | | | (2,282) | | | (228) | | | — | | | (2,097) | |
Total fair value | $ | 10,172 |
| $ | (5,514 | ) | $ | (2,009 | ) | $ | — |
| $ | 2,649 |
| Total fair value | $ | 10,197 | | | $ | (2,846) | | | $ | (2,165) | | | $ | — | | | $ | 5,186 | |
_______________
| |
1
| Prices provided by external pricing service, which utilizes broker quotes and pricing models. |
1.Prices provided by external pricing service, which utilizes broker quotes and pricing models.
For further details regarding both the fair value of derivative instruments and the impacts such instruments have on current period earnings, see Note 9,10, "Accounting for Derivative Instruments and Hedging Activities" and Note 10,11, "Fair Value Measurements" to the consolidated financial statements included in Item 8 of this report.
Contingent Features and Counterparty Credit Risk
PSE is exposed to credit risk primarily through buying and selling electricity and natural gas to serve customers. Credit risk is the potential loss resulting from a counterparty’s non-performance under an agreement. PSE manages credit risk with policies and procedures for, among other things, counterparty analysis and measurement, monitoring and mitigation of exposure.
PSE has entered into commodity master arrangements with its counterparties to mitigate credit exposure to those counterparties. PSE generally enters into the following master arrangements: WSPP, Inc. (WSPP) agreements which standardize physical power contracts in the electric industry; International Swaps and Derivatives Association (ISDA) agreements which standardize financial natural gas and electric contracts; and North American Energy Standards Board (NAESB) agreements which standardize physical natural gas contracts. PSE believes that entering into such agreements reduces the credit risk exposure because such agreements provide for the netting and offsetting of monthly payments as well as right of set-off in the event of counterparty default. It is possible that volatility in energy commodity prices could cause PSE to have material credit risk exposures with one or more counterparties. If such counterparties fail to perform their obligations under one or more agreements, PSE could suffer a material financial loss. In order to mitigate concentrated credit risk with a subset of counterparties, PSE executed a futures and cleared swaps agreement in November 2016, with the intent to transact power futures contractstransacts on the Intercontinental Exchange (ICE) beginning in early 2017.for power futures contracts and ICE NGX for natural gas futures contracts.
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, 2016,2019, PSE held approximately $321.1$571.6 million in standby letters of credit or limited parental guarantees and had sixnine counterparties with unlimited parental guarantees, in support of various electric and natural gas transactions. PSEThe Company monitors counterparties that are experiencing financial problems, havefor significant swings in credit default swap rates, have credit rating changes by external rating agencies, ownership changes or have changes in ownership.financial distress. As of December 31, 2016,2019, approximately 80%27.4% of the Company's total energy portfolio exposure including NPNS transactions, werewas entered into with investment grade counterparties which, in the majority of cases, do not require collateral calls on the contracts. Counterparty credit risk may impact PSE's decisions on derivative accounting treatment.
Should a counterparty file for bankruptcy, which would be considered a default under master arrangements, PSE may terminate related contracts. Derivative accounting entries previously recorded would be reversed in the financial statements. PSE would compute any terminations receivable or payable, based on the terms of existing master agreements. The Company computes credit reserves at a master agreement level by counterparty. The Company considers external credit ratings and market factors, such as credit default swaps and bond spreads, in determination of reserves. The Company recognizes that external ratings may not always reflect how a market participant perceives a counterparty’s risk of default. The Company uses both default factors published by Standard & Poor’s and factors derived through analysis of market risk, which reflect the application of an industry standard recovery rate. The Company selects a default factor by counterparty at an aggregate master agreement level based on a weighted-average default tenor for that counterparty’s deals. The default tenor is determined by weighting the fair value and contract tenors for all deals by 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, 2016,2019, 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, 2016,2019, PSE had cash posted as collateral of $14.8 million for contracts executed on the ICE. Also, as of December 31, 2019, PSE has posted a $1.0 million letter of credit as a condition of transacting on a physical energy exchange and clearinghouse in Canada.the ICE NGX Exchange. PSE did not trigger any collateral requirements with any of its counterparties.
Interest Rate Risk
The Company believes its interest rate risk primarily relates to the use of short-term debt instruments, variable-rate leases and anticipated long-term debt financing needed to fund capital requirements. The Company manages its interest rate risk through the issuance of mostly fixed-rate debt of various maturities. The Company utilizes internal cash from operations, borrowings under its commercial paper program, and its credit facilities to meet short-term funding needs. Short-term obligations are commonly refinanced with fixed-rate bonds or notes when needed and when interest rates are considered favorable.
The following table presents the carrying value and fair value of Puget Energy and Puget Sound Energy's debt instruments:
| | | | | | | | | | | | | | | | | | | | | | | |
Financial Debt Instruments | December 31, 2019 | | | | December 31, 2018 | | |
(Dollars in Thousands) | Carrying Amount | | Fair Value | | Carrying Amount | | Fair Value |
Puget Energy | $ | 5,920,325 | | | $ | 7,412,416 | | | $ | 6,051,788 | | | $ | 6,984,939 | |
Puget Sound Energy | 4,336,142 | | | 5,571,818 | | | 4,274,157 | | | 4,953,908 | |
|
| | | | | | | | | | | | |
Financial Debt Instruments | December 31, 2016 | December 31, 2015 |
(Dollars in Thousands) | Carrying Amount | Fair Value | Carrying Amount1 | Fair Value |
Puget Energy | $ | 5,599,836 |
| $ | 6,805,791 |
| $ | 5,486,522 |
| $ | 6,679,008 |
|
Puget Sound Energy | $ | 3,993,061 |
| $ | 4,816,807 |
| $ | 3,903,366 |
| $ | 4,699,621 |
|
_______________
| |
1
| Due to an accounting principle change, the prior year balance sheet as of December 31, 2015 reflect "debt discount, issuance cost and other" in the carrying amount for PE and PSE which was applied retrospectively. |
For further details regarding Puget Energy and Puget Sound Energy debt instruments, see Note 6,7, "Long-Term Debt" and Note 10,11, "Fair Value Measurements" to the consolidated financial statements included in Item 8 of this report.
From time to time, PSE may enter into treasury locks or forward starting swap contracts to hedge interest rate exposure related to an anticipated debt issuance. The ending balance in OCI related to the forward starting swaps and previously settled treasury lock contracts at December 31, 20162019, was a net loss of $5.4 million after tax and accumulated amortization. This compares to an after-tax loss of $5.7 million in OCI as of December 31, 2015.2018. All financial hedge contracts of this type are reviewed by an officer, presented to the Board of Directors, or a committee of the Board, as applicable and are approved prior to execution. PSE had no treasury locks or forward starting swap contracts outstanding at December 31, 2016.2019.
The Company may also enter into swap instruments or other financial hedge instruments to manage the interest rate risk associated with these debts. As of December 31, 2016, Puget Energy2019, the Company had two interest rate swap contracts outstanding and PSE did not have anyno outstanding interest rate swap instruments. At December 31, 2016, the fair value of the interest rate swaps was a $0.1 million pre-tax loss, and matured in January 2017. The fair value considers the risk of Puget Energy’s non-performance by using its incremental borrowing rate on unsecured debt over the risk-free rate in the valuation estimate. Currently, all changes in market value are recorded in earnings.
The change in fair value of Puget Energy’s outstanding interest rate swaps from December 31, 2015 through December 31, 2016 is summarized in the table below:
|
| | | |
Puget Energy | |
Interest Rate Swap Contracts Asset (Liability) | |
(Dollars in Thousands) | |
Fair value of contracts outstanding at December 31, 2015 | $ | (5,050 | ) |
Contracts realized or otherwise settled during 2016 | 2,008 |
|
Change in fair value of derivatives | 2,901 |
|
Fair value of contracts outstanding at December 31, 2016 | $ | (141 | ) |
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
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REPORTS: | Page |
REPORTS: | |
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INDEX TO FINANCIAL STATEMENTS: |
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PUGET ENERGY: | |
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PUGET SOUND ENERGY: | |
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PUGET SOUND ENERGY: |
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Consolidated Balance Sheets - December 31, 2019, and 2018 | |
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NOTES to the Consolidated Financial Statements of Puget Energy and Puget Sound Energy: | |
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Note 1. | | |
Note 2. | | |
Note 3. | | |
Note 4. | | |
Note 4.5. | | |
Note 5.6. | | |
Note 6.7. | | |
Note 7.8. | | |
Note 8.9. | | |
Note 9.10. | | |
Note 10.11. | | |
Note 11.12. | | |
Note 12.13. | | |
Note 13.14. | | |
Note 14.15. | | |
Note 15.16. | | |
Note 16.17. | | |
Note 17.18. | | |
Note 18.19. | | |
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SCHEDULE: |
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- December 31, 2019, and 2018, and for the Years Ended December 31, 2019, 2018, and 2017 | |
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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.
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:
1.Our Board has adopted clear corporate governance guidelines.
2.With the exception of the President and Chief Executive Officer, the Board members are independent of management.
3.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.
4.The non-management members of our Board meet regularly without the presence of Puget Energy and Puget Sound Energy management.
5.The Charters of our Board committees clearly establish their respective roles and responsibilities.
6.The Company has adopted a Corporate Ethics and Compliance Code of Conduct 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.
7.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/ Mary E. Kipp |
| | | |
Kimberly J. Harris | | /s/ Daniel A. Doyle |
| Matthew R. Marcelia/s/ Stephen J. King |
Mary E. Kipp |
| Daniel A. Doyle |
| Stephen J. King |
President and Chief Executive Officer |
| Senior Vice President and Chief Financial Officer |
| Controller and Principal Accounting Officer |
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRMReport of Independent Registered Public Accounting Firm
To the Board of Directors and Shareholder of
Puget Energy, Inc.
Opinions on the Financial Statements and Internal Control over Financial Reporting
We have audited the consolidated financial statements, including the related notes and financial statement schedules, of Puget Energy, Inc. and its subsidiaries (the “Company”) as listed in the accompanying index (collectively referred to as the “consolidated financial statements”). We also have audited the Company's internal control over financial reporting as of December 31, 2019, based on criteria established in Internal Control - Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO).
In our opinion, the consolidated financial statements listed in the accompanying indexreferred to above present fairly, in all material respects, the financial position of Puget Energy, Inc. and its subsidiariesatthe Company as of December 31, 20162019 and December 31, 2015,2018, and the results of theirits operations and theirits cash flows for each of the three years in the period ended December 31, 20162019 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 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, 2016,2019, based on criteria established in Internal Control - Integrated Framework (2013) issued by the Committee of Sponsoring Organizations ofCOSO.
Change in Accounting Principle
As discussed in Note 2 to the Treadway Commission (COSO). consolidated financial statements, the Company changed the manner in which it accounts for leases in 2019.
Basis for Opinions
The Company's management is responsible for these consolidated 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 the accompanying Management’s Report on Internal Control over Financial Reporting appearing under Item 9A. Our responsibility is to express opinions on thesethe Company’s consolidated financial statements on the financial statement schedules, and on the Company's internal control over financial reporting based on our integrated audits. We are a public accounting firm registered with the Public Company Accounting Oversight Board (United States) (PCAOB) and are required to be independent with respect to the Company in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.
We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States).PCAOB. Those standards require that we plan and perform the audits to obtain reasonable assurance about whether the consolidated financial statements are free of material misstatement, whether due to error or fraud, and whether effective internal control over financial reporting was maintained in all material respects.
Our audits of the consolidated financial statements included performing procedures to assess the risks of material misstatement of the consolidated financial statements, whether due to error or fraud, and performing procedures that respond to those risks. Such procedures included examining, on a test basis, evidence supportingregarding the amounts and disclosures in the consolidated financial statements, assessingstatements. Our audits also included evaluating the accounting principles used and significant estimates made by management, andas well as evaluating the overall presentation of the consolidated financial statement presentation.statements. 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.
Definition and Limitations of Internal Control over Financial Reporting
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 2, 2017
February 21, 2020
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRMWe have served as the Company or its predecessor’s auditor since 1933.
Report of Independent Registered Public Accounting Firm
To the Board of Directors and Shareholder of
Puget Sound Energy, Inc.
Opinions on the Financial Statements and Internal Control over Financial Reporting.
We have audited the consolidated financial statements, including the related notes and financial statement schedule, of Puget Sound Energy, Inc. and its subsidiary (the “Company”) as listed in the accompanying index (collectively referred to as the “consolidated financial statements”). We also have audited the Company's internal control over financial reporting as of December 31, 2019, based on criteria established in Internal Control - Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO).
In our opinion, the consolidated financial statements listed in the accompanying indexreferred to above present fairly, in all material respects, the financial position of Puget Sound Energy Inc. and its subsidiaryatthe Company as of December 31, 20162019 and December 31, 2015,2018, and the results of theirits operations and theirits cash flows for each of the three years in the period ended December 31, 20162019 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, 2016,2019, based on criteria established in Internal Control - Integrated Framework (2013) issued by the Committee of Sponsoring Organizations ofCOSO.
Change in Accounting Principle
As discussed in Note 2 to the Treadway Commission (COSO). consolidated financial statements, the Company changed the manner in which it accounts for leases in 2019.
Basis for Opinions
The Company's management is responsible for these consolidated 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 the accompanying Management’s Report on Internal Control over Financial Reporting appearing under Item 9A. Our responsibility is to express opinions on thesethe Company’s consolidated financial statements on the financial statement schedule, and on the Company's internal control over financial reporting based on our integrated audits. We are a public accounting firm registered with the Public Company Accounting Oversight Board (United States) (PCAOB) and are required to be independent with respect to the Company in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.
We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States).PCAOB. Those standards require that we plan and perform the audits to obtain reasonable assurance about whether the consolidated financial statements are free of material misstatement, whether due to error or fraud, and whether effective internal control over financial reporting was maintained in all material respects.
Our audits of the consolidated financial statements included performing procedures to assess the risks of material misstatement of the consolidated financial statements, whether due to error or fraud, and performing procedures that respond to those risks. Such procedures included examining, on a test basis, evidence supportingregarding the amounts and disclosures in the consolidated financial statements, assessingstatements. Our audits also included evaluating the accounting principles used and significant estimates made by management, andas well as evaluating the overall presentation of the consolidated financial statement presentation.statements. 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.
Definition and Limitations of Internal Control over Financial Reporting
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 2, 2017
February 21, 2020
We have served as the Company or its predecessor’s auditor since 1933.
PUGET ENERGY, INC.
CONSOLIDATED STATEMENTS OF INCOME
(Dollars in Thousands)
| | | | | | | | | | | | | | | | | |
| Year Ended December 31, | | | | |
| 2019 | | 2018 | | 2017 |
Operating revenue: | | | | | | | | | |
Electric | $ | 2,497,041 | | | $ | 2,455,919 | | | $ | 2,420,663 | |
Natural gas | 875,371 | | | 850,748 | | | 997,759 | |
Other | 28,718 | | | 39,829 | | | 41,854 | |
Total operating revenue | 3,401,130 | | | 3,346,496 | | | 3,460,276 | |
Operating expenses: | | | | | | | | |
Energy costs: | | | | | | | | |
Purchased electricity | 652,560 | | | 638,775 | | | 590,030 | |
Electric generation fuel | 282,864 | | | 204,174 | | | 206,275 | |
Residential exchange | (79,187) | | | (77,454) | | | (75,933) | |
Purchased natural gas | 290,976 | | | 296,699 | | | 360,009 | |
Unrealized (gain) loss on derivative instruments, net | 3,574 | | | (41,662) | | | 30,790 | |
Utility operations and maintenance | 596,676 | | | 602,638 | | | 592,277 | |
Non-utility expense and other | 47,907 | | | 54,519 | | | 53,864 | |
Depreciation and amortization | 656,323 | | | 666,432 | | | 481,969 | |
Conservation amortization | 96,571 | | | 111,714 | | | 121,216 | |
Taxes other than income taxes | 333,858 | | | 336,603 | | | 360,673 | |
Total operating expenses | 2,882,122 | | | 2,792,438 | | | 2,721,170 | |
Operating income (loss) | 519,008 | | | 554,058 | | | 739,106 | |
Other income (deductions): | | | | | | | | |
Other income | 59,905 | | | 52,957 | | | 49,283 | |
Other expense | (9,053) | | | (11,201) | | | (14,076) | |
Interest charges: | | | | | | | | |
AFUDC | 14,559 | | | 13,695 | | | 10,826 | |
Interest expense | (356,638) | | | (343,795) | | | (354,802) | |
Income (loss) before income taxes | 227,781 | | | 265,714 | | | 430,337 | |
Income tax (benefit) expense | 17,073 | | | 30,092 | | | 255,143 | |
Net income (loss) | $ | 210,708 | | | $ | 235,622 | | | $ | 175,194 | |
|
| | | | | | | | | |
| Year Ended December 31, |
| 2016 | 2015 | 2014 |
Operating revenue: | | | |
Electric | $ | 2,238,492 |
| $ | 2,128,468 |
| $ | 2,083,797 |
|
Natural gas | 890,510 |
| 947,549 |
| 1,012,859 |
|
Other | 35,299 |
| 16,683 |
| 16,515 |
|
Total operating revenue | 3,164,301 |
| 3,092,700 |
| 3,113,171 |
|
Operating expenses: | |
| |
| |
|
Energy costs: | |
| |
| |
|
Purchased electricity | 531,596 |
| 499,522 |
| 514,087 |
|
Electric generation fuel | 215,331 |
| 249,907 |
| 263,493 |
|
Residential exchange | (69,824 | ) | (112,473 | ) | (129,036 | ) |
Purchased natural gas | 313,954 |
| 403,310 |
| 458,691 |
|
Unrealized (gain) loss on derivative instruments, net | (83,795 | ) | (13,233 | ) | 84,146 |
|
Utility operations and maintenance | 568,492 |
| 530,720 |
| 550,146 |
|
Non-utility expense and other | 27,151 |
| 10,818 |
| 13,109 |
|
Depreciation and amortization | 439,579 |
| 420,807 |
| 365,606 |
|
Conservation amortization | 107,784 |
| 110,866 |
| 104,096 |
|
Taxes other than income taxes | 328,649 |
| 320,531 |
| 310,982 |
|
Total operating expenses | 2,378,917 |
| 2,420,775 |
| 2,535,320 |
|
Operating income (loss) | 785,384 |
| 671,925 |
| 577,851 |
|
Other income (deductions): | |
| |
| |
|
Other income | 25,539 |
| 20,711 |
| 24,038 |
|
Other expense | (10,923 | ) | (6,764 | ) | (7,457 | ) |
Non-hedged interest rate swap expense | (1,062 | ) | (3,796 | ) | (3,915 | ) |
Interest charges: | |
| |
| |
|
AFUDC | 9,304 |
| 7,575 |
| 5,611 |
|
Interest expense | (355,139 | ) | (356,696 | ) | (367,308 | ) |
Income (loss) before income taxes | 453,103 |
| 332,955 |
| 228,820 |
|
Income tax (benefit) expense | 140,204 |
| 91,776 |
| 56,985 |
|
Net income (loss) | $ | 312,899 |
| $ | 241,179 |
| $ | 171,835 |
|
The accompanying notes are an integral part of the consolidated financial statements.
PUGET ENERGY, INC.
CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME
(Dollars in Thousands)
| | | | | | | | | | | | | | | | | |
| Year Ended December 31, | | | | |
| 2019 | | 2018 | | 2017 |
Net income (loss) | $ | 210,708 | | | $ | 235,622 | | | $ | 175,194 | |
Other comprehensive income (loss): | | | | | | | |
Net unrealized gain (loss) from pension and postretirement plans, net of tax of $(1,846) and $(12,677) and $5,078, respectively | (6,947) | | | (47,690) | | | 9,430 | |
| | | | | |
Reclassification of stranded taxes to retained earnings due to tax reform | — | | | (5,230) | | | — | |
Other comprehensive income (loss) | (6,947) | | | (52,920) | | | 9,430 | |
Comprehensive income (loss) | $ | 203,761 | | | $ | 182,702 | | | $ | 184,624 | |
|
| | | | | | | | | |
| Year Ended December 31, |
| 2016 | 2015 | 2014 |
Net income (loss) | $ | 312,899 |
| $ | 241,179 |
| $ | 171,835 |
|
Other comprehensive income (loss): | |
| |
| |
|
Net unrealized gain (loss) from pension and postretirement plans, net of tax of $(3,471), $5,087 and $(45,890), respectively | (6,446 | ) | 9,444 |
| (85,224 | ) |
Reclassification of net unrealized (gain) loss on energy derivative instruments, net of tax of $0, $179 and $200, respectively | — |
| 333 |
| 372 |
|
Reclassification of net unrealized (gain) loss on interest rate swaps, net of tax of $0, $0 and $50, respectively | — |
| — |
| 94 |
|
Other comprehensive income (loss) | (6,446 | ) | 9,777 |
| (84,758 | ) |
Comprehensive income (loss) | $ | 306,453 |
| $ | 250,956 |
| $ | 87,077 |
|
The accompanying notes are an integral part of the consolidated financial statements.
PUGET ENERGY, INC.
CONSOLIDATED BALANCE SHEETS
(Dollars in Thousands)
ASSETS
|
| | | | | | |
| December 31, |
| 2016 | 2015 |
Utility plant (at original cost, including construction work in progress of $420,278 and $408,795, respectively): | | |
Electric plant | $ | 7,673,772 |
| $ | 7,432,490 |
|
Natural gas plant | 3,051,586 |
| 2,850,290 |
|
Common plant | 594,994 |
| 508,750 |
|
Less: Accumulated depreciation and amortization | (2,161,796 | ) | (1,878,868 | ) |
Net utility plant | 9,158,556 |
| 8,912,662 |
|
Other property and investments: | |
| |
|
Goodwill | 1,656,513 |
| 1,656,513 |
|
Other property and investments | 106,418 |
| 86,731 |
|
Total other property and investments | 1,762,931 |
| 1,743,244 |
|
Current assets: | |
| |
|
Cash and cash equivalents | 28,878 |
| 42,494 |
|
Restricted cash | 12,418 |
| 7,949 |
|
Accounts receivable, net of allowance for doubtful accounts of $9,798 and $9,756, respectively | 329,375 |
| 324,391 |
|
Unbilled revenue | 234,053 |
| 217,274 |
|
Purchased gas adjustment receivable | 2,785 |
| — |
|
Materials and supplies, at average cost | 106,378 |
| 78,244 |
|
Fuel and natural gas inventory, at average cost | 58,181 |
| 58,658 |
|
Unrealized gain on derivative instruments | 54,341 |
| 24,418 |
|
Prepaid expense and other | 43,046 |
| 17,120 |
|
Power contract acquisition adjustment gain | 33,413 |
| 37,031 |
|
Total current assets | 902,868 |
| 807,579 |
|
Other long-term and regulatory assets: | |
| |
|
Regulatory asset for deferred income taxes | 72,038 |
| 73,231 |
|
Power cost adjustment mechanism | 4,531 |
| 4,749 |
|
Regulatory assets related to power contracts | 22,613 |
| 26,223 |
|
Other regulatory assets | 1,034,348 |
| 894,071 |
|
Unrealized gain on derivative instruments | 8,738 |
| 5,225 |
|
Power contract acquisition adjustment gain | 241,648 |
| 288,757 |
|
Other | 58,109 |
| 58,513 |
|
Total other long-term and regulatory assets | 1,442,025 |
| 1,350,769 |
|
Total assets | $ | 13,266,380 |
| $ | 12,814,254 |
|
The accompanying notes are an integral part of the consolidated financial statements.
PUGET ENERGY, INC.
CONSOLIDATED BALANCE SHEETS
(Dollars in Thousands)
CAPITALIZATION AND LIABILITIESASSETS
| | | | | | | | | | | | | | |
| | December 31, | | |
| | 2019 | | 2018 |
Utility plant (at original cost, including construction work in progress of $591,199 and $550,466, respectively): | | | | | | |
Electric plant | | $ | 8,811,889 | | | $ | 8,515,482 | |
Natural gas plant | | 3,916,040 | | | 3,598,732 | |
Common plant | | 1,096,649 | | | 1,027,023 | |
Less: Accumulated depreciation and amortization | | (3,236,240) | | | (2,832,321) | |
Net utility plant | | 10,588,338 | | | 10,308,916 | |
Other property and investments: | | | | |
Goodwill | | 1,656,513 | | | 1,656,513 | |
Other property and investments | | 286,975 | | | 244,444 | |
Total other property and investments | | 1,943,488 | | | 1,900,957 | |
Current assets: | | | | | | |
Cash and cash equivalents | | 45,259 | | | 37,521 | |
Restricted cash | | 20,887 | | | 18,041 | |
Accounts receivable, net of allowance for doubtful accounts of $8,294 and $8,408, respectively | | 316,352 | | | 338,782 | |
Unbilled revenue | | 224,657 | | | 205,285 | |
Purchased gas adjustment receivable | | — | | | 9,921 | |
Materials and supplies, at average cost | | 115,684 | | | 116,180 | |
Fuel and natural gas inventory, at average cost | | 52,083 | | | 53,351 | |
Unrealized gain on derivative instruments | | 23,626 | | | 46,507 | |
Prepaid expenses and other | | 27,504 | | | 25,674 | |
Power contract acquisition adjustment gain | | 9,067 | | | 6,114 | |
Total current assets | | 835,119 | | | 857,376 | |
Other long-term and regulatory assets: | | | | | | |
Power cost adjustment mechanism | | 41,745 | | | 4,735 | |
Purchased gas adjustment receivable | | 132,766 | | | — | |
Regulatory assets related to power contracts | | 14,146 | | | 16,693 | |
Other regulatory assets | | 673,021 | | | 773,552 | |
Unrealized gain on derivative instruments | | 7,682 | | | 2,512 | |
Power contract acquisition adjustment gain | | 147,530 | | | 156,597 | |
Operating lease right-of-use asset | | 183,048 | | | — | |
Other | | 92,980 | | | 77,523 | |
Total other long-term and regulatory assets | | 1,292,918 | | | 1,031,612 | |
Total assets | | $ | 14,659,863 | | | $ | 14,098,861 | |
|
| | | | | | |
| December 31, |
| 2016 | 2015 |
Capitalization: | | |
Common shareholder’s equity: | | |
Common stock $0.01 par value, 1,000 shares authorized, 200 shares outstanding | $ | — |
| $ | — |
|
Additional paid-in capital | 3,308,957 |
| 3,308,957 |
|
Retained earnings | 413,468 |
| 249,534 |
|
Accumulated other comprehensive income (loss), net of tax | (33,712 | ) | (27,266 | ) |
Total common shareholder’s equity | 3,688,713 |
| 3,531,225 |
|
Long-term debt: | |
| |
|
First mortgage bonds and senior notes | 3,362,000 |
| 3,364,412 |
|
Pollution control bonds | 161,860 |
| 161,860 |
|
Junior subordinated notes | 250,000 |
| 250,000 |
|
Long-term debt | 1,812,480 |
| 1,800,000 |
|
Debt discount, issuance costs and other | (234,679 | ) | (248,754 | ) |
Total long-term debt | 5,351,661 |
| 5,327,518 |
|
Total capitalization | 9,040,374 |
| 8,858,743 |
|
Current liabilities: | |
| |
|
Accounts payable | 317,043 |
| 259,353 |
|
Short-term debt | 245,763 |
| 159,004 |
|
Current maturities of long-term debt | 2,412 |
| — |
|
Purchased gas adjustment liability | — |
| 12,589 |
|
Accrued expenses: | |
| |
|
Taxes | 111,428 |
| 114,854 |
|
Salaries and wages | 49,749 |
| 38,457 |
|
Interest | 73,610 |
| 73,378 |
|
Unrealized loss on derivative instruments | 44,310 |
| 136,173 |
|
Power contract acquisition adjustment loss | 3,159 |
| 3,611 |
|
Other | 71,996 |
| 53,867 |
|
Total current liabilities | 919,470 |
| 851,286 |
|
Other Long-term and regulatory liabilities: | |
| |
|
Deferred income taxes | 1,570,931 |
| 1,435,955 |
|
Unrealized loss on derivative instruments | 16,261 |
| 48,073 |
|
Regulatory liabilities | 654,622 |
| 652,441 |
|
Regulatory liabilities related to power contracts | 275,061 |
| 325,788 |
|
Power contract acquisition adjustment loss | 19,454 |
| 22,613 |
|
Other deferred credits | 770,207 |
| 619,355 |
|
Total other long-term and regulatory liabilities | 3,306,536 |
| 3,104,225 |
|
Commitments and contingencies (Note 15) |
|
|
|
|
Total capitalization and liabilities | $ | 13,266,380 |
| $ | 12,814,254 |
|
The accompanying notes are an integral part of the consolidated financial statements.
PUGET ENERGY, INC.
CONSOLIDATED BALANCE SHEETS
(Dollars in Thousands)
CAPITALIZATION AND LIABILITIES
| | | | | | | | | | | | | | |
| | December 31, | | |
| | 2019 | | 2018 |
Capitalization: | | | | | | |
Common shareholder’s equity: | | | | | | |
Common stock $0.01 par value, 1,000 shares authorized, 200 shares outstanding | | $ | — | | | $ | — | |
Additional paid-in capital | | 3,308,957 | | | 3,308,957 | |
Retained earnings | | 775,491 | | | 629,003 | |
Accumulated other comprehensive income (loss), net of tax | | (84,149) | | | (77,202) | |
Total common shareholder’s equity | | 4,000,299 | | | 3,860,758 | |
Long-term debt: | | | | | | |
First mortgage bonds and senior notes | | 4,212,000 | | | 3,764,412 | |
Pollution control bonds | | 161,860 | | | 161,860 | |
| | | | |
Long-term debt | | 1,758,100 | | | 1,961,900 | |
Debt discount, issuance costs and other | | (211,635) | | | (215,681) | |
Total long-term debt | | 5,920,325 | | | 5,672,491 | |
Total capitalization | | 9,920,624 | | | 9,533,249 | |
Current liabilities: | | | | | | |
Accounts payable | | 325,913 | | | 480,069 | |
Short-term debt | | 176,000 | | | 379,297 | |
Current maturities of long-term debt | | 452,412 | | | — | |
| | | | |
Accrued expenses: | | | | | | |
Taxes | | 99,979 | | | 118,112 | |
Salaries and wages | | 50,091 | | | 50,785 | |
Interest | | 74,855 | | | 70,099 | |
Unrealized loss on derivative instruments | | 13,428 | | | 46,661 | |
Power contract acquisition adjustment loss | | 2,418 | | | 2,547 | |
Operating lease liabilities | | 15,862 | | | — | |
Other | | 107,809 | | | 79,312 | |
Total current liabilities | | 1,318,767 | | | 1,226,882 | |
Other Long-term and regulatory liabilities: | | | | | | |
Deferred income taxes | | 824,720 | | | 789,297 | |
Unrealized loss on derivative instruments | | 12,693 | | | 11,095 | |
Regulatory liabilities | | 730,879 | | | 747,203 | |
Regulatory liability for deferred income taxes | | 946,179 | | | 975,974 | |
Regulatory liabilities related to power contracts | | 156,597 | | | 162,711 | |
Power contract acquisition adjustment loss | | 11,728 | | | 14,146 | |
Operating lease liabilities | | 174,327 | | | — | |
Other deferred credits | | 563,349 | | | 638,304 | |
Total long-term and regulatory liabilities | | 3,420,472 | | | 3,338,730 | |
Commitments and contingencies (Note 16) | | | | | | |
Total capitalization and liabilities | | $ | 14,659,863 | | | $ | 14,098,861 | |
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)
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | | | | | | | | | | |
| Common Stock | | | | Additional | | | | Accumulated Other | | |
| Shares | | Amount | | Paid-in Capital | | Retained Earnings | | Comprehensive Income (Loss) | | Total Equity |
Balance at December 31, 2016 | 200 | | $ | — | | | $ | 3,308,957 | | | $ | 413,468 | | | $ | (33,712) | | | $ | 3,688,713 | |
Net income (loss) | — | | | — | | | — | | | 175,194 | | | — | | | 175,194 | |
Common stock dividend paid | — | | | — | | | — | | | (123,307) | | | — | | | (123,307) | |
Other comprehensive income (loss) | — | | | — | | | — | | | — | | | 9,430 | | | 9,430 | |
Balance at December 31, 2017 | 200 | | $ | — | | | $ | 3,308,957 | | | $ | 465,355 | | | $ | (24,282) | | | $ | 3,750,030 | |
Net income (loss) | — | | | — | | | — | | | 235,622 | | | — | | | 235,622 | |
Common stock dividend paid | — | | | — | | | — | | | (77,204) | | | — | | | (77,204) | |
Other comprehensive income (loss) | — | | | — | | | — | | | — | | | (52,920) | | | (52,920) | |
Cumulative effect of accounting change | — | | | — | | | — | | | 5,230 | | | — | | | 5,230 | |
Balance at December 31, 2018 | 200 | | $ | — | | | $ | 3,308,957 | | | $ | 629,003 | | | $ | (77,202) | | | $ | 3,860,758 | |
Net income (loss) | — | | | — | | | — | | | 210,708 | | | — | | | 210,708 | |
Common stock dividend paid | — | | | — | | | — | | | (64,220) | | | — | | | (64,220) | |
Other comprehensive income (loss) | — | | | — | | | — | | | — | | | (6,947) | | | (6,947) | |
| | | | | | | | | | | |
Balance at December 31, 2019 | 200 | | $ | — | | | $ | 3,308,957 | | | $ | 775,491 | | | $ | (84,149) | | | $ | 4,000,299 | |
|
| | | | | | | | | | | | | | | | | |
| Common Stock | Additional | | Accumulated Other | |
| Shares | Amount | Paid-in Capital | Retained Earnings | Comprehensive Income (Loss) | Total Equity |
Balance at December 31, 2013 | 200 |
| $ | — |
| $ | 3,308,957 |
| $ | 323,007 |
| $ | 47,715 |
| $ | 3,679,679 |
|
Net income (loss) | — |
| — |
| — |
| 171,835 |
| — |
| 171,835 |
|
Common stock dividend | — |
| — |
| — |
| (223,428 | ) | — |
| (223,428 | ) |
Other comprehensive income (loss) | — |
| — |
| — |
| — |
| (84,758 | ) | (84,758 | ) |
Balance at December 31, 2014 | 200 |
| $ | — |
| $ | 3,308,957 |
| $ | 271,414 |
| $ | (37,043 | ) | $ | 3,543,328 |
|
Net income (loss) | — |
| — |
| — |
| 241,179 |
| — |
| 241,179 |
|
Common stock dividend | — |
| — |
| — |
| (263,059 | ) | — |
| (263,059 | ) |
Other comprehensive income (loss) | — |
| — |
| — |
| — |
| 9,777 |
| 9,777 |
|
Balance at December 31, 2015 | 200 |
| $ | — |
| $ | 3,308,957 |
| $ | 249,534 |
| $ | (27,266 | ) | $ | 3,531,225 |
|
Net income (loss) | — |
| — |
| — |
| 312,899 |
| — |
| 312,899 |
|
Common stock dividend | — |
| — |
| — |
| (148,965 | ) | — |
| (148,965 | ) |
Other comprehensive income (loss) | — |
| — |
| — |
| — |
| (6,446 | ) | (6,446 | ) |
Balance at December 31, 2016 | 200 |
| $ | — |
| $ | 3,308,957 |
| $ | 413,468 |
| $ | (33,712 | ) | $ | 3,688,713 |
|
The accompanying notes are an integral part of the consolidated financial statements.
PUGET ENERGY, INC.
CONSOLIDATED STATEMENTS OF CASH FLOWS
| | | | | | | | | | Year Ended December 31, | |
| Year Ended December 31, | | 2019 | | 2018 | | 2017 |
| 2016 | 2015 | 2014 | |
Operating activities: | | |
Net income (loss) | $ | 312,899 |
| $ | 241,179 |
| $ | 171,835 |
| |
Operating Activities: | | Operating Activities: | | | | | | | | |
Net Income (Loss) | | Net Income (Loss) | $ | 210,708 | | | $ | 235,622 | | | $ | 175,194 | |
Adjustments to reconcile net income (loss) to net cash provided by operating activities: | |
| |
| |
| Adjustments to reconcile net income (loss) to net cash provided by operating activities: | | | | | | | | |
Depreciation and amortization | 439,579 |
| 420,807 |
| 365,606 |
| Depreciation and amortization | 656,323 | | | 666,432 | | | 481,969 | |
Conservation amortization | 107,784 |
| 110,866 |
| 104,096 |
| Conservation amortization | 96,571 | | | 111,714 | | | 121,216 | |
Deferred income taxes and tax credits, net | 139,640 |
| 91,978 |
| 56,984 |
| Deferred income taxes and tax credits, net | 7,475 | | | 19,457 | | | 254,524 | |
Net unrealized (gain) loss on derivative instruments | (88,704 | ) | (17,255 | ) | 80,139 |
| Net unrealized (gain) loss on derivative instruments | 3,574 | | | (41,662) | | | 30,650 | |
Derivative contracts classified as financing activities due to merger | — |
| 8,045 |
| 16,349 |
| |
AFUDC - equity | (12,576 | ) | (9,325 | ) | (7,002 | ) | AFUDC - equity | (15,802) | | | (17,191) | | | (15,027) | |
Production tax credit | | Production tax credit | (68,622) | | | (83,976) | | | (53,331) | |
Other non-cash | | Other non-cash | (4,639) | | | 15,339 | | | 17,568 | |
Funding of pension liability | (24,000 | ) | (18,000 | ) | (18,000 | ) | Funding of pension liability | (18,000) | | | (18,000) | | | (18,000) | |
Regulatory assets and liabilities | (150,855 | ) | (153,877 | ) | (228,334 | ) | Regulatory assets and liabilities | (79,233) | | | (71,348) | | | (88,875) | |
Other long-term assets and liabilities | 30,459 |
| 35,270 |
| 19,691 |
| |
Purchased gas adjustment | | Purchased gas adjustment | (132,766) | | | | — | | | | — | |
Other long term assets and liabilities | | Other long term assets and liabilities | (16,098) | | | 2,695 | | | (27,411) | |
Change in certain current assets and liabilities: | |
| |
| |
| Change in certain current assets and liabilities: | | | | | | | | |
Accounts receivable and unbilled revenue | (21,763 | ) | (66,703 | ) | 153,434 |
| Accounts receivable and unbilled revenue | 3,058 | | | 17,659 | | | 132 | |
Materials and supplies | (28,134 | ) | 4,945 |
| 4,951 |
| Materials and supplies | (6,018) | | | (9,177) | | | (625) | |
Fuel and natural gas inventory | 473 |
| 9,332 |
| (2,742 | ) | Fuel and natural gas inventory | 1,268 | | | (3,443) | | | 8,266 | |
Purchased gas adjustment | | Purchased gas adjustment | 9,921 | | | (25,972) | | | 18,836 | |
Prepayments and other | (25,927 | ) | 4,086 |
| (2,140 | ) | Prepayments and other | (1,103) | | | (3,679) | | | 21,050 | |
Purchased gas adjustment | (15,374 | ) | 33,662 |
| (27,011 | ) | |
Accounts payable | 32,465 |
| (48,037 | ) | 9,098 |
| Accounts payable | (116,311) | | | 117,270 | | | 26,396 | |
Taxes payable | (3,426 | ) | 7,072 |
| (1,777 | ) | Taxes payable | (18,133) | | | 164 | | | 6,520 | |
Other | 36,750 |
| (5,323 | ) | 6,605 |
| Other | 15,163 | | | (7,723) | | | 13,079 | |
Net cash provided by (used in) operating activities | 729,290 |
| 648,722 |
| 701,782 |
| Net cash provided by (used in) operating activities | 527,336 | | | 904,181 | | | 972,131 | |
Investing activities: | |
| |
| |
| Investing activities: | | | | | | | | |
Construction expenditures - excluding equity AFUDC | (706,444 | ) | (587,225 | ) | (493,130 | ) | Construction expenditures - excluding equity AFUDC | (959,387) | | | (1,072,670) | | | (1,040,135) | |
Treasury grants received | — |
| — |
| 107,876 |
| |
Proceeds from disposition of assets | — |
| — |
| 20,296 |
| |
Restricted cash | (4,469 | ) | 24,914 |
| (25,692 | ) | |
Other | (1,921 | ) | 754 |
| (4,512 | ) | Other | 6,908 | | | 2,097 | | | (195) | |
Net cash provided by (used in) investing activities | (712,834 | ) | (561,557 | ) | (395,162 | ) | Net cash provided by (used in) investing activities | (952,479) | | | (1,070,573) | | | (1,040,330) | |
Financing activities: | |
| |
| |
| |
Financing Activities: | | Financing Activities: | | | | | | | | |
Change in short-term debt, net | 86,759 |
| 74,004 |
| (77,000 | ) | Change in short-term debt, net | (203,297) | | | 49,834 | | | 83,700 | |
Dividends paid | (148,965 | ) | (263,059 | ) | (223,428 | ) | Dividends paid | (64,220) | | | (77,204) | | | (123,307) | |
| Proceeds from long-term debt and bonds issued | 12,481 |
| 825,000 |
| 299,000 |
| Proceeds from long-term debt and bonds issued | 689,351 | | | 804,050 | | | 90,120 | |
Redemption of bonds and notes | — |
| (711,000 | ) | (299,000 | ) | Redemption of bonds and notes | — | | | (600,000) | | | — | |
Derivative contracts classified as financing activities due to merger | — |
| (8,045 | ) | (16,349 | ) | |
Other | 19,653 |
| 902 |
| 3,382 |
| Other | 13,893 | | | 8,513 | | | 13,151 | |
Net cash provided by (used in) financing activities | (30,072 | ) | (82,198 | ) | (313,395 | ) | Net cash provided by (used in) financing activities | 435,727 | | | 185,193 | | | 63,664 | |
Net increase (decrease) in cash and cash equivalents | (13,616 | ) | 4,967 |
| (6,775 | ) | |
Cash and cash equivalents at beginning of period | 42,494 |
| 37,527 |
| 44,302 |
| |
Cash and cash equivalents at end of period | $ | 28,878 |
| $ | 42,494 |
| $ | 37,527 |
| |
Net increase (decrease) in cash, cash equivalents, and restricted cash | | Net increase (decrease) in cash, cash equivalents, and restricted cash | 10,584 | | | 18,801 | | | (4,535) | |
Cash, cash equivalents, and restricted cash at beginning of period | | Cash, cash equivalents, and restricted cash at beginning of period | 55,562 | | | 36,761 | | | 41,296 | |
Cash, cash equivalents, and restricted cash at end of period | | Cash, cash equivalents, and restricted cash at end of period | 66,146 | | | 55,562 | | | 36,761 | |
Supplemental cash flow information: | |
| |
| |
| Supplemental cash flow information: | | | | | | | | |
Cash payments for interest (net of capitalized interest) | $ | 329,603 |
| $ | 339,866 |
| $ | 349,402 |
| Cash payments for interest (net of capitalized interest) | $ | 328,703 | | | $ | 322,476 | | | $ | 326,798 | |
Cash payments (refunds) for income taxes | — |
| 2 |
| — |
| Cash payments (refunds) for income taxes | 10,616 | | | 8,303 | | | 1,649 | |
| Non-cash financing and investing activities: | | Non-cash financing and investing activities: | | | | | | | | |
Accounts payable for capital expenditures eliminated from cash flows | $ | 76,813 |
| $ | 51,588 |
| $ | 51,776 |
| |
Accounts payable for capital expenditures eliminated from cash flow | | Accounts payable for capital expenditures eliminated from cash flow | $ | 58,329 | | | $ | 97,673 | | | $ | 92,959 | |
Reclassification of Colstrip from utility plant to a regulatory asset | 176,804 |
| — |
| — |
| Reclassification of Colstrip from utility plant to a regulatory asset | 4,163 | | | (3,086) | | | (49,177) | |
Reclassification of hydro treasury grants to a regulatory liability | | Reclassification of hydro treasury grants to a regulatory liability | $ | — | | | $ | — | | | $ | 95,935 | |
The accompanying notes are an integral part of the consolidated financial statements.
PUGET SOUND ENERGY, INC.
CONSOLIDATED STATEMENTS OF INCOME
(Dollars in Thousands)
| | | | | | | | | | | | | | | | | |
| Year Ended December 31, | | | | |
| 2019 | | 2018 | | 2017 |
Operating revenue: | | | | | | | | | |
Electric | $ | 2,497,041 | | | $ | 2,455,919 | | | $ | 2,420,663 | |
Natural gas | 875,371 | | | 850,748 | | | 997,759 | |
Other | 28,718 | | | 39,829 | | | 41,854 | |
Total operating revenue | 3,401,130 | | | 3,346,496 | | | 3,460,276 | |
Operating expenses: | | | | | | | | |
Energy costs: | | | | | | | | |
Purchased electricity | 652,560 | | | 638,775 | | | 590,030 | |
Electric generation fuel | 282,864 | | | 204,174 | | | 206,275 | |
Residential exchange | (79,187) | | | (77,454) | | | (75,933) | |
Purchased natural gas | 290,976 | | | 296,699 | | | 360,009 | |
Unrealized (gain) loss on derivative instruments, net | 3,574 | | | (41,662) | | | 30,790 | |
Utility operations and maintenance | 596,676 | | | 602,638 | | | 592,277 | |
Non-utility expense and other | 44,403 | | | 51,549 | | | 52,389 | |
Depreciation and amortization | 656,220 | | | 666,324 | | | 481,955 | |
Conservation amortization | 96,571 | | | 111,714 | | | 121,216 | |
Taxes other than income taxes | 333,858 | | | 336,603 | | | 360,673 | |
Total operating expenses | 2,878,515 | | | 2,789,360 | | | 2,719,681 | |
Operating income (loss) | 522,615 | | | 557,136 | | | 740,595 | |
Other income (deductions): | | | | | | | | |
Other income | 47,766 | | | 39,847 | | | 34,867 | |
Other expense | (9,053) | | | (11,201) | | | (14,104) | |
| | | | | |
Interest charges: | | | | | | | | |
AFUDC | 14,559 | | | 13,695 | | | 10,826 | |
Interest expense | (243,815) | | | (231,615) | | | (240,144) | |
Income (loss) before income taxes | 332,072 | | | 367,862 | | | 532,040 | |
Income tax (benefit) expense | 39,148 | | | 50,700 | | | 211,986 | |
Net income (loss) | $ | 292,924 | | | $ | 317,162 | | | $ | 320,054 | |
| | | | | |
|
| | | | | | | | | |
| Year Ended December 31, |
| 2016 | 2015 | 2014 |
Operating revenue: | | | |
Electric | $ | 2,238,492 |
| $ | 2,128,468 |
| $ | 2,083,797 |
|
Natural gas | 890,510 |
| 947,549 |
| 1,012,859 |
|
Other | 35,616 |
| 17,241 |
| 19,467 |
|
Total operating revenue | 3,164,618 |
| 3,093,258 |
| 3,116,123 |
|
Operating expenses: | |
| |
| |
|
Energy costs: | |
| |
| |
|
Purchased electricity | 531,596 |
| 499,522 |
| 514,087 |
|
Electric generation fuel | 215,331 |
| 249,907 |
| 263,493 |
|
Residential exchange | (69,824 | ) | (112,473 | ) | (129,036 | ) |
Purchased natural gas | 313,954 |
| 403,310 |
| 458,691 |
|
Unrealized (gain) loss on derivative instruments, net | (83,795 | ) | (12,688 | ) | 85,636 |
|
Utility operations and maintenance | 568,492 |
| 530,720 |
| 550,146 |
|
Non-utility expense and other | 37,859 |
| 26,618 |
| 23,729 |
|
Depreciation and amortization | 439,579 |
| 420,807 |
| 365,606 |
|
Conservation amortization | 107,784 |
| 110,866 |
| 104,096 |
|
Taxes other than income taxes | 328,649 |
| 320,531 |
| 310,982 |
|
Total operating expenses | 2,389,625 |
| 2,437,120 |
| 2,547,430 |
|
Operating income (loss) | 774,993 |
| 656,138 |
| 568,693 |
|
Other income (deductions): | |
| |
| |
|
Other income | 25,537 |
| 20,711 |
| 24,036 |
|
Other expense | (10,923 | ) | (6,764 | ) | (7,457 | ) |
Interest charges: | |
| |
| |
|
AFUDC | 9,304 |
| 7,575 |
| 5,611 |
|
Interest expense | (242,983 | ) | (247,571 | ) | (264,927 | ) |
Income (loss) before income taxes | 555,928 |
| 430,089 |
| 325,956 |
|
Income tax (benefit) expense | 175,347 |
| 125,900 |
| 89,342 |
|
Net income (loss) | $ | 380,581 |
| $ | 304,189 |
| $ | 236,614 |
|
The accompanying notes are an integral part of the consolidated financial statements.
PUGET SOUND ENERGY, INC.
CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME
(Dollars in Thousands)
| | | | | | | | | | | | | | | | | |
| Year Ended December 31, | | | | |
| 2019 | | 2018 | | 2017 |
Net income (loss) | $ | 292,924 | | | $ | 317,162 | | | $ | 320,054 | |
Other comprehensive income (loss): | | | | | | | | |
Net unrealized gain (loss) from pension and postretirement plans, net of tax of $539, $(9,844) and $9,848, respectively | 2,022 | | | (37,030) | | | 18,288 | |
Amortization of treasury interest rate swaps to earnings, net of tax of $102, $102 and $171, respectively | 385 | | | 385 | | | 317 | |
Reclassification of stranded taxes to retained earnings due to tax reform | — | | | (27,333) | | | — | |
Other comprehensive income (loss) | 2,407 | | | (63,978) | | | 18,605 | |
Comprehensive income (loss) | $ | 295,331 | | | $ | 253,184 | | | $ | 338,659 | |
|
| | | | | | | | | |
| Year Ended December 31, |
| 2016 | 2015 | 2014 |
Net income (loss) | $ | 380,581 |
| $ | 304,189 |
| $ | 236,614 |
|
Other comprehensive income (loss): | |
| |
| |
|
Net unrealized gain (loss) from pension and postretirement plans, net of tax of $2,004, $10,987 and $(41,395), respectively | 3,722 |
| 20,404 |
| (76,876 | ) |
Reclassification of net unrealized (gain) loss on energy derivative instruments, net of tax of $0, $369 and $722, respectively | — |
| 686 |
| 1,341 |
|
Amortization of treasury interest rate swaps to earnings, net of tax of $171, $171 and $171, respectively | 317 |
| 317 |
| 317 |
|
Other comprehensive income (loss) | 4,039 |
| 21,407 |
| (75,218 | ) |
Comprehensive income (loss) | $ | 384,620 |
| $ | 325,596 |
| $ | 161,396 |
|
The accompanying notes are an integral part of the consolidated financial statements.
PUGET SOUND ENERGY, INC.
CONSOLIDATED BALANCE SHEETS
(Dollars in Thousands)
ASSETS
|
| | | | | | |
| December 31, |
| 2016 | 2015 |
Utility plant (at original cost, including construction work in progress of $420,278 and $408,795, respectively): | | |
Electric plant | $ | 9,813,169 |
| $ | 9,601,091 |
|
Natural gas plant | 3,640,271 |
| 3,444,744 |
|
Common plant | 632,718 |
| 548,657 |
|
Less: Accumulated depreciation and amortization | (4,927,602 | ) | (4,681,830 | ) |
Net utility plant | 9,158,556 |
| 8,912,662 |
|
Other property and investments: | |
| |
|
Other property and investments | 77,960 |
| 83,069 |
|
Total other property and investments | 77,960 |
| 83,069 |
|
Current assets: | |
| |
|
Cash and cash equivalents | 28,481 |
| 41,856 |
|
Restricted cash | 12,418 |
| 7,949 |
|
Accounts receivable, net of allowance for doubtful accounts of $9,798 and $9,756, respectively | 344,964 |
| 324,358 |
|
Unbilled revenue | 234,053 |
| 217,274 |
|
Purchased gas adjustment receivable | 2,785 |
| — |
|
Materials and supplies, at average cost | 106,378 |
| 78,244 |
|
Fuel and natural gas inventory, at average cost | 56,851 |
| 57,324 |
|
Unrealized gain on derivative instruments | 54,341 |
| 24,418 |
|
Prepaid expenses and other | 43,046 |
| 17,119 |
|
Total current assets | 883,317 |
| 768,542 |
|
Other long-term and regulatory assets: | | |
Regulatory asset for deferred income taxes | 71,517 |
| 72,694 |
|
Power cost adjustment mechanism | 4,531 |
| 4,749 |
|
Other regulatory assets | 1,034,352 |
| 894,059 |
|
Unrealized gain on derivative instruments | 8,738 |
| 5,225 |
|
Other | 58,109 |
| 58,513 |
|
Total other long-term and regulatory assets | 1,177,247 |
| 1,035,240 |
|
Total assets | $ | 11,297,080 |
| $ | 10,799,513 |
|
The accompanying notes are an integral part of the consolidated financial statements.
PUGET SOUND ENERGY, INC.
