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, 20172019
OR
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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.
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, LLC |
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; |
• | Changes in tax law as a result of the Tax Cuts and Jobs Act legislation and uncertain interpretations related thereto; |
• | 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, Macquarie Capital Group Limited, 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, 20172019, and 2016:2018:
| | | December 31, | | December 31, | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| 2017 | | 2016 | | Percent | | 2017 | | 2016 | | 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 | 1,003,984 |
| | 992,959 |
| | 1.1% | | 767,045 |
| | 756,330 |
| | 1.4% | Residential | 1,033 | | | 1,018 | | | 1.5% | | | 788 | | | 778 | | | 1.2% | |
Commercial | 127,836 |
| | 125,737 |
| | 1.7 | | 55,996 |
| | 55,671 |
| | 0.6 | Commercial | 130 | | | 129 | | | 1.0% | | | 57 | | | 56 | | | 0.5% | |
Industrial | 3,377 |
| | 3,417 |
| | (1.2) | | 2,332 |
| | 2,365 |
| | (1.4) | Industrial | 3 | | | 3 | | | (0.7)% | | | 2 | | | 2 | | | (0.2)% | |
Other | 6,856 |
| | 6,591 |
| | 4.0 | | 226 |
| | 227 |
| | (0.4) | Other | 8 | | | 7 | | | 6.6% | | | — | | | — | | | (3.4)% | |
Total1 | 1,142,053 |
| | 1,128,704 |
| | 1.2% | | 825,599 |
| | 814,593 |
| | 1.4% | Total1 | 1,174 | | | 1,157 | | | 1.5% | | | 847 | | | 836 | | | 1.3% | |
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1
| At December 31, 2017 and 2016, approximately 398,518 and 392,806 customers purchased both electricity and natural gas from PSE, respectively. |
1At December 31, 2019, and 2018, approximately 409,820 and 404,540 customers purchased both electricity and natural gas from PSE, respectively.
| | | December 31, | | December 31, | | | December 31, | |
| December 31, | |
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Retail Revenue by Class | 2017 | | 2016 | | Percent | | 2017 | | 2016 | | Percent | 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 | $ | 1,232,075 |
| | $ | 1,138,871 |
| | 8.2% | | $ | 686,438 |
| | $ | 578,955 |
| | 18.6% | Residential | $ | 1,139,356 | | | $ | 1,147,260 | | | (0.7)% | | | $ | 613,617 | | | $ | 598,923 | | | 2.5% | |
Commercial | 892,360 |
| | 872,057 |
| | 2.3 | | 274,907 |
| | 235,695 |
| | 16.6 | Commercial | 854,910 | | | 885,457 | | | (3.4)% | | | 236,059 | | | 239,552 | | | (1.5)% | |
Industrial | 112,817 |
| | 113,469 |
| | (0.6) | | 21,071 |
| | 19,643 |
| | 7.3 | Industrial | 105,020 | | | 110,607 | | | (5.1)% | | | 16,322 | | | 18,198 | | | (10.3)% | |
Other | 32,313 |
| | 30,982 |
| | 4.3 | | 21,718 |
| | 20,322 |
| | 6.9 | Other | 37,920 | | | 32,596 | | | 16.3% | | | 20,283 | | | 19,984 | | | 1.5% | |
Total | $ | 2,269,565 |
| | $ | 2,155,379 |
| | 5.3% | | $ | 1,004,134 |
| | $ | 854,615 |
| | 17.5% | 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 and 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 corresponding higher power costs, during the winter heating season in the first and fourth quarters of the year and its lowest sales and corresponding 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 3,4, "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, 20172019, and gross utility plant by category and percentages as of December 31, 2017:2019:
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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 | 2013-2017 |
(Dollars in Thousands) | Electric | | Natural Gas | | Common |
Additions | $ | 2,148,599 |
| | $ | 868,919 |
| | $ | 499,934 |
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Retirements | (537,049 | ) | | (125,042 | ) | | (257,473 | ) |
Net Utility Plant | $ | 1,611,550 |
| | $ | 743,877 |
| | $ | 242,461 |
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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, 2017 |
(Dollars in Thousands) | Electric | | Natural Gas | | Common |
Distribution | $ | 3,757,600 |
| | 36.7 | % | | $ | 3,532,397 |
| | 91.0 | % | | $ | — |
| | — | % |
Generation | 3,948,102 |
| | 38.6 |
| | 5,956 |
| | 0.2 |
| | — |
| | — |
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Transmission | 1,471,337 |
| | 14.4 |
| | — |
| | — |
| | — |
| | — |
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General Plant & Other | 1,055,732 |
| | 10.3 |
| | 344,380 |
| | 8.8 |
| | 843,145 |
| | 100.0 |
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Total | $ | 10,232,771 |
| | 100.0 | % | | $ | 3,882,733 |
| | 100.0 | % | | $ | 843,145 |
| | 100.0 | % |
Employees
At December 31, 2017,2019, PSE had approximately 3,1403,130 full-time equivalent employees. Approximately 1,1101,020 PSE employees are represented by the International Brotherhood of Electrical Workers Union (IBEW) or the United Association of Plumbers and Pipefitters (UA). The contracts with the IBEW and the UA were both ratified effective December 2017, and will expire March 31, 2020, and September 30, 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 and PSE operate 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.
Rate mechanisms include: (i) trackers that typically track specific costs during the previous twelve-month period and (ii) riders that project cost recovery during a forward lookingforward-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 January 13, 2017, PSE filed itsa GRC with the Washington Commission on June 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 the settlement agreement was accepted bytraditional areas of focus (revenue requirements, cost allocation, rate design and cost of capital), the Washington CommissionCompany 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 December 5, 2017equity 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 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 rates became effective December 19, 2017. 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 20172019 GRC filing, see Note 3, "Regulation4, "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 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 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.
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 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 are 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. Total 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. For further details regarding decoupling filings, see Note 3,4, "Regulation and Rates" to the consolidated financial statements included in Item 8 of 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 hydrologicalhydroelectric 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 $30.0 million cumulative deferral trigger is reached.
On August 7, 2015, the Washington Commission issued an order approving changes to the PCA mechanism. The settlement agreement took effectEffective January 1, 2017, and will apply the following graduated scale:
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 |
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 load being different thancompared to the forecasted 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 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 is adjusted each year in May based on that year's assessed property taxes and true-up from the prior year.
Federal Incentive Tracker Tariff
The Federal Incentive Tracker Tariff passes through to customers the benefits associated with the wind-related treasury 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 to 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.
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 bi-annually on October 1.
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 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 be adjusted each year in May based on that year's assessed property taxes and true-up from the prior year.
Natural Gas Rate Filings
Natural Gas Cost Recovery Mechanism
The purpose of the CRMcost recovery mechanism (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. Rates change annually on November 1.
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. Rates typically change annually on November 1.1, although out-of-cycle rate changes are allowed at other times of the 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 is adjusted each year in May based on that year's assessed property 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.
ELECTRIC UTILITY OPERATING STATISTICS
| | | Year Ended December 31, | | Year Ended December 31, | |
| 2017 | | 2016 | | 2015 | | 2019 | | 2018 | | 2017 |
Generation and purchased power, MWh | | | | | | Generation and purchased power, MWh | | | | | |
Company-controlled resources | 10,825,778 |
| | 11,577,608 |
| | 12,747,014 |
| Company-controlled resources | 13,420,043 | | | 11,168,286 | | | 10,825,778 | |
Contracted resources | 8,337,348 |
| | 7,023,786 |
| | 5,911,012 |
| Contracted resources | 6,752,261 | | | 7,654,872 | | 8,337,348 |
Non-firm energy purchased | 6,147,778 |
| | 6,005,797 |
| | 5,315,266 |
| Non-firm energy purchased | 5,707,102 | | | 6,490,602 | | 6,147,778 |
Total generation and purchased power | 25,310,904 |
| | 24,607,191 |
| | 23,973,292 |
| Total generation and purchased power | 25,879,406 | | | 25,313,760 | | | 25,310,904 | |
Less: losses and Company use | (1,568,599 | ) | | (1,547,619 | ) | | (1,514,272 | ) | Less: losses and Company use | (1,298,854) | | | (1,513,451) | | (1,568,599) |
Total energy sales, MWh | 23,742,305 |
| | 23,059,572 |
| | 22,459,020 |
| Total energy sales, MWh | 24,580,552 | | | 23,800,309 | | | 23,742,305 | |
Electric energy sales, MWh | |
| | |
| | |
| Electric energy sales, MWh | | | | | | |
Residential | 10,931,999 |
| | 10,245,326 |
| | 10,164,703 |
| Residential | 10,756,628 | | | 10,497,389 | | 10,931,999 |
Commercial | 9,089,842 |
| | 8,895,950 |
| | 8,999,068 |
| Commercial | 8,837,457 | | | 8,932,681 | | 9,089,842 |
Industrial | 1,214,818 |
| | 1,223,214 |
| | 1,257,958 |
| Industrial | 1,161,149 | | | 1,189,828 | | 1,214,818 |
Other customers | 87,230 |
| | 90,753 |
| | 94,847 |
| Other customers | 85,302 | | | 84,382 | | 87,230 |
Total energy sales to customers | 21,323,889 |
| | 20,455,243 |
| | 20,516,576 |
| Total energy sales to customers | 20,840,536 | | | 20,704,280 | | | 21,323,889 | |
Sales to other utilities and marketers | 2,418,416 |
| | 2,604,329 |
| | 1,942,444 |
| Sales to other utilities and marketers | 3,740,016 | | | 3,096,029 | | 2,418,416 |
Total energy sales, MWh | 23,742,305 |
| | 23,059,572 |
| | 22,459,020 |
| Total energy sales, MWh | 24,580,552 | | | 23,800,309 | | | 23,742,305 | |
Transportation, including unbilled | 2,001,244 |
| | 2,085,574 |
| | 2,012,827 |
| Transportation, including unbilled | 2,322,021 | | | 2,028,727 | | 2,001,244 |
Electric energy sales and transportation, MWh | 25,743,549 |
| | 25,145,146 |
| | 24,471,847 |
| 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 | $ | 1,232,075 |
| | $ | 1,138,871 |
| | $ | 1,061,117 |
| Residential | $ | 1,139,356 | | | $ | 1,147,260 | | | $ | 1,232,075 | |
Commercial | 892,360 |
| | 872,057 |
| | 867,786 |
| Commercial | 854,910 | | | 885,457 | | 892,360 |
Industrial | 112,817 |
| | 113,469 |
| | 114,223 |
| Industrial | 105,020 | | | 110,607 | | 112,817 |
Other customers | 19,729 |
| | 20,045 |
| | 20,216 |
| Other customers | 18,408 | | | 18,718 | | 19,729 |
Total operating revenue from customers | 2,256,981 |
| | 2,144,442 |
| | 2,063,342 |
| Total operating revenue from customers | 2,117,694 | | | 2,162,042 | | | 2,256,981 | |
Transportation, including unbilled | 12,584 |
| | 10,937 |
| | 10,143 |
| Transportation, including unbilled | 19,512 | | | 13,878 | | 12,584 |
Sales to other utilities and marketers | 53,789 |
| | 50,124 |
| | 46,666 |
| Sales to other utilities and marketers | 109,105 | | | 89,324 | | 53,789 |
Decoupling revenue | 9,975 |
| | 29,968 |
| | 13,630 |
| Decoupling revenue | 15,673 | | | 13,530 | | 9,975 |
Other decoupling revenue1 | (27,706 | ) | | (21,168 | ) | | (16,634 | ) | Other decoupling revenue1 | (6,866) | | | (5,475) | | (27,706) |
Miscellaneous operating revenue | 115,040 |
| | 24,189 |
| | 11,321 |
| Miscellaneous operating revenue | 241,923 | | | 182,620 | | 115,040 |
Total electric operating revenue | $ | 2,420,663 |
| | $ | 2,238,492 |
| | $ | 2,128,468 |
| Total electric operating revenue | $ | 2,497,041 | | | $ | 2,455,919 | | | $ | 2,420,663 | |
Number of customers served (average): | |
| | |
| | |
| Number of customers served (average): | | | | | |
Residential | 998,078 |
| | 984,739 |
| | 970,830 |
| Residential | 1,025,024 | | | 1,010,574 | | 998,078 |
Commercial | 126,829 |
| | 125,067 |
| | 123,072 |
| Commercial | 129,944 | | | 128,845 | | 126,829 |
Industrial | 3,399 |
| | 3,425 |
| | 3,434 |
| Industrial | 3,328 | | | 3,362 | | 3,399 |
Other | 6,722 |
| | 6,472 |
| | 6,283 |
| Other | 7,323 | | | 6,992 | | 6,722 |
Transportation | 16 |
| | 16 |
| | 16 |
| Transportation | 80 | | | 16 | | 16 |
Total customers | 1,135,044 |
| | 1,119,719 |
| | 1,103,635 |
| 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, | |
| | 2017 | | 2016 | | 2015 | | 2019 | | 2018 | | 2017 |
Average kWh used per customer: | | | | |
| | |
| Average kWh used per customer: | | | | | |
Residential | | 10,953 |
| | 10,404 |
| | 10,470 |
| Residential | 10,494 | | | 10,388 | | | 10,953 | |
Commercial | | 71,670 |
| | 71,129 |
| | 73,120 |
| Commercial | 68,010 | | 69,329 | | 71,670 |
Industrial | | 357,404 |
| | 357,143 |
| | 366,324 |
| Industrial | 348,903 | | 353,905 | | 357,404 |
Other | | 12,977 |
| | 14,022 |
| | 15,096 |
| Other | 11,649 | | 12,068 | | 12,977 |
Average revenue per customer: | | | | | | | Average revenue per customer: | | | | | |
Residential | | $ | 1,234 |
| | $ | 1,157 |
| | $ | 1,093 |
| Residential | $ | 1,112 | | | $ | 1,135 | | | $ | 1,234 | |
Commercial | | 7,036 |
| | 6,973 |
| | 7,051 |
| Commercial | 6,579 | | 6,872 | | 7,036 |
Industrial | | 33,191 |
| | 33,130 |
| | 33,262 |
| Industrial | 31,556 | | 32,899 | | 33,191 |
Other | | 2,935 |
| | 3,097 |
| | 3,218 |
| Other | 2,514 | | 2,677 | | 2,935 |
Average retail revenue per kWh sold: | | | | | | | Average retail revenue per kWh sold: | | | | | |
Residential | | $ | 0.1127 |
| | $ | 0.1112 |
| | $ | 0.1044 |
| Residential | $ | 0.1059 | | | $ | 0.1093 | | | $ | 0.1127 | |
Commercial | | 0.0982 |
| | 0.0980 |
| | 0.0964 |
| Commercial | 0.0967 | | 0.0991 | | 0.0982 |
Industrial | | 0.0929 |
| | 0.0928 |
| | 0.0908 |
| Industrial | 0.0904 | | 0.0930 | | 0.0929 |
Other | | 0.2262 |
| | 0.2209 |
| | 0.2131 |
| Other | 0.2158 | | 0.2218 | | 0.2262 |
Average retail revenue per kWh sold | | $ | 0.1058 |
| | $ | 0.1048 |
| | $ | 0.1006 |
| Average retail revenue per kWh sold | $ | 0.1016 | | | $ | 0.1044 | | | $ | 0.1058 | |
Heating degree days | | 4,584 |
| | 3,823 |
| | 3,800 |
| Heating degree days | 4,208 | | | 4,065 | | 4,584 |
Percent of normal - NOAA2 30-year average | | 97.2 | % | | 81.0 | % | | 80.5 | % | Percent of normal - NOAA2 30-year average | 89.6 | % | | 86.2 | % | | 97.2 | % |
Load factor3 | | 51.6 | % | | 56.2 | % | | 56.2 | % | Load factor3 | 61.6 | % | | 64.2 | % | | 51.6 | % |
_______________
| |
2
| National Oceanic and Atmospheric Administration (NOAA). |
| |
3
| 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, 2017,2019, 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 4,7374,733 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, 20172019, and 2016:2018: | | | Peak Power Resources At December 31, | | Energy Production At December 31, | |
` | | ` | Peak Power Resources At December 31, | | | Energy Production At December 31, | |
| 2017 | | 2016 | | 2017 | | 2016 | | 2019 | | | 2018 | | | 2019 | | | 2018 | |
| MW | | % | | MW | | % | | MWh | | % | | MWh | | % | | MW | | % | | MW | | % | | MWh | | % | | MWh | | % |
Purchased resources: | | | | | | | | | | | | | | | | Purchased resources: | | | | | | | | | | | | | | | | | | | |
Columbia River PUD contracts | 711 |
| | 15.0 | % | | 708 |
| | 14.6 | % | | 3,355,134 |
| | 13.3 | % | | 3,371,827 |
| | 13.7 | % | |
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 | 72 |
| | 1.5 |
| | 79 |
| | 1.6 |
| | 281,619 |
| | 1.1 |
| | 365,670 |
| | 1.5 |
| Other hydroelectric | 72 | | | 1.5 | | | 72 | | 1.5 | | | 272,653 | | 1.0 | | | 315,948 | | 1.2 | |
Other producers | 284 |
| | 6.0 |
| | 387 |
| | 8.0 |
| | 3,679,623 |
| | 14.6 |
| | 2,999,171 |
| | 12.1 |
| Other producers | 285 | | | 6.0 | | | 284 | | 6.2 | | | 3,276,502 | | 12.7 | | | 3,406,627 | | 13.6 | |
Wind | 56 |
| | 1.2 |
| | 56 |
| | 1.2 |
| | 119,690 |
| | 0.5 |
| | 138,148 |
| | 0.6 |
| Wind | 56 | | | 1.2 | | | 56 | | 1.2 | | | 123,368 | | 0.5 | | | 131,270 | | 0.5 | |
Short-term wholesale energy purchases | N/A |
| | — |
| | N/A |
| | — |
| | 7,049,060 |
| | 27.8 |
| | 6,154,767 |
| | 25.0 |
| Short-term wholesale energy purchases | N/A | | | — | | | N/A | | N/A | | | 6,144,663 | | 23.7 | | | 6,822,927 | | 26.9 | |
Total purchased | 1,123 |
| | 23.7 | % | | 1,230 |
| | 25.4 | % | | 14,485,126 |
| | 57.3 | % | | 13,029,583 |
| | 52.9 | % | 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 |
| | 5.4 | % | | 254 |
| | 5.2 | % | | 864,821 |
| | 3.4 | % | | 933,522 |
| | 3.8 | % | Hydroelectric | 250 | | | 5.3% | | | 250 | | 5.3% | | | 712,727 | | 2.8% | | | 914,540 | | 3.6% | |
Coal | 677 |
| | 14.3 |
| | 677 |
| | 14.0 |
| | 4,463,705 |
| | 17.6 |
| | 4,529,179 |
| | 18.4 |
| |
Coal3 | | Coal3 | 677 | | | 14.3 | | | 677 | | 14.4 | | | 4,347,639 | | 16.8 | | | 4,184,950 | | 16.5 | |
Natural gas/oil | 1,908 |
| | 40.3 |
| | 1,908 |
| | 39.4 |
| | 3,822,462 |
| | 15.1 |
| | 4,152,205 |
| | 16.9 |
| Natural gas/oil | 1,931 | | | 40.8 | | | 1,908 | | 40.6 | | | 6,692,188 | | 25.9 | | | 4,152,359 | | 16.4 | |
Wind | 773 |
| | 16.3 |
| | 773 |
| | 16.0 |
| | 1,674,790 |
| | 6.6 |
| | 1,962,702 |
| | 8.0 |
| Wind | 773 | | | 16.3 | | | 773 | | 16.5 | | | 1,667,489 | | 6.4 | | | 1,932,378 | | 7.6 | |
Other1 | 2 |
| | — |
| | 2 |
| | — |
| | — |
| | — |
| | — |
| | — |
| |
Other2 | | Other2 | 2 | | | — | | | 2 | | — | | | — | | — | | | — | | — | |
Total company-controlled | 3,614 |
| | 76.3 | % | | 3,614 |
| | 74.6 | % | | 10,825,778 |
| | 42.7 | % | | 11,577,608 |
| | 47.1 | % | Total company-controlled | 3,633 | | | 76.8% | | | 3,610 | | 76.8% | | | 13,420,043 | | 51.9% | | | 11,184,227 | | 44.1% | |
Total resources | 4,737 |
| | 100.0 | % | | 4,844 |
| | 100.0 | % | | 25,310,904 |
| | 100.0 | % | | 24,607,191 |
| | 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 746.5 and 250.0 MWh as of December 31, 2017 and 2016, respectively. |
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, 2017,2019, 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 | | |
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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 2017,2019, approximately 13.3%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, 2017,2019, 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 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 Project1 | 2028 | | 2052 | | 29.9 | % | | 251 |
|
Grant County PUD: | | | | | | | |
Priest Rapids Development | 2052 | | 2052 | | 0.6 | % | | 6 |
|
Wanapum Development | 2052 | | 2052 | | 0.6 | % | | 7 |
|
Total | | | | | | | 745 |
|
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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. |
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 had seasonal energy and capacity exchange agreements with the Bonneville Power Administration (BPA) for 44 aMW of capacity which expired 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 600450 MW of existing BPA transmission solely for the EIM market. Participation has resulted in reduced costs for PSE customers of approximately $10.0$16.2 million per annum, enhanced system reliability, integration of variable energy resources, and 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 2017,2019, PSE had 4,6464,797 MW and 595 MW of total transmission demand contracted with the BPA and other utilities, respectively. Additionally, PSE contracted with BPA for an additional 53 MW of transmission demand that went into effect from May to November of 2017. 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 2017, PSE purchased approximately 69.9% of its natural gas in British Columbia, 21.8% in Alberta and 8.3% 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 2017However, 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 14,15, 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 conservation projections from the 2017 and identifiedIRP, the following capacity shortfalls and surpluses:surpluses are:
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| | | | | | | | | |
| 2018 | | 2019 | | 2020 | | 2021 | | 2022 |
Projected MW shortfall/(surplus) | (73) | | (34) | | (121) | | (128) | | 192 |
| | | | | | | | | | | | | | | | | | | | | | | | | | |
| | 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 2017 IRP. PSE projects that beginning in 2022 its future energy needs will exceed current resources in its supply portfolio becauseAs part of the retirementCETA, PSE must achieve sales with renewable or non-emitting resources of Colstrip Units 1at least 80% by 2030 and 2, approximately 307 MW of capacity. Therefore, PSE’s100% by 2045. The 2021 IRP sets forth a multi-part strategy of implementing energy efficiency programs and pursuing additional renewable resources and additional capacity resources such as battery storage and generation plants that operate during peak loads. If PSE cannot acquire needed energy supply resources at a reasonable cost, it may be required to purchase additional power inwill fully explore the wholesale market. These purchases are subject to the sharing bandsimplementation of the PCA mechanism, at a cost that could, inCETA. PSE is currently pursuing resource acquisitions to meet the absence of regulatory relief, increase its expenses and reduce earnings and cash flows.current capacity shortfall projections.
NATURAL GAS UTILITY OPERATING STATISTICS
| | | | | | | | | | Year Ended December 31, | |
| Year Ended December 31, | | 2019 | | 2018 | | 2017 |
| 2017 | | 2016 | | 2015 | |
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 | $ | 686,438 |
| | $ | 578,955 |
| | $ | 597,572 |
| Residential | $ | 613,617 | | | $ | 598,923 | | | $ | 686,438 | |
Commercial firm | 251,584 |
| | 213,138 |
| | 239,849 |
| Commercial firm | 218,302 | | 219,390 | | 251,584 |
Industrial firm | 20,077 |
| | 17,753 |
| | 21,533 |
| Industrial firm | 15,698 | | 17,247 | | 20,077 |
Interruptible | 24,317 |
| | 24,447 |
| | 29,082 |
| Interruptible | 18,381 | | 21,113 | | 24,317 |
Total retail natural gas sales | 982,416 |
| | 834,293 |
| | 888,036 |
| Total retail natural gas sales | 865,998 | | | 856,673 | | | 982,416 | |
Transportation services | 21,718 |
| | 20,322 |
| | 18,666 |
| Transportation services | 20,283 | | 19,984 | | 21,718 |
Decoupling revenue | 3,522 |
| | 52,114 |
| | 51,981 |
| Decoupling revenue | 2,296 | | 6,115 | | 3,522 |
Other decoupling revenue1 | (22,862 | ) | | (28,761 | ) | | (26,038 | ) | Other decoupling revenue1 | (29,737) | | (37,022) | | (22,862) |
Other | 12,965 |
| | 12,542 |
| | 14,904 |
| Other | 16,531 | | 4,998 | | 12,965 |
Total natural gas operating revenue | $ | 997,759 |
| | $ | 890,510 |
| | $ | 947,549 |
| Total natural gas operating revenue | $ | 875,371 | | | $ | 850,748 | | | $ | 997,759 | |
Number of customers served (average): | |
| | |
| | |
| Number of customers served (average): | | | | | |
Residential | 761,010 |
| | 749,586 |
| | 737,339 |
| Residential | 782,413 | | 772,130 | | 761,010 |
Commercial firm | 55,372 |
| | 54,992 |
| | 54,646 |
| Commercial firm | 56,113 | | 55,716 | | 55,372 |
Industrial firm | 2,330 |
| | 2,371 |
| | 2,378 |
| Industrial firm | 2,304 | | 2,308 | | 2,330 |
Interruptible | 398 |
| | 410 |
| | 429 |
| Interruptible | 367 | | 393 | | 398 |
Transportation | 226 |
| | 227 |
| | 221 |
| Transportation | 230 | | 234 | | 226 |
Total customers | 819,336 |
| | 807,586 |
| | 795,013 |
| Total customers | 841,427 | | | 830,781 | | | 819,336 | |
Natural gas volumes, therms (thousands): | |
| | |
| | |
| Natural gas volumes, therms (thousands): | | | | | |
Residential | 621,915 |
| | 521,771 |
| | 492,997 |
| Residential | 605,313 | | 571,265 | | 621,915 |
Commercial firm | 279,656 |
| | 233,586 |
| | 230,507 |
| Commercial firm | 277,639 | | 264,775 | | 279,656 |
Industrial firm | 25,500 |
| | 22,783 |
| | 23,777 |
| Industrial firm | 22,915 | | 23,890 | | 25,500 |
Interruptible | 49,249 |
| | 49,533 |
| | 43,931 |
| Interruptible | 45,176 | | 47,275 | | 49,249 |
Total retail natural gas volumes, therms | 976,320 |
| | 827,673 |
| | 791,212 |
| Total retail natural gas volumes, therms | 951,043 | | | 907,205 | | | 976,320 | |
Transportation volumes | 236,578 |
| | 230,724 |
| | 220,392 |
| Transportation volumes | 227,657 | | 230,735 | | 236,578 |
Total volumes | 1,212,898 |
| | 1,058,397 |
| | 1,011,604 |
| Total volumes | 1,178,700 | | | 1,137,940 | | | 1,212,898 | |
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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, |
| 2017 | | 2016 | | 2015 |
Working natural gas volumes in storage at year end, therms (thousands): | |
| | |
| | |
|
Jackson Prairie | 86,051 |
| | 86,374 |
| | 78,337 |
|
Clay Basin | 45,854 |
| | 63,136 |
| | 54,199 |
|
Average therms used per customer: | | | | | |
|
Residential | 817 |
| | 696 |
| | 669 |
|
Commercial firm | 5,050 |
| | 4,248 |
| | 4,218 |
|
Industrial firm | 10,944 |
| | 9,609 |
| | 9,999 |
|
Interruptible | 123,742 |
| | 120,812 |
| | 102,403 |
|
Transportation | 1,046,806 |
| | 1,016,406 |
| | 997,249 |
|
Average revenue per customer: | |
| | |
| | |
|
Residential | $ | 902 |
| | $ | 772 |
| | $ | 810 |
|
Commercial firm | 4,544 |
| | 3,876 |
| | 4,389 |
|
Industrial firm | 8,617 |
| | 7,488 |
| | 9,055 |
|
Interruptible | 61,098 |
| | 59,626 |
| | 67,791 |
|
Transportation | 96,099 |
| | 89,524 |
| | 84,460 |
|
Average revenue per therm sold: | |
| | |
| | |
|
Residential | $ | 1.104 |
| | $ | 1.110 |
| | $ | 1.212 |
|
Commercial firm | 0.900 |
| | 0.912 |
| | 1.041 |
|
Industrial firm | 0.787 |
| | 0.779 |
| | 0.906 |
|
Interruptible | 0.494 |
| | 0.494 |
| | 0.662 |
|
Average retail revenue per therm sold | $ | 1.006 |
| | $ | 1.008 |
| | $ | 1.122 |
|
Transportation | 0.092 |
| | 0.088 |
| | 0.085 |
|
Heating degree days | 4,584 |
| | 3,823 |
| | 3,800 |
|
Percent of normal - NOAA 30-year average | 97.2 | % | | 81.0 | % | | 80.5 | % |
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, LLC (NWP), the sole interstate pipeline delivering directly into PSE’s service territory. Accordingly, delivery of natural gas supply to PSE’s natural gas system is dependent upon the reliable operations of NWP.
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 2017, PSE purchased approximately 54.8% of its natural gas for its natural gas customers in British Columbia, 19.1% in Alberta and 26.1% 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 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. 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 640,600 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 12.9 million Dth of Clay Basin storage capacity and approximately 107,400 Dth per day of firm withdrawal capacity under two long-term contracts with remaining terms of twoone 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; 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.
Tacoma LNG Facility
Currently under construction at the Port of Tacoma, the Tacoma LNG facility is expected to be operational in 2019. On2021. In January 24, 2018, the Puget Sound Clean Air Agency’sAgency (PSCAA) determined a Supplemental Environmental Impact Statement is(SEIS) was necessary in order to rule on the air quality permit for the facility. As a result of requiring a Supplemental Environmental Impact Statement, the Company's construction schedule may be impacted depending on the Puget Sound Clean Air Agency'sSEIS, PSCAA's timing and decision on the air quality permit. Ifpermit delayed the Company's construction scheduleschedule. 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 costs may be adversely impacted. Thenonprofit law firm Earthjustice. When completed, the Tacoma LNG facility willis designed to provide peak-shaving services to PSE’s natural gas customers, and will provide LNG as fuel to transportation customers, particularly in the marine market. Pursuant to the Washington Commission’s order, PSE will be allocated 43.0% of the capital and operating costs, consistent with the regulated portion of the Tacoma LNG facility, and Puget LNG will be allocated the remaining 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 Enbridge 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 542,900 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 447,100 Dth per day of seasonal firm capacity on NWP to provide for delivery of natural gas stored at Jackson Prairie to natural gas customers. PSE holds approximately 217,900 Dth per day of firm transportation capacity on NWP to supply natural gas to its electric generating facilities. In addition, PSE holds over 34,200 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 2one to 2725 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 135,800 Dth per day under various contracts, with remaining terms of twofour to six years. PSE has other firm transportation capacity on Westcoast’s pipeline, which supplies the electric generating facilities, totaling 88,400 Dth per day, with remaining terms of threefour to six 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 79,000 Dth per day, with remaining terms of threefour to six 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 three to sixfour years. PSE’s firm transportation capacity for its natural gas customers on the GTN pipeline, totaling over 77,000 Dth per day, with remaining termsterm of sixfour 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 40,600 Dth per day, with remaining terms of threeone to sixfour years. PSE holds 259,000 decatherms per day of firm capacity on CNGC to connect 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 2017 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 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.
The EPA publishedFurther, Colstrip met 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 for the installation of controls. Colstrip met the 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 has considered 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 20162017 were 10.810.2 million metric tons of carbon dioxide equivalents. Approximately 43.0%43.7% of PSE’s total GHG emissions (approximately 4.64.5 million metric tons) are associated with PSE’s ownership and contractual interests in Colstrip.Colstrip (with the closure of Units 1&2 effective December 31, 2019, PSE expects an approximately 45% reduction in Colstrip GHG 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. OnIn 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 10, 2017, the EPA proposed to repeal thisthe 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 will accept comments until April 26, 2018. As such,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 monitoring the situation and awaitingevaluating the final determination byACE rule to determine its impact on operations pending the EPA.outcome of the 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 5.0% 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. On December 15, 2017,In March 2018, the Thurston County Superior Court invalidated the CAR. A final court order is pending andThe Department of Ecology appealed the Superior Court decision in May 2018. As a result of the meantime,appeal, direct review to the Washington State Department of Ecology, submitted a brief requesting severability, which would makeSupreme Court was granted and oral argument was held on March 16, 2019. In January 2020, the ruleWashington Supreme Court affirmed that CAR is not valid for industries with direct emissions. This would“indirect emitters” meaning it does not apply to the Company's electric utility thermal generation units but not to itssale of natural gas utility. Appeals couldfor use by customers. The court ruled, however, that the rule can be filedsevered and is valid for direct emitters including electric utilities with permitted air emission sources, but remanded the case back to the Thurston County Courtto determine which parts of Appeals after the court's finalrule survive. Meanwhile, the federal court litigation has been held in abeyance pending resolution of the state 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 a clean, affordable, and reliable energy future. The Clean Energy Transition Act requires all electric utilities to eliminate coal-fired generation from their allocation of electricity by December 31, 2025; to be carbon-neutral by January 1, 2030, through a combination of non-emitting electric generation, renewable generation, and/or alternative compliance options; and makes it the state policy that, by 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 2045 standard between 2030 and 2045, and lay out an actionable plan that they intend to pursue to meet the 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 law requires additional rulemaking by several Washington agencies for its ruling on severability.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 clean energy legislation through the regulatory process.
Regional Haze Rule
OnIn January 10, 2017, the EPA provided revisions to the Regional Haze Rule which were published in the Federal Register. Among other things, these revisions delayed new Regional Haze review from 2018 to 2021;2021, however, the end date will remain 2028. AspectsIn January 2018, the EPA announced that it would revisit certain aspects of these revisions and PSE is unable to predict the outcome. Challenges to the 2017 Regional Haze Revision Rule are currently being challenged by various entities nationwide and briefing has not yet been scheduled. Inpending in abeyance in the meantime, the stateU.S. Court of Montana has indicated plans to work on and submit a State Implementation PlanAppeals 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's) under the Resource Conservation and Recovery Act, Subtitle D. The EPA issued another rule, effective October 4, 2016, extending certain compliance deadlines under the CCR rule. 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, onin January 30, 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 March 1, 2018February 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 |
K. J. HarrisM. E. Kipp |
| 5352 |
| | 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 |
| 5961 |
| | Senior Vice President and Chief Financial Officer since November 2011 |
S. R. Secrist |
| 5658 |
| | 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 |
S. J. King |
| 3436 |
| | Controller and Principal Accounting Officer since November 2, 2017. Senior Manager (audited utility, technology and telecommunication companies) at PwCPricewaterhouseCoopers LLP (PwC), a public accounting firm, July 2016 - November 2017; Manager at PwC July 2013 - July 2016; Senior Associate at PwC July 2010 - July 20132016 |
The executive officers of PSE as of March 1, 2018February 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 |
K. J. HarrisM. E. Kipp |
| 5352 |
| | 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 |
| 5961 |
| | Senior Vice President and Chief Financial Officer since November 2011 |
B. K. Gilbertson |
| 5456 |
| | 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 |
| 5759 |
| | Senior Vice President and Chief Administrative Officer since February 2011 |
D. E. Mills |
| 6062 |
| | 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 |
| 5658 |
| | 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 |
S. J. King |
| 3436 |
| | Controller and Principal Accounting Officer since November 2, 2017. Senior Manager (audited utility, technology and telecommunication companies) at PwC July 2016 - November 2017; Manager at PwC July 2013 - July 2016; Senior Associate at PwC July 2010 - July 20132016 |
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 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 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 settlement agreement accepted by the Washington Commission on December 5, 2017 and effective December 19, 2017 provided for an updatedauthorized rate of return of 7.60%.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.
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.
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 the event of a deterioration of financial ratios, may increase Puget Energy's and PSE’s cost of borrowing or adversely affect the ability to access one or more financial markets.
The amount of the Company's debt could adversely affect its liquidity and results of operations. Puget Energy and PSE have short-term and long-term debt, and may incur additional debt (including secured debt) in the future. Puget Energy has access to a multi-year $800.0 million revolving credit facility, secured by substantially all of its assets, which has a maturity date of October 25, 2022.2023. There was $102.6$24.1 million outstanding under the facility as of December 31, 2017.2019. 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, 2022.2023. As of December 31, 2017,2019, 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, 2017,2019, had approximately $3.8$4.4 billion outstanding under first mortgage bonds, pollution control bonds senior notes and junior subordinatedsenior 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 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 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 particular, the Tax Cuts and Jobs Act which was enacted onin December 22, 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. The final interpretation and regulatory treatment of the tax reform changes is uncertain.
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 20182020 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���sCompany’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.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 6, 2009, pursuant to the terms of the Washington Commission merger order, PSE may not declare or pay dividends if PSE’s common equity ratio calculated on a regulatory basis is 44.0% or below, except to the extent a lower equity ratio is ordered by the Washington Commission. Also, pursuant to the merger order, PSE'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 48.0%48.4% at December 31, 20172019, and the EBITDA to interest expense was 5.55.3 to 1.0 for the twelve-months ended December 31, 2017.2019.
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.
Challenges relating to the construction or future operation of 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 2019,2021, 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 could 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, 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 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 2017, 20162019, 2018, and 2015,2017, 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 Item 7, "Management's Discussion and Analysis of Financial Condition and Results of Operation" of this Form 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) | 2017 | | 2016 | | 2015 | | 2014 | | 2013 |
Operating revenue | $ | 3,460,276 |
| | $ | 3,164,301 |
| | $ | 3,092,700 |
| | $ | 3,113,171 |
| | $ | 3,187,297 |
|
Operating income | 760,497 |
| | 785,384 |
| | 671,925 |
| | 577,851 |
| | 755,160 |
|
Net income | 175,194 |
| | 312,899 |
| | 241,179 |
| | 171,835 |
| | 285,728 |
|
| | | | | | | | | |
Total assets at year-end | $ | 13,690,789 |
| | $ | 13,266,380 |
| | $ | 12,814,254 |
| | $ | 12,637,946 |
| | $ | 12,781,672 |
|
Long-term debt | 5,207,929 |
| | 5,104,073 |
| | 5,077,518 |
| | 4,957,951 |
| | 4,943,577 |
|
Junior subordinated notes | 250,000 |
| | 250,000 |
| | 250,000 |
| | 250,000 |
| | 250,000 |
|
Capital lease obligations | 1,129 |
| | 645 |
| | 378 |
| | 9,473 |
| | 17,051 |
|
|
| | | | | | | | | | | | | | | | | | | |
Puget Sound Energy | | | | | | | | | |
Summary of Operations | Year Ended December 31, |
(Dollars in Thousands) | 2017 | | 2016 | | 2015 | | 2014 | | 2013 |
Operating revenue | $ | 3,460,276 |
| | $ | 3,164,618 |
| | $ | 3,093,258 |
| | $ | 3,116,123 |
| | $ | 3,187,335 |
|
Operating income | 748,609 |
| | 774,993 |
| | 656,138 |
| | 568,693 |
| | 735,574 |
|
Net income | 320,054 |
| | 380,581 |
| | 304,189 |
| | 236,614 |
| | 356,129 |
|
| | | | | | | | | |
Total assets at year-end | $ | 11,731,706 |
| | $ | 11,297,080 |
| | $ | 10,799,513 |
| | $ | 10,552,727 |
| | $ | 10,636,634 |
|
Long-term debt | 3,499,911 |
| | 3,497,298 |
| | 3,494,362 |
| | 3,484,571 |
| | 3,482,062 |
|
Junior subordinated notes | 250,000 |
| | 250,000 |
| | 250,000 |
| | 250,000 |
| | 250,000 |
|
Capital lease obligations | 1,129 |
| | 645 |
| | 378 |
| | 9,473 |
| | 17,051 |
|
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, 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, Macquarie Capital Group Limited, 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 MeasuresElectric 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 forecasted 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 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 is adjusted each year in May based on that year's assessed property taxes and true-up from the prior year.
Federal Incentive Tracker Tariff
The Federal Incentive Tracker Tariff passes through to customers the benefits associated with the wind-related treasury 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 federal 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 to 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.
Natural Gas Rate Filings
Natural Gas Cost Recovery Mechanism
The purpose of the cost recovery mechanism (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. Rates change annually on November 1.
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. Rates typically change annually on November 1, although out-of-cycle rate changes are allowed at other times of the 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 is adjusted each year in May based on that year's assessed property 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 compared to forecast conservation expenditures from the prior year, as well as actual compared 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.
ELECTRIC UTILITY OPERATING STATISTICS
| | | | | | | | | | | | | | | | | |
| Year Ended December 31, | | | | |
| 2019 | | 2018 | | 2017 |
Generation and purchased power, MWh | | | | | |
Company-controlled resources | 13,420,043 | | | 11,168,286 | | | 10,825,778 | |
Contracted resources | 6,752,261 | | | 7,654,872 | | 8,337,348 |
Non-firm energy purchased | 5,707,102 | | | 6,490,602 | | 6,147,778 |
Total generation and purchased power | 25,879,406 | | | 25,313,760 | | | 25,310,904 | |
Less: losses and Company use | (1,298,854) | | | (1,513,451) | | (1,568,599) |
Total energy sales, MWh | 24,580,552 | | | 23,800,309 | | | 23,742,305 | |
Electric energy sales, MWh | | | | | | |
Residential | 10,756,628 | | | 10,497,389 | | 10,931,999 |
Commercial | 8,837,457 | | | 8,932,681 | | 9,089,842 |
Industrial | 1,161,149 | | | 1,189,828 | | 1,214,818 |
Other customers | 85,302 | | | 84,382 | | 87,230 |
Total energy sales to customers | 20,840,536 | | | 20,704,280 | | | 21,323,889 | |
Sales to other utilities and marketers | 3,740,016 | | | 3,096,029 | | 2,418,416 |
Total energy sales, MWh | 24,580,552 | | | 23,800,309 | | | 23,742,305 | |
Transportation, including unbilled | 2,322,021 | | | 2,028,727 | | 2,001,244 |
Electric energy sales and transportation, MWh | 26,902,573 | | | 25,829,036 | | | 25,743,549 | |
Electric operating revenue by classes | | | | | |
(Dollars in Thousands) | | | | | |
Residential | $ | 1,139,356 | | | $ | 1,147,260 | | | $ | 1,232,075 | |
Commercial | 854,910 | | | 885,457 | | 892,360 |
Industrial | 105,020 | | | 110,607 | | 112,817 |
Other customers | 18,408 | | | 18,718 | | 19,729 |
Total operating revenue from customers | 2,117,694 | | | 2,162,042 | | | 2,256,981 | |
Transportation, including unbilled | 19,512 | | | 13,878 | | 12,584 |
Sales to other utilities and marketers | 109,105 | | | 89,324 | | 53,789 |
Decoupling revenue | 15,673 | | | 13,530 | | 9,975 |
Other decoupling revenue1 | (6,866) | | | (5,475) | | (27,706) |
Miscellaneous operating revenue | 241,923 | | | 182,620 | | 115,040 |
Total electric operating revenue | $ | 2,497,041 | | | $ | 2,455,919 | | | $ | 2,420,663 | |
Number of customers served (average): | | | | | |
Residential | 1,025,024 | | | 1,010,574 | | 998,078 |
Commercial | 129,944 | | | 128,845 | | 126,829 |
Industrial | 3,328 | | | 3,362 | | 3,399 |
Other | 7,323 | | | 6,992 | | 6,722 |
Transportation | 80 | | | 16 | | 16 |
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.