CONSOLIDATED BALANCE SHEETS
(Dollars in Thousands)
CAPITALIZATION AND LIABILITIESASSETS
| | | | | | | | | | | |
| December 31, | | |
| 2019 | | 2018 |
Utility plant (at original cost, including construction work in progress of $591,199 and $550,466, respectively): | | | |
Electric plant | $ | 10,671,328 | | | $ | 10,587,231 | |
Natural gas plant | 4,478,048 | | | 4,164,489 | |
Common plant | 1,121,568 | | | 1,052,544 | |
Less: Accumulated depreciation and amortization | (5,682,606) | | | (5,495,348) | |
Net utility plant | 10,588,338 | | | 10,308,916 | |
Other property and investments: | | | |
Other property and investments | 81,112 | | | 76,986 | |
Total other property and investments | 81,112 | | | 76,986 | |
Current assets: | | | |
Cash and cash equivalents | 44,004 | | | 35,452 | |
Restricted cash | 20,887 | | | 18,041 | |
Accounts receivable, net of allowance for doubtful accounts of $8,294 and $8,408, respectively | 319,229 | | | 346,251 | |
Unbilled revenue | 224,657 | | | 205,285 | |
Purchased gas adjustment receivable | — | | | 9,921 | |
Materials and supplies, at average cost | 115,684 | | | 116,180 | |
Fuel and natural gas inventory, at average cost | 50,818 | | | 52,028 | |
Unrealized gain on derivative instruments | 23,626 | | | 46,507 | |
Prepaid expenses and other | 27,504 | | | 25,674 | |
Total current assets | 826,409 | | | 855,339 | |
Other long-term and regulatory assets: | | | |
Power cost adjustment mechanism | 41,745 | | | 4,735 | |
Purchased gas adjustment receivable | 132,766 | | | — | |
Other regulatory assets | 673,021 | | | 773,552 | |
Unrealized gain on derivative instruments | 7,682 | | | 2,512 | |
Operating lease right-of-use asset | 183,048 | | | — | |
Other | 90,924 | | | 75,483 | |
Total other long-term and regulatory assets | 1,129,186 | | | 856,282 | |
Total assets | $ | 12,625,045 | | | $ | 12,097,523 | |
|
| | | | | | |
| December 31, |
| 2016 | 2015 |
Capitalization: | | |
Common shareholder’s equity: | | |
Common stock $0.01 par value, 150,000,000 shares authorized, 85,903,791 shares outstanding | $ | 859 |
| $ | 859 |
|
Additional paid-in capital | 3,275,105 |
| 3,275,105 |
|
Retained earnings | 359,795 |
| 236,578 |
|
Accumulated other comprehensive income (loss), net of tax | (145,511 | ) | (149,550 | ) |
Total common shareholder’s equity | 3,490,248 |
| 3,362,992 |
|
Long-term debt: | |
| |
|
First mortgage bonds and senior notes | 3,362,000 |
| 3,364,412 |
|
Pollution control bonds | 161,860 |
| 161,860 |
|
Junior subordinated notes | 250,000 |
| 250,000 |
|
Debt discount, issuance costs and other | (28,974 | ) | (31,910 | ) |
Total long-term debt | 3,744,886 |
| 3,744,362 |
|
Total capitalization | 7,235,134 |
| 7,107,354 |
|
Current liabilities: | |
| |
|
Accounts payable | 317,043 |
| 259,353 |
|
Short-term debt | 245,763 |
| 159,004 |
|
Current maturities of long-term debt | 2,412 |
| — |
|
Purchased gas adjustment liability | — |
| 12,589 |
|
Accrued expenses: | |
| |
|
Taxes | 111,428 |
| 114,854 |
|
Salaries and wages | 49,749 |
| 38,457 |
|
Interest | 48,087 |
| 47,772 |
|
Unrealized loss on derivative instruments | 44,170 |
| 131,420 |
|
Other | 71,996 |
| 53,868 |
|
Total current liabilities | 890,648 |
| 817,317 |
|
Other Long-term and regulatory liabilities: | |
| |
|
Deferred income taxes | 1,732,390 |
| 1,556,616 |
|
Unrealized loss on derivative instruments | 16,261 |
| 47,776 |
|
Regulatory liabilities | 653,296 |
| 651,094 |
|
Other deferred credits | 769,351 |
| 619,356 |
|
Total other long-term and regulatory liabilities | 3,171,298 |
| 2,874,842 |
|
Commitments and contingencies (Note 15) |
|
|
|
|
Total capitalization and liabilities | $ | 11,297,080 |
| $ | 10,799,513 |
|
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
| | | | | | | | | | | |
| Year Ended December 31, | | |
| 2019 | | 2018 |
Capitalization: | | | |
Common shareholder’s equity: | | | |
Common stock $0.01 par value, 150,000,000 shares authorized, 85,903,791 shares outstanding | $ | 859 | | | $ | 859 | |
Additional paid-in capital | 3,485,105 | | | 3,275,105 | |
Retained earnings | 751,193 | | | 622,844 | |
Accumulated other comprehensive income (loss), net of tax | (188,477) | | | (190,884) | |
Total common shareholder’s equity | 4,048,680 | | | 3,707,924 | |
Long-term debt: | | | | |
First mortgage bonds and senior notes | 4,212,000 | | | 3,764,417 | |
Pollution control bonds | 161,860 | | | 161,860 | |
| | | |
Debt discount, issuance costs and other | (37,718) | | | (31,417) | |
Total long-term debt | 4,336,142 | | | 3,894,860 | |
Total capitalization | 8,384,822 | | | 7,602,784 | |
Current liabilities: | | | | |
Accounts payable | 325,980 | | | 480,195 | |
Short-term debt | 176,000 | | | 379,297 | |
Current maturities of long-term debt | 2,412 | | | — | |
| | | |
Accrued expenses: | | | | |
Taxes | 99,977 | | | 117,993 | |
Salaries and wages | 50,091 | | | 50,785 | |
Interest | 48,917 | | | 43,951 | |
Unrealized loss on derivative instruments | 13,428 | | | 46,661 | |
Operating lease liabilities | 15,862 | | | — | |
Other | 107,809 | | | 79,312 | |
Total current liabilities | 840,476 | | | 1,198,194 | |
Other Long-term and regulatory liabilities: | | | | |
Deferred income taxes | 977,163 | | | 926,403 | |
Unrealized loss on derivative instruments | 12,693 | | | 11,095 | |
Regulatory liabilities | 729,614 | | | 745,880 | |
Regulatory liability for deferred income taxes | 946,936 | | | 976,582 | |
Operating lease liabilities | 174,327 | | | — | |
Other deferred credits | 559,014 | | | 636,585 | |
Total long-term and regulatory liabilities | 3,399,747 | | | 3,296,545 | |
Commitments and contingencies (Note 16) | | | | | |
Total capitalization and liabilities | $ | 12,625,045 | | | $ | 12,097,523 | |
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)
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | | | | | | | | | | |
| Common Stock | | | | Additional | | | | Accumulated Other | | |
| Shares | | Amount | | Paid-in Capital | | Retained Earnings | | Comprehensive Income (Loss) | | Total Equity |
Balance at December 31, 2016 | $ | 85,903,791 | | | $ | 859 | | | $ | 3,275,105 | | | $ | 359,795 | | | $ | (145,511) | | | $ | 3,490,248 | |
Net income (loss) | — | | | — | | | — | | | 320,054 | | | — | | | 320,054 | |
Common stock dividend paid | — | | | — | | | — | | | (227,783) | | | — | | | (227,783) | |
| | | | | | | | | | | |
Other comprehensive income (loss) | — | | | — | | | — | | | — | | | 18,605 | | | 18,605 | |
Balance at December 31, 2017 | $ | 85,903,791 | | | $ | 859 | | | $ | 3,275,105 | | | $ | 452,066 | | | $ | (126,906) | | | $ | 3,601,124 | |
Net income (loss) | — | | | — | | | — | | | 317,162 | | | — | | | 317,162 | |
Common stock dividend paid | — | | | — | | | — | | | (173,716) | | | — | | | (173,716) | |
| | | | | | | | | | | |
Other comprehensive income (loss) | — | | | — | | | — | | | — | | | (63,978) | | | (63,978) | |
Cumulative effect of accounting change | — | | | — | | | — | | | 27,332 | | | — | | | 27,332 | |
Balance at December 31, 2018 | $ | 85,903,791 | | | $ | 859 | | | $ | 3,275,105 | | | $ | 622,844 | | | $ | (190,884) | | | $ | 3,707,924 | |
Net income (loss) | — | | | — | | | — | | | 292,924 | | | — | | | 292,924 | |
Common stock dividend paid | — | | | — | | | — | | | (164,575) | | | — | | | (164,575) | |
Capital Contribution | — | | | — | | | 210,000 | | | — | | | — | | | 210,000 | |
Other comprehensive income (loss) | — | | | — | | | — | | | — | | | 2,407 | | | 2,407 | |
| | | | | | | | | | | |
Balance at December 31, 2019 | $ | 85,903,791 | | | $ | 859 | | | $ | 3,485,105 | | | $ | 751,193 | | | $ | (188,477) | | | $ | 4,048,680 | |
|
| | | | | | | | | | | | | | | | | |
| Common Stock | Additional | | Accumulated Other | |
| Shares | Amount | Paid-in Capital | Retained Earnings | Comprehensive Income (loss) | Total Equity |
Balance at December 31, 2013 | 85,903,791 |
| $ | 859 |
| $ | 3,246,205 |
| $ | 289,432 |
| $ | (95,739 | ) | $ | 3,440,757 |
|
Net income (loss) | — |
| — |
| — |
| 236,614 |
| — |
| 236,614 |
|
Common stock dividend | — |
| — |
| — |
| (323,424 | ) | — |
| (323,424 | ) |
Other comprehensive income (loss) | — |
| — |
| — |
| — |
| (75,218 | ) | (75,218 | ) |
Balance at December 31, 2014 | 85,903,791 |
| $ | 859 |
| $ | 3,246,205 |
| $ | 202,622 |
| $ | (170,957 | ) | $ | 3,278,729 |
|
Net income (loss) | — |
| — |
| — |
| 304,189 |
| — |
| 304,189 |
|
Common stock dividend | — |
| — |
| — |
| (270,233 | ) | — |
| (270,233 | ) |
Capital Contribution | — |
| — |
| 28,900 |
| — |
| — |
| 28,900 |
|
Other comprehensive income (loss) | — |
| — |
| — |
| — |
| 21,407 |
| 21,407 |
|
Balance at December 31, 2015 | 85,903,791 |
| $ | 859 |
| $ | 3,275,105 |
| $ | 236,578 |
| $ | (149,550 | ) | $ | 3,362,992 |
|
Net income (loss) | — |
| — |
| — |
| 380,581 |
| — |
| 380,581 |
|
Common stock dividend | — |
| — |
| — |
| (257,364 | ) | — |
| (257,364 | ) |
Other comprehensive income (loss) | — |
| — |
| — |
| — |
| 4,039 |
| 4,039 |
|
Balance at December 31, 2016 | 85,903,791 |
| $ | 859 |
| $ | 3,275,105 |
| $ | 359,795 |
| $ | (145,511 | ) | $ | 3,490,248 |
|
The accompanying notes are an integral part of the consolidated financial statements.
PUGET SOUND ENERGY, INC.
CONSOLIDATED STATEMENTS OF CASH FLOWS
(Dollars in Thousands)
| | | | | | | | | | | | | | | | | |
| Year Ended December 31, | | | | |
| 2019 | | 2018 | | 2017 |
Operating Activities: | | | | | |
Net Income (Loss) | $ | 292,924 | | | $ | 317,162 | | | $ | 320,054 | |
Adjustments to reconcile net income (loss) to net cash provided by operating activities: | | | | | | | | |
Depreciation and amortization | 656,220 | | | 666,324 | | | 481,955 | |
Conservation amortization | 96,571 | | | 111,714 | | | 121,216 | |
Deferred income taxes and tax credits, net | 20,474 | | | 30,995 | | | 210,842 | |
Net unrealized (gain) loss on derivative instruments | 3,574 | | | (41,662) | | | 30,790 | |
AFUDC - equity | (15,802) | | | (17,191) | | | (15,027) | |
Production tax credit | (68,622) | | | (83,976) | | | (53,331) | |
Other non-cash | (15,154) | | | 4,428 | | | 6,445 | |
Funding of pension liability | (18,000) | | | (18,000) | | | (18,000) | |
Regulatory assets and liabilities | (79,173) | | | (71,348) | | | (88,875) | |
Purchased gas adjustment | (132,766) | | | | — | | | | — | |
Other long term assets and liabilities | (8,967) | | | 16,917 | | | (14,547) | |
Change in certain current assets and liabilities: | | | | | | | | |
Accounts receivable and unbilled revenue | 7,650 | | | 12,626 | | | 13,285 | |
Materials and supplies | (6,018) | | | (9,177) | | | (625) | |
Fuel and natural gas inventory | 1,210 | | | (3,443) | | | 8,266 | |
Purchased gas adjustment | 9,921 | | | (25,972) | | | 18,836 | |
Prepayments and other | (1,103) | | | (3,679) | | | 21,050 | |
Accounts payable | (116,370) | | | 117,397 | | | 26,396 | |
Taxes payable | (18,016) | | | 930 | | | 5,635 | |
Other | 15,371 | | | (8,141) | | | 12,438 | |
Net cash provided by (used in) operating activities | 623,924 | | | 995,904 | | | 1,086,803 | |
Investing Activities: | | | | | |
Construction expenditures - excluding equity AFUDC | (919,271) | | | (1,010,506) | | | (963,652) | |
Other | 6,908 | | | 2,097 | | | 241 | |
Net cash provided by (used in) investing activities | (912,363) | | | (1,008,409) | | | (963,411) | |
Financing Activities | | | | | |
Change in short-term debt, net | (203,297) | | | 49,834 | | | 83,700 | |
Dividends paid | (164,575) | | | (173,716) | | | (227,783) | |
| | | | | |
Investment from Parent | 210,000 | | | — | | | — | |
Proceeds from long-term debt and bonds issued | 443,151 | | | 594,750 | | | — | |
Redemption of bonds and notes | — | | | (450,000) | | | — | |
Other | 14,558 | | | 9,121 | | | 15,801 | |
Net cash provided by (used in) financing activities | 299,837 | | | 29,989 | | | (128,282) | |
Net increase (decrease) in cash, cash equivalents, and restricted cash | 11,398 | | | 17,484 | | | (4,890) | |
Cash, cash equivalents, and restricted cash at beginning of period | 53,493 | | | 36,009 | | | 40,899 | |
Cash, cash equivalents, and restricted cash at end of period | $ | 64,891 | | | $ | 53,493 | | | $ | 36,009 | |
Supplemental cash flow information: | | | | | |
Cash payments for interest (net of capitalized interest) | $ | 219,665 | | | $ | 221,155 | | | $ | 224,423 | |
Cash payments (refunds) for income taxes | 19,269 | | | 18,124 | | | 3,058 | |
| | | | | |
| | | | | |
Non-cash financing and investing activities: | | | | | |
Accounts payable for capital expenditures eliminated from cash flow | $ | 58,329 | | | $ | 97,673 | | | $ | 92,959 | |
Reclassification of Colstrip from utility plant to a regulatory asset | 4,163 | | | (3,086) | | | (49,177) | |
Reclassification of hydro treasury grants to a regulatory liability | — | | | — | | | 95,935 | |
|
| | | | | | | | | |
| Year Ended December 31, |
| 2016 | 2015 | 2014 |
Operating activities: | | | |
Net income (loss) | $ | 380,581 |
| $ | 304,189 |
| $ | 236,614 |
|
Adjustments to reconcile net income (loss) to net cash provided by operating activities: | |
| |
| |
|
Depreciation and amortization | 439,579 |
| 420,807 |
| 365,606 |
|
Conservation amortization | 107,784 |
| 110,866 |
| 104,096 |
|
Deferred income taxes and tax credits, net | 174,776 |
| 125,900 |
| 89,342 |
|
Net unrealized (gain) loss on derivative instruments | (83,795 | ) | (12,688 | ) | 85,636 |
|
AFUDC - equity | (12,576 | ) | (9,325 | ) | (7,002 | ) |
Funding of pension liability | (24,000 | ) | (18,000 | ) | (18,000 | ) |
Regulatory assets and liabilities | (149,998 | ) | (153,877 | ) | (228,334 | ) |
Other long-term assets and liabilities | 33,119 |
| 39,379 |
| 16,518 |
|
Change in certain current assets and liabilities: | |
| |
| |
|
Accounts receivable and unbilled revenue | (37,385 | ) | (66,547 | ) | 153,626 |
|
Materials and supplies | (28,134 | ) | 4,945 |
| 4,951 |
|
Fuel and natural gas inventory | 473 |
| 9,332 |
| (2,742 | ) |
Prepayments and other | (25,927 | ) | 4,089 |
| (2,140 | ) |
Purchased gas adjustment | (15,374 | ) | 33,662 |
| (27,011 | ) |
Accounts payable | 32,465 |
| (48,031 | ) | 9,098 |
|
Taxes payable | (3,426 | ) | 7,072 |
| (1,777 | ) |
Other | 30,754 |
| (12,992 | ) | 4,246 |
|
Net cash provided by (used in) operating activities | 818,916 |
| 738,781 |
| 782,727 |
|
Investing activities: | |
| |
| |
|
Construction expenditures - excluding equity AFUDC | (681,112 | ) | (587,225 | ) | (493,130 | ) |
Treasury grants received | — |
| — |
| 107,876 |
|
Proceeds from disposition of assets | — |
| — |
| 20,296 |
|
Restricted cash | (4,469 | ) | 24,914 |
| (25,692 | ) |
Other | 4,156 |
| 6,386 |
| (1,683 | ) |
Net cash provided by (used in) investing activities | (681,425 | ) | (555,925 | ) | (392,333 | ) |
Financing activities: | |
| |
| |
|
Change in short-term debt, net | 86,759 |
| 74,004 |
| (77,000 | ) |
Dividends paid | (257,364 | ) | (270,233 | ) | (323,424 | ) |
Loan from (payment to) parent | — |
| (28,933 | ) | (665 | ) |
Investment from parent | — |
| 28,900 |
| — |
|
Proceeds from long-term debt and bonds issued | — |
| 425,000 |
| — |
|
Redemption of bonds and notes | — |
| (412,000 | ) | — |
|
Other | 19,739 |
| 4,796 |
| 4,050 |
|
Net cash provided by (used in) financing activities | (150,866 | ) | (178,466 | ) | (397,039 | ) |
Net increase (decrease) in cash and cash equivalents | (13,375 | ) | 4,390 |
| (6,645 | ) |
Cash and cash equivalents at beginning of period | 41,856 |
| 37,466 |
| 44,111 |
|
Cash and cash equivalents at end of period | $ | 28,481 |
| $ | 41,856 |
| $ | 37,466 |
|
Supplemental cash flow information: | |
| |
| |
|
Cash payments for interest (net of capitalized interest) | $ | 227,668 |
| $ | 242,774 |
| $ | 253,803 |
|
Cash payments (refunds) for income taxes | — |
| 2 |
| — |
|
Non-cash financing and investing activities: | | | |
Accounts payable for capital expenditures eliminated from cash flows | $ | 76,813 |
| $ | 51,588 |
| $ | 51,776 |
|
Reclassification of Colstrip from utility plant to a regulatory asset
| 176,804 |
| — |
| — |
|
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 approximately 6,000 square miles, primarily in the Puget Sound region. Puget Energy also has a wholly-owned non-regulated subsidiary, Puget LNG, LLC (Puget LNG), which has the sole purpose of owning, developing and financing the non-regulated activity of the Tacoma liquefied natural gas (LNG) facility, currently under construction. PSE and Puget LNG are considered related parties with similar ownership by Puget Energy. Therefore, capital and operating costs that are incurred by PSE and allocated to Puget LNG are related party transactions by nature.
In 2009, Puget Holdings, LLC (Puget Holdings), owned by a consortium of long-term infrastructure investors, completed its merger with Puget Energy (the merger). As a result of the merger, all of Puget Energy’s common stock is indirectly owned by Puget Holdings. The acquisition of Puget Energy was accounted for in accordance with Financial Accounting Standards Board (FASB) Accounting Standards Codification (ASC) 805, “Business Combinations” (ASC 805), as of the date of the merger. ASC 805 requires the acquirer to recognize and measure identifiable assets acquired and liabilities assumed at fair value as of the merger date.
The consolidated financial statements of Puget Energy reflect the accounts of Puget Energy and its subsidiaries. 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.”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 ASCAccounting Standards Codification (ASC) 805, “Business Combinations” (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.
Change in Accounting Principle
On January 1, 2016, the Company changed its method of presenting unamortized debt issuance costs in the balance sheet. The new method of presenting debt issuance costs was adopted to comply with Accounting Standards Update (ASU) 2015-03, "Interest-Imputation of Interest (Subtopic 835-30): Simplifying the Presentation of Debt Issuance Costs". ASU 2015-03 requires debt issuance costs related to a recognized debt liability be presented in the balance sheet as a direct deduction from the carrying amount of the debt liability, consistent with the presentation of a debt discount. The prior year comparative balance sheet has been adjusted to apply the new method retrospectively. Due to the change in accounting principle, the December 31, 2015 financial statement line item “Other long-term assets” decreased and “Debt discount, issuance costs and other” increased 38.4 million and 30.0 million at Puget Energy and PSE, respectively.
Utility Plant
Puget Energy and PSE capitalize, at original cost, additions to utility plant, including renewals and betterments. Costs include indirect costs such as engineering, supervision, certain taxes, pension and other employee benefits and an allowance for funds used during construction (AFUDC). Replacements of minor items of property are included in maintenance expense. When the utility plant is retired and removed from service, the original cost of the property is charged to accumulated depreciation and costs associated with removal of the property, less salvage, are charged to the cost of removal regulatory liability.
Planned Major Maintenance
Planned major maintenance is an activity that typically occurs when PSE overhauls or substantially upgrades various systems and equipment on its natural gas fired combustion turbines on a scheduled basis. Costs related to planned major maintenance are deferred and amortized to the next scheduled major maintenance. This accounting method also follows the Washington Utilities and Transportation Commission (Washington Commission) regulatory treatment related to these generating facilities.
Non-UtilityOther Property Plant and EquipmentInvestments
For PSE, the costs of other property plant and equipmentinvestments (i.e., non-utility) 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. Replacements of minor items are expensed on a current basis. Gains and losses on assets sold or retired, which were previously recorded in utility plant, are apportioned between regulatory assets/liabilities and earnings. However, gains and losses on assets sold or retired, not previously recorded in utility plant, are reflected in earnings.
Depreciation and Amortization
For financial statement purposes, theThe 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%3.4%, for each of 2016, 20153.3%, and 2014;2.8% in 2019, 2018, and 2017, respectively; depreciable natural gas
utility plant was 3.4%2.8%, for each of 2016, 20152.8%, and 2014;3.4% in 2019, 2018, and 2017, respectively; and depreciable common utility plant was 9.7%7.3%, 8.5%7.1% and 8.5%8.3% in 2016, 20152019, 2018, and 2014,2017, 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.
GoodwillTacoma LNG Facility
In 2009,August 2015, PSE filed a proposal with the Washington Commission to develop an LNG facility at the Port of Tacoma. Currently under construction at the Port of Tacoma, the facility is expected to be operational in 2021. The Tacoma LNG facility is designed to provide peak-shaving services to PSE’s natural gas customers. By storing surplus natural gas, PSE is able to meet the requirements of peak consumption. LNG will also provide fuel to transportation customers, particularly in the marine market. On January 24, 2018, Puget Holdings completed its mergerSound Clean Air Agency (PSCAA) determined a Supplemental Environmental Impact Statement (SEIS) was necessary in order to rule on the air quality permit for the facility. As a result of requiring a SEIS, the Company's construction schedule was impacted. PSE received the SEIS which concluded the LNG facility would result in a net decrease in GHG emissions providing, in part, that the natural gas for the facility was sourced from British Columbia or Alberta. On December 10, 2019, the PSCAA approved the Notice of Construction permit, a decision which has been appealed to the Washington Pollution Control Hearings Board by each of the Puyallup Tribe of Indians and nonprofit law firm Earthjustice.
Pursuant to an order by the Washington Commission, PSE will be allocated approximately 43.0% of common capital and operating costs, consistent with the regulated portion of the Tacoma LNG facility. The remaining 57.0% of common capital and operating costs of the Tacoma LNG facility will be allocated to Puget Energy.LNG. Per this allocation of costs, $199.9 million and $165.6 million of construction work in progress related to Puget LNG's portion of the Tacoma LNG facility is reported in the Puget Energy remeasured the carrying amount"Other property and investments" financial statement line item as of all its assetsDecember 31, 2019, and liabilities to fair value, which resulted in recognitionDecember 31, 2018, respectively. Additionally, $1.2 million, $2.0 million, and $0.3 million 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 changeoperating costs are reported in the Company’s business or regulatory outlook, legal factors, a sale or dispositionPuget Energy "Non-utility expense and other" financial statement line item in 2019, 2018, and 2017, respectively. Additionally, $162.8 million and $130.8 million of a significantconstruction work in progress related to PSE’s portion of a reporting unit or significant changesthe Tacoma LNG facility is reported in the PSE “Utility plant - Natural gas plant” 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 2016 using an October 1, 2016 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 goodwillstatement line item as of October 1, 2016. There were no known events or circumstances from the date of the assessment through December 31, 2016 that would impact management’s conclusion.2019, and December 31, 2018, respectively, as PSE is a regulated entity.
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 carrying amounts of cash and cash equivalents are reported at cost and approximate fair value, due to the short-term maturity.
Restricted Cash
Restricted cash amounts are primarily represent cash posted as collateral for derivative contracts as well as funds required to be set aside for contractual obligations related to transmission and generation facilities.
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 recordThe Company records these items at weighted-average cost.
Fuel and Natural Gas Inventory
Fuel and natural 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. Natural gas inventory consists of natural gas and liquefied natural gas (LNG)LNG held in storage for future sales. Puget Energy and PSE recordThe Company records these items at the lower of cost or marketnet realizable 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 or losses that would otherwise be charged to expense, if it is probable that future rates will permit recovery of such costs. It similarly requires deferral of revenues or gains and losses that are expected to be returned to customers in the future. Accounting under ASC 980 is appropriate as long as rates are established by or subject to approval by independent third-party regulators; rates are designed to recover the specific enterprise’s cost of service; and in view of demand for service, it is reasonable to assume that rates set at levels that will recover costs can be charged to and collected from customers. In most cases, PSE classifies regulatory assets and liabilities as long-term due to the length of the amortization.when amortization periods extend longer
than one year. For further details regarding regulatory assets and liabilities, see Note 3,4, "Regulation and Rates" to the consolidated financial statements included in Item 8 of this report.
Puget Energy recorded regulatory assets and liabilities at the time of the merger related to power purchase contracts.
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 primarily 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; the AFUDC debt portion is credited to interest expense, while the AFUDC equity portion is credited to other income. Cash inflow related to AFUDC does not occur until these charges are reflected in rates. The current AFUDC rate authorized by the Washington Commission for natural gas and electric utility plant additions as of July 1, 2013through December 18, 2017, was 7.77%. Effective December 19, 2017, with the Washington Commission order, the new AFUDC rate authorized is 7.77%7.60%.
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).revenue. Revenue from retail sales is billed based on tariff rates approved by the Washington Commission. 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 tariff rate schedule to estimate the unbilled revenues by customer.
PSE collected Washington State excise taxes (which are a component of general retail customer rates) and municipal taxes totaling $235.3$236.5 million, $234.2$239.3 million and $231.7$257.1 million for 2016, 20152019, 2018, and 2014,2017, respectively. The Company reports the collection of such taxes on a gross basis in operation revenue and as expense in taxes other than income taxes in the accompanying consolidated statements of income.
The non-utility subsidiary recognizes revenue when services are performed or upon the sale of assets. Revenue from retail sales is billed based on tariff rates approved by the Washington Commission.
PSE's electric and natural gas operations contain a revenue decoupling mechanism under which PSE's actual energy delivery revenues related to electric transmission and distribution, natural gas operations and general administrative costs are compared with authorized revenues allowed under the mechanism. The mechanism mitigates volatility in revenue due to weather and gross margin erosion relateddue to weather and energy efficiency. Any differences in revenue are deferred to a regulatory asset for under recovery or regulatory liability for over recovery under alternative revenue recognition standard. To record revenuesRevenue is recognized under this program the Company must be able to collect the revenuewhen deemed collectible within 24 months based on alternative revenue recognition guidance. Decoupled rate increases are effective May 1 of each year subject to a 3.0% cap of total revenue for decoupled rate schedules. Any excess revenue above 3.0% will be included in the following year's decoupled rate. The Company will be able to recognize revenue below the 3.0% cap of total revenue for decoupled rate schedules. For revenue deferrals exceeding the annual 3.0% rate cap of total revenue for decoupled rate schedules, the Company will assess the excess amount to determine its ability to be collected within 24 months. For GAAP purposes only,On December 5, 2017, the Washington Commission approved PSE’s request within the 2017 general rate case (GRC) to extend the decoupling mechanism with some changes to the methodology that took effect on December 19, 2017. The rate test which limits the amount of revenues PSE can collect in its annual filings increased from 3.0% to 5.0% for natural gas customers but will remain at 3.0% for electric customers. The Company will not record any decoupling revenue that is expected to take longer than 24 months to collect following the end of the annual period in which the revenues would have otherwise been recognized. Once determined to be collectible within 24 months, any previously non-recordednon-recognized amounts will be recorded.recognized. Revenues associated
with energy costs under the power cost adjustment (PCA) mechanism and purchased gas adjustment (PGA) mechanism 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 balance for allowance for doubtful accounts at December 31, 20162019, and 20152018, was $9.8$8.3 million each year.and $8.4 million, respectively.
Self-Insurance
PSE is self-insured for storm damage and certain environmental contamination associated with current operations occurring on PSE-owned property. In addition, PSE is required to meet a deductible for a portion of the risk associated with comprehensive liability, workers’ compensation claims and catastrophic property losses other than those which are storm related. TheUnder the December 5, 2017, Washington Commission has approvedorder regarding PSE’s GRC, the cumulative annual cost threshold for deferral of certain uninsured qualifying storm damage costs that exceed $8.0storms under the mechanism increased from $8.0 million which will be requested for collection in future rates. to $10.0 million effective January 1, 2018. 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's 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, whowhich is the ultimate tax payer.
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 Natural Gas Sales
As part of the Company’s electric operations, PSE purchases natural gas for 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 natural 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 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.sources during the first ten years of operation. Before the 2017 GRC, the tax savings from these credits were intended to be refunded by PSE recordsto its customers when monetized, used on the benefitincome tax return, through its revenue requirement as initially approved by the Washington Commission. As the Company had not generated taxable income with which to monetize the credits, they had not been refunded to customers. Amounts to be refunded have been recorded as a regulatory liability with an offsetting reduction to revenue as it was intended to be refunded through the revenue requirement. A deferred tax asset and reduction to deferred tax expense were also recorded for the regulatory liability. These entries resulted in no net income impact. In connection with the GRC settlement in 2017, the Washington Commission authorized the Company to utilize the tax savings associated with the monetization of the PTCs to fund the following: (i) Colstrip Community Transition Fund, (ii) unrecovered Colstrip plant and (iii) incurred decommissioning and remediation costs for Colstrip. As PTCs will no longer be refunded to customers through the revenue requirement, a non-cash increase to revenue and deferred tax expense will be recorded as a deferred credit until such time as PSE utilizes the PTCs are monetized. These entries will result in no net income impact. As of December 31, 2019 and 2018, $67.5 million and $84.0 million of PTCs were estimated to be monetized through tax credit on its tax return. Once utilized, PSE will reclassify the credits to a regulatory liability and pass the benefit to customers.filings, respectively.
Accounting for 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. 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 natural gas related derivatives due to the 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. 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 (AOCI) 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. When these contracts are settled, the contract price becomes part of purchased electricity or electric generation fuel which becomes part of PSE’s PCA mechanism and the unrealized gain or loss is listed separately under energy costs, as it represents the non-rate treatment of energy costs.
The Company may enter into swap instruments or other financial derivative instruments to manage the interest rate risk associated with its long-term debt financing and debt instruments. As of December 31, 2016, Puget Energy has interest rate swap contracts outstanding originally related to its long-term debt. For additional information, see Note 9,10, "Accounting for Derivative Instruments and Hedging Activities" to the consolidated financial statements included in Item 8 of this report.
Fair Value Measurements of Derivatives
ASC 820, “Fair Value Measurements and Disclosures” (ASC 820), defines fair value as the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date (exit price). As permitted under ASC 820, the Company utilizes a mid-market pricing convention (the mid-point price between bid and ask prices) as a practical expedient for valuing the majority of its assets and liabilities measured and reported at fair value. The Company utilizes market data or assumptions that market participants would use in pricing the asset or liability, including assumptions about risk and the risks inherent in the inputs to the valuation technique. These inputs can be readily observable, market corroborated or generally unobservable. The Company primarily applies the market approach for recurring fair value measurements as it believes that the approach is used by market participants for these types of assets and liabilities. Accordingly, the Company utilizes valuation techniques that maximize the use of observable inputs and minimize the use of unobservable inputs.
The Company values derivative instruments based on daily quoted prices from an independent external pricing service. When external quoted market prices are not available for derivative contracts, the Company uses a valuation model that uses volatility assumptions relating to future energy prices based on specific energy markets and utilizes externally available forward market price curves. All derivative instruments are sensitive to market price fluctuations that can occur on a daily basis. For additional information, see Note 10,11, "Fair Value Measurements" to the consolidated financial statements included in Item 8 of this report.
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.PSE and presented net of long-term liabilities on the balance sheet.
Leases
PSE determines if an arrangement is, or contains, a lease at inception of the contract. If the arrangement is, or contains a lease, PSE assesses whether the lease is operating or financing for income statement and balance sheet classification. Operating leases are included in operating lease right-of-use (ROU) assets, operating lease current liabilities, and operating lease liabilities in our consolidated balance sheets. Finance leases are included in utility plant, other current liabilities, and other deferred credits in our consolidated balance sheets.
ROU assets represent the right to use an underlying asset for the lease term, and consist of the amount of the initial measurement of the lease liability, any lease payments made to the lessor at or before the commencement date, minus any lease incentives received, and any initial direct costs incurred by the lessee. Lease liabilities represent our obligation to make lease payments arising from the lease and are measured at present value of the lease payments not yet paid, discounted using the discount rate for the lease, determined based on PSE's incremental borrowing rate, at commencement. As most of PSE's leases do not provide an implicit interest rate, PSE uses the incremental borrowing rate based on the information available at commencement date in determining the present value of lease payments. For fleet, IT and wind farm leases, this rate is applied using a portfolio approach. The lease terms may include options to extend or terminate the lease when it is reasonably certain that PSE will exercise that option. On the statement of income, operating leases are generally accounted for under a straight-line expense model, while finance leases, which were previously referred to as capital leases, are generally accounted for under a financing model. Consistent with the previous lease guidance, however, the standard allows rate-regulated utilities to recognize expense consistent with the timing of recovery in rates.
PSE has lease agreements with lease and non-lease components. Non-lease components comprise common area maintenance and utilities, and are accounted for separately from lease components.
(2) New Accounting Pronouncements
Revenue RecognitionRecently Adopted Accounting Guidance
In May 2014, the FASB issued ASU No. 2014-09, "Revenue from Contracts with Customers (Topic 606)". ASU 2014-09 and the related amendments outline a single comprehensive model for use in accounting for revenue arising from contracts with customers and supersedes most current revenue recognition guidance, including industry-specific guidance. The ASU is based on the principle that an entity should recognize revenue to depict the transfer of goods or services to customers in an amount that reflects the consideration to which the entity expects to be entitled in exchange for those goods or services. The ASU also requires additional disclosure about the nature, amount, timing and uncertainty of revenue and cash flows arising from customer contracts, including significant judgments and changes in judgments and assets recognized from costs incurred to fulfill a contract.
In August 2015, the FASB issued ASU 2015-14, "Revenue from Contracts with Customers (Topic 606): Deferral of the Effective Date," deferring the effective date for ASU 2014-09 to fiscal years, and interim periods within those fiscal years, beginning after December 15, 2017. In addition to the FASB's deferral decision, FASB provided reporting entities with an option to adopt ASU 2014-09 for the fiscal years, and interim periods within those fiscal years, beginning after December 15, 2016, the original effective date.
The Company plans to adopt ASU 2014-09 during the first quarter of fiscal year 2018. Reporting entities have the option of using either a full retrospective or a modified retrospective approach for the adoption of the new standard. At this time, the Company has not yet selected a transition method; however, it is in the process of completing its analysis and expects to decide in early 2017. Additionally, the Company initiated a steering committee and project team to evaluate the impact of this standard, update any policies and procedures that may be affected, and implement the new revenue recognition guidance. After a substantial evaluation of this standard, the Company does not anticipate significant impacts to its results of operations or on its consolidated financial statements. The Company is still waiting on the resolution of certain industry implementation issues, including contributions in aid of construction (CIAC), to determine the full impact. The Company is anticipating additional disclosures related to the implementation of the new standard.
Lease Accounting
In February 2016, the FASB issued ASU 2016-02, "Leases"Leases (Topic 842)". The FASB issued this ASU to increase transparency and comparability among organizations by recognizing right-of-use lease assets and lease liabilities on the balance sheet and disclosing key information about leasing arrangements. To meet that objective, the FASB amended the FASB ASC and created Topic 842, Leases. ASU 2016-02requires lessees to recognize the following for all leases (with the exception of short-term leases) at the commencement date: (i) a lease liability, which is a lessee's obligation to make lease payments arising from a lease, measured on a discounted basis; and (ii) a right-of-use asset, which is an asset that represents the lessee’s right to use, or control the use of, a specified asset for the lease term. The income statement recognition is similar to existing lease accounting and is based on lease classification. Under the new guidance, lessor accounting is largely unchanged.
This amendment isIn January 2018, the FASB issued ASU 2018-01, "Leases (Topic 842): Land Easement Practical Expedient for Transition to Topic 842". In connection with the FASB’s transition support efforts, the amendments in this update provide an optional transition practical expedient to not evaluate under Topic 842 existing or expired land easements that were not previously accounted for as leases under the current guidance in Topic 840. An entity that elects this practical expedient should evaluate new or modified land easements under Topic 842 upon adoption. Land easements (also commonly referred to as rights of way) represent the right to use, access, or cross another entity’s land for a specified purpose. The Company elected this practical expedient.
In July 2018, the FASB issued both ASU 2018-10 and ASU 2018-11, "Leases (Topic 842): Codification Improvements" and "Leases (Topic 842): Targeted Improvements". These ASUs provide entities with both clarification on existing guidance issued in ASU 2016-02, as well as an additional transition method to adopt the new leasing standard. Under the new transition method, the entity initially applies the new standard at the adoption date by recognizing a cumulative-effect adjustment to the opening balance of retained earnings in the period of adoption. Consequently, an entity's reporting for the comparative periods presented in the financial statements will continue to be in accordance with Topic 840. The Company has elected to adopt the standard using this new modified transition method.
In preparation for adoption of the standard, the Company assembled a project team that met bi-weekly to make key accounting assessments and perform pre-implementation controls related to the scoping and completeness of existing leases. Additionally, the Company implemented a new leasing system and drafted accounting policies including discount rate, variable pricing, power purchase agreements, and election of practical expedients. In addition to the land easement practical expedient, the Company has elected the practical expedient package.
These amendments are effective for financial statements issued for fiscal years beginning after December 15, 2018, including interim periods within those fiscal years. Earlier adoption is permitted for all entities upon issuance. Reporting entities must apply a modified retrospective approach forThe Company adopted ASU 2016-02 as of January 1, 2019, which resulted in the adoptionrecognition of right-of-use asset and lease liability financial statement line items that have not previously been recorded and are material to the consolidated balance sheets. Adoption of the new standard.standard did not have a material impact on the income statement. The Company plansfinancial impact as of the date of adoption was not materially different than what has been disclosed as of December 31, 2019, in Note 9, "Leases", to adopt ASU 2016-02 during the first quarter of fiscal year 2019. At this time, the Company plans to initiate a steering committee and project team to evaluate the impact this standard will have on its results of operations and consolidated financial statements.statements included in Item 8 of this report.
Derivatives and HedgingInternal-Use Software
In March 2016,August 2018, the FASB issued ASU 2016-06, "Derivatives2018-15, "Intangibles—Goodwill and Hedging (Topic 815)Other—Internal-Use Software (Subtopic 350-40): Contingent Put and Call OptionsCustomer’s Accounting for Implementation Costs Incurred in Debt Instruments"a Cloud Computing Arrangement That Is a Service Contract". Topic 815 requires that embedded derivatives be separated from the host contract and accounted for separately as derivatives if certain criteria are met, including the “clearly and closely related” criterion. ASU 2016-06 clarifiesThese amendments align the requirements for assessing whether contingent callcapitalizing implementation costs incurred in a hosting arrangement that is a service contract with the requirements for capitalizing implementation costs incurred to develop or put optionsobtain internal-use software (and hosting arrangements that can accelerateinclude an internal-use software license). The accounting for the paymentservice element of principala hosting arrangement that is a service contract is not affected by these amendments. While the standard requires that the capitalized implementation costs be reported on debt instruments are clearlythe balance sheet in the same manner as a prepayment and closelythe related to their debt hosts. An entity performingamortization expense in the assessment undersame expense line item on the amendment is required to assessincome statement as the embedded call or put options solelyexpense for the associated cloud computing arrangement, the Company capitalizes implementation costs associated with cloud computing arrangements as a utility plant asset and amortizes the costs in a consistent manner in accordance with the four-step decision sequence.FERC Docket Number AI90-1-000.
This amendment isThe amendments in this update are effective for financial statements issuedpublic business entities for fiscal years beginning after December 15, 2016, including interim periods within those fiscal years. Earlier adoption is permitted for all entities upon issuance. Reporting entities must apply a modified retrospective approach for the adoption of the new standard. The Company plans to adopt ASU 2016-06 during the first quarter of fiscal year 2017. The Company anticipates the new guidance will not have a significant impact on its financial statements.
Statement of Cash Flows
In August 2016, the FASB issued ASU 2016-15, "Statement of Cash Flows (Topic 230): Classification of Certain Cash Receipts and Cash Payments". The amendments in ASU 2016-15 provide guidance for eight specific cash flow issues that include (i) debt prepayment or debt extinguishment costs, (ii) settlement of zero-coupon debt instruments, (iii) contingent consideration payments
made after a business combination, (iv) proceeds from the settlement of insurance claims, (v) proceeds from the settlement of corporate-owned life insurance policies, including bank-owned life insurance policies, (vi) distribution received from equity method investees, (vii) beneficial interest in securitization transactions, and (viii) separately identifiable cash flows and application of the predominance principle. Current GAAP is unclear or does not include specific guidance on the eight cash flow classification issues included in the amendments.
This update is effective for financial statements issued for fiscal years beginning after December 15, 20172019, and interim periods within those fiscal years. Early adoption of the amendments in this update is permitted, including adoption in any interim period, for all entities upon issuance.entities. The amendments in this update should be applied using a retrospective transition methodeither retrospectively or prospectively to each period presented.all implementation costs incurred after the date of adoption. The Company plans to adopt ASU 2016-15 duringadopted this update prospectively
in 2019 for implementation costs incurred in hosting arrangements and application of the first quarter of fiscal year 2018 and is inamendment did not have a material impact on the process of evaluating the impact this standard will have on its consolidated statement of cash flows.financial statements.
Accounting Standards Issued but Not Yet Adopted
Credit Losses
In NovemberJune 2016, the FASB issued ASU 2016-18, "Statement2016-13, "Financial Instruments - Credit Losses (Topic 326): Measurement of Cash Flows (Topic 230): Restricted Cash"Credit Losses on Financial Instruments". The amendments in thisthe update require thatchange how entities account for credit losses on receivables and certain other assets. The guidance requires use of a statementcurrent expected loss model, which may result in earlier recognition of cash flows explaincredit losses than under previous accounting standards. ASU 2016-13 is effective for interim and annual periods beginning on or after December 15, 2019. The Company has analyzed its financial instruments within the change duringscope of the periodguidance and does not expect a material impact to the consolidated financial statements..
Fair Value Measurement
In August 2018, the FASB issued ASU 2018-13, "Fair Value Measurement (Topic 820): Disclosure Framework - Changes to the Disclosure Requirements for Fair Value Measurement". The guidance in ASU No. 2018-13 eliminates such disclosures as the totalamount of cash, cash equivalents, and amounts generally described as restricted cash or restricted cash equivalents.reasons for transfers between Level 1 and Level 2 of the fair value hierarchy. The amendments in ASU No. 2018-13 add new standarddisclosure requirements for Level 3 measurements. ASU No. 2018-13 is effective for fiscal years beginning after December 15, 2017,2019, and interim periods within those fiscal years, beginningwith early adoption permitted for any eliminated or modified disclosures. Certain disclosures in ASU No. 2018-13 are required to be applied on a retrospective basis and others on a prospective basis. As the amendment contemplates changes in disclosures only, it will have no material impact on the Company's results of operations, cash flows, or consolidated balance sheet.
Retirement Benefits
In August 2018, the FASB issued ASU 2018-14, "Compensation—Retirement Benefits—Defined Benefit Plans—General (Subtopic 715-20): Disclosure Framework—Changes to the Disclosure Requirements for Defined Benefit Plans". This update modifies the disclosure requirements for employers that sponsor defined benefit pension or other postretirement plans through added, removed, and clarified requirements of relevant disclosures.
The amendments in this update are effective for fiscal years ending after December 15, 2018.2020, for public business entities and for fiscal years ending after December 15, 2021, for all other entities. Early adoption is permitted for all entities. The Company plansis in the process of evaluating potential impacts of these amendments to adopt ASU 2016-18 duringNote 13, "Retirement Benefits" to the first quarterconsolidated financial statements.
(3) Revenue
The following table presents disaggregated revenue from contracts with customers, and other revenue by major source:
| | | | | | | | | | | |
Puget Energy and Puget Sound Energy | | | |
(Dollars in Thousands) | Year Ended December 31, | | |
Revenue from Contracts with Customers: | 2019 | | 2018 |
Electric retail | $ | 2,132,522 | | | $ | 2,138,008 | |
Natural gas retail | 870,457 | | | 849,898 | |
Other | 308,111 | | | 234,187 | |
Total revenue from contracts with customers | 3,311,090 | | | 3,222,093 | |
Alternative revenue programs | (18,634) | | | (22,852) | |
Other non-customer revenue | 108,674 | | | 147,255 | |
Total operating revenue | $ | 3,401,130 | | | $ | 3,346,496 | |
Revenue at PSE is recognized when performance obligations under the terms of fiscal year 2018a contract or tariff with our customers are satisfied. Performance obligations are satisfied generally through performance of PSE's obligation over time or with transfer of control of electric power, natural gas, and other revenue from contracts with customers. Revenue is measured as the amount of consideration expected to be received in exchange for transferring goods and services.
Electric and Natural Gas Retail Revenue
Electric and natural gas retail revenue consists of tariff-based sales of electricity and natural gas to PSE's customers. For tariff contracts, PSE has elected the portfolio approach practical expedient model to apply the revenue from contracts with customers to groups of contracts. The Company determined that the portfolio approach will not differ from considering each contract or performance obligation separately. Electric and natural gas tariff contracts include the performance obligation of standing ready to perform electric and natural gas services. The electricity and natural gas the customer chooses to consume is considered an option and is recognized over time using the output method when the customer simultaneously consumes the electricity or natural gas. PSE has elected the right to invoice practical expedient for unbilled retail revenue. The obligation of standing ready to perform electric service and the consumption of electricity and natural gas at market value implies a right to consideration for performance completed to date. The Company believes that tariff prices approved by the Washington Commission represent stand-alone selling prices for the performance obligations under ASC 606. PSE collects Washington State excise taxes (which are a component of general retail customer rates) and municipal taxes and presents the taxes on a gross basis, as PSE is the taxpayer for those excise and municipal taxes.
Other Revenue from Contracts with Customers
Other revenue from contracts with customers is primarily comprised of electric transmission, natural gas transportation, biogas, and wholesale revenue sold on an intra-month basis.
Electric Transmission and Natural Gas Transportation
Transmission and transportation tariff contracts include the performance obligation to transmit and transport electricity or natural gas. Transfer of control and recognition of revenue occurs over time as the customer simultaneously receives the transmission and transportation services. Measurement of satisfaction of this performance obligation is determined using the output method. Similar to retail revenue, the Company utilizes the right to invoice practical expedient as PSE’s right to consideration is tied directly to the value of power and natural gas transmitted and transported each month. The price is based on the tariff rates that were approved by the Washington Commission or the FERC and, therefore, corresponds directly to the value to the customer for performance completed to date.
Biogas
Biogas is a renewable natural gas fuel that PSE purchases and sells along with the renewable green attributes derived from the renewable natural gas. Biogas contracts include the performance obligations of biogas and renewable credit delivery upon PSE receiving produced biogas from its supplier. Transfer of control and recognition of revenue occurs at a point in time as biogas is considered a storable commodity and may not be consumed as it is delivered.
Wholesale
Wholesale revenue at PSE includes sales of electric power and non-core natural gas to other utilities or marketers. Wholesale revenue contracts include the performance obligation of physical electric power or natural gas. There are typically no added fixed or variable amounts on top of the established rate for power or natural gas and contracts always have a stated, fixed quantity of power or natural gas delivered. Transfer of control and recognition of revenue occurs at a point in time when the customer takes physical possession of electric power or natural gas. Non-core gas consists of natural gas supply in excess of natural gas used for generation, sold to third parties to mitigate the costs of firm transportation and storage capacity for its core natural gas customers. PSE reports non-core gas sold net of costs as PSE does not anticipatetake control of the new guidance will havenatural gas but is merely an agent within the market that connects a significant impact on its consolidated statement of cash flows.seller to a purchaser.
Other Revenue
In accordance with ASC 606, PSE separately presents revenue not collected from contracts with customers that falls under other accounting guidance. (3)
(4) Regulation and Rates
Regulatory Assets and Liabilities
Regulatory accounting allows 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 that are expected to be returned to customers in the future.
The net regulatory assets and liabilities at December 31, 20162019, and 20152018, included the following:
| | | | | | | | | | | | | | | | | | | |
Puget Sound Energy | Remaining Amortization Period | | | December 31, | | | |
(Dollars in Thousands) | | | | 2019 | | | 2018 |
Storm damage costs electric | 1 to 4 years | | | $ | 121,894 | | | | $ | 118,331 | |
Chelan PUD contract initiation | 11.8 years | | | 83,875 | | | | 90,964 | |
Environmental remediation | (a) | | | 68,486 | | | | 76,345 | |
Lower Snake River | 17.4 years | | | 62,899 | | | | 67,021 | |
Decoupling deferrals and interest | Less than 2 years | | | 43,509 | | | | 65,779 | |
Baker Dam licensing operating and maintenance costs | N/A | | | 56,427 | | | | 55,607 | |
Deferred Washington Commission AFUDC | 30 years | | | 57,553 | | | | 52,029 | |
Property tax tracker | Less than 2 years | | | 22,442 | | | | 45,621 | |
Unamortized loss on reacquired debt | 2 to 48 years | | | 40,177 | | | | 42,378 | |
Colstrip 1 & 2 Regulatory Asset | N/A | | | — | | | | 37,674 | |
Energy conservation costs | (a) | | | 25,272 | | | | 30,701 | |
Get to zero depreciation expense deferral | N/A | | | 22,148 | | | | — | |
Advanced metering infrastructure | (a) | | | 14,845 | | | | — | |
Generation plant major maintenance, excluding Colstrip | 3 to 10 years | | | 12,744 | | | | 15,027 | |
PGA deferral of unrealized losses on derivative instruments | N/A | | | — | | | | 14,739 | |
White River relicensing and other costs | 1 year | | | 6,399 | | | | 12,966 | |
Mint Farm ownership and operating costs | 5.3 years | | | 10,318 | | | | 12,319 | |
PGA receivable | 2 years | | | 132,766 | | | | 9,922 | |
Snoqualmie licensing operating and maintenance costs | N/A | | | 7,442 | | | | 7,407 | |
Colstrip major maintenance | 0.0 years | | | 2,929 | | | | 6,841 | |
PCA mechanism | N/A | | | 41,745 | | | | 4,735 | |
Colstrip common property | 4.4 years | | | 3,188 | | | | 3,903 | |
Ferndale | 0.0 years | | | — | | | | 3,316 | |
Various other regulatory assets | (a) | | | 10,474 | | | | 14,583 | |
Total PSE regulatory assets | | | | $ | 847,532 | | | | $ | 788,208 | |
Deferred income taxes (d) | N/A | | | (946,936) | | | | (976,582) | |
Cost of removal | (b) | | | (469,922) | | | | (424,727) | |
Treasury grants | 18 years | | | (101,981) | | | | (168,884) | |
Production tax credits | (c) | | | (85,323) | | | | (93,616) | |
Gain on Sale Shuffleton | N/A | | | (12,483) | | | | — | |
Microsoft special contract regulatory liability | N/A | | | (12,661) | | | | — | |
Repurposed production tax credits | N/A | | | (23,171) | | | | — | |
Accumulated provision for rate refunds | N/A | | | — | | | | (34,579) | |
| | | | | | | |
| | | | | | | |
Total decoupling liability | Less than 2 years | | | (8,500) | | | | (13,758) | |
| | | | | | | |
Various other regulatory liabilities | (a) | | | (15,573) | | | | (10,316) | |
Total PSE regulatory liabilities | | | | (1,676,550) | | | | (1,722,462) | |
PSE net regulatory assets (liabilities) | | | | $ | (829,018) | | | | $ | (934,254) | |
__________________
(a)Amortization periods vary depending on timing of underlying transactions.
(b)The balance is dependent upon the cost of removal of underlying assets and the life of utility plant.
(c)Amortize as PTCs are utilized by PSE on its tax return.
(d)For additional information, see Note 14,"Income Taxes" to the consolidated financial statements included in Item 8 of this report.
|
| | | | | | | | | | | |
Puget Sound Energy | Remaining Amortization Period | December 31, |
(Dollars in Thousands) | 2016 | 2015 |
Colstrip Regulatory Asset | (a) | | $ | 176,804 |
| | $ | — |
|
Storm damage costs electric | 1 to 2 years | | 122,709 |
| | 125,777 |
|
Chelan PUD contract initiation | 14.8 years | | 105,140 |
| | 112,228 |
|
Decoupling deferrals and interest | | 156,408 |
|
|
| 104,150 |
| |
Decoupling 24-month revenue reserve | | (20,847 | ) | | (9,980 | ) | |
Total decoupling asset | Less than 2 years | | 135,561 |
| | 94,170 |
|
Lower Snake River | 1 to 20.3 years | | 74,862 |
| | 79,599 |
|
Deferred income taxes | (a) | | 71,517 |
| | 72,694 |
|
Environmental remediation | (a) | | 74,557 |
| | 66,887 |
|
Baker Dam licensing operating and maintenance costs | 42 years | | 61,453 |
| | 63,394 |
|
PGA deferral of unrealized losses on derivative instruments | (a) | | — |
| | 60,889 |
|
Deferred Washington Commission AFUDC | 35 years | | 51,404 |
| | 52,197 |
|
Unamortized loss on reacquired debt | 1 to 30 years | | 42,196 |
| | 44,984 |
|
Property tax tracker | Less than 2 years | | 41,949 |
| | 40,353 |
|
Energy conservation costs | 1 to 2 years | | 41,027 |
| | 36,646 |
|
White River relicensing and other costs | 15.9 years | | 21,627 |
| | 23,054 |
|
Mint Farm ownership and operating costs | 8.3 years | | 16,319 |
| | 18,320 |
|
Ferndale | 2.8 years | | 11,274 |
| | 15,253 |
|
Electron unrecovered loss | 2 years | | 7,178 |
| | 10,569 |
|
Snoqualmie licensing operating and maintenance costs | 28 years | | 8,018 |
| | 7,980 |
|
Colstrip common property | (a) | | 5,334 |
| | 6,049 |
|
Colstrip major maintenance | 2 years | | 6,589 |
| | 5,897 |
|
Investment in Bonneville Exchange power contract | 1 year | | 1,763 |
| | 5,290 |
|
Snoqualmie | 1.8 years | | 3,251 |
| | 5,024 |
|
PCA mechanism | (a) | | 4,531 |
| | — |
|
PGA receivable | 1 year | | 2,785 |
| | — |
|
Various other regulatory assets | Varies | | 25,337 |
| | 24,248 |
|
Total PSE regulatory assets | | | 1,113,185 |
| | 971,502 |
|
Cost of removal | (b) | | (369,300 | ) | | (347,472 | ) |
Treasury grants | 3 to 42 years | | (133,709 | ) | | (157,102 | ) |
Production tax credits | (c) | | (93,616 | ) | | (93,616 | ) |
Decoupling ROR excess earnings | | (13,300 | ) | | (25,483 | ) | |
Decoupling deferrals and interest | | (16,448 | ) | | — |
| |
Total decoupling liability | Less than 2 years | | (29,748 | ) | | (25,483 | ) |
PGA payable | 1 year | | — |
| | (12,589 | ) |
Summit purchase option buy-out | 3.8 years | | (6,038 | ) | | (7,612 | ) |
Deferral of treasury grant amortization | Less than 3 years | | (3,920 | ) | | (6,058 | ) |
PGA deferral of unrealized gains on derivative instruments | (a) | | (7,517 | ) | | — |
|
Lower Snake River interest due | Less than 2 years | | (4,189 | ) | | — |
|
Various other regulatory liabilities | Up to 4 years | | (5,259 | ) | | (13,751 | ) |
Total PSE regulatory liabilities | | | (653,296 | ) | | (663,683 | ) |
PSE net regulatory assets (liabilities) | | | $ | 459,889 |
| | $ | 307,819 |
|
| | | | | | | | | | | | | | |
Puget Energy | Remaining Amortization Period | December 31, | | |
(Dollars in Thousands) | | 2019 | | 2018 |
Total PSE regulatory assets | (a) | $ | 847,532 | | | $ | 788,208 | |
Puget Energy acquisition adjustments: | | | | |
Regulatory assets related to power contracts | 6 to 33 years | 14,146 | | | 16,693 | |
| | | | |
Total Puget Energy regulatory assets | | 861,678 | | | 804,901 | |
Total PSE regulatory liabilities | (a) | (1,676,550) | | | (1,722,462) | |
Puget Energy acquisition adjustments: | | | | |
Deferred income taxes | | 757 | | | 608 | |
Regulatory liabilities related to power contracts | 6 to 33 years | (156,597) | | | (162,711) | |
Various other regulatory liabilities | Varies | (1,265) | | | (1,323) | |
Total Puget Energy regulatory liabilities | | (1,833,655) | | | (1,885,888) | |
Puget Energy net regulatory asset (liabilities) | | $ | (971,977) | | | $ | (1,080,987) | |
_______________
| |
(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. |
____________________
(a)Puget Energy’s regulatory assets and liabilities include purchase accounting adjustments under ASC 805. |
| | | | | | | |
Puget Energy | Remaining Amortization Period | December 31, |
(Dollars in Thousands) | 2016 | 2015 |
Total PSE regulatory assets | (a) | $ | 1,113,185 |
| $ | 971,502 |
|
Puget Energy acquisition adjustments: | | |
| |
|
Regulatory assets related to power contracts | 1 to 21 years | 22,613 |
| 26,223 |
|
Various other regulatory assets | Varies | 517 |
| 549 |
|
Total Puget Energy regulatory assets | | 1,136,315 |
| 998,274 |
|
Total PSE regulatory liabilities | (a) | (653,296 | ) | (663,683 | ) |
Puget Energy acquisition adjustments: | | |
| |
|
Regulatory liabilities related to power contracts | 1 to 36 years | (275,061 | ) | (325,788 | ) |
Various other regulatory liabilities | Varies | (1,326 | ) | (1,347 | ) |
Total Puget Energy regulatory liabilities | | (929,683 | ) | (990,818 | ) |
Puget Energy net regulatory asset (liabilities) | | $ | 206,632 |
| $ | 7,456 |
|
_______________
| |
(a)
| Puget Energy’s regulatory assets and liabilities include purchase accounting adjustments under ASC 805. |
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’sCompany's financial statements.
In accordance with guidance provided by ASC 410, “Asset Retirement and Environmental Obligations (ARO),” PSE reclassified from accumulated depreciation to a regulatory liability $369.3$469.9 million and $347.5$424.7 million in 20162019 and 2015,2018, respectively, for the cost of removal of utility plant. These amounts are collected from PSE’s customers through depreciation rates.
2013 ExpeditedGeneral Rate Case Filing Decoupling and Centralia Decision
PSE filed a settlement agreementGRC with the Washington Commission on March 22, 2013. The agreement was intendedJune 20, 2019, requesting an overall increase in electric and natural gas rates of 6.9% and 7.9% respectively. PSE requested a return on equity of 9.8% with an overall rate of return of 7.62%. In addition to settle all issues regarding decoupling,the traditional areas of focus (revenue requirements, cost allocation, rate design and cost of capital), the Company completed an attrition study and included a power purchase agreement with TransAlta Centraliaportion of the attrition revenue requirement in the overall request in order address the expected regulatory lag in the rate year. Additionally, as the non-plant related excess deferred taxes that resulted from the Tax Cuts and theJobs Act (TCJA) remained outstanding from PSE’s Expedited Rate Filing (ERF) which is limitedas discussed below, PSE requested in scope and rate impact, includesits GRC to pass back the property tax tracker, and is intended to establish baseline rates on which the decoupling mechanisms are to operate. The Washington Commission placed the ERF and decoupling filings underamounts over four years. On September 17, 2019, PSE filed a common procedural schedule.