ELECTRIC UTILITY OPERATING STATISTICS (Continued)
| | | | | | | | | | | | | | | | | |
| Year Ended December 31, | | | | |
| 2019 | | 2018 | | 2017 |
Average kWh used per customer: | | | | | |
Residential | 10,494 | | | 10,388 | | | 10,953 | |
Commercial | 68,010 | | 69,329 | | 71,670 |
Industrial | 348,903 | | 353,905 | | 357,404 |
Other | 11,649 | | 12,068 | | 12,977 |
Average revenue per customer: | | | | | |
Residential | $ | 1,112 | | | $ | 1,135 | | | $ | 1,234 | |
Commercial | 6,579 | | 6,872 | | 7,036 |
Industrial | 31,556 | | 32,899 | | 33,191 |
Other | 2,514 | | 2,677 | | 2,935 |
Average retail revenue per kWh sold: | | | | | |
Residential | $ | 0.1059 | | | $ | 0.1093 | | | $ | 0.1127 | |
Commercial | 0.0967 | | 0.0991 | | 0.0982 |
Industrial | 0.0904 | | 0.0930 | | 0.0929 |
Other | 0.2158 | | 0.2218 | | 0.2262 |
Average retail revenue per kWh sold | $ | 0.1016 | | | $ | 0.1044 | | | $ | 0.1058 | |
Heating degree days | 4,208 | | | 4,065 | | 4,584 |
Percent of normal - NOAA2 30-year average | 89.6 | % | | 86.2 | % | | 97.2 | % |
Load factor3 | 61.6 | % | | 64.2 | % | | 51.6 | % |
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2.National Oceanic and Atmospheric Administration (NOAA).
3.Average megawatt (aMW) usage by customers divided by their maximum usage.
Electric Supply
At December 31, 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 4,733 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 discussiontable shows PSE’s electric energy supply resources and energy production for the years ended December 31, 2019, and 2018:
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
` | Peak Power Resources At December 31, | | | | | | | | Energy Production At December 31, | | | | | | |
| 2019 | | | | 2018 | | | | 2019 | | | | 2018 | | |
| MW | | % | | MW | | % | | MWh | | % | | MWh | | % |
Purchased resources: | | | | | | | | | | | | | | | | | | | |
Columbia River PUD contracts1 | 687 | | | 14.5% | | | 674 | | 14.3% | | | 2,642,177 | | 10.2% | | | 3,468,702 | | 13.7% | |
Other hydroelectric | 72 | | | 1.5 | | | 72 | | 1.5 | | | 272,653 | | 1.0 | | | 315,948 | | 1.2 | |
Other producers | 285 | | | 6.0 | | | 284 | | 6.2 | | | 3,276,502 | | 12.7 | | | 3,406,627 | | 13.6 | |
Wind | 56 | | | 1.2 | | | 56 | | 1.2 | | | 123,368 | | 0.5 | | | 131,270 | | 0.5 | |
Short-term wholesale energy purchases | N/A | | | — | | | N/A | | N/A | | | 6,144,663 | | 23.7 | | | 6,822,927 | | 26.9 | |
Total purchased | 1,100 | | | 23.2% | | | 1,086 | | | 23.2% | | | 12,459,363 | | | 48.1% | | | 14,145,474 | | | 55.9% | |
Company-controlled resources: | | | | | | | | | | | | | | | | | | | |
Hydroelectric | 250 | | | 5.3% | | | 250 | | 5.3% | | | 712,727 | | 2.8% | | | 914,540 | | 3.6% | |
Coal3 | 677 | | | 14.3 | | | 677 | | 14.4 | | | 4,347,639 | | 16.8 | | | 4,184,950 | | 16.5 | |
Natural gas/oil | 1,931 | | | 40.8 | | | 1,908 | | 40.6 | | | 6,692,188 | | 25.9 | | | 4,152,359 | | 16.4 | |
Wind | 773 | | | 16.3 | | | 773 | | 16.5 | | | 1,667,489 | | 6.4 | | | 1,932,378 | | 7.6 | |
Other2 | 2 | | | — | | | 2 | | — | | | — | | — | | | — | | — | |
Total company-controlled | 3,633 | | | 76.8% | | | 3,610 | | 76.8% | | | 13,420,043 | | 51.9% | | | 11,184,227 | | 44.1% | |
Total resources | 4,733 | | | 100.0% | | | 4,696 | | | 100.0% | | | 25,879,406 | | | 100.0% | | | 25,329,701 | | | 100.0% | |
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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, 2019, PSE owns the following plants with an aggregate net generating capacity of 3,633 MW:
| | | | | | | | | | | | | | | | | | | | |
Plant Name | | Plant Type | | Net Maximum Capacity (MW)1 | | Year Installed |
Colstrip Units 3 & 4 (25% interest) | | Coal | | 370 | | 1984 & 1986 |
Colstrip Units 1 & 2 (50% interest)2 | | Coal | | 307 | | 1975 & 1976 |
Mint Farm | | Natural gas combined cycle | | 320 | | 2007; acquired 2008; upgraded 2017 |
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 2005 |
Lower Snake River | | Wind | | 343 | | 2012 |
Wild Horse | | Wind | | 273 | | 2006 & 2009 |
Hopkins Ridge | | Wind | | 157 | | 2005 & 2008 |
Fredonia Units 1 & 2 | | Dual-fuel combustion turbines | | 207 | | 1984 |
Frederickson Units 1 & 2 | | 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 |
Ferndale | | Natural gas co-generation | | 253 | | 1994; acquired 2012 |
Encogen | | Natural gas co-generation | | 165 | | 1993; acquired 1999 |
Sumas | | Natural gas co-generation | | 127 | | 1993; acquired 2008 |
Upper Baker River | | Hydroelectric | | 91 | | 1959; unit 2 upgraded 1997 |
Lower Baker River | | Hydroelectric | | 105 | | 1925: reconstructed 1960; upgraded 2001 and 2013 |
Snoqualmie Falls3 | | Hydroelectric | | 54 | | 1898 to 1911 & 1957; rebuilt 2013 |
Crystal Mountain | | Internal combustion | | 3 | | 1969 |
Glacier Battery Storage | | Lithium Iron Phosphate | | 2 | | 2016 |
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. 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 2019, approximately 10.2% of PSE’s energy supply 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’s payments are not contingent upon the projects being operable.
As of December 31, 2019, PSE's portion of the power output of the PUDs’ projects are 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 |
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 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 has resulted in reduced costs for PSE customers of approximately $16.2 million per annum, enhanced system reliability, integration of variable energy resources, and 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 2019, PSE had 4,797 MW and 595 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 through gas-fired generation. Supplies range from long-term to daily agreements, as turbine 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.
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. However, 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 15, 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 conservation projections from the 2017 IRP, the capacity shortfalls and surpluses are:
| | | | | | | | | | | | | | | | | | | | | | | | | | |
| | 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 2017 IRP. As part of the CETA, PSE must 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 implementation of the CETA. PSE is currently pursuing resource acquisitions to meet the current capacity shortfall projections.
NATURAL GAS UTILITY OPERATING STATISTICS
| | | | | | | | | | | | | | | | | |
| Year Ended December 31, | | | | |
| 2019 | | 2018 | | 2017 |
Natural gas operating revenue by classes (Dollars in Thousands): | | | | | |
Residential | $ | 613,617 | | | $ | 598,923 | | | $ | 686,438 | |
Commercial firm | 218,302 | | 219,390 | | 251,584 |
Industrial firm | 15,698 | | 17,247 | | 20,077 |
Interruptible | 18,381 | | 21,113 | | 24,317 |
Total retail natural gas sales | 865,998 | | | 856,673 | | | 982,416 | |
Transportation services | 20,283 | | 19,984 | | 21,718 |
Decoupling revenue | 2,296 | | 6,115 | | 3,522 |
Other decoupling revenue1 | (29,737) | | (37,022) | | (22,862) |
Other | 16,531 | | 4,998 | | 12,965 |
Total natural gas operating revenue | $ | 875,371 | | | $ | 850,748 | | | $ | 997,759 | |
Number of customers served (average): | | | | | |
Residential | 782,413 | | 772,130 | | 761,010 |
Commercial firm | 56,113 | | 55,716 | | 55,372 |
Industrial firm | 2,304 | | 2,308 | | 2,330 |
Interruptible | 367 | | 393 | | 398 |
Transportation | 230 | | 234 | | 226 |
Total customers | 841,427 | | | 830,781 | | | 819,336 | |
Natural gas volumes, therms (thousands): | | | | | |
Residential | 605,313 | | 571,265 | | 621,915 |
Commercial firm | 277,639 | | 264,775 | | 279,656 |
Industrial firm | 22,915 | | 23,890 | | 25,500 |
Interruptible | 45,176 | | 47,275 | | 49,249 |
Total retail natural gas volumes, therms | 951,043 | | | 907,205 | | | 976,320 | |
Transportation volumes | 227,657 | | 230,735 | | 236,578 |
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.
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 | % |
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, LLC (NWP), the sole interstate pipeline delivering directly into PSE’s service territory. Accordingly, delivery of natural gas supply to PSE’s natural gas system is dependent upon the reliable operations of NWP.
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 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.
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 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 designates 397,100 Dth per day of the firm withdrawal capacity and over 9.2 million Dth of storage capacity to serve natural gas 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 640,600 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 12.9 million Dth of Clay Basin storage capacity and approximately 107,400 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.
LNG and Propane-Air Resources
LNG and propane-air resources provide firm natural gas supply on short notice for short periods of time. Due to their typically high cost and slow cycle times, these resources are normally utilized as a last resort supply source in extreme peak-demand periods, typically during the coldest hours or days.
PSE holds a contract for LNG storage services of 241,700 Dth of PSE-owned natural gas at Plymouth, with a maximum daily deliverability of 70,500 Dth for use of the PSE generation 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 holds 15,000 Dth/day of firm pipeline capacity from Plymouth for the generation fleet. The balance of the LNG capacity is 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; however, it is temporarily out-of-service pending planned environmental 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.
Tacoma LNG Facility
Currently under construction at the Port of Tacoma, the Tacoma LNG facility is expected to be operational in 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, PSE will be allocated 43.0% of the capital and operating costs, consistent with the regulated portion of the Tacoma LNG facility, and Puget LNG will be allocated the remaining 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 Enbridge Westcoast Energy (Westcoast). GTN, NOVA, and Foothills are all TC 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 542,900 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 447,100 Dth per day of seasonal firm capacity on NWP to provide for delivery of natural gas stored at Jackson Prairie to natural gas customers. PSE holds approximately 217,900 Dth per day of firm transportation capacity on NWP to supply natural gas to its electric generating facilities. In addition, PSE holds over 34,200 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 one to 25 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 135,800 Dth per day under various contracts, with remaining terms of four to six years. PSE has other firm transportation capacity on Westcoast’s pipeline, which supplies the electric generating facilities, totaling 88,400 Dth per day, with remaining terms of four to six 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 79,000 Dth per day, with remaining terms of four to six 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 term of four years. PSE’s firm transportation capacity for its natural gas customers on the GTN pipeline, totaling over 77,000 Dth per day, with remaining term of four 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 40,600 Dth per day, with remaining terms of one to four years. PSE holds 259,000 decatherms per day of firm capacity on CNGC to connect 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 preparedand 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 accordance with U.S. Generally Accepted Accounting Principles (GAAP)2017 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 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 returnthird-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 equity (ROE) excluding unrealized gainshandling and lossesdisposing 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 derivative instruments (net income plus unrealized losses and/drainage, facility or minus unrealized gainsconstruction 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 derivative instruments divided bya rolling twelve-month average, common equity) thatwas 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 considered a “non-GAAP financial measure.” Generally, a non-GAAP financial measuresubject to the State Environmental Policy Act, and may be subject to the federal National Environmental Policy Act, if there is a numerical measurefederal 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 company’s financial performance, financial positionfederal, state or cash flows that includes adjustments that resultlocal 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 takes seriously environmental stewardship, implementing both short-term measures and long-term strategies designed to manage greenhouse gas emissions in a departure from GAAP presentation.scientifically sound and responsible fashion. The Company believes that returnhas worked closely with federal, state and local governments on averagedeep decarbonization, and the reduction and mitigation of monthly averages (AMA) equity, alsogreenhouse gases. As a non-GAAP measure, is a more suitable metric for comparing ROE across yearsresult, the Company intends 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 notexpects be comparable to other companies' ROE measures. Furthermore, this measure is not intended to replace ROE (GAAP net income dividedzero methane emissions by GAAP average common equity) as an indicator of operating performance.
The following table presents PSE’s ROE, its return on AMA equity2022, coal free by 2025 and its authorized regulated ROEelectric 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 2017maritime and 2016:
|
| | | | | | | | | | | |
| 2017 | | | | 2016 |
(Dollars in Thousands) | Earnings | | Average Common Equity | | Return on Equity | | Earnings | | Average Common Equity | | Return on Equity |
Return on equity | $320,054 | | $3,545,686 | | 9.0% | | $380,581 | | $3,426,620 | | 11.1% |
Less/Plus: Unrealized gains and losses on derivative instruments, after-tax | 20,014 | | — | | * | | (54,467) | | — | | * |
Less/Plus: Equity adjustments1 | — | | 169,298 | | * | | — | | 177,196 | | * |
Plus: Impact of average of monthly average (AMA) | — | | 78,793 | | * | | — | | 57,212 | | * |
Return on AMA equity | $340,068 | | $3,793,777 | | 9.0% | | $326,114 | | $3,661,028 | | 8.9% |
Authorized regulated return on equity2 | | | | | 9.8% | | | | | | 9.8% |
_______________
| |
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 changed to 9.5% effective December 19, 2017, per the approved GRC. |
| |
*
| Not meaningful and/or applicable. |
commercial transportation. PSE also remains mindful of our customers' expectation of reliable, affordable service. The Company’s 2017 return on AMA equity was 9.0%, which is lower thanCompany considers the authorized regulated ROE primarily due to the following:
Regulated equity (rate base time's equity percent) was $478.0 million lower than AMA equity for the year ended December 31, 2017. The variance was primarily driven by the impact on rate basecost of the deferred tax liability for utility, plant and equipment. The impact on ROE for this variance was negative 1.2%.
Rates are based on an assumption of normal weather. The amount of variance duedecarbonization efforts to weather was $13.2 million, which resulteddate, as well as future efforts in an impact on ROE of positive 0.3%.
Depreciation expense was $24.8 million higher than the amount allowed in rates for the year ended December 31, 2017 for an impact on ROE of negative 0.7%.
Partially offsetting the above was net revenue from below the line activities and interest savings which totaled $28.2 million for an impact on ROE of positive 0.7%.
The Company’s 2016 return on AMA equity was 8.9%, which is lower than the authorized regulated ROE primarily due to the following:
Regulated equity (rate base time's equity percent) was $360.0 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. The impact on ROE for this variance was negative 1.0%.
Depreciation expense was $10.5 million higher than the amount allowed in rates for the year ended December 31, 2016.
Partially offsetting the above was net revenue from below the line activities which totaled $4.3 million.
Factors and Trends Affecting PSE’s Performance
PSE’s ongoing regulatory requirements and operational needs necessitated the investment of substantial capital in 2017its IRP process, and will continue to do soengage in futureclimate and 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 2017 were 10.2 million metric tons of carbon dioxide equivalents. Approximately 43.7% of PSE’s total GHG emissions (approximately 4.5 million metric tons) are associated with PSE’s ownership and contractual interests in Colstrip (with the closure of Units 1&2 effective December 31, 2019, PSE expects an approximately 45% reduction in Colstrip GHG 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 Rules: New and Existing Power Plants
On October 23, 2015, the EPA published 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. 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. Carbon Dioxide Capture and Sequestration (CCS) was reaffirmed by the EPA in this rule as the “best system of emission reductions” (BSER).
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 either utility boilers or integrated gasification combined cycle (IGCC) units based on the Agency’s proposed revised Best System of Emission Reduction (BSER). The EPA is not proposing any changes nor reopening the standards of performance for newly constructed or reconstructed stationary combustion turbines.. For large units, the 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 proposes to replace the CCS BSER determination with a BSER for 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 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 sale to NorthWestern Energy.
Washington Clean Air Rule
The 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, including PSE. The CAR sets a cap on emissions associated with covered entities, which decreases over time approximately 5.0% every three years. BecauseEntities must reduce their carbon emissions, or purchase emission reduction units (ERUs), as defined under the rule, from others.
In September 2016, PSE, along with Avista Corporation, Cascade Natural Gas Corporation and NW Natural, filed a lawsuit in the U.S. District Court for the Eastern District of 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 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 resolution of the state 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 a clean, affordable, and reliable energy future. The Clean Energy Transition Act requires all electric utilities to eliminate coal-fired generation from their allocation of electricity by December 31, 2025; to be carbon-neutral by January 1, 2030, through a combination of non-emitting electric generation, renewable generation, and/or alternative compliance options; and makes it the state policy that, by 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 2045 standard between 2030 and 2045, and lay out an actionable plan that they intend to pursue to meet the 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 law 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 such investmentsany costs associated with the clean energy legislation through the regulatory process.
Regional Haze Rule
In January 2017, the EPA provided revisions to the Regional Haze Rule which were published in the Federal Register. 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 would revisit certain aspects of these revisions and PSE is 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 D.C. Circuit, pending resolution of EPA’s reconsideration of the rule.
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 financial results depend heavily upon favorable outcomes from that process. 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 principalexecutive officers of Puget Energy as of February 21, 2020, are listed below along with their business economicexperience 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 affectPuget 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 performance include: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 rates PSE is allowed to charge for its services;
actions of regulators can significantly affect 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, stream-flowearnings, liquidity and wind-speed which affect power generation, supply and price;
Regulatory decisions allowing PSE to recover purchased power and fuel costs, on a timely basis;
PSE’s ability to supply electricity and natural gas, either through company-owned generation, purchase power contracts or by procuring natural gas or electricity in wholesale markets;
Equal sharing between PSE and its customers of earnings which exceed PSE's authorized rate of return;
Availability and access to capital and the cost of capital;
Regulatory compliance costs, including those related to new and developing federal regulations of electric system reliability, state regulations of natural gas pipelines and federal, state and local environmental laws and regulations;
Wholesale commodity prices of electricity and natural gas;
Increasing capital expenditures with additional depreciation and amortization;
Tax reform, the effect of lower tax rates, and regulatory treatment of excess deferred tax balances on rate 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.
Regulation of PSE Rates and Recovery of PSE Costs
business activities. The rates that PSE is allowed to charge for its services influenceare the single most important item influencing its financial condition,position, results of operations and liquidity. PSE is highly regulated and the rates that it charges its wholesale and retail customers are approveddetermined 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. The Washington Commission has traditionally required theseto determine the rates, revenue may not be determined based,sufficient 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 revenuepermit PSE to earn its allowed return or to cover general cost increases over time due to the combined effects of regulatory lag and attrition.its costs. In addition, the Washington Commission determines whetherhas the Company's expensesauthority to determine what level of expense and capital investments areinvestment is reasonable and prudent for the provision of cost effective, reliable and safein providing electric and natural gas service. If the Washington Commission determinesdecides that an operating expense or capital investment doespart of PSE’s costs do not meet the reasonable and prudent standards, thestandard, those 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. 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.
During 2013,
PSE completed an expedited rate filing (ERF), which wasis currently subject to 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 actual cash payments for the year.
The decoupling mechanism allowsWashington Commission order that requires PSE to recover delivery costs on a per customer basis rather than on a consumption basis. Included inshare its excess earnings above 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. with customers. The rate plan included predetermined annual increases to PSE’s allowedWashington Commission previously approved an electric and natural gas revenue. Thisdecoupling mechanism for the recovery of its delivery-system and fixed production costs, along with a rate plan required PSE to file a GRC no later than April 1, 2016, which was later extended to January 17, 2017. The GRC was filed with the Washington Commission on January 13, 2017.
Washington state law alsoand earnings sharing mechanism that requires PSE and its customers 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.
2013 Expedited Rate Filing and Decoupling Decision
In 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. 7share in the ERF/decoupling proceeding approved PSE's ERF filing with a small change to its cost of capital to 7.77% which updated 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 will share 50.0% of any earnings in excess of the 7.77% authorized rate of return with customers. In addition, the K-Factor (rate plan) increase allowed decoupling revenue per customer for the recovery of delivery system costs to subsequently increase by 3.0% per year for electric customers and 2.2% per year for natural gas customers on January 1 of each year, until the effective date of new rates in PSE's General Rate Case (GRC)7.60%. The new rates became effective December 19, 2017, as discussed below. Inearnings test is done for each service (electric/natural gas) separately, so PSE would be obligated to share the decoupling mechanism, increases were subject to a capearnings for one service exceeding the authorized rate of 3.0% of the total revenue for customers.
General Rate Case Filing
On January 13, 2017, PSE filed its GRC with the Washington Commission the settlement agreement was accepted by the Washington Commission on December 5, 2017 and the rates became effective December 19, 2017. For further details regarding the 2017 GRC filing, see Note 3, "Regulation and Rates" to the consolidated financial statements included in Item 8 of this report.
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 and electric fixed production energy costs will now be decoupled and recovered on a fixed monthly amount basis. The allowed decoupling revenue will no longer increase annually on January 1 for electric and natural gas customers and these amounts can only be changed in a GRC, Power Cost Only Rate Case (PCORC) or ERF filing. Other changes 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 cap 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 the effective date of PSE's first GRC filed in or after 2021, or in a separate proceeding if appropriate unless the continuation of the mechanism is approved in either of those proceedings. PSE’s decoupling mechanism over and under collections will still be collectible or refundable after this effective datereturn, even if the decouplingother service did not exceed the authorized rate of return.