On June 25, 2013, the Washington Commission issued final orders resolving the amended decoupling petition, the ERFsupplemental filing and the Petition for Reconsideration (related to the TransAlta Centralia power purchase agreement). Order No. 7 in the ERF/decoupling proceeding approved PSE's ERFGRC, which provided updates as discussed in our original filing, with a small change to its cost of capital from 7.80% to7.77% to update long term debt costsbut did not impact the requested overall electric and a capital structure that included 48.0% common equity with anatural gas rate increases, return on equity (ROE) of 9.8%. This order also approved the property tax tracker discussed below and approved the amended decoupling and rate plan filing with the further condition that PSE and the customers will share 50.0% each in earnings in excess of the 7.77% authorizedor overall rate of return. In addition,return as originally filed. On January 15, 2020, PSE filed rebuttal testimony which included a reduction to the requested return on equity to 9.5%, which decreased the rate plan (K-Factor)of return to 7.48%.The requested rate increase allowed decoupling revenue per customer for both electric and natural gas remained at 6.9% and 7.9%, respectively. For both electric and natural gas PSE did not originally request its full attrition adjustment; therefore, the recovery of delivery system costsdecrease in return on equity led to subsequently increase by 3.0% fora reduction in the electric customersrate increase of only $1.5 million and 2.2% fordid not have an impact on the natural gas customers onrate increase.
In January 1 of each year, until the conclusion of PSE's next General Rate Case (GRC), which was filed on January 13, 2017. In the rate plan, increases are subject to a cap of 3.0% of the total revenue for customers.
General Rate Case Filing
On March 17, 2016, the Washington Commission approved a joint petition postponing the filing of PSE’s GRC until no later than January 17, 2017. As part of the petition, PSE agreed to update power costs on December 1, 2016 in conjunction with the Centralia PPA compliance filing. Additionally, PSE agreed to include in its GRC filing a plan for closure of coal fired steam electric generation facility in Colstrip, Montana (Colstrip) Units 1 and 2, of which PSE owns a 50% interest. Monthly allowed revenue per customer includes an automatic annual increase and will continue through December 2017 when new rates go into effect from PSE's 2017 GRC.
On January 13, 2017, PSE filed its GRC with the Washington Commission. The GRC filing included a required plan to address Colstrip Units 1 and 2 closures, requested that electric energy supply fixed costs be included in PSE's decoupling mechanism, and contained requests for 2 new mechanisms to address regulatory lag. The Washington Commission which proposedentered a final order accepting the multi-party settlement agreement and determined the contested issues in the case on December 5, 2017, and new rates became effective December 19, 2017. The settlement agreement provided for a weighted cost of capital of 7.74%7.6%, or 6.69%6.55% after-tax, and a capital structure of 48.5% in common equity with a return on equity of 9.8%9.5%. The requestedsettlement also resulted in a combined electric tariff changes would resultchange that resulted in a net increase of $86.3$20.2 million, or 4.1%. The requested0.9%, annually, and a combined natural gas tariff
changes would result change that resulted in a net decrease of $22.3$35.5 million, or 2.4%. 3.8%, annually.
The filing was subsequently suspended, which means that2017 GRC also re-purposed the final rates granted in the proceeding will go into effect no later than December 13, 2017.
PSE’s GRC filing included the required planbenefit of hydro-related treasury grants to fund and recover decommissioning and remediation costs for Colstrip Units 1 and 2 closures, see Item 3, "Legal Proceedings"2.
Expedited Rate Filing Rate Adjustment
On November 7, 2018, PSE filed an expedited rate filing (ERF) with the Washington Commission. The filing requested to change rates associated with PSE’s delivery and fixed production costs. It did not include variable power costs, purchased gas costs or natural gas pipeline replacement program costs, which are recovered in separate mechanisms. The filing was based on historical test year costs and rate base, and followed the reporting requirements of a Commission Basis Report, as defined by the Washington Administrative Code, but used end of period rate base and certain annualizing adjustments. It did not include any forward-looking or pro-forma adjustments. Included in the filing was a reduction to the consolidated financial statementsoverall authorized rate of return from 7.6% to 7.49% to recognize a reduction in debt costs associated with recent debt activity. PSE requested an overall increase in electric rates of $18.9 million annually, which is a 0.9% increase, and an overall increase in natural gas rates of $21.7 million annually, which is a 2.7% increase.
On January 22, 2019, all parties in the proceeding reached an agreement on settlement terms that resolved all issues in the filing. The settlement agreement was filed on January 30, 2019. The parties agreed to a $21.5 million for natural gas and 0 rate increase for electric which became effective March 1, 2019. As is discussed below, these rates include the offsetting effect of passing back to customers plant related excess deferred income taxes that resulted from the TCJA, using the average rate assumption method (ARAM) amounts to arrive at the settlement rate changes.
The settlement agreement provides for the pass back of plant related excess deferred income taxes that resulted from the TCJA using the ARAM methodology based on 2018 amounts beginning March 1, 2019, in the amount of $6.1 million for natural gas customers and $25.9 million for electric customers. The settlement agreement left the determination for the regulatory treatment of the remaining items related to the TCJA, listed below, to PSE’s next GRC, filed June 20, 2019:
1)excess deferred taxes for non-plant-related book/tax differences for periods prior to March 1, 2019,
2)the deferred balance associated with the over-collection of income tax expense for the period January 1 through April 30, 2018 (the time period that encompasses the effective date of the TCJA to May 1, 2018, the effective date of the TCJA rate change); and
3)the turnaround of plant related excess deferred income taxes using the ARAM method for the period from January 2018 through February 2019, the rate effective date for the ERF.
The agreement provides that PSE may defer the depreciation expense associated with PSE’s ongoing investment in its advanced metering infrastructure (AMI) investment and may defer the return on the AMI investment that was included in Item 8the test year of the filing. The agreement preserves the parties' rights to argue whether or not these deferrals should be recovered in the Company’s 2019 GRC. The rate of return adopted in the settlement for reporting and deferral purposes is 7.49% . On February 21, 2019, the Washington Commission approved the settlement with one condition: PSE must pass back the deferred balance associated with the tax over-collection of $34.6 million for the period from January 1, 2018, through April 30, 2018, over a one-year period which began May 1, 2019.
Washington Commission Tax Deferral Filing
The TCJA was signed into law in December 2017. As a result of this report.change, PSE re-measured its deferred tax balances under the new corporate tax rate. PSE filed an accounting petition on December 29, 2017, requesting deferred accounting treatment for the impacts of tax reform. The requested deferral accounting treatment resulted in the tax rate change being captured in the deferred income tax balance with an offset to the regulatory liability for deferred income taxes for GAAP purposes. Additionally, PSE’s filing contains requestson March 30, 2018, PSE filed for two new mechanisms to address regulatory lag. PSE has requested proceduresa rate change for an ERF that can be used to update PSE’s delivery revenues on an expedited basis following a GRC proceeding. PSE also requested approval to establish an electric CRM similar to its existingand natural gas CRMcustomers associated with TCJA to reflect the decrease in the federal corporate income tax rate from 35.0% to 21.0%. The overall impact of the rate change, based on the annual period from May 2018 through April 2019, is a revenue decrease of $72.9 million, or 3.4%, for electric and $23.6 million, or 2.7%, for natural gas and became effective May 1, 2018, by operation of law.
The March 30, 2018, rate change filing did not address excess deferred taxes or the deferred balance associated with the over-collection of income tax expense of $34.6 million for the period January 1 through April 30, 2018 (the time period that encompasses the effective date of the TCJA through May 1, 2018, the effective date of the rate change). The $34.6 million tax over-collection decreased PSE's revenue and increased the regulatory liability for a refund to customers.
As a result of the Washington Commission's final order in the ERF, the excess deferred taxes associated with non-plant-related book/tax differences and the treatment of the excess deferred taxes associated with plant related book/tax differences from January 1, 2019, through February 28, 2019, was addressed in PSE’s GRC, which would allowwas filed on June 20, 2019. The Washington Commission also required in the ERF order that PSE to obtain accelerated cost recovery on specified electric reliability projects.pass back the deferred balance associated with the tax over-collection for the period from January 1, 2018, through April 30, 2018, as discussed above, over a one-year period which began May 1, 2019.
Decoupling Filings
While fluctuations in weather conditions will continue to affect PSE's billed revenue and energy supply expenses from month to month, PSE's decoupling mechanisms are expected to mitigateassist in mitigating the impact of weather on operating revenue and net income. TheSince July 2013, the Washington Commission has allowed PSE to record a monthly adjustment to its electric and natural gas operating revenues related to electric transmission and distribution, natural gas operations and general administrative costs from most residential, commercial and industrial customers to mitigate the effects of abnormal weather, conservation impacts and changes in usage patterns per customer. As a result, these electric and natural gas revenues will beare recovered on a per customer basis regardless of actual consumption levels. ThePSE's energy supply costs, which are part of the PCA and PGA mechanisms, are not included in the decoupling mechanism. The revenue recorded under the decoupling mechanisms will be affected by customer growth and not actual consumption. Following each calendar year, PSE will recover from, or refund to, customers the difference between allowed decoupling revenue and the corresponding actual revenue to affected customers over a 12-month period beginningduring the following May.May to April time period.
On December 5, 2017, the Washington Commission approved PSE’s request within the 2017 GRC to extend the decoupling mechanism with several changes to the methodology that took effect on December 19, 2017. Electric and natural gas delivery revenues continue to be recovered on a per customer basis and electric fixed production energy costs are now decoupled and recovered on the basis of a fixed monthly amount. The allowed decoupling revenue for electric and natural gas customers will no longer increase annually each January 1 as occurred prior to December 19, 2017. Approved revenue per customer costs can only be changed in a GRC or ERF. Approved electric fixed production energy costs can also be changed in a power cost only rate case (PCORC). Other changes to the decoupling methodology approved by the Washington Commission include regrouping of electric and natural gas non-residential customers and the exclusion of certain electric schedules from the decoupling mechanism going forward. The rate test, which limits the amount of revenues PSE can collect in its annual filings, increased from 3.0% to 5.0% for natural gas customers but will remain at 3.0% for electric customers. The decoupling mechanism will end on December 31, 2017 unless the continuation of the requestedbe reviewed again in PSE’s first rate case filed in or after 2021, or in a separate proceeding, if appropriate. PSE’s decoupling mechanism is approved in PSE's 2017 GRC which PSE filed on January 13, 2017. Decoupling overover- and underunder- collections will still be collectible or refundable after December 31, 2017,this effective date even if the decoupling mechanism is not extended.
TheOn February 21, 2019, the Washington Commission approved the followingmulti-party settlement agreement which was filed within PSE’s ERF filing. As part of this settlement agreement, electric and natural gas allowed delivery revenue per customer was updated to reflect changes in the approved revenue requirement. For electric, there were no changes to the annual allowed fixed power cost revenue. The changes took effect on March 1, 2019.
On December 31, 2019, PSE requestsperformed an analysis to change rates under itsdetermine if electric and natural gas decoupling mechanisms:
|
| | |
Effective Date | Average Percentage Increase (Decrease) in Rates | Increase (Decrease) in Revenue (Dollars in Millions) |
Electric: | | |
May 1, 2016 | 1.0% | $20.8 |
May 1, 2015 | 2.6 | 53.8 |
May 1, 2014 | 0.5 | 10.6 |
Natural Gas: | | |
May 1, 2016 | 2.8% | $25.4 |
May 1, 2015 | 2.1 | 22.0 |
May 1, 2014 | (0.1) | (1.0) |
As partrevenue deferrals would be collected from customers within 24 months of the April 22, 2015 filing,annual period, per ASC 980. If not, for GAAP purposes only, PSE requestedwould need to changerecord a reserve against the methodologydecoupling revenue and regulatory asset balance. Once the reserve is probable of how decoupling deferrals are calculated going forward and adjust deferrals calculated in 2014. The change was done to ensure thatcollection within 24 months from the amortization of prior years’ accumulated decoupling deferrals were not included in the calculationend of the current yearannual period, the reserve can be recognized as decoupling deferrals.revenue. The effect of the methodology change was a reduction of approximately $12.0 million of previously recognized revenue from May through December of 2014.
In addition, PSE exceeded the earnings test threshold in 2016, 2015 and 2014. The amount of the reduction to the 2016 decoupling deferral will not be known until the final earnings test result is filed in PSE's decoupling mechanism filinganalysis indicated that will be made on March 31, 2017.
PSE recorded the following reductions in decoupling deferrals to the electric and natural gas rate increases above:
|
| |
Effective Date | Reduction in Rate Increases due to Excess Earnings (Dollars in Millions) |
Electric: | |
2016 (estimated) | $11.2 |
2015 | 16.3 |
2014 | 3.4 |
Natural Gas: | |
2016 (estimated) | $2.1 |
2015 | 9.2 |
2014 | — |
As noted earlier, the Company is also limited to a 3.0% annual decoupling related cap on increases in total revenue. This limitation has been triggered as follows:
|
| |
Effective Date Accrued Through | Deferrals not Included in Annual Rate Increases (Dollars in Millions) |
Electric: | |
2015 | $— |
2014 | 1.9 |
Natural Gas: | |
2015 | $28.7 |
2014 | 8.2 |
Existing deferrals maydeferred revenue will be included in customer rates beginning in May 2018, subject to subsequent applicationcollected within 24 months of the earnings test and the 3.0% cap onannual period; therefore, no adjustment was booked to 2019 decoupling related rate increases.
Electric Regulation and Rates
Storm Damage Deferral Accounting
revenue. The Washington Commission issued a GRC order that defined deferrable catastrophic/extraordinary losses and provided that costs in excesspreviously unrecognized decoupling deferrals 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 2016 and 2015, PSE incurred $22.0$0.8 million and $33.6$20.8 million respectively,at December 31, 2018, and December 31, 2016, were recognized as decoupling revenue in storm-related electric transmissionthe year ended December 31, 2019, and distribution system restoration costs, of which $12.4 million was deferred in 2016 and $22.4 million was deferred in 2015.December 31, 2017, respectively.
Power Cost Adjustment Mechanism
PSE currently has a PCA mechanism that provides for the deferral of power costs that 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 savings are apportioned between PSE and its customers pursuant to the graduated scale set forth in the PCA mechanism and will trigger a surcharge or refund when the cumulative deferral trigger is reached.
TheEffective January 1, 2017, the following graduated scale thatis used in the PCA mechanism:
| | | | | | | | | | | | | | | | | | | | | | | |
| Company’s Share | | | | Customers' Share | | |
Annual Power Cost Variability | Over | | Under | | Over | | Under |
Over or Under Collected by up to $17 million | 100 | % | | 100 | % | | — | % | | — | % |
Over or Under Collected by between $17 million - $40 million | 35 | | | 50 | |
| 65 | | | 50 | |
Over or Under Collected beyond $40 + million | 10 | | | 10 | |
| 90 | | | 90 | |
In September 2016, PSE filed an accounting petition with the Washington Commission which requested deferral of the variances, either positive or negative, between the fixed costs previously recovered in the PCA and the revenue received to cover the allowed fixed costs. The deferral period requested was applicableJanuary 1, 2017, through December 31, 2017, when rates were to go into effect from PSE's 2017 GRC. In November 2016, was as follows:
|
| | |
Annual Power Cost Variability | Company’s Share | Customers' Share |
+/- $20 million | 100% | —% |
+/- $20 million - $40 million | 50 | 50 |
+/- $40 million - $120 million | 10 | 90 |
+/- $120 + million | 5 | 95 |
On August 7, 2015, the Washington Commission issued an orderOrder No. 01 approving PSE’s accounting petition. With the settlement proposing changes tofinal determination in PSE’s GRC, this deferral ceased with the PCA mechanism. The settlement agreement took effect January 1, 2017 and will apply the following graduated scale:rate effective date of December 19, 2017.
|
| | | | | |
Annual Power Cost Variability | Company's Share | Customers' Share |
Over or Under Collection: | Over | Under | Over | Under |
Over or Under Collected by up to $17 million | 100% | 100% | —% | —% |
Over or Under Collected by between $17 million - $40 million | 35 | 50 | 65 | 50 |
Over or Under Collected beyond $40 + million | 10 | 10 | 90 | 90 |
The settlement also resulted in the following changes to the PCA mechanism:
Reduction to the cumulative deferral trigger for surcharge or refund from $30.0 million to $20.0 million;
Removal of fixed production costs from the PCA mechanism and placing them in the decoupling mechanism, assuming the decoupling mechanism continues after its review in the 2017 GRC. If decoupling was not to continue, those fixed production costs would be treated the same as other non-PCA costs unless permission to treat them in another manner is obtained from the Washington Commission. These fixed production costs include: (i) return and depreciation/amortization on fixed production assets and regulatory assets and liabilities; (ii) return on depreciation, transmission expense and revenues on specific transmission assets; and (iii) hydro, other production and other power related expenses and O&M costs;
Suspension of the requirement that a GRC must be filed within three months after rates are approved in a Power Cost Only Rate Case (PCORC);
Agreement, for a five-year period, that PSE will not file a GRC or PCORC within six months of the date rates go into effect for a PCORC filing; and
Establishment of a five-year moratorium on changes to the PCA.
PSE had an annual PCA receivable duringFor the year ended December 31, 2016, due2019, in its PCA mechanism, PSE under recovered its allowable costs by $67.2 million of which $36.0 million was apportioned to under recoveringcustomers and $1.0 million of power costs of which no amounts were apportioned to customers.interest was accrued on the deferred customer balance. This compares to an annual PCA receivableunder recovery of $8.7allowable costs of $3.5 million for the year ended December 31, 20152018, of which no0 amounts were apportioned to customers. The change was drivencustomers and accrued $0.2 million of interest on the total deferred customer balance. Power costs have been higher than the allowed base line in 2019 which has led to an increase in the PCA deferral causing a higher under-collection compared to the prior year. Actual power costs were higher than baseline rates in 2018 also but by a decrease in actual costs.
Federal Incentive Tracker Tariff
The following table sets forth Federal Incentive Tracker Tariff rate adjustments approved by the Washington Commission and the corresponding impact on PSE’s revenue based on the effective dates:
|
| | |
Effective Date | Average Percentage Increase (Decrease) in Rates from prior year | Total credit to be passed back to eligible customers (Dollars in Millions) |
January 1, 2017, proposed | 0.3% | $(51.7) |
January 1, 2016 | (0.2) | (57.3) |
January 1, 2015 | (0.2) | (55.2) |
January 1, 2014 | (0.3) | (58.5) |
Power Cost Only Rate Case and Update Compliance Filing
The following table sets forth PCORC and update compliance filing rate adjustments approved by the Washington Commission and the corresponding impact on PSE’s revenue based on the effective dates:
|
| | |
Effective Date | Average Percentage Increase (Decrease) in Rates | Increase (Decrease) in Revenue (Dollars in Millions) |
December 1, 2016 | (1.7)% | $(37.3) |
December 1, 2014 | (0.9) | (19.4) |
Electric Property Tax Tracker Mechanism
The following table sets forth property tax tracker mechanism rate adjustments approved by the Washington Commission and the corresponding impact on PSE’s revenue based on the effective dates:
|
| | |
Effective Date | Average Percentage Increase (Decrease) in Rates | Increase (Decrease) in Revenue (Dollars in Millions) |
May 1, 2016 | 0.3% | $5.7 |
May 1, 2015 | 0.3 | 6.5 |
May 1, 2014 | 0.5 | 11.0 |
Electric Conservation Rider
The following table sets forth conservation rider rate adjustments approved by the Washington Commission and the corresponding impact on PSE’s revenue based on the effective dates:
|
| | |
Effective Date | Average Percentage Increase (Decrease) in Rates | Increase (Decrease) in Revenue (Dollars in Millions) |
May 1, 2017, proposed | 0.7% | $16.5 |
May 1, 2016 | (0.5) | (11.7) |
May 1, 2015 | 0.2 | 4.2 |
May 1, 2014 | 0.6 | 12.2 |
Accounting Orders and Petitions
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 millionnarrower margin, resulting in lower under-collection. Power prices increased during 2019 as compared to the prior year due to: (i) Cold weather in February and early March, which drove regional loads and demand for power up; (ii) Westcoast pipeline capacity limitations, which contributed to higher natural gas and power prices; (iii) An outage on a pre-tax gain of approximately $60.0 million. A final order was rendered on September 11, 2014transmission line, which authorized PSE to retain $7.5 million of the gain and return $52.7 million to customers. The customer portion was bookedcontributed to a regulatory liability accountliquidity crisis at Mid-C and resulted in other current liabilitieshigh market power prices; and accrued interest at PSE's after-tax rate(iv) The relative prices of return. PSE paid this amount to customers through a bill credit innatural gas and power, which reduced the monthsupply of December 2014.natural gas-fired generation and increased the demand for market power, increasing prices.
Natural Gas Regulation and Rates
Natural Gas General Rate Cases and Other Filings Affecting Rates
Purchased Gas Adjustment
For the year ended December 31, 2018, PSE had a beginning PGA payable balance of $16.1 million, incurred actual natural gas costs of $319.3 million, of which $292.0 million was recovered through rates. The following table sets forthdifference between actual and allowed costs, less interest $1.3 million, resulted in a PGA receivable of $9.9 million. For the year ended December 31, 2019, PSE had incurred actual natural gas costs of $406.2 million, of which $289.9 million was recovered through rates. The difference between actual and allowed costs, plus interest of $6.6 million, resulted in a PGA receivable of $132.8 million.
On April 25, 2019, the Washington Commission approved PSE’s request for an out-of-cycle change to PGA rates with the rate adjustmentschange taking effect May 1, 2019. The out-of-cycle PGA filing was needed to begin amortizing a large PGA commodity deferral balance that had grown due to higher than projected commodity costs during the 2018/19 winter. These higher than projected commodity costs were primarily due to an October 9, 2018, rupture and subsequent explosion on Westcoast Pipeline which is one of the major pipelines feeding PSE’s distribution system. The pipeline was repaired in October 2018, however supply capacity on the pipeline was limited over the 2018/19 winter leading to higher prices. February weather was also much colder than normal which also increased the demand for natural gas. The amortization period will be from May 2019 through April 2020.
On October 24, 2019, the Washington Commission approved PSE’s request for November 2019 PGA rates, with the rate change taking effect on November 1, 2019. As part of that filing, PSE requested PGA rates increase annual revenue by $17.8 million, while the new tracker rates increased by annual revenue of $100.6 million; this was in addition to continuing the collection on the remaining balance of $54.0 million from the out-of-cycle PGA. The tracker rates include deferral balances for the three separate amounts: (i) $114.4 million of under collected commodity balances deferred in February and March; (ii) a $10.8 million balance of over-collected commodity costs for the 2018 PGA, and (iii) a $4.1 million remaining balance from the $54.7 million credit to customers, caused by the 2017 over-collection, established in the 2018 tracker. The high commodity deferral balances for winter months through March 2019 were the result of three noteworthy events last winter experienced by PSE: the Enbridge pipeline rupture, unusually low temperatures in February and March, and a compressor failure in February at the Jackson Prairie storage facility. Additionally, to reduce customer impact, as part of the approved PGA filing, PSE will be collecting $114.4 million commodity deferrals and related interest over a two year period, instead of the historic one year period, from November 2019 through October 2021.
Get to Zero Depreciation Deferral
On April 10, 2019, PSE filed an accounting petition with the Washington Commission, requesting authorization to defer depreciation expense associated with Get To Zero (GTZ) projects that were placed in service after June 30, 2018. The GTZ project consists of a number of short-lived technology upgrades. The depreciation expense associated with the GTZ projects with lives of 10 years or less that were placed in service after June 30, 2018, were deferred beginning May 1 per the petition request. For the year ended December 31, 2019, PSE deferred $21.7 million of depreciation expense for GTZ. In addition to the deferral of depreciation expense, PSE had also requested to defer carrying charges on the GTZ deferral, to be calculated utilizing the Company’s currently authorized after tax rate of return, or 6.89% per the 2018 ERF. For the year ended December 31, 2019, PSE deferred $0.5 million of carrying charges on the deferral. The GTZ accounting petition was consolidated with
PSE’s 2019 GRC and is currently being reviewed by the Washington CommissionCommission. If authorized, both the GTZ depreciation and the corresponding impact on PSE’s revenue basedinterest on the effective dates:deferral will be begin amortizing over three years in May 2020
|
| | |
Effective Date | Average Percentage Increase (Decrease) in Rates | Increase (Decrease) in Revenue (Dollars in Millions) |
November 1, 2016 | (0.4)% | $(4.1) |
November 1, 2015 | (17.4) | (185.9) |
November 1, 2014 | 2.5 | 23.3 |
Cost Recovery MechanismStorm Damage Deferral Accounting
The following table sets forth CRM rate adjustments approved by the Washington Commission issued a GRC order that defined deferrable storm events and provided that costs in excess of the corresponding impact on PSE’s revenue based onannual cost threshold may be deferred for qualifying storm damage costs that meet the effective dates:
|
| | |
Effective Date | Average Percentage Increase (Decrease) in Rates | Increase (Decrease) in Revenue (Dollars in Millions) |
November 1, 2016 | 0.6% | $5.6 |
November 1, 2015 | 0.5 | 5.3 |
November 1, 2014 | 0.2 | 2.3 |
Natural Gas Property Tax Tracker Mechanism
The following table sets forth property tax tracker mechanism rate adjustments approved bymodified Institute of Electrical and Electronics Engineers outage criteria for system average interruption duration index. For the year ended December 31, 2019, PSE incurred $39.3 million in storm-related electric transmission and distribution system restoration costs, of which the Company deferred $0.4 million and $28.5 million as regulatory assets related to storms that occurred in 2018 and 2019, respectively. This compares to $25.4 million incurred in storm-related electric transmission and distribution system restoration costs for the year ended December 31, 2018, of which the Company deferred $3.3 million and $11.9 million as regulatory assets related to storms that occurred in 2017 and 2018, respectively. Under the December 5, 2017, Washington Commission order regarding PSE’s GRC, the following changes to PSE’s storm deferral mechanism were approved: (i) the cumulative annual cost threshold for deferral of storms under the mechanism increased from $8.0 million to $10.0 million effective January 1, 2018; and (ii) qualifying events where the corresponding impact on PSE’s revenue based ontotal qualifying cost is less than $0.5 million will not qualify for deferral and these costs will also not count toward the effective dates:$10.0 million annual cost threshold.
|
| | |
Effective Date | Average Percentage Increase (Decrease) in Rates | Increase (Decrease) in Revenue (Dollars in Millions) |
May 1, 2016 | 0.4% | $3.5 |
June 1, 2015 | (0.2) | (2.3) |
May 1, 2014 | 0.6 | 5.6 |
Natural Gas Conservation Rider
The following table sets forth conservation rider rate adjustments approved by the Washington Commission and the corresponding annual impact on PSE’s revenue based on the effective dates:
|
| | |
Effective Date | Average Percentage Increase (Decrease) in Rates | Increase (Decrease) in Revenue (Dollars in Millions) |
May 1, 2017, proposed | (0.1)% | (1.0) |
May 1, 2016 | 0.3 | 2.9 |
May 1, 2015 | 0.2 | 2.3 |
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 agencyEnvironmental 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 natural gas and electric methodological approaches to remediation and deferred accounting in an order issued October 8, 2008.
In accordance with the guidance of ASC 450, “Contingencies,” the Company reviews its estimated future obligations and will record adjustments, if any, on a quarterly basis. Management believes it is probable and reasonably estimable that the impact of the potential outcomes of disputes with certain property owners and other potentially responsible parties will result in environmental remediation costs of $38.0$41.8 million for natural gas and $6.2$8.7 million for electric. The Company believes a significant portion of its past and future environmental remediation costs are recoverable from insurance companies, from third parties or from customers under a Washington Commission order. The Company is also subject to cost-sharing agreements with third parties regarding environmental remediation projects in Seattle, Washington and Bellingham, Washington. The Company has taken the lead for both projects, and as of December 31, 2016,2019, the Company’s share of future remediation costs is estimated to be approximately $24.9$31.6 million. The Company's deferred electric environmental costs are $13.8 million, $14.0$13.7 million and $13.4$14.1 million at December 31, 2016, 20152019 and 2014,2018, respectively, net of insurance proceeds. The Company's deferred natural gas environmental costs are $60.7 million, $52.9$54.8 million and $52.6$62.2 million at December 31, 2016, 20152019 and 2014,2018, respectively, net of insurance proceeds. In the pending2017 GRC, the Company has requested to ratebasehad its third party recoveries and remediation costs incurred as of September 30, 2016, net of a portion of insurance, approved for amortization and third party recoveries.inclusion in rates, effective December 19, 2017.
(4)(5) 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, 2016,2019, approximately $532.9$914.2 million of unrestricted retained earnings was available for the payment of dividends under the most restrictive mortgage indenture covenant.
Pursuant to the terms of the Washington Commission merger order, PSE may not declare or pay dividends if PSE’s common equity ratio, calculated on a regulatory basis, is 44.0% or below except to the extent a lower equity ratio is ordered by the Washington Commission. Also, pursuant to the merger order, PSE may not declare or make any distribution unless on the date of distribution PSE’s corporate credit/issuer rating is investment grade, or, if its credit ratings are below investment grade, PSE’s ratio of earnings before interest, tax, depreciation and amortization (EBITDA) to interest expense for the most recently ended four fiscal quarter periods prior to such date is equal to or greater than 3.0 to 1.0. The common equity ratio, calculated on a regulatory basis, was 47.9%48.4% at December 31, 2016,2019, and the EBITDA to interest expense was 5.25.3 to 1.0 for the twelve months ended December 31, 2016.
2019.
PSE’s ability to pay dividends is also limited by the terms of its credit facilities, pursuant to which PSE is not permitted to pay dividends during any Event of Default (as defined in the facilities), or if the payment of dividends would result in an Event of Default, such as failure to comply with certain financial covenants.
Puget Energy’s ability to pay dividends is also limited by the merger order issued by the Washington Commission. Pursuant to the merger order, Puget Energy may not declare or make a distribution unless on such date Puget Energy’s ratio of consolidated EBITDA to consolidated interest expense for the four most recently ended fiscal quarters prior to
such date is equal to or greater than 2.0 to 1.0. Puget Energy's EBITDA to interest expense was 3.53.6 to 1.0 for the twelve months ended December 31, 2016.2019.
At December 31, 2016,2019, the Company was in compliance with all applicable covenants, including those pertaining to the payment of dividends.
(5)(6) Utility Plant
The following table presents electric, natural gas and common utility plant classified by account:
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | | Puget Energy | | | | Puget Sound Energy | | |
Utility Plant | Estimated Useful Life | | December 31, | | | | December 31, | | |
(Dollars in Thousands) | (Years) | | 2019 | | 2018 | | 2019 | | 2018 |
Distribution plant | 20-65 | | $ | 6,602,934 | | | $ | 6,122,739 | | | $ | 8,185,700 | | | $ | 7,722,024 | |
Production plant | 12-90 | | 3,066,792 | | | 3,099,805 | | | 3,743,493 | | | 3,974,250 | |
Transmission plant | 43-75 | | 1,463,288 | | | 1,442,854 | | | 1,571,186 | | | 1,550,950 | |
General plant | 5-75 | | 698,275 | | | 682,976 | | | 731,279 | | | 718,105 | |
Intangible plant (including capitalized software)1 | 3-50 | | 735,826 | | | 662,328 | | | 726,383 | | | 652,942 | |
Plant acquisition adjustment | N/A | | 242,826 | | | 242,826 | | | 282,792 | | | 282,792 | |
Underground storage | 25-60 | | 37,511 | | | 35,404 | | | 50,963 | | | 48,874 | |
Liquefied natural gas storage | 25-60 | | 12,628 | | | 12,628 | | | 14,498 | | | 14,498 | |
Plant held for future use | N/A | | 46,233 | | | 39,384 | | | 46,385 | | | 39,536 | |
Recoverable Cushion Gas | N/A | | 8,655 | | | 8,655 | | | 8,655 | | | 8,655 | |
Plant not classified | N/A | | 316,923 | | | 239,857 | | | 316,923 | | | 239,857 | |
Finance leases, net of accumulated amortization2 | N/A | | 1,488 | | | 1,315 | | | 1,488 | | | 1,315 | |
Less: accumulated provision for depreciation | | | (3,236,240) | | | (2,832,321) | | | (5,682,606) | | | (5,495,348) | |
Subtotal | | | $ | 9,997,139 | | | $ | 9,758,450 | | | $ | 9,997,139 | | | $ | 9,758,450 | |
Construction work in progress | | | 591,199 | | | 550,466 | | | 591,199 | | | 550,466 | |
Net utility plant | | | $ | 10,588,338 | | | $ | 10,308,916 | | | $ | 10,588,338 | | | $ | 10,308,916 | |
|
| | | | | | | | | | | | | |
| | Puget Energy | Puget Sound Energy |
Utility Plant | Estimated Useful Life | At December 31, | At December 31, |
(Dollars in Thousands) | (Years) | 2016 | 2015 | 2016 | 2015 |
Distribution plant | 10-50 | $ | 5,287,542 |
| $ | 5,007,077 |
| $ | 6,922,176 |
| $ | 6,657,597 |
|
Production plant | 25-125 | 3,007,546 |
| 3,028,481 |
| 3,910,129 |
| 3,950,231 |
|
Transmission plant | 45-65 | 1,307,687 |
| 1,236,823 |
| 1,420,334 |
| 1,351,216 |
|
General plant | 5-35 | 541,424 |
| 491,845 |
| 611,237 |
| 563,850 |
|
Intangible plant (including capitalized software) | 3-50 | 347,697 |
| 305,705 |
| 338,327 |
| 294,380 |
|
Plant acquisition adjustment | 2-22 | 242,826 |
| 242,826 |
| 282,792 |
| 282,792 |
|
Underground storage | 25-60 | 30,695 |
| 28,914 |
| 44,206 |
| 42,545 |
|
Liquefied natural gas storage | 25-45 | 12,628 |
| 12,628 |
| 14,498 |
| 14,498 |
|
Plant held for future use | NA | 52,484 |
| 55,890 |
| 52,636 |
| 56,042 |
|
Recoverable Cushion Gas | NA | 8,655 |
| 8,655 |
| 8,655 |
| 8,655 |
|
Plant not classified | 1-125 | 159,345 |
| 65,892 |
| 159,345 |
| 65,892 |
|
Grant | NA | (99,100 | ) | (102,379 | ) | (99,100 | ) | (102,379 | ) |
Capital leases, net of accumulated amortization1 | 2 | 645 |
| 378 |
| 645 |
| 378 |
|
Less: accumulated provision for depreciation | | (2,161,796 | ) | (1,878,868 | ) | (4,927,602 | ) | (4,681,830 | ) |
Subtotal | | $ | 8,738,278 |
| $ | 8,503,867 |
| $ | 8,738,278 |
| $ | 8,503,867 |
|
Construction work in progress | NA | 420,278 |
| 408,795 |
| 420,278 |
| 408,795 |
|
Net utility plant | | $ | 9,158,556 |
| $ | 8,912,662 |
| $ | 9,158,556 |
| $ | 8,912,662 |
|
______________________________________1.Intangible assets include capitalized software and franchise agreements with useful lives ranging between 3-10 years and 10-50 years, respectively.
| |
1
| Accumulated amortization of capital leases at Puget Energy and PSE was $0.6 million in 2016 and $32.3 million in 2015.
|
2.At December 31, 2019, and 2018, accumulated amortization of capital leases at Puget Energy and PSE was $1.0 million and $1.3 million, respectively.
Jointly owned generating plant service costs are included in utility plant service cost at the Company's ownership share. The Company provides financing for its ownership interest in the jointly owned utility plants. The following table indicatestables indicate the Company’s percentage ownership and the extent of the Company’s investment in jointly owned generating plants in service at December 31, 2016.2019. These amounts are also included in the Utility Plant table above. The Company's share of fuel costs and operating expenses for plant in service are included in the corresponding accounts in the Consolidated Statements of Income.
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
Puget Energy | | | | | | | | | |
Jointly Owned Generating Plants (Dollars in Thousands) | Energy Source (Fuel) | | Company’s Ownership Share | | Plant in Service at Cost | | Construction Work in Progress | | Accumulated Depreciation |
| | | | | | | | | |
Colstrip Units 3 & 4 | Coal | | 25.00% | | | $ | 323,100 | | | $ | — | | | $ | (138,827) | |
Frederickson 1 | Natural Gas | | 49.85 | | | 61,820 | | | — | | | (10,995) | |
Jackson Prairie | Natural Gas | | 33.34 | | | 36,837 | | | 119 | | | (8,452) | |
Tacoma LNG | Natural Gas | | various | | — | | | 362,684 | | | — | |
| Puget Sound Energy | | Puget Sound Energy | | | | | | | | | |
Jointly Owned Generating Plants (Dollars in Thousands) | | Jointly Owned Generating Plants (Dollars in Thousands) | Energy Source (Fuel) | | Company’s Ownership Share | | Plant in Service at Cost | | Construction Work in Progress | | Accumulated Depreciation |
| | | Puget Energy’s Share | Puget Sound Energy’s Share | |
Jointly Owned Generating Plants (Dollars in Thousands) | Energy Source (Fuel) | Company’s Ownership Share | Plant in Service at Cost | Accumulated Depreciation | Plant in Service at Cost | Accumulated Depreciation | |
Colstrip Units 1 & 2 | Coal | 50% | $ | 70,717 |
| $ | (22,284 | ) | $ | 204,334 |
| $ | (155,902 | ) | |
Colstrip Units 3 & 4 | Coal | 25% | 307,383 |
| (40,343 | ) | 575,902 |
| (308,861 | ) | Colstrip Units 3 & 4 | Coal | | 25.00% | | | $ | 582,372 | | | $ | — | | | $ | (398,099) | |
Colstrip Units 1 – 4 Common Facilities | Coal | various | 83 |
| (27 | ) | 252 |
| (196 | ) | |
Frederickson 1 | Natural Gas | 49.85% | 61,780 |
| (9,779 | ) | 70,729 |
| (18,728 | ) | Frederickson 1 | Natural Gas | | 49.85 | | | 67,888 | | | — | | | (17,063) | |
Jackson Prairie | Natural Gas Storage | 33.34% | 30,021 |
| (5,544 | ) | 44,206 |
| (19,730 | ) | Jackson Prairie | Natural Gas | | 33.34 | | | 50,963 | | | 119 | | | (22,578) | |
Tacoma LNG | | Tacoma LNG | Natural Gas | | various | | — | | | 162,820 | | | — | |
In June 2019, Talen, the plant operator of Colstrip 1&2, announced a plan to shut down as of December 31, 2019. The Company retired Colstrip 1&2 from Utility Plant and transferred the unrecovered plant amount of $126.5 million to regulatory assets. Consistent with the GRC settlement in 2017, monetization of the PTCs will fund the following: (i) Colstrip Community Transition Fund, (ii) unrecovered Colstrip plant and (iii) incurred decommissioning and remediation costs for Colstrip. At December 31, 2019, the unrecovered plant for Colstrip 1&2 was fully offset with PTCs.
Asset Retirement Obligation
The Company has recorded liabilities for steam generation sites, combustion turbine generation sites, wind generation sites, distribution and transmission poles, natural gas mains, and leased facilities where disposal is governed by ASC 410 “ARO”“Asset Retirement and Environmental Obligations" (ARO).
On April 17, 2015, the United States EPA published a final rule, effective October 19, 2015, that regulates Coal Combustion Residuals (CCR) under the Resource Conservation and Recovery Act, Subtitle D. The CCR ruling requires the Company to perform an extensive study on the effects of coal ash on the environment and public health. The rule addresses the risks from coal ash disposal, such as leaking of contaminants into ground water, blowing of contaminants into the air as dust, and the catastrophic failure of coal ash surface impoundments.
The CCR rule and two new legal agreements which include a consent decree with the Sierra Club and a settlement agreement with the Sierra Club and the National Wildlife Federation in 2016 make significant changes to the Company’s Colstrip operations and those changes were reviewed by the Company and the plant operator in the second quarter of 2015 and the third quarter of 2016. PSE had previously recognized a legal obligation in 2003 under the EPA rules to dispose of coal ash material at Colstrip. Due to the updated Colstrip information, additional disposal costs were added to the ARO.
During the third quarter 2016, PSE entered into two new legal agreements requiring the Company to close the Colstrip 1 and 2 plants on or before July 1, 2022 and to incur additional monitoring costs, water treatment costs, forced evaporation cost, and post closure care costs for all Colstrip Units. As a result, the Company adjusted the Colstrip ARO ending liability to increase by $45.7 million for Colstrip 1 and 2 and $37.0 million for Colstrip 3 and 4.
The actual ARO costs related to the CCR rule requirements may vary substantially from the estimates used to record the increased obligation due to uncertainty about the compliance strategies that will be used and the preliminary nature of available data used to estimate costs. We will continue to gather additional data and coordinate with the plant operator to make decisions about compliance strategies and the timing of closure activities. As additional information becomes available, the Company will update the ARO obligation for these changes, which could be material.
DuringFor the first quarter 2016,twelve months ended December 31, 2019, the Company updated itsreviewed the estimated decommissioningremediation costs at Colstrip and increased the Colstrip ARO liability by $4.2 million for Colstrip Units 1 and 2 and $0.5 million for Colstrip Units 3 and 4. The 2019 increase to the Colstrip ARO liability are primarily due to accelerated timing of activities due to the timingclosure of itsColstrip Units 1 and 2 at the end of 2019. For the twelve months ended December 31, 2018, the company reduced the Colstrip ARO liability by $11.0 million for Lower Snake RiverColstrip Units 1 and Hopkins Ridge wind generation sites2, and increased $1.8 million for Colstrip Units 3 and 4. The 2018 change to the Colstrip ARO liability is primarily based on the plant site remedy report approved by the Montana Department of Environmental Quality. For the twelve months ended December 31, 2019 and 2018, the Company also recorded the Colstrip relief of liability of $12.4 million and $4.8 million, respectively. In addition, the Company recorded Tacoma LNG facility ARO liability of $19.7 million.
The following table describes the changes to the Company’s ARO liability$3.0 million and $2.7 million for PSE and $4.3 million and $1.7 million for Puget LNG as of December 31, 20162019 and 2015:December 31, 2018, respectively. The 2019 increase to the Tacoma LNG facility ARO liability is primarily due to continued construction of the plant.
| | | At December 31, | |
Puget Energy and Puget Sound Energy | | Puget Energy and Puget Sound Energy | December 31, | |
(Dollars in Thousands) | 2016 | 2015 | (Dollars in Thousands) | 2019 | | 2018 |
Asset retirement obligation at beginning of period | $ | 85,028 |
| $ | 48,909 |
| |
Asset retirement obligation at beginning of the period | | Asset retirement obligation at beginning of the period | $ | 182,203 | | | $ | 191,176 | |
New asset retirement obligation recognized in the period | — |
| 34,534 |
| New asset retirement obligation recognized in the period | — | | | 501 | |
Liability adjustment in the period | (411 | ) | (3,628 | ) | |
Relief of liability | | Relief of liability | (12,449) | | | (4,750) | |
Revisions in estimated cash flows | 113,081 |
| 3,403 |
| Revisions in estimated cash flows | 5,922 | | | (10,512) | |
Accretion expense | 2,647 |
| 1,810 |
| Accretion expense | 5,677 | | | 5,788 | |
Asset retirement obligation at end of period | $ | 200,345 |
| $ | 85,028 |
| |
Asset retirement obligation at end of period1 | | Asset retirement obligation at end of period1 | $ | 181,353 | | | $ | 182,203 | |
___________________
1.Asset retirement obligations include $4.3 million and $1.7 million for Puget LNG held only at PE as of December 31, 2019, and 2018, respectively.
The Company has identified the following obligations, as defined by ASC 410, “ARO,” which were not recognized because the liability for these assets cannot be reasonably estimated at December 31, 2016 due to:2019:
•A legal obligation under Federal Dangerous Waste Regulations to dispose of asbestos-containing material in facilities that are not scheduled for remodeling, demolition or sales. The disposal cost related to these facilities could not be measured since the retirement date is indeterminable; therefore, the liability cannot be reasonably estimated;
•An obligation under Washington state law to decommission the wells at the Jackson Prairie natural gas storage facility upon termination of the project. Since the project is expected to continue as long as the Northwest pipeline continues to operate, the liability cannot be reasonably estimated;
•An obligation to pay its share of decommissioning costs at the end of the functional life of the major transmission lines. The major transmission lines are expected to be used indefinitely; therefore, the liability cannot be reasonably estimated;
•A legal obligation under Washington state environmental laws to remove and properly dispose of certain under and above ground fuel storage tanks. The disposal costs related to under and above ground storage tanks could not be measured since the retirement date is indeterminable; therefore, the liability cannot be reasonably estimated;
•An obligation to pay decommissioning costs at the end of utility service franchise agreements to restore the surface of the franchise area. The decommissioning costs related to facilities at the franchise area could not be measured since the decommissioning date is indeterminable; therefore, the liability cannot be reasonably estimated; and
•A potential legal obligation may arise upon the expiration of an existing FERC hydropower license if FERC orders the project to be decommissioned, although PSE contends that FERC does not have such authority. Given the value of ongoing generation, flood control and other benefits provided by these projects, PSE believes that the potential for decommissioning is remote and cannot be reasonably estimated.
(7) Long-Term Debt
The following table presents outstanding long-term debt principal amounts and due dates as of 2019 and 2018:
| | | | | | | | | | | | | | | | | | | | | | | |
(Dollars in Thousands) | | | | | December 31, | | |
Series | | Type | | Due | 2019 | | 2018 |
Puget Sound Energy: | | | | | | | |
5.500% | | | Promissory Note1 | | 2020 | $ | — | | | $ | 2,412 | |
7.150% | | | First Mortgage Bond | | 2025 | 15,000 | | | 15,000 | |
7.200% | | | First Mortgage Bond | | 2025 | 2,000 | | | 2,000 | |
7.020% | | | Senior Secured Note | | 2027 | 300,000 | | | 300,000 | |
7.000% | | | Senior Secured Note | | 2029 | 100,000 | | | 100,000 | |
3.900% | | | Pollution Control Bond | | 2031 | 138,460 | | | 138,460 | |
4.000% | | | Pollution Control Bond | | 2031 | 23,400 | | | 23,400 | |
5.483% | | | Senior Secured Note | | 2035 | 250,000 | | | 250,000 | |
6.724% | | | Senior Secured Note | | 2036 | 250,000 | | | 250,000 | |
6.274% | | | Senior Secured Note | | 2037 | 300,000 | | | 300,000 | |
5.757% | | | Senior Secured Note | | 2039 | 350,000 | | | 350,000 | |
5.795% | | | Senior Secured Note | | 2040 | 325,000 | | | 325,000 | |
5.764% | | | Senior Secured Note | | 2040 | 250,000 | | | 250,000 | |
4.434% | | | Senior Secured Note | | 2041 | 250,000 | | | 250,000 | |
5.638% | | | Senior Secured Note | | 2041 | 300,000 | | | 300,000 | |
4.300% | | | Senior Secured Note | | 2045 | 425,000 | | | 425,000 | |
4.223% | | | Senior Secured Note | | 2048 | 600,000 | | | 600,000 | |
3.250% | | | Senior Secured Note | | 2049 | 450,000 | | | — | |
4.700% | | | Senior Secured Note | | 2051 | 45,000 | | | 45,000 | |
| | | | | | | |
* | | Debt discount, issuance cost and other | | * | (37,718) | | | (31,412) | |
Total PSE long-term debt | | | | | 4,336,142 | | | 3,894,860 | |
Puget Energy: | | | | | | | |
* | | Fair value adjustment of PSE long-term debt | | * | (173,865) | | | (182,372) | |
* | | Revolving Credit Agreement | | 2023 | 24,100 | | | 11,900 | |
* | | Term Loan Agreement | | 2021 | 174,000 | | | 150,000 | |
* | | Term Loan Agreement | | 2022 | 210,000 | | | — | |
6.500% | | | Senior Secured Note2 | | 2020 | — | | | 450,000 | |
6.000% | | | Senior Secured Note | | 2021 | 500,000 | | | 500,000 | |
5.625% | | | Senior Secured Note | | 2022 | 450,000 | | | 450,000 | |
3.650% | | | Senior Secured Note | | 2025 | 400,000 | | | 400,000 | |
* | | Debt discount, issuance cost and other | | * | (52) | | | (1,897) | |
Total Puget Energy long-term debt | | | | | $ | 5,920,325 | | | $ | 5,672,491 | |
___________________
*Not Applicable.
1.5.500% Promissory Note in the amount of $2.4 million was classified on the Balance Sheet as a current maturity of long-term debt as of August 12, 2019.
2.6.500% Senior Secured Note in the amount of $450.0 million was classified on the Balance Sheet as a current maturity of long-term debt as of December 31, 2016 and 2015:14,2019.
|
| | | | | | | | |
(Dollars in Thousands) | | At December 31, |
Series | Type | Due | 2016 | 2015 |
Puget Sound Energy: |
5.500% | Promissory Note | 2017 | $ | 2,412 |
| $ | 2,412 |
|
6.740% | Senior Secured Note | 2018 | 200,000 |
| 200,000 |
|
7.150% | First Mortgage Bond | 2025 | 15,000 |
| 15,000 |
|
7.200% | First Mortgage Bond | 2025 | 2,000 |
| 2,000 |
|
7.020% | Senior Secured Note | 2027 | 300,000 |
| 300,000 |
|
7.000% | Senior Secured Note | 2029 | 100,000 |
| 100,000 |
|
3.900% | Pollution Control Bond | 2031 | 138,460 |
| 138,460 |
|
4.000% | Pollution Control Bond | 2031 | 23,400 |
| 23,400 |
|
5.483% | Senior Secured Note | 2035 | 250,000 |
| 250,000 |
|
6.724% | Senior Secured Note | 2036 | 250,000 |
| 250,000 |
|
6.274% | Senior Secured Note | 2037 | 300,000 |
| 300,000 |
|
5.757% | Senior Secured Note | 2039 | 350,000 |
| 350,000 |
|
5.795% | Senior Secured Note | 2040 | 325,000 |
| 325,000 |
|
5.764% | Senior Secured Note | 2040 | 250,000 |
| 250,000 |
|
4.434% | Senior Secured Note | 2041 | 250,000 |
| 250,000 |
|
5.638% | Senior Secured Note | 2041 | 300,000 |
| 300,000 |
|
4.300% | Senior Secured Note | 2045 | 425,000 |
| 425,000 |
|
4.700% | Senior Secured Note | 2051 | 45,000 |
| 45,000 |
|
6.974% | Junior Subordinated Note | 2067 | 250,000 |
| 250,000 |
|
* | Debt discount, issuance cost and other | * | (28,974 | ) | (31,910 | ) |
Total PSE long-term debt | 3,747,298 |
| 3,744,362 |
|
Puget Energy: | | |
* | Fair value adjustment of PSE long-term debt | * | (199,436 | ) | (207,977 | ) |
* | Revolving Credit Agreement | 2018 | 12,480 |
| — |
|
6.500% | Senior Secured Note | 2020 | 450,000 |
| 450,000 |
|
6.000% | Senior Secured Note | 2021 | 500,000 |
| 500,000 |
|
5.625% | Senior Secured Note | 2022 | 450,000 |
| 450,000 |
|
3.650% | Senior Secured Note | 2025 | 400,000 |
| 400,000 |
|
* | Debt discount, issuance cost and other | * | (6,269 | ) | (8,867 | ) |
Total Puget Energy long-term debt | $ | 5,354,073 |
| $ | 5,327,518 |
|
_______________
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, 2016,2019, the latest maturity date of the first mortgage bonds, other than pledged first mortgage bonds, is December 22, 2025.
Puget Energy Long-Term Debt
On October 1, 2018, Puget Energy entered into a $150.0 million, three-year term loan agreement with a small group of banks. The agreement allows Puget Energy to borrow at either the banks' prime rate or at London Interbank Offered Rate (LIBOR) plus a spread based on credit rating. The Term Loan Agreement also includes an expansion feature, pursuant to which Puget Energy may request to increase the aggregate amount of the Term Loan Agreement, obtain incremental term loans or any combination of increases and incremental term loans in an amount up to $100.0 million. The proceeds from the term loan will be used to repay borrowings under the revolving credit facility, which carries a higher interest rate.
In April 2019, Puget Energy entered into an additional $24.0 million of supplemental loans under the expansion feature of the term loan agreement with the existing lenders. All other terms and conditions of the agreement remain unchanged. The proceeds from the term loan and supplemental loans will be used to repay borrowings under the revolving credit facility, which carries a higher interest rate.
On September 26, 2019, Puget Energy entered into a separate $210.0 million, three-year term loan agreement with a small group of banks. The agreement allows Puget Energy to borrow at either the banks' prime rate or LIBOR plus a spread, which will vary as those base rates fluctuate over the loan period. The Term Loan Agreement also includes an expansion feature, pursuant to which Puget Energy may request to increase the aggregate amount of the Term Loan Agreement, obtain incremental term loans or any combination of increases and incremental term loans in an amount up to $100.0 million. The proceeds from the term loan were contributed as equity to PSE and used to repay outstanding short term debt under the Company's commercial paper program.
Puget Sound Energy Long-Term Debt
On August 2, 2019, PSE has in effectfiled a new shelf registration statement ("the existing shelf") under which it may issue, as of the date of this report, up to $800.0 million$1.0 billion aggregate principal amount of senior notes secured by first mortgage bonds. As of the date of this report, $550.0 million was available under the registration. The existing shelf registration will expire in November 2019.August 2022.
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, 2016,2019, the earnings available for interest exceeded the required amount.
On May 26, 2015,March 5, 2018, PSE commenced a tender offer and related consent solicitation to purchase any and all of the outstanding $250.0 million 6.974% Series A Enhanced Junior Subordinated Notes due June 1, 2067. Holders of the notes received $1,005 per $1,000 principal amount of notes plus accrued and unpaid interest for notes tendered and accepted by the early tender payment deadline of March 16, 2018. Holders of notes tendered after the early tender payment deadline, but prior to the tender offer expiration on April 2, 2018, were to receive the tender offer consideration of $975 per $1,000 of principal amount of the notes plus accrued but unpaid interest. A total of $193.4 million in principal amount of notes were tendered by the early payment deadline and no notes were tendered after the early payment deadline. On March 20, 2018, $194.9 million was paid to the holders of the tendered notes. This amount included the principal, early tender consideration and accrued interest up to, but not including March 20, 2018.
Concurrently with the tender offer, PSE solicited consents from a majority (in principal amount) of the holders of PSE’s 6.274% Senior Notes due March 15, 2037 to terminate the replacement capital covenant granted to the holders of those notes. The termination of the covenant was necessary because it included restrictions related to repurchases, redemptions and repayments of the 6.974% Series A Enhanced Junior Subordinated Notes. PSE received consents from holders of 87.7% of the 6.274% Senior Notes and paid a consent fee totaling $2.6 million to those holders on March 19, 2018.
On March 28, 2018, PSE issued $425.0a notice of redemption, effective April 27, 2018, for the remaining $56.6 million principal amount of the 6.974% Series A Enhanced Junior Subordinated Notes. The notes were redeemed at a price equal to 100% of their principal amount plus accrued and unpaid interest up to, but excluding the redemption date.
On June 4, 2018, PSE issued $600.0 million of 30-year Senior Notes under its senior notes secured by first mortgage bonds. The notes mature in May 2045 and havenote indenture at an interest rate of 4.30%, which is payable semi-annually in May and November. Net4.223% with a maturity date of June 15, 2048. The proceeds offrom the issuance were used to fundpay the early retirement, includingprincipal and accrued interest on the Company’s $200.0 million Secured Notes that matured on June 15, 2018, outstanding commercial paper borrowings of $348.0 million and make-whole call premiums, of the Company's $150.0 million 5.197% senior notes maturing in October 2015 and the Company's $250.0 million 6.75% senior notes maturing in January 2016.other general corporate expenses.
Puget Energy Long-Term Debt
In May 2015, Puget EnergyOn August 30, 2019, PSE issued $400.0$450.0 million of senior secured notes in a private placement. The notes mature in May 2025 and haveat an interest rate of 3.65%, which is payable3.250%. The notes pay interest semi-annually in May and November. Net proceedsare due to mature on September 15, 2049. Proceeds from the sale of the issuancenotes were used to repay outstanding Puget Energy indebtedness and to fund a special dividend to shareholders. In November 2015, Puget Energy exchanged $400.0 million of its 3.65% senior secured notes that were originally issued inshort term debt under the May 2015 private placement for registered notes of the same amount.Company’s commercial paper program.
Long-Term Debt Maturities
The principal amounts of long-term debt maturities for the next five years and thereafter are as follows:
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
(Dollars in Thousands) | 2020 | | 2021 | | 2022 | | 2023 | | 2024 | | Thereafter | | Total |
Maturities of: | | | | | | | | | | | | | |
PSE | $ | 2,412 | | | $ | — | | | $ | — | | | $ | — | | | $ | — | | | $ | 4,373,860 | | | $ | 4,376,272 | |
Puget Energy | 450,000 | | | 674,000 | | | 660,000 | | | 24,100 | | | — | | | 400,000 | | | 2,208,100 | |
Total long-term debt | $ | 452,412 | | | $ | 674,000 | | | $ | 660,000 | | | $ | 24,100 | | | $ | — | | | $ | 4,773,860 | | | $ | 6,584,372 | |
|
| | | | | | | | | | | | | | | | | | | | | |
(Dollars in Thousands) | 2017 | 2018 | 2019 | 2020 | 2021 | Thereafter | Total |
Maturities of: | | | | | | | |
PSE long-term debt | $ | 2,412 |
| $ | 200,000 |
| $ | — |
| $ | — |
| $ | — |
| $ | 3,573,860 |
| $ | 3,776,272 |
|
Puget Energy long-term debt | — |
| 12,480 |
| — |
| 450,000 |
| 500,000 |
| 850,000 |
| 1,812,480 |
|
Puget Energy long-term debt | $ | 2,412 |
| $ | 212,480 |
| $ | — |
| $ | 450,000 |
| $ | 500,000 |
| $ | 4,423,860 |
| $ | 5,588,752 |
|
(7)(8) Liquidity Facilities and Other Financing Arrangements
As of December 31, 20162019, and 2015,2018, PSE had $245.8$176.0 million and $159.0$379.3 million in short-term debt outstanding, respectively, exclusive of the demand promissory note with Puget Energy.respectively. 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 facilitiesfacility 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 20162019 and 20152018 was 3.21%3.4% and 4.24%3.4%, respectively. As of December 31, 2016,2019, PSE and Puget Energy had several committed credit facilities that are described below.
Puget Sound Energy
Credit FacilitiesFacility
In October 2017, PSE hasentered into a new $800.0 million credit facility which consolidates the two unsecured revolving creditprevious facilities which provide, in aggregate, $1.0 billion of short-term liquidity needs. These facilities consist ofinto a $650.0 million revolving liquidity facility (which includes a liquiditysingle, smaller facility. All other features including fees, interest rate options, letter of credit, facilitysame day swingline borrowings, financial covenant and a swingline facility) to be used for general corporate purposes, including a backstop toaccordion feature remain substantially the Company's commercial paper program and a $350.0 million revolving energy hedging facility (which includes an energy hedging letter ofsame. The credit facility). The $650.0 million liquidity facility includes a swingline feature allowing same day availability on borrowings up to $75.0 million. The credit facilitiesfacility also havehas an accordionexpansion feature which, upon the banks' approval, would increase the total size of these facilitiesthe facility to $1.5$1.4 billion.
In April 2014, On September 25, 2019, with no changes to the Company completed a one-year extension on bothsize, terms or conditions, the maturity of the liquidity and hedging facilities, extending the maturity from February 2018 to April 2019, and updating or clarifying the definitions of other terms and conditions of the facilities from when they were committedunsecured revolving credit facility was extended for one year. The facility now matures in 2013. October 2023.
The credit agreements areagreement is syndicated among numerous lenders and containcontains usual and customary affirmative and negative covenants that, among other things, placeplaces limitations on PSE's ability to transact with affiliates, make asset dispositions and investments or permit liens to exist. The credit agreementsagreement also containcontains 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, 2016,2019, PSE was in compliance with all applicable covenant ratios.
The credit agreements provideagreement provides PSE with the ability to borrow at different interest rate options. The credit agreements allowagreement allows PSE to borrow at the bank's prime rate or to make floating rate advances at the London Interbank Offered Rate (LIBOR)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.facility. 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 1.75%1.25% and the commitment fee is 0.275%0.175%.
As of December 31, 2016,2019, no amounts were drawn and outstanding under either PSE's $650.0 million facility or PSE's $350.0 million energy hedgingcredit facility. No letters of credit were outstanding under either facility, and $245.8$176.0 million was outstanding under the commercial paper program. Outside of the credit agreements,agreement, PSE had a $3.5$2.8 million letter of credit in support of a long-term transmission contract and a $1.0 million letter of credit in support of natural gas purchases in Canada.
Demand Promissory Note
In 2006, PSE entered into a revolving credit facility with Puget Energy, in the form of a credit agreement and a demand promissory note (Note) pursuant to which PSE may borrow up to $30.0 million from Puget Energy subject to approval by Puget Energy. Under the terms of the Note, PSE pays interest on the outstanding borrowings based on the lower of the weighted-average interest rates of PSE’s outstanding commercial paper interest rate or PSE’s senior unsecured revolving credit
facility. Absent such borrowings, interest is charged at one-month LIBOR plus 0.25%. As of December 31, 2016,2019, there was no outstanding balance under the Note.
Puget Energy
Credit Facility
At December 31, 2016,In October 2017, Puget Energy maintained anentered into a new $800.0 million revolving senior secured credit facility. In April, 2014, the Company completed an amendment to the senior secured credit facility extendingto replace the maturity from February 2017 to April 2018, updating the fee structure, eliminating aexisting facility. The terms and conditions, including fees, interest rate options, financial covenant, and updatingexpansion feature remain substantially the same. On September 25, 2019, with no changes to the size, terms or clarifyingconditions, the definitionsmaturity of other termsthe unsecured revolving credit facility was extended for one year. The facility now matures in October 2023. As of December 31, 2019, there was $24.1 million drawn and conditions ofoutstanding under the facility. The Puget Energy revolving senior secured credit facility also has an accordionexpansion feature which, upon the banks' approval, would increase the size of the facility to $1.3 billion.
The revolving senior secured credit facility provides Puget Energy the ability to borrow at different interest rate options and includes variable fee levels. Interest rates may be based on the bank's prime rate or LIBOR plus a spread based on Puget Energy's credit ratings. Puget Energy must pay a commitment fee on the unused portion of the facility. As of December 31, 2016, there was $12.5 million outstanding under the facility. As a resultdate of Puget Energy's credit rating upgrade in 2014,this report, the spread over LIBOR was 1.75% and the commitment fee was 0.275% as of the date of this report. Puget Energy entered into interest rate swap contracts to manage the interest rate risk associated with the credit facility or similar variable rate debt. For additional information, see Note 9, "Accounting for Derivative Instruments and Hedging Activities" to the consolidated financial statements included in Item 8 of this report..
The revolving senior secured credit facility contains usual and customary affirmative and negative covenants. The agreement also contains a maximum leverage ratio financial covenant as defined in the agreement governing the senior secured credit facility. As of December 31, 2016,2019, Puget Energy was in compliance with all applicable covenants.
(8)(9) Leases
PSE has operating leases for buildings for corporate offices and operations, real estate for operating facilities and the PSE and PLNG LNG facility, land for our wind farms, and vehicles for PSE’s fleet. The finance leases are for office printers. The leases have remaining lease terms of less than a year to 50 years. PSE's ROU assets under operating leases. Certainand lease liabilities include options to extend leases contain purchase options, renewal options and escalation provisions.when it is reasonably certain that PSE will exercise that option.
During the fourth quarter of 2019, PSE became reasonably certain to exercise an option to extend its lease at the Port of Tacoma for an additional 25 years as a result of the approval of the Notice of Construction permit for the Tacoma LNG facility. This remeasurement resulted in an increase of the Operating lease expenses netright-of-use asset and Operating lease liabilities of sublease receipts were:$14.7 million.
The components of lease cost were as follows:
| | | | | |
Puget Energy and Puget Sound Energy | Year Ended December 31, |
(Dollars in Thousands) | 2019 |
Finance lease cost: | |
Amortization of right-of-use asset | $ | 562 | |
Interest on lease liabilities | 40 | |
Total finance lease cost | $ | 602 | |
| |
Operating lease cost1 | $ | 20,639 | |
_______________
1.Includes $1.0 million allocated to PLNG at PE related to the Port of Tacoma lease.
|
| | | |
(Dollars in Thousands) | |
At December 31, | |
Years | Operating Lease Expense |
2016 | $ | 31,786 |
|
2015 | 27,843 |
|
2014 | 30,737 |
|
Supplemental cash flow information related to leases was as follows: | | | | | |
Puget Energy and Puget Sound Energy | Year Ended December 31, |
(Dollars in Thousands) | 2019 |
Cash paid for amounts included in the measurement of lease liabilities: | |
Operating cash flow for operating leases | $ | 14,104 | |
Investing cash flow for operating leases1 | 6,535 |
Operating cash flow for finance leases | 40 |
Financing cash flow for finance leases | 562 |
Non-cash disclosure upon commencement of new lease | |
Right-of-use assets obtained in exchange for new operating lease liabilities | $ | 5,976 | |
Right-of-use assets obtained in exchange for new finance lease liabilities | 745 | |
Non-cash disclosure upon modification of existing lease | |
Modification of operating lease right-of-use assets | $ | 14,712 | |
Payments received for_______________
1 Includes $1.0 million allocated to PLNG at PE related to the subleasesPort of properties were immaterial for each ofTacoma lease.
Supplemental balance sheet information related to leases was as follows:
| | | | | |
Puget Sound Energy | |
(Dollars in Thousands) | At December 31, |
Operating Leases | 2019 |
Operating lease right-of-use asset | $ | 183,048 | |
| | |
Operating leases liabilities current | 15,862 | |
Operating lease liabilities long-term | 174,327 | |
Total Operating lease liabilities: | $ | 190,189 | |
| | |
Finance Leases | | |
Common Plant | $ | 1,488 | |
| | |
Other current liabilities | 669 | |
Other deferred credits | 811 | |
Total finance lease liabilities | $ | 1,480 | |
| |
Weighted Average Remaining Lease Term | |
Operating leases | 19.24 Years |
Finance leases | 2.76 Years |
| |
Weighted Average Discount Rate | |
Operating leases | 3.59 | % |
Finance leases | 2.98 | % |
The following tables summarize the years ended 2016, 2015 and 2014.
FutureCompany’s estimated future minimum lease payments for non-cancelableas of December 31, 2019, and December 31, 2018, respectively:
| | | | | | | | | | | |
Maturities of lease liabilities | Future Minimum Lease Payments | | |
(Dollars in Thousands) | | | |
At December 31, | Operating Leases | | Finance Leases |
2020 | $ | 22,500 | | | $ | 643 | |
2021 | 22,527 | | | 508 | |
2022 | 21,856 | | | 279 | |
2023 | 21,415 | | | 98 | |
2024 | 20,690 | | | — | |
Thereafter | 160,410 | | | — | |
Total lease payments | $ | 269,398 | | | $ | 1,528 | |
Less imputed interest | (79,209) | | | (48) | |
Total net present value | $ | 190,189 | | | $ | 1,480 | |
| | | | | | | | | | | |
Maturities of lease liabilities | Future Minimum Lease Payments | | |
(Dollars in Thousands) | | | |
At December 31, | Operating Leases | | Finance Leases |
2019 | $ | 20,635 | | | $ | 495 | |
2020 | 20,704 | | | 446 | |
2021 | 20,630 | | | 311 | |
2022 | 20,202 | | | 82 | |
2023 | 19,223 | | | — | |
Thereafter | 132,889 | | | — | |
Total lease payments | $ | 234,283 | | | $ | 1,334 | |
PSE adopted ASU 2016-02 and elected the modified transition method practical expedient. Consequently, comparative period disclosures are presented in accordance with ASC 840. For further details see Note 2, "New Accounting Pronouncements" to the consolidated financial statements included in Item 8 of this report. Operating lease expense, which includes both cancellable and non-cancellable leases, net of sublease receipts are:are presented in the following table.
| | | | | |
(Dollars in Thousands) | Operating Lease Expense |
Year Ended December 31, | |
2018 | $ | 34,093 | |
2017 | 35,198 | |
|
| | | | | | |
(Dollars in Thousands) | | |
At December 31, | Future Minimum Lease Payments |
Years | Operating | Capital |
2017 | $ | 22,212 |
| $ | 296 |
|
2018 | 19,834 |
| 296 |
|
2019 | 18,078 |
| 74 |
|
2020 | 16,507 |
| — |
|
2021 | 8,137 |
| — |
|
Thereafter | 102,393 |
| — |
|
Total minimum lease payments | $ | 187,161 |
| $ | 666 |
|
(9)(10) Accounting for Derivative Instruments and Hedging Activities
PSE employs various energy portfolio optimization strategies, but is not in the business of assuming risk for the purpose of realizing speculative trading revenue. The nature of serving regulated electric customers with its portfolio of owned and contracted electric generation resources exposes PSE and its customers to some volumetric and commodity price risks within the sharing mechanism of the PCA. Therefore, wholesale market transactions and PSE's related hedging strategies are focused on reducing costs and risks where feasible, thus reducing volatility in costs in the portfolio. In order to manage its exposure to the variability in future cash flows for forecasted energy transactions, PSE utilizes a programmatic hedging strategy which extends out three years. PSE's hedging strategy includes a risk-responsive component for the core natural gas portfolio, which utilizes quantitative risk-based measures with defined objectives to balance both portfolio risk and hedge costs.
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. Currently, the Company does not apply cash flow hedge accounting, and therefore records all mark-to-market gains or losses through earnings.
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, 2016, Puget Energy had two interest rate swap contracts outstanding which matured January 2017. Currently, these swap instruments do not hedge any variable interest rate debt. PSE did not have any outstanding interest rate swap instruments.
The following table presents the volumes, fair values and locationsclassification of the Company's derivative instruments recorded on the balance sheets:
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
Puget Energy and Puget Sound Energy | Year Ended December 31, | | | | | | | | | | |
(Dollars in Thousands) | Volumes (millions) | | | | Assets1 | | | | Liabilities² | | |
| 2019 | | 2018 | | 2019 | | 2018 | | 2019 | | 2018 |
Electric portfolio derivatives | * | | | * | | | $ | 19,933 | | | $ | 33,287 | | | $ | 17,504 | | | $ | 27,284 | |
Natural gas derivatives (MMBtus)3 | 316 | | 337 | | 11,375 | | | 15,732 | | | 8,617 | | | 30,472 | |
Total derivative contracts | | | | | | | $ | 31,308 | | | $ | 49,019 | | | $ | 26,121 | | | $ | 57,756 | |
Current | | | | | | | 23,626 | | | 46,507 | | | 13,428 | | | 46,661 | |
Long-term | | | | | | | 7,682 | | | 2,512 | | | 12,693 | | | 11,095 | |
Total derivative contracts | | | | | | | $ | 31,308 | | | $ | 49,019 | | | $ | 26,121 | | | $ | 57,756 | |
|
| | | | | | | | | | | | | | | | |
Puget Energy and Puget Sound Energy | At Year Ended December 31, |
(Dollars in Thousands) | Volumes (millions) | Assets1 | Liabilities2 |
| 2016 | 2015 | 2016 | 2015 | 2016 | 2015 |
Interest rate swap derivatives3 | $450.0 | $450.0 | $ | — |
| $ | — |
| $ | 141 |
| $ | 5,050 |
|
Electric portfolio derivatives | * | * | 36,460 |
| 23,443 |
| 41,329 |
| 112,106 |
|
Natural gas derivatives (MMBtus)4 | 336.4 |
| 369.5 |
| 26,619 |
| 6,200 |
| 19,101 |
| 67,090 |
|
Total derivative contracts | ** | ** | $ | 63,079 |
| $ | 29,643 |
| $ | 60,571 |
| $ | 184,246 |
|
Current | ** | ** | $ | 54,341 |
| $ | 24,418 |
| $ | 44,310 |
| $ | 136,173 |
|
Long-term | ** | ** | 8,738 |
| 5,225 |
| 16,261 |
| 48,073 |
|
Total derivative contracts | ** | ** | $ | 63,079 |
| $ | 29,643 |
| $ | 60,571 |
| $ | 184,246 |
|
_________________________1.Balance sheet classification: Current and Long-term Unrealized gain on derivative instruments.
| |
1
| Balance sheet location: Current and Long-term Unrealized gain on derivative instruments. |
| |
2
| Balance sheet location: Current and Long-term Unrealized loss on derivative instruments. |
| |
3
| Interest rate swap contracts are only held at Puget Energy. |
| |
4
| All fair value adjustments on derivatives relating to the natural gas business have been deferred in accordance with ASC 980, “Regulated Operations,” due to the PGA mechanism. The net derivative asset or liability and offsetting regulatory liability or asset are related to contracts used to economically hedge the cost of physical gas purchased to serve natural gas customers. |
| |
*
| Electric portfolio derivatives consist of electric generation fuel of 186.8 million One Million British Thermal Units (MMBtus) and purchased electricity of 3.6 million megawatt hours (MWhs) at December 31, 2016 and 202.1 million MMBtus and 0.1 million MWhs at December 31, 2015. |
| |
** | Not meaningful and/or applicable. |
2.Balance sheet classification: Current and Long-term Unrealized loss on derivative instruments.
3.All fair value adjustments on derivatives relating to the natural gas business have been deferred in accordance with ASC 980, “Regulated Operations,” due to the PGA mechanism. The net derivative asset or liability and offsetting regulatory liability or asset are related to contracts used to economically hedge the cost of physical gas purchased to serve natural gas customers.
*Electric portfolio derivatives consist of electric generation fuel of 229.3 million One Million British Thermal Units (MMBtus) and purchased electricity of 10.4 million megawatt hours (MWhs) at December 31, 2019, and 194.8 million MMBtus and 6.6 million MWhs at December 31, 2018.
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 natural gas and electric contracts; and North American Energy Standards Board (NAESB) agreements, which standardize physical natural gas contracts. The Company believes that such agreements reduce credit risk exposure because such agreements provide for the netting and offsetting of monthly payments as well as the right of set-off in the event of counterparty default. The set-off provision can be used as a final settlement of accounts which extinguishes the mutual debts owed between the parties in exchange for a new net amount. For further details regarding the fair value of derivative instruments, see Note 10,11, "Fair Value Measurements,"Measurements", to the consolidated financial statements included in Item 8 of this report.
The following tables present the potential effect of netting arrangements, including rights of set-off associated with the Company's derivative assets and liabilities:
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
Puget Energy and Puget Sound Energy | | | | | | | | | | | |
December 31, 2019 | | | | | | | | | | | |
(Dollars in Thousands) | Gross Amount Recognized in the Consolidated Balance Sheet1 | | Gross Amounts Offset in the Consolidated Balance Sheet | | Net of Amounts Presented in the Consolidated Balance Sheet | | Gross Amounts Not Offset in the Consolidated Balance Sheet | | | | |
| | | | | | | Commodity Contracts2 | | Cash Collateral Received/Pledged | | Net Amount |
Assets: | | | | | | | | | | | |
Energy derivative contracts | $ | 31,308 | | | $ | — | | | $ | 31,308 | | | $ | (14,922) | | | $ | — | | | $ | 16,386 | |
Liabilities: | | | | | | | | | | | | | | | | | |
Energy derivative contracts | 26,121 | | | — | | | 26,121 | | | (14,922) | | | 2,000 | | | 13,199 | |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
Puget Energy and Puget Sound Energy | | | | | | | | | | | |
December 31, 2018 | | | | | | | | | | | |
(Dollars in Thousands) | Gross Amount Recognized1 | | Gross Amounts Offset in the Consolidated Balance Sheet | | Net of Amounts Presented in the Consolidated Balance Sheet | | Gross Amounts Not Offset in the Consolidated Balance Sheet | | | | |
| | | | | | | Commodity Contracts2 | | Cash Collateral Received/Pledged | | Net Amount |
Assets | | | | | | | | | | | |
Energy Derivative Contracts | $ | 49,019 | | | $ | — | | | $ | 49,019 | | | $ | (25,388) | | | $ | — | | | $ | 23,631 | |
Liabilities | | | | | | | | | | | | | | | | | |
Energy Derivative Contracts | 57,756 | | | — | | | 57,756 | | | (25,388) | | | — | | | 32,368 | |
__________
1.All Derivative Contract deals are executed under ISDA, NAESB and WSPP Master Netting Agreements with Right of set-off.
2.Balance sheet classification: Current and Long-term Unrealized loss on derivative instruments.
|
| | | | | | | | | | | | | | | | | | |
Puget Energy and Puget Sound Energy | | | | |
At December 31, 2016 |
(Dollars in Thousands) | Gross Amounts Recognized in the Statement of Financial Position 1 | Gross Amounts Offset in the Statement of Financial Position | Net of Amounts Presented in the Statement of Financial Position | Gross Amounts Not Offset in the Statement of Financial Position | |
Commodity Contracts | Cash Collateral Received/Posted | Net Amount |
Assets: | | | | | | |
Energy derivative contracts | $ | 63,079 |
| $ | — |
| $ | 63,079 |
| $ | (42,858 | ) | $ | — |
| $ | 20,221 |
|
Liabilities: | | | | | | |
Energy derivative contracts | 60,430 |
| — |
| 60,430 |
| (42,858 | ) | — |
| 17,572 |
|
Interest rate swaps2 | 141 |
| — |
| 141 |
| — |
| — |
| 141 |
|
| | | | | | |
Puget Energy and Puget Sound Energy | | | | |
At December 31, 2015 |
(Dollars in Thousands) | Gross Amounts Recognized in the Statement of Financial Position 1 | Gross Amounts Offset in the Statement of Financial Position | Net of Amounts Presented in the Statement of Financial Position | Gross Amounts Not Offset in the Statement of Financial Position | |
Commodity Contracts | Cash Collateral Received/Posted | Net Amount |
Assets: | | | | | | |
Energy derivative contracts | $ | 29,643 |
| $ | — |
| $ | 29,643 |
| $ | (23,998 | ) | $ | — |
| $ | 5,645 |
|
Liabilities: | | | | | | |
Energy derivative contracts | 179,196 |
| — |
| 179,196 |
| (23,998 | ) | — |
| 155,198 |
|
Interest rate swaps2 | 5,050 |
| — |
| 5,050 |
| — |
| — |
| 5,050 |
|
_______________
| |
1
| All Derivative Contract deals are executed under ISDA, NAESB and WSPP Master Netting Agreements with Right of set-off. |
| |
2
| Interest Rate Swap Contracts are only held at Puget Energy. |
The following tables present the effect and locations of the realized and unrealized gains (losses) of the Company's derivatives recorded on the statements of income:
|
| | | | | | | | | | |
Puget Energy | | Year Ended December 31, |
(Dollars in Thousands) | Location | 2016 | 2015 | 2014 |
Interest rate contracts: | | | | |
| Non-hedged interest rate swap (expense) income | $ | (1,062 | ) | $ | (3,796 | ) | $ | (3,915 | ) |
| Interest expense | — |
| 560 |
| 500 |
|
Gas for Power Derivatives: | | | | |
Unrealized | Unrealized gain (loss) on derivative instruments, net | 62,318 |
| (9,315 | ) | (42,334 | ) |
Realized | Electric generation fuel | (39,656 | ) | (44,648 | ) | 6,511 |
|
Power Derivatives: | | | | |
Unrealized | Unrealized gain (loss) on derivative instruments, net1 | 21,477 |
| 22,548 |
| (41,812 | ) |
Realized | Purchased electricity | (21,998 | ) | (39,137 | ) | (4,212 | ) |
Total gain (loss) recognized in income on derivatives | | $ | 21,079 |
| $ | (73,788 | ) | $ | (85,262 | ) |
| Puget Energy and Puget Sound Energy | | Puget Energy and Puget Sound Energy | | Year Ended December 31, | |
(Dollars in Thousands) | | (Dollars in Thousands) | Location | 2019 | | 2018 | | 2017 |
Interest rate contracts1: | | Interest rate contracts1: | | | | | | |
| | | Non-hedged interest rate swap (expense) income | $ | — | | | $ | — | | | $ | 28 | |
| Puget Sound Energy | | Year Ended December 31, | |
(Dollars in Thousands) | Location | 2016 | 2015 | 2014 | |
Gas for Power Derivatives: | | | Gas for Power Derivatives: | | | | | | | | | |
Unrealized | Unrealized gain (loss) on derivative instruments, net | $ | 62,318 |
| $ | (9,315 | ) | $ | (42,334 | ) | Unrealized | Unrealized gain (loss) on derivative instruments, net | 16,970 | | | 23,186 | | | (32,492) | |
Realized | Electric generation fuel | (39,656 | ) | (44,648 | ) | 6,511 |
| Realized | Electric generation fuel | 10,828 | | | 26,222 | | | (23,195) | |
Power Derivatives: | | | Power Derivatives: | | | | | | | | | |
Unrealized | Unrealized gain (loss) on derivative instruments, net1 | 21,477 |
| 22,003 |
| (43,302 | ) | Unrealized | Unrealized gain (loss) on derivative instruments, net | (20,544) | | | 18,476 | | | 1,702 | |
Realized | Purchased electricity | (21,998 | ) | (39,137 | ) | (4,212 | ) | Realized | Purchased electricity | 48,686 | | | 12,240 | | | (17,873) | |
Total gain (loss) recognized in income on derivatives | | $ | 22,141 |
| $ | (71,097 | ) | $ | (83,337 | ) | Total gain (loss) recognized in income on derivatives | | $ | 55,940 | | | $ | 80,124 | | | $ | (71,830) | |
_______________
| |
1
| Differences between Puget Energy and PSE for the twelve months ended December 31, 2015 and 2014 are due to certain derivative contracts recorded at fair value in 2009 and subsequently designated as NPNS or cash flow hedges. These differences occurred through February 2015. |
1.Interest rate swap contracts were held at Puget Energy, and matured January 2017.
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, and exposure monitoring and exposure mitigation.
The Company monitors counterparties that havefor significant swings in credit default swap rates, have credit rating changes by external rating agencies, haveownership 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, 2016,2019, approximately 93.1%95.0% of the Company's energy portfolio exposure, excluding NPNSnormal purchase normal sale (NPNS) transactions, is with counterparties that are rated investment grade by rating agencies and 6.9%5.0% are either rated below investment grade or not rated by rating agencies. The Company assesses credit risk internally for counterparties that are not rated by the major rating agencies.
The Company computes credit reserves at a master agreement level by counterparty. The Company considers external credit ratings and market factors, such as credit default swaps and bond spreads, in the determination of reserves. The Company recognizes
that external ratings may not always reflect how a market participant perceives a counterparty's risk of default. The Company uses both default factors published by Standard & Poor's and factors derived through analysis of market risk, which reflect the application of an industry standard recovery rate. The Company selects a default factor by counterparty at an aggregate master agreement level based on a weighted average default tenor for that counterparty's deals. The default tenor is determined by weighting the fair value and contract tenors for all deals for each counterparty to derive an average value. The default factor used is dependent upon whether the counterparty is in a net asset or a net liability position after applying the master agreement levels.
The Company applies the counterparty's default factor to compute credit reserves for counterparties that are in a net asset position. The Company calculates a non-performance risk on its derivative liabilities by using its estimated incremental borrowing rate over the risk-free rate. Credit reserves are netted against unrealized gain (loss) positions. As of December 31, 2016,2019, the Company was in a net assetliability position with the majority of counterparties, however,so the default factors of counterparties did not have a significant impact on reserves for the period. The majority of the Company's derivative contracts are with financial institutions and other utilities operating within the Western Electricity Coordinating Council. PSE also transacts power futures contracts on the Intercontinental Exchange (ICE), and natural gas contracts on the ICE NGX exchange platform. Execution of contracts on ICE requires the daily posting of margin calls as collateral through a futures and clearing agent. As of December 31, 2016,2019, PSE had cash posted as collateral of $14.8 million related to contracts executed on the ICE platform. Also, as of December 31, 2019, PSE has posted a $1.0 million letter of credit posted as collateral as a condition of transacting on a physical energy exchange and clearinghouse in Canada.the ICE NGX exchange. PSE did not trigger any collateral requirements with any of its counterparties during the twelve months ended December 31, 2016,2019, nor were any of PSE's counterparties required to post collateral resulting from credit rating downgrades.
The following table below presents the aggregate fair value of all derivative instruments with credit-risk-related contingent features that are in a liability position and the overall contractual contingent liability positions foramount of additional collateral the Company's derivative activity:Company could be required to post:
| | Puget Energy and Puget Sound Energy | At December 31, | Puget Energy and Puget Sound Energy | December 31, | |
(Dollars in Thousands) | 2016 | 2015 | (Dollars in Thousands) | 2019 | | | 2018 | |
Contingent Feature | Fair Value1 Liability | Posted Collateral | Contingent Collateral | Fair Value1 Liability | Posted Collateral | Contingent Collateral | Contingent Feature | Fair Value1 Liability | | Posted Collateral | | Contingent Collateral | | Fair Value1 Liability | | Posted Collateral | | Contingent Collateral |
Credit rating2 | $ | 4,894 |
| $ | — |
| $ | 4,894 |
| $ | 24,187 |
| $ | — |
| $ | 24,187 |
| Credit rating2 | $ | 6,110 | | | $ | — | | | $ | 6,110 | | | $ | 574 | | | $ | — | | | $ | 574 | |
Requested credit for adequate assurance | 7,427 |
| — |
| — |
| 67,003 |
| — |
| — |
| Requested credit for adequate assurance | 5,253 | | | — | | | — | | | 18,495 | | | — | | | — | |
Forward value of contract3 | 507 |
| — |
| — |
| — |
| — |
| — |
| Forward value of contract3 | — | | | 14,827 | | | N/A | | | — | | | — | | | — | |
Total | $ | 12,828 |
| $ | — |
| $ | 4,894 |
| $ | 91,190 |
| $ | — |
| $ | 24,187 |
| Total | $ | 11,363 | | | $ | 14,827 | | | $ | 6,110 | | | $ | 19,069 | | | $ | — | | | $ | 574 | |
_______________
| |
1
| Represents the derivative fair value of contracts with contingent features for counterparties in net derivative liability positions. Excludes NPNS, accounts payable and accounts receivable. |
| |
2
| Failure by PSE to maintain an investment grade credit rating from each of the major credit rating agencies provides counterparties a contractual right to demand collateral. |
| |
3
| Collateral requirements may vary, based on changes in the forward value of underlying transactions relative to contractually defined collateral thresholds. |
1.Represents the derivative fair value of contracts with contingent features for counterparties in net derivative liability positions. Excludes NPNS, accounts payable and accounts receivable.
2.Failure by PSE to maintain an investment grade credit rating from each of the major credit rating agencies provides counterparties a contractual right to demand collateral.
3.Collateral requirements may vary, based on changes in the forward value of underlying transactions relative to contractually defined collateral thresholds. (10)
(11) 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;curves, contract terms and prices;prices, credit-risk adjustments;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 becauseas 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 and natural gas and interest rate swap contracts as Level 2 derivative instruments as such contracts are commonly traded as over-the-counter forwards with indirectly observable price quotes. However, certain energy derivative instruments with maturity dates falling outside the range of observable price quotes are classified as Level 3 in the fair value hierarchy. Management's assessment wasis 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 Level 2 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 carrying values of cash and cash equivalents, restricted cash, and short-term debt as reported on the balance sheet are reasonable estimates of their fair value due to the short-term nature of these instruments and are classified as Level 1 in the fair value hierarchy. The carrying value of other investments of $49.1$51.5 million and $52.8$49.5 million at December 31, 20162019, and 2015,2018, respectively, are included in other"Other property and investmentsinvestments" on the balance sheet. These values are also reasonable estimates of their fair value and classified as Level 2 in the fair value hierarchy as they are valued based on market rates for similar transactions.
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 CompanyCompany's credit spreads as inputs, interpolating to the maturity date of each issue. CarryingThe carrying values and estimated fair values were as follows:
|
| | | | | | | | | | | | | |
Puget Energy | | At December 31, 2016 | At December 31, 2015 |
(Dollars in Thousands) | Level | Carrying Value | Fair Value | Carrying Value | Fair Value |
Liabilities: | | | | | |
Junior subordinated notes | 2 | $ | 250,000 |
| $ | 210,261 |
| $ | 250,000 |
| $ | 211,173 |
|
Long-term debt (fixed-rate), net of discount1 | 2 | 5,091,593 |
| 6,337,287 |
| 5,077,518 |
| 6,308,831 |
|
Long-term debt (variable-rate) | 2 | 12,480 |
| 12,480 |
| — |
| — |
|
Total | | $ | 5,354,073 |
| $ | 6,560,028 |
| $ | 5,327,518 |
| $ | 6,520,004 |
|
| | | | | |
Puget Sound Energy | | At December 31, 2016 | At December 31, 2015 |
(Dollars in Thousands) | Level | Carrying Value | Fair Value | Carrying Value | Fair Value |
Liabilities: | | | | | |
Junior subordinated notes | 2 | $ | 250,000 |
| $ | 210,261 |
| $ | 250,000 |
| $ | 211,173 |
|
Long-term debt (fixed-rate), net of discount2 | 2 | 3,497,298 |
| 4,360,783 |
| 3,494,362 |
| 4,329,444 |
|
Total | | $ | 3,747,298 |
| $ | 4,571,044 |
| $ | 3,744,362 |
| $ | 4,540,617 |
|
_______________ | |
1
| The carrying value includes debt issuances costs of $33.0 million and $38.4 million for December 31, 2016 and 2015, respectively, which are not included in fair value. |
| |
2
| The carrying value includes debt issuances costs of $27.2 million and $30.0 million for December 31, 2016 and 2015, respectively, which are not included in fair value. |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
Puget Energy | | | December 31, 2019 | | | | December 31, 2018 | | |
(Dollars in Thousands) | Level | | Carrying Value | | Fair Value | | Carrying Value | | Fair Value |
Financial liabilities: | | | | | | | | | |
| | | | | | | | | |
Long-term debt (fixed-rate), net of discount1 | 2 | | $ | 5,512,225 | | | $ | 7,004,316 | | | $ | 5,510,591 | | | $ | 6,443,742 | |
Long-term debt (variable-rate), net of discount | 2 | | 408,100 | | | 408,100 | | | 161,900 | | | 161,900 | |
Total | | | $ | 5,920,325 | | | $ | 7,412,416 | | | $ | 5,672,491 | | | $ | 6,605,642 | |
| | | | | | | | | |
Puget Sound Energy | | | December 31, 2019 | | | | December 31, 2018 | | |
(Dollars in Thousands) | Level | | Carrying Value | | Fair Value | | Carrying Value | | Fair Value |
Financial liabilities: | | | | | | | | | |
| | | | | | | | | |
Long-term debt (fixed-rate), net of discount2 | 2 | | $ | 4,336,142 | | | $ | 5,571,818 | | | $ | 3,894,860 | | | $ | 4,574,611 | |
Total | | | $ | 4,336,142 | | | $ | 5,571,818 | | | $ | 3,894,860 | | | $ | 4,574,611 | |
_______________
1.The carrying value includes debt issuances costs of $24.1 million and $26.1 million for December 31, 2019, and 2018, respectively, which are not included in fair value.
2.The carrying value includes debt issuances costs of $24.4 million and $24.6 million for December 31, 2019, and 2018, respectively, which are not included in fair value.
Assets and Liabilities Measured at Fair Value on a Recurring Basis
The following tables present the Company's financial assets and liabilities by level, within the fair value hierarchy, that were accounted for at fair value on a recurring basis and the reconciliation of the changes in the fair value of Level 3 derivatives in the fair value hierarchy:
| | Puget Energy | Fair Value | |
| At December 31, 2016 | At December 31, 2015 | |
Puget Energy and Puget Sound Energy | | Puget Energy and Puget Sound Energy | Fair Value | | | Fair Value | |
| | December 31, 2019 | | | December 31, 2018 | |
(Dollars in Thousands) | Level 2 | Level 3 | Total | Level 2 | Level 3 | Total | (Dollars in Thousands) | Level 2 | | Level 3 | | Total | | Level 2 | | Level 3 | | Total |
Assets: | | Assets: | | | | | | | | | | | |
Electric Derivative Instruments | | Electric Derivative Instruments | $ | 19,282 | | | $ | 651 | | | $ | 19,933 | | | $ | 28,765 | | | $ | 4,522 | | | $ | 33,287 | |
Gas Derivative Instruments | | Gas Derivative Instruments | 9,852 | | | 1,523 | | | 11,375 | | | 12,247 | | | 3,485 | | | 15,732 | |
Total derivative assets | | Total derivative assets | $ | 29,134 | | | $ | 2,174 | | | $ | 31,308 | | | $ | 41,012 | | | $ | 8,007 | | | $ | 49,019 | |
Liabilities: | | | | Liabilities: | | | | | | | | | | | | | | | | | |
Interest rate derivative instruments | $ | 141 |
| $ | — |
| $ | 141 |
| $ | 5,050 |
| $ | — |
| $ | 5,050 |
| |
Electric Derivative Instruments | | Electric Derivative Instruments | $ | 13,474 | | | $ | 4,030 | | | $ | 17,504 | | | $ | 24,124 | | | $ | 3,160 | | | $ | 27,284 | |
Gas Derivative Instruments | | Gas Derivative Instruments | 8,376 | | | 241 | | | 8,617 | | | 28,660 | | | 1,812 | | | 30,472 | |
Total derivative liabilities | $ | 141 |
| $ | — |
| $ | 141 |
| $ | 5,050 |
| $ | — |
| $ | 5,050 |
| Total derivative liabilities | $ | 21,850 | | | $ | 4,271 | | | $ | 26,121 | | | $ | 52,784 | | | $ | 4,972 | | | $ | 57,756 | |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
Puget Energy and Puget Sound Energy | Year Ended December 31, | | | | | | | | | | | | | | | | |
Level 3 Roll-Forward Net Asset(Liability) | 2019 | | | | | | 2018 | | | | | | 2017 | | | | |
(Dollars in Thousands) | Electric | | Natural Gas | | Total | | Electric | | Natural Gas | | Total | | Electric | | Natural Gas | | Total |
Balance at beginning of period | $ | 1,362 | | | $ | 1,673 | | | $ | 3,035 | | | $ | 1,098 | | | $ | 1,923 | | | $ | 3,021 | | | $ | 972 | | | $ | 625 | | | $ | 1,597 | |
Changes during period | | | | | | | | | | | | | | | | | | | | | | |
Realized and unrealized energy derivatives: | | | | | | | | | | | | | | | | | | | | | | |
Included in earnings1 | 3,558 | | | — | | | 3,558 | | | 34,604 | | | — | | | 34,604 | | | 2,781 | | | — | | | 2,781 | |
Included in regulatory assets / liabilities | — | | | 3,151 | | | 3,151 | | | — | | | 6,075 | | | 6,075 | | | — | | | 6,346 | | | 6,346 | |
Settlements2 | (11,265) | | | (4,708) | | | (15,973) | | | (33,067) | | | (7,197) | | | (40,264) | | | (6,549) | | | (6,372) | | | (12,921) | |
Transferred into Level 3 | 4,390 | | | (398) | | | 3,992 | | | (1,987) | | | — | | | (1,987) | | | 523 | | | (553) | | | (30) | |
Transferred out Level 3 | (1,424) | | | 1,564 | | | 140 | | | 714 | | | 872 | | | $ | 1,586 | | | 3,371 | | | 1,877 | | | $ | 5,248 | |
Balance at end of period | $ | (3,379) | | | $ | 1,282 | | | $ | (2,097) | | | $ | 1,362 | | | $ | 1,673 | | | $ | 3,035 | | | $ | 1,098 | | | $ | 1,923 | | | $ | 3,021 | |
|
| | | | | | | | | | | | | | | | | | |
Puget Energy and Puget Sound Energy | Fair Value | Fair Value |
At December 31, 2016 | At December 31, 2015 |
(Dollars in Thousands) | Level 2 | Level 3 | Total | Level 2 | Level 3 | Total |
Assets: | | | | | | |
Electric derivative instruments | $ | 30,666 |
| $ | 5,794 |
| $ | 36,460 |
| $ | 10,709 |
| $ | 12,734 |
| $ | 23,443 |
|
Natural gas derivative instruments | 23,316 |
| 3,303 |
| 26,619 |
| 4,538 |
| 1,662 |
| 6,200 |
|
Total derivative assets | $ | 53,982 |
| $ | 9,097 |
| $ | 63,079 |
| $ | 15,247 |
| $ | 14,396 |
| $ | 29,643 |
|
Liabilities: | |
| |
| |
| |
| |
| |
|
Electric derivative instruments | $ | 36,507 |
| $ | 4,822 |
| $ | 41,329 |
| $ | 92,027 |
| $ | 20,079 |
| $ | 112,106 |
|
Natural gas derivative instruments | 16,423 |
| 2,678 |
| 19,101 |
| 63,045 |
| 4,045 |
| 67,090 |
|
Total derivative liabilities | $ | 52,930 |
| $ | 7,500 |
| $ | 60,430 |
| $ | 155,072 |
| $ | 24,124 |
| $ | 179,196 |
|
__________________
1.Income Statement classification: 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 $(3.2) million, $1.1 million and $1.5 million for the years ended December 31, 2019, 2018, and 2017, respectively. |
| | | | | | | | | | | | | | | | | | | | | | | | | | | |
Puget Energy and Puget Sound Energy | Year Ended December 31, |
Level 3 Roll-Forward Net (Liability) | 2016 | 2015 | 2014 |
(Dollars in Thousands) | Electric | Gas | Total | Electric | Gas | Total | Electric | Gas | Total |
Balance at beginning of period | $ | (7,345 | ) | $ | (2,383 | ) | $ | (9,728 | ) | $ | (12,062 | ) | $ | (2,040 | ) | $ | (14,102 | ) | $ | (15,421 | ) | $ | (361 | ) | $ | (15,782 | ) |
Changes during period | | | | | | |
|
| |
Realized and unrealized energy derivatives: | | | | | | |
|
| |
Included in earnings1 | 4,007 |
| — |
| 4,007 |
| (6,432 | ) | — |
| (6,432 | ) | (5,537 | ) | — |
| (5,537 | ) |
Included in regulatory assets / liabilities | — |
| 4,312 |
| 4,312 |
| — |
| 3,695 |
| 3,695 |
| — |
| 1,630 |
| 1,630 |
|
Settlements2 | (1,129 | ) | (2,679 | ) | (3,808 | ) | 902 |
| (3,885 | ) | (2,983 | ) | 1,036 |
| (1,534 | ) | (498 | ) |
Transferred into Level 3 | (3,021 | ) | — |
| (3,021 | ) | (787 | ) | — |
| (787 | ) | 5,155 |
| (585 | ) | 4,570 |
|
Transferred out of Level 3 | 8,460 |
| 1,375 |
| 9,835 |
| 11,034 |
| (153 | ) | 10,881 |
| 2,705 |
| (1,190 | ) | 1,515 |
|
Balance at end of period | $ | 972 |
| $ | 625 |
| $ | 1,597 |
| $ | (7,345 | ) | $ | (2,383 | ) | $ | (9,728 | ) | $ | (12,062 | ) | $ | (2,040 | ) | $ | (14,102 | ) |
2.The Company had no purchases, sales or issuances during the reported periods._______________
| |
1
| Income Statement location: Unrealized (gain) loss on derivative instruments, net. Includes unrealized gains (losses) on derivatives still held in position as of the reporting date for electric derivatives of $2.0 million, $(7.4) million and $(9.6) million for the years ended December 31, 2016, 2015 and 2014, respectively.
|
| |
2
| The Company had no purchases, sales or issuances during the reported periods. |
Realized gains and losses on energy derivatives for Level 3 recurring items are included in energy costs in the Company's consolidated statements of income under purchased electricity, electric generation fuel or purchased natural gas when settled. Unrealized gains and losses on energy derivatives for Level 3 recurring items are included in net unrealized (gain) loss on derivative instruments in the Company's consolidated statements of income.
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, 20162019, 2018, and 2015.2017. The Company does periodically transact at locations, or market price points, that are illiquid or for which no prices are available from the independent pricing service. In such circumstances the Company uses a more liquid price point and performs a 15-month regression against the illiquid locations to serve as a proxy for market prices. Such transactions are classified as Level 3. The Company does not use internally developed models to make adjustments to significant unobservable pricing inputs.
The only significant unobservable input into the fair value measurement of the Company's Level 3 assets and liabilities is the forward price for electric and natural gas contracts.
Below are the forward price ranges for the Company's commodity contracts, as of December 31, 2016:2019:
| | Puget Energy and Puget Sound Energy | Fair Value | | Range | | Puget Energy and Puget Sound Energy | Fair Value | | | | | | | Range | |
(Dollars in Thousands) | Assets1 | Liabilities1 | Valuation Technique | Unobservable Input | Low | High | Weighted Average | (Dollars in Thousands) | Assets1 | | Liabilities1 | | Valuation Technique | | Unobservable Input | | Low | | High | | Weighted |
Electric | $5,794 | $4,822 | Discounted cash flow | Power Prices | $11.86 per MWh | $33.52 per MWh | $27.61 per MWh | |
Natural gas | $3,303 | $2,678 | Discounted cash flow | Natural Gas Prices | $2.00 per MMBtu | $3.24 per MMBtu | $2.42 per MMBtu | |
Electricity | | Electricity | $ | 651 | | | $ | 4,030 | | | Discounted cash flow | | Power Prices (per MWh) | | $ | 9.00 | | | $ | 43.85 | | | $ | 33.99 | |
Natural Gas | | Natural Gas | $ | 1,523 | | | $ | 241 | | | Discounted cash flow | | Natural Gas Prices (per MMBtu) | | $ | 1.25 | | | $ | 3.18 | | | $ | 2.47 | |
_______________
| |
1
| The valuation techniques, unobservable inputs and ranges are the same for asset and liability positions. |
1 The valuation techniques, unobservable inputs and ranges are the same for asset and liability positions.
The significant unobservable inputs listed above would have a direct impact on the fair values of the above instruments if they were adjusted. Consequently, significant increases or decreases in the forward prices of electricity or natural gas in isolation would result in a significantly higher or lower fair value for Level 3 assets and liabilities. Generally, interrelationships exist between market prices of natural gas and power. As such, an increase in natural gas pricing would potentially have a similar impact on forward power markets. At December 31, 2016,2019, a hypothetical 10% increase or decrease in market prices of natural gas and electricity would change the fair value of the Company's derivative portfolio, classified as Level 3 within the fair value hierarchy, by $0.2$2.5 million.
Long-Lived Assets Measured at Fair Value on a Nonrecurring Basis
Puget Energy records 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 anyrecoverability whenever events or changes in circumstances indicate that wouldits carrying amount may not be more likely than not to reduce the fair value of the long-lived assets below their carrying value.recoverable. One such triggering event is a significant decrease in the forward market prices of power.
Puget Energy evaluated the triggering event criteria in ASC 360 during 2019 and determined there was no indication of impairment of its power purchase contracts. During 20162018, decreases in forward power prices and 2015,decreases in forecasted revenue and cost estimates indicated the carrying value of Puget Energy’s power purchase contracts may not have been recoverable. Puget Energy completed valuation and impairment testing of its power purchase contracts classified as intangible assets. In 2016 and 2015, due to decreases in forecasted revenue and cost estimates and continued significant decreases in forward power prices,2018, the following impairments were recorded to the Company's intangible asset contracts, with corresponding reductions to the regulatory liability as follows:
| | Puget Energy | | | Puget Energy | | | | | |
(Dollars in Thousands) | | | (Dollars in Thousands) | | | | | |
Valuation Date | Contract Name | Carrying Value | Fair Value | Write Down | Valuation Date | Contract Name | Carrying Value | | Fair Value | | Write Down |
September 30, 2016 | Priest Rapids | $ | 18,969 |
| $ | 6,191 |
| $ | 12,778 |
| |
March 31, 2016 | Wells Hydro | 25,193 |
| 19,855 |
| 5,338 |
| |
December 31, 2015 | Wells Hydro | 32,988 |
| 27,628 |
| 5,360 |
| |
March 31, 2018 | | March 31, 2018 | Wells Hydro | $ | 4,302 | | | $ | 2,395 | | | $ | 1,907 | |
Total 2018 Impairments | | Total 2018 Impairments | | | | | | | | $ | 1,907 | |
The valuations were measured using a discounted cash flow, income-based valuation methodology. 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 impaired long termlong-term power purchase contracts' fair value in 20162019 and 2015:2018:
| | | | | | | | | | | | | | | | | | | | | | | |
Puget Energy | | | | | | | |
Valuation Date | Contract | Unobservable Input | Low | | High | | Average |
March 31, 2018 | Wells Hydro | Power prices (per MWh) | $ | 9.69 | | | $ | 25.30 | | | $ | 17.50 | |
| | Power contract costs per quarter (in thousands) | 4,126 | | | 4,126 | | | 4,126 | |
|
| | | | |
Puget Energy | | | | |
Valuation Date | Unobservable Input | Low | High | Average |
September 30, 2016 | | | | |
| Power prices | $24.24 per MWh | $58.96 per MWh | $39.31 per MWh |
| Power contract costs (in thousands) | $618 per year | $4,633 per year | $2,472 per year |
March 31, 2016 | | | | |
| Power prices | $9.46 per MWh | $25.96 per MWh | $21.38 per MWh |
| Power contract costs (in thousands) | $4,100 per qtr. | $4,659 per qtr. | $4,452 per qtr. |
December 31, 2015 | | | | |
| Power prices | $15.16 per MWh | $27.25 per MWh | $23.23 per MWh |
| Power contract costs (in thousands) | $4,100 per qtr. | $4,659 per qtr. | $4,417 per qtr. |
(11)(12) Employee Investment Plans
The Company's Investment Plan is a qualified employee 401(k) plan, under which employee salary deferrals and after-tax contributions are used to purchase several different investment fund options. PSE’s contributions to the employee Investment Plan were $17.2$21.7 million, $16.1$20.7 million and $14.9$19.2 million for the years 2016, 20152019, 2018, and 2014,2017, respectively. The employee Investment Plan eligibility requirements are set forth in the plan documents.
Non-represented employees and United Association of Journeymen and Apprentices of the Plumbing and Pipefitting Industry (UA) represented employees hired before January 1, 2014, and International Brotherhood of Electrical Workers Local Union 77 (IBEW) represented employees hired before December 12, 2014, have the following company contributions:
1.For employees under the Cash Balance retirement plan formula, PSE will match 100% of an employee's contribution up to 6%6.0% of plan compensation each paycheck, and will make an additional year-end contribution equal to 1%1.0% of base pay.
2.For employees grandfathered under the Final Average Earning retirement plan formula, PSE will match 55%55.0% of an employee’s contribution up to 6%6.0% of plan compensation each paycheck.
Non-represented and UA-represented employees hired on or after January 1, 2014 along with IBEW-represented employees hired on or after December 12, 2014, will have access to the 401(k) plan. The two contribution sources from PSE are below:
1.401(k) Company Matching: NewFor non-represented, UA-represented and IBEW-represented employees PSE will receive company match each paycheck based on a new schedule-100%match: 100% match on the first 3%3.0% of pay contributed and 50%50.0% match on the next 3%3.0% of pay contributed. Ancontributed, such that an employee who contributes 6%6.0% of pay will receive 4.5% of pay in company match. Company matching will be immediately vested.
2.Company Contribution: NewFor UA-represented employees will receive an annual company contribution of 4%4.0% of eligible pay placed in the Cash Balance retirement plan. New non-representedNon-represented and IBEW-represented employees will receive an annual company contribution of 4%4.0% of eligible pay, placed either in the Investment Plan 401(k) plan or in PSE’s Cash Balance retirement plan. New non-representedNon-represented and IBEW-represented employees will make a one-time election within 30 days of hire and direct that PSE put the 4%4.0% contribution either into the 401(k) plan or into an account in the Cash Balance retirement plan. The Company’s 4%Company's 4.0% contribution will vest after three years of service.
(12)(13) Retirement Benefits
PSE has a defined benefit pension plan (Qualified Pension Benefits) covering the largest portiona substantial majority of PSE employees. Pension benefits earned are a function of age, salary, years of service and, in the case of employees in the cash balance formula plan, the applicable annual interest crediting rates. Starting with January 1, 2014, all non-represented and UA-representedUA represented employees along with IBEW-represented employees hired on or after December 12, 2014 who elect to accumulate the Company contributionwill receive annual pay contributions of 4.0% of eligible pay each year in the cash balance formula portionplan of the pension plan,defined benefit pension. Starting January 1, 2014, for non-represented employees, and December 12, 2014 for employees represented by the IBEW, participants will receive annual employer contributions of 4.0% of eligible pay creditseach year in the cash balance formula of 4% each year. They willthe defined benefit pension or 401k plan account. Those employees receiving contributions in the cash balance formula plan also receive interest credits, like other participants in the cash balance pension formula of the pension plan, which are at least 1%1.0% per quarter. When an employee with a vested cash balance formula benefit leaves PSE, he or shethey will have annuity and lump sum options for distribution. Those who select the lump sum option will receive their current cash balance amount. PSE also maintainshas a non-qualified Supplemental Executive Retirement Plan (SERP) for itscertain key senior management employees.employees that closed to new participants in 2019. PSE has an officer restoration benefit for new officers who join PSE or are promoted beginning in 2019,
such that company contributions under PSE’s applicable tax-qualified plan, which otherwise would have been earned if not for IRS limitations, are credited to an account with the Deferred Compensation Plan.
In addition to providing pension benefits, PSE provides legacy group health care and life insurance benefits (Other Benefits) for certain retired employees. These benefits are provided principally through an insurance company. The insurance premiums, paid primarily by retirees, are based on the benefits provided during the prior year. On June 11, 2019, the Welfare Benefits Committee approved the termination of the Plan effective December 31, 2019, and the creation of a Retiree Health Reimbursement Account (HRA) Plan effective January 1, 2020. No eligible individual may become a participant or covered dependent in the Plan on or after January 1, 2020, and no benefits will be payable under insurance contracts or the Plan on or after January 1, 2020. Effective January 1, 2020, assets in the 401(h) account will be allocated to the Retiree HRA instead of the Plan to cover the Company's portion of premiums for health benefits for retiree and their beneficiaries.
Puget Energy records purchase accounting adjustments associated with the re-measurementEnergy's retirement plans were remeasured as a result of the merger in 2009, which represents the difference between Puget Energy and PSE's retirement plans.
In March 2017, the FASB issued ASU 2017-07, requiring that an employer report the service cost component in the same line items as other compensation costs arising from services rendered by the pertinent employees during the period. The other components of net benefit cost (which include interest costs, expected return on plan assets, amortization of prior service cost or credits and actuarial gains and losses) are required to be presented in the income statement separately from the service cost component and outside a subtotal of income from operations. Pursuant to the standard, the Company has retrospectively included in the consolidated statements of income: (i) the components of service cost within utility operations and maintenance for PSE and within non-utility expense and other for Puget Energy, and (ii) all non-service cost components in other income.