The PCA mechanism, is not extended.
The Washington Commission approved the followingby which variations in PSE’s power costs are apportioned between PSE requests to change rates underand 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, 2017 | | 2.0% | | $41.9 |
May 1, 2016 | | 1.0 | | 20.8 |
May 1, 2015 | | 2.6 | | 53.8 |
Natural Gas: | | | | |
May 1, 2017 | | 2.4% | | $22.4 |
May 1, 2016 | | 2.8 | | 25.4 |
May 1, 2015 | | 2.1 | | 22.0 |
| |
1
| The increase in revenue is net of reductions from excess earnings of $11.9 million for electric and $2.2 million for natural gas effective May1, 2017, and $11.9 million for electric and $5.5 million for natural gas effective May 1, 2016. |
As noted earlier, at the time of the filings below, the Company was also limitedcustomers pursuant to a 3.0% annual decoupling related cap ongraduated scale, could result in significant 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) |
Natural Gas: | | |
2016 | | $47.4 |
2015 | | 28.7 |
Existing deferrals may be included in customer rates beginning in May 2018, subject to subsequent application ofPSE’s expenses if power costs are significantly higher than the earnings test and the cap on decoupling related rate increases for natural gas customers, which was changed from 3.0% to 5.0% as a result of the Washington Commission order in PSE's GRC.
Electric Rates
Power Cost Adjustment Mechanism
baseline rate. PSE currently has a PCA mechanism that provides for the deferralrecovery of power costs thatfrom customers or refunding of power cost savings to customers, as those costs vary from the “power cost baseline” level of power costs. The “power cost baseline” levelscosts which are set, in part, based on normalized assumptions about weather and hydrological conditions. Excess power costs or power cost savings arewill 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 the event of a deterioration of financial ratios, may increase Puget Energy's and PSE’s cost of borrowing or adversely affect the ability to access one or more financial markets.
The amount of the Company's debt could adversely affect its liquidity and results of operations. Puget Energy and PSE have short-term and long-term debt, and may incur additional debt (including secured debt) in the future. Puget Energy has access to a multi-year $800.0 million revolving credit facility, secured by substantially all of its assets, 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 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 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 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 graduated scale that waspayment of dividends by PSE to Puget Energy is restricted by provisions of certain covenants 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,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 Commission issued anmerger order, approving the changesPSE 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 PCA mechanism.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 rating and EBITDA to interest ratio, as previously discussed above. The settlementcommon 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 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.
Challenges relating to the construction or future operation of 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 took effect January 1, 2017with a maritime customer, and will applyis marketing the following graduated scale: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 could unfavorably impact Puget Energy’s return on investment.
|
| | | | | | | | | | | |
| 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 |
|
ITEM 1B. UNRESOLVED STAFF COMMENTS
None.
ITEM 2. PROPERTIES
The PCA settlementprincipal 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
For information on litigation or legislative rulemaking proceedings, see Note 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 resultedlimited 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 2019, 2018, and 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 changestables 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 Item 7, "Management's Discussion and Analysis of Financial Condition and Results of Operation" of this Form 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 | | | — | | | — | | | — | | | — | |
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 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. Inclusionidentify certain of these costs inforward-looking statements. However, these words are not the decoupling mechanism was subsequently approved in the GRC. These fixed production costs include: (i) return and depreciation/amortizationexclusive 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 fixed production assets and regulatory assets and liabilities; (ii) return, depreciation, transmission expense and revenues on specific transmission assets; and (iii) hydroelectric, 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 PCORC;
Agreement, for a five-year period, that PSE will not file a GRC or PCORC within six monthsthese forward-looking statements, which speak only as of the date rates go into effect for a PCORC filing;of this report. Puget Energy’s and
Establishment of a five-year moratorium on changes 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 PCA.
On September 30, 2016,section entitled “Forward-Looking Statements” and “Risk Factors” included elsewhere in this report. Except as required by law, neither Puget Energy nor PSE undertakes any obligation to revise any forward-looking statements in order to reflect events or circumstances that may subsequently arise. Readers are urged to carefully review and consider the various disclosures made in this report and in Puget Energy’s and PSE’s other reports filed an accounting petition with the WashingtonU.S. Securities and Exchange Commission which requested deferral(SEC) that attempt to advise interested parties of the variances, either positive or negative, betweenrisks 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 fixed costs previously recoveredlargest electric and natural gas utility in the PCAstate 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, Puget LNG, LLC (Puget LNG), which has the revenue receivedsole purpose of owning, developing and financing the non-regulated activity of the Tacoma liquefied 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 the Canada Pension Plan Investment Board, the British Columbia Investment Management Corporation (BCI), the Alberta Investment Management 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 cover the allowed fixed costs. The deferral period requestedOMERS, PGGM Vermogensbeheer B.V., AIMCo and BCI was January 1, 2017 through December 31, 2017, when rates went into effect from PSE's 2017 GRC. On November 10, 2016,approved by various federal and state agencies, including that of the Washington Utilities and Transportation Commission issued Order No. 01 approving PSE’s accounting petition. With(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 final determination in PSE’s GRC, this deferral ceased with the rate effective datesale of December 19, 2017.
For the year ended December 31, 2017, in its PCA mechanism, PSE under recovered its power costs by $11.5 million of which no amount was apportionedelectric and natural gas services to customers. This compares to an under recovery of power costs of $1.0 million for the year ended December 31, 2016 of which no amounts were apportioned to customers. Although load increased in 2017 compared to 2016, that increase was offset byresidential and commercial customers within a decreaseservice territory covering approximately 6,000 square miles, principally in the total baseline rate and an increase in costs. Additionally, the year over year variance was due to the 2017 mechanism changes where fixed production costs, other costs and adjustments are no longer included. The mechanism is now comparing variable PCA costs using the variable costs portionPuget Sound region of the baseline rate.state of Washington. PSE continually balances its load requirements, generation resources, purchase power agreements, and market purchases to meet customer demand. The fixed costs became partCompany'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 decoupling mechanism, effective December 19, 2017 as a result of the GRC but until then the revenue variance associated with the fixed production costs are being deferred using the fixed cost portion of the baseline rate. The revenue variance associated with the fixed production costs was deferred using the fixed cost portion of the baseline rate until December 19, 2017, when the fixed costs became part of the decoupling mechanism with the resolution of PSE’s GRC.Management's Discussion and Analysis.
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 forecasted 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 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 is adjusted each year in May based on that year's assessed property taxes and true-up from the prior year.
Federal Incentive Tracker Tariff
The Federal Incentive Tracker Tariff passes through to customers the benefits associated with the wind-related treasury 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 federal 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 to 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.
Natural Gas Rate Filings
Natural Gas Cost Recovery Mechanism
The purpose of the cost recovery mechanism (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. Rates change annually on November 1.
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. Rates typically change annually on November 1, although out-of-cycle rate changes are allowed at other times of the 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 is adjusted each year in May based on that year's assessed property 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 compared to forecast conservation expenditures from the prior year, as well as actual compared 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.
ELECTRIC UTILITY OPERATING STATISTICS
| | | | | | | | | | | | | | | | | |
| Year Ended December 31, | | | | |
| 2019 | | 2018 | | 2017 |
Generation and purchased power, MWh | | | | | |
Company-controlled resources | 13,420,043 | | | 11,168,286 | | | 10,825,778 | |
Contracted resources | 6,752,261 | | | 7,654,872 | | 8,337,348 |
Non-firm energy purchased | 5,707,102 | | | 6,490,602 | | 6,147,778 |
Total generation and purchased power | 25,879,406 | | | 25,313,760 | | | 25,310,904 | |
Less: losses and Company use | (1,298,854) | | | (1,513,451) | | (1,568,599) |
Total energy sales, MWh | 24,580,552 | | | 23,800,309 | | | 23,742,305 | |
Electric energy sales, MWh | | | | | | |
Residential | 10,756,628 | | | 10,497,389 | | 10,931,999 |
Commercial | 8,837,457 | | | 8,932,681 | | 9,089,842 |
Industrial | 1,161,149 | | | 1,189,828 | | 1,214,818 |
Other customers | 85,302 | | | 84,382 | | 87,230 |
Total energy sales to customers | 20,840,536 | | | 20,704,280 | | | 21,323,889 | |
Sales to other utilities and marketers | 3,740,016 | | | 3,096,029 | | 2,418,416 |
Total energy sales, MWh | 24,580,552 | | | 23,800,309 | | | 23,742,305 | |
Transportation, including unbilled | 2,322,021 | | | 2,028,727 | | 2,001,244 |
Electric energy sales and transportation, MWh | 26,902,573 | | | 25,829,036 | | | 25,743,549 | |
Electric operating revenue by classes | | | | | |
(Dollars in Thousands) | | | | | |
Residential | $ | 1,139,356 | | | $ | 1,147,260 | | | $ | 1,232,075 | |
Commercial | 854,910 | | | 885,457 | | 892,360 |
Industrial | 105,020 | | | 110,607 | | 112,817 |
Other customers | 18,408 | | | 18,718 | | 19,729 |
Total operating revenue from customers | 2,117,694 | | | 2,162,042 | | | 2,256,981 | |
Transportation, including unbilled | 19,512 | | | 13,878 | | 12,584 |
Sales to other utilities and marketers | 109,105 | | | 89,324 | | 53,789 |
Decoupling revenue | 15,673 | | | 13,530 | | 9,975 |
Other decoupling revenue1 | (6,866) | | | (5,475) | | (27,706) |
Miscellaneous operating revenue | 241,923 | | | 182,620 | | 115,040 |
Total electric operating revenue | $ | 2,497,041 | | | $ | 2,455,919 | | | $ | 2,420,663 | |
Number of customers served (average): | | | | | |
Residential | 1,025,024 | | | 1,010,574 | | 998,078 |
Commercial | 129,944 | | | 128,845 | | 126,829 |
Industrial | 3,328 | | | 3,362 | | 3,399 |
Other | 7,323 | | | 6,992 | | 6,722 |
Transportation | 80 | | | 16 | | 16 |
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.
ELECTRIC UTILITY OPERATING STATISTICS (Continued)
| | | | | | | | | | | | | | | | | |
| Year Ended December 31, | | | | |
| 2019 | | 2018 | | 2017 |
Average kWh used per customer: | | | | | |
Residential | 10,494 | | | 10,388 | | | 10,953 | |
Commercial | 68,010 | | 69,329 | | 71,670 |
Industrial | 348,903 | | 353,905 | | 357,404 |
Other | 11,649 | | 12,068 | | 12,977 |
Average revenue per customer: | | | | | |
Residential | $ | 1,112 | | | $ | 1,135 | | | $ | 1,234 | |
Commercial | 6,579 | | 6,872 | | 7,036 |
Industrial | 31,556 | | 32,899 | | 33,191 |
Other | 2,514 | | 2,677 | | 2,935 |
Average retail revenue per kWh sold: | | | | | |
Residential | $ | 0.1059 | | | $ | 0.1093 | | | $ | 0.1127 | |
Commercial | 0.0967 | | 0.0991 | | 0.0982 |
Industrial | 0.0904 | | 0.0930 | | 0.0929 |
Other | 0.2158 | | 0.2218 | | 0.2262 |
Average retail revenue per kWh sold | $ | 0.1016 | | | $ | 0.1044 | | | $ | 0.1058 | |
Heating degree days | 4,208 | | | 4,065 | | 4,584 |
Percent of normal - NOAA2 30-year average | 89.6 | % | | 86.2 | % | | 97.2 | % |
Load factor3 | 61.6 | % | | 64.2 | % | | 51.6 | % |
_______________
2.National Oceanic and Atmospheric Administration (NOAA).
3.Average megawatt (aMW) usage by customers divided by their maximum usage.
Electric Supply
At December 31, 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 4,733 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, 2019, and 2018:
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
` | Peak Power Resources At December 31, | | | | | | | | Energy Production At December 31, | | | | | | |
| 2019 | | | | 2018 | | | | 2019 | | | | 2018 | | |
| MW | | % | | MW | | % | | MWh | | % | | MWh | | % |
Purchased resources: | | | | | | | | | | | | | | | | | | | |
Columbia River PUD contracts1 | 687 | | | 14.5% | | | 674 | | 14.3% | | | 2,642,177 | | 10.2% | | | 3,468,702 | | 13.7% | |
Other hydroelectric | 72 | | | 1.5 | | | 72 | | 1.5 | | | 272,653 | | 1.0 | | | 315,948 | | 1.2 | |
Other producers | 285 | | | 6.0 | | | 284 | | 6.2 | | | 3,276,502 | | 12.7 | | | 3,406,627 | | 13.6 | |
Wind | 56 | | | 1.2 | | | 56 | | 1.2 | | | 123,368 | | 0.5 | | | 131,270 | | 0.5 | |
Short-term wholesale energy purchases | N/A | | | — | | | N/A | | N/A | | | 6,144,663 | | 23.7 | | | 6,822,927 | | 26.9 | |
Total purchased | 1,100 | | | 23.2% | | | 1,086 | | | 23.2% | | | 12,459,363 | | | 48.1% | | | 14,145,474 | | | 55.9% | |
Company-controlled resources: | | | | | | | | | | | | | | | | | | | |
Hydroelectric | 250 | | | 5.3% | | | 250 | | 5.3% | | | 712,727 | | 2.8% | | | 914,540 | | 3.6% | |
Coal3 | 677 | | | 14.3 | | | 677 | | 14.4 | | | 4,347,639 | | 16.8 | | | 4,184,950 | | 16.5 | |
Natural gas/oil | 1,931 | | | 40.8 | | | 1,908 | | 40.6 | | | 6,692,188 | | 25.9 | | | 4,152,359 | | 16.4 | |
Wind | 773 | | | 16.3 | | | 773 | | 16.5 | | | 1,667,489 | | 6.4 | | | 1,932,378 | | 7.6 | |
Other2 | 2 | | | — | | | 2 | | — | | | — | | — | | | — | | — | |
Total company-controlled | 3,633 | | | 76.8% | | | 3,610 | | 76.8% | | | 13,420,043 | | 51.9% | | | 11,184,227 | | 44.1% | |
Total resources | 4,733 | | | 100.0% | | | 4,696 | | | 100.0% | | | 25,879,406 | | | 100.0% | | | 25,329,701 | | | 100.0% | |
_______________
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, 2019, PSE owns the following plants with an aggregate net generating capacity of 3,633 MW:
| | | | | | | | | | | | | | | | | | | | |
Plant Name | | Plant Type | | Net Maximum Capacity (MW)1 | | Year Installed |
Colstrip Units 3 & 4 (25% interest) | | Coal | | 370 | | 1984 & 1986 |
Colstrip Units 1 & 2 (50% interest)2 | | Coal | | 307 | | 1975 & 1976 |
Mint Farm | | Natural gas combined cycle | | 320 | | 2007; acquired 2008; upgraded 2017 |
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 2005 |
Lower Snake River | | Wind | | 343 | | 2012 |
Wild Horse | | Wind | | 273 | | 2006 & 2009 |
Hopkins Ridge | | Wind | | 157 | | 2005 & 2008 |
Fredonia Units 1 & 2 | | Dual-fuel combustion turbines | | 207 | | 1984 |
Frederickson Units 1 & 2 | | 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 |
Ferndale | | Natural gas co-generation | | 253 | | 1994; acquired 2012 |
Encogen | | Natural gas co-generation | | 165 | | 1993; acquired 1999 |
Sumas | | Natural gas co-generation | | 127 | | 1993; acquired 2008 |
Upper Baker River | | Hydroelectric | | 91 | | 1959; unit 2 upgraded 1997 |
Lower Baker River | | Hydroelectric | | 105 | | 1925: reconstructed 1960; upgraded 2001 and 2013 |
Snoqualmie Falls3 | | Hydroelectric | | 54 | | 1898 to 1911 & 1957; rebuilt 2013 |
Crystal Mountain | | Internal combustion | | 3 | | 1969 |
Glacier Battery Storage | | Lithium Iron Phosphate | | 2 | | 2016 |
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. 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 2019, approximately 10.2% of PSE’s energy supply 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’s payments are not contingent upon the projects being operable.
As of December 31, 2019, PSE's portion of the power output of the PUDs’ projects are 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 |
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 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 has resulted in reduced costs for PSE customers of approximately $16.2 million per annum, enhanced system reliability, integration of variable energy resources, and 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 2019, PSE had 4,797 MW and 595 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 through gas-fired generation. Supplies range from long-term to daily agreements, as turbine 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.
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. However, 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 15, 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 conservation projections from the 2017 IRP, the capacity shortfalls and surpluses are:
| | | | | | | | | | | | | | | | | | | | | | | | | | |
| | 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 2017 IRP. As part of the CETA, PSE must 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 implementation of the CETA. PSE is currently pursuing resource acquisitions to meet the current capacity shortfall projections.
NATURAL GAS UTILITY OPERATING STATISTICS
| | | | | | | | | | | | | | | | | |
| Year Ended December 31, | | | | |
| 2019 | | 2018 | | 2017 |
Natural gas operating revenue by classes (Dollars in Thousands): | | | | | |
Residential | $ | 613,617 | | | $ | 598,923 | | | $ | 686,438 | |
Commercial firm | 218,302 | | 219,390 | | 251,584 |
Industrial firm | 15,698 | | 17,247 | | 20,077 |
Interruptible | 18,381 | | 21,113 | | 24,317 |
Total retail natural gas sales | 865,998 | | | 856,673 | | | 982,416 | |
Transportation services | 20,283 | | 19,984 | | 21,718 |
Decoupling revenue | 2,296 | | 6,115 | | 3,522 |
Other decoupling revenue1 | (29,737) | | (37,022) | | (22,862) |
Other | 16,531 | | 4,998 | | 12,965 |
Total natural gas operating revenue | $ | 875,371 | | | $ | 850,748 | | | $ | 997,759 | |
Number of customers served (average): | | | | | |
Residential | 782,413 | | 772,130 | | 761,010 |
Commercial firm | 56,113 | | 55,716 | | 55,372 |
Industrial firm | 2,304 | | 2,308 | | 2,330 |
Interruptible | 367 | | 393 | | 398 |
Transportation | 230 | | 234 | | 226 |
Total customers | 841,427 | | | 830,781 | | | 819,336 | |
Natural gas volumes, therms (thousands): | | | | | |
Residential | 605,313 | | 571,265 | | 621,915 |
Commercial firm | 277,639 | | 264,775 | | 279,656 |
Industrial firm | 22,915 | | 23,890 | | 25,500 |
Interruptible | 45,176 | | 47,275 | | 49,249 |
Total retail natural gas volumes, therms | 951,043 | | | 907,205 | | | 976,320 | |
Transportation volumes | 227,657 | | 230,735 | | 236,578 |
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.
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 | % |
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, LLC (NWP), the sole interstate pipeline delivering directly into PSE’s service territory. Accordingly, delivery of natural gas supply to PSE’s natural gas system is dependent upon the reliable operations of NWP.
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 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.
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 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 designates 397,100 Dth per day of the firm withdrawal capacity and over 9.2 million Dth of storage capacity to serve natural gas 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 640,600 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 12.9 million Dth of Clay Basin storage capacity and approximately 107,400 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.
LNG and Propane-Air Resources
LNG and propane-air resources provide firm natural gas supply on short notice for short periods of time. Due to their typically high cost and slow cycle times, these resources are normally utilized as a last resort supply source in extreme peak-demand periods, typically during the coldest hours or days.
PSE holds a contract for LNG storage services of 241,700 Dth of PSE-owned natural gas at Plymouth, with a maximum daily deliverability of 70,500 Dth for use of the PSE generation 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 holds 15,000 Dth/day of firm pipeline capacity from Plymouth for the generation fleet. The balance of the LNG capacity is 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; however, it is temporarily out-of-service pending planned environmental 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.
Tacoma LNG Facility
Currently under construction at the Port of Tacoma, the Tacoma LNG facility is expected to be operational in 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, PSE will be allocated 43.0% of the capital and operating costs, consistent with the regulated portion of the Tacoma LNG facility, and Puget LNG will be allocated the remaining 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 Enbridge Westcoast Energy (Westcoast). GTN, NOVA, and Foothills are all TC 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 542,900 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 447,100 Dth per day of seasonal firm capacity on NWP to provide for delivery of natural gas stored at Jackson Prairie to natural gas customers. PSE holds approximately 217,900 Dth per day of firm transportation capacity on NWP to supply natural gas to its electric generating facilities. In addition, PSE holds over 34,200 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 one to 25 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 135,800 Dth per day under various contracts, with remaining terms of four to six years. PSE has other firm transportation capacity on Westcoast’s pipeline, which supplies the electric generating facilities, totaling 88,400 Dth per day, with remaining terms of four to six 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 79,000 Dth per day, with remaining terms of four to six 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 term of four years. PSE’s firm transportation capacity for its natural gas customers on the GTN pipeline, totaling over 77,000 Dth per day, with remaining term of four 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 40,600 Dth per day, with remaining terms of one to four years. PSE holds 259,000 decatherms per day of firm capacity on CNGC to connect 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 2017 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 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 takes seriously environmental stewardship, implementing both short-term measures and long-term strategies designed to manage greenhouse gas emissions in a scientifically sound and responsible fashion. The Company has worked closely with federal, state and 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 mindful 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 its IRP process, and will continue to engage in climate and 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 2017 were 10.2 million metric tons of carbon dioxide equivalents. Approximately 43.7% of PSE’s total GHG emissions (approximately 4.5 million metric tons) are associated with PSE’s ownership and contractual interests in Colstrip (with the closure of Units 1&2 effective December 31, 2019, PSE expects an approximately 45% reduction in Colstrip GHG 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 Rules: New and Existing Power Plants
On October 23, 2015, the EPA published 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. 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. Carbon Dioxide Capture and Sequestration (CCS) was reaffirmed by the EPA in this rule as the “best system of emission reductions” (BSER).