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, 20162019, and 2015:2018:
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
Puget Energy and Puget Sound Energy | Qualified Pension Benefits | | | | SERP Pension Benefits | | | | Other Benefits | | |
(Dollars in Thousands) | 2019 | | 2018 | | 2019 | | 2018 | | 2019 | | 2018 |
Change in benefit obligation: | | | | | | | | | | | | | | | | | |
Benefit obligation at beginning of period | $ | 677,643 | | | $ | 700,481 | | | $ | 55,708 | | | $ | 55,754 | | | $ | 10,636 | | | $ | 11,454 | |
Amendments | — | | | — | | | — | | | 1,446 | | | 9,049 | | | — | |
Service cost | 22,656 | | | 22,757 | | | 1,023 | | | 847 | | | 61 | | | 69 | |
Interest cost | 28,913 | | | 27,303 | | | 2,314 | | | 2,120 | | | 410 | | | 444 | |
Curtailment Loss / (Gain) | — | | | — | | | — | | | — | | | (7,486) | | | — | |
Actuarial loss (gain) | 84,272 | | | (29,067) | | | 6,756 | | | 1,122 | | | (287) | | | (379) | |
Benefits paid | (36,740) | | | (42,662) | | | (2,801) | | | (5,581) | | | (982) | | | (1,037) | |
Medicare part D subsidy received | — | | | — | | | — | | | — | | | 226 | | | 85 | |
Administrative expense | (2,439) | | | (1,169) | | | — | | | — | | | — | | | — | |
Benefit obligation at end of period | $ | 774,305 | | | $ | 677,643 | | | $ | 63,000 | | | $ | 55,708 | | | $ | 11,627 | | | $ | 10,636 | |
|
| | | | | | | | | | | | | | | | | | |
Puget Energy and Puget Sound Energy | Qualified Pension Benefits | SERP Pension Benefits | Other Benefits |
(Dollars in Thousands) | 2016 | 2015 | 2016 | 2015 | 2016 | 2015 |
Change in benefit obligation: | | | | | | |
Benefit obligation at beginning of period | $ | 643,088 |
| $ | 690,194 |
| $ | 51,279 |
| $ | 55,855 |
| $ | 13,946 |
| $ | 15,688 |
|
Service cost | 18,913 |
| 21,287 |
| 1,085 |
| 1,108 |
| 93 |
| 112 |
|
Interest cost | 28,689 |
| 28,088 |
| 2,325 |
| 2,281 |
| 533 |
| 621 |
|
Actuarial loss (gain) | 1,545 |
| (55,665 | ) | 106 |
| (4,430 | ) | (2,262 | ) | (1,416 | ) |
Benefits paid | (38,730 | ) | (39,963 | ) | (3,061 | ) | (3,535 | ) | (1,264 | ) | (1,354 | ) |
Medicare part D subsidy received | — |
| — |
| — |
| — |
| 148 |
| 295 |
|
Administrative expense | (898 | ) | (853 | ) | — |
| — |
| — |
| — |
|
Benefit obligation at end of period | $ | 652,607 |
| $ | 643,088 |
| $ | 51,734 |
| $ | 51,279 |
| $ | 11,194 |
| $ | 13,946 |
|
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
Puget Energy and Puget Sound Energy | Qualified Pension Benefits | | | | SERP Pension Benefits | | | | Other Benefits | | |
(Dollars in Thousands) | 2019 | | 2018 | | 2019 | | 2018 | | 2019 | | 2018 |
Change in plan assets: | | | | | | | | | | | |
Fair value of plan assets at beginning of period | $ | 640,242 | | | $ | 704,360 | | | $ | — | | | $ | — | | | $ | 5,960 | | | $ | 7,138 | |
Actual return on plan assets | 133,939 | | | (38,379) | | | — | | | — | | | 1,006 | | | (395) | |
Employer contribution | 18,000 | | | 18,000 | | | 2,801 | | | 5,581 | | | 305 | | | 254 | |
Benefits paid | (36,740) | | | (42,662) | | | (2,801) | | | (5,581) | | | (982) | | | (1,037) | |
Administrative expense | (2,399) | | | (1,077) | | | — | | | — | | | — | | | — | |
Fair value of plan assets at end of period | $ | 753,042 | | | $ | 640,242 | | | $ | — | | | $ | — | | | $ | 6,289 | | | $ | 5,960 | |
Funded status at end of period | $ | (21,263) | | | $ | (37,401) | | | $ | (63,000) | | | $ | (55,708) | | | $ | (5,338) | | | $ | (4,676) | |
|
| | | | | | | | | | | | | | | | | | |
Puget Energy and Puget Sound Energy | Qualified Pension Benefits | SERP Pension Benefits | Other Benefits |
(Dollars in Thousands) | 2016 | 2015 | 2016 | 2015 | 2016 | 2015 |
Change in plan assets: | | | | | | |
Fair value of plan assets at beginning of period | $ | 598,865 |
| $ | 626,173 |
| $ | — |
| $ | — |
| $ | 7,203 |
| $ | 8,360 |
|
Actual return on plan assets | 37,022 |
| (4,489 | ) | — |
| — |
| 926 |
| (378 | ) |
Employer contribution | 24,000 |
| 18,000 |
| 3,061 |
| 3,535 |
| 335 |
| 575 |
|
Benefits paid | (38,730 | ) | (39,963 | ) | (3,061 | ) | (3,535 | ) | (1,264 | ) | (1,354 | ) |
Administrative expense | (897 | ) | (856 | ) | — |
| — |
| — |
| — |
|
Fair value of plan assets at end of period | $ | 620,260 |
| $ | 598,865 |
| $ | — |
| $ | — |
| $ | 7,200 |
| $ | 7,203 |
|
Funded status at end of period | $ | (32,347 | ) | $ | (44,223 | ) | $ | (51,734 | ) | $ | (51,279 | ) | $ | (3,994 | ) | $ | (6,743 | ) |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
Puget Energy and Puget Sound Energy | Qualified Pension Benefits | | | | SERP Pension Benefits | | | | Other Benefits | | |
(Dollars in Thousands) | 2019 | | 2018 | | 2019 | | 2018 | | 2019 | | 2018 |
Amounts recognized in Consolidated Balance Sheet consist of: | | | | | | | | | | | | | | | | | |
Noncurrent assets | $ | — | | | $ | — | | | $ | — | | | $ | — | | | $ | — | | | $ | — | |
Current liabilities | — | | | — | | | (22,604) | | | (6,249) | | | (308) | | | (332) | |
Noncurrent liabilities | (21,263) | | | (37,401) | | | (40,396) | | | (49,459) | | | (5,030) | | | (4,344) | |
Net assets (liabilities) | $ | (21,263) | | | $ | (37,401) | | | $ | (63,000) | | | $ | (55,708) | | | $ | (5,338) | | | $ | (4,676) | |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
Puget Energy and Puget Sound Energy | Qualified Pension Benefits | | | | SERP Pension Benefits | | | | Other Benefits | | |
(Dollars in Thousands) | 2019 | | 2018 | | 2019 | | 2018 | | 2019 | | 2018 |
Pension Plans with an Accumulated Benefit Obligation in excess of Plan Assets: | | | | | | | | | | | |
Projected benefit obligation | $ | 774,305 | | | $ | 677,643 | | | $ | 63,000 | | | $ | 55,708 | | | $ | 11,627 | | | $ | 10,636 | |
Accumulated benefit obligation | 762,838 | | | 668,469 | | | 59,988 | | | 51,031 | | | 11,604 | | | 10,557 | |
Fair value of plan assets | 753,042 | | | 640,242 | | | — | | | — | | | 6,289 | | | 5,960 | |
|
| | | | | | | | | | | | | | | | | | |
Puget Energy and Puget Sound Energy | Qualified Pension Benefits | SERP Pension Benefits | Other Benefits |
(Dollars in Thousands) | 2016 | 2015 | 2016 | 2015 | 2016 | 2015 |
Amounts recognized in Statement of Financial Position consist of: | | | | | | |
Noncurrent assets | $ | — |
| $ | — |
| $ | — |
| $ | — |
| $ | — |
| $ | — |
|
Current liabilities | — |
| — |
| (1,911 | ) | (2,545 | ) | (325 | ) | (353 | ) |
Noncurrent liabilities | (32,347 | ) | (44,223 | ) | (49,823 | ) | (48,734 | ) | (3,669 | ) | (6,390 | ) |
Net assets (liabilities) | $ | (32,347 | ) | $ | (44,223 | ) | $ | (51,734 | ) | $ | (51,279 | ) | $ | (3,994 | ) | $ | (6,743 | ) |
|
| | | | | | | | | | | | | | | | | | |
Puget Energy and Puget Sound Energy | Qualified Pension Benefits | SERP Pension Benefits | Other Benefits |
(Dollars in Thousands) | 2016 | 2015 | 2016 | 2015 | 2016 | 2015 |
Pension Plans with an Accumulated Benefit Obligation in excess of Plan Assets: | | | | | | |
Projected benefit obligation | $ | 652,607 |
| $ | 643,088 |
| $ | 51,734 |
| $ | 51,279 |
| $ | 11,194 |
| $ | 13,946 |
|
Accumulated benefit obligation | 641,855 |
| 635,599 |
| 47,639 |
| 46,978 |
| 11,092 |
| 13,828 |
|
Fair value of plan assets | 620,260 |
| 598,865 |
| — |
| — |
| 7,200 |
| 7,203 |
|
The following tables summarize Puget Energy's and PSE's pension benefit amounts recognized in AOCI for the years ended December 31, 20162019, and 2015:2018:
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
Puget Energy | Qualified Pension Benefits | | | | SERP Pension Benefits | | | | Other Benefits | | |
(Dollars in Thousands) | 2019 | | 2018 | | 2019 | | 2018 | | 2019 | | 2018 |
Amounts recognized in Accumulated Other Comprehensive Income consist of: | | | | | | | | | | | | | | | | | |
Net loss (gain) | $ | 94,319 | | | $ | 94,929 | | | $ | 15,003 | | | $ | 9,612 | | | $ | (197) | | | $ | (2,564) | |
Prior service cost (credit) | (3,884) | | | (5,863) | | | 1,276 | | | 1,607 | | | — | | | — | |
Total | $ | 90,435 | | | $ | 89,066 | | | $ | 16,279 | | | $ | 11,219 | | | $ | (197) | | | $ | (2,564) | |
| | Puget Energy | Qualified Pension Benefits | SERP Pension Benefits | Other Benefits | |
Puget Sound Energy | | Puget Sound Energy | Qualified Pension Benefits | | | SERP Pension Benefits | | | Other Benefits | |
(Dollars in Thousands) | 2016 | 2015 | 2016 | 2015 | 2016 | 2015 | (Dollars in Thousands) | 2019 | | 2018 | | 2019 | | 2018 | | 2019 | | 2018 |
Amounts recognized in Accumulated Other Comprehensive Income consist of: | | | | | | | Amounts recognized in Accumulated Other Comprehensive Income consist of: | | | | | | | | | | | |
Net loss (gain) | $ | 56,588 |
| $ | 45,447 |
| $ | 9,043 |
| $ | 9,848 |
| $ | (4,190 | ) | $ | (1,834 | ) | Net loss (gain) | $ | 217,502 | | | $ | 229,819 | | | $ | 16,473 | | | $ | 11,450 | | | $ | (364) | | | $ | (3,857) | |
Prior service cost (credit) | (9,822 | ) | (11,802 | ) | 246 |
| 288 |
| — |
| — |
| Prior service cost (credit) | (3,086) | | | (4,659) | | | 1,276 | | | 1,609 | | | — | | | — | |
Total | $ | 46,766 |
| $ | 33,645 |
| $ | 9,289 |
| $ | 10,136 |
| $ | (4,190 | ) | $ | (1,834 | ) | Total | $ | 214,416 | | | $ | 225,160 | | | $ | 17,749 | | | $ | 13,059 | | | $ | (364) | | | $ | (3,857) | |
|
| | | | | | | | | | | | | | | | | | |
Puget Sound Energy | Qualified Pension Benefits | SERP Pension Benefits | Other Benefits |
(Dollars in Thousands) | 2016 | 2015 | 2016 | 2015 | 2016 | 2015 |
Amounts recognized in Accumulated Other Comprehensive Income consist of: | |
| |
| |
| |
| |
| |
|
Net loss (gain) | $ | 217,143 |
| $ | 221,064 |
| $ | 11,978 |
| $ | 13,202 |
| $ | (5,994 | ) | $ | 3,834 |
|
Prior service cost (credit) | (7,806 | ) | (9,379 | ) | 251 |
| 295 |
| — |
| — |
|
Total | $ | 209,337 |
| $ | 211,685 |
| $ | 12,229 |
| $ | 13,497 |
| $ | (5,994 | ) | $ | 3,834 |
|
The following tables summarize Puget Energy's and PSE's net periodic benefit cost for the years ended December 31, 2016, 20152019, 2018, and 2014:2017.
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
Puget Energy | Qualified Pension Benefits | | | | | | SERP Pension Benefits | | | | | | Other Benefits | | | | |
(Dollars in Thousands) | 2019 | | 2018 | | 2017 | | 2019 | | 2018 | | 2017 | | 2019 | | 2018 | | 2017 |
Components of net periodic benefit cost: | | | | | | | | | | | | | | | | | |
Service cost | $ | 22,656 | | | $ | 22,757 | | | $ | 20,081 | | | $ | 1,023 | | | $ | 847 | | | $ | 913 | | | $ | 61 | | | $ | 69 | | | $ | 72 | |
Interest cost | 28,913 | | | 27,303 | | | 28,373 | | | 2,314 | | | 2,120 | | | 2,285 | | | 410 | | | 444 | | | 500 | |
Expected return on plan assets | (50,249) | | | (50,202) | | | (47,784) | | | — | | | — | | | — | | | (393) | | | (472) | | | (461) | |
Amortization of prior service cost (credit) | (1,980) | | | (1,980) | | | (1,980) | | | 331 | | | 1,580 | | | 42 | | | — | | | — | | | — | |
Amortization of net loss (gain) | 1,151 | | | 2,187 | | | — | | | 1,365 | | | 42 | | | 1,077 | | | (374) | | | (335) | | | (402) | |
Net periodic benefit cost | $ | 491 | | | $ | 65 | | | $ | (1,310) | | | $ | 5,033 | | | $ | 4,589 | | | $ | 4,317 | | | $ | (296) | | | $ | (294) | | | $ | (291) | |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
Puget Sound Energy | Qualified Pension Benefits | | | | | | SERP Pension Benefits | | | | | | Other Benefits | | | | |
(Dollars in Thousands) | 2019 | | 2018 | | 2017 | | 2019 | | 2018 | | 2017 | | 2019 | | 2018 | | 2017 |
Components of net periodic benefit cost: | | | | | | | | | | | | | | | | | |
Service cost | $ | 22,656 | | | $ | 22,757 | | | $ | 20,081 | | | $ | 1,023 | | | $ | 847 | | | $ | 913 | | | $ | 61 | | | $ | 69 | | | $ | 72 | |
Interest cost | 28,913 | | | 27,303 | | | 28,373 | | | 2,314 | | | 2,120 | | | 2,285 | | | 410 | | | 444 | | | 500 | |
Expected return on plan assets | (50,267) | | | (50,240) | | | (47,862) | | | — | | | — | | | — | | | (393) | | | (472) | | | (461) | |
Amortization of prior service cost (credit) | (1,573) | | | (1,573) | | | (1,573) | | | 333 | | | 44 | | | 44 | | | — | | | — | | | — | |
Amortization of net loss (gain) | 12,877 | | | 14,917 | | | 13,048 | | | 1,733 | | | 2,069 | | | 1,565 | | | (562) | | | (556) | | | (641) | |
Net periodic benefit cost | $ | 12,606 | | | $ | 13,164 | | | $ | 12,067 | | | $ | 5,403 | | | $ | 5,080 | | | $ | 4,807 | | | $ | (484) | | | $ | (515) | | | $ | (530) | |
|
| | | | | | | | | | | | | | | | | | | | | | | | | | | |
Puget Energy | Qualified Pension Benefits | SERP Pension Benefits | Other Benefits |
(Dollars in Thousands) | 2016 | 2015 | 2014 | 2016 | 2015 | 2014 | 2016 | 2015 | 2014 |
Components of net periodic benefit cost: | | | | | | | | | |
Service cost | $ | 18,913 |
| $ | 21,287 |
| $ | 17,437 |
| $ | 1,085 |
| $ | 1,108 |
| $ | 1,042 |
| $ | 93 |
| $ | 112 |
| $ | 112 |
|
Interest cost | 28,689 |
| 28,088 |
| 28,039 |
| 2,325 |
| 2,281 |
| 2,310 |
| 533 |
| 621 |
| 684 |
|
Expected return on plan assets | (46,619 | ) | (45,038 | ) | (42,464 | ) | — |
| — |
| — |
| (446 | ) | (531 | ) | (535 | ) |
Amortization of prior service cost (credit) | (1,980 | ) | (1,980 | ) | (1,980 | ) | 42 |
| 42 |
| 42 |
| — |
| — |
| — |
|
Amortization of net loss (gain) | — |
| 3,887 |
| — |
| 911 |
| 1,641 |
| 913 |
| (386 | ) | (130 | ) | (393 | ) |
Net periodic benefit cost | $ | (997 | ) | $ | 6,244 |
| $ | 1,032 |
| $ | 4,363 |
| $ | 5,072 |
| $ | 4,307 |
| $ | (206 | ) | $ | 72 |
| $ | (132 | ) |
|
| | | | | | | | | | | | | | | | | | | | | | | | | | | |
Puget Sound Energy | Qualified Pension Benefits | SERP Pension Benefits | Other Benefits |
(Dollars in Thousands) | 2016 | 2015 | 2014 | 2016 | 2015 | 2014 | 2016 | 2015 | 2014 |
Components of net periodic benefit cost: | | | | | | | | | |
Service cost | $ | 18,913 |
| $ | 21,287 |
| $ | 17,437 |
| $ | 1,085 |
| $ | 1,108 |
| $ | 1,042 |
| $ | 93 |
| $ | 112 |
| $ | 112 |
|
Interest cost | 28,689 |
| 28,088 |
| 28,039 |
| 2,325 |
| 2,281 |
| 2,310 |
| 533 |
| 621 |
| 684 |
|
Expected return on plan assets | (46,814 | ) | (45,462 | ) | (43,252 | ) | — |
| — |
| — |
| (446 | ) | (531 | ) | (535 | ) |
Amortization of prior service cost (credit) | (1,573 | ) | (1,573 | ) | (1,573 | ) | 44 |
| 44 |
| 44 |
| — |
| 3 |
| 3 |
|
Amortization of net loss(gain) | 15,257 |
| 20,555 |
| 13,195 |
| 1,330 |
| 2,120 |
| 1,461 |
| (632 | ) | (406 | ) | (702 | ) |
Net periodic benefit cost | $ | 14,472 |
| $ | 22,895 |
| $ | 13,846 |
| $ | 4,784 |
| $ | 5,553 |
| $ | 4,857 |
| $ | (452 | ) | $ | (201 | ) | $ | (438 | ) |
The following tables summarize Puget Energy's and PSE's benefit obligations recognized in other comprehensive income (OCI) for the years ended December 31, 20162019, and 2015:2018:
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
Puget Energy | Qualified Pension Benefits | | | | SERP Pension Benefits | | | | Other Benefits | | |
(Dollars in Thousands) | 2019 | | 2018 | | 2019 | | 2018 | | 2019 | | 2018 |
Other changes (pre-tax) in plan assets and benefit obligations recognized in other comprehensive income: | | | | | | | | | | | |
Net loss (gain) | $ | 541 | | | $ | 59,422 | | | $ | 6,756 | | | $ | 1,122 | | | $ | (900) | | | $ | 488 | |
Amortization of net (loss) gain | (1,151) | | | (2,187) | | | (1,365) | | | (1,580) | | | 374 | | | 335 | |
Settlements, mergers, sales, and closures | — | | | — | | | — | | | (619) | | | 2,892 | | | — | |
Prior service cost (credit) | — | | | — | | | — | | | 1,446 | | | — | | | — | |
Amortization of prior service (cost) credit | 1,980 | | | 1,980 | | | (331) | | | (42) | | | — | | | — | |
Total change in other comprehensive income for year | $ | 1,370 | | | $ | 59,215 | | | $ | 5,060 | | | $ | 327 | | | $ | 2,366 | | | $ | 823 | |
|
| | | | | | | | | | | | | | | | | | |
Puget Energy | Qualified Pension Benefits | SERP Pension Benefits | Other Benefits |
(Dollars in Thousands) | 2016 | 2015 | 2016 | 2015 | 2016 | 2015 |
Other changes (pre-tax) in plan assets and benefit obligations recognized in other comprehensive income: | | | | | | |
Net loss (gain) | $ | 11,141 |
| $ | (6,136 | ) | $ | 106 |
| $ | (4,430 | ) | $ | (2,742 | ) | $ | (508 | ) |
Amortization of net loss (gain) | — |
| (3,887 | ) | (910 | ) | (1,641 | ) | 385 |
| 131 |
|
Amortization of prior service credit | 1,980 |
| 1,980 |
| (42 | ) | (42 | ) | — |
| — |
|
Total change in other comprehensive income for year | $ | 13,121 |
| $ | (8,043 | ) | $ | (846 | ) | $ | (6,113 | ) | $ | (2,357 | ) | $ | (377 | ) |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
Puget Sound Energy | Qualified Pension Benefit | | | | SERP Pension Benefits | | | | Other Benefits | | |
(Dollars in Thousands) | 2019 | | 2018 | | 2019 | | 2018 | | 2019 | | 2018 |
Other changes (pre-tax) in plan assets and benefit obligations recognized in other comprehensive income: | | | | | | | | | | | |
Net loss (gain) | $ | 559 | | | $ | 59,460 | | | $ | 6,756 | | | $ | 1,122 | | | $ | (900) | | | $ | 488 | |
Amortization of net (loss) gain | (12,877) | | | (14,917) | | | (1,733) | | | (2,069) | | | 562 | | | 556 | |
Settlements, mergers, sales, and closures | — | | | — | | | — | | | (737) | | | 3,832 | | | — | |
Prior service cost (credit) | — | | | — | | | — | | | 1,446 | | | — | | | — | |
Amortization of prior service (cost) credit | 1,573 | | | 1,573 | | | (333) | | | (44) | | | — | | | — | |
Total change in other comprehensive income for year | $ | (10,745) | | | $ | 46,116 | | | $ | 4,690 | | | $ | (282) | | | $ | 3,494 | | | $ | 1,044 | |
|
| | | | | | | | | | | | | | | | | | |
Puget Sound Energy | Qualified Pension Benefit | SERP Pension Benefits | Other Benefits |
(Dollars in Thousands) | 2016 | 2015 | 2016 | 2015 | 2016 | 2015 |
Other changes (pre-tax) in plan assets and benefit obligations recognized in other comprehensive income: | | | | | | |
Net loss (gain) | $ | 11,336 |
| $ | (5,711 | ) | $ | 106 |
| $ | (4,430 | ) | $ | (2,742 | ) | $ | (508 | ) |
Amortization of net (loss) gain | (15,257 | ) | (20,556 | ) | (1,330 | ) | (2,120 | ) | 631 |
| 407 |
|
Amortization of prior service cost (credit) | 1,573 |
| 1,573 |
| (44 | ) | (44 | ) | — |
| (3 | ) |
Total change in other comprehensive income for year | $ | (2,348 | ) | $ | (24,694 | ) | $ | (1,268 | ) | $ | (6,594 | ) | $ | (2,111 | ) | $ | (104 | ) |
The estimated net (loss) gain and prior service cost (credit) for the pension plans that will be amortized from accumulated OCIAOCI into net periodic benefit cost in 20172020 by PSE are $(13.7)include a $18.6 million net loss and $(1.6)a $1.6 million credit, respectively. The estimated net (loss) gain for the SERP that will be amortized from accumulated OCI into net periodic benefit cost in 2017 is $(1.6) million. The estimatedand prior service cost (credit) for the SERP that will be amortized from accumulated OCIAOCI into net periodic benefit cost in 20172020 is immaterial.a $2.6 million net loss and a $0.3 million net loss, respectively. The estimated net (loss) gain and prior service cost (credit) for the other postretirement plans that will be amortized from accumulated OCIAOCI into net periodic benefit cost in 20172020 is immaterial.a net loss of $0.2 million. For Puget Energy, the overall amounts expected to be amortized from accumulated OCIAOCI into net period benefit cost in 2017 were immaterial.2020 is a net loss of $8.4 million.
The aggregate expected contributions by the Company to fund the qualified pension plan, SERP and the other postretirement plans for the year ending December 31, 20172020, are expected to be at least $18.0 million, $1.9$22.6 million and $0.3$0.1 million, respectively.
Assumptions
In accounting for pension and other benefit obligations and costs under the plans, the following weighted-average actuarial assumptions were used by the Company: | | | Qualified Pension Benefits | SERP Pension Benefits | Other Benefits | | Qualified Pension Benefits | | | SERP Pension Benefits | | | Other Benefits | |
Benefit Obligation Assumptions | 2016 | 2015 | 2014 | 2016 | 2015 | 2014 | 2016 | 2015 | 2014 | Benefit Obligation Assumptions | 2019 | | 2018 | | 2017 | | 2019 | | 2018 | | 2017 | | 2019 | | 2018 | | 2017 |
Discount rate | 4.50 | % | 4.65 | % | 4.25 | % | 4.50 | % | 4.65 | % | 4.25 | % | 4.50 | % | 4.65 | % | 4.25 | % | Discount rate | 3.35 | % | | 4.40 | % | | 4.00 | % | | 3.35 | % | | 4.40 | % | | 4.00 | % | | 3.35 | % | | 4.40 | % | | 4.00 | % |
Rate of compensation increase | 4.50 |
| 4.50 |
| 4.50 |
| 4.50 |
| 4.50 |
| 4.50 |
| 4.50 |
| 4.50 |
| 4.50 |
| Rate of compensation increase | 4.50 | | | 4.50 | | | 4.50 | | | 4.50 | | | 4.50 | | | 4.50 | | | 4.50 | | | 4.50 | | | 4.50 | |
Medical trend rate | — |
| — |
| — |
| — |
| — |
| — |
| 8.80 |
| 7.20 |
| 5.70 |
| |
Medical trend rate1 | | Medical trend rate1 | — | | | — | | | — | | | — | | | — | | | — | | | N/A | | | 7.60 | | | 6.80 | |
Benefit Cost Assumptions | | | | | | Benefit Cost Assumptions | | | | | | | | | | | | | | | | | | | | | | | | | | |
Discount rate | 4.65 | % | 4.25 | % | 5.10 | % | 4.65 | % | 4.25 | % | 5.10 | % | 4.65 | % | 4.25 | % | 5.10 | % | Discount rate | 4.40 | | | 4.40 | | | 4.50 | | | 4.40 | | | 4.40 | | | 4.50 | | | 4.40 | | | 4.40 | | | 4.50 | |
Return on plan assets | 7.75 |
| 7.75 |
| 7.75 |
| — |
| — |
| — |
| 6.75 |
| 7.00 |
| 7.00 |
| Return on plan assets | 7.50 | | | 7.50 | | | 7.45 | | | — | | | — | | | — | | | 7.00 | | | 7.00 | | | 6.75 | |
Rate of compensation increase | 4.50 |
| 4.50 |
| 4.50 |
| 4.50 |
| 4.50 |
| 4.50 |
| 4.50 |
| 4.50 |
| 4.50 |
| Rate of compensation increase | 4.50 | | | 4.50 | | | 4.50 | | | 4.50 | | | 4.50 | | | 4.50 | | | 4.50 | | | 4.50 | | | 4.50 | |
Medical trend rate | — |
| — |
| — |
| — |
| — |
| — |
| 5.30 |
| 7.20 |
| 6.70 |
| |
Medical trend rate1 | | Medical trend rate1 | — | | | — | | | — | | | — | | | — | | | — | | | N/A | | | 7.60 | | | 9.50 | |
________________________
The assumed1.As of December 31,2019, PSE terminated the previous group retiree medical plan and created an HRA. As a result, medical inflation rate used to determineis no longer applicable in accounting for the related benefit obligations is 8.80% in 2017 grading down to 4.30% in 2018. A 1.0% change in the assumed medical inflation rate would have the following effects:obligation.
|
| | | | | | | | | | | | |
| 2016 | 2015 |
(Dollars in Thousands) | 1% Increase | 1% Decrease | 1% Increase | 1% Decrease |
Effect on post-retirement benefit obligation | $ | 38 |
| $ | (35 | ) | $ | 52 |
| $ | (42 | ) |
Effect on service and interest cost components | 2 |
| (2 | ) | 2 |
| (2 | ) |
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, and 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 during the next five years and the aggregate total to be paid for the five years thereafter are as follows:
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
(Dollars in Thousands) | 2020 | | 2021 | | 2022 | | 2023 | | 2024 | | 2025-2029 |
Qualified Pension total benefits | $ | 45,000 | | | $ | 45,200 | | | $ | 46,200 | | | $ | 47,900 | | | $ | 48,800 | | | $ | 253,400 | |
SERP Pension total benefits | 22,604 | | | 1,940 | | | 5,792 | | | 3,663 | | | 6,290 | | | 21,283 | |
Other Benefits total with Medicare Part D subsidy | 843 | | | 826 | | | 972 | | | 937 | | | 901 | | | 4,053 | |
Other Benefits total without Medicare Part D subsidy | 1,055 | | | 1,007 | | | 972 | | | 937 | | | 901 | | | 4,053 | |
|
| | | | | | | | | | | | | | | | | | |
(Dollars in Thousands) | 2017 |
| 2018 |
| 2019 |
| 2020 |
| 2021 |
| 2022-2026 |
|
Qualified Pension total benefits | $ | 41,400 |
| $ | 42,500 |
| $ | 43,600 |
| $ | 44,600 |
| $ | 45,200 |
| $ | 240,800 |
|
SERP Pension total benefits | 1,911 |
| 5,278 |
| 5,666 |
| 4,454 |
| 1,724 |
| 34,043 |
|
Other Benefits total with Medicare Part D subsidy | 928 |
| 893 |
| 863 |
| 829 |
| 787 |
| 3,873 |
|
Other Benefits total without Medicare Part D subsidy | 1,256 |
| 1,239 |
| 1,216 |
| 1,191 |
| 1,158 |
| 5,294 |
|
Plan Assets
Plan contributions and the actuarial present value of accumulated plan benefits are prepared based on certain assumptions pertaining to interest rates, inflation rates and employee demographics, all of which are subject to change. Due to uncertainties inherent in the estimations and assumptions process, changes in these estimates and assumptions in the near term may be material to the financial statements.
The Company has a Retirement Plan Committee that establishes investment policies, objectives and strategies designed to balance expected return with a prudent level of risk. All changes to the investment policies are reviewed and approved by the Retirement Plan Committee prior to being implemented.
The Retirement Plan Committee invests trust assets with investment managers who have historically achieved above-median long-term investment performance within the risk and asset allocation limits that have been established. Interim evaluations are routinely performed with the assistance of an outside investment consultant.
To obtain the desired return needed to fund the pension benefit plans, the Retirement Plan Committee has established investment allocation percentages by asset classes as follows:
| | | | | | | | | | | | | | | | | |
| Allocation | | | | |
Asset Class | Minimum | | Target | | Maximum |
Domestic large cap equity | 25 | % | | 31 | % | | 40 | % |
Domestic small cap equity | — | | | 9 | | | 15 | |
Non-U.S. equity | 10 | | | 25 | | | 30 | |
Fixed income | 15 | | | 25 | | | 30 | |
Real estate | — | | | — | | | 10 | |
Absolute return | 5 | | | 10 | | | 15 | |
Cash | — | | | — | | | 5 | |
Plan Fair Value Measurements
ASC 715, “Compensation – Retirement Benefits” (ASC 715) directs companies to provide additional disclosures about plan assets of a defined benefit pension or other postretirement plan. The objectives of the disclosures are to disclose the following: (i) how investment allocation decisions are made, including the factors that are pertinent to an understanding of investment policies and strategies; (ii) major categories of plan assets; (iii) inputs and valuation techniques used to measure the fair value of plan assets; (iv) effect of fair value measurements using significant unobservable inputs (Level 3) on changes in plan assets for the period; and (v) 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, 20162019, and 2015:2018:
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Recurring Fair Value Measures | | | | | | Recurring Fair Value Measures | | | | |
| December 31, 2019 | | | | | | December 31, 2018 | | | | |
(Dollars in Thousands) | Level 1 | | Level 2 | | Total | | Level 1 | | Level 2 | | Total |
Assets: | | | | | | | | | | | |
Mutual Funds | $ | 91,658 | | | $ | — | | | $ | 91,658 | | | $ | 103,661 | | | $ | — | | | $ | 103,661 | |
Common Stock | 224,146 | | | — | | | 224,146 | | | 177,949 | | | — | | | 177,949 | |
Government Securities | 34,916 | | | — | | | 34,916 | | | — | | | — | | | — | |
Corporate Bonds | — | | | — | | | — | | | — | | | — | | | — | |
Cash and cash equivalents | — | | | 150 | | | 150 | | | — | | | 702 | | | 702 | |
Subtotal | $ | 350,720 | | | $ | 150 | | | $ | 350,870 | | | $ | 281,610 | | | $ | 702 | | | $ | 282,312 | |
Investments measured at NAV1 | | | | | | | 401,668 | | | | | | | | | 356,586 | |
Net (payable) receivable | | | | | | | 505 | | | | | | | | | 1,345 | |
Total assets | | | | | | | $ | 753,043 | | | | | | | | | $ | 640,243 | |
|
| | | | | | | | | | | | | | | | | | |
| Recurring Fair Value Measures | Recurring Fair Value Measures |
| As of December 31, 2016 | As of December 31, 2015 |
(Dollars in Thousands) | Level 1 |
| Level 2 | Total | Level 1 | Level 2 | Total |
Assets: | | | | | | |
Mutual Funds | $ | 181,212 |
| $ | — |
| $ | 181,212 |
| $ | 169,165 |
| $ | — |
| $ | 169,165 |
|
Common Stock | 154,255 |
| — |
| $ | 154,255 |
| 146,321 |
| — |
| $ | 146,321 |
|
Government Securities | 18,754 |
| 16,197 |
| $ | 34,951 |
| 8,835 |
| 14,268 |
| $ | 23,103 |
|
Corporate Bonds | — |
| 38,543 |
| $ | 38,543 |
| — |
| 44,157 |
| $ | 44,157 |
|
Subtotal | 354,221 |
| 54,740 |
| 408,961 |
| 324,321 |
| 58,425 |
| 382,746 |
|
Investments measured at NAV1 | * | * | 222,819 |
| * | * | 223,663 |
|
Net (payable) receivable | * | * | (9,894 | ) | * | * | (7,544 | ) |
Total assets | * | * | $ | 621,886 |
| * | * | $ | 598,865 |
|
_______________________________________
| |
11.In accordance with ASU 2015-07, "Fair Value Measurement (Topic 820): Disclosures for Investments in Certain Entities that Calculate Net Asset Value per Share (or Its Equivalent)", certain investments that are measured at NAV per share (or its equivalent) are not classified in the fair value hierarchy. The fair value amounts presented in this table are intended to permit reconciliation of the fair value hierarchy to the line items presented in the statement of net assets available for benefits. Investments measured at NAV primarily consist of common/collective trust funds and two partnerships held as of December 31, 2019, and 2018. | In accordance with ASU 2015-07, "Fair Value Measurement (Topic 820): Disclosures for Investments in Certain Entities that Calculate Net Asset Value per Share (or Its Equivalent)", certain investments that were measured at NAV per share (or its equivalent) have not been classified in the fair value hierarchy. The fair value amounts presented in this table are intended to permit reconciliation of the fair value hierarchy to the line items presented in the statement of net assets available for benefits. Investments measured at NAV consist of common/collective trust funds and two partnerships held as of December 31, 2016. |
Mesirow Institutional Multi-Strategy Fund Partnership, L.P. utilizes a combination of long and short strategies through investments in investment funds. The major strategy allocations of the investment funds include (1) Investments in debt obligations of public and private entities; typically, in financial duress, and (2) Investments in equity positions on a global basis utilizing fundamental analysis.
Grosvenor Institutional Partners Fund, L.P invests substantially all of the fund assets available in the Grosvenor Master Fund, a Cayman Islands exempted company which is sponsored, managed and has the same investment objective as the Partnership fund. In addition to the Master Fund, investments are made primarily in offshore investment funds, investment partnerships, and pooled investment vehicles; collectively referred to as Portfolio Funds, which generally implement "nontraditional" or "alternative" investment strategies.
The following table sets forth by level, within the fair value hierarchy, the Other Benefits plan assets which consist of insurance benefits for retired employees, at fair value:
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Recurring Fair Value Measures | | | | | | Recurring Fair Value Measures | | | | |
| December 31, 2019 | | | | | | December 31, 2018 | | | | |
(Dollars in Thousands) | Level 1 | | Level 2 | | Total | | Level 1 | | Level 2 | | Total |
Assets: | | | | | | | | | | | |
Mutual fund1 | $ | 6,201 | | | $ | — | | | $ | 6,201 | | | $ | 5,910 | | | $ | — | | | $ | 5,910 | |
Investments measured at NAV2 | | | | | | | 88 | | | | | | | | | 50 | |
Total assets | | | | | | | $ | 6,289 | | | | | | | | | $ | 5,960 | |
________________
1.This is a publicly traded balanced mutual fund. The fund seeks regular income, conservation of principal, and an opportunity for long-term growth of principal and income. The fair value is determined by taking the number of shares owned by the plan, and multiplying by the market price as of December 31, 2019, and 2018.
2.In accordance with ASU 2015-07, "Fair Value Measurement (Topic 820): Disclosures for Investments in Certain Entities that Calculate Net Asset Value per Share (or Its Equivalent)", certain investments are measured at NAV per share (or its equivalent) are not classified in the fair value hierarchy. The fair value amounts presented in this table are intended to permit reconciliation of the fair value hierarchy to the line items presented in the statement of net assets available for benefits. Investments measured at NAV consist of a common/collective trust fund as of December 31, 2019, and 2018.
|
| | | | | | | | | | | | | | | | | | |
| Recurring Fair Value Measures | Recurring Fair Value Measures |
| As of December 31, 2016 | As of December 31, 2015 |
(Dollars in Thousands) | Level 1 | Level 2 | Total | Level 1 | Level 2 | Total |
Assets: | | | | | | |
Mutual fund1 | $ | 7,182 |
| $ | — |
| $ | 7,182 |
| $ | 7,135 |
| $ | — |
| $ | 7,135 |
|
Cash equivalents2 | — |
| 80 |
| 80 |
| — |
| 68 |
| 68 |
|
Total assets | $ | 7,182 |
| $ | 80 |
| $ | 7,262 |
| $ | 7,135 |
| $ | 68 |
| $ | 7,203 |
|
_______________
| |
1
| This is a publicly traded balanced mutual fund. The fund seeks regular income, conservation of principal, and an opportunity for long-term growth of principal and income. The fair value is determined by taking the number of shares owned by the plan, and multiplying by the market price as of December 31, 2016. |
| |
2
| The investment consists of a money market fund (at level 1) and a collective trust fund (at level 2). The money market fund is valued at the net asset value per share of $1.00 per unit as of December 31, 2016. The collective trust 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)(14) Income Taxes
The details of income tax (benefit) expense are as follows:
| | Puget Energy | Year Ended December 31, | Puget Energy | Year Ended December 31, | |
(Dollars in Thousands) | 2016 | 2015 | 2014 |
| (Dollars in Thousands) | 2019 | | 2018 | | 2017 |
Charged to operating expenses: | | | Charged to operating expenses: | | | | | |
Current: | | Current: | | | | | |
Federal | $ | — |
| $ | — |
| $ | — |
| Federal | $ | 9,424 | | | $ | 10,382 | | | $ | 1,127 | |
State | 20 |
| — |
| — |
| State | 164 | | | 263 | | | 17 | |
Deferred: | |
| |
| | Deferred: | | | | | | | | |
Federal | 140,315 |
| 91,968 |
| 57,152 |
| Federal | 7,357 | | | 19,451 | | | 254,420 | |
State | (131 | ) | (192 | ) | (167 | ) | State | 128 | | | (4) | | | (421) | |
Total income tax expense | $ | 140,204 |
| $ | 91,776 |
| $ | 56,985 |
| Total income tax expense | $ | 17,073 | | | $ | 30,092 | | | $ | 255,143 | |
| | Puget Sound Energy | Year Ended December 31, | Puget Sound Energy | Year Ended December 31, | |
(Dollars in Thousands) | 2016 | 2015 | 2014 | (Dollars in Thousands) | 2019 | | 2018 | | 2017 |
Charged to operating expenses: | | Charged to operating expenses: | | | | | |
Current: | | Current: | | | | | |
Federal | $ | — |
| $ | — |
| $ | — |
| Federal | $ | 18,093 | | | $ | 19,283 | | | $ | 1,127 | |
State | 20 |
| — |
| — |
| State | 570 | | | 438 | | | 17 | |
Deferred: | |
| |
| |
| Deferred: | | | | | | | | |
Federal | 175,327 |
| 125,900 |
| 89,342 |
| Federal | 20,485 | | | 30,979 | | | 210,842 | |
State | — |
| — |
| — |
| State | — | | | — | | | — | |
Total income tax expense | $ | 175,347 |
| $ | 125,900 |
| $ | 89,342 |
| Total income tax expense | $ | 39,148 | | | $ | 50,700 | | | $ | 211,986 | |
The following reconciliation compares pre-tax book income at the federal statutory rate of 21.0% in 2019 and 2018 and 35.0% in 2017 to the actual income tax expense in the Statements of Income:
| | | | | | | | | | | | | | | | | |
Puget Energy | Year Ended December 31, | | | | |
(Dollars in Thousands) | 2019 | | 2018 | | 2017 |
Income taxes at the statutory rate | $ | 47,834 | | | $ | 55,800 | | | $ | 148,847 | |
Increase (decrease): | | | | | | | | |
Utility plant differences1 | $ | (23,025) | | | $ | (25,871) | | | $ | — | |
AFUDC, net | (4,462) | | | (4,173) | | | (4,506) | |
Executive compensation | 2,596 | | | 4,439 | | | — | |
Treasury grant amortization | (7,870) | | | (4,861) | | | (9,537) | |
Tax reform | — | | | — | | | 117,185 | |
Other–net | 2,000 | | | 4,758 | | | 3,154 | |
Total income tax expense | $ | 17,073 | | | $ | 30,092 | | | $ | 255,143 | |
Effective tax rate | 7.5 | % | | 11.3 | % | | 60.0 | % |
|
| | | |
Puget Energy | Year Ended December 31, |
(Dollars in Thousands) | 2016 | 2015 | 2014 |
Income taxes at the statutory rate | $158,586 | $116,534 | $80,087 |
Increase (decrease): | | | |
Production tax credit1 | (12,925) | (19,470) | (23,073) |
Utility plant differences | 3,966 | 5,671 | 7,090 |
Treasury grant amortization | (9,788) | (8,807) | (8,808) |
Other - net | 365 | (2,152) | 1,689 |
Total income tax expense | $140,204 | $91,776 | $56,985 |
Effective tax rate | 30.9% | 27.6% | 24.9% |
| | Puget Sound Energy | Year Ended December 31, | Puget Sound Energy | Year Ended December 31, | |
(Dollars in Thousands) | 2016 | 2015 | 2014 | (Dollars in Thousands) | 2019 | | 2018 | | 2017 |
Income taxes at the statutory rate | $194,572 | $150,531 | $114,084 | Income taxes at the statutory rate | $ | 69,735 | | | $ | 77,251 | | | $ | 185,430 | |
Increase (decrease): | | Increase (decrease): | | | | | | | | |
Production tax credit1 | (12,925) | (19,470) | (23,073) | |
Utility plant differences | 3,966 | 5,671 | 7,090 | |
Utility plant differences1 | | Utility plant differences1 | $ | (23,025) | | | $ | (25,871) | | | $ | — | |
AFUDC, net | | AFUDC, net | (4,462) | | | (4,173) | | | (4,506) | |
Executive Compensation | | Executive Compensation | 2,596 | | | 4,439 | | | — | |
Treasury grant amortization | (9,788) | (8,807) | (8,808) | Treasury grant amortization | (7,870) | | | (4,861) | | | (9,537) | |
Other - net | (478) | (2,025) | 49 | |
Tax reform | | Tax reform | — | | | — | | | 36,328 | |
Other–net | | Other–net | 2,174 | | | 3,915 | | | 4,271 | |
Total income tax expense | $175,347 | $125,900 | $89,342 | Total income tax expense | $ | 39,148 | | | $ | 50,700 | | | $ | 211,986 | |
Effective tax rate | 31.5% | 29.3% | 27.4% | Effective tax rate | 11.8 | % | | 13.8 | % | | 40.0 | % |
_______________
| |
1
| PSE's Wild Horse wind plant and Hopkins Ridge wind plant earned their last PTCs in December 2016 and 2015, respectively. No further PTCs are expected. |
1.Utility plant differences include the reversal of excess deferred taxes using the average rate assumption method in the amount of $27.6 million and $29.8 million in 2019, and 2018, respectively.
The Company’s net deferred tax liability at December 31, 20162019, and 20152018, is composed of amounts related to the following types of temporary differences:
| | | | | | | | | | | |
Puget Energy | At December 31, | | |
(Dollars in Thousands) | 2019 | | 2018 |
Utility plant and equipment | $ | 1,943,730 | | | $ | 1,998,721 | |
Other deferred tax liabilities | 133,440 | | | 113,051 | |
Subtotal deferred tax liabilities | 2,077,170 | | | 2,111,772 | |
Net operating loss carryforward | (238,869) | | | (224,885) | |
Net regulatory liability for income taxes | (946,179) | | | (975,974) | |
Production tax credit carryforward | (67,402) | | | (121,616) | |
Subtotal deferred tax assets | (1,252,450) | | | (1,322,475) | |
Total net deferred tax liabilities | $ | 824,720 | | | $ | 789,297 | |
|
| | | | | | |
Puget Energy | At December 31, |
(Dollars in Thousands) | 2016 |
| 2015 |
|
Utility plant and equipment | $ | 1,880,782 |
| $ | 1,788,078 |
|
Regulatory asset for income taxes | 72,038 |
| 73,231 |
|
Fair value of debt instruments | 67,444 |
| 70,260 |
|
Pensions and other compensation | 77,230 |
| 77,230 |
|
Other, net deferred tax liabilities | 119,050 |
| 84,397 |
|
Subtotal deferred tax liabilities | 2,216,544 |
| 2,093,196 |
|
Net operating loss carryforward | (352,827 | ) | (384,338 | ) |
Production tax credit carryforward | (190,999 | ) | (178,075 | ) |
Regulatory liability on production tax credit | (101,787 | ) | (94,828 | ) |
Subtotal deferred tax assets | (645,613 | ) | (657,241 | ) |
Total net deferred tax liabilities | $ | 1,570,931 |
| $ | 1,435,955 |
|
| | | | | | | | | | | |
Puget Sound Energy | At December 31, | | |
(Dollars in Thousands) | 2019 | | 2018 |
Utility plant and equipment | $ | 1,943,730 | | | $ | 1,998,721 | |
Other, net deferred tax liabilities | 47,774 | | | 25,880 | |
Subtotal deferred tax liabilities | 1,991,504 | | | 2,024,601 | |
Net regulatory liability for income taxes | (946,936) | | | (976,582) | |
Production tax credit carryforward | (67,405) | | | (121,616) | |
Subtotal deferred tax assets | (1,014,341) | | | (1,098,198) | |
Total net deferred tax liabilities | $ | 977,163 | | | $ | 926,403 | |
|
| | | | | | |
Puget Sound Energy | At December 31, |
(Dollars in Thousands) | 2016 |
| 2015 |
|
Utility plant and equipment | $ | 1,880,782 |
| $ | 1,788,078 |
|
Regulatory asset for income taxes | 71,517 |
| 72,694 |
|
Other, net deferred tax liabilities | 113,938 |
| 80,351 |
|
Subtotal deferred tax liabilities | 2,066,237 |
| 1,941,123 |
|
Net operating loss carryforward | (41,061 | ) | (111,604 | ) |
Production tax credit carryforward | (190,999 | ) | (178,075 | ) |
Regulatory liability on production tax credit | (101,787 | ) | (94,828 | ) |
Subtotal deferred tax assets | (333,847 | ) | (384,507 | ) |
Total net deferred tax liabilities | $ | 1,732,390 |
| $ | 1,556,616 |
|
In November 2015, the FASB issued ASU 2015-17, "Income Taxes (Topic 740): Balance Sheet Classification of Deferred Taxes". ASU 2015-17 requires reporting entities to classify deferred tax liabilities and assets as noncurrent in a classified balance sheet instead of separating such deferred taxes into current and noncurrent amounts.
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’sPSE’s PTC carryforwards expire from 20272033 through 2036. The Company’sPuget Energy’s net operating loss carryforwards expire from 20292027 through 2036.2037. Net operating losses generated in 2018 and thereafter have no expiration date. No valuation allowance has been provided for PTC or net operating loss carryforwards.
Federal Income Tax Law Changes
On December 22, 2017, President Trump signed into law legislation referred to as the TCJA. Substantially all of the provisions of the TCJA are effective for taxable years beginning after December 31, 2017. The TCJA includes significant changes to the Internal Revenue Code of 1986 (as amended, the Code), including amendments which significantly change the taxation of business entities and includes specific provisions related to regulated public utilities including PSE. The most significant change that impacts the Company included in the TCJA is the reduction in the corporate federal income tax rate from 35.0% to 21.0% and the limitation of deductibility of executive compensation. The specific provisions related to regulated public utilities in the TCJA generally allow for the continued deductibility of interest expense, the elimination of full expensing for tax purposes of certain property acquired after December 31, 2017, and continues normalization requirements for accelerated depreciation benefits.
Under GAAP, specifically ASC Topic 740, Income Taxes, the tax effects of changes in tax laws must be recognized in the period in which the law is enacted and deferred tax assets and liabilities are to be re-measured at the enacted tax rate expected to apply when temporary differences are to be realized or settled. For ratemaking purposes,PSE, the change in deferred taxes are not provided for certain temporary differences. PSE has establishedis recorded as either an offset to a regulatory asset or liability and is subject to approval by the Washington Commission. For Puget Energy, the change in deferred taxes is recorded as an adjustment to Puget Energy’s income tax expense, which decreased Puget Energy’s net income.
Upon enactment of the TCJA, the Company re-measured its deferred tax assets and liabilities based upon the TCJA’s 21.0% percent corporate federal income tax rate. The corporate tax rate change for PSE is captured in the deferred tax balance with an offset to the regulatory liability for deferred income taxes. The balance of the regulatory deferred tax account at the beginning of 2017, before tax reform, was a $71.5 million asset. As a result of tax reform, the balance was a liability of $1,012.3 million. Since PSE is in a net regulatory liability position with respect to these income tax matters, PSE netted the regulatory asset for deferred income taxes against the regulatory liability for deferred income taxes. Under the normalization requirements continued by the TCJA, $919.8 million of the net regulatory liability related to certain accelerated tax depreciation benefits is to be reversed over the remaining lives of the related assets using ARAM. The remainder of the net regulatory liability of $91.9 million is available for PSE and the Washington Commission regulatory process to determine how the amounts will be refunded to customers. PSE requested to delay the impact of tax reform in an accounting petition which was filed with the Washington Commission on December 29, 2017. For further details regarding PSE's ERF and Accounting Petition, see Note 4, "Regulation and Rates" to the consolidated financial statements included in Item 8 of this report. In 2019 and 2018, the Company reversed excess deferred taxes for plant-related items using ARAM in the amount of $27.6 million and $29.8 million, respectively.
The impact of the TCJA to income tax expense as of December 31, 2017, was $36.3 million of which $3.0 million relates to deferred tax balances that are not subject to regulatory treatment. In addition, $33.3 million relates to the revaluation of the deferred tax for regulatory liability on PTC balances. The regulatory liability owed to customers for PTCs, which previously reduced revenue upon generation of the PTCs, was also revalued at the new rate of 21.0%. The change in the liability owed to customers for PTCs increased revenue by $51.2 million, which increased tax expense by $17.9 million, to reverse the initial deferral. The changes in the deferred tax and the liability owed to customers for PTCs had no impact on net income. Incrementally, Puget Energy increased its tax expense by $80.9 million primarily due to the revaluation of Puget Energy's net deferred tax asset on its net operating loss carryforward.
The staff of the US Securities and Exchange Commission (SEC) has recognized the complexity of reflecting the impacts of the TCJA and on December 22, 2017, issued guidance in Staff Accounting Bulletin 118 (SAB 118). The guidance clarifies accounting for income taxes recoverable through future rates relatedunder ASC 740 if information is not yet available or complete and provides for up to those temporary differencesa one year period in which to complete the required analysis and accounting (the measurement period). The Company completed the required analysis and accounting for which no deferred taxes have been provided, based on priorthe effects of the TCJA's enactment and expected future ratemaking treatment.did not identify any additional adjustments required.
Unrecognized Tax Benefits
The Company accounts for uncertain tax positionpositions 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, 20162019, and 2015,2018, the Company had no material unrecognized tax benefits. As a result, no interest or penalties were accrued for unrecognized tax benefits during the year.
The Company has open tax years from 20132016 through 2016.2019. The Company classifies interest as interest expense and penalties as other expense in the financial statements.
(14)(15) Litigation
From time to time, the Company is involved in litigation or legislative rulemaking proceedings relating to its operations in the normal course of business. The following is a description of pending proceedings that are material to PSE’s operations:
Colstrip
PSE has a 50% ownership interest in Colstrip Units 1 and 2 and a 25% interest in each of Colstrip Units 3 and 4. OnIn March 6, 2013,
the Sierra Club and the Montana Environmental Information Center filed a Clean Air Act citizen suit against all Colstrip owners in the U.S. District Court, District of Montana. Based on a second amended complaint filed in August 2014, plaintiffs' lawsuit alleged violations of permitting requirements under the New Source Review/Prevention of Significant Deterioration program of the Clean Air Act arising from projects (plaintiffs initially claimed seventy-three projects, but this was reduced to two projects before trial in May 2016) undertaken at Colstrip during the time period from 2001 to 2012. OnIn July 12, 2016, PSE reached a settlement with the Sierra Club to dismiss all of the Clean Air Act allegations against the Colstrip Generating Station, which was approved by the court onin September 6, 2016. As part of the settlement that was signed by all Colstrip owners, Colstrip 1 and 2 owners, PSE agreed, along withand Talen Energy (the owner of the other 50% interest in Colstrip Units 1 and 2)Corporation (Talen), agreed to retire the two2 oldest units (Units 1 and 2) at Colstrip in eastern Montana by no later than July 1, 2022. PSE expects that the Washington Commission will allow full recovery inDepreciation rates of the net book value (NBV) at retirement and related decommissioning costs consistent with prior precedents. As a result, PSE reclassified $176.8 million from a plant asset to a regulatory asset, which represents the expected NBV at retirement of Colstrip Units 1 and 2, based on the
expected shutdown date of July 1, 2022. Colstrip Units 3 and 4, which are newer and more efficient, are not affected by the settlement, and allegationswere updated in the lawsuit against Colstrip Units 3 and 4 were dismissed as part of the settlement. While PSE has estimated the asset retirement obligationGRC effective December 19, 2017, where PSE's depreciation increased for Colstrip Units 1 and 2 to recover plant costs to the expected shutdown date. Additionally, PSE has accelerated the depreciation of Colstrip Units 3 and 4, per the terms of the GRC settlement, to December 31, 2027. The GRC also repurposed PTCs and hydro-related treasury grants to recover unrecovered plant costs and to fund and recover decommissioning and remediation costs for Colstrip Units 1 through 4.
Consistent with a June 2019 announcement, Talen permanently shut down Units 1 and 2 at the end of the year due to operational losses associated with the Units. Colstrip Units 1 and 2 were retired effective December 31, 2019. The Washington Clean Energy Transition Act requires the Washington Commission to provide recovery of the investment, decommissioning, and remediation costs associated with the facilities that are not recovered through the repurposed PTC's and hydro-related treasury grants. The full scope of decommissioning activities and costs are unknown and willmay vary from the estimates that are available at this time.
Greenwood
On March 9, 2016, a natural gas explosion occurredDecember 10, 2019, PSE announced its intention to sell its interest in the Greenwood neighborhood of Seattle, WA, damaging multiple structures. The Washington Commission Staff completedColstrip Unit 4 to NorthWestern Energy for $1. Under this agreement, PSE would retain its investigationobligation to fund 25% of the incidentenvironmental remediation and filed a complaint September 20, 2016, seeking from PSE $3.2 million in fines. As a result,decommissioning costs associated with Unit 4 during PSE's operation. The agreement is subject to approval by the Washington Commission will initiateand the Montana Public Service Commission. Additionally, PSE has agreed to enter into a hearing before makingpower purchase agreement with NorthWestern Energy for 90 MW through 2025 to facilitate the transition, and sell a final determination. Asportion of its dedicated Colstrip transmission system, conditioned upon regulatory approval. PSE expects external parties to intervene on the contingent purchase agreement for Colstrip Unit 4. For accounting purposes, management has evaluated the applicable held for sale criteria as of December 31, 2016,2019, and determined that these criteria were not met. As such, Unit 4 is classified as Electric Utility Plant on the balance sheet, see Note 6, "Utility Plant," to the consolidated financial statements included in Item 8 of this report.
Regional Haze Rule
In January 2017, the EPA published revisions to the Regional Haze Rule. Among other things, these revisions delayed new Regional Haze review from 2018 to 2021, however the end date will remain 2028. In January 2018, the EPA announced that it was reconsidering certain aspects of these revisions and PSE has accrued $3.2 millionis unable to predict the outcome. Challenges to the 2017 Regional Haze Revision Rule are pending in abeyance in the U.S. Court of Appeals for the fine.D.C. Circuit, pending resolution of the EPA’s reconsideration of the rule.
Clean Air Act 111(d)/EPA Affordable clean Energy Rule
In June 2014, the EPA issued a proposed Clean Power Plan (CPP) rule under Section 111(d) of the Clean Air Act designed to regulate GHG emissions from existing power plants. The proposed rule includes state-specific goals and guidelines for states to develop plans for meeting these goals. The EPA published a final rule in October 2015. In March 2017, then EPA Administrator, Scott Pruitt, signed a notice of withdrawal of the proposed CPP federal plan and model trading rules and, in October 2017, the EPA proposed to repeal the CPP rule.
In August 2018, the EPA proposed the Affordable Clean Energy (ACE) rule, pursuant to Section 111(d) of the Clean Air Act.. The ACE rule was finalized in June 2019, and establishes emission guidelines for states to develop plans to address greenhouse gas emissions from existing coal-fired plants. Compliance plans under ACE are due July 2020, and compliance generally required by July 2024. PSE is evaluating the final ACE rule to determine its impact on operations pending the outcome of the proposed Colstrip Unit 4 sale to NorthWestern Energy.
Washington Clean Air Rule
PSE, along with otherThe CAR was adopted in September 2016, in Washington State and attempts to reduce greenhouse gas emissions from “covered entities” located within Washington State. Included under the new rule are large manufacturers, petroleum producers and natural gas utilities, jointly filedincluding PSE. The CAR sets a lawsuit in federal courtcap on emissions associated with covered entities, which decreases over time approximately 5.0% every three years. Entities must reduce their carbon emissions, or purchase emission reduction units (ERUs), as defined under the rule, from others.
In September 27, 2016, (United States District Court Eastern District of Washington) and Washington State court (Thurston County Superior Court) on September 30, 2016 challenging Washington Department of Ecology’s Clean Air Rule. Other parties in the suit includePSE, along with Avista Corporation, Cascade Natural Gas Corp.Corporation and NorthwestNW Natural, Gas. Thefiled a lawsuit contends that this Rule will have the unintended consequence of increasing carbon emissions while penalizing customers for using natural gas.
Other Proceedings
The Company is also involved in litigation relating to claims arising out of its operations in the normal courseU.S. District Court for the Eastern District of business.Washington challenging the CAR. In September 2016, the four companies filed a similar challenge to the CAR in Thurston County Superior Court. In March 2018, the Thurston County Superior Court invalidated the CAR. The CompanyDepartment of Ecology appealed the Superior Court decision in May 2018. As a result of the appeal, direct review to the Washington State Supreme Court was granted and oral argument was held on March 16, 2019. In January 2020, the Washington Supreme Court affirmed that CAR is not valid for “indirect emitters” meaning it does not apply to the sale of natural gas for use by customers. The court ruled, however, that the rule can be severed and is valid for direct emitters including electric utilities with permitted air emission sources, but remanded the case back to the Thurston County to determine which parts of the rule survive. Meanwhile, the federal court litigation has recorded reservesbeen held in abeyance pending resolution of $0.7 million and $0.3 million relating to these claims as of December 31, 2016 and 2015, respectively.the state case.
(15)(16) Commitments and Contingencies
For the year ended December 31, 2016,2019, approximately 13.7%10.2% of the Company’s energy output was obtained at an average cost of approximately $0.023$0.033 per Kilowatt Hour (kWh) through long-term contracts with three3 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 share of power 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 levelthrough 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 31:31, :
| | | | | | | | | | | | | | | | | |
(Dollars in Thousands) | 2019 | | 2018 | | 2017 |
PUD contract costs | $ | 87,135 | | | $ | 80,165 | | | $ | 73,827 | |
|
| | | | | | | | | |
(Dollars in Thousands) | 2016 |
| 2015 |
| 2014 |
|
PUD contract costs | $ | 77,667 |
| $ | 72,833 |
| $ | 69,661 |
|
As of December 31, 2016,2019, the Company purchased portions of the power output of the PUDs' projects as set forth in the following table: | | | | Company's Current Share of | | | Company's Current Share of | |
(Dollars in Thousands) | Contract Expiration | Percent of Output | Megawatt Capacity |
| Estimated 2017 Costs | 2017 Debt Service Costs | Interest included in 2017 Debt Service Costs | Debt Outstanding | (Dollars in Thousands) | Contract Expiration | | Percent of Output | | Megawatt Capacity | | Estimated 2020 Costs | | 2020 Debt Service Costs | | Interest included in 2020 Debt Service Costs | | Debt Outstanding |
Chelan County PUD: | | | | Chelan County PUD: | | | | | | | | | | | | | |
Rock Island Project | 2031 | 25.0 | % | 156 |
| $ | 28,886 |
| $ | 10,430 |
| $ | 5,638 |
| $ | 88,518 |
| Rock Island Project | 2031 | | 25.0 | % | | 156 | | $ | 34,180 | | | $ | 11,499 | | | $ | 5,681 | | | $ | 96,956 | |
Rocky Reach Project | 2031 | 25.0 |
| 325 |
| 28,376 |
| 7,574 |
| 2,854 |
| 44,305 |
| Rocky Reach Project | 2031 | | 25.0 | | | 325 | | 31,190 | | | 4,940 | | | 2,129 | | | 33,317 | |
Douglas County PUD: | | | |
| | Douglas County PUD: | | | | | | | | | | | | | | | | | | |
Wells Project | 2018 | 29.9 |
| 251 |
| 16,547 |
| 8,004 |
| 2,153 |
| 54,847 |
| |
Wells Project1 | | Wells Project1 | 2028 | | 27.1 | | | 228 | | 43,004 | | | — | | | — | | | — | |
Grant County PUD: | | | |
| | Grant County PUD: | | | | | | | | | | | | | | | | | | |
Priest Rapids Development | 2052 | 0.6 |
| 8 |
| 2,809 |
| 1,670 |
| 1,670 |
| 18,579 |
| Priest Rapids Development | 2052 | | 0.6 | | | 6 | | 1,831 | | | 1,085 | | | 586 | | | 12,793 | |
Wanapum Development | 2052 | 0.6 |
| 9 |
| 2,809 |
| 1,670 |
| 1,670 |
| 18,579 |
| Wanapum Development | 2052 | | 0.6 | | | 7 | | 1,831 | | | 1,085 | | | 586 | | | 12,793 | |
Total | | | 749 |
| $ | 79,427 |
| $ | 29,348 |
| $ | 13,985 |
| $ | 224,828 |
| Total | | | | | 722 | | $ | 112,036 | | | $ | 18,609 | | | $ | 8,982 | | | $ | 155,859 | |
_______________
1.In March 2017, PSE entered a new PPA with Douglas County PUD for Wells Project output that begins upon expiration of the existing contract on August 31, 2018, and continues through September 30, 2028.
The following table summarizes the Company’s estimated payment obligations for power purchases from the Columbia River projects, electric portfolio contracts with other utilities and contracts with non-utilities.electric wholesale market transactions. These contracts have varying terms and may include escalation and termination provisions.
| | (Dollars in Thousands) | 2017 |
| 2018 |
| 2019 |
| 2020 |
| 2021 |
| Thereafter |
| Total |
| (Dollars in Thousands) | 2020 | | 2021 | | 2022 | | 2023 | | 2024 | | Thereafter | | Total |
Columbia River projects | $ | 73,733 |
| $ | 69,527 |
| $ | 58,921 |
| $ | 59,172 |
| $ | 56,396 |
| $ | 597,468 |
| $ | 915,217 |
| Columbia River projects | $ | 121,680 | | | $ | 111,125 | | | $ | 103,879 | | | $ | 103,377 | | | $ | 102,976 | | | $ | 609,912 | | | $ | 1,152,949 | |
Other utilities | 10,499 |
| 1,257 |
| 888 |
| — |
| — |
| — |
| 12,644 |
| |
Non-utility contracts | 198,681 |
| 203,428 |
| 208,328 |
| 212,042 |
| 218,431 |
| 935,826 |
| 1,976,736 |
| |
| Electric portfolio contracts | | Electric portfolio contracts | 263,940 | �� | | 300,795 | | | 302,838 | | | 307,888 | | | 315,593 | | | 969,383 | | | 2,460,437 | |
Electric wholesale market transactions | | Electric wholesale market transactions | 188,822 | | | 24,901 | | | 3,190 | | | — | | | — | | | — | | | 216,913 | |
Total | $ | 282,913 |
| $ | 274,212 |
| $ | 268,137 |
| $ | 271,214 |
| $ | 274,827 |
| $ | 1,533,294 |
| $ | 2,904,597 |
| Total | $ | 574,442 | | | | $ | 436,821 | | | $ | 409,907 | | | $ | 411,265 | | | $ | 418,569 | | | $ | 1,579,295 | | | $ | 3,830,299 | |
Total purchased power contracts provided the Company with approximately 13.012.5 million, 11.214.1 million and 12.114.5 million MWhs of firm energy at a cost of approximately $402.5$550.6 million, $373.8$508.2 million and $401.4$456.4 million for the years 2016, 2015 and 2014, respectively.
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 $45.7 million, $10.5 million and $3.9 million in 2017,2019, 2018, and 2019,2017, respectively.
Natural Gas Supply Obligations
The Company has entered into various firm supply, transportation and storage service contracts in order to ensure adequate availability of natural gas supply for its customers and generation requirements. 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 transportation and storage contracts, which have remaining terms from less than one1 year to 2825 years, provide that the Company must pay a fixed demand charge each month, regardless of actual usage. The Company incurred demand charges for 20162019 for firm transportation, storage and peaking services for its natural gas customers of $120.2$125.1 million. The Company incurred demand charges in 20162019 for firm transportation and storage services for the natural gas supply for its combustion turbines in the amount of $43.2$51.2 million.
The following table summarizes the Company’s obligations for future natural gas supply and demand charges through the primary terms of its existing contracts. The quantified obligations are based on the FERC and NEB (NationalCER (Canadian Energy Board)Regulator) currently authorized rates, which are subject to change.
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
Natural Gas Supply and Demand Charge Obligations (Dollars in Thousands) | 2020 | | 2021 | | 2022 | | 2023 | | 2024 | | Thereafter | | Total |
Natural gas portfolio contracts | $ | 273,263 | | | $ | 196,806 | | | $ | 178,208 | | | $ | 148,165 | | | $ | 82,509 | | | $ | — | | | $ | 878,951 | |
Firm transportation service | 176,741 | | | 173,133 | | | 172,190 | | | 161,508 | | | 116,842 | | | 828,136 | | | 1,628,550 | |
Firm storage service | 8,954 | | | 4,503 | | | 3,014 | | | 853 | | | 140 | | | 213 | | | 17,677 | |
Total | $ | 458,958 | | | $ | 374,442 | | | | $ | 353,412 | | | | $ | 310,526 | | | | $ | 199,491 | | | | $ | 828,349 | | | | $ | 2,525,178 | |
|
| | | | | | | | | | | | | | | | | | | | | |
Natural Gas Supply and Demand Charge Obligations (Dollars in Thousands) | 2017 |
| 2018 |
| 2019 |
| 2020 |
| 2021 |
| Thereafter |
| Total |
|
Natural gas supply | $ | 320,238 |
| $ | 211,256 |
| $ | 230,109 |
| $ | 177,390 |
| $ | 107,621 |
| $ | — |
| $ | 1,046,614 |
|
Firm transportation service | 156,290 |
| 154,155 |
| 149,277 |
| 140,672 |
| 128,049 |
| 467,266 |
| 1,195,709 |
|
Firm storage service | 6,616 |
| 3,861 |
| 2,943 |
| 1,950 |
| 1,619 |
| 2,475 |
| 19,464 |
|
Total | $ | 483,144 |
| $ | 369,272 |
| $ | 382,329 |
| $ | 320,012 |
| $ | 237,289 |
| $ | 469,741 |
| $ | 2,261,787 |
|
Service Contracts
The following table summarizes the Company’s estimated obligations for service contracts through the terms of its existing contracts.
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
Service Contract Obligations (Dollars in Thousands) | 2020 | | 2021 | | 2022 | | 2023 | | 2024 | | Thereafter | | Total |
Energy production service contracts | $ | 28,474 | | | $ | 29,219 | | | $ | 29,923 | | | $ | 30,645 | | | $ | 31,400 | | | $ | 141,817 | | | $ | 291,478 | |
Automated meter reading system | 43,971 | | | 44,849 | | | 45,526 | | | 46,218 | | | 46,926 | | | 96,149 | | | 323,639 | |
Total | $ | 72,445 | | | $ | 74,068 | | | $ | 75,449 | | | $ | 76,863 | | | $ | 78,326 | | | $ | 237,966 | | | $ | 615,117 | |
|
| | | | | | | | | | | | | | | | | | | | | |
Service Contract Obligations (Dollars in Thousands) | 2017 |
| 2018 |
| 2019 |
| 2020 |
| 2021 |
| Thereafter |
| Total |
|
Energy production service contracts | $ | 31,573 |
| $ | 31,970 |
| $ | 31,313 |
| $ | 50,656 |
| $ | 32,934 |
| $ | 204,687 |
| $ | 383,133 |
|
Automated meter reading system | 18,175 |
| 18,693 |
| 18,718 |
| 20,191 |
| 20,939 |
| 116,811 |
| 213,527 |
|
Total | $ | 49,748 |
| $ | 50,663 |
| $ | 50,031 |
| $ | 70,847 |
| $ | 53,873 |
| $ | 321,498 |
| $ | 596,660 |
|
Other Commitments and Contingencies
For information regarding PSE's environmental remediation obligations, see Note 3,4, "Regulation and Rates," to the consolidated financial statements included in itemItem 8 of this report.
(16)(17) Related Party Transactions
Scott Armstrong serves on the Board of Directors of theThe Company and, until its acquisition by Kaiser Permanente on February 1, 2017, was the President and Chief Executive Officer of Group Health Cooperative (Group Health). Group Health provided coverage to over 600,000 residents in Washington and Northern Idaho. Certain employees of PSE elected Group Health as their medical provider and as a result, PSE paid Group Health a total of $23.3 million and $20.3 million for medical coverage foridentified no material related party transactions during the year ended December 31, 20162019 and 2015, respectively.December 31, 2018.
Kimberly Harris, the President and Chief Executive Officer and a director of
(18) Segment Information
Puget Energy and PSE is married to Kyle Branum, who through 2016 was a principal at the law firm Riddell Williams P.S. As of January 2017, Mr. Branum is a partner at Summit Law Group, which provides legal services to PSE. In 2016 and 2015, Riddell Williams was paid $1.0 million and $1.8 million, respectively, for legal services provided to PSE and Mr. Branum was among the lawyers at Riddell Williams who provided such legal services. This work was performed under the supervision of PSE's General Counsel.
On October 10, 2014, U.S. Bancorp announced the appointment of Kimberly Harris to its board of directors effective October 20, 2014. Ms. Harris is the President and Chief Executive Officer of both Puget Energy and PSE. U.S. Bancorp is the parent company of U.S. Bank N.A., which directly or through its subsidiaries or affiliates provides credit, banking, investment and trust services to both Puget Energy and PSE. For the year ended December 31, 2016 and 2015, Puget Energy and PSE paid a total of approximately $0.3 million and $1.0 million, respectively, in fees and interest to U.S. Bank N.A. and its subsidiaries or affiliates.
(17) Segment Information
Puget Energy operates oneoperate 1 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.
(19) Accumulated Other Comprehensive Income (Loss)
The following tables present the changes in the Company’s (loss) AOCI by component for the years ended December 31, 2016, 20152019, 2018, and 2014,2017, respectively:
| | Puget Energy | Net unrealized gain (loss) and prior service cost on pension plans | Net unrealized gain (loss) on energy derivative instruments | Net unrealized gain (loss) on interest rate swaps | | Puget Energy | Net unrealized gain (loss) and prior service cost on pension plans | | | | |
Changes in AOCI, net of tax | | Changes in AOCI, net of tax | | | | | |
(Dollars in Thousands) | Total | (Dollars in Thousands) | | | | | Total |
Balance at December 31, 2013 | $ | 48,514 |
| $ | (705 | ) | $ | (94 | ) | $ | 47,715 |
| |
Balance at December 31, 2016 | | Balance at December 31, 2016 | $ | (33,712) | | | | | $ | (33,712) | |
Other comprehensive income (loss) before reclassifications | (84,301 | ) | — |
| — |
| (84,301 | ) | Other comprehensive income (loss) before reclassifications | 10,251 | | | | | 10,251 | |
Amounts reclassified from accumulated other comprehensive income (loss), net of tax | (923 | ) | 372 |
| 94 |
| (457 | ) | Amounts reclassified from accumulated other comprehensive income (loss), net of tax | (821) | | | | | (821) | |
Net current-period other comprehensive income (loss) | (85,224 | ) | 372 |
| 94 |
| (84,758 | ) | Net current-period other comprehensive income (loss) | 9,430 | | | | | 9,430 | |
Balance at December 31, 2014 | $ | (36,710 | ) | $ | (333 | ) | $ | — |
| $ | (37,043 | ) | |
Balance at December 31, 2017 | | Balance at December 31, 2017 | $ | (24,282) | | | | | $ | (24,282) | |
Other comprehensive income (loss) before reclassifications | 7,196 |
| — |
| — |
| 7,196 |
| Other comprehensive income (loss) before reclassifications | (48,870) | | | | | (48,870) | |
Amounts reclassified from accumulated other comprehensive income (loss), net of tax | 2,248 |
| 333 |
| — |
| 2,581 |
| Amounts reclassified from accumulated other comprehensive income (loss), net of tax | 1,180 | | | | | 1,180 | |
Reclassification of stranded taxes to retained earnings due to tax reform | | Reclassification of stranded taxes to retained earnings due to tax reform | (5,230) | | | | | (5,230) | |
Net current-period other comprehensive income (loss) | 9,444 |
| 333 |
| — |
| 9,777 |
| Net current-period other comprehensive income (loss) | (52,920) | | | | | (52,920) | |
Balance at December 31, 2015 | $ | (27,266 | ) | $ | — |
| $ | — |
| $ | (27,266 | ) | |
Balance at December 31, 2018 | | Balance at December 31, 2018 | $ | (77,202) | | | | | $ | (77,202) | |
Other comprehensive income (loss) before reclassifications | (5,528 | ) | — |
| — |
| (5,528 | ) | Other comprehensive income (loss) before reclassifications | (7,337) | | | | | (7,337) | |
Amounts reclassified from accumulated other comprehensive income (loss), net of tax | (918 | ) | — |
| — |
| (918 | ) | Amounts reclassified from accumulated other comprehensive income (loss), net of tax | 390 | | | | | 390 | |
| Net current-period other comprehensive income (loss) | (6,446 | ) | — |
| — |
| (6,446 | ) | Net current-period other comprehensive income (loss) | (6,947) | | | | | (6,947) | |
Balance at December 31, 2016 | $ | (33,712 | ) | $ | — |
| $ | — |
| $ | (33,712 | ) | |
Balance at December 31, 2019 | | Balance at December 31, 2019 | $ | (84,149) | | | | | $ | (84,149) | |
| | | | | | | | | | | | | | | | | | | |
| | | | | | | |
Puget Sound Energy | Net unrealized gain (loss) and prior service cost on pension plans | | | | Net unrealized gain (loss) on treasury interest rate swaps | | |
Changes in AOCI, net of tax | | | | | | | |
(Dollars in Thousands) | | | | | | | Total |
Balance at December 31, 2016 | $ | (140,155) | | | | | $ | (5,356) | | | $ | (145,511) | |
Other comprehensive income (loss) before reclassifications | 10,200 | | | | | — | | | 10,200 | |
Amounts reclassified from accumulated other comprehensive income (loss), net of tax | 8,088 | | | | | 317 | | | 8,405 | |
Net current-period other comprehensive income (loss) | 18,288 | | | | | 317 | | | 18,605 | |
Balance at December 31, 2017 | $ | (121,867) | | | | | $ | (5,039) | | | $ | (126,906) | |
Other comprehensive income (loss) before reclassifications | (48,802) | | | | | — | | | (48,802) | |
Amounts reclassified from accumulated other comprehensive income (loss), net of tax | 11,772 | | | | | 385 | | | 12,157 | |
Reclassification of stranded taxes to retained earnings due to tax reform | (26,233) | | | | | (1,100) | | | (27,333) | |
Net current-period other comprehensive income (loss) | (63,263) | | | | | (715) | | | (63,978) | |
Balance at December 31, 2018 | $ | (185,130) | | | | | $ | (5,754) | | | $ | (190,884) | |
Other comprehensive income (loss) before reclassifications | (8,096) | | | | | — | | | (8,096) | |
Amounts reclassified from accumulated other comprehensive income (loss), net of tax | 10,118 | | | | | 385 | | | 10,503 | |
| | | | | | | |
Net current-period other comprehensive income (loss) | 2,022 | | | | | 385 | | | 2,407 | |
Balance at December 31, 2019 | $ | (183,108) | | | | | $ | (5,369) | | | $ | (188,477) | |
|
| | | | | | | | | | | | |
Puget Sound Energy | Net unrealized gain (loss) and prior service cost on pension plans | Net unrealized gain (loss) on energy derivative instruments | Net unrealized gain (loss) on treasury interest rate swaps | |
Changes in AOCI, net of tax | |
(Dollars in Thousands) | Total |
Balance at December 31, 2013 | $ | (87,405 | ) | $ | (2,027 | ) | $ | (6,307 | ) | $ | (95,739 | ) |
Other comprehensive income (loss) before reclassifications | (84,955 | ) | — |
| — |
| (84,955 | ) |
Amounts reclassified from accumulated other comprehensive income (loss), net of tax | 8,079 |
| 1,341 |
| 317 |
| 9,737 |
|
Net current-period other comprehensive income (loss) | (76,876 | ) | 1,341 |
| 317 |
| (75,218 | ) |
Balance at December 31, 2014 | $ | (164,281 | ) | $ | (686 | ) | $ | (5,990 | ) | $ | (170,957 | ) |
Other comprehensive income (loss) before reclassifications | 6,922 |
| — |
| — |
| 6,922 |
|
Amounts reclassified from accumulated other comprehensive income (loss), net of tax | 13,482 |
| 686 |
| 317 |
| 14,485 |
|
Net current-period other comprehensive income (loss) | 20,404 |
| 686 |
| 317 |
| 21,407 |
|
Balance at December 31, 2015 | $ | (143,877 | ) | $ | — |
| $ | (5,673 | ) | $ | (149,550 | ) |
Other comprehensive income (loss) before reclassifications | (5,655 | ) | — |
| — |
| (5,655 | ) |
Amounts reclassified from accumulated other comprehensive income (loss), net of tax | 9,377 |
| — |
| 317 |
| 9,694 |
|
Net current-period other comprehensive income (loss) | 3,722 |
| — |
| 317 |
| 4,039 |
|
Balance at December 31, 2016 | $ | (140,155 | ) | $ | — |
| $ | (5,356 | ) | $ | (145,511 | ) |
Details about the reclassifications out of AOCI (loss) for the years ended December 31, 2016, 20152019, 2018, and 2014,2017, respectively, are as follows:
| | Puget Energy | | | Puget Energy | | | | | |
(Dollars in Thousands) | | | (Dollars in Thousands) | | | | | |
Details about accumulated other comprehensive income (loss) components | Affected line item in the statement where net income (loss) is presented | Amount reclassified from accumulated other comprehensive income (loss) | Details about accumulated other comprehensive income (loss) components | Affected line item in the statement where net income (loss) is presented | Amount reclassified from accumulated other comprehensive income (loss) | |
2016 |
| 2015 | 2014 | | 2019 | | 2018 | | 2017 |
Net unrealized gain (loss) and prior service cost on pension plans: | | | Net unrealized gain (loss) and prior service cost on pension plans: | | | | | | |
Amortization of prior service cost | (a) | $ | 1,938 |
| $ | 1,938 |
| $ | 1,938 |
| Amortization of prior service cost | (a) | $ | 1,648 | | | $ | 1,937 | | | $ | 1,938 | |
Amortization of net gain (loss) | (a) | (525 | ) | (5,397 | ) | (519 | ) | Amortization of net gain (loss) | (a) | (2,142) | | | (3,431) | | | (675) | |
| Total before tax | 1,413 |
| (3,459 | ) | 1,419 |
| | Total before tax | $ | (494) | | | $ | (1,494) | | | $ | 1,263 | |
| Tax (expense) or benefit | (495 | ) | 1,211 |
| (496 | ) | | Tax (expense) or benefit | 104 | | | 314 | | | (442) | |
| Net of Tax | 918 |
| (2,248 | ) | 923 |
| | Net of Tax | (390) | | | (1,180) | | | 821 | |
Net unrealized gain (loss) on energy derivative instruments: | | | |
Commodity contracts: Electric derivatives | Purchased electricity | — |
| (512 | ) | (572 | ) | |
| Tax (expense) or benefit | — |
| 179 |
| 200 |
| |
| Net of Tax | — |
| (333 | ) | (372 | ) | |
Net unrealized gain (loss) on interest rate swaps: | | | | | |
Interest rate contracts | Interest expense | — |
| — |
| (144 | ) | |
| | Tax (expense) or benefit | — |
| — |
| 50 |
| |
| Net of Tax | — |
| — |
| (94 | ) | |
Total reclassification for the period | Net of Tax | $ | 918 |
| $ | (2,581 | ) | $ | 457 |
| Total reclassification for the period | Net of Tax | $ | (390) | | | $ | (1,180) | | | $ | 821 | |
_______________
| |
(a)
| These AOCI components are included in the computation of net periodic pension cost (see Note 12, "Retirement Benefits" for additional details). |
__________
(a)These AOCI components are included in the computation of net periodic pension cost, see Note 13, "Retirement Benefits," to the consolidated financial statements included in item 8 of this report for additional details.
| | | | | | | | | | | | | | | | | | | | |
Puget Sound Energy | | | | | | | | | |
(Dollars in Thousands) | | | | | | | | | |
Details about accumulated other comprehensive income (loss) components | Affected line item in the statement where net income (loss) is presented | Amount reclassified from accumulated other comprehensive income (loss) | | | | | |
| | 2019 | | 2018 | | 2017 |
Net unrealized gain (loss) and prior service cost on pension plans: | | | | | | | |
Amortization of prior service cost | (a) | $ | 1,240 | | | $ | 1,529 | | | $ | 1,529 | |
Amortization of net gain (loss) | (a) | (14,048) | | | (16,430) | | | (13,972) | |
| Total before tax | $ | (12,808) | | | $ | (14,901) | | | $ | (12,443) | |
| Tax (expense) or benefit | 2,690 | | | 3,129 | | | 4,355 | |
| Net of tax | $ | (10,118) | | | $ | (11,772) | | | $ | (8,088) | |
| | | | | | |
| | | | | | |
| | | | | | |
| | | | | | |
Net unrealized gain (loss) on treasury interest rate swaps: | | | | | | | | | |
Interest rate contracts | Interest expense | (487) | | | (487) | | | (488) | |
| Tax (expense) or benefit | 102 | | | 102 | | | 171 | |
| Net of Tax | $ | (385) | | | $ | (385) | | | $ | (317) | |
Total reclassification for the period | Net of Tax | $ | (10,503) | | | $ | (12,157) | | | $ | (8,405) | |
____________
(a)These AOCI components are included in the computation of net periodic pension cost, see Note 13, "Retirement Benefits," to the consolidated financial statements included in item 8 of this report for additional details.
|
| | | | | | | | | | |
Puget Sound Energy | | | | |
(Dollars in Thousands) | | | | |
Details about accumulated other comprehensive income (loss) components | Affected line item in the statement where net income (loss) is presented | Amount reclassified from accumulated other comprehensive income (loss) |
2016 |
| 2015 | 2014 |
Net unrealized gain (loss) and prior service cost on pension plans: | | | | |
Amortization of prior service cost | (a) | $ | 1,529 |
| $ | 1,526 |
| $ | 1,526 |
|
Amortization of net gain (loss) | (a) | (15,955 | ) | (22,268 | ) | (13,954 | ) |
| Total before tax | (14,426 | ) | (20,742 | ) | (12,428 | ) |
| Tax (expense) or benefit | 5,049 |
| 7,260 |
| 4,349 |
|
| Net of tax | (9,377 | ) | (13,482 | ) | (8,079 | ) |
Net unrealized gain (loss) on energy derivative instruments: | | | | |
Commodity contracts: Electric derivatives | Purchased electricity | — |
| (1,055 | ) | (2,063 | ) |
| Tax (expense) or benefit | — |
| 369 |
| 722 |
|
| Net of Tax | — |
| (686 | ) | (1,341 | ) |
Net unrealized gain (loss) on treasury interest rate swaps: | | | | |
Interest rate contracts | Interest expense | (488 | ) | (488 | ) | (488 | ) |
| Tax (expense) or benefit | 171 |
| 171 |
| 171 |
|
| Net of Tax | (317 | ) | (317 | ) | (317 | ) |
Total reclassification for the period | Net of Tax | $ | (9,694 | ) | $ | (14,485 | ) | $ | (9,737 | ) |
_______________
| |
(a)
| These AOCI components are included in the computation of net periodic pension cost (see Note 12, "Retirement Benefits" 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.
| | | | | | | | | | | | | | | | | | | | | | | |
Puget Energy | 2019 Quarter | | | | | | |
(Unaudited; Dollars in Thousands) | First | | Second | | Third | | Fourth |
Operating revenue | $ | 1,114,839 | | | $ | 670,930 | | | $ | 627,007 | | | $ | 988,354 | |
Operating income | 213,460 | | | 39,115 | | | 26,126 | | | 240,307 | |
Net income (loss) | 132,154 | | | (32,952) | | | (39,443) | | | 150,949 | |
|
| | | | | | | | | | | | |
Puget Energy | 2016 Quarter |
(Unaudited; Dollars in Thousands) | First |
| Second |
| Third |
| Fourth |
|
Operating revenue | $ | 962,697 |
| $ | 668,169 |
| $ | 618,278 |
| $ | 915,157 |
|
Operating income | 284,824 |
| 175,634 |
| 88,072 |
| 236,854 |
|
Net income (loss) | 141,186 |
| 64,553 |
| 2,335 |
| 104,825 |
|
| | | | | | | | | | | | | | | | | | | | | | | |
| 2018 Quarter | | | | | | |
(Unaudited; Dollars in Thousands) | First | | Second | | Third | | Fourth |
Operating revenue | $ | 1,038,008 | | | $ | 671,852 | | | $ | 651,464 | | | $ | 985,172 | |
Operating income | 232,785 | | | 84,091 | | | 37,297 | | | 199,885 | |
Net income (loss) | 146,897 | | | 3,642 | | | (21,970) | | | 107,053 | |
| | | | | | | | | | | | | | | | | | | | | | | |
Puget Sound Energy | 2019 Quarter | | | | | | |
(Unaudited; Dollars in Thousands) | First | | Second | | Third | | Fourth |
Operating revenue | $ | 1,114,839 | | | $ | 670,930 | | | $ | 627,007 | | | $ | 988,354 | |
Operating income | 214,159 | | | 39,780 | | | 26,721 | | | 241,955 | |
Net income (loss) | 147,302 | | | (8,325) | | | (15,257) | | | 169,204 | |
| | | | | | | | | | | | | | | | | | | | | | | |
| 2018 Quarter | | | | | | |
(Unaudited; Dollars in Thousands) | First | | Second | | Third | | Fourth |
Operating revenue | $ | 1,038,008 | | | $ | 671,852 | | | $ | 651,464 | | | $ | 985,172 | |
Operating income | 235,856 | | | 81,701 | | | 46,147 | | | 193,432 | |
Net income (loss) | 163,037 | | | 26,778 | | | 3,891 | | | 123,456 | |
|
| | | | | | | | | | | | |
| 2015 Quarter |
(Unaudited; Dollars in Thousands) | First |
| Second |
| Third |
| Fourth |
|
Operating revenue | $ | 926,835 |
| $ | 658,341 |
| $ | 605,733 |
| $ | 901,791 |
|
Operating income | 245,235 |
| 126,772 |
| 69,888 |
| 230,030 |
|
Net income (loss) | 115,676 |
| 25,616 |
| (7,928 | ) | 107,815 |
|
|
| | | | | | | | | | | | |
Puget Sound Energy | 2016 Quarter |
(Unaudited; Dollars in Thousands) | First |
| Second |
| Third |
| Fourth |
|
Operating revenue | $ | 962,697 |
| $ | 668,169 |
| $ | 618,594 |
| $ | 915,158 |
|
Operating income | 281,425 |
| 171,991 |
| 84,476 |
| 237,101 |
|
Net income (loss) | 156,505 |
| 80,900 |
| 18,977 |
| 124,199 |
|
|
| | | | | | | | | | | | |
| 2015 Quarter |
(Unaudited; Dollars in Thousands) | First |
| Second |
| Third |
| Fourth |
|
Operating revenue | $ | 926,843 |
| $ | 658,341 |
| $ | 605,913 |
| $ | 902,161 |
|
Operating income | 240,903 |
| 122,753 |
| 66,036 |
| 226,446 |
|
Net income (loss) | 129,100 |
| 42,699 |
| 9,876 |
| 122,514 |
|
SCHEDULE I: CONDENSED FINANCIAL INFORMATION OF PUGET ENERGY
Puget Energy
Condensed Statements of Income and Comprehensive Income (Loss)
(Dollars in Thousands)
| | | | | | | | | | | | | | | | | |
| Year Ended December 31, | | | | |
| 2019 | | 2018 | | 2017 |
Non-utility expense and other | $ | (1,495) | | | $ | (1,345) | | | $ | (1,466) | |
Other income (deductions): | | | | | | | | |
Equity in earnings of subsidiary | 294,724 | | | 320,122 | | | 323,568 | |
Non-hedged interest rate swap expense | — | | | — | | | 28 | |
Interest income | 6,643 | | | 4,273 | | | 1,039 | |
Interest expense | (111,716) | | | (108,816) | | | (106,072) | |
Income tax expense (benefit) | 22,552 | | | 21,388 | | | (41,903) | |
Net income (loss) | $ | 210,708 | | | $ | 235,622 | | | $ | 175,194 | |
Comprehensive income (loss) | $ | 203,761 | | | $ | 182,702 | | | $ | 184,624 | |
|
| | | | | | | | | |
| Year Ended December 31, |
| 2016 | 2015 | 2014 |
Non-utility expense and other | $ | (5,252 | ) | $ | (1,617 | ) | $ | (5,390 | ) |
Other income (deductions): | |
| |
| |
|
Equity in earnings of subsidiary | 385,838 |
| 309,603 |
| 240,102 |
|
Non-hedged interest rate swap expense | (1,062 | ) | (3,796 | ) | (3,915 | ) |
Interest income | 2 |
| 63 |
| 185 |
|
Interest expense | (104,600 | ) | (100,114 | ) | (93,382 | ) |
Income taxes | 37,973 |
| 37,040 |
| 34,235 |
|
Net income (loss) | 312,899 |
| 241,179 |
| 171,835 |
|
Comprehensive income (loss) | $ | 306,453 |
| $ | 250,956 |
| $ | 87,077 |
|
See accompanying notes to the condensed financial statements.
Puget Energy
Condensed Balance Sheets
(Dollars in Thousands)
| | | December 31, | | December 31, | |
| 2016 | 2015 | | 2019 | | 2018 |
Assets: | | Assets: | | | |
Investment in subsidiaries | $ | 3,571,550 |
| $ | 3,415,571 |
| Investment in subsidiaries | $ | 4,153,618 | | | $ | 3,820,347 | |
Other property and investments: | |
| |
| Other property and investments: | | | |
Goodwill | 1,656,513 |
| 1,656,513 |
| Goodwill | 1,656,513 | | 1,656,513 |
Current assets: | |
| |
| Current assets: | | | |
Cash | 397 |
| 639 |
| Cash | 947 | | 2,067 |
Receivables from affiliates1 | 213 |
| 203 |
| Receivables from affiliates1 | 180,527 | | 138,714 |
Total current assets | 610 |
| 842 |
| Total current assets | 181,474 | | | 140,781 |
Long-term assets: | |
| |
| Long-term assets: | | | |
Deferred income taxes | 309,812 |
| 272,487 |
| Deferred income taxes | 235,428 | | 221,660 |
Other | 521 |
| 537 |
| Other | 2,056 | | 2,040 |
Total long-term assets | 310,333 |
| 273,024 |
| Total long-term assets | 237,484 | | 223,700 |
Total assets | $ | 5,539,006 |
| $ | 5,345,950 |
| Total assets | $ | 6,229,089 | | | $ | 5,841,341 | |
Capitalization and liabilities: | |
| |
| Capitalization and liabilities: | | | |
Common equity | $ | 3,688,713 |
| $ | 3,531,225 |
| Common equity | $ | 4,000,299 | | | $ | 3,860,728 | |
Long-term debt | 1,808,828 |
| 1,783,898 |
| Long-term debt | 1,752,644 | | | 1,954,205 |
Total capitalization | 5,497,541 |
| 5,315,123 |
| Total capitalization | 5,752,943 | | | 5,814,933 | |
Current liabilities: | |
| |
| Current liabilities: | | | |
Account Payable | 15,801 |
| 171 |
| Account Payable | 208 | | 260 |
Current maturities of long-term debt | | Current maturities of long-term debt | 450,000 | | — |
Interest | 25,523 |
| 25,606 |
| Interest | 25,938 | | 26,148 |
Unrealized loss on derivative instruments | 141 |
| 4,753 |
| |
Total current liabilities | 41,465 |
| 30,530 |
| Total current liabilities | 476,146 | | | 26,408 | |
Long-term liabilities: | |
| |
| |
Unrealized loss on derivative instruments | — |
| 297 |
| |
Total long-term liabilities | — |
| 297 |
| |
Commitments and contingencies | | | |
Commitments and contingencies (Note 16) | | Commitments and contingencies (Note 16) | | | |
Total capitalization and liabilities | $ | 5,539,006 |
| $ | 5,345,950 |
| Total capitalization and liabilities | $ | 6,229,089 | | | $ | 5,841,341 | |
_______________
| |
1
| Eliminated in consolidation. |
1 Eliminated in consolidation.
See accompanying notes to the condensed financial statements.
Puget Energy
Condensed Statements of Cash Flows
(Dollars in Thousands)
| | | | | | | | | | | | | | | | | |
| Year Ended December 31, | | | | |
| 2019 | | 2018 | | 2017 |
Operating activities: | | | | | |
Net cash provided by (used in) operating activities | $ | 68,724 | | | $ | 79,176 | | | $ | 139,005 | |
Investing activities: | | | | | | | | |
Investment in subsidiaries | (210,000) | | | — | | | (24,222) | |
(Increase) decrease in loan to subsidiary | (41,708) | | | (59,864) | | | (78,155) | |
Other | — | | | — | | | (437) | |
Net cash provided by (used in) investing activities | (251,708) | | | (59,864) | | | (102,814) | |
Financing activities: | | | | | | | | |
Dividends paid | (64,220) | | | (77,204) | | | (123,307) | |
Issuance of bond | 246,200 | | | 209,300 | | | — | |
Issuance/redemption of term-loan and other long-term debt | — | | | (150,000) | | | 90,120 | |
Issue costs and others | (116) | | | (92) | | | (2,650) | |
Net cash provided by (used in) by financing activities | 181,864 | | | (17,996) | | | (35,837) | |
Increase (decrease) in cash | (1,120) | | | 1,316 | | | 354 | |
Cash at beginning of year | 2,067 | | | 751 | | | 397 | |
Cash at end of year | $ | 947 | | | $ | 2,067 | | | $ | 751 | |
|
| | | | | | | | | |
| Year Ended December 31, |
| 2016 | 2015 | 2014 |
Operating activities: | | | |
Net cash provided by (used in) operating activities | $ | 145,719 |
| $ | 171,576 |
| $ | 225,459 |
|
Investing activities: | |
| |
| |
|
Investment in subsidiaries | — |
| (28,900 | ) | — |
|
(Increase) decrease in loan to subsidiary | — |
| 28,933 |
| 665 |
|
Other | (6,078 | ) | (5,632 | ) | (2,829 | ) |
Net cash provided by (used in) investing activities | (6,078 | ) | (5,599 | ) | (2,164 | ) |
Financing activities: | |
| |
| |
|
Dividends paid | (148,965 | ) | (263,059 | ) | (223,428 | ) |
Issuance of bond | — |
| 400,000 |
| — |
|
Issuance/redemption of term-loan and other long-term debt | 12,480 |
| (299,000 | ) | — |
|
Issue costs and others | (3,398 | ) | (3,341 | ) | 4 |
|
Net cash provided by (used in) by financing activities | (139,883 | ) | (165,400 | ) | (223,424 | ) |
Increase (decrease) in cash | (242 | ) | 577 |
| (129 | ) |
Cash at beginning of year | 639 |
| 62 |
| 191 |
|
Cash at end of year | $ | 397 |
| $ | 639 |
| $ | 62 |
|
See accompanying notes to the condensed financial statements.
NOTES TO CONDENSED FINANCIAL STATEMENTS
(1) Basis of Presentation
Puget Energy is an energy services holding company that conducts substantially all of its business operations through its regulated subsidiary, PSE. Puget Energy also hasa wholly-owned non-regulated subsidiary, named Puget LNG, LLC (Puget LNG). Puget LNG was formed onin November 29, 2016, and has the sole purpose of owning, developing and financing the non-regulated activity of a LNGliquefied natural gas (LNG) facility at the Port of Tacoma, Washington. 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 subsidiaries have been included using the equity method, should be read in conjunction with the consolidated financial statements and notes thereto of Puget Energy included in Item 8, "Financial Statements and Supplementary Data" of this Form 10-K. Puget Energy owns 100% of the common stock of its subsidiaries.
Equity earnings of subsidiary included earnings from PSE of $380.6$292.9 million, $304.2$317.2 million and $236.6$320.1 million for the years ended December 31, 2016, 20152019, 2018, and 2014,2017, respectively, and business combination accounting adjustments under ASC 805 recorded at Puget Energy for PSE of $5.2$2.9 million, $5.4$4.7 million and $3.5$3.9 million for the years ended December 31, 2016, 20152019, 2018, and 2014,2017, respectively. Investment in subsidiaries includes Puget Energy business combination accounting adjustments under ASC 805 that are recorded at Puget Energy.
Change in Accounting Principle
On January 1, 2016, the Company changed its method of presenting unamortized debt issuance costs in the balance sheet. The new method of presenting debt issuance costs was adopted to comply with ASU 2015-03, "Interest-Imputation of Interest (Subtopic 835-30): Simplifying the Presentation of Debt Issuance Costs". ASU 2015-03 requires debt issuance costs related to a recognized debt liability be presented in the balance sheet as a direct deduction from the carrying amount of the debt liability, consistent with the presentation of a debt discount. The prior year comparative balance sheet has been adjusted to apply the new method retrospectively. Due to the change in accounting principle, the December 31, 2015 long-term asset financial statement line item “Other” and the liability financial statement line item “Long-term debt” both decreased $15.6 million at Puget Energy.
(2) Long-Term Debt
For information concerning Puget Energy’s long-term debt obligations, see Note 6,7, "Long-Term Debt" to the consolidated financial statements included in Item 8 of this report.
(3) Commitments and Contingencies
For information concerning Puget Energy’s material contingencies and guarantees, see Note 15,16, "Commitments and Contingencies" to the consolidated financial statements included in Item 8 of this report.
SCHEDULE II:VALUATION AND QUALIFYING ACCOUNTS AND RESERVES
| | | | | | | | | | | | | | | | | | | | | | | |
Puget Energy and Puget Sound Energy (Dollars in Thousands) | Balance at Beginning of Period | | Additions Charged to Costs and Expenses | | Deductions | | Balance at End of Period |
Year Ended December 31, 2019 | | | | | | | |
Accounts deducted from assets on balance sheet: | | | | | | | |
Allowance for doubtful accounts receivable | $ | 8,408 | | | $ | 17,633 | | | $ | 17,747 | | | $ | 8,294 | |
Year Ended December 31, 2018 | | | | | | | | | | | |
Accounts deducted from assets on balance sheet: | | | | | | | | | | | |
Allowance for doubtful accounts receivable | $ | 8,901 | | | $ | 24,846 | | | $ | 25,339 | | | $ | 8,408 | |
Year Ended December 31, 2017 | | | | | | | | | | | |
Accounts deducted from assets on balance sheet: | | | | | | | | | | | |
Allowance for doubtful accounts receivable | $ | 9,798 | | | $ | 26,266 | | | $ | 27,163 | | | $ | 8,901 | |
|
| | | | | | | | | | | | |
Puget Energy and Puget Sound Energy (Dollars in Thousands) | Balance at Beginning of Period | Additions Charged to Costs and Expenses | Deductions | Balance at End of Period |
Year Ended December 31, 2016 | | | | |
Accounts deducted from assets on balance sheet: | | | | |
Allowance for doubtful accounts receivable | $ | 9,756 |
| $ | 24,389 |
| $ | 24,347 |
| $ | 9,798 |
|
Year Ended December 31, 2015 | |
| |
| |
| |
|
Accounts deducted from assets on balance sheet: | |
| |
| |
| |
|
Allowance for doubtful accounts receivable | $ | 7,472 |
| $ | 20,732 |
| $ | 18,448 |
| $ | 9,756 |
|
Year Ended December 31, 2014 | |
| |
| |
| |
|
Accounts deducted from assets on balance sheet: | |
| |
| |
| |
|
Allowance for doubtful accounts receivable | $ | 7,385 |
| $ | 27,228 |
| $ | 27,141 |
| $ | 7,472 |
|
ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE
None.
ITEM 9A. CONTROLS AND PROCEDURES
PugetEnergy
Evaluation of Disclosure Controls and Procedures
Under the supervision and with the participation of Puget Energy’s management, including the President and Chief Executive Officer and 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, 2016,2019, 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
During 2018, Puget Energy implemented internal controls covering the evaluation and assessment of leasing contracts related to the adoption of the new leasing standard as of January 1, 2019.
There have been no changes in Puget Energy’s internal control over financial reporting during the yearquarter ended December 31, 20162019, 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 (2013) 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, 2016.2019.
Puget Energy’s effectiveness of internal control over financial reporting as of December 31, 20162019, 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, 2016,2019, 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
During 2018, PSE implemented internal controls covering the evaluation and assessment of leasing contracts related to the adoption of the new leasing standard as of January 1, 2019.
There have been no changes in PSE’s internal control over financial reporting during the yearquarter ended December 31, 20162019, that have materially affected, or are reasonably likely to materially affect, PSE’s internal control over financial reporting.
In January 2017, PSE implemented a financial systems modernization project designed to improve the financial processes, tools and methods used throughout our business. The modernized systems are being used for transactions in 2017, but were not utilized in preparing 2016 financial information. Management monitored developments related to the financial systems modernization project, including working with the project team to ensure control impacts were identified and documented, in order to assist management in evaluating impacts to internal control. System integration and user acceptance testing were conducted to aid management in its evaluations. Post-implementation reviews of the system implementation and impacted business processes are being conducted to enable management to evaluate the design and effectiveness of internal controls during 2017.
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, PSE’s management assessed the effectiveness of internal control over financial reporting based on the framework in Internal Control – Integrated Framework (2013) 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, 2016.2019
PSE’s effectiveness of internal control over financial reporting as of December 31, 20162019, has been audited by PricewaterhouseCoopers LLP, an independent registered public accounting firm, as stated in their report which is included herein.
ITEM 9B. OTHER INFORMATION
None.
PART III
ITEM 10. DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE
Board of Directors
As of March 2, 2017, tenFebruary 21, 2020, twelve directors constitute Puget Energy’s Board of Directors and eleventhirteen 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.
Scott Armstrong, age 57,60, has been a director on the boardboards of PSE since June 25, 2015.of 2015 and on the board of Puget Energy since November 2017. Mr. Armstrong was President and CEO of Group Health Cooperative of Seattle, Washington, a health insurance and medical care provider, positions he had held since January 2005, until its acquisition by Kaiser Permanente on February 1, 2017. An independent director not affiliated with any of the Company’s investors, Mr. Armstrong’s executive leadership experience in a heavily regulated industry that has undergone extensive change, along with his involvement in civic affairs in the Pacific Northwest, are among the reasons for his appointment to the PSE board.
Kenton Bradbury, age 50, has been a director on the boards of both Puget Energy and PSE effective April 17, 2019. He is currently the Managing Director of OMERS Infrastructure Management Inc. a position he has held since 2015. Prior to that, Mr. Bradbury served as a director of Infracapital, the infrastructure investment arm of M&G Investments, and served as Senior Vice President of Infrastructure and Regulation at E.ON in Germany. Mr. Bradbury will not receive any director compensation from the Companies for his service as an Owner Director on the Boards, but will be reimbursed for out-of-pocket expenses.
Andrew ChapmanRichard Dinneny, age 57, has been a director on the boards of both Puget Energy and PSE effective April 17, 2019. Mr. Dinneny is currently the Senior Portfolio Manager, Infrastructure and Renewable Resources for British Columbia Investment Management Corporation (BCI) where he has responsibility for all aspects of investing in infrastructure transactions. Mr. Dinneny is a director of Vier Gas Services GmbH & Co. KG, Essen, the owner of Open Grid Europe, German’s leading natural gas transport company. Mr. Dinneny served on the board of Cleco Group LLC, Cleco Corporate Holdings LLC, and Cleco Power LLC. Mr. Dinneny will not receive any director compensation from the Companies for his service as an Owner Director on the Boards, but will be reimbursed for out-of-pocket expenses.
Barbara Gordon, age 61, has been a director on the board of PSE since November 2017. Ms. Gordon currently serves on the Woodland Park Zoo board of directors and as the Vice Chair of the Animal Care Committee. Ms. Gordon previously served as a Vice President of the board of directors for Seattle-King County Habitat for Humanity, a non-profit organization (2016-2018). Prior to that time, Ms. Gordon served as Executive Vice President and Chief Customer Officer of Bellevue-based Apptio, a developer of technology business management software (2016-2017), Senior Vice President and Chief Operating Officer of Isilon/EMC, a digital storage systems company (2013-2016), and as Corporate Vice President of Worldwide Customer Service and Support at Microsoft (2003-2013). An independent director not affiliated with any of the Company's investors, Ms. Gordon brings to the Board her expertise in customer-facing technology initiatives and enterprise level management of customer service and support.
Christopher Hind, age 50, has been a director on the boards of both Puget Energy and PSE since February 2009. Mr. Chapman28, 2018. He is currently a Managing Director in the Macquarie Capital Funds division of the Macquarie Group,Senior Principal, Private Infrastructure with Canada Pension Plan Investment Board (CPPIB), an investment management organization, which position he has held since 2006.January 2016. Prior to joining the Macquarie Group,that, Mr. Chapman was Vice President – Strategy & Regulation for American Water from 2005 to 2006 and RegionalHind served as a Managing Director, Investment Banking, at CIBC, a financial institution, from 2003October 1997 to 2004.January 2016. Mr. ChapmanHind also servedcurrently serves on the boardsboard of Cleco Power LLCdirectors of Transportadora de Gas del Peru S.A., the largest transporter of natural gas and Aquarion Water Company.natural gas liquids in Peru. Mr. Chapman representsHind was selected by CPPIB and pursuant to the Company’s Macquarie affiliated investorsAmended and Restated Bylaws of each of the Companies, will serve as an Owner Director on their respective Boards of Directors. Mr. Hind will not receive any director compensation from the Companies for his service as an Owner Director 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.Boards, but will be reimbursed for out-of-pocket expenses.
Steven W. Hooper, age 52, is66, has been 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. Ms. Harris is currently on the board of directors of U.S. Bancorp, a bank holding company.
Steven W. Hooper, age 63, is a director on the boards of both Puget Energy and PSE, which positions he has held since January 2015. Mr. Hooper is currently co-founder and partner of Ignition Partners, a venture capital firm that focuses on technology based in Bellevue, Washington, which position he has held since 2000. Previously, Mr. Hooper was the co-CEO of Teledesic (1998-2000) and CEO of Nextlink (1997-1998) and AT&T Wireless (1994-1997). Mr. Hooper also currently serves on the boards of directors of Recreational Equipment, Inc. (REI), an outdoor equipment company, and Airbiquity, Inc. and Blucora, Inc., an automotive telematics company, as well as on the boards of various Ignition Partners portfolio companies. An independent director not affiliated with any of the Company’s investors, Mr. Hooper’s leadership skills, experience with the challenges facing regulated businesses, and involvement with regional educational and civic organizations are some of the reasons that led to his appointment to the Puget Energy and PSE boards.
Karl KuchelTom King, age 3858, has been a director on the boards of both Puget Energy and PSE effective April 17, 2019. Mr. King is currently the Operating Executive with AEA investors, a middle market private equity firm, which position he has held since January 2017,2017. Mr. King served as Chairman and President of National Grid U.S. from 2007-2015. Prior to that, he was president of PG&E Corporation and Chairman and CEO of Pacific Gas and Electric from 2003-2007. Mr. King serves on the board of Entregado Group and Allied Power Group and served on the board of Peak Reliability and EnergySavvy, Inc. Mr. King serves on the boards of Puget Energy and PSE as a representative of CPPIB’s ownership interests, pursuant to the Company’s Macquarie affiliated investors and FSS Infrastructure Trust, consistent withterms of the Puget Energy and PSE bylaws. Mr. Kuchel is currently the Chief Executive Officer of Macquarie Infrastructure Partners, Inc., which position he has held since June 2016. Prior to that time, Mr. Kuchel served as Chief Operating Officer (from November 2010 through May 2016) of Macquarie Infrastructure Partners, Inc. Mr. Kuchel also currently serves on the boards of directors of various other portfolio companies managed and advised by Macquarie Infrastructure Partners, Inc., and provides the Puget Energy and PSE boards the benefit of his experience managing and overseeing the financial and operational affairs of infrastructure owners.
Christopher LeslieMary Kipp, age 52, 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 Energyeffective January 3, 2020. Ms. Kipp has also been elected President 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 also serves as a director on the board of Cleco Power, LLC. In addition to his managementofficer since January 3, 2020, 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 64, 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 boardswas President of Puget Energy and PSE from August 2019 to December 2019. Prior to that time Ms. Kipp served as a representativePresident, Chief Executive Officer and Director of Canada Pension Plan Investment Board (CPPIB)'s ownership interests, pursuantEl Paso Electric Company (El Paso) from May 2017 to the termsAugust 2019. Prior to that she served as Chief Executive Officer and director of the Puget EnergyEl Paso from December 2015 to May 2017, and PSE bylaws,President of El Paso from 2014 to 2015. Ms. Kipp also served as Senior Vice President, General Counsel and bringsChief Compliance Officer at El Paso from 2010 to this service his skills in project finance and experience with managing the capital requirements of energy companies.2014.
Paul McMillan,age 62,65, has been a director on the boards of both Puget Energy and PSE since April 23, 2015. Mr. McMillan is currently principal of Tidal Shift Capital Inc., which provides consulting and project development services to energy and infrastructure clients, of Toronto, Ontario, Canada, which position he has held since July 2009. He served as Senior Vice President of EPCOR Energy Division of Edmonton, Alberta, Canada, from May 2005 to July 2009 and President of EPCOR Merchant and Capital LP from September 2000 to May 2005. In addition, Mr. McMillan is on the board of BluEarth Renewables. Mr. McMillan serves on the boards of Puget Energy and PSE as a representative of Aimco’s ownership interests, pursuant to the terms of the Puget Energy and PSE bylaws, and brings to this service his experience in energy and gas operations and trading as well as renewable and gas project development.
Mary McWilliams, age 68,71, has been a director on the boards of both Puget Energy and PSE since March 1, 2011. Ms. McWilliams was most recently the Executive Director at Washington Health Alliance, a health care organization, which position she held from 2008 to 2014. 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 Virginia Mason Health System, a health care services organization. Her civic commitments have included Seattle Rotary, Seattle Symphony, YWCA and Business Health Trust.the Greater Seattle Chamber of Commerce. Ms. McWilliams’sMcWilliams’ significant experience managing consumer-focused organizations with challenging regulatory and compliance regimes, her civic involvement in the community, 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.
Etienne MiddletonChristopher Trumpy, age 42, has been a director on the boards of both Puget Energy and PSE since March 1, 2016. Mr. Middleton is currently the Senior Principal, Private Infrastructure with CPPIB, which position he has held since 2009. Mr. Middleton 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. Mr. Middleton also serves on the boards of Transelec S.A., a Chilean transmission company, and Grupo Costanera, a Chilean toll-road operator.
Christopher Trumpy, age 62,65, 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, a policy and governance consulting firm, 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)BCI) 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,BCI, 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.
Martijn Verwoest, age 43, has been a director on the boards of both Puget Energy and PSE effective April 17, 2019. Mr. Verwoest is currently the Head of Energy & Utilities at Stichting Pensioenfonds Zorg en Welzijn (PGGM), and is a member of their Infrastructure Investment Committee since 2007. From 2001 to 2007, he worked in PGGM’s public equity department. Mr. Verwoest will not receive any director compensation from the Companies for his service as an Owner Director on the Boards, but will be reimbursed for out-of-pocket expenses.
Steven Zucchet, age 54, has been a director on the boards of both Puget Energy and PSE effective April 17, 2019. Mr. Zucchet is currently the Managing Director at Ontario Municipal Employees Retirement System Infrastructure Management (OMERS). Since joining OMERS in 2003, Mr. Zucchet has led numerous transactions and had asset management responsibilities at a number of utility and generation companies in Canada and the United States. He is currently on the board of Oncor and Bruce Power Inc. Mr. Zucchet will not receive any director compensation from the Companies for his service as an Owner Director on the Boards, but will be reimbursed for out-of-pocket expenses.
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,Kenton Bradbury, Richard Dinneny, Steven Hooper, David MacMillanPaul McMillan and Paul McMillanTom King are the members of the Audit Committee. The Board has determined that Andrew ChapmanPaul McMillan 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
There have been no material changes to the procedures by which shareholders may recommend nominees to the Boards of Directors of Puget Energy and PSE. 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 EthicsConduct
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,EST-11, 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. 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 2016,2019, nor were they 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 below. For 20162019, the Company’s Named Executive Officers and titles were:
•Kimberly J. Harris, President and Chief Executive Officer (CEO); until August 30, 2019, and CEO until her retirement effective January 2, 2020;
•Mary E. Kipp, President, effective August 30, 2019, and President and CEO, effective January 3, 2020;
•Daniel A. Doyle, Senior Vice President and Chief Financial Officer (CFO);
•Steve R. Secrist, Senior Vice President, General Counsel, Chief Ethics and Compliance Officer; and
•Marla D. Mellies, Senior Vice President, Chief Administrative Officer; andOfficer.
•Philip K. Bussey, Senior Vice President, Chief Customer 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.provides to its Named Executive Officers.
Compensation Program Objectives
The Company’s executive compensation program has two main objectives:
•Support sustained Company performance by attracting, retaining and motivating talented people to run the business.
•Align incentive compensation payments with the achievement of short and long-term 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 the executive compensation program from its independent executive compensation consultant, Frederic W. Cook & Co., Inc. (Cook & Co.)Meridian Compensation Partners, LLC (Meridian). The Committee recommends to the full Board for approval both the salary level for our CEO, based on information provided by Cook & Co.,Meridian and other relevant factors described below, 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 target and actual awards under those plans.plans, based on the compensation philosophy and taking into consideration information provided by Meridian and other relevant factors.
In 2016,2019, the CommitteeCompany used the following strategies to achieve the objectives of our executive compensation program:
•Design and deliver a competitive total compensation opportunity. To attract, retain and motivate a talented executive team, the CommitteeCompany believes that total pay opportunity should be competitive with companies of similar size, revenue, industry and scope of operations so that new executives will want to join the Company and current executives will be retained.operations. As described below in the discussion of Compensation Program Elements (Review of Pay Element Competitiveness), the Committee, with the support of Meridian, annually compares executive compensation levels to external market data from similar companies in our industry and targets each element of target total direct compensation (the sum of base(base salary and target annual and long-term incentive award opportunities) to the 50th percentile of the market data with variations by individual executive, as appropriate.During 2019, the Committee worked with Meridian to develop a compensation package for the new President, and now President and CEO, Mary Kipp, who succeeded Ms. Harris. The Committeeterms of Ms. Kipp’s compensation are described below.The Company also
recognizes the importance of providing retirement income. Executives choose to work forAs such, 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 ofour retirement programs provided by our comparator group and provides benefits that are commensuratecompetitive with this group.
our peers.•Place a significant portion of each executive’s target totalincentive 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 deliverCompany maintains an incentive compensation program that supports the Company’s business direction as approved by the Boardstrategy 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 rewardedearned based on achievement relative to annual and long-term performance goals. For example, Ms. Harris, CEO in 2019, had a mix of 2019 cash compensation comprised of 22% base salary and 78% at-risk target compensation. By establishing goals, monitoring results, and rewarding achievement of goals, the Company focusesseeks to focus executives on actions that will improve the Company and enhance investor value, while also retaining key talent. The Committee annually evaluates and establishes the performance factorsgoals 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.
•Oversee the Company’s talent management process to ensure that executive leadership continues uninterrupted by executive retirements or other personnel changes. The CEO leads 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. As part of its ongoing succession planning efforts, during 2019, the Committee and the Board executed a CEO succession plan pursuant to which Ms. Kipp became CEO effective January 2020.