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 either utility boilers or integrated gasification combined cycle (IGCC) units based on the Agency’s proposed revised Best System of Emission Reduction (BSER). The EPA is not proposing any changes nor reopening the standards of performance for newly constructed or reconstructed stationary combustion turbines.. For large units, the 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 proposes to replace the CCS BSER determination with a BSER for 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 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 sale to NorthWestern Energy.
Washington Clean Air Rule
The 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, including PSE. The CAR sets a cap 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 2016, PSE, along with Avista Corporation, Cascade Natural Gas Corporation and NW Natural, filed a lawsuit in the U.S. District Court for the Eastern District of 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 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 resolution of the state 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 a clean, affordable, and reliable energy future. The Clean Energy Transition Act requires all electric utilities to eliminate coal-fired generation from their allocation of electricity by December 31, 2025; to be carbon-neutral by January 1, 2030, through a combination of non-emitting electric generation, renewable generation, and/or alternative compliance options; and makes it the state policy that, by 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 2045 standard between 2030 and 2045, and lay out an actionable plan that they intend to pursue to meet the 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 law 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 clean energy legislation through the regulatory process.
Regional Haze Rule
In January 2017, the EPA provided revisions to the Regional Haze Rule which were published in the Federal Register. 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 would revisit certain aspects of these revisions and PSE is 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 D.C. Circuit, pending resolution of EPA’s reconsideration of the rule.
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 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 the event of a deterioration of financial ratios, may increase Puget Energy's and PSE’s cost of borrowing or adversely affect the ability to access one or more financial markets.
The amount of the Company's debt could adversely affect its liquidity and results of operations. Puget Energy and PSE have short-term and long-term debt, and may incur additional debt (including secured debt) in the future. Puget Energy has access to a multi-year $800.0 million revolving credit facility, secured by substantially all of its assets, 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 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 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 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 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'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 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.
Challenges relating to the construction or future operation of 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 could 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, 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 information on litigation or legislative rulemaking proceedings, see Note 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 2019, 2018, and 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 Item 7, "Management's Discussion and Analysis of Financial Condition and Results of Operation" of this Form 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 | | | — | | | — | | | — | | | — | |
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 any obligation to revise any forward-looking statements in order to reflect events or circumstances that may subsequently arise. Readers are urged to carefully review and consider the various disclosures made in this report and in Puget Energy’s and PSE’s other reports filed with the U.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, 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. 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 the Canada Pension Plan Investment Board, the British Columbia Investment Management Corporation (BCI), the Alberta Investment Management 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 (GAAP net income divided by GAAP average common equity) as an indicator of operating performance.
The following table presents PSE’s ROE, its return on AMA equity and its authorized regulated ROE for 2019 and 2018:
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| 2019 | | | | | | 2018 | | | | |
(Dollars in Thousands) | Earnings | | Average Common Equity | | Return on Equity | | Earnings | | Average Common Equity | | Return on Equity |
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 | 2,823 | | — | | * | | | (32,913) | | — | | * | |
Less/Plus: Equity adjustments1 | — | | 179,517 | | * | | | — | | 179,852 | | * | |
Plus: Impact of average of monthly average (AMA) | — | | (48,247) | | * | | | — | | 18,075 | | * | |
Return on AMA equity | $295,747 | | | $4,009,572 | | | 7.4% | | | $284,249 | | | $3,852,451 | | | 7.4% | |
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.
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 2019 return on AMA equity was 7.4%, which is lower than the authorized regulated ROE primarily due to the following:
•Regulated equity (rate base multiplied by equity percent) was $351.6 million lower than AMA equity for the year ended December 31, 2019. The impact on ROE for this variance was 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 $90.7 million higher than the amount allowed in rates on a pre-tax basis for the year ended December 31, 2019, for an impact on ROE of negative 2.3%.
The Company’s 2018 return on AMA equity was 7.4%, which is lower than the authorized regulated ROE primarily due to the following:
•Regulated equity (rate base multiplied by equity percent) was $379.9 million lower than AMA equity for the year ended December 31, 2018. The impact on ROE for this variance was 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.
•Depreciation expense was $50.7 million higher than the amount allowed in rates on a pre-tax basis for the year ended December 31, 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 2019 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, 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 (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;
•Failure to complete capital projects on schedule and within budget or the abandonment 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 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;
•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. 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, reliable and safe electric and natural gas service. If the Washington Commission determines that a capital investment is not reasonable or prudent, the costs (including return on any resulting rate base) related to such capital investment may be disallowed, partially or entirely, and not recovered in rates.
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
PSE filed a GRC with the Washington Commission on June 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 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 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 and electric fixed production energy costs will now be decoupled and recovered on the basis of a fixed monthly amount. 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 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 remain at 3.0% for electric customers. The decoupling mechanism is 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 over- and under- collections will still be collectible or refundable after this effective date even if the decoupling mechanism is not extended.
On February 21, 2019, the Washington Commission approved the multi-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 performed an analysis to determine if electric and natural gas decoupling revenue deferrals would be collected from customers within 24 months of 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 that 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 $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 power, 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 based 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 |
|
| | | | |
Effective Date | | Average Percentage Increase (Decrease) in Rates | | Increase (Decrease) in Revenue (Dollars in Millions) |
May 1, 2017 | | 0.7% | | $16.5 |
May 1, 2016 | | (0.5) | | (11.7) |
May 1, 2015 | | 0.2 | | 4.2 |
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 Federal Incentive Tracker Tariff rate adjustmentsthe 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) |
|
| | | | |
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, 2018 | | 0.2% | | $(48.2) |
January 1, 2017 | | 0.3 | | (51.7) |
January 1, 2016 | | (0.2) | | (57.3) |
January 1, 2015 | | (0.2) | | (55.2) |
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) |
Residential Exchange Benefit
The residential exchange program passes through the residential exchange program benefits that PSE will be receiving from the Bonneville Power Administration (BPA) between October 1, 2017 and September 30, 2019. Rates change bi-annually on October 1.
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) | |
|
| | | | |
Effective Date | | Average Percentage Increase (Decrease) in Rates | | Total credit to be passed back to eligible customers (Dollars in Millions) |
October 1, 2017 | | (0.6)% | | $(80.8) |
October 1, 2015 | | 2.4 | | (76.4) |
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, 2017 | | (0.4)% | | $(0.9) |
May 1, 2016 | | 0.3 | | 5.7 |
May 1, 2015 | | 0.3 | | 6.5 |
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 |
|
| | | | |
Effective Date | | Average Percentage Increase (Decrease) in Rates | | Increase (Decrease) in Revenue (Dollars in Millions) |
November 1, 2017 | | 0.5% | | $4.9 |
November 1, 2016 | | 0.6 | | 5.6 |
November 1, 2015 | | 0.5 | | 5.3 |
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 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.
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) |
|
| | | | |
Effective Date | | Average Percentage Increase (Decrease) in Rates | | Increase (Decrease) in Revenue (Dollars in Millions) |
November 1, 2017 | | (3.3)% | | $(30.8) |
November 1, 2016 | | (0.4) | | (4.1) |
November 1, 2015 | | (17.4) | | (185.9) |
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) |
|
| | | | |
Effective Date | | Average Percentage Increase (Decrease) in Rates | | Increase (Decrease) in Revenue (Dollars in Millions) |
May 1, 2017 | | (0.1)% | | $(1.1) |
May 1, 2016 | | 0.4 | | 3.5 |
June 1, 2015 | | (0.2) | | (2.3) |
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) | |
|
| | | | |
Effective Date | | Average Percentage Increase (Decrease) in Rates | | Increase (Decrease) in Revenue (Dollars in Millions) |
May 1, 2017 | | (0.1)% | | $(1.0) |
May 1, 2016 | | 0.3 | | 2.9 |
May 1, 2015 | | 0.2 | | 2.3 |
Other Proceedings
Large Customer Retail WheelingMicrosoft Special Contract
On October 7, 2016,Following discussions between PSE, filedthe Microsoft Corporation, and others, and after completing a tariff to provide open access service to a narrow set of qualifying customers. Subsequent to that tariff filing, parties tonegotiated regulatory process, the case reachedWashington Commission issued an all-party settlement that converted the tariff toorder in July 2017 approving a special contract only allowingbetween PSE and Microsoft relating to retail access for theMicrosoft loads of the Microsoft Corporation 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 itMicrosoft must be carbon free, (iii) there will be no reduction in itsMicrosoft's funding of PSE’s conservation programs, (iv) an exitMicrosoft paid a transition fee be paid that will bewas a straight pass-through to customers and (v) Microsoft will fund enhanced low-income support. A definitive agreement among the parties, the special contract and supportive testimony were filed with the Washington Commission on April 11, 2017 with hearings that occurred on May 3, 2017. The Washington Commission issued an order on July 13, 2017 approving PSE’s special contract with Microsoft. Microsoft cannot beginbegan taking service under the special contract until it hason April 1, 2019, after meeting the required metering installed, has contracts foreligibility requirements under the supply and transmission of its power supply and pays the exit fee. PSE currently anticipates these conditions will be met in early 2019.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 provides 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 initially offered this service, Green Direct, to larger customers (aggregated annual loads greater than 10,000,000 kWh)10,000 MWh) and government customers. Approximately 136.8 MW ofThe initial resource option offered under this rate schedule is a new wind generation facilities will be constructedfacility with the capacity of approximately 136.8 MW currently under construction in the region by a developer under contract to PSEPSE. The project is fully subscribed and is expected to meetbegin generating power in 2020. Twenty-one customers will receive the demand for this voluntary renewableanticipated output of the project.
In July 2018, the Washington Commission approved a second phase of the Green Direct product. The phase 2 offering will be a blend of the phase 1 wind and a solar project to be built in Washington. Phase 1 customers will receive wind through 2020; and then are expected to receive the blended energy product project. PSE anticipates thatin 2021. An additional twenty customers will start receiving energy through thisphase 2 of the program, in 2019.likely by 2021.
For additional information, see Business,Note 4, "Regulation and Rates" to the consolidated financial statements included in Item 18 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. In October 2017, PSE and Puget Energy each entered into new 5-year credit facilities that replaced the previous facilities and are scheduled to mature in October 2022. For additional information on credit facilities, see Note 7, “Liquidity Facilities and Other Financing Arrangements" included in Item 8 of this report.
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 amount of resources to fulfill requirements set by regulatory agencies, many of which have greatly expanded mandates on measures including 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. Further, 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, 2017, 20162019, and 2015.December 31, 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 chart displays the changes in PSE’s electric margin from 2016for the years ended December 31, 2018, to 2017:December 31, 2019:
_______________ _______________
*Includes decoupling cash collections, rate of return excess earnings, and decoupling 24-month revenue reserve.
20162018 compared to 20172019
Electric Operating Revenue
Electric operating revenues increased $182.2$41.2 million primarily due to higher retail sales of $112.5 million, increased transportation and other revenue of $92.5$65.0 million, sales to other utilities and marketers of $19.8 million and decoupling revenue of $2.1 million; partially offset by decreased decoupling revenuelower retail sales of $20.0$44.3 million and other decoupling revenue of $6.5$1.4 million. These items are discussed in detail below:
•Electric retail sales increased $112.5 decreased $44.3 million due to a decrease of $60.7 million in rates partially offset by an increase of $100.0 million from additionalin retail electricity usage of 4.2%0.7%, or $16.4 million, compared to the prior year and an increase in rates of $12.5 million due to the decoupling rate mechanism.year. The additional usage was due to an increase of residential sales and commercial use per customerother retail sales of 6.7%2.5% and 2.2%1.1%, respectively, which was driven by an increase in heating degree days of 19.9%3.5% compared to 2016,2018 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.
Decoupling revenue decreased $20.0•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 deferralsrevenue decreased $1.4 million, primarily related to earnings in excess of $23.5allowed ROR. In 2018, $10.1 million driven by actual revenue being closerof earnings in excess of allowed ROR was passed back to PSE's allowed revenue per the decoupling mechanismcustomers, as compared to 2016. The increaseonly $3.5 million in actual revenue was due to an increase in load as discussed above in electric retail sales.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 decoupling revenue of $3.5 million due to fixed production cost deferrals, which were removed from the PCA mechanism and placed into the decoupling mechanism effective January 1, 2017.
Other decoupling revenue decreased $6.5 million due to an increase2019 than in decoupling collections of $9.5 million due to an increase in rates in 2017.2018. In 2016,addition, there was $1.3a $1.7 million increase related to GAAP alternative revenue program recognition guidelines. In 2018, there was $0.8 million of decoupling deferred revenue that couldwas not anticipated to be collected within 24 months, compared to no reserveand therefore was deferred. This amount was recognized in the current year. The decoupling collection and refundfirst quarter of rate of return (ROR) excess earnings are driven by2019, when the tariff rates and retail sales.
alternative revenue program revenue recognition guidelines were met.•Transportation and other revenue increased $92.5$65.0 million primarily due to a change in production tax credit (PTC) deferral revenue of $73.2 million due to a $19.9 million reduction to revenue in 2016 as PTCs were generated compared to no PTC generated in 2017, as well as, a $51.2 million remeasurement of the PTC deferral in 2017 due to tax law change. Additionally, there was an increase in net wholesale natural gas sales of $17.5$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 $14.9 million for the re-purpose of the PTCs The increase in net wholesale non-core natural gas sales was due to increased purchased electricity, as discussed below.
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 $43.2$90.7 million primarily due to an increase of $58.4 million of purchased electricity costs, partially offset by a decrease of $9.1$78.7 million of electric generation fuel expensecosts and an increase of $6.1$13.8 million of residential exchange credits.purchased electricity costs. These items are discussed in detail below:
•Purchased electricity expense increased $58.4$13.8 million primarily due to an 11.2%a 15.9% increase in wholesale electricity purchases,prices partially offset by a 0.2%11.9% decrease in prices.wholesale electricity purchases. The increasedecrease in purchases was primarily driven by an increase in load and lower wholesale electricity prices on the open market compared to generating power. Additionally, a decrease in hydro purchases at Mid-Columbia of hydro and wind production of 7.4% and 14.7%23.7%, increased the need to purchase additional wholesale power.
Electric generation fuel expense decreased $9.1 million primarily due to a $2.7 million reductionunfavorable hydro conditions, driving an increase in combustion turbine generation, costs as a result of a 7.9% reduction in combustion turbine generation due to favorable wholesale electricity prices and a $6.3 million decrease in coal generation costs primarily at Colstrip units 3 and 4 for variable fuel costs due to less coal delivered and burned in 2017.
Residential exchange credits increased $6.1 million resulting from higher Residential Exchange Program (REP) credits associated with the BPA REP settlement due to the REP credit tariff increase in 2017 and increased usage. 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 BPA. Pursuant to agreements (including settlement agreements) between BPA and PSE, 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.
The following chart displays the changes in PSE’s electric margin from 2015 to 2016:
_______________
| |
*
| Includes decoupling cash collections, rate of return excess earnings, and decoupling 24-month revenue reserve. |
2015 compared to 2016
Electric Operating Revenue
Electric operating revenues increased $110.0 million primarily due to higher retail sales of $81.1 million, increased decoupling revenue of $16.3 million and transportation and other revenue of $13.6 million. These items are discussed in detail below:
Electric retail sales increased $81.1 million due to increases in rates of $86.4 million primarily from the reduction of the residential exchange credits and an increase in the decoupling rate mechanism. The increase from rates was partially offset by $5.6 million due to a 0.3% reduction in retail electricity usage. The reduction in usage was due to a decrease of residential, commercial and industrial average use per customer of 0.6%, 2.7% and 2.5%, respectively, as a result of energy efficiency. The reduction in use per customer were offset by an increase in retail customers of 1.5% and an increase in heating degree days of 0.6% compared to 2015.
Decoupling revenue increased $16.3 million due to actual revenues were lower than PSE's allowed revenue per the decoupling mechanism compared to 2015. This increase was primarily from residential and commercial decoupled rate schedules, which increased $15.6 million in 2016. The increase was driven from an increase in customers which increases the allowed revenue and a decrease in use per customer, which lowers the actual revenue resulting in higher decoupled revenue.
Other decoupling revenue decreased $4.5 million due to an increase of $16.8 million of decoupling collections as compared to 2015 from an increase in rates in 2016; partially offset by a decrease in the ROR excess earnings sharing of $13.5 million from a reduction in the ROR excess earnings accrual of $6.5 million compared to 2015 and an increase of $7.0 million in refunds to customers for the 2015 ROR excess earnings set into customer rates in 2016. The decoupling collection and refund of ROR excess earnings are driven by the tariff rates and retail sales.
Transportation and other revenue increased $13.6 million primarily due to a reduction of amortization of PTC deferral credits of $10.1 million since PTC generation at Hopkins Ridge ended in 2015 and increase in net wholesale natural gas sales of $6.8 million.
Electric Power Costs
Electric power costs increased $40.1 million primarily due to a decrease of $42.6 million of residential exchange credit, an increase of $32.1 million of purchased electricity costs, partially offset by a decrease of $34.6 million of electric generation fuel expense. These items are discussed in detail below:
Purchased electricity expense increased $32.1 million primarily due to a 16.1% increase in wholesale electricity purchases, partially offset by a 8.3% decrease in wholesale electricity prices. The increase in purchases was primarily driven by an increase in load and lower wholesale electricity prices on the open market compared to generating power. Additionally, an increase of hydro and wind production of 32.2% and 14.4% decreased the need to purchase additional wholesale power due to favorable conditions.
power.•Electric generation fuel expense decreased $34.6increased $78.7 million primarily due to a $43.0$63.0 million reductionincrease in combustion turbine generation costs primarily driven by an increase in generation of 61.2% as a result of a 28.8% reduction in combustion turbine generation due to favorable heat rates, unfavorable wholesale electricity prices, reduced hydro purchases of 23.7% and increasedreduced hydro and wind generation of 22.0% and hydro generation.13.7%, respectively. This was partially offset by an $8.4 million increasea decrease in coal generation costs primarily due to an increasecost per kWh generated of 8.7%,
For additional information on prior years, please see discussion in the weighted-average costItem 7, "Non-GAAP Financial Measures - Electric Margin" of coal.
Form 10-K for period ended December 31, 2018.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 BPA. Pursuant to agreements (including settlement agreements) between BPA and PSE, 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.
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 chart displays the changes in PSE’s natural gas margin from 2016for the years ended December 31, 2018, to 2017:December 31, 2019:
_______________
*Includes decoupling cash collections, rate of return excess earnings, and decoupling 24-month revenue reserve.
20162018 compared to 20172019
Natural Gas Operating Revenue
Natural gas operating revenueincreased $107.3$24.6 million primarily due to higher retail sales of $148.1$9.3 million, increased transportation and other revenue of $11.9 million and increased other decoupling revenue of $5.9$7.3 million; partially offset by a decrease in decoupling revenue of $48.6$3.8 million. These items are discussed in the following details:
•Natural gas retail sales increased $148.1$9.3 million due to an increase of $155.1 million in natural gas sales, which is a result of an increase in natural gas load of 18.0% from 2016,4.8%, or $44.7 million in natural gas sales, which was partially offset by a decrease in revenue per thermrates of $6.9$35.4 million. The decrease in revenue per therm wasNatural gas load increased primarily due to a rate decrease on customer bills for PGA, which decreased rates 0.4% effective November 1, 2016 andthe year over year increase in decoupling ratesusage for residential and commercial firm customers of 2.4% effective May 1, 2017, see6.0% 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 rate changes. Naturalusage, as noted above in the retail revenue section. This resulted in actual natural gas load increased primarily duerevenues being closer to allowed natural gas revenues in the current year as compared to the increase in average therms used per residential and commercial customers of 17.4% and 18.9%, respectively, compared to 2016 as a result of a 19.9% increase in heating degree days and an increase of 1.5% in natural gas customers, whichprior year.
•Other decoupling revenue increased the natural gas heating load compared to prior year.
Decoupling revenue decreased $48.6$7.3 million, primarily due to an increasea $12.0 million decrease in use per customer, driven by an increase in heating degree days as discussed above in natural gas retail sales. This caused actual revenue to increase closer to PSE's allowed revenue, which lowered decoupled revenue in 2017.
Other decoupling revenue increased $5.9 millioncurrent year amortization of prior 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 following: (i) an increaseprior year's estimate of earnings in decoupling collectionsexcess of $14.7 million from an increaseallowed ROR was trued up to match actual earnings in the amortization rate in 2017 and an increase in therms used; (ii) in 2017,excess of allowed ROR by a favorable $3.4 million. In 2019, there was $19.6no 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 deferred decoupling revenue that was recognized as it met the alternative revenue program revenue recognition criteria that it is expected to be collected from customers within 24 months, compared to the 24-month reserve of $9.6 million in 2016; and (iii) an increase in net overearnings accruals and cash refunds of $8.6$15.4 million.
Natural Gas Energy Costs
Purchased natural gas expense increased $46.1decreased $5.7 million due to an increasea decrease in natural gas costs included in PGA rates effective November 1, 2016 as compared to those effective November 1, 2015, and an increase in natural gas usage of 18.0%.
The following chart displays the changes in PSE’s natural gas margin from 2015 to 2016:
_______________
| |
*
| Includes decoupling cash collections, rate of return excess earnings, and decoupling 24-month revenue reserve. |
2015 compared to 2016
Natural gas operating revenue decreased $57.0 million primarily due to lower natural gas retail sales revenue of $53.7 million and a decrease in other decoupling revenue of $2.7 million, see discussion below.
Natural gas retail sales revenue decreased $53.7 million due to a decrease in revenue per therm of $90.6 million, partially offset by an increase of $41.0 million in natural gas sales, due to an increase in natural gas load of 4.6% from 2015. The decrease in revenue per therm was primarily due to a rate decrease on customer bills for PGA, which decreased rates 17.4% effective November 1, 2015 partially offset by an increase in decoupling rates of 2.8% effective May 1, 2016, see Management's Discussion and Analysis, "Regulation and Rates" included in Item 7 of this report for natural gas rate changes. Natural gas load increased primarily due to the increase in average therms used per residential and commercial customers of 4.0% and 0.7%, respectively, compared to 2015. In addition, natural gas customers increased by 1.6% and heating degree days increased by 0.6%, which increased the natural gas heating load compared to prior year.
Other decoupling revenue decreased $2.7 million due to an increase in decoupling deferral collection of $17.9 million, as a result of an additional $17.3 million being set in rates on May 1, 2016, which was partially offset by a decrease in ROR excess earnings sharing accrual of $12.5 million and an increase in ROR excess earnings refund in 2016 of $2.5 million. The decoupling collection and refund of ROR excess earnings are driven by the tariff rates and customer usage.
Natural Gas Energy Costs
Purchased natural gas expense decreased $89.4 million primarily due to lower natural gas costs included in PGA rates effective November 1, 2015, which was partially offset by an increase in natural gas usage of 4.6%4.8%.
For additional information on prior years, please see discussion in Item 7, "Non-GAAP Financial Measures - Natural Gas Margin" of Form 10-K for period ended December 31, 2018.
Other Operating Expenses and Other Income (Deductions)
The following chart displays the details of PSE's other operating expenses and other income (deductions) from period 2016for the years ended December 31, 2018, to 2017:December 31, 2019:
20162018 compared to 20172019
Other Operating Expenses
•Net unrealized (gain) loss on derivative instruments expense increased $114.6 decreased $45.2 million to a net loss of $30.8$3.6 million for the year ended December 31, 2017. The primary2019. One of the drivers for the increase consistchange is related to the net settlements of a reduction of $20.6electric and natural gas trades previously recorded as $36.4 million in gains from contract settlements previously recorded asand $15.4 million in losses, that settledrespectively. The other driver is related to purchased electricity orthe change in the weighted average forward prices for electric generation fueland natural gas. Specifically, electric price decreased 16.7% resulting in a $2.6 million loss for electric. Natural gas derivative unrealized 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 $94.0decrease in forward prices at December 31, 2019.
•Utility operations and maintenance expense decreased $6.0 million lossprimarily due to a decrease in natural gas and electricity forward prices of 26.9% and 27.5%, respectively. The $20.6 million reduction from contract settlements was comprised of a $16.5 million from natural gas and a $4.1 million from wholesale electric contracts. The decrease in the weighted average natural gas and wholesale electric forward prices resulted in a $78.4 million loss and a $15.6 million loss, respectively.
Utility operations and maintenance expense increased $15.8 million primarily driven by increases in the following: $6.7(i) bad debt expense of $5.4 million for electricdue 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 natural gas operations(iv) rent expense of $1.7 million due to facility consolidations; partially offset by (v) an increase in hardware and software maintenance costs of $7.5 million due to an increase in IT projects..
•Non-utility and other expense decreased $7.0 million primarily due to increased electric operations third-party service providera decrease in biogas gas purchase expense of $5.6 million and a decrease in non-qualified pension plan costs of $3.2 million and gas distribution system integrity costs of $2.0 million $5.5 million increase in outside services expense for customer service optimization initiatives that began in 2016, and a $4.6 million increase in overall labor expense. These increases were$1.9 million; partially offset by $1.6 million reduction of uncollectible account costs compared to 2016.
Non-utility and other expense increased $14.5 million primarily due to an increase in the long-term incentive plan accrual of $12.3$1.4 million due to an increase in 2017 which resulted from a total returnlong-term incentive plan awards in 2017 of 29.1% which resulted in the total return component to be funded at 200.0%. For more information see Part III, "Executive Compensation" included in Item 11 of this report for the Company's long term incentive plan.
2019.•Depreciation and amortization expense increased $55.8decreased $25.2 million primarily due to the following:driven by: (i) electric depreciation expense of $12.1 million, primarily due to asset net additions to distribution, transmission, and general plant of $186.4 million, $92.0 million and $83.1 million respectively; (ii) natural gas depreciation expense of $6.1 million increased due primarily to net additions to distribution assets of $192.3 million; (iii) $15.5 million of amortization expense due to
computer software net additions of $123.7 million; (iv)a decrease in amortization of PTC regulatory liability of $2.1$15.4 million in 2017;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 amortization of the 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 the Washington Commission, (v) a decrease of Lower Snake River U.S. Treasury interest in conservation
amortization of $3.2 million;$15.1 million due to lower rates in 2019 as compared to 2018; partially offset by (vi) an increase in common amortization of ARO accretion$33.8 million driven by net additions of $88.3 million of software; (vii) electric depreciation expense of $2.8increased $10.2 million due to a change in the Colstrip ARO in 2016; and (vii) conservation amortization increased $13.4 million, $10.3 for electric and $3.2 for natural gas, primarily due to an increasenet asset additions to distribution of usage attributed to$212.5 million and (viii) an increase in heating degree days and customers for both electric and natural gas in 2017 as compareddepreciation expense of $7.3 million primarily due to 2016.net asset additions to distribution of $214.5 million.
•Taxes other than income taxes increased $32.0 decreased $2.7 million primarily due to increasesdecreases in municipal taxes of $11.5$2.4 million and state excise taxes of $10.2 million, as well as a resultdecrease of an increase in revenue and an increase of $9.3$2.1 million in property taxes related to increasedthe property values and expected levy rates.
tax tracker.
Other Income, Interest Expense and Income Tax Expense
•Other income/expense decreased $10.1 million as a result of an increase in other income of $7.9 million and a decrease in other expenses of $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 Washington Commission allowance for funds used during construction (AFUDC) 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 $36.6$11.3 million primarily driven by the impactrelated to PSE's issuance of tax reform on the deferred tax balances and partially offset by a 4.3% decrease in pre-tax income.$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.
The following chart displays the details of PSE's other operating expenses and other income (deductions) from period 2015 to 2016:
2015 compared to 2016
OtherFor additional information on prior years, please see discussion in Item 7, "Other Operating Expenses
Net unrealized (gain) loss on derivative instruments expense decreased $71.1 million to a net gain and Other Income (Deductions)" of $83.8 millionForm 10-K for the yearperiod ended December 31, 2016. The primary drivers for the 2016 net gain consist of a $61.7 million gain from contract settlements previously recorded as losses in the 2015 unrealized gain on derivative instruments that settle to purchased electricity and electric generation fuel. The $61.7 million gain from contract settlements was comprised of a $39.7 million gain from natural gas and a $22.0 million gain from wholesale electric contract settlements. Natural gas and wholesale electricity gain increased $22.1 million primarily due to increases in forward market prices of 5.7% and 10.8%, respectively. This compares to a net gain of $12.7 million in 2015, comprised of $83.6 million in settlement gains offset by a $70.9 million loss due to a decrease in natural gas and wholesale electricity prices.2018.
Utility operations and maintenance expense increased $37.8 million primarily driven by (i) an increase of $26.9 million of maintenance expense primarily related to natural gas leak repairs and sewer cross bore inspections, maintenance on gearboxes and generators at the Hopkins Ridge and Wild Horse wind generation facilities, electric distribution maintenance for overhead lines and vegetation management; (ii) an increase of outside services expense of $7.4 million primarily related to customer service initiatives; (iii) an increase of salary expense of $2.9 million primarily related to incentive increases; partially offset by (iv) a decrease of $4.6 million in meter reading expense due to the purchase of previously leased meter reading equipment during 2015.
Depreciation and amortization expense increased $15.7 million primarily due to $16.5 million of depreciation expense primarily due to net additions of $173.9 million of natural gas distribution assets, $148.5 million of electric distribution assets and $90.6 million of electric transmission assets.
Taxes other than income taxes increased $8.1 million primarily due to an increase in electric property taxes of $6.0 million based on assessed value and levy rates, electric state excise and municipal taxes of $5.8 million driven by an increase in electric revenue, partially offset by a decrease of $4.8 million in natural gas state excise and municipal taxes from a decrease in natural gas revenue.
Other Income, Interest Expense and Income Tax Expense
Interest expense decreased $6.3 million primarily due to a reduction of $3.8 million in interest on long-term debt related to debt that was refinanced in May 2015 at an interest rate of 4.30% compared to interest rates of 5.197% and 6.75%; and an increase of $1.7 million related to allowance for funds used during construction (AFUDC) debt due to an increase in average construction work in progress (CWIP).
Income tax expense increased $49.4 million primarily driven by $44.0 million from higher pre-tax income and an increase of $6.5 million due to Hopkins Ridge no longer generating PTCs. PTCs are generated for the first ten years at a wind facility. As of December 2015, Hopkins Ridge is no longer eligible to generate PTCs. For additional information, see Note 13, "Income Taxes" to the consolidated financial statements included in Item 8 of this report.
Puget Energy
Substantially all the operations of Puget Energy are conducted through its regulated subsidiary, PSE. Puget Energy’s results of operation for the years ended December 31, 2017, 20162018, and 2015December 31, 2019, were as follows:
20162018 compared to 20172019
Summary Results of Operations
Puget Energy’s net income decreased by $137.7$24.9 million, which is primarily attributable to an income tax expense increase of $79.3 million, as well asa decrease in PSE's net income decrease of $60.5$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:
Income Tax Expense increased by $79.3 million primarily due to tax reform passed on December 22, 2017 that lowered the corporate tax rate from 35.0% to 21.0%. As a result, income tax expense was effected by the revaluation of Puget Energy's deferred tax assets at the 21.0% rate.
2015 compared to 2016
Item 7, "PE Summary Results of OperationsOperation" of Form 10-K for period ended December 31, 2018.
Puget Energy’s net income increased by $71.7 million, which is primarily attributable to PSE's net income increase of $76.4 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 $5.1 million primarily due to legal outside services of $2.8 million and qualified pension expense of $1.2 million.52
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, 2017:2019:
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| 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 | | 2018 | | 2019 - 2020 | | 2021 - 2022 | | Thereafter |
Contractual obligations: | | | | | | | | | |
Energy purchase obligations1 | $ | 5,508,991 |
| | $ | 824,417 |
| | $ | 1,352,132 |
| | $ | 1,184,192 |
| | $ | 2,148,250 |
|
Long-term debt including interest2 | 7,967,957 |
| | 402,854 |
| | 393,521 |
| | 393,521 |
| | 6,778,061 |
|
Short-term debt including interest | 329,463 |
| | 329,463 |
| | — |
| | — |
| | — |
|
Service contract obligations | 724,899 |
| | 76,919 |
| | 145,371 |
| | 149,222 |
| | 353,387 |
|
Non-cancelable operating leases3 | 171,813 |
| | 21,371 |
| | 36,584 |
| | 15,884 |
| | 97,974 |
|
PSE capital leases3 | 1,162 |
| | 527 |
| | 538 |
| | 97 |
| | — |
|
Pension and other benefits funding and payments | 78,187 |
| | 23,803 |
| | 10,685 |
| | 6,305 |
| | 37,394 |
|
Total PSE contractual cash obligations | 14,782,472 |
| | 1,679,354 |
| | 1,938,831 |
| | 1,749,221 |
| | 9,415,066 |
|
Long-term debt including interest2 | 2,321,374 |
| | 201,763 |
| | 647,043 |
| | 1,038,008 |
| | 434,560 |
|
Total Puget Energy contractual cash obligations | $ | 17,103,846 |
| | $ | 1,881,117 |
| | $ | 2,585,874 |
| | $ | 2,787,229 |
| | $ | 9,849,626 |
|
___________________________________
| |
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, 2017:2019:
| | | Amount of Available Commitments Expiration Per Period | | Amount of Available Commitments Expiration Per Period | |
(Dollars in Thousands) | Total |
| | 2018 |
| | 2019 - 2020 | | 2021 - 2022 |
| | Thereafter |
| (Dollars in Thousands) | Total | | 2020 | | 2021-2022 | | 2022-2023 | | Thereafter |
Commercial commitments: | | | | | | | | | | Commercial commitments: | | | | | | | | | |
PSE revolving credit facility1 | $ | 800,000 |
| | $ | — |
| | $ | — |
| | $ | 800,000 |
| | $ | — |
| 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 | 830,000 |
| | — |
| | — |
| | 800,000 |
| | 30,000 |
| Total PSE commercial commitments | 830,000 | | | — | | | — | | | 800,000 | | | 30,000 | |
Puget Energy revolving credit facility3 | 697,400 |
| | — |
| | — |
| | 697,400 |
| | — |
| 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 | $ | 1,497,400 |
| | $ | — |
| | $ | — |
| | $ | 1,497,400 |
| | $ | — |
| Total Puget Energy commercial commitments | $1,575,900 | | | $— | | | $— | | | $1,575,900 | | | $— | |
_______________
| |
1
| As of December 31, 2017, 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 2022. 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, 2017, no loans or letters of credit were outstanding under the credit facility and $329.5 million was outstanding under the commercial paper program. The credit agreement is syndicated among numerous lenders. Outside of the credit agreement, PSE has a $3.1 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, 2017, 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, 2017, Puget Energy had a revolving senior secured credit facility totaling $800.0 million, which matures in October 2022. 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, 2017, there was $102.6 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, 2017,2019, 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, other than the items disclosed in Note 8, "Leases" and in Note 15, "Commitment and Contingencies" to the consolidated financial statements included in Item 2 of this report.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 $963.7$919.3 million in 2017.2019. 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) | 2018 | | 2019 | | 2020 |
Total energy delivery, technology and facilities expenditures | $ | 1,003,000 |
| | $ | 839,000 |
| | $ | 740,000 |
|
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, | Puget Sound Energy | Year Ended December 31, | |
(Dollars in Millions) | 2017 | | 2016 | | Change | |
(Dollars in Thousands) | | (Dollars in Thousands) | 2019 | | 2018 | | Change |
Net income | $ | 320,054 |
| | $ | 380,581 |
| | $ | (60,527 | ) | Net income | $ | 292,924 | | | | $ | 317,162 | | | | $ | (24,238) | |
Non-cash items1 | 782,890 |
| | 631,440 |
| | 151,450 |
| Non-cash items1 | 677,261 | | | | 670,632 | | | | 6,629 | |
Changes in cash flow resulting from working capital2 | 105,281 |
| | (46,554 | ) | | 151,835 |
| Changes in cash flow resulting from working capital2 | (107,355) | | | | 80,541 | | | | (187,896) | |
Regulatory assets and liabilities | (88,875 | ) | | (152,786 | ) | | 63,911 |
| Regulatory assets and liabilities | (79,173) | | | | (71,348) | | | | (7,825) | |
Purchased gas adjustment | | Purchased gas adjustment | (132,766) | | | — | | | (132,766) | |
Other non-current assets and liabilities3 | (32,547 | ) | | 6,235 |
| | (38,782 | ) | Other non-current assets and liabilities3 | (26,967) | | | | (1,083) | | | | (25,884) | |
Net cash provided by operating activities | $ | 1,086,803 |
| | $ | 818,916 |
| | $ | 267,887 |
| Net cash provided by operating activities | $ | 623,924 | | | | $ | 995,904 | | | | $ | (371,980) | |
_______________
| |
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. |
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, 20172019, compared to 20162018
Cash generated from operations for the year ended December 31, 2017 increased2019, decreased by $267.9$372.0 million, including a net income decrease of $60.5$24.2 million. The following are significant factors that impacted PSE's cash flows from operations:
Non-cash•Cash flow adjustments resulting from non-cash items increased $151.5$6.6 million primarily due to changes ina $45.2 million change from a net unrealized gain on derivative instruments of $114.6$41.7 million to a net unrealized loss on derivative instruments of $3.6 million, as well as a decrease in production tax credits monetization of $15.4 million, offset by decreases in depreciation and amortization of $42.4$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 $36.1 million and conservation amortization of $13.4 million offset by a decrease of $53.3 million in production tax credits.$10.5 million. For further discussion, see Other"Other Operating ExpensesExpenses" in Item 7, Management's Discussion and Analysis and Note 13,14, "Income Taxes" in Item 8.
Changes in cash flow•Cash flows resulting from changes in working capital increased $151.8 decreased $187.9 million primarily due to changesincreased cash outflow in accounts receivablepayable by $233.8 million, which was mainly due to payment of significant power and unbilled revenuenatural gas costs accrued as of $50.7 million, an increase to theDecember 31, 2018, that were paid in 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 $34.2$35.9 million as discussed previouslyand 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 electricPCA 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 margin discussion, an increase of $27.5 millioncosts being above natural gas baseline rates in materialsthe PGA mechanism. For further details, see "Natural Gas Margin" in Item 7, Management's Discussion and supplies, and an increase of $47.0 million in prepayments.
Analysis.Regulatory assets and liabilities cash•Cash flow increased $63.9 million primarily due toresulting from changes in decoupling and derivatives offset by changes in purchased gas adjustments.
Otherother non-current assets and liabilities cash flow decreased $38.8$25.9 million primarily due to an increasedecrease in the long-term incentive plan accrual, an increase in major maintenance and inspections, reduced pension funding andliability offset with other changes in long-term assets and liabilities.
| | Puget Energy | Year Ended December 31, | Puget Energy | Year Ended December 31, | |
(Dollars in Millions) | 2017 | | 2016 | | Change | |
(Dollars in Thousands) | | (Dollars in Thousands) | 2019 | | 2018 | | Change |
Net income | $ | 175,194 |
| | $ | 312,899 |
| | $ | (137,705 | ) | Net income | $ | (82,216) | | | $ | (81,540) | | | $ | (676) | |
Non-cash items1 | 837,569 |
| | 602,535 |
| | 235,034 |
| Non-cash items1 | (2,381) | | | (519) | | | (1,862) | |
Changes in cash flow resulting from working capital2 | 93,654 |
| | (24,936 | ) | | 118,590 |
| Changes in cash flow resulting from working capital2 | (4,800) | | | 4,558 | | | (9,358) | |
Regulatory assets and liabilities | (88,875 | ) | | (153,643 | ) | | 64,768 |
| Regulatory assets and liabilities | (60) | | | — | | | (60) | |
Other non-current assets and liabilities3 | (45,411 | ) | | (7,565 | ) | | (37,846 | ) | Other non-current assets and liabilities3 | (7,131) | | | (14,222) | | | 7,091 | |
Net cash provided by operating activities | $ | 972,131 |
| | $ | 729,290 |
| | $ | 242,841 |
| 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, AFUDC-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 pension liability. |
1.Non-cash items include depreciation, amortization, deferred income taxes, net unrealized (gain) loss on derivative instruments, AFUDC-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 pension liability.
Year Ended December 31, 20172019, compared to 20162018
Cash generated from operations for the year ended December 31, 2017 increased2019, decreased by $242.8$4.9 million compared to the same period in 2016.2018. 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 increased $83.6 decreased $1.9 million primarily due to changes in deferred taxes of $78.8$1.5 million. For further discussion, see Note 13, "Income Taxes" in Item 8.
•Changes in cash flow resulting from working capital decreased $33.2$9.4 million primarily due to amounts owed to PSE related to Puget LNG.
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.
For information on Puget Energy and PSE dividends, long-term debt and credit facilities, see Note 4,5, “Dividend Payment Restrictions, Note 6,7, “Long-term Debt” and Note 7,8, “Liquidity Facilities and Other Financing Arrangements” to the consolidated financial statements included in Item 8 of this report.
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, 2017,2019, PSE could issue:
•Approximately $2.6$2.0 billion of additional first mortgage bonds under PSE’s electric mortgage indenture based on approximately $4.3$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, 2017;2019; and
•Approximately $535.0$739.0 million of additional first mortgage bonds under PSE’s natural gas mortgage indenture based on approximately $891.7 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, 2017
2019At December 31, 2017,2019, PSE had approximately $7.2$7.8 billion in electric and natural gas rate base to support the interest coverage ratio limitation test for net earnings available for interest.
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. Management believes the following accounting policies are particularly important to the financial statements and 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. 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-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, 20172019, in the amount of $953.1$847.5 million and $1,758.6$1,676.6 million, respectively, and regulatory assets and liabilities at December 31, 20162018, of $1.1 billion$788.2 million and $653.3$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 Management's Discussion and Analysis, "Regulation and Rates" included in Item 7 "Business – Regulation and Rates".of this report. The increases and decreases in the cost of natural gas supply are reflected in customer bills through the PGA mechanism. PSE expects to fully recover/refund these regulatory balances 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 qualitative and quantitative test. Management must first assess qualitative factors to determine whether it is more likely than not that the fair value of a reporting unit is less than its carrying amount, including goodwill. If, after assessing the totality of events or circumstances during a qualitative assessment, management determines the fair value of a reporting unit is less than its carrying amount, then the entity shall perform a quantitative test to determine impairment. 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, 2017. 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 and other market factors, (ii) estimation of the long-term rate of growth for Puget Energy’s business including other market factors, (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 $5.5 billion at the October 1, 2017 measurement date for the annual test of goodwill impairment. The carrying value of Puget Energy’s equity was approximately $3.8 billion with the excess of the fair value over the carrying value representing 44.7% or $1.7 billion.
The income approach and the market approach valuations resulted in Puget Energy equity values of $5.2 and $5.8 billion, respectively. The result of the income approach was very sensitive to long-term cash flow growth rates applicable to periods beyond management’s five-year business plan and financial forecast period and the weighted-average cost of capital assumptions of 3.0% and 5.9%, 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 |
| 2.8 | % | | 2.9 | % | | 3.0 | % | | 3.1 | % | | 3.2 | % | �� | 3.3 | % |
6.2% | $ | 3.7 |
| | $ | 4.0 |
| | $ | 4.3 |
| | $ | 4.6 |
| | $ | 4.9 |
| | $ | 5.3 |
|
5.9 | 4.5 |
| | 4.9 |
| | 5.2 |
| | 5.6 |
| | 6.0 |
| | 6.5 |
|
5.7 | 5.6 |
| | 6.0 |
| | 6.4 |
| | 6.9 |
| | 7.4 |
| | 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 (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.
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. PSE 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, 2017, the Company did not have any outstanding interest rate swap instruments.
For additional information, see Item 7A, "Quantitative and Qualitative Disclosures about Market Risk" 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 $12.1 million, $14.5$12.6 million and $22.9$13.2 million for the years ended December 31, 2017, 20162019, and 2015,2018, respectively. Of these amounts, approximately 51.6%, 55.5%49.0% and 58.5%49.4% were included in utility operations and maintenance expense in 2017, 20162019 and 2015,2018, respectively, and the remaining amounts were capitalized. For the years ended December 31, 20172019, and 2016,2018, Puget Energy recognized incremental qualified pension income of $13.4$12.1 million and $15.5$13.1 million, respectively. In 2018,2020, it is expected that PSE and Puget Energy will recognize pension expense of $11.5$16.2 million and incremental qualified pension income of $13.0$11.1 million, respectively.
PSE has a Supplemental Executive Retirement Plan (SERP). PSE recognized pension and other postretirement benefit expenses of $4.8 million, $4.8$5.4 million and $5.6$5.1 million for the years ended December 31, 2017, 20162019, and 2015,2018, respectively. For the years ended December 31, 20172019, and 2016,2018, Puget Energy recognized incremental income of $0.5$0.4 million and $0.4$0.5 million, respectively. In 2018,2020, it is expected that PSE and Puget Energy will recognize pension expense of $5.1$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 $0.5 million and $0.2$0.5 million for the years ended December 31, 2017, 20162019, and 2015,2018, respectively. For the years ended December 31, 20172019, and 2016,2018, Puget Energy recognized incremental expense of $0.2 million each year. In 2018,2020, it is expected that PSE and Puget Energy will recognize incomeexpense of $0.5$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 2017,2019, the Company made cash contributions of $18.0 million to the qualified defined benefitpension plan. Management is closely monitoring the funding status of its qualified pension plan. At December 31, 20172019, and 2016,2018, the Company’s qualified pension plan was $3.9$21.3 million overfundedunderfunded and $32.3$37.4 million underfunded as measured under GAAP, or 100.6%97.3% and 95.0%94.5% funded, respectively. As of January 1, 2018,2020, 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, 20182020, are expected to be at least $18.0 million, $5.5$22.6 million and $0.3$0.1 million, respectively.
The discount rate used in accounting for pension and other benefit obligations decreased from 4.50%4.40% in 20162018 to 4.00%3.35% in 2017.2019. The discount rate used in accounting for pension and other benefit expense decreased from 4.65%was 4.40% in 2016 to 4.50% in 2017.both 2018 and 2019. The rate of return on plan assets for qualified pension benefits decreased from 7.75%was 7.50% in 2016 to 7.45% in 2017.both 2018 and 2019. The rate of return on plan assets for other benefits was 7.0% in 2017both 2018 and 2016 was 6.75%, 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) | | | | |
(Dollars in Thousands) |
|
| Pension Benefits | | SERP |
| Other Benefits |
Increase in discount rate | 50 basis points |
| $ | (44,028) | |
| $ | (1,440) | |
| $ | (528) | |
Decrease in discount rate | 50 basis points |
| 48,863 | | | 1,536 | |
| 576 | |
| | Puget Energy and Puget Sound Energy | Change in Assumption | | Impact on Projected Benefit Obligation Increase /(Decrease) | |
Puget Energy | | Puget 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 | | $ | (38,831 | ) | | $ | (1,940 | ) | | $ | (548 | ) | Increase in discount rate | 50 basis points |
| $ | (3,170) | | | $ | (126) | |
| $ | 7 | |
Decrease in discount rate | 50 basis points | | 43,000 |
| | 2,069 |
| | 601 |
| Decrease in discount rate | 50 basis points |
| 3,479 | | | 137 | |
| (24) | |
Increase in return on plan assets | | Increase in return on plan assets | 50 basis points |
| $ | (3,498) | | | * |
| $ | (28) | |
Decrease in return on plan assets | | Decrease in return on plan assets | 50 basis points |
| 3,498 | | | * |
| 28 | |
|
| | | | | | | | | | | | | |
Puget Energy | Change in Assumption | | Impact on 2017 Pension Expense Increase /(Decrease) |
(Dollars in Thousands) | | | Pension Benefits | | SERP | | Other Benefits |
Increase in discount rate | 50 basis points | | $ | 155 |
| | $ | (173 | ) | | $ | (50 | ) |
Decrease in discount rate | 50 basis points | | 2,333 |
| | 181 |
| | 52 |
|
Increase in return on plan assets | 50 basis points | | (3,207 | ) | | * |
| | (34 | ) |
Decrease in return on plan assets | 50 basis points | | 3,207 |
| | * |
| | 34 |
|
| | Puget Sound Energy | Change in Assumption | | Impact on 2017 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 | | $ | (2,906 | ) | | $ | (173 | ) | | $ | (51 | ) | Increase in discount rate | 50 basis points |
| $ | (3,717) | |
| $ | (128) | |
| $ | 8 | |
Decrease in discount rate | 50 basis points | | 3,026 |
| | 181 |
| | 52 |
| Decrease in discount rate | 50 basis points |
| 3,478 | |
| 138 | |
| (7) | |
Increase in return on plan assets | 50 basis points | | (3,212 | ) | | * |
| | (34 | ) | Increase in return on plan assets | 50 basis points |
| $ | (3,499) | |
| * |
| $ | (28) | |
Decrease in return on plan assets | 50 basis points | | 3,212 |
| | * |
| | 34 |
| 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, 2017 | | December 31, 2016 |
(Dollars in Thousands) | Assets | | Liabilities | | Assets | | Liabilities |
Electric portfolio: | | | | | | | |
Current | $ | 12,553 |
| | $ | 37,991 |
| | $ | 30,596 |
| | $ | 30,997 |
|
Long-term | 838 |
| | 11,059 |
| | 5,864 |
| | 10,332 |
|
Total electric derivatives | 13,391 |
| | 49,050 |
| | 36,460 |
| | 41,329 |
|
Natural Gas portfolio: | |
| | |
| | |
| | |
|
Current | 9,694 |
| | 26,868 |
| | 23,745 |
| | 13,172 |
|
Long-term | 1,320 |
| | 10,176 |
| | 2,874 |
| | 5,929 |
|
Total natural gas derivatives | 11,014 |
| | 37,044 |
| | 26,619 |
| | 19,101 |
|
Total energy derivatives | $ | 24,405 |
| | $ | 86,094 |
| | $ | 63,079 |
| | $ | 60,430 |
|
At December 31, 2017,2019, the Company had total assets of $24.4$31.3 million and total liabilities of $86.1$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 $10.6$30.1 million.
The change in fair value of the Company’s outstanding energy derivative instruments from December 31, 20162018, through December 31, 20172019, 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, 2016 | | $ | 2,649 |
|
Contracts realized or otherwise settled during 2017 | | 54,169 |
|
Change in fair value of derivatives | | (118,507 | ) |
Fair value of contracts outstanding at December 31, 2017 | | $ | (61,689 | ) |
The fair value of the Company’s outstanding derivative instruments at December 31, 2017,2019, 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) | 2018 | | 2019-2020 | | 2021-2022 | | Thereafter | | Total | (Dollars in Thousands) | 2020 | | | 2021-2022 | | 2023-2024 | | Thereafter | | Total |
Prices provided by external sources1 | $ | (46,927 | ) | | $ | (17,434 | ) | | $ | (349 | ) | | $ | — |
| | $ | (64,710 | ) | Prices provided by external sources1 | $ | 9,784 | | | $ | (564) | | | $ | (1,937) | | | $ | — | | | $ | 7,283 | |
Prices based on internal models and valuation methods | 4,315 |
| | 18 |
| | (1,312 | ) | | — |
| | 3,021 |
| Prices based on internal models and valuation methods | 413 | | | (2,282) | | | (228) | | | — | | | (2,097) | |
Total fair value | $ | (42,612 | ) | | $ | (17,416 | ) | | $ | (1,661 | ) | | $ | — |
| | $ | (61,689 | ) | 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, and began transacting power futures contractstransacts on the Intercontinental Exchange (ICE) 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, 2017,2019, PSE held approximately $458.5$571.6 million in standby letters of credit or limited parental guarantees and had 6nine counterparties with unlimited parental guarantees, in support of various electric and natural gas transactions. The Company monitors counterparties for significant swings in credit default swap rates, credit rating changes by external rating agencies, ownership changes or financial distress. As of December 31, 2017,2019, approximately 83.6%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, 2017,2019, 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, 2017,2019, 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, 2017 | | December 31, 2016 |
(Dollars in Thousands) | Carrying Amount | | Fair Value | | Carrying Amount | | Fair Value |
Puget Energy | $ | 5,787,392 |
| | $ | 7,191,513 |
| | $ | 5,599,836 |
| | $ | 6,805,791 |
|
Puget Sound Energy | $ | 4,079,374 |
| | $ | 5,118,528 |
| | $ | 3,993,061 |
| | $ | 4,816,807 |
|
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, 20172019, was a net loss of $5.0$5.4 million after tax and accumulated amortization. This compares to an after-tax loss of $5.4$5.7 million in OCI as of December 31, 2016.2018. 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, 2017.2019.
The Company may also enter into swap instruments or other financial hedge instruments to manage the interest rate risk associated with these debts. In January 2017, Puget Energy's outstanding interest rate swaps matured, and asAs of December 31, 2017,2019, the Company had no outstanding interest rate swap instruments.
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.
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| | | | | | | | | | | | | |
/s/ Kimberly J. HarrisMary E. Kipp |
| /s/ Daniel A. Doyle |
| /s/ Stephen J. King |
Kimberly J. HarrisMary 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 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. (the Company) 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, 2017,2019, 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 consolidatedfinancial statements referred to above present fairly, in all material respects, the financial position of the Company as of December 31, 20172019 and 2016, 2018, and the results of theirits operations and theirits cash flows for each of the three years in the period ended December 31, 20172019 in conformity with accounting principles generally accepted in the United States of America. Also in our opinion, the Company maintained, in all material respects, effective internal control over financial reporting as of December 31, 2017,2019, based on criteria established in Internal Control - Integrated Framework(2013)issued by the COSO.
Change in Accounting Principle
As discussed in Note 2 to the 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, 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.Reporting appearing under Item 9A. Our responsibility is to express opinions on the Company’s consolidatedfinancial statements and on the Company's internal control over financial reporting based on our audits. We are a public accounting firm registered with the Public Company Accounting Oversight Board (United States) ("PCAOB")(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 PCAOB. Those standards require that we plan and perform the audits to obtain reasonable assurance about whether the consolidatedfinancial 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 regarding the amounts and disclosures in the consolidated financial statements. Our audits also included evaluating the accounting principles used and significant estimates made by management, as well as evaluating the overall presentation of the consolidated financial 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 1, 2018February 21, 2020
We 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 ReportingReporting.
We have audited the consolidated financial statements, including the related notes and financial statement schedule, of Puget Sound Energy, Inc. (the Company) 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, 2017,2019, 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 consolidatedfinancial statements referred to above present fairly, in all material respects, the financial position of the Company as of December 31, 20172019 and 2016, 2018, and the results of theirits operations and theirits cash flows for each of the three years in the period ended December 31, 20172019 in conformity with accounting principles generally accepted in the United States of America. Also in our opinion, the Company maintained, in all material respects, effective internal control over financial reporting as of December 31, 2017,2019, based on criteria established in Internal Control - Integrated Framework(2013)issued by the COSO.
Change in Accounting Principle
As discussed in Note 2 to the 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, 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.Reporting appearing under Item 9A. Our responsibility is to express opinions on the Company’s consolidatedfinancial statements and on the Company's internal control over financial reporting based on our audits. We are a public accounting firm registered with the Public Company Accounting Oversight Board (United States) ("PCAOB")(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 PCAOB. Those standards require that we plan and perform the audits to obtain reasonable assurance about whether the consolidatedfinancial 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 regarding the amounts and disclosures in the consolidated financial statements. Our audits also included evaluating the accounting principles used and significant estimates made by management, as well as evaluating the overall presentation of the consolidated financial 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 1, 2018February 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, |
| 2017 | | 2016 | | 2015 |
Operating revenue: | | | | | |
Electric | $ | 2,420,663 |
| | $ | 2,238,492 |
| | $ | 2,128,468 |
|
Natural gas | 997,759 |
| | 890,510 |
| | 947,549 |
|
Other | 41,854 |
| | 35,299 |
| | 16,683 |
|
Total operating revenue | 3,460,276 |
| | 3,164,301 |
| | 3,092,700 |
|
Operating expenses: | |
| | |
| | |
|
Energy costs: | |
| | |
| | |
|
Purchased electricity | 590,030 |
| | 531,596 |
| | 499,522 |
|
Electric generation fuel | 206,275 |
| | 215,331 |
| | 249,907 |
|
Residential exchange | (75,933 | ) | | (69,824 | ) | | (112,473 | ) |
Purchased natural gas | 360,009 |
| | 313,954 |
| | 403,310 |
|
Unrealized (gain) loss on derivative instruments, net | 30,790 |
| | (83,795 | ) | | (13,233 | ) |
Utility operations and maintenance | 584,263 |
| | 568,492 |
| | 530,720 |
|
Non-utility expense and other | 40,487 |
| | 27,151 |
| | 10,818 |
|
Depreciation and amortization | 481,969 |
| | 439,579 |
| | 420,807 |
|
Conservation amortization | 121,216 |
| | 107,784 |
| | 110,866 |
|
Taxes other than income taxes | 360,673 |
| | 328,649 |
| | 320,531 |
|
Total operating expenses | 2,699,779 |
| | 2,378,917 |
| | 2,420,775 |
|
Operating income (loss) | 760,497 |
| | 785,384 |
| | 671,925 |
|
Other income (deductions): | |
| | |
| | |
|
Other income | 27,892 |
| | 25,539 |
| | 20,711 |
|
Other expense | (14,104 | ) | | (10,923 | ) | | (6,764 | ) |
Non-hedged interest rate swap expense | 28 |
| | (1,062 | ) | | (3,796 | ) |
Interest charges: | |
| | |
| | |
|
AFUDC | 10,826 |
| | 9,304 |
| | 7,575 |
|
Interest expense | (354,802 | ) | | (355,139 | ) | | (356,696 | ) |
Income (loss) before income taxes | 430,337 |
| | 453,103 |
| | 332,955 |
|
Income tax (benefit) expense | 255,143 |
| | 140,204 |
| | 91,776 |
|
Net income (loss) | $ | 175,194 |
| | $ | 312,899 |
| | $ | 241,179 |
|
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, |
| 2017 | | 2016 | | 2015 |
Net income (loss) | $ | 175,194 |
| | $ | 312,899 |
| | $ | 241,179 |
|
Other comprehensive income (loss): | |
| | |
| | |
|
Net unrealized gain (loss) from pension and postretirement plans, net of tax of $5,078, $(3,471) and $5,087, respectively | 9,430 |
| | (6,446 | ) | | 9,444 |
|
Reclassification of net unrealized (gain) loss on energy derivative instruments, net of tax of $0, $0 and $179, respectively | — |
| | — |
| | 333 |
|
Other comprehensive income (loss) | 9,430 |
| | (6,446 | ) | | 9,777 |
|
Comprehensive income (loss) | $ | 184,624 |
| | $ | 306,453 |
| | $ | 250,956 |
|
The accompanying notes are an integral part of the consolidated financial statements.
PUGET ENERGY, INC.