Compensation Philosophy
The target total compensation package is designed to provide participants with appropriate incentives that are competitive with the comparator group described below and motivate the achievement of 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 awards 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 2019 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.
As a matter of philosophy, all three components of target total direct compensation are generally targeted at the 50th percentile of industry practice, with deviations by individual executive as described below. If Company performance results are below expectations, actual compensation is expected to be below this targeted level. If Company performance exceeds target, actual compensation is expected to be above this targeted level.
Individual pay adjustments are reviewed annually to see how they position the executive relative to the 50th percentile of market pay, while also considering other factors such as, the executive’s recent performance, experience level, company performance, retention and internal pay equity. Notwithstanding the median philosophy, the Company may choose to target an executive’s compensation 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 differ from those typically found in the market.
Role of Market Data
The Company uses market data compiled by Meridian to inform its pay decisions on base salary, target annual incentives and target long-term incentive awards. Market data is obtained from both industry-specific surveys and proxy statements of public companies selected for inclusion in the Company’s custom executive compensation benchmarking peer group. The market survey data were sourced from a select cut from the Willis Towers Watson 2018 Energy Services Survey, comprised of utility and other companies similar in size and scope of operations to PSE. The 22 companies in the custom market survey cut used to inform target compensation decisions for 2019 are shown below:
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
Custom Survey Peer Group | |
|
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1. | Alliant Energy |
| 10. |
| Hawaiian Electric Industries, Inc. |
| 19. |
| Spire, Inc. |
2. | Ameren |
| 11. |
| NiSource |
| 20. |
| Vectren |
3. | Atmos Energy |
| 12. |
| OGE Energy |
| 21. |
| WEC Energy Group |
4. | Avangrid |
| 13. |
| ONE Gas, Inc |
| 22. |
| Westar Energy |
5. | Avista |
| 14. |
| Pinnacle West Capital |
| |
| |
6. | Black Hills |
| 15. |
| PNM Resources |
| |
| |
7 | CMS Energy |
| 16. |
| Portland General Electric |
| |
| |
8 | Eversource Energy |
| 17. |
| SCANA |
|
|
|
|
9. | Great Plains Energy |
| 18. |
| Southwest Gas |
|
|
|
|
| | | | | | | | | |
The market survey data were supplemented with proxy statement data for select positions in the Company’s executive compensation peer group, which was comprised of 16 companies, all but one of which overlapped with companies included in the market survey data. The 2018 median revenue of the executive compensation peers was $3.6 billion, which was comparable to PSE’s annual revenues of $3.4 billion at the time the peer group was developed. The peer companies included in the Company’s executive compensation benchmarking peer group to inform 2019 compensation decisions are the same as those used for 2018 and are shown below:
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
Proxy Peer Group | |
|
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|
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1. | Alliant Energy |
| 7. |
| Great Plains Energy |
| 13. |
| SCANA |
2. | Ameren |
| 8. |
| MDU Resources Group |
| 14. |
| Vectren |
3. | Avista |
| 9. |
| NiSource |
| 15. |
| WEC Energy |
4. | Black Hills |
| 10. |
| OGE Energy |
| 16. |
| Westar Energy |
5. | CMS Energy |
| 11. |
| Pinnacle West Capital |
|
|
|
|
6. | Eversource Energy |
| 12. |
| Portland General Electric |
|
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|
Compensation Program Elements
The Company’s executive 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 2009.2009 under certain legacy arrangements. Since the Company is not publicly listed and does not grant equity awards to its executives, it relies on a mix of non-equityfixed and variable cash-based compensation elements to achieve its compensation objectives.
The target total compensation package is designed to provide participants with appropriate incentives that are competitive withobjectives, including a performance unit plan, which helps align the comparator group described below and drive the achievementinterests of 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 awards 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 2016 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 those of investors.
Review of Pay Element Competitiveness
To help inform the Committee’s recommendations for 2016 base salaries, annual incentive programs and long-term incentive programs, the Committee reviewed market data obtained from both industry-specific surveys and proxy statements of public companies selected for inclusion in the Company’s custom executive compensation benchmarking peer group. The market survey data were sourced from a select cut from the Towers Watson 2015 Energy Services Survey, comprised of utility and other companies similar in size and scope of operations to PSE. The 24 companies in the custom market survey cut used to inform target compensation decisions for 2016 are:
|
| | | | | |
Custom Survey Peer Group | | | | |
1. | AGL Resources | 10. | MDU Resources Group | 19. | Teco Energy |
2. | Alliant Energy | 11. | NiSource | 20. | UIL Holdings |
3. | Ameren | 12. | OGE Energy | 21. | UNS Energy |
4. | Atmos Energy | 13. | Oncor Electric Delivery | 22. | Vectren |
5. | Avista | 14. | Pinnacle West Capital | 23. | Westar Energy |
6. | Black Hills | 15. | PNM Resources | 24. | Wisconsin Energy |
7. | CMS Energy | 16. | Portland General Electric | | |
8. | CPS Energy | 17. | SCANA | | |
9. | LLG&E and KU Energy | 18. | Southwest Gas | | |
As noted, the market survey data were supplemented with proxy statement data for select positions in the Company’s executive compensation peer group, which was comprised of 14 companies, all but four of which overlapped with companies included in the market survey data. The 2015 median revenue of the executive compensation peers was $3.6 billion, which was comparable to PSE’s annual revenues of $3.0 billion at the time the peer group was developed. The peer companies included in the Company’s executive compensation benchmarking peer group to inform 2016 compensation decisions are shown below:
|
| | | | | |
Proxy Peer Group | | | | |
1. | Alliant Energy | 6. | MDU Resources Group | 11. | SCANA |
2. | Avista | 7. | NiSource | 12. | Vectren |
3. | Eversource Energy | 8. | Pepco Holdings | 13. | Westar Energy |
4. | Great Plains Energy | 9. | Pinnacle West Capital | 14. | Wisconsin Energy |
5. | Integrys Energy Group | 10. | Portland General Electric | | |
As a matter of philosophy, all three components of target total direct compensation are generally targeted at the 50th percentile of industry practice, with deviations by individual executive as described below. If Company performance results are below expectations, actual compensation is expected to be below this targeted level and if Company performance exceeds target, actual compensation is expected to be above this targeted level.
Individual pay adjustments are reviewed annually 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. Despite the median philosophy, the Company may choose to target an executive’s compensation 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 market data, the Committee generally also received advice from Cook & Co. in connection with 2016 compensation decisions.
Base Salary
We recognize that it is necessary to provide executives with a fixed amount of regularly paid compensation that is delivered each month and provides a balance to other pay elements that are at risk. As mentioned above, baseBase salaries are reviewed annually by the Committee based on its median philosophy, internal pay equity considerations and considerations specific to an individual executive considerations such as an executive’s expertise, level of performance achievement, experience in the role and contribution relative to others in the organization.
Base Salary Adjustments for 20162019
The Committee reviewed the base salaries of the Named Executive Officers in early 20162019 and recommended base salary adjustments to the Board. The Board approved the Committee’s recommendation to increase executive salaries assalary recommendations shown in the table below. The adjustments were effective March 1, 2016.2019. Base salaries for 20162019 generally remained at the 50th percentile of market among the comparator group. The annual salary for Ms. Harris is unchanged from 2015, given that her current base salary was slightly higher thanaligns with the 50th percentile of market among the survey peer group.median. The salary increase percentages approved by the Board for the other Named Executive OfficersMr. Doyle and Mr. Secrist were approximately 3%, similar to salary increases for other non-represented employees, except for Mr. Secrist whoand Ms. Mellies received an additional adjustment to better align with the market levels.level. For Ms. Kipp, who joined the Company as President in August 2019, the Committee recommended and the Board approved a base salary consistent with the market level for her position.
| | Name | 2015 Base Salary | 2016 Base Salary | % Change | Name |
| 2018 Base Salary |
| 2019 Base Salary |
| % Change |
Kimberly J. Harris | $900,000 | $900,000 | —% | Kimberly J. Harris |
| $950,000 | |
| $1,000,000 | |
| 5% |
Mary E. Kipp | | Mary E. Kipp | | n/a | | | 860,000 | | | n/a |
Daniel A. Doyle | 496,501 | 511,396 | 3 | Daniel A. Doyle |
| 521,000 | |
| 531,420 | |
| 2 |
Steve R. Secrist | 362,923 | 388,327 | 7 | Steve R. Secrist |
| 445,000 | |
| 462,800 | |
| 4 |
Marla D. Mellies | 299,763 | 308,755 | 3 | Marla D. Mellies |
| 360,000 | |
| 392,400 | |
| 9 |
Philip K. Bussey | 297,583 | 306,510 | 3 | |
20162019 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 achievingincent our employees to achieve desired annual operating results, measured by EBITDA, while also meetingand meet the Company’s service quality commitment to customers, a reliability measure (non-storm outage duration—System Average Interruption Disruption Index-- or “SAIDI”) 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.Target incentive opportunities under the plan are based on a percentage of an employee’s base salary.
For 2016,2019, the Company’s service quality commitment was measured by performance against nineeight Service Quality Indicators (SQIs) covering three broad categories, set forth below. These are the same SQIs for which the Company is accountable to the Washington Commission. Annual incentive funding is decreased if a SQI is not achieved. 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 20162019 were the same as those in 20152018 and were as follows:
•Customer Satisfaction (3 SQIs) - Customer satisfaction with the telephone accesscustomer care center, and natural gas field services and number of Washington Commission complaints.
•Customer Service (2 SQIs) (1 SQI)- Calls answered “live” and on-time appointments.within 60 seconds by customer care center.
Safety and Reliability•Operations Services (4 SQIs)- Gas emergency response, electric emergency response, non-storm outage frequency, and non-storm outage duration.
on-time appointments.
In 2016,2019, the Company retainedbegan measuring SAIDI according to a scale based on improvement compared to a five-year average, with the measure for 2019 being 159 minutes.
The employee safety performance measure in the annual incentive plan funding to promote itsreflects the Company’s continued commitment to employee safety.The safety performance measure contains three targets which must all be satisfied for the safety measure to be treated as met.The three targets for 2019 were:
•All employees attend a monthly safety “meeting in a box” presentation or complete the same content online.The target completion rate is no less than 95%.
•The Company DART (Days Away from Work, days of Restricted Work, or Job Transfer) not to exceed a rate of 0.49
•All employees complete two modules of a PSE Athlete training program.The target completion rate is no less than 95%.
Annual incentive funding is decreased if a SQI is not achieved. The employee safety measure functionsand SAIDI function similarly to the nineeight SQIs in determining the funding of the annual incentive plan. That is, if the safety measure or SAIDI is not achieved, annual incentive funding will be decreased by 10%, in the same way as a missed SQI. The safety performance measure contains four targets which must all be satisfied for the safety measure to be treated as met. The four targets for 2016 were:
All employees attend a monthly safety “meeting in a box” presentation, or complete the same content online. The target completion rate is no less than 95%.
The Company DART (Days Away from Work, days of Restricted Work, or Job Transfer) not to exceed a rate of 0.52 in 2016.
Field employees to attend the Industrial Athlete program, a new training designed to improve mobility and strengthen stability. The target completion rate is no less than 95% of field employees.
Office employees to complete an on-line training to increase knowledge and skill in CPR and First Aid. The target completion rate is no less than 95% of office employees.
In 2016,2019, 100% funding for the annual incentive plan required (i) achievement of 10 out of 10 customer service and safety measures (all nineeight SQIs, SAIDI and achievement of the safety measure) and (ii) target EBITDA performance.All 10 customer service and safety measures were met.
Funding levelsmet for 20162019, but the safety measure was not met, and EBITDA finished at maximum, target, and threshold are shown in the table below: |
| | | | | | |
Annual Incentive Performance Payout Scale and Actual Performance |
Performance | 2016 EBITDA (In Millions) | SQI & Safety* | Funding Level |
Maximum | $ | 1,688.0 |
| 10/10 | 200 | % |
Target | 1,250.0 |
| 10/10 | 100 |
|
Threshold | 1,125.0 |
| 6/10 | 30 |
|
2016 Actual Performance | $ | 1,255.3 |
| 10/10 | 102 | % |
_______________
| |
*
| Combined SQI & Safety results of 6/10 or better and minimum EBITDA of $1,125 million are required for any annual incentive payout funding. SQI/Safety results below 10/10 reduce funding (e.g., 9/10 = 90%, 8/10 = 80%, 7/10 = 70%). |
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. For 2016, the Committee adjusted the level of EBITDA at target lower by $1.1 million to reflect the additional 2016 incentive paid based on 2015 SQI results (see section below “2015 Annual Incentive Review during 2016”) and keep the 2016 EBITDA performance at the same percentage96.4% of target, that would have applied absent the payment. so funding was less than 100%, as described further below.
Individual awards may be adjusted upward or downward based on an evaluation of an executive officer’s performance against individual and team goals that align with the corporate goals described below.
20162019 Corporate Goals
In 2016,2019, the Company continued using the Integrated Strategic Plan (ISP) to summarize for employees the direction and overall goals of the Company. The plan has five objectives which capture our 20162019 corporate goals and which have been
communicated to our employees. Each employee, including the Named Executive Officers, has specific individual and team goals linked to driving strategies that meet one or more of the following ISP objectives:
•Safety - Our Safety Objectivesafety objective is our foundation: If Nobody Gets Hurt Today,nobody gets hurt today, we will feel safe and secure and be able to perform at our best.
•People - When we’re Safe,safe, we can achieve our People Objectivepeople objective of being a Great Placegreat place to Work,work, with engaged employees who live our values, embrace an ownership culture and are motivated to drive results for our company and our customers.
•Process and Tools - Engaged employees take us to our Processprocess and Tools Objectivetools objective where results start with achieving Operational Excellence,operational excellence, with continuous improvement of our internal processes and tools so that we can increase efficiency, eliminate waste, improve reliability and enhance customer service.
•Customer- We now have the fundamentals to achieve our Customer Objectivecustomer objective of delivering greater value and being our Customer’s Energy Partnercustomer’s energy partner of Choicechoice in a competitive marketplace.
•Financial - Being our customer’s energy partner of choice takes us to our Financial Objectivefinancial objective of increasing our Financial Strength,financial strength, allowing us to sustain further improvement.
2015 Annual Incentive Review During 2016
In March 2016, the Company paid annual incentive awards based on 2015 EBITDA performance of $1,222.2 million (98.9% of target performance) and 8/10 Safety/SQI goals met, for an overall funding level of 75.6% of target, as described in the Company’s 2015 Form 10-K. The Company filed for an exception with the Washington Commission for the SQI goal of System Average Interruption Disruption Index (SAIDI), due to extraordinary storm activity during August and November 2015. On May 12, 2016, the Company received approval to exclude the extraordinary storm activity, resulting in the SQI having been deemed met. With 9/10 Safety/SQI goals met in 2015, the funding for annual goals and incentives would have increased to 84.7% of target. In light of the approval from the Washington Commission, the Board approved an additional payment in 2016 based on the impact from the SQI being deemed met. Accordingly, employees who received an annual incentive in 2015 and are eligible to receive an annual incentive in 2016 will be paid this additional amount in March 2017. For the Named Executive Officers, these amounts are included in the “Bonus” column of the 2016 Summary Compensation Table.
20162019 Annual Incentive Plan Results
AchievementFor 2019, achievement of the corporate goals for 2016under the annual incentive plan was at 100.4%96.4% of target for EBITDA, and fully9/10 measures met for SQI, safety, and safetySAIDI achievement. PSE EBITDA was $1,255.3$1,293.2 million, and SQI, SAIDI and safety achievement was 109 out of 10, leading to a funding level for 20162019 of 102%74.0% for the annual incentive plan.plan for the named executive officers.
Funding levels for 2019 at maximum, target, and threshold are shown in the table below:
| | | | | | | | | | | | | | | | | | | | | | | |
Annual Incentive Performance Payout Scale and Actual Performance | | | | | | | |
Performance Measure (Dollars in Millions) | 2019 EBITDA | | |
| SQI, SAIDI& Safety* |
| Funding Level |
Maximum | | $ | 1,810.4 | |
|
| 10/10 |
| 200% |
Target | | | 1,341.0 | |
|
| 10/10 |
| 100 |
Threshold | | | 1,206.9 | |
|
| 6/10 |
| 30 |
2019 Actual Performance | | $ | 1,293.2 | |
|
| 9/10 |
| 74.0% |
_______________
* Combined SQI, SAIDI & Safety results of 6/10 or better and minimum EBITDA of $1,206.9 million are required for any annual incentive pay out funding
SQI Safety results below 10/10 reduce funding (e.g., 9/10=90%, 8/10=80%, 7/10=70%)
For 2016,2019, individual target incentive levels for the annual incentive plan varied by executive officer as a percentage of 20162019 base salary as shown in the table below, based on the executive’s level of responsibility within the Company and informed by market data. Target annual incentive opportunities as a percentage of base salary for the Named Executive Officers remainedwere unchanged from 2015 levels.2018 levels, except for Ms. Kipp who joined the Company in 2019 and whose target annual incentive opportunity was set at 90% of base salary. No bonus is earned unless at least threshold EBITDA and SQI goals are achieved. The achievement of threshold performance results in a 30% of target bonus payout. The maximum incentive payable for exceptional performance in this plan is twice thetwo times each Named Executive Officer's target incentive.
An executive’s individual award amount can be increased or decreased based on an 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, adjustments were made by the CEO for individual performance of certain Named Executive Officers below CEO in 2016. In recognition of the achievement of individual goals and the Company's financial performance, the Committee similarly recommended an award adjustment for the CEO in 2016.2019. The adjustments for individual performance are noted in the "Bonus" column on the Summary Compensation table and did not materially change the amounts resulting from 20162019 achievement of the corporate goals. The Board approved the incentive amounts shown below, which will be paid in March 2017:2020:
| | Name | Target Incentive (% of Base Salary) | 2016 Actual Incentive Paid | 2016 Actual Incentive (% of Base Salary) | Name |
| Target Incentive (% of Base Salary) |
| | 2019 Actual Incentive Paid | |
| 2019 Actual Incentive (% of Base Salary) | |
Kimberly J. Harris | 100% | $ | 1,101,600 |
| 122 | % | Kimberly J. Harris |
| 100% |
|
| | | $ | 740,000 | |
|
| | 74% | | |
Mary E. Kipp | | Mary E. Kipp | | 90* | | 190,920 | | | 67* | |
Daniel A. Doyle | 45 | 234,731 |
| 46 |
| Daniel A. Doyle | 65 | |
| | | 255,613 | |
|
| 48 |
|
Steve R. Secrist | 45 | 213,891 |
| 55 |
| Steve R. Secrist | 65 | |
| | | 222,607 | |
|
| 48 |
|
Marla D. Mellies | 45 | 148,804 |
| 48 |
| Marla D. Mellies | 65 | |
| | | 226,493 | |
|
| 58 |
|
Philip K. Bussey | 45 | 140,688 |
| 46 |
| |
_____________
* Target incentive of 90% of base salary, prorated and payable based on 4 months of service in 2019; actual % of base shown as annual value.
Long-Term Incentive Compensation
Long-term incentive compensation opportunities are designed to bealign the interests of executives with those of our investors, provide competitive with market practices,pay opportunities, support a customer-focused utility, reward long-term performance and promote retention. Long-term incentive plan (LTI Plan) awards are denominated in units and are settled in cash if at least threshold performance measures are met. Performance measures arehave typically been based on two financial goals, total return (Total Return)each weighted equally and ROE, each measured over a three-year performance cycle. cycle:
•Total return (Total Return) and
•ROE
The 2019-2021 grant cycle was focused exclusively on the ROE metric, as described below. Total Return reflects the change in the value of the Company during the performance cycle plus any distributions made to investors. ROE reflects the income earned on our equity investment. Achievement of each performance measure during the performance cycle is evaluated independently of the other.
The Committee recommends for Board approval a targeted LTI grant value for each executive, which is expressed as a percentage of base salary. The recommended and targeted LTI grant value is determined by evaluating LTI grant values provided to similarly situated executives at comparable companies (using the previously discussed survey and peer group data) as well as other relevant executive-specific factors. The Company generally does not consider previously granted awards or the level of accrued value from prior or other programs when making new LTI Plan grants.
The target LTI grant value is then converted into a target number of units, allocated equally among the two financial goals, based on the unit value on the grant date. The initial per-unit value is measured at the Puget Holdings level and is calculated annually by an independent auditing firm.firm or based on market transactions. The number of units ultimately earned may range from 0% to 200% of target depending on performance, with the payout being made in cash based on the number of units earned and the per-unit value at the end of the performance period. Executives generally must be employed on the payment date to receive a cash payment under the LTI Plan, except in the event of retirement, disability or death.
The Committee recommends for Board approval the number of LTI Plan units granted to each executive by evaluating long-term incentive grant values provided to similarly situated executives at comparable companies (using the previously discussed survey and peer group data) as well as other relevant executive-specific factors. The Committee generally does not consider previously granted awards or the level of accrued value from prior or other programs when making new LTI Plan grants.
Half of the target units are earned based on Total Return and the other half are earned based on ROE, each over a 3-year performance period. These metrics and weightings have remained unchanged since the 2012 - 2014 grant cycle.
2016-20182019-2021 Long-Term Incentive Plan Target Awards and Performance Goals
Consistent with prior years, target LTI Plan awards for the 2016-20182019-2021 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 and the corresponding market data. For Ms. Kipp, a target LTI Plan level of 220% of base salary for the 2019-2021 performance cycle was approved by the Board to provide immediate alignment with PSE and other executives. Target LTI Plan award amounts for the 2016-20182019-2021 performance cycle were 220% of base salary for Ms. Harris and 95% for Mr. Doyle, Mr. Secrist, Ms. Mellies and Mr. Bussey, whichare shown in the following table.
| | | | | | | | |
Name |
| Target Long Term Incentive (% of Base Salary) |
Kimberly J. Harris |
| 265% |
Mary E. Kipp | | 220 |
Daniel A. Doyle |
| 95 |
Steve R. Secrist |
| 95 |
Marla D. Mellies |
| 95 |
These percentages were unchanged from amounts established for the 2015-20172018-2020 performance cycle, except forwith the exception of Ms. Harris. The Board approved an increaseKipp who joined the Company in Ms. Harris’ target award from 200% to 220% to provide a target level of award that was market competitive.2019. The total number of target LTI Plan units granted to a Named Executive Officer for the 2016-20182019-2021 performance cycle is equal to the applicable percentage of salary
(converted (converted to dollars) divided by the per unit value at the beginning of the performance cycle, including for Ms. Kipp, which was $48.05.$81.86. Details of the number of units granted and expected values at target, threshold and maximum performance levels can be found in the “2016“2019 Grants of Plan-Based Awards” table below. Effective with the 2015-2017Prior outstanding LTI Plan grants, the Board approved a change in the calculation of performance results. Under this change, actual performance is measured as a percentage of target performance and plan funding is based on the modified payout scales shown below. Target Total Return is set annually by the Board prior to the grant date, and was set at 9.7% for the 2016-2018 performance cycle. Target ROE remains based on the ROE target in the Board’s approved budget for each year. Prior outstanding LTIP grants continue to have the performance targets and payout scales in effect at the time of grant.
The table below showsIn connection with Mr. Kipp’s appointment as President in 2019 and anticipated appointment as CEO in 2020, in July 2019, the percentageBoard, upon the recommendation of LTI Planthe Committee, also approved Ms. Kipp’s participation in the 2017-2019 performance cycle at a target awards underamount of 110% of 2019 base salary and in the Total Return component2018-2020 performance cycle at a target amount of 165% of 2019 base salary. Ms. Kipp’s target amounts reflected her reduced participation in these performance cycles that could be earned based on three-yearbegan prior to her commencement of employment and are intended to incentivize performance during the 2016-2018in such performance cycle. Payout percentages will be linearly interpolated if performance falls between the values shown below:cycles following commencement of employment
|
| |
Annualized Three-Year Total Return Compared to Target | Plan Funding for Total Return (% of Target Units) |
117.5% of Target or More | 200.0% |
115% of Target | 185.5 |
110% of Target | 157.0 |
105% of Target | 128.5 |
100% of Total Return Target | 100.0 |
95% of Target | 92.9 |
90% of Target | 85.7 |
85% of Target | 78.6 |
82.5% of Target | 75.0 |
80% of Target | 56.7 |
75% of Target | 20.0 |
<75% of Target | — |
The table below shows the percentage of LTI Plan target awards under the ROE component that could be earned based on average performance during the three-year performance period. Payout percentages will be interpolated if performance falls between the values shown below:
|
| |
ROE Compared to Target | Plan Funding |
117.5% of Target or More | 200.0% |
115% of Target | 185.5 |
110% of Target | 157.0 |
105% of Target | 128.5 |
Target ROE | 100.0 |
95% of Target | 84.0 |
90% of Target | 68.0 |
85% of Target | 52.0 |
80% of Target | 36.0 |
75% of Target | 20.0 |
<75% of Target | — |
Performance Scales for the 2015-2017 LTI Plan Grant
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 during the 2015-2017 performance cycle. Payout percentages will be linearly interpolated if performance falls between the values shown below:
|
| |
Annualized Three-Year Total Return Compared to Target | Plan Funding for Total Return (% of Target Units) |
117.5% of Target or More | 200.0% |
115% of Target | 185.5 |
110% of Target | 157.0 |
105% of Target | 128.5 |
100% of Total Return Target | 100.0 |
95% of Target | 89.6 |
90% of Target | 79.2 |
88% of Target | 75.0 |
85% of Target | 62.3 |
80% of Target | 41.2 |
75% of Target | 20.0 |
<75% of Target | — |
The table below shows the percentage of LTI Plan target awards under the ROE component that could be earned based on average performance during the three-year performance period. Payout percentages will be interpolated if performance falls between the values shown below:
|
| |
ROE Compared to Target | Plan Funding |
117.5% of Target or More | 200.0% |
115% of Target | 185.5 |
110% of Target | 157.0 |
105% of Target | 128.5 |
Target ROE | 100.0 |
95% of Target | 84.0 |
90% of Target | 68.0 |
85% of Target | 52.0 |
80% of Target | 36.0 |
75% of Target | 20.0 |
<75% of Target | — |
Performance Scales for the 2014-2016 LTI Plan Grant
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 during the 2014-2016 performance cycle. Payout percentages will be linearly interpolated if performance falls between the values shown below:
|
| |
Annualized Three-Year Total Return | Plan Funding for Total Return (% of Target Units) |
15% or more | 200.0% |
14% | 180.0 |
13% | 160.0 |
12% | 140.0 |
11% | 120.0 |
10% | 100.0 |
9% | 80.0 |
8% | 60.0 |
7% | 40.0 |
6% | 20.0 |
<6% | — |
The table below shows the percentage of LTI Plan target awards under the ROE component that could be earned based on average performance during the three-year 2014-2016 performance period. Payout percentages will be interpolated if performance falls between the values shown below:
|
| |
ROE Compared to Target | Plan Funding for ROE (% of Target Units) |
Target + 250 bps | 200.0% |
Target + 200 bps | 180.0 |
Target + 150 bps | 160.0 |
Target + 100 bps | 140.0 |
Target + 50 bps | 120.0 |
Target ROE | 100.0 |
Target - 50 bps | 80.0 |
Target - 100 bps | 60.0 |
Target - 150 bps | 40.0 |
Target - 200 bps | 20.0 |
<Target - 200 bps | — |
Long-Term Incentive Plan Performance 2014-20162017-2019 Performance Cycle Results and Payouts
The 2014-20162017-2019 performance cycle has now ended. Amounts payable as a result of award vesting are shown in the following table:
•Performance on Total Return in 2019 was -1.2%, which was significantly lower than Total Return growth in 2018.
•Performance on the Total Return component for the three-year performance cycle was a compounded annual rate of 8.28%19.9%, belowabove target and at the target but abovemaximum of the threshold needed for payment.funding scale. The Total Return Component funded at 65.6%200% of target units.
•Performance on the ROE component of the grant was an average of target plus 23 basis points for funding110.7% of target. The ROE component funded at 109.2%160.7% of target units.
| | Name | Target Incentive (% of Base Salary)1 | Total Return Component Units Granted/Paid | ROE Component Units Granted/Paid | 2014-2016 Actual LTIP Paid2 | Name |
| Target Incentive (% of Base Salary)1 |
| Total Return Component Units Granted/Paid |
| ROE Component Units Granted/Paid | 2017-2019 Actual LTIP Paid2 | |
Kimberly J. Harris | 170% | 18,545.5/12,165.8 | 18,545.5/20,251.7 | $ | 1,697,706 |
| Kimberly J. Harris |
| 200% |
| 22,770.5/45,541 |
| 22,770.5/36,592.2 | | $ | 6,642,111 | |
Mary E. Kipp | | Mary E. Kipp | | 110 | | 5,778.2/11,556.3 | | 5,778.2/9,285.5 | | 1,685,478 | |
Daniel A. Doyle | 95% | 5,551/3,641.5 | 5,551/6,061.7 | 508,154 |
| Daniel A. Doyle |
| 95 |
| 4,638.5/9,277 |
| 4,638.5/7,454.1 | | 1,353,042 | |
Steve R. Secrist | 95% | 4,057.5/2,661.7 | 4,057.5/4,430.8 | 371,435 |
| Steve R. Secrist |
| 95 |
| 3,663.0/7,326 |
| 3,663.0/5,886.4 | | 1,068,490 | |
Marla D. Mellies | 95% | 3,335/2,187.8 | 3,335/3,641.8 | 305,295 |
| Marla D. Mellies |
| 95 |
| 2,884.5/5,769 |
| 2,884.5/4,635.4 | | 841,403 | |
Philip K. Bussey | 95% | 3,359.5/2,203.8 | 3,359.5/3,668.6 | 307,538 |
| |
______________
| |
1
| 1Target LTI Plan incentive is a percentage of 2017 base salary when the grants were made in 2017 with a percentage of 2014 base salary when the grants were made in 2014. |
| |
2
| 2014-2016 actual LTI Plan amount payable is equal to the unit price of $52.37, except that Ms. Kipp’s target is a percentage of 2019 base salary equal to 50% of target LTI % of 220% with a per unit price of $81.86.22017-2019 actual LTI Plan amount payable is equal to the unit price of $80.87 multiplied by earned Total Return and ROE component units. |
Long-Term Incentive Plan Performance for Outstanding Cycles
The table below summarizes the status of the two other outstanding performance cycles from the initial grant date to December 31, 2016, with the projected payout assuming this same performance for the full three-year cycle under the applicable payout scales for Total Return and ROE:ROE component units.
|
| | | | | | |
Performance Cycle | Cycle Progress | Total Return Performance | Payout (% of Target) | ROE Performance | Payout (% of Target) | Total Projected Payout (based on performance as of 12/31/2016) |
2015- 2017 | 67% Complete | 8.4% | 67% | 100% | 99% | 82.8% |
2016 - 2018 | 33% Complete | 8.7% | 85% | 101% | 103% | 94.3% |
Retirement Plans - SERP–– Executive Retirement Plans and Retirement Plan
The Company maintains the SERPexecutive retirement plans 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,executive retirement plans, these executives would receive lower percentages of replacement income during retirement than other employees. All the Named Executive Officers participate in executive retirement plans—Ms. Harris, Mr. Doyle, Mr. Secrist and Ms. Mellies in the SERP.SERP and Ms. Kipp in the Officer Restoration Benefit, as part of the Deferred Compensation Plan for Key Employees. Additional information regarding the SERP, Officer Restoration Benefit and the Retirement Plan is shown in the “2016“2019 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 “2016“2019 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 byat the Company)time, including Ms. Harris and Mr. Secrist (who was not then an officer).Ms. Mellies. The Executive Employment Agreements provide for an employment period of two years following a change in control and provide severance benefits in the event of a qualifying termination of employment within two years of a change in control. Since 2009, the Company has ceased entering into these agreements with new executive officers. Mr. Bussey was an officer of PSE at March 30, 2009, but left PSEofficers and, during 2019 only the agreements for Ms. Harris and Ms. Mellies remained in May 2009 and upon his rehire in March 2012 does not have an employmenteffect. The agreement with the Company.Ms. Harris terminated upon her retirement on January 2, 2020.
The Committee periodically reviews existing change in control and severance arrangements for the peer group companies. 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, 2016.2019.
Other Compensation
In addition to base salary and annual and long-term incentive award opportunities, theThe Company also provides the Named Executive Officers with benefits and limited perquisites. 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. In connection with Ms. Kipp’s commencement of employment, she received a hiring bonus in the amount of $800,000. Ms. Kipp is required to reimburse the Company for this bonus if she resigns or terminates for cause (as defined in her employment offer letter) within twelve months of payment. Ms. Kipp is also eligible to receive an additional bonus of $1,500,000 in the event the previously announced acquisition of El Paso by the Infrastructure Investments Fund, an investment vehicle advised by J.P. Morgan Incentive Management Inc. is completed in 2020.
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 and legal services and business club memberships 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 personal 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 2016.2019. Executives are taxed on the value of the perquisites received, with no corresponding gross-up by the Company.
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 opportunities for both annual and long-term incentives, because each plan operates with a target 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 Tax and Accounting Treatment of Compensation
The accounting treatment of compensation generally has not been a significant 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. As a result of changes in federal tax law effective in 2018, the Company is now subject to IRS section 162(m). Section 162(m) limits the tax deductibility of compensation paid to certain executive officers, including the Named Executive Officers, to $1 million per year. Notwithstanding the new tax law, the Company does not expect to make changes in its executive compensation program designs.
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 the 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 2016,2019, 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, 20162019, for filing with the SEC.
Compensation and Leadership
Development Committee of
Puget Energy, Inc.
Puget Sound Energy, Inc.
Steven Zucchet, chair, joined Committee May 1, 2019
Christopher Trumpy, ChairScott Armstrong
Christopher Leslie
Etienne Middleton (served beginning May 5, 2016)Barbara Gordon
Mary McWilliams
Christopher Trumpy
Martijn Verwoest, joined Committee May 1, 2019
Summary Compensation Table
The following information is provided for the year ended December 31, 20162019, (and for prior years where applicable) with respect to the Named Executive Officers during 2016.2019. The positions listed below are at Puget Energy and PSE, except that Ms. Mellies and Mr. Bussey are executivesis an executive of PSE only. Positions listed are those held by the Named Executive Officers as of December 31, 2016.2019. Salary and incentive compensation includes amounts deferred at the executive’s election.
| | Name and Principal Position | Year | Salary | Bonus1 | Stock Awards | Option Awards | Non-Equity Incentive Plan Compensation2 | Change in Pension Value and Nonqualified Deferred Compensation Earnings3 | All Other Compensation4 | Total | Name and Principal Position | Year | Salary | Bonus1 | Stock Awards | Option Awards | Non-Equity Incentive Plan Compensation2 | Change in Pension Value and Nonqualified Deferred Compensation3 | All Other Compensation4 | Total |
Kimberly J. Harris | 2016 | $ | 900,000 |
| $ | 269,595 |
| $ | — |
| $ | — |
| $ | 2,615,706 |
| $ | 650,281 |
| $ | 20,338 |
| $ | 4,455,920 |
| Kimberly J. Harris | 2019 | $ | 989,799 | | $ | — | | $ | — | | $ | — | | $ | 7,382,111 | | $ | 3,373,594 | | $ | 28,864 | | $ | 11,774,368 | |
President and Chief | 2015 | 900,000 |
| — |
| — |
| — |
| 2,245,875 |
| 157,077 |
| 25,032 |
| 3,327,984 |
| President and Chief | 2018 | 939,823 | | 45,220 | | — | 6,593,310 | | 445,343 | | 20,888 | | 8,044,584 | |
Executive Officer5 | 2014 | 897,763 |
| — |
| — |
| — |
| 2,271,584 |
| 2,333,346 |
| 27,128 |
| 5,529,821 |
| Executive Officer5 | 2017 | 900,001 | | 50,940 | | — | 5,293,105 | | 1,523,783 | | 20,338 | | 7,788,167 | |
Mary E. Kipp, President6 | | Mary E. Kipp, President6 | 2019 | 252,540 | | — | | — | 1,876,398 | | — | | 813,893 | | 2,942,831 | |
Daniel A. Doyle | 2016 | $ | 508,322 |
| $ | 18,299 |
| | $ | 742,885 |
| $ | 370,670 |
| $ | 49,836 |
| $ | 1,690,012 |
| Daniel A. Doyle | 2019 | 521,399 | | — | | — | 1,608,655 | | 964,614 | | 63,555 | | 3,158,223 | |
Senior Vice President | 2015 | 493,488 |
| — |
| — |
| — |
| 609,770 |
| 360,012 |
| 51,487 |
| 1,514,757 |
| Senior Vice President | 2018 | 519,039 | | — | | — | 1,718,288 | | 489,180 | | 60,657 | | 2,787,164 | |
and Chief Financial Officer6 | 2014 | 479,115 |
| — |
| — |
| — |
| 637,579 |
| 336,575 |
| 47,822 |
| 1,501,091 |
| |
Chief Financial Officer7 | | Chief Financial Officer7 | 2017 | 511,396 | | — | | — | 1,406,575 | | 483,109 | | 56,801 | | 2,457,881 | |
Steve R. Secrist | 2016 | $ | 383,085 |
| $ | 50,510 |
| $ | — |
| $ | — |
| $ | 549,678 |
| $ | 268,972 |
| $ | 41,344 |
| $ | 1,293,589 |
| Steve R. Secrist | 2019 | 459,165 | | — | | — | 1,291,097 | | 786,634 | | 53,517 | | 2,590,413 | |
Senior Vice President, | 2015 | 360,721 |
| — |
| — |
| — |
| 297,862 |
| 95,399 |
| 23,861 |
| 777,843 |
| |
General Counsel, Chief Ethics & Compliance Officer7 | 2014 | 349,529 |
| 7,485 |
| — |
| — |
| 310,104 |
| 621,610 |
| 21,225 |
| 1,309,953 |
| |
Senior Vice President | | Senior Vice President | 2018 | 436,600 | | — | | — | 1,335,367 | | 273,059 | | 46,850 | | 2,091,876 | |
General Counsel, Chief Ethics & Compliance Officer8 | | General Counsel, Chief Ethics & Compliance Officer8 | 2017 | 400,690 | | — | | — | 1,024,487 | | 576,802 | | 46,033 | | 2,048,012 | |
Marla D. Mellies | 2016 | $ | 306,901 |
| $ | 20,588 |
| $ | — |
| $ | — |
| $ | 447,014 |
| $ | 279,975 |
| $ | 30,414 |
| $ | 1,084,892 |
| Marla D. Mellies | 2019 | 382,671 | | 37,749 | | — | 1,030,148 | | 866,607 | | 44,728 | | 2,361,903 | |
Senior Vice President, | 2015 | 297,651 |
| — |
| — |
| — |
| 387,201 |
| 143,686 |
| 30,941 |
| 859,479 |
| |
Chief Administrative Officer8 | 2014 | 287,868 |
| 12,367 |
| — |
| — |
| 385,549 |
| 388,950 |
| 30,126 |
| 1,104,860 |
| |
Philip K. Bussey | 2016 | $ | 304,668 |
| $ | 12,186 |
| $ | — |
| $ | — |
| $ | 448,226 |
| $ | 305,837 |
| $ | 25,503 |
| $ | 1,096,420 |
| |
Senior Vice President, Chief Customer Officer9 | 2015 | 296,367 |
| — |
| — |
| — |
| 378,286 |
| 408,937 |
| 23,792 |
| 1,107,382 |
| |
Senior Vice President | | Senior Vice President | 2018 | 351,428 | | 33,415 | — | 1,065,467 | | 378,398 | | 38,778 | | 1,867,486 | |
Chief Administrative Officer9 | | Chief Administrative Officer9 | 2017 | 316,128 | | — | | — | 838,219 | | 478,905 | | 34,531 | | 1,667,783 | |
_______________
| |
1
| For 2016, reflects additional incentive paid based on review of 2015 results for SQIs as described in the "Compensation Discussion and Analysis," section titled "2015 Annual Incentive Review During 2016" in the amount of: Ms. Harris, $85,995; Mr. Doyle, $18,299; Mr. Secrist, $14,862; Ms. Mellies, $13,503; Mr. Bussey, $12,186 and includes adjustments to reflect individual performance above target as described in the "Compensation Discussion and Analysis," section titled "2016 Annual Incentive Plan Results" in the amount of: Ms. Harris, $183,600; Mr. Secrist, $35,648; Ms. Mellies, $7,085. |
| |
2
| For 2016, reflects annual cash incentive compensation paid under the 2016 Goals and Incentive Plan and cash incentive compensation paid under the LTI Plan for the 2014-2016 performance cycle. Cash incentive amounts were paid in early 2017 or deferred at the executive's election. The 2016 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 2017. |
| |
3
| Reflects the aggregate increase in the actuarial present value of the executive’s accumulated benefit under all pension plans during the year. The amounts are determined using interest rate and mortality rate assumptions consistent with those used in the Company’s financial statements and include amounts which the executive may not currently be entitled to receive because such amounts are not vested. In 2016, updated interest rate assumptions have increased the actuarial value of the underlying retirement benefits relative to assumptions for 2015. Information regarding these pension plans is set forth in further detail under “2016 Pension Benefits.” The change in pension value amounts for 2016 are: Ms. Harris, $646,248; Mr. Doyle, $370,670; Mr. Secrist, $268,972, Ms. Mellies, $279,410; and Mr. Bussey, $305,837. Also included in this column are the portions of Deferred Compensation Plan earnings that are considered above market. These amounts for 2016 are: Ms. Harris, $4,033; Mr. Doyle, $0; Mr. Secrist, $0; Ms. Mellies, $565; and Mr. Bussey, $0. See the “2016 Nonqualified Deferred Compensation” table for all Deferred Compensation Plan earnings. |
| |
4
| All Other Compensation for 2016 is shown in detail in the table below. |
| |
5
| Ms. Harris was promoted to President and CEO from President on March 1, 2011. |
| |
6
| Mr. Doyle joined PSE and Puget Energy as Senior Vice President and Chief Financial Officer on November 28, 2011. |
| |
7
| Mr. Secrist has worked at PSE since May 1989. |
| |
8
| Ms. Mellies has worked at PSE since October 2005. |
| |
9
| Mr. Bussey rejoined PSE as Senior Vice President and Chief Customer Officer on March 19, 2012. |
1.For 2019, reflects individual performance above target as described in the "Compensation Discussion and Analysis," section titled "2019 Annual Incentive Plan Results" in the amount of: $37,749 for Ms. Mellies.
2.For 2019, reflects annual cash incentive compensation paid under the 2019 Goals and Incentive Plan and cash incentive compensation paid under the LTI Plan for the 2017-2019 performance cycle. Cash incentive amounts were paid in early 2020 or deferred at the executive's election. The 2019 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 2020.
3.Reflects the aggregate increase in the actuarial present value of the executive’s accumulated benefit under all pension plans during the year. The amounts are determined using interest rate and mortality rate assumptions consistent with those used in the Company’s financial statements and include amounts which the executive may not currently be entitled to receive because such amounts are not vested. In 2019, updated interest rates relative to those used for 2018 have generally resulted in larger increases in value than in prior years. Information regarding these pension plans is set forth in further detail under “2019 Pension Benefits.” The change in pension value amounts for 2019 are: Ms. Harris, $3,371,078; Ms. Kipp, $0; Mr. Doyle, $964,614; Mr. Secrist, $786,634, and Ms. Mellies, $866,255. Also included in this column are the portions of Deferred Compensation Plan earnings that are considered above market. These amounts for 2019 are: Ms. Harris, $2,516, Ms. Kipp, $0, Mr. Doyle, $0; Mr. Secrist, $0; and Ms. Mellies, $352. See the “2019 Nonqualified Deferred Compensation” table for all Deferred Compensation Plan earnings.
4.All Other Compensation for 2019 is shown in detail in the table below.
5.Ms. Harris was promoted to President and CEO from President on March 1, 2011, became CEO effective August 31, 2019, and retired on January 3, 2020.
6.Ms. Kipp joined PSE and Puget Energy as President on August 31, 2019, and became President and CEO on January 3, 2020, with the retirement of Ms. Harris.
7.Mr. Doyle joined PSE and Puget Energy as Senior Vice President and Chief Financial Officer on November 28, 2011.
8.Mr. Secrist has worked at PSE since May 1989.
9.Ms. Mellies has worked at PSE since October 2005.
Detail of All Other Compensation
| | Name | Perquisites and Other Personal Benefits1 | Registrant Contributions to Defined Contribution and Deferred Compensation Plans2 | Other3 | Name |
| Perquisites and Other Personal Benefits1 | |
| Registrant Contributions to Defined Contribution and Deferred Compensation Plans2 | |
| Other3 | |
Kimberly J. Harris | $ | — |
| $ | 14,650 |
| $ | 5,688 |
| Kimberly J. Harris |
| | $ | 5,000 | |
|
| | $ | 15,416 | |
|
| | $ | 8,448 | |
|
Mary E. Kipp | | Mary E. Kipp | | 5,000 | | 6,773 | | 802,121 | |
Daniel A. Doyle | 2,500 |
| 41,563 |
| 5,773 |
| Daniel A. Doyle |
| | 2,500 |
|
| | 53,851 |
|
| | 7,204 | |
Steve R. Secrist | 3,502 |
| 33,043 |
| 4,799 |
| Steve R. Secrist |
| | 1,370 |
|
| | 46,822 |
|
| | 5,325 | |
Marla D. Mellies | 1,050 |
| 26,269 |
| 3,095 |
| Marla D. Mellies |
| | 493 |
|
| | 39,097 |
|
| | 5,138 | |
Philip K. Bussey | 475 |
| 18,550 |
| 6,478 |
| |
_______________
| |
1
| Reimbursement for financial planning, tax planning, and/or legal planning, with the initial plan up to a maximum of $5,000, and then annual reimbursement up to a maximum of $5,000 for Ms. Harris and $2,500 for the other Named Executive Officers. |
| |
2
| Includes Company contributions during 2016 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, $14,650; Mr. Doyle, $18,550; Mr. Secrist $16,344 ; Ms. Mellies, $18,550; and Mr. Bussey, $18,550 Company contributions to the Deferred Compensation Plan are as follows: Ms. Harris, $0; Mr. Doyle, $23,013; Mr. Secrist, $16,699; Ms. Mellies, $7,719; and Mr. Bussey, $0. |
| |
3
| Reflects the value of imputed income for life insurance and Company paid premiums on supplemental disability insurance. |
1.Reimbursement for financial planning, tax planning, and/or legal planning, with the initial plan up to a maximum of $5,000, and then annual reimbursement up to a maximum of $5,000 for Ms. Harris and Ms. Kipp and $2,500 for the other Named Executive Officers.
20162.Includes Company contributions during 2019 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, $15,416; Ms. Kipp, $6,773; Mr. Doyle, $19,550; Mr. Secrist $19,550; and Ms. Mellies, $19,550. Company contributions to the Deferred Compensation Plan are as follows: Ms. Harris, $0; Ms. Kipp, $0; Mr. Doyle, $34,301; Mr. Secrist, $27,272; and Ms. Mellies, $19,547.
3.Reflects the value of imputed income for life insurance and Company paid premiums on supplemental disability insurance for all Named Executive Officers. For Ms. Kipp also includes a signing bonus of $800,000 as described in the Compensation Discussion and Analysis, “Other Compensation.”
2019 Grants of Plan-Based Awards
The following table presents information regarding 20162019 grants of non-equity annual incentive awards and LTI Plan awards, including, as applicable, the range of potential payouts for the awards.
| | | | | | Estimated Future Payouts under Non-Equity Incentive Plan Awards |
| Estimated Future Payouts under Non-Equity Incentive Plan Awards | |
Name | | Grant Date | | Number Of Units Granted | | Threshold | | Target | | Maximum |
Name |
| Grant Date |
| Number Of Units Granted | |
| Threshold |
| Target |
| Maximum |
Kimberly J. Harris | | | | | | | | | | | Kimberly J. Harris |
|
|
|
| |
| |
| |
| |
Annual Incentive1 | | 1/1/2016 | | | | $ | 270,000 |
| | $ | 900,000 |
| | $ | 1,800,000 |
| Annual Incentive1 |
| 1/1/2019 |
| |
| $ | 300,000 | |
| $ | 1,000,000 | |
| $ | 2,000,000 | |
LTI Plan 2016-20182 | | 2/26/2016 | | 41,207 |
| | 488,880 |
| | 2,613,760 |
| | 5.473,938 |
| |
LTI Plan 2019-20212 | | LTI Plan 2019-20212 |
| 2/21/2019 |
| 32,372 | |
| 640,189 | |
| 3,200,943 | |
| 6,401,887 | |
Mary E. Kipp | | Mary E. Kipp |
|
|
|
| |
| |
| |
| |
Annual Incentive1 | | Annual Incentive1 | | 8/31/2019 | | $ | 77,400 | | | $ | 258,000 | | | $ | 516,000 | |
LTI Plan 2019-20213 | | LTI Plan 2019-20213 | | 23,113 | | 457,075 | | | 2,285,377 | | | 4,570,754 | |
LTI Plan 2018-20203 | | LTI Plan 2018-20203 |
| |
| 17,334 | |
| 321,893 | |
| 1,609,465 | |
| 3,218,930 | |
LTIP Plan 2017-20193 | | LTIP Plan 2017-20193 |
| | | 11,556 |
|
| 201,498 | |
| 1,007,490 | |
| 2,014,981 | |
Daniel A. Doyle | | | | | | | | | | | Daniel A. Doyle |
|
|
|
| |
| |
| |
| |
Annual Incentive1 | | 1/1/2016 | | | | $ | 69,038 |
| | $ | 230,128 |
| | $ | 460,256 |
| Annual Incentive1 |
| 1/1/2019 |
| |
| $ | 103,627 | |
| $ | 345,423 | |
| $ | 690,846 | |
LTI Plan 2016-20182 | | 2/26/2016 | | 10,111 |
| | 119,957 |
| | 641,341 |
| | 1,343,145 |
| |
LTI Plan 2019-20212 | | LTI Plan 2019-20212 |
| 2/21/2019 |
| 6,167 |
|
| 121,959 | |
| 609,793 | |
| 1,219,586 | |
Steve R. Secrist | | | | | | | | | | | Steve R. Secrist |
|
|
|
| |
| |
| |
| |
Annual Incentive1 | | 1/1/2016 | | | | $ | 52,424 |
| | $ | 174,748 |
| | $ | 349,495 |
| Annual Incentive1 |
| 1/1/2019 |
|
| |
| $ | 90,246 | | | $ | 300,820 | |
| $ | 601,640 | |
LTI Plan 2016-20182 | | 2/26/2016 | | 7,678 |
| | 91,092 |
| | 487,016 |
| | 1,019,946 |
| |
LTI Plan 2019-20212 | | LTI Plan 2019-20212 |
| 2/21/2019 |
| 5,371 |
|
| 106,217 | |
| 531,084 | |
| 1,062,169 | |
Marla D. Mellies | | | | | | | | | | | Marla D. Mellies |
|
|
|
| |
| |
| |
| |
Annual Incentive1 | | 1/1/2016 | | | | $ | 41,682 |
| | $ | 138,940 |
| | $ | 277,880 |
| Annual Incentive1 |
| 1/1/2019 |
|
| |
| $ | 76,518 | |
| $ | 255,060 | | | $ | 510,120 | |
LTI Plan 2016-20182 | | 2/26/2016 | | 6,104 |
| | 72,418 |
| | 387,177 |
| | 810,855 |
| |
Philip K. Bussey | | | | | | | | | | | |
Annual Incentive1 | | 1/1/2016 | | | | $ | 41,379 |
| | $ | 137,930 |
| | $ | 275,859 |
| |
LTI Plan 2016-20182 | | 2/26/2016 | | 6,060 |
| | 71,896 |
| | 384,386 |
| | 805,010 |
| |
LTI Plan 2019-20212 | | LTI Plan 2019-20212 |
| 2/21/2019 |
| 4,554 |
|
| 90,060 | |
| 450,300 | |
| 900,599 | |
_______________
| |
1
| As described in the “Compensation Discussion and Analysis,” the 2016 Goals and Incentive Plan had dual funding triggers in 2016 of $1,125 million EBITDA and SQI performance of 6/10. Payment would be $0 if either trigger is not met. The threshold estimate assumes $1,126 million EBITDA and SQI/Safety measure performance at 6/10. The target estimate assumes $1,250 million EBITDA and SQI/Safety measure performance at 10/10. The maximum estimate assumes $1,688 million EBITDA or higher and SQI/Safety measure performance at 10/10. |
| |
2
| As described in the “Compensation Discussion and Analysis,” LTI Plan grants for the 2016-2018 performance cycle were equally allocated between a Total Return component and an ROE component. Payments are calculated based on Total Return at Puget Holdings during the three-year performance cycle, the average three-year performance of ROE and the unit value at the end of the performance cycle. |
1.As described in the “Compensation Discussion and Analysis,” the 2019 Goals and Incentive Plan had dual funding triggers in 2019 of $1,206.9 million EBITDA and SQI performance of 6/10. Payment would be $0 if either trigger is not met. The threshold estimate assumes $1,206.9 million EBITDA and SQI/Safety measure performance at 6/10. The target estimate assumes $1,341 million EBITDA and SQI/Safety measure performance at 10/10. The maximum estimate assumes $1,810.4 million EBITDA or higher and SQI/Safety measure performance at 10/10.
2.As described in the “Compensation Discussion and Analysis,” LTI Plan grants for the 2019-2021 performance cycle were allocated 100% to the ROE component. Payments are calculated based on the average three-year performance of ROE and a unit value at the end of the performance cycle equal to $98.88, representing an increase in Total Return of 6.5% per year.
3.Upon her hire on August 31, 2019, Ms. Kipp received LTIP grants of the units shown for the 2019-2021, 2018-2020, and 2017-2019 LTIP cycles.
2016
2019 Pension Benefits
The Company and its affiliates maintain two pension plans: the Retirement Plan and the SERP.SERP, in addition to an Officer Restoration Benefit as part of the Deferred Compensation Plan. 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.
| | Name | Plan Name | Number of Years Credited Service | Present Value of Accumulated Benefit 1,2 | Payments During Last Fiscal Year |
Name |
|
Plan Name |
|
Number of Years Credited Service | |
| Present Value of Accumulated Benefit 1,2, 3 | |
| Payments During Last Fiscal Year | |
Kimberly J. Harris | Retirement Plan | 17.7 |
| $ | 387,166 |
| $ | — |
| Kimberly J. Harris |
| Retirement Plan |
| 20.7 |
|
| | | $ | 588,937 | |
|
| | | $ | — | | |
| |
| SERP |
| 20.7 |
|
| | 13,144,354 |
|
| — | |
|
Mary E. Kipp | | Mary E. Kipp |
| Retirement Plan |
| 0.3 |
|
| | — |
|
| — | |
|
| SERP | 17.7 |
| 8,011,240 |
| — |
|
| Restoration Plan |
| 0.3 |
|
| | — |
|
| — | |
|
Daniel A. Doyle | Retirement Plan | 5.1 |
| 138,534 |
| — |
| Daniel A. Doyle |
| Retirement Plan |
| 8.1 |
|
| | 269,865 |
|
| — | |
|
| SERP | 5.1 |
| 1,328,364 |
| — |
|
| SERP |
| 8.1 |
|
| | 3,133,936 |
|
| — | |
|
Steve R. Secrist | Retirement Plan | 27.6 |
| 456,562 |
| — |
| Steve R. Secrist |
| Retirement Plan |
| 30.6 |
|
| | 672,138 |
|
| — | |
|
| SERP | 27.6 |
| 2,214,826 |
| — |
|
| SERP |
| 30.6 |
|
| | 3,635,745 |
|
| — | |
|
Marla D. Mellies | Retirement Plan | 11.2 |
| 276,461 |
| — |
| Marla D. Mellies |
| Retirement Plan |
| 14.2 |
|
| | 436,224 |
|
| — | |
|
| SERP | 11.2 |
| 1,525,889 |
| — |
|
| SERP |
| 14.2 |
|
| | 3,088,940 |
|
| — | |
|
Philip K. Bussey | Retirement Plan | 10.3 |
| 309,974 |
| — |
| |
| SERP | 10.3 |
| 1,638,506 |
| — |
| |
_______________
1.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, 2019, 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 assumed to be 4.0% annually. The discount assumption is 3.35%, and the post-retirement mortality assumption is based on the 2020 417(e) unisex mortality table. Annuity benefits are converted to lump sum amounts at retirement based on assumed future 417(e) segment rates of 2.79%, 3.92%, and 4.38% (the 24-month average of the underlying rates as of September 2019), except that payments assumed to occur during 2020 use segment rates in effect for 2020 (this includes Ms. Harris' and Mr. Doyle's SERP present values). These assumptions are consistent with the ones used for the Retirement Plan and the SERP for financial reporting purposes for 2019. 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, 2018, for the benefits earned as of that date using the assumptions used for financial reporting purposes for 2018. These assumptions included assumed cash balance interest credits of 4.0%, a discount assumption of 4.40% and post-retirement mortality assumption based on the 2019 417(e) unisex mortality table. Annuity benefits were converted to lump sum amounts at retirement based on assumed future 417(e) segment rates of 2.28%, 3.81%, and 4.46% (the 24-month average of the underlying rates as of September 2018). Other assumptions used to determine the value as of December 31, 2018, were the same as those used for December 31, 2019.
2.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, except Ms. Harris, at age 62 (without discounting to the present), calculated as if such Named Executive Officer had terminated employment on December 31, 2019. Each SERP-eligible Named Executive Officer was vested in his or her SERP benefits as of December 31, 2019.