CONSOLIDATED BALANCE SHEETS
(Dollars in Thousands)
ASSETS
|
| | | | | | | |
| December 31, |
| 2017 | | 2016 |
Utility plant (at original cost, including construction work in progress of $495,937 and $420,278, respectively): | | | |
Electric plant | $ | 8,135,847 |
| | $ | 7,673,772 |
|
Natural gas plant | 3,307,545 |
| | 3,051,586 |
|
Common plant | 811,815 |
| | 594,994 |
|
Less: Accumulated depreciation and amortization | (2,428,524 | ) | | (2,161,796 | ) |
Net utility plant | 9,826,683 |
| | 9,158,556 |
|
Other property and investments: | |
| | |
|
Goodwill | 1,656,513 |
| | 1,656,513 |
|
Other property and investments | 182,355 |
| | 106,418 |
|
Total other property and investments | 1,838,868 |
| | 1,762,931 |
|
Current assets: | |
| | |
|
Cash and cash equivalents | 26,616 |
| | 28,878 |
|
Restricted cash | 10,145 |
| | 12,418 |
|
Accounts receivable, net of allowance for doubtful accounts of $8,901 and $9,798, respectively | 341,110 |
| | 329,375 |
|
Unbilled revenue | 222,186 |
| | 234,053 |
|
Purchased gas adjustment receivable | — |
| | 2,785 |
|
Materials and supplies, at average cost | 107,003 |
| | 106,378 |
|
Fuel and natural gas inventory, at average cost | 49,908 |
| | 58,181 |
|
Unrealized gain on derivative instruments | 22,247 |
| | 54,341 |
|
Prepaid expense and other | 21,996 |
| | 43,046 |
|
Power contract acquisition adjustment gain | 12,207 |
| | 33,413 |
|
Total current assets | 813,418 |
| | 902,868 |
|
Other long-term and regulatory assets: | |
| | |
|
Regulatory asset for deferred income taxes | — |
| | 72,038 |
|
Power cost adjustment mechanism | 4,576 |
| | 4,531 |
|
Regulatory assets related to power contracts | 19,454 |
| | 22,613 |
|
Other regulatory assets | 948,532 |
| | 1,034,348 |
|
Unrealized gain on derivative instruments | 2,158 |
| | 8,738 |
|
Power contract acquisition adjustment gain | 162,711 |
| | 241,648 |
|
Other | 74,389 |
| | 58,109 |
|
Total other long-term and regulatory assets | 1,211,820 |
| | 1,442,025 |
|
Total assets | $ | 13,690,789 |
| | $ | 13,266,380 |
|
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, |
| 2017 | | 2016 |
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 | 465,355 |
| | 413,468 |
|
Accumulated other comprehensive income (loss), net of tax | (24,282 | ) | | (33,712 | ) |
Total common shareholder’s equity | 3,750,030 |
| | 3,688,713 |
|
Long-term debt: | |
| | |
|
First mortgage bonds and senior notes | 3,164,412 |
| | 3,362,000 |
|
Pollution control bonds | 161,860 |
| | 161,860 |
|
Junior subordinated notes | 250,000 |
| | 250,000 |
|
Long-term debt | 1,902,600 |
| | 1,812,480 |
|
Debt discount, issuance costs and other | (220,943 | ) | | (234,679 | ) |
Total long-term debt | 5,257,929 |
| | 5,351,661 |
|
Total capitalization | 9,007,959 |
| | 9,040,374 |
|
Current liabilities: | |
| | |
|
Accounts payable | 359,586 |
| | 317,043 |
|
Short-term debt | 329,463 |
| | 245,763 |
|
Current maturities of long-term debt | 200,000 |
| | 2,412 |
|
Purchased gas adjustment payable | 16,051 |
| | — |
|
Accrued expenses: | |
| | |
|
Taxes | 117,948 |
| | 111,428 |
|
Salaries and wages | 53,220 |
| | 49,749 |
|
Interest | 73,564 |
| | 73,610 |
|
Unrealized loss on derivative instruments | 64,859 |
| | 44,310 |
|
Power contract acquisition adjustment loss | 2,762 |
| | 3,159 |
|
Other | 80,206 |
| | 71,996 |
|
Total current liabilities | 1,297,659 |
| | 919,470 |
|
Other Long-term and regulatory liabilities: | |
| | |
|
Deferred income taxes | 746,868 |
| | 1,570,931 |
|
Unrealized loss on derivative instruments | 21,235 |
| | 16,261 |
|
Regulatory liabilities | 731,587 |
| | 654,622 |
|
Regulatory liability for deferred income taxes | 1,011,626 |
| | — |
|
Regulatory liabilities related to power contracts | 174,918 |
| | 275,061 |
|
Power contract acquisition adjustment loss | 16,693 |
| | 19,454 |
|
Other deferred credits | 682,244 |
| | 770,207 |
|
Total other long-term and regulatory liabilities | 3,385,171 |
| | 3,306,536 |
|
Commitments and contingencies (Note 15) |
|
| |
|
|
Total capitalization and liabilities | $ | 13,690,789 |
| | $ | 13,266,380 |
|
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, 2014 | 200 |
| | $ | — |
| | $ | 3,308,957 |
| | $ | 271,414 |
| | $ | (37,043 | ) | | $ | 3,543,328 |
|
Net income (loss) | — |
| | — |
| | — |
| | 241,179 |
| | — |
| | 241,179 |
|
Common stock dividend paid | — |
| | — |
| | — |
| | (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 paid | — |
| | — |
| | — |
| | (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 |
|
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 |
|
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 |
| 2017 | | 2016 | | 2015 | |
Operating activities: | | | | | | |
Net income (loss) | $ | 175,194 |
| | $ | 312,899 |
| | $ | 241,179 |
| |
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 | 481,969 |
| | 439,579 |
| | 420,807 |
| Depreciation and amortization | 656,323 | | | 666,432 | | | 481,969 | |
Conservation amortization | 121,216 |
| | 107,784 |
| | 110,866 |
| Conservation amortization | 96,571 | | | 111,714 | | | 121,216 | |
Deferred income taxes and tax credits, net | 254,524 |
| | 139,640 |
| | 91,978 |
| Deferred income taxes and tax credits, net | 7,475 | | | 19,457 | | | 254,524 | |
Net unrealized (gain) loss on derivative instruments | 30,650 |
| | (88,704 | ) | | (17,255 | ) | Net unrealized (gain) loss on derivative instruments | 3,574 | | | (41,662) | | | 30,650 | |
Derivative contracts classified as financing activities due to merger | — |
| | — |
| | 8,045 |
| |
AFUDC - equity | (15,027 | ) | | (12,576 | ) | | (9,325 | ) | AFUDC - equity | (15,802) | | | (17,191) | | | (15,027) | |
Production tax credits | (53,331 | ) | | — |
| | — |
| |
Production tax credit | | Production tax credit | (68,622) | | | (83,976) | | | (53,331) | |
Other non-cash | 17,568 |
| | 16,812 |
| | 16,155 |
| Other non-cash | (4,639) | | | 15,339 | | | 17,568 | |
Funding of pension liability | (18,000 | ) | | (24,000 | ) | | (18,000 | ) | Funding of pension liability | (18,000) | | | (18,000) | | | (18,000) | |
Regulatory assets and liabilities | (88,875 | ) | | (153,643 | ) | | (156,491 | ) | Regulatory assets and liabilities | (79,233) | | | (71,348) | | | (88,875) | |
Other long-term assets and liabilities | (27,411 | ) | | 16,435 |
| | 21,729 |
| |
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 | 132 |
| | (21,763 | ) | | (66,703 | ) | Accounts receivable and unbilled revenue | 3,058 | | | 17,659 | | | 132 | |
Materials and supplies | (625 | ) | | (28,134 | ) | | 4,945 |
| Materials and supplies | (6,018) | | | (9,177) | | | (625) | |
Fuel and natural gas inventory | 8,266 |
| | 473 |
| | 9,332 |
| 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 | 21,050 |
| | (25,927 | ) | | 4,086 |
| Prepayments and other | (1,103) | | | (3,679) | | | 21,050 | |
Purchased gas adjustment | 18,836 |
| | (15,374 | ) | | 33,662 |
| |
Accounts payable | 26,396 |
| | 32,465 |
| | (48,037 | ) | Accounts payable | (116,311) | | | 117,270 | | | 26,396 | |
Taxes payable | 6,520 |
| | (3,426 | ) | | 7,072 |
| Taxes payable | (18,133) | | | 164 | | | 6,520 | |
Other | 13,079 |
| | 36,750 |
| | (5,323 | ) | Other | 15,163 | | | (7,723) | | | 13,079 | |
Net cash provided by (used in) operating activities | 972,131 |
| | 729,290 |
| | 648,722 |
| Net cash provided by (used in) operating activities | 527,336 | | | 904,181 | | | 972,131 | |
Investing activities: | |
| | |
| | |
| Investing activities: | | | | | | | | |
Construction expenditures - excluding equity AFUDC | (1,040,135 | ) | | (706,444 | ) | | (587,225 | ) | Construction expenditures - excluding equity AFUDC | (959,387) | | | (1,072,670) | | | (1,040,135) | |
Restricted cash | 2,273 |
| | (4,469 | ) | | 24,914 |
| |
Other | (195 | ) | | (1,921 | ) | | 754 |
| Other | 6,908 | | | 2,097 | | | (195) | |
Net cash provided by (used in) investing activities | (1,038,057 | ) | | (712,834 | ) | | (561,557 | ) | 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 | 83,700 |
| | 86,759 |
| | 74,004 |
| Change in short-term debt, net | (203,297) | | | 49,834 | | | 83,700 | |
Dividends paid | (123,307 | ) | | (148,965 | ) | | (263,059 | ) | Dividends paid | (64,220) | | | (77,204) | | | (123,307) | |
| Proceeds from long-term debt and bonds issued | 90,120 |
| | 12,481 |
| | 825,000 |
| Proceeds from long-term debt and bonds issued | 689,351 | | | 804,050 | | | 90,120 | |
Redemption of bonds and notes | — |
| | — |
| | (711,000 | ) | Redemption of bonds and notes | — | | | (600,000) | | | — | |
Derivative contracts classified as financing activities due to merger | — |
| | — |
| | (8,045 | ) | |
Other | 13,151 |
| | 19,653 |
| | 902 |
| Other | 13,893 | | | 8,513 | | | 13,151 | |
Net cash provided by (used in) financing activities | 63,664 |
| | (30,072 | ) | | (82,198 | ) | Net cash provided by (used in) financing activities | 435,727 | | | 185,193 | | | 63,664 | |
Net increase (decrease) in cash and cash equivalents | (2,262 | ) | | (13,616 | ) | | 4,967 |
| |
Cash and cash equivalents at beginning of period | 28,878 |
| | 42,494 |
| | 37,527 |
| |
Cash and cash equivalents at end of period | $ | 26,616 |
| | $ | 28,878 |
| | $ | 42,494 |
| |
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) | $ | 326,798 |
| | $ | 329,603 |
| | $ | 339,866 |
| Cash payments for interest (net of capitalized interest) | $ | 328,703 | | | $ | 322,476 | | | $ | 326,798 | |
Cash payments (refunds) for income taxes | 1,649 |
| | — |
| | 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 | $ | 92,959 |
| | $ | 76,813 |
| | $ | 51,588 |
| |
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 | (49,177 | ) | | 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
| 95,935 |
| | — |
| | — |
| 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, |
| 2017 | | 2016 | | 2015 |
Operating revenue: | | | | | |
Electric | $ | 2,420,663 |
| | $ | 2,238,492 |
| | $ | 2,128,468 |
|
Natural gas | 997,759 |
| | 890,510 |
| | 947,549 |
|
Other | 41,854 |
| | 35,616 |
| | 17,241 |
|
Total operating revenue | 3,460,276 |
| | 3,164,618 |
| | 3,093,258 |
|
Operating expenses: | |
| | |
| | |
|
Energy costs: | |
| | |
| | |
|
Purchased electricity | 590,030 |
| | 531,596 |
| | 499,522 |
|
Electric generation fuel | 206,275 |
| | 215,331 |
| | 249,907 |
|
Residential exchange | (75,933 | ) | | (69,824 | ) | | (112,473 | ) |
Purchased natural gas | 360,009 |
| | 313,954 |
| | 403,310 |
|
Unrealized (gain) loss on derivative instruments, net | 30,790 |
| | (83,795 | ) | | (12,688 | ) |
Utility operations and maintenance | 584,263 |
| | 568,492 |
| | 530,720 |
|
Non-utility expense and other | 52,389 |
| | 37,859 |
| | 26,618 |
|
Depreciation and amortization | 481,955 |
| | 439,579 |
| | 420,807 |
|
Conservation amortization | 121,216 |
| | 107,784 |
| | 110,866 |
|
Taxes other than income taxes | 360,673 |
| | 328,649 |
| | 320,531 |
|
Total operating expenses | 2,711,667 |
| | 2,389,625 |
| | 2,437,120 |
|
Operating income (loss) | 748,609 |
| | 774,993 |
| | 656,138 |
|
Other income (deductions): | |
| | |
| | |
|
Other income | 26,853 |
| | 25,537 |
| | 20,711 |
|
Other expense | (14,104 | ) | | (10,923 | ) | | (6,764 | ) |
Interest charges: | |
| | |
| | |
|
AFUDC | 10,826 |
| | 9,304 |
| | 7,575 |
|
Interest expense | (240,144 | ) | | (242,983 | ) | | (247,571 | ) |
Income (loss) before income taxes | 532,040 |
| | 555,928 |
| | 430,089 |
|
Income tax (benefit) expense | 211,986 |
| | 175,347 |
| | 125,900 |
|
Net income (loss) | $ | 320,054 |
| | $ | 380,581 |
| | $ | 304,189 |
|
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, |
| 2017 | | 2016 | | 2015 |
Net income (loss) | $ | 320,054 |
| | $ | 380,581 |
| | $ | 304,189 |
|
Other comprehensive income (loss): | |
| | |
| | |
|
Net unrealized gain (loss) from pension and postretirement plans, net of tax of $9,848, $2,004 and $10,987, respectively | 18,288 |
| | 3,722 |
| | 20,404 |
|
Reclassification of net unrealized (gain) loss on energy derivative instruments, net of tax of $0, $0 and $369, respectively | — |
| | — |
| | 686 |
|
Amortization of treasury interest rate swaps to earnings, net of tax of $171, $171 and $171, respectively | 317 |
| | 317 |
| | 317 |
|
Other comprehensive income (loss) | 18,605 |
| | 4,039 |
| | 21,407 |
|
Comprehensive income (loss) | $ | 338,659 |
| | $ | 384,620 |
| | $ | 325,596 |
|
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, |
| 2017 | | 2016 |
Utility plant (at original cost, including construction work in progress of $495,937 and $420,278, respectively): | | | |
Electric plant | $ | 10,232,771 |
| | $ | 9,813,169 |
|
Natural gas plant | 3,882,733 |
| | 3,640,271 |
|
Common plant | 843,145 |
| | 632,718 |
|
Less: Accumulated depreciation and amortization | (5,131,966 | ) | | (4,927,602 | ) |
Net utility plant | 9,826,683 |
| | 9,158,556 |
|
Other property and investments: | |
| | |
|
Other property and investments | 76,350 |
| | 77,960 |
|
Total other property and investments | 76,350 |
| | 77,960 |
|
Current assets: | |
| | |
|
Cash and cash equivalents | 25,864 |
| | 28,481 |
|
Restricted cash | 10,145 |
| | 12,418 |
|
Accounts receivable, net of allowance for doubtful accounts of $8,901 and $9,798, respectively | 343,546 |
| | 344,964 |
|
Unbilled revenue | 222,186 |
| | 234,053 |
|
Purchased gas adjustment receivable | — |
| | 2,785 |
|
Materials and supplies, at average cost | 107,003 |
| | 106,378 |
|
Fuel and natural gas inventory, at average cost | 48,585 |
| | 56,851 |
|
Unrealized gain on derivative instruments | 22,247 |
| | 54,341 |
|
Prepaid expenses and other | 21,996 |
| | 43,046 |
|
Total current assets | 801,572 |
| | 883,317 |
|
Other long-term and regulatory assets: | | | |
Regulatory asset for deferred income taxes | — |
| | 71,517 |
|
Power cost adjustment mechanism | 4,576 |
| | 4,531 |
|
Other regulatory assets | 948,540 |
| | 1,034,352 |
|
Unrealized gain on derivative instruments | 2,158 |
| | 8,738 |
|
Other | 71,827 |
| | 58,109 |
|
Total other long-term and regulatory assets | 1,027,101 |
| | 1,177,247 |
|
Total assets | $ | 11,731,706 |
| | $ | 11,297,080 |
|
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, |
| 2017 | | 2016 |
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 | 452,066 |
| | 359,795 |
|
Accumulated other comprehensive income (loss), net of tax | (126,906 | ) | | (145,511 | ) |
Total common shareholder’s equity | 3,601,124 |
| | 3,490,248 |
|
Long-term debt: | |
| | |
|
First mortgage bonds and senior notes | 3,164,412 |
| | 3,362,000 |
|
Pollution control bonds | 161,860 |
| | 161,860 |
|
Junior subordinated notes | 250,000 |
| | 250,000 |
|
Debt discount, issuance costs and other | (26,361 | ) | | (28,974 | ) |
Total long-term debt | 3,549,911 |
| | 3,744,886 |
|
Total capitalization | 7,151,035 |
| | 7,235,134 |
|
Current liabilities: | |
| | |
|
Accounts payable | 359,585 |
| | 317,043 |
|
Short-term debt | 329,463 |
| | 245,763 |
|
Current maturities of long-term debt | 200,000 |
| | 2,412 |
|
Purchased gas adjustment payable | 16,051 |
| | — |
|
Accrued expenses: | |
| | |
|
Taxes | 117,063 |
| | 111,428 |
|
Salaries and wages | 53,220 |
| | 49,749 |
|
Interest | 47,837 |
| | 48,087 |
|
Unrealized loss on derivative instruments | 64,859 |
| | 44,170 |
|
Other | 80,206 |
| | 71,996 |
|
Total current liabilities | 1,268,284 |
| | 890,648 |
|
Other Long-term and regulatory liabilities: | |
| | |
|
Deferred income taxes | 869,473 |
| | 1,732,390 |
|
Unrealized loss on derivative instruments | 21,235 |
| | 16,261 |
|
Regulatory liabilities | 730,273 |
| | 653,296 |
|
Regulatory liability for deferred income taxes | 1,012,260 |
| | — |
|
Other deferred credits | 679,146 |
| | 769,351 |
|
Total other long-term and regulatory liabilities | 3,312,387 |
| | 3,171,298 |
|
Commitments and contingencies (Note 15) |
|
| |
|
|
Total capitalization and liabilities | $ | 11,731,706 |
| | $ | 11,297,080 |
|
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, 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 paid | — |
| | — |
| | — |
| | (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 paid | — |
| | — |
| | — |
| | (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 |
|
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 |
|
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, |
| 2017 | | 2016 | | 2015 |
Operating activities: | | | | | |
Net income (loss) | $ | 320,054 |
| | $ | 380,581 |
| | $ | 304,189 |
|
Adjustments to reconcile net income (loss) to net cash provided by operating activities: | |
| | |
| | |
|
Depreciation and amortization | 481,955 |
| | 439,579 |
| | 420,807 |
|
Conservation amortization | 121,216 |
| | 107,784 |
| | 110,866 |
|
Deferred income taxes and tax credits, net | 210,842 |
| | 174,776 |
| | 125,900 |
|
Net unrealized (gain) loss on derivative instruments | 30,790 |
| | (83,795 | ) | | (12,688 | ) |
AFUDC - equity | (15,027 | ) | | (12,576 | ) | | (9,325 | ) |
Production tax credits | (53,331 | ) | | — |
| — |
| — |
|
Other non-cash | 6,445 |
| | 5,672 |
| | 5,512 |
|
Funding of pension liability | (18,000 | ) | | (24,000 | ) | | (18,000 | ) |
Regulatory assets and liabilities | (88,875 | ) | | (152,786 | ) | | (156,491 | ) |
Other long-term assets and liabilities | (14,547 | ) | | 30,235 |
| | 36,481 |
|
Change in certain current assets and liabilities: | |
| | |
| | |
|
Accounts receivable and unbilled revenue | 13,285 |
| | (37,385 | ) | | (66,547 | ) |
Materials and supplies | (625 | ) | | (28,134 | ) | | 4,945 |
|
Fuel and natural gas inventory | 8,266 |
| | 473 |
| | 9,332 |
|
Prepayments and other | 21,050 |
| | (25,927 | ) | | 4,089 |
|
Purchased gas adjustment | 18,836 |
| | (15,374 | ) | | 33,662 |
|
Accounts payable | 26,396 |
| | 32,465 |
| | (48,031 | ) |
Taxes payable | 5,635 |
| | (3,426 | ) | | 7,072 |
|
Other | 12,438 |
| | 30,754 |
| | (12,992 | ) |
Net cash provided by (used in) operating activities | 1,086,803 |
| | 818,916 |
| | 738,781 |
|
Investing activities: | |
| | |
| | |
|
Construction expenditures - excluding equity AFUDC | (963,652 | ) | | (681,112 | ) | | (587,225 | ) |
Restricted cash | 2,273 |
| | (4,469 | ) | | 24,914 |
|
Other | 241 |
| | 4,156 |
| | 6,386 |
|
Net cash provided by (used in) investing activities | (961,138 | ) | | (681,425 | ) | | (555,925 | ) |
Financing activities: | |
| | |
| | |
|
Change in short-term debt, net | 83,700 |
| | 86,759 |
| | 74,004 |
|
Dividends paid | (227,783 | ) | | (257,364 | ) | | (270,233 | ) |
Loan from (payment to) parent | — |
| | — |
| | (28,933 | ) |
Investment from parent | — |
| | — |
| | 28,900 |
|
Proceeds from long-term debt and bonds issued | — |
| | — |
| | 425,000 |
|
Redemption of bonds and notes | — |
| | — |
| | (412,000 | ) |
Other | 15,801 |
| | 19,739 |
| | 4,796 |
|
Net cash provided by (used in) financing activities | (128,282 | ) | | (150,866 | ) | | (178,466 | ) |
Net increase (decrease) in cash and cash equivalents | (2,617 | ) | | (13,375 | ) | | 4,390 |
|
Cash and cash equivalents at beginning of period | 28,481 |
| | 41,856 |
| | 37,466 |
|
Cash and cash equivalents at end of period | $ | 25,864 |
| | $ | 28,481 |
| | $ | 41,856 |
|
Supplemental cash flow information: | |
| | |
| | |
|
Cash payments for interest (net of capitalized interest) | $ | 224,423 |
| | $ | 227,668 |
| | $ | 242,774 |
|
Cash payments (refunds) for income taxes | 3,058 |
| | — |
| | 2 |
|
Non-cash financing and investing activities: | | | | | |
Accounts payable for capital expenditures eliminated from cash flows | $ | 92,959 |
| | $ | 76,813 |
| | $ | 51,588 |
|
Reclassification of Colstrip from utility plant to a regulatory asset
| (49,177 | ) | | 176,804 |
| | — |
|
Reclassification of hydro treasury grants to a regulatory liability | 95,935 |
| | — |
| | — |
|
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, named Puget LNG, LLC (Puget LNG), formed in 2016, 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. PSE and Puget LNG are considered related parties with similar ownership by Puget Energy. Therefore, capital and operating costs that occur underare incurred by PSE and are 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 of December 31, 2017, Puget LNG has incurred $104.3 million in construction work in progress and operating costs related to Puget LNG’s portiona result of the Tacoma LNG facility.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 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.
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 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.
Other Property and Investments
For PSE, the costs of other property and investments (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
The Company provides for depreciation and amortization on a straight-line basis. Amortization is recorded for intangibles such as regulatory assets and liabilities, computer software and franchises. The annual depreciation provision stated as a percent of a depreciable electric utility plant was 2.8%3.4%, for each of3.3%, and 2.8% in 2019, 2018, and 2017, 2016 and 2015;respectively; depreciable natural gas
utility plant was 3.4%2.8%, for each of2.8%, and 3.4% in 2019, 2018, and 2017, 2016 and 2015;respectively; and depreciable common utility plant was 8.3%7.3%, 9.7%7.1% and 8.5%8.3% in 2017, 20162019, 2018, and 2015,2017, respectively. The cost of removal is collected from PSE’s customers through depreciation expense and any excess is recorded as a regulatory liability.
Goodwill
In 2009, Puget Holdings completed its merger with Puget Energy. Puget Energy remeasured the carrying amount of all its assets and liabilities to fair value, which resulted in recognition of approximately $1.7 billion in goodwill. ASC 350, “Intangibles - Goodwill and Other” (ASC 350), requires that goodwill be tested for impairment at the reporting unit level on an annual basis
and between annual tests if an event occurs or circumstances change that would more likely than not reduce the fair value of a reporting unit below its carrying value. These events or circumstances could include a significant change in the Company’s business or regulatory outlook, legal factors, a sale or disposition of a significant portion of a reporting unit or significant changes in the financial markets which could influence the Company’s access to capital and interest rates. Application of the goodwill impairment test requires judgment, including the identification of reporting units, assignment of assets and liabilities to reporting units, assignment of goodwill to reporting units and the determination of the fair value of the reporting units. Management has determined Puget Energy has only one reporting unit.
The goodwill recorded by Puget Energy represents the potential long-term return to the Company’s investors. Goodwill is tested for impairment annually using a qualitative and quantitative test. Management must first assess qualitative factors to determine whether it is more likely than not that the fair value of a reporting unit is less than its carrying amount, including goodwill. If, after assessing the totality of events or circumstances during a qualitative assessment, management determines the fair value of a reporting unit is less than its carrying amount, then the entity shall perform a quantitative test to determine impairment. 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 2017 using an October 1, 2017 measurement date. The fair value of Puget Energy’s reporting unit was estimated using a combination of the discounted cash flow and market approach. The discounted cash flow approach requires significant judgments, including estimation of future cash flows, which is dependent on internal forecasts, estimation of long-term rate of growth for Puget Energy business, estimation of the useful life over which cash flows will occur, the selection of utility holding companies determined to be comparable to Puget Energy and determination of an appropriate weighted-average cost of capital or discount rate. The market approach estimates the fair value of the business based on market prices of stocks of comparable companies engaged in the same or similar lines of business. In addition, indications of market value are estimated by deriving multiples of equity or invested capital to various measures of revenue, earnings or cash flow. Changes in these estimates and/or assumptions could materially affect the determination of fair value and goodwill impairment of the reporting unit. Based on the test performed, management has determined that there was no indication of impairment of Puget Energy’s goodwill as of October 1, 2017. There were no known events or circumstances from the date of the assessment through December 31, 2017 that would impact management’s conclusion.
Tacoma LNG Facility
In 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 intendeddesigned 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 later during different seasons.consumption. LNG will also provide fuel to transportation customers, particularly in the marine market. On January 24, 2018, the Puget Sound Clean Air Agency’sAgency (PSCAA) determined a Supplemental Environmental Impact Statement is(SEIS) was necessary in order to rule on the air quality permit for the facility. As a result of requiring a Supplemental Environmental Impact Statement,SEIS, the Company's construction schedule may be impacted depending onwas impacted. PSE received the Puget Sound Clean Air Agency's timing andSEIS 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 on the air quality permit. If delayed, the construction schedule and costs may be adversely impacted. Pursuantwhich has been appealed to the Washington Commission’sPollution 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 LNG.
For Puget Energy, $104.0 Per this allocation of costs, $199.9 million inand $165.6 million of construction work in progress related to Puget LNG’sLNG's portion of the Tacoma LNG facility is reported in the “OtherPuget Energy "Other property and investments”investments" financial statement line item. For PSE,item as of December 31, 2019, and December 31, 2018, respectively. Additionally, $1.2 million, $2.0 million, and $0.3 million of operating costs are reported in the Puget 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 construction work in progress