3.Ms. Kipp does not have a SERP benefit as that plan was closed prior to her joining PSE. Upon hire, Ms. Kipp elected to have her 4% company retirement contribution made to her 401(k) account. Ms. Kipp also participates in an Officer Restoration Benefit Plan as described below, with vesting after three years of service. Values of accumulated benefit will be shown after Ms. Kipp attains one year of service.
| | | | | | | | | | | | | | |
Name | 1
| 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, 2016 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 assumed to be 4.0% annually. The discount assumption is 4.50%, and the post-retirement mortality assumption is based on the 2017 417(e) unisex mortality table. Annuity benefits are converted to lump sum amounts at retirement based on assumed future 417(e) segment rates of 1.52%, 3.80%, and 4.79% (the 24-month average of the underlying rates as of September 2016). These assumptions are consistent with the ones used for the Retirement Plan and the SERP for financial reporting purposes for 2016. 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, 2015 for the benefits earned as of that date using the assumptions used for financial reporting purposes for 2015. These assumptions included assumed cash balance interest credits of 4.0%, a discount assumption of 4.65% and post-retirement mortality assumption based on the 2016 417(e) unisex mortality table. Annuity benefits were converted to lump sum amounts at retirement based on assumed future 417(e) segment rates of 1.34%, 4.03% and 5.06% (the 24-month average of the underlying rates as of September 2015). Other assumptions used to determine the value as of December 31, 2015 were the same as those used for December 31, 2016.Estimated Lump Sum |
| |
Daniel A. Doyle | 2
| 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, 2016. Each SERP-eligible Named Executive Officer (except Mr. Doyle) was vested in his or her SERP benefits as of December 31, 2016. | $ | 3,194,757 | |
|
Steve R. Secrist |
| | 4,159,373 | |
Marla D. Mellies |
| | 3,326,658 | |
_______________________
4.As a result of retirement on January 2, 2020, Ms. Harris received a SERP lump sum in the amount of $13,144,354, calculated per the plan and paid according to Ms. Harris’ election of payment format.
|
| | | |
Name | Estimated Lump Sum |
|
Kimberly J. Harris | $ | 12,081,432 |
|
Daniel A. Doyle | 1,555,310 |
|
Steve R. Secrist | 3,025,148 |
|
Marla D. Mellies | 1,922,575 |
|
Philip K. Bussey | 1,731,185 |
|
Retirement Plan
Under the Retirement Plan, the Company's eligible employees hired prior to January 1, 2014 (prior to December 12, 2014, in the case of IBEW-represented 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, and IBEW-represented employees hired on or after December 12, 2014, will receive pay credits equal to 4% (rather than the age-based pay credit described above), which non-represented and IBEW-represented employees may choose to have contributed to the Company’s 401(k) plan, rather than credited under the Retirement 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 2016,2019, the limit was $265,000.$280,000. For 2017,2020, the limit is $270,000.$285,000. 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 20162019 and 2017,2020, 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, 2016,2019, all the Named Executive Officers, except Ms. Kipp, 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 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. The Company closed the SERP plan to new participants as of August 1, 2019, but existing officer participants continue to accrue benefits in the plan. All the Named Executive Officers hired prior to 2019 participate in the SERP. A participating Named Executive Officer’s SERP benefit generally vests upon the executive’s completion of five years of participation in the SERP and attainment of age 55 while employed by the Company or any of its affiliates. However, SERP participants as of December 31, 2012, who have not yet attained age 55, including Ms. Harris, and Mr. Secrist, have been exempted from the age 55 vesting requirement. All the participating Named Executive Officers are vested in their SERP benefits.
The monthly benefit payable under the SERP to a Named Executive Officer (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 (i) below minus the sum of (ii) and (iii) below:
i.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.
ii.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.
iii.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 “2016“2019 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. An executive may also elect to have his or her SERP benefit transferred to the Deferred Compensation Plan and paid in accordance with his or her elections under that plan.
An executive may elect to have his or her SERP benefit paid, or commence to be paid, upon termination of employment after attaining age 55 but prior to attaining age 62. The SERP benefit of any executive who receives such early retirement benefits will be reduced by 1/3% for each month that the early commencement date precedes the beginning of the month coincident with or next following the date on which the executive attains age 62.
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.
Officer Restoration Benefit
The Officer Restoration Benefit provides a benefit to participating Officers that supplements the retirement income provided to the executives. Executives participating in the SERP are not eligible. Ms. Kipp participates in the benefit and those Company contributions under PSE’s applicable tax-qualified plan that would otherwise have been earned, if not for IRS limitations, are credited by the Company to an account within the Deferred Compensation Plan.
2016
2019 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 20162019 and year-end account balances under the Deferred Compensation Plan.
| | Name | Executive Contributions in 20161 | Registrant Contributions in 20162 | Aggregate Earnings in 20163 | Aggregate Withdrawals/ Distributions | Aggregate Balance at December 31, 20164 |
Name |
| Executive Contributions in 20191 | |
| Registrant Contributions in 20192 | |
| Aggregate Earnings in 20193 | |
| Aggregate Withdrawals/ Distributions | |
| Aggregate Balance at December 31, 20194 | |
Kimberly J. Harris | $ | — |
| $ | — |
| $ | 12,114 |
| $ | — |
| $ | 312,189 |
| Kimberly J. Harris |
| | $ | — | |
|
| | $ | — | |
|
| | $ | 13,694 | |
|
| | $ | — | |
|
| | $ | 351,927 | |
|
Mary E. Kipp | | Mary E. Kipp | | 64,500 | | | — | | | 870 | | | — | | | 65,370 | | |
Daniel A. Doyle | 250,495 |
| 23,013 |
| 42,035 |
| — |
| 798,771 |
| Daniel A. Doyle |
| | 32,101 | |
|
| | 34,301 |
|
| 167,665 | | |
| | — | |
|
| | 1,219,744 | |
|
Steve R. Secrist | 22,524 |
| 16,699 |
| 526 |
| — |
| 39,750 |
| Steve R. Secrist |
| | 39,762 | | |
| | 27,272 |
|
| | 24,361 | |
|
| | — | |
|
| | 245,900 | |
|
Marla D. Mellies | 7,145 |
| 7,719 |
| 6,600 |
| — |
| 129,921 |
| Marla D. Mellies |
| | 19,518 | |
|
| | 19,547 |
|
| | 41,881 | |
|
| | — | |
|
| | 272,177 | |
|
Philip K. Bussey | — |
| — |
| — |
| — |
| — |
| |
_______________
| |
1
| The amount in this column reflects elective deferrals by the executive of salary, annual incentive compensation or LTI Plan awards paid in 2016. Deferred salary amounts are: Ms. Harris, $0; Mr. Doyle, $21,620; Mr. Secrist, $22,524; Ms. Mellies, $7,145; and Mr. Bussey, $0. Deferred incentive compensation amounts are: Ms. Harris, $0; Mr. Doyle, $0; Mr. Secrist, $0; Ms. Mellies, $0; and Mr. Bussey, $0. Mr. Doyle deferred $228,875 of LTIP earnings. The amounts are also included in the applicable column of the Summary Compensation Table for 2016. |
| |
2
| 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 2016. |
| |
3
| 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 2016. |
| |
4
| Of the amounts in this column, the amounts in the table below have also been reported in the Summary Compensation Table for 2016, 2015 and 2014. |
1.The amount in this column reflects elective deferrals by the executive of salary, annual incentive compensation or LTI Plan awards paid in 2019. Deferred salary amounts are: Ms. Harris, $0; Ms. Kipp, $64,500; Mr. Doyle, $32,101; Mr. Secrist, $39,762; and Ms. Mellies, $19,518. Deferred incentive compensation amounts are: Ms. Harris, $0; Ms. Kipp, $0; Mr. Doyle, $0; Mr. Secrist, $0; and Ms. Mellies, $0. The amounts are also included in the applicable column of the Summary Compensation Table for 2019. |
| | | | | | | | | |
Name | Reported for 2016 | Reported for 2015 | Reported for 2014 |
Kimberly J. Harris | $ | 4,033 |
| $ | 3,259 |
| $ | 2,190 |
|
Daniel A. Doyle | 273,509 |
| 259,782 |
| 132,127 |
|
Steve R. Secrist | 39,223 |
| — |
| — |
|
Marla D. Mellies | 15,428 |
| 17,869 |
| 16,314 |
|
Philip K. Bussey | — |
| — |
| — |
|
2.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 2019.
3.The amount in this column for each executive reflects the change in value of investment tracking funds. Amounts of zero indicate no change in value or a decrease in value. 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 2019.
4.Of the amounts in this column, the amounts in the table below have also been reported in the Summary Compensation Table for 2019, 2018, and 2017.
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
Name |
| Reported for 2019 | | |
| Reported for 2018 | | |
| Reported for 2017 | | |
Kimberly J. Harris |
| | $ | 2,516 | |
|
| | $ | 2,154 | |
|
| | $ | 3,165 | |
|
Mary E. Kipp | | | — | | | | | — | | | | | — | | |
Daniel A. Doyle |
| | 66,403 |
|
| | 61,671 |
|
| | 57,531 |
|
Steve R. Secrist |
| | 67,034 |
|
| | 55,044 |
|
| | 53,922 |
|
Marla D. Mellies |
| | 39,417 |
|
| | 25,207 |
|
| | 22,280 |
|
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 20162019 calendar year returns of these tracking funds were:
|
| | | | | | | |
Vanguard Total Bond Market Index | 2.61
| %8.73% |
Vanguard 500 Index | 11.82
| 31.46 |
Vanguard Money Market Index | 0.3
| 2.14 |
Interest Crediting Fund (pre-2012 deferrals) | 4.10
| 4.12 |
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).
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) a change in control; (ii) an involuntary termination without cause or for good reason in connection with a change in control; (iii) retirement; (iv) disability; or (v) death.
Certain Company benefit plans provide incremental benefits or payments in the event of certain terminations of employment. In addition, Ms. Harris and Ms. Mellies are each parties to an Executive Employment Agreement with the Company, dated March 2009. The agreements which provide for benefits or payments upon certain qualifying terminations of employment from the Company following a 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, under certain conditions, as 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 in which awards are not assumed or substituted, outstanding LTI Plan awards will be paid on a pro-rata basis 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 in control.
Employment Agreements with Certain Named Executive Officers
In March 2009, PSE entered into Executive Employment Agreements (Employment Agreements) with each of Ms. Harris and Ms. Mellies (the Covered Executives). The Employment Agreements provide for an employment period of two years following a change in control. 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:
•Lump sum payment of 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 2016,2019, 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 for the remainder of the two-year protection period. 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 (and non-revocation) 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, 2016.2019. 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.
| | | | Upon Change in Control | | After Change in Control Involuntary Termination w/o Cause or for Good Reason | | Retirement | | Disability | | Death |
| Upon Change in Control (and awards not assumed or substituted) | |
| After Change in Control Involuntary Termination w/o Cause or for Good Reason | |
| Retirement | |
| Disability | |
| Death | |
Kimberly J. Harris | | $ | — |
| | $ | — |
| | $ | — |
| | $ | — |
| | $ | — |
| Kimberly J. Harris |
| $ | — | | |
| $ | — | | |
| $ | — | | | | | $ | — | | |
| $ | — | | |
Cash Severance (salary and/or annual incentive) | | — |
| | 5,400,000 |
| | — |
| | — |
| | — |
| Cash Severance (salary and/or annual incentive) |
| — | | |
| 6,000,000 | |
| — | | |
| — | | |
| — | | |
Long Term Incentive Plan | | 4,072,922 |
| | 4,072,922 |
| | — |
| | 3,543,948 |
| | 3,543,948 |
| Long Term Incentive Plan |
| 12,000,606 | |
| 12,000,606 | |
| — | | |
| 12,000,606 | |
| 12,000,606 | |
SERP (additional years of credited service)1 | | — |
| | — |
| | — |
| | — |
| | — |
| SERP (additional years of credited service)1 |
| — | | |
| — | | |
| — | | |
| — | | |
| — | | |
Benefits (continuation)2 | | — |
| | 28,948 |
| | — |
| | 28,948 |
| | 28,948 |
| Benefits (continuation)2 |
| — | | |
| 30,700 | |
| — | | |
| 30,700 | |
| 30,700 | |
Supplemental Life Insurance | | Supplemental Life Insurance |
| — | | |
| — | | |
| — | | |
| — | | |
| 3,400,000 | |
Total Estimated Incremental Value | | Total Estimated Incremental Value |
| $ | 12,000,606 | | |
| $ | 18,031,306 | | |
| $ | — | | |
| $ | 12,031,306 | | |
| $ | 15,431,306 | | |
Mary E. Kipp | | Mary E. Kipp | | $ | — | | | | $ | — | | | | $ | — | | | | $ | — | | | | $ | — | | |
Long Term Incentive Plan | | Long Term Incentive Plan | | 4,089,968 | | | 4,089,968 | | | 4,089,968 | | | 4,089,968 | | | 4,089,968 | |
Benefits (continuation)1 | | Benefits (continuation)1 | | — | | | | — | | | | — | | | | — | | | | — | | |
Supplemental Life Insurance | | — |
| | — |
| | — |
| | — |
| | 3,000,000 |
| Supplemental Life Insurance | | — | | | | — | | | | — | | | | — | | | | 2,805,200 | |
Total Estimated Incremental Value | | $ | 4,072,922 |
| | $ | 9,501,870 |
| | $ | — |
| | $ | 3,572,896 |
| | $ | 6,572,896 |
| Total Estimated Incremental Value | | $ | 4,089,968 | | | | $ | 4,089,968 | | | | $ | 4,089,968 | | | | $ | 4,089,968 | | | | $ | 6,895,168 | | |
Daniel A. Doyle | | $ | — |
| | $ | — |
| | $ | — |
| | $ | — |
| | $ | — |
| Daniel A. Doyle |
| $ | — | | |
| $ | — | | |
| $ | — | | |
| $ | — | | |
| $ | — | | |
Long Term Incentive Plan | | 1,127,802 |
| | 1,127,802 |
| | — |
| | 980,745 |
| | 980,745 |
| Long Term Incentive Plan |
| 2,430,151 | |
| 2,430,151 | |
| — | | |
| 2,430,151 | |
| 2,430,151 | |
SERP (additional years of credited service)1 | | — |
| | — |
| | — |
| | — |
| | — |
| SERP (additional years of credited service)1 |
| — | | |
| — | | |
| — | | |
| — | | |
| — | | |
Benefits (continuation)2 | | — |
| | — |
| | — |
| | — |
| | — |
| Benefits (continuation)2 |
| — | | |
| — | | |
| — | | |
| — | | |
| — | | |
Supplemental Life Insurance | | — |
| | — |
| | — |
| | — |
| | 971,652 |
| Supplemental Life Insurance |
| — | | |
| — | | |
| — | | |
| — | | |
| 1,222,266 | |
Total Estimated Incremental Value | | $ | 1,127,802 |
| | $ | 1,127,802 |
| | $ | — |
| | $ | 980,745 |
| | $ | 1,952,397 |
| Total Estimated Incremental Value |
| $ | 2,430,151 | | |
| $ | 2,430,151 | | |
| $ | — | | |
| $ | 2,430,151 | | |
| $ | 3,652,417 | | |
Steve R. Secrist | | $ | — |
| | $ | — |
| | $ | — |
| | $ | — |
| | $ | — |
| Steve R. Secrist |
| $ | — | | |
| $ | — | | |
| $ | — | | |
| $ | — | | |
| $ | — | | |
Long Term Incentive Plan | | 829,360 |
| | 829,360 |
| | — |
| | 721,581 |
| | 721,581 |
| Long Term Incentive Plan |
| 1,908,392 | |
| 1,908,392 | |
| — | | |
| 1,908,392 | |
| 1,908,392 | |
SERP (additional years of credited service)1 | | — |
| | — |
| | — |
| | — |
| | — |
| SERP (additional years of credited service)1 |
| — | | |
| — | | |
| — | | |
| — | | |
| — | | |
Benefits (continuation)2 | | — |
| | — |
| | — |
| | — |
| | — |
| Benefits (continuation)2 |
| — | | |
| — | | |
| — | | |
| — | | |
| — | | |
Supplemental Life Insurance | | — |
| | — |
| | — |
| | — |
| | 737,926 |
| Supplemental Life Insurance |
| — | | |
| — | | |
| — | | |
| — | | |
| 1,064,440 | |
Total Estimated Incremental Value | | $ | 829,360 |
| | $ | 829,360 |
| | $ | — |
| | $ | 721,581 |
| | $ | 1,459,507 |
| Total Estimated Incremental Value |
| $ | 1,908,392 | | |
| $ | 1,908,392 | | |
| $ | — | | |
| $ | 1,908,392 | | |
| $ | 2,972,832 | | |
Marla D. Mellies | | $ | — |
| | $ | — |
| | $ | — |
| | $ | — |
| | $ | — |
| Marla D. Mellies |
| $ | — | | |
| $ | — | | |
| $ | — | | | | | $ | — | | |
| $ | — | | |
Cash Severance (salary and/or annual incentive) | | — |
| | 1,343,089 |
| | — |
| | — |
| | — |
| Cash Severance (salary and/or annual incentive) |
| — | | |
| 1,942,380 | |
| — | | |
| — | | |
| — | | |
Long Term Incentive Plan | | 679,185 |
| | 679,185 |
| | — |
| | 590,616 |
| | 590,616 |
| Long Term Incentive Plan |
| 1,563,151 | |
| 1,563,151 | |
| — | | |
| 1,563,151 | |
| 1,563,151 | |
SERP (additional years of credited service)1 | | — |
| | 412,166 |
| | — |
| | — |
| | — |
| SERP (additional years of credited service)1 |
| — | | |
| 430,688 | |
| — | | |
| — | | |
| — | | |
Benefits (continuation)2 | | — |
| | 40,549 |
| | — |
| | 40,549 |
| | 40,549 |
| Benefits (continuation)2 |
| — | | |
| 48,853 | |
| — | | |
| 48,853 | |
| 48,853 | |
Supplemental Life Insurance | | — |
| | — |
| | — |
| | — |
| | 586,636 |
| Supplemental Life Insurance |
| — | | |
| — | | |
| — | | |
| 0 | |
| 902,520 | |
Total Estimated Incremental Value | | $ | 679,185 |
| | $ | 2,474,989 |
| | $ | — |
| | $ | 631,165 |
| | $ | 1,217,801 |
| Total Estimated Incremental Value |
| $ | 1,563,151 | | |
| $ | 3,985,072 | | |
| $ | — | | |
| $ | 1,612,004 | | |
| $ | 2,514,524 | | |
Philip K. Bussey | | $ | — |
| | $ | — |
| | $ | — |
| | $ | — |
| | $ | — |
| |
Cash Severance (salary and/or annual incentive) | | | | | | | | | | | |
Long Term Incentive Plan | | — |
| | — |
| | — |
| | — |
| | — |
| |
SERP (additional years of credited service)1 | | 679,377 |
| | 679,377 |
| | — |
| | 590,805 |
| | 590,805 |
| |
Benefits (continuation)2 | | — |
| | — |
| | — |
| | — |
| | — |
| |
Supplemental Life Insurance | | — |
| | — |
| | — |
| | — |
| | 582,369 |
| |
Total Estimated Incremental Value | | $ | 679,377 |
|
| $ | 679,377 |
|
| $ | — |
|
| $ | 590,805 |
|
| $ | 1,173,174 |
| |
_______________
| |
1
| 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, 2016. These values are based on interest rate and mortality rate assumptions consistent with those used in the Company’s financial statements. |
| |
2
| 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. |
1.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, 2019. These values are based on interest rate and mortality rate assumptions consistent with those used in the Company’s financial statements.
2.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.
3.Ms. Harris retired January 2, 2020, and per the LTIP plan is eligible for pro rata payments of LTIP grants for the 2018-2020 cycle of $3,871,077 and the 2019-2021 cycle of $1,105,636 to be paid in March 2020.
Chief Executive Officer Pay Ratio
We are providing the following information about the relationship of the annual total compensation of our employees and the annual total compensation for our Chief Executive Officer in accordance with SEC Item 402(u) of Regulation S-K.
For 2019, our last completed fiscal year:
•The annual total compensation of our CEO, as reported in the 2019 Summary Compensation Table, was $11,774,369.
•The median of the annual total compensation of all our employees (excluding our CEO) was $125,510.
As a result, for 2019 the ratio of annual total compensation of our Chief Executive Officer to the median of our annual total compensation of all employees was 94:1. CEO total compensation was higher in 2019 than previous years due to the valuation of the CEO’s SERP benefit.Without SERP valuation impact, the CEO pay ratio would have been similar to 2018’s ratio of 65:1.
We identified our median employee by examining the total cash compensation we paid during 2019 to all individuals, excluding our CEO, who were employed by us on December 31, 2019, which totaled approximately 3,148 individuals, all located in the United States (as reported in Item 1. Business), including employees, whether employed on a full-time, part-time or seasonal basis. Total cash compensation consisted of base salary, overtime, paid time off and annual incentives as reflected in our payroll records. We consistently applied this compensation measure and did not make any assumptions, adjustments, or estimates with respect to total cash compensation. We believe that the use of total cash compensation for all employees is a consistently applied compensation measure because it includes all major compensation elements available to employees. Pay for all non-represented employees in the organization is benchmarked periodically to ensure alignment with our compensation philosophy of paying at the market median.
After identifying the median employee based on total cash compensation for 2019, we calculated annual total compensation for such employee for 2019 using the same methodology we use for our named executive officers as set forth in the 2019 Summary Compensation Table in accordance with the requirements of Item 402 (c)(2)(x) of Regulation S-K. Annual total compensation for 2019 for our median employee included annual salary, annual incentives, and company contributions towards benefits including retirement. Annual total compensation for 2019 for our CEO consists of the amount reported in the "Total" column of our 2019 Summary Compensation Table.
Director Compensation for Fiscal Year 20162019
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 20162019 for service as directors. We refer to these directors as nonemployeenon-employee 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, Alan James, Christopher Leslie,Kenton Bradbury, Richard Dinneny, Chris Hind, Martijn Verwoest, and Etienne Middleton. Kimberly Harris is employed by the Company and also serves as a director.Steven Zucchet.
As described in further detail below, the Company’s nonemployeenon-employee director compensation program in 20162019 consisted of quarterly retainer cash fees of $27,500.$35,000. 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.
| | Name | Fees Earned | Nonqualified Deferred Compensation Earnings 1 | Total | Name |
| Fees Earned | | Nonqualified Deferred Compensation Earnings1 | | Total |
Scott Armstrong | $ | 136,000 |
| $ | — |
| $ | 136,000 |
| Scott Armstrong |
| $ | 192,500 | |
| $ | — | |
| $ | 192,500 | |
Melanie Dressel | 186,600 |
| — |
| 186,600 |
| |
Barbara Gordon | | Barbara Gordon |
| 170,000 | |
| — | | | 170,000 | |
Steve Hooper | — |
| 140,400 |
| 140,400 |
| Steve Hooper |
| — | |
| 231,400 | |
| 231,400 | |
David MacMillan | 154,400 |
| — |
| 154,400 |
| |
Thomas King | | Thomas King |
| 87,000 | |
| — | |
| 87,000 | |
Paul McMillan | 136,400 |
| — |
| 136,400 |
| Paul McMillan |
| 185,000 | |
| — | |
| 185,000 | |
Mary O. McWilliams | 131,600 |
| — |
| 131,600 |
| Mary O. McWilliams |
| 170,000 | |
| — | |
| 170,000 | |
Herbert Simon2 | 12,367 |
| — |
| 12,367 |
| |
Christopher Trumpy | 140,400 |
| — |
| 140,400 |
| Christopher Trumpy |
| 185,800 | |
| — | |
| 185,800 | |
_______________
| |
1
| Represents earnings accrued on deferred compensation considered to be above market. |
| |
2
| Herbert Simon resigned from his position as a member of the Board of Directors of PSE, effective as of January 21, 2016. |
1.Represents earnings accrued on deferred compensation considered to be above market.
Nonemployee
Non-employee Director Compensation Program
The 2016 nonemployee2019 non-employee director compensation program is based on the principles that the level of nonemployeenon-employee director compensation should be based on Board and committee responsibilities and should be competitive with comparable companies.
The 20162019 compensation program for nonemployeenon-employee directors was as follows:
1.A base cash quarterly retainer fee of $27,500;$35,000;
$1,600 for attendance at each in-person Board and committee meeting; and
$2.A $1,600 per meeting fee ($800 for each telephonic meeting lasting 60 minutestelephonic) will be paid when the number of Board or less, and $1,600 for each telephonic meeting lasting more than 60 minutes.Committee meetings exceed six per year (not applicable to Asset Management Committee calls).
In 2016, nonemployee2019, non-employee directors were paid the following additional cash quarterly retainer fees:
1.Independent Board Chairman, $13,750;
2.Chair of the Compensation and Leadership Development Committee, $2,000;$3,750;
3.Chair of the Governance and Public Affairs Committees, $1,500;Committee, $3,750;
4.Chair of the Business Planning Committee, $3,750
5.Chair of the Audit Committee, $2,500;$3,750; and
6.Each member of the Audit Committee other than the chair, $1,000.
7.Additional retainer for ad hoc working group facilitator, $3,750
Nonemployee8.Additional payment (payable in cash in 2019; equity-like phantom stock or similar payments subsequent to 2019), $7,500
Non-employee directors were reimbursed for actual travel and out-of-pocket expenses incurred in connection with their services.
Nonemployee Non-employee 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 $500 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
NonemployeeNon-employee 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. Nonemployeenon-employee directors. Non-employee 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. NonemployeeNon-employee directors are permitted to make changes in measurement fund allocations quarterly. Steve Hooper is the only independent board member to defer any director fees during 2016.2019.
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, 20162019, 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 LLC (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 PSE common stock outstanding as of December 31, 2016.2019.
Beneficial Ownership Table of Puget Energy and PSE
|
| | | | | | | | | | | | | |
| | Number of Beneficially Owned Shares |
Name | Puget Energy | PSE |
Name | | Puget Energy |
| Puget Sound Energy |
Puget Equico LLC and affiliates | | 2001, 2 | —
| — |
Puget Energy | | — |
| 85,903,7913 |
|
_______________
| |
1
| Information presented above and in this footnote is based on Amendment No. 2 to Schedule 13D/A filed on February 13, 2009 (the Schedule 13D) by Puget Equico, 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: |
1Information 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, among others, 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), 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 (BCI), PIP2PX (Pad) Ltd. (PIP2PX) and PIP2GV (Pad) Ltd. (PIP2GV and together with MIP, PMGH, CPPIB, BCI 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. As of February 21, 2020:
•The address of the principal office of Puget Holdings, Puget Intermediate and Puget Equico is the PSE Building, 10885355 110th Ave NE, 4th Street, Bellevue, WA 98004.
•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 2500, P.O. Box 101, Toronto, Ontario, Canada M5C 2W5.
•The address of the principal office of bcIMCBCI is Suite 300-2950 Jutland Road,750 Pandora Ave, Victoria, British Columbia, Canada V8T 5K2.V8W 0E4.
•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, as amended and extended April 15, 2014, 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, June 15, 2012 and May 12, 2015.
|
| |
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, as amended and extended April 15, 2014, 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, June 15, 2012 and May 12, 2015. |
In August 2018, Macquarie Infrastructure Partners and Macquarie Capital Group Limited reached an agreement to sell their shares to Ontario Municipal Employee Retirement System (OMERS), PGGM Vermogensbeheer B.V. and current owners, AIMCo and BCI. The sale was approved by various federal and state agencies, including that of the Washington Commission, and closed on April 17th, 2019.
•The address of the principal office of OMERS is 900-100 Adelaide Street West, Toronto, Ontario, Canada, M5H E02
•The address of the principal office of PGGM Vermogensbeheer B.V. is Noordweg Noord 150, 3704 JG Zeist, Netherlands
2Pursuant 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, as amended and extended April 15, 2014, 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, June 15, 2012 and May 12, 2015. 3Pursuant 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, as amended and extended April 15, 2014, 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, June 15, 2012 and May 12, 2015.
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:
1.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.
2.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.
3.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:
1.The extent of the related person’s interest in the transaction;
2.Whether the terms are comparable to those generally available in arm's length transactions; and
3.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.
Scott Armstrong serves on the Board of Directors of the Company and, until its acquisition by Kaiser Permanente on February 1, 2017, was the president and Chief Executive Officer of Group Health Cooperative (Group Health). Group Health provided coverage to over 600,000 residents in Washington and Northern Idaho. Certain employees of PSE elected Group Health as their medical provider and as a result, PSE paid Group Health a total of $23.3 million and $20.3 million for medical coverage for the year ended December 31, 2016 and 2015, respectively.
Kimberly Harris, theformer President and Chief Executive Officer and a director of Puget Energy and PSE, who retired effective January 2, 2020, is married to Kyle Branum, who through 2016 was a principal at the law firm Riddell Williams P.S. As of January 2017, Mr. Branum is a partner at Summit Law Group, which provides legal services to PSE. In 2016 and 2015, Riddell WilliamsSummit Law Group was paid $1.0$0.7 million and $1.8 million, respectively, for legal services provided to PSE in 2019, and Mr. Branum was among the lawyers at Riddell WilliamsSummit Law Group who provided such legal services. This work was performed under the supervision of PSE's General Counsel.
On October 10, 2014, U.S. Bancorp announced the appointment of Kimberly Harris to its board of directors effective October 20, 2014. Ms. Harris is the President and Chief Executive Officer of both Puget Energy and PSE. U.S. Bancorp is the parent company of U.S. Bank N.A., which directly or through its subsidiaries or affiliates provides credit, banking, investment and trust services to both Puget Energy and PSE. For the year ended December 31, 2016 and 2015, Puget Energy and PSE paid a total of approximately $0.3 million and $1.0 million, respectively, in fees and interest to U.S. Bank N.A. and its subsidiaries or affiliates.
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, Steven Hooper (member of the Boards of both Puget Energy and PSE), Melanie DresselScott Armstrong (member of the BoardsBoard of bothPSE and added to the Board of Puget Energy and PSE)at the November, 2017, Board Meeting), and Scott ArmstrongBarbara Gordon (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: (i) 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), (ii) shall not be an officer or employee of PSE, (iii) shall be a resident of the state of Washington, and (iv) 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 Boards have 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. Mr. Hooper, and Mr. Armstrong, and Ms. McWilliams and Ms. Dressel serve (or served) as directors or officers of, or otherwise havehave/had 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. Because these relationships either fall within the Boards' 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, in isolation, 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. Ms. Dressel,Mr. Hooper, 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, "Directors, Executives Officers and Corporate Governance" of Part III of this Form 10-K under the section “Communications with the Board.”
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, 20162019, and 20152018 were as follows:
| | | 2016 | 2015 |
| 2019 | | | 2018 | |
(Dollars in Thousands) | Puget Energy | PSE | Puget Energy | PSE | (Dollars in Thousands) | Puget Energy | | PSE | | Puget Energy | | PSE |
Audit fees1 | $ | 2,597 |
| $ | 2,397 |
| $ | 2,413 |
| $ | 2,128 |
| Audit fees1 | $ | 2,630 | | | $ | 2,378 | | | $ | 2,695 | | | $ | 2,495 | |
Audit related fees2 | 47 |
| 47 |
| 45 |
| 45 |
| Audit related fees2 | 114 | | | 114 | | | 204 | | 204 |
Tax fees3 | — |
| — |
| — |
| — |
| Tax fees3 | — | | | — | | | — | | | — |
Other fees4 | 383 |
| 383 |
| 52 |
| 52 |
| Other fees4 | 52 | | | 52 | | | 204 | | 204 |
Total | $ | 3,027 |
| $ | 2,827 |
| $ | 2,510 |
| $ | 2,225 |
| Total | $ | 2,796 | | | $ | 2,544 | | | $ | 3,103 | | | $ | 2,903 | |
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1
| 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 2016 fees are estimated and include an aggregate amount of $1.4 million billed to Puget Energy and $1.2 million to PSE through December 2016. |
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2
| Consists of work performed in connection with registration statements and other regulatory audits. |
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3
| Consists of tax consulting and tax return reviews. |
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4
| Consists of software and research tools. |
1.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 2019 fees are estimated and include an aggregate amount of $1.7 million billed to Puget Energy and $1.6 million to PSE through December 2019.
2.Consists of work performed in connection with registration statements and other regulatory audits.
3.Consists of tax consulting and tax return reviews.
4.Consists of software and research tools.
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 the Audit Committee. In addition, any proposed services exceeding pre-approved cost levels will require specific pre-approval by the 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 20162019 and 2015,2018, all audit and non-audit services were pre-approved.
PART IV
ITEM 15. EXHIBITS AND FINANCIAL STATEMENT SCHEDULES
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a) | Documents filed as part of this report: |
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, 2016, 20152019, 2018, and 2014,2017, consist of the following:
I. Condensed Financial Information of Puget Energy
II. Valuation of Qualifying Accounts and Reserves
3) Exhibits
ITEM 16. FORM 10-K SUMMARY
None.
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.
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PUGET ENERGY, INC. | | PUGET SOUND ENERGY, INC. |
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/s/ Kimberly J. Harris | | /s/ Kimberly J. Harris |
Kimberly J. Harris | | Kimberly J. Harris |
President and Chief Executive Officer | | President and Chief Executive Officer |
| | | | |
Date: | March 2, 2017 | | Date: | March 2, 2017 |
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.
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Signature | Title | Date |
| (Puget Energy and PSE unless otherwise noted) |
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/s/ Kimberly J. Harris | President and | March 2, 2017 |
(Kimberly J. Harris) | Chief Executive Officer | |
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/s/ Daniel A. Doyle | Senior Vice President and | |
(Daniel A. Doyle) | Chief Financial Officer | |
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/s/ Matthew Marcelia | Controller and Principal Accounting Officer | |
(Matthew Marcelia) | | |
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/s/ Scott Armstrong | Director of PSE only | |
(Scott Armstrong) | | |
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/s/ Andrew Chapman | Director | |
(Andrew Chapman) | | |
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/s/ Steven W. Hooper | Director | |
(Steven W. Hooper) | | |
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/s/ Karl Kuchel | Director | |
(Karl Kuchel) | | |
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/s/ Christopher J. Leslie | Director | |
(Christopher J. Leslie) | | |
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/s/ David MacMillan | Director | |
(David MacMillan) | | |
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/s/ Paul McMillan | Director | |
(Paul McMillan) | | |
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/s/ Mary O. McWilliams | Director | |
(Mary O. McWilliams) | | |
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| Director | |
(Etienne Middleton) | | |
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/s/ Christopher Trumpy | Director | |
(Christopher Trumpy) | | |
EXHIBIT INDEX
Certain of the following exhibits are filed herewith. Certain other of the following exhibits have heretofore been filed with the SEC and are incorporated herein by reference.
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*** | 4.1 | Indenture between Puget Sound Energy, Inc. and U.S. Bank National Association (as successor to State Street Bank and Trust Company) defining the rights of the holders of Puget Sound Energy’s senior notes (incorporated herein by reference to Exhibit 4-a to Puget Sound Energy’s Quarterly Report on Form 10-Q for the quarter ended June 30, 1998, Commission File No. 1-4393). |
| | First, Second, Third, Fourth, and FourthFifth Supplemental Indentures defining the rights of the holders of Puget Sound Energy’s senior notes (incorporated herein by reference to Exhibit 4-b to Puget Sound Energy’s Quarterly Report on Form 10-Q for the quarter ended June 30, 1998 (Exhibit originally filed with the Securities and Exchange Commission in paper format and as such, a hyperlink is not available.), Commission File No. 1-4393; Exhibit 4.26 to Puget Sound Energy’s Current Report on Form 8-K, dated March 4, 1999 (Exhibit originally filed with the Securities and Exchange Commission in paper format and as such, a hyperlink is not available.), Commission File No. 1-4393; Exhibit 4.1 to Puget Sound Energy’s Current Report on Form 8-K, dated November 2, 2000 (Exhibit originally filed with the Securities and Exchange Commission in paper format and as such, a hyperlink is not available.), Commission File No. 1-4393; and Exhibit 4.1 to Puget Sound Energy’s Current Report on Form 8-K, dated May 28, 2003, Commission File No. 1-4393).1-4393 and Exhibit 4.1 to Puget Sound Energy's Current Report on Form 8-K, dated May 23, 2018, Commission File No. 1-4393.) |
| | Fortieth through Sixtieth Supplemental Indentures defining the rights of the holders of Puget Sound Energy’s Electric Utility First Mortgage Bond (incorporated herein by reference to Exhibits 4.3 through and including 4.23 to Puget Sound Energy’s Registration Statement on Form S-3, filed March 13, 2009, Registration No. 333-157960). |
| 4.4
| Exhibits 4.3 through and including 4.23: 4.3, 4.4, 4.5, 4.6, 4.7, 4.8, 4.9. 4.10, 4.11, 4.12, 4.13, 4.14, 4.15, 4.16, 4.17, 4.18, 4.19, 4.20, 4.21, 4.22, 4.23. |
*** | 4.4 | Sixty-first through Eighty-seventh Supplemental Indentures defining the rights of the holders of Puget Sound Energy’s Electric Utility First Mortgage Bonds (incorporated herein by reference to Exhibit (4)-j-1 to Registration No. 2-72061; Exhibit (4)-a to Registration No. 2-91516; Exhibit (4)-b to Puget Sound Energy’s Report on Form 10-K for the fiscal year ended December 31, 1985, (Exhibit originally filed with Securities and Exchange Commission File No. 1-4393; Exhibits (4)(a) and (4)(b) to Puget Sound Energy’s Current Report on Form 8-K, dated April 22, 1986, Commission File No. 1-4393; Exhibit (4)(b) to Puget Sound Energy’s Current Report on Form 8-K, dated September 5, 1986, not available). Commission File No. 1-4393; Exhibit (4)-b to Puget Sound Energy’s Report on Form 10-Q for the quarter ended September 30, 1986, Commission File No. 1-4393; Exhibit (4)-c to Registration No. 33-18506; Exhibit (4)-b to Puget Sound Energy’s Report on Form 10-K for the fiscal year ended December 31, 1989, Commission File No. 1-4393; Exhibit (4)-b to Puget Sound Energy’s Report on Form 10-K for the fiscal year ended December 31, 1990, Commission File No. 1-4393; Exhibits (4)-d and (4)-e to Registration No. 33-45916; Exhibit (4)-c to Registration No. 33-50788; Exhibit (4)-a to Registration No. 33-53056; Exhibit 4.3 to Registration No. 33-63278; Exhibit 4-c to Puget Sound Energy’s Report on Form 10-Q for the quarter ended June 20, 1998,1998. |
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*** |
| Commission File No. 1-4393); Exhibit 4.4 to Post-Effective Amendment No. 2 to Puget Sound Energy’s Registration Statement on Form S-3, filed February 9, 2009, 2009. |
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*** |
| Commission File No. 1-4393; Exhibit 4.1 to Puget Sound Energy’s Report on Form 10-K for the fiscal year ended December 31, 2007,2007. Commission File No. 1-4393; and Exhibit 4.5 to Post-Effective Amendment No. 2 to Puget Sound Energy’s Registration Statement on Form S-3, filed February 9, 2009, 2009. |
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| 4.5
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| | Eighty-eighth, Eighty-ninth and Ninetieth Supplemental Indentures defining the rights of the holders of Puget Sound Energy's Electric Utility First Mortgage Bonds (incorporated herein by reference to Exhibits 4.1 through 4.3 to Puget Sound Energy's Report on Form 10-Q for the quarter ended March 31, 2012, Commission File No. 1-4393). |
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| | First, Sixth, Seventh, Sixteenth and Seventeenth Supplemental Indenture to the Gas Utility First Mortgage, dated as of April 1, 1957, August 1, 1966, February 1, 1967, June 1, 1977, and August 9, 1978, respectively (incorporated herein by reference to Exhibits 4.26 through and including 4.30 to Puget Sound Energy's Registration Statement on Form S-3, filed March 13, 2009, Registration No. 333-157960). |
| 4.9
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*** | 4.9 | Twenty-second Supplemental Indenture to the Gas Utility First Mortgage, dated as of July 15, 1986 (incorporated herein by reference to Exhibit 4-B.20 to Washington Natural Gas Company’s Annual Report on Form 10-K for the fiscal year ended September 30, 1986, Commission File No. 0-951). |
*** | 4.10 | Twenty-seventh Supplemental Indenture to the Gas Utility First Mortgage, dated as of September 1, 1990 (incorporated herein by reference to Exhibit 4.12 to Post-Effective Amendment No. 2 to Puget Sound Energy’s Registration Statement on Form S-3, filed February 9, 2009, Registration No. 333-132497-01). |
*** | 4.11 | Twenty-eighth through Thirty-sixth Supplemental Indentures to the Gas Utility First Mortgage (incorporated herein by reference to Exhibit 4-A to Washington Natural Gas Company’s Quarterly Report on Form 10-Q for the quarter ended March 31, 1993, Commission File No. 0-951; Exhibit 4-A to Washington Natural Gas Company’s Registration Statement on Form S-3, Registration No. 33-49599; Exhibit 4-A to Washington Natural Gas Company’s Registration Statement on Form S-3, Registration No. 33-61859; Exhibit 4.30 to Puget Sound Energy’s Annual Report on Form 10-K for the fiscal year ended December 31, 2002, Commission File No. 1-4393; Exhibits 4.22 and 4.23 to Puget Sound Energy’s Annual Report on Form 10-K for the fiscal year ended December 31, 2005,2005. Commission File No. 1-4393; Exhibits 4.22 and 4.23 to Puget Sound Energy’s Annual Report on Form 10-K for the fiscal year ended December 31, 2007, Commission File No. 1-4393; and Exhibit 4.14 to Post-Effective Amendment No. 2 to Puget Sound Energy’s Registration Statement on Form S-3, filed February 9, 2009, Registration No. 333-132497-01). |
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| 4.15 | |
| 4.16 | |
| 4.17 | |
| 4.18 | |
| 4.19 | |
| 4.20 | |
| 4.21 | |
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*** | 10.1 | |
| 10.1 | First Amendment dated as of October 4, 1961 to Power Sales Contract between Public Utility District No. 1 of Chelan County, Washington and Puget Sound Energy, Inc., relating to the Rocky Reach Project (incorporated herein by reference to Exhibit 10.1 to Puget Sound Energy’s Report on Form 10-Q for the quarter ended March 31, 2009, Commission File No. 1-4393). |
*** | 10.2 | First Amendment dated February 9, 1965 to Power Sales Contract between Public Utility District No. 1 of Douglas County, Washington and Puget Sound Energy, Inc., relating to the Wells Development (incorporated herein by reference to Exhibit 10.2 to Puget Sound Energy’s Report on Form 10-Q for the quarter ended March 31, 2009, Commission File No. 1-4393). |
*** | 10.3 | Contract dated November 14, 1957 between Public Utility District No. 1 of Chelan County, Washington and Puget Sound Energy, Inc., relating to the Rocky Reach Project (incorporated herein by reference to Exhibit 10.3 to Puget Sound Energy’s Report on Form 10-Q for the quarter ended March 31, 2009, Commission File No. 1-4393). |
*** | 10.4 | Power Sales Contract dated as of November 14, 1957 between Public Utility District No. 1 of Chelan County, Washington and Puget Sound Energy, Inc., relating to the Rocky Reach Project (incorporated herein by reference to Exhibit 10.4 to Puget Sound Energy’s Report on Form 10-Q for the quarter ended March 31, 2009, Commission File No. 1-4393). |
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*** | 10.5 | Power Sales Contract dated May 21, 1956 between Public Utility District No. 2 of Grant County, Washington and Puget Sound Energy, Inc., relating to the Priest Rapids Project (incorporated herein by reference to Exhibit 10.5 to Puget Sound Energy’s Report on Form 10-Q for the quarter ended March 31, 2009, Commission File No. 1-4393). |
*** | 10.6 | First Amendment to Power Sales Contract dated as of August 5, 1958 between Puget Sound Energy, Inc. and Public Utility District No. 2 of Grant County, Washington, relating to the Priest Rapids Development (incorporated herein by reference to Exhibit 10.6 to Puget Sound Energy’s Report on Form 10-Q for the quarter ended March 31, 2009, Commission File No. 1-4393). |
*** | 10.7 | Power Sales Contract dated June 22, 1959 between Public Utility District No. 2 of Grant County, Washington and Puget Sound Energy, Inc., relating to the Wanapum Development (incorporated herein by reference to Exhibit 10.7 to Puget Sound Energy’s Report on Form 10-Q for the quarter ended March 31, 2009, Commission File No. 1-4393). |
*** | 10.8 | Agreement to Amend Power Sales Contracts dated July 30, 1963 between Public Utility District No. 2 of Grant County, Washington and Puget Sound Energy, Inc., relating to the Wanapum Development (incorporated herein by reference to Exhibit 10.8 to Puget Sound Energy’s Report on Form 10-Q for the quarter ended March 31, 2009, Commission File No. 1-4393). |
*** | 10.9 | Power Sales Contract executed as of September 18, 1963 between Public Utility District No. 1 of Douglas County, Washington and Puget Sound Energy, Inc., relating to the Wells Development (incorporated herein by reference to Exhibit 10.9 to Puget Sound Energy’s Report on Form 10-Q for the quarter ended March 31, 2009, Commission File No. 1-4393). |
*** | 10.10 | Construction and Ownership Agreement dated as of July 30, 1971 between The Montana Power Company and Puget Sound Energy, Inc. (incorporated herein by reference to Exhibit 10.10 to Puget Sound Energy’s Report on Form 10-Q for the quarter ended March 31, 2009, Commission File No. 1-4393). |
*** | 10.11 | Operation and Maintenance Agreement dated as of July 30, 1971 between The Montana Power Company and Puget Sound Energy, Inc. (incorporated herein by reference to Exhibit 10.11 to Puget Sound Energy’s Report on Form 10-Q for the quarter ended March 31, 2009, Commission File No. 1-4393). |
*** | 10.12 | Contract dated June 19, 1974 between Puget Sound Energy, Inc. and P.U.D. No. 1 of Chelan County (incorporated herein by reference to Exhibit 10.12 to Puget Sound Energy’s Report on Form 10-Q for the quarter ended March 31, 2009, Commission File No. 1-4393). |
*** | 10.13 | Transmission Agreement dated April 17, 1981 between the Bonneville Power Administration and Puget Sound Energy, Inc. (Colstrip Project) (incorporated herein by reference to Exhibit (10)-55 to Report on Form 10-K for the fiscal year ended December 31, 1987, Commission File No. 1-4393). |
*** | 10.14 | Transmission Agreement dated April 17, 1981 between the Bonneville Power Administration and Montana Intertie Users (Colstrip Project) (incorporated herein by reference to Exhibit (10)-56 to Report on Form 10-K for the fiscal year ended December 31, 1987, Commission File No. 1-4393). |
*** | 10.15 | Ownership and Operation Agreement dated as of May 6, 1981 between Puget Sound Energy, Inc. and other Owners of the Colstrip Project (Colstrip 3 and 4) (incorporated herein by reference to Exhibit (10)-57 to Report on Form 10-K for the fiscal year ended December 31, 1987, Commission File No. 1-4393). |
*** | 10.16 | Colstrip Project Transmission Agreement dated as of May 6, 1981 between Puget Sound Energy, Inc. and Owners of the Colstrip Project (incorporated herein by reference to Exhibit (10)-58 to Report on Form 10-K for the fiscal year ended December 31, 1987, Commission File No. 1-4393). |
*** | 10.17 | Common Facilities Agreement dated as of May 6, 1981 between Puget Sound Energy, Inc. and Owners of Colstrip 1 and 2, and 3 and 4 (incorporated herein by reference to Exhibit (10)-59 to Report on Form 10-K for the fiscal year ended December 31, 1987, Commission File No. 1-4393). |
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*** | 10.18 | |
| 10.18 | Amendment dated as of June 1, 1968, to Power Sales Contract between Public Utility District No. 1 of Chelan County, Washington and Puget Sound Energy, Inc. (Rocky Reach Project) (incorporated herein by reference to Exhibit (10)-66 to Report on Form 10-K for the fiscal year ended December 31, 1987, Commission File No. 1-4393). |
*** | 10.19 | Transmission Agreement dated as of December 30, 1987 between the Bonneville Power Administration and Puget Sound Energy, Inc. (Rock Island Project) (incorporated herein by reference to Exhibit (10)-74 to Report on Form 10-K for the fiscal year ended December 31, 1988, Commission File No. 1-4393). |
*** | 10.20 | Amendment No. 1 to the Colstrip Project Transmission Agreement dated as of February 14, 1990 among The Montana Power Company, The Washington Water Power Company (Avista), Portland General Electric Company, PacifiCorp and Puget Sound Energy, Inc. (incorporated herein by reference to Exhibit (10)-91 to Report on Form 10-K for the fiscal year ended December 31, 1990, Commission File No. 1-4393). |
*** | 10.21 | Amendment of Seasonal Exchange Agreement, dated December 4, 1991 between Pacific Gas and Electric Company and Puget Sound Energy, Inc. (incorporated herein by reference to Exhibit (10)-107 to Report on Form 10-K for the fiscal year ended December 31, 1991, Commission File No. 1-4393). |
*** | 10.22 | Capacity and Energy Exchange Agreement, dated as of October 4, 1991 between Pacific Gas and Electric Company and Puget Sound Energy, Inc. (incorporated herein by reference to Exhibit (10)-108 to Report on Form 10-K for the fiscal year ended December 31, 1991, Commission File No. 1-4393). |
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*** | 10.23 | General Transmission Agreement dated as of December 1, 1994 between the Bonneville Power Administration and Puget Sound Energy, Inc. (BPA Contract No. DE-MS79-94BP93947) (incorporated herein by reference to Exhibit 10.115 to Report on Form 10-K for the fiscal year ended December 31, 1994, Commission File No. 1-4393). |
*** | 10.24 | PNW AC Intertie Capacity Ownership Agreement dated as of October 11, 1994 between the Bonneville Power Administration and Puget Sound Energy, Inc. (BPA Contract No. DE-MS79-94BP94521) (incorporated herein by reference to Exhibit 10.116 to Report on Form 10-K for the fiscal year ended December 31, 1994, Commission File No. 1-4393). |
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| 10.30 | Credit Agreement dated as of February 10, 2012 among Puget Energy, Inc., as Borrower, JPMorgan Chase Bank, N.A., as Administrative Agent, the other agents party thereto, and the lenders party thereto (incorporated herein by reference to Exhibit 10.1 to Puget Energy’s and Puget Sound Energy’s Report on Form 8-K dated February 16, 2012, Commission File Nos. 1-16305 and 1-4393). |
| 10.31 | Amendment No. 1 dated April 6, 2012 to Credit Agreement dated as of February 10, 2012 among Puget Energy, Inc., as Borrower, JPMorgan Chase Bank, N.A., as Administrative Agent, the other agents party thereto, and the lenders party thereto (incorporated herein by reference to Exhibit 10.2 to Puget Energy's Report on Form 10-Q for the quarter ended March 31, 2012, Commission File No. 1-16305). |
| 10.32 | Credit Agreement dated as of February 4, 2013 among Puget Sound Energy, Inc., as Borrower, Wells Fargo Bank, National Association, as Administration Agent, the other agents party thereto, and the lenders party thereto. (incorporated herein by reference to Exhibit 10.1 to Puget Energy’s and Puget Sound Energy’s Report on
Form 8-K dated February 11, 2013, Commission File Nos. 1-16305 and 1-4393).
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| 10.33 | |
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** | 10.34 | |
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| | Puget Sound Energy, Inc. Amended and Restated Supplemental Executive Retirement Plan effective January 1, 2013 (incorporated |
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| 10.36 | |
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| 10.37 | |
** | 10.38 | Summary of Director Compensation (incorporated herein by reference to Exhibit 10.38 to Puget Energy’s and
Puget Sound Energy’s Report on Form 10-K for the fiscal year ended December 31, 2015, Commission File No.
1-16305 and 1-4393).
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** | 10.39 | Puget Sound Energy,, Inc. Supplemental Death BenefitDisability Plan for Executive Employees, effective October 1, 2000 as amended (incorporated herein by referencereference to Exhibit 10.45Exhibit 10.47 to Puget Energy’sEnergy's and Puget Sound Energy’sEnergy's Report on Form 10-K for the fiscal year ended DecemberDecember 31, 2008,2008, CommissionFile No. 1-16305 and 1-4393)1-4393). |
**
| 10.40 | |
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| 10.41 | Puget Sound Energy, Inc. Supplemental Disability Plan for Executive Employees, effective October 1, 2000, as amended (incorporated herein by reference to Exhibit 10.47 to Puget Energy’s and Puget Sound Energy’s Report on Form 10-K for the fiscal year ended December 31, 2008, Commission File No. 1-16305 and 1-4393). |
** | 10.42 | Amendment to Puget Sound Energy, Inc. Supplemental Death Benefit Plan for Executive Employees, effective November 1, 2007, as amended (incorporated herein by reference to Exhibit 10.48 to Puget Energy’s and Puget Sound Energy’s Report on Form 10-K for the fiscal year ended December 31, 2008, Commission File No. 1-16305 and 1-4393). |
** | 10.43 | |
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| 10.44 | Amendment No. 1 dated April 15, 2014 to |
| 10.45 | Amendment No. 2 dated April 15, 2014 to Credit Agreement dated as of February 10, 2012October 25, 2017, among Puget Energy Inc., as Borrower, JPMorgan Chase Bank National Association,N.A., as Administrative Agent, and the Lenderslenders party thereto. (incorporated herein by reference to Exhibit 10.1 to Puget Energy’s and Puget Sound Energy’sEnergy's Current Report on Form 10-Q for8-K, filed October 31, 2017, Commission File No. 1-16305). |
| | Credit Agreement dated October 25, 2017, among Puget Sound Energy, Inc., as Borrower, Mizuho Bank, Ltd., as Administrative Agent, and the quarter ended Marchlenders party thereto. (incorporated by reference to Exhibits 10.2 to Puget Sound Energy's Current Report on Form 8-K, filed October 31, 2014,2017, Commission Filefile No. 1-4393). |
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* | 12.1 | Statement setting forth computation of ratios of earnings to fixed charges of Puget Energy, Inc. (2012 through 2016). |
* | 12.2 | Statement setting forth computation of ratios of earnings to fixed charges of Puget Sound Energy, Inc. (2012 through 2016). |
* | 21.1 | |
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* | 23.1 | |
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Mary E. Kipp.
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* | 32.2 | |
* | 101 | Financial statements from the Annual Report on Form 10-K of Puget Energy, Inc. and Puget Sound Energy, Inc. for the fiscal year ended December 31, 2016,2018, filed on March 2, 2017,February 20, 2019, formatted in XBRL: (i) the Consolidated Statement of Income (Unaudited), (ii) the Consolidated Statements of Comprehensive Income (Unaudited), (iii) the Consolidated Balance Sheets (Unaudited), (iii) the Consolidated Statements of Cash Flows (Unaudited), and (iv) the Notes to Consolidated Financial Statements (submitted electronically herewith). |
* | 101.INS | Inline XBRL Instance |
* | 101.SCH | Inline XBRL Taxonomy Extension Schema |
* | 101.CAL | Inline XBRL Taxonomy Extension Calculation |
* | 101.DEF | Inline XBRL Taxonomy Extension Definition |
* | 101.LAB | Inline XBRL Taxonomy Extension Label |
* | 101.PRE | Inline XBRL Taxonomy Extension Presentation |
* | 104 | Cover Page Interactive Data File (formatted as Inline XBRL and contained in Exhibit 101) |
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*Filed herewith.
** Management contract, compensatory plan or arrangement.
*** Exhibit originally filed with the Securities and Exchange Commission in paper format and as such, a hyperlink is not available.
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.
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*PUGET ENERGY, INC. | Filed herewith. |
| PUGET SOUND ENERGY, INC. | |
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/s/ Mary E. Kipp | |
| /s/ Mary E. Kipp | |
Mary E. Kipp | |
| Mary E. Kipp | |
President and Chief Executive Officer | |
| President and Chief Executive Officer | |
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Date: | February 21, 2020 |
| Date: | February 21, 2020 |
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Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following person son behalf of each registrant and in the capacities and on the dates indicated.
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**Signature | Management contract, compensatory plan or arrangement.Title | Date |
| (Puget Energy and PSE unless otherwise noted) | |
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/s/ Mary E. Kipp | President and | February 21, 2020 |
(Mary E. Kipp) | Chief Executive Officer |
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/s/ Daniel A. Doyle | Senior Vice President and |
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(Daniel A. Doyle) | Chief Financial Officer |
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/s/ Stephen J. King | Controller and Principal Accounting Officer |
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(Stephen J. King) |
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/s/ Scott Armstrong | Director |
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(Scott Armstrong) |
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/s/ Kenton Bradbury | Director |
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(Kenton Bradbury) |
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/s/ Steven W. Hooper | Director |
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(Steven W. Hooper) |
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/s/ Tom King | Director |
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(Tom King) |
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/s/ Richard Dinneny | Director | |
(Richard Dinneny) | | |
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/s/ Barbara Gordon | Director of PSE Only | |
(Barbara Gordon) | | |
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/s/ Christopher Hind | Director | |
(Christopher Hind ) | | |
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/s/ Paul McMillan | Director |
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(Paul McMillan) |
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/s/ Mary O. McWilliams | Director |
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(Mary O. McWilliams) |
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/s/ Christopher Trumpy | Director |
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(Christopher Trumpy) |
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/s/ Martijn Verwoest | Director | |
(Martijn Verwoest) | | |
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/s/ Steven Zucchet | Director |
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(Steven Zucchet) |
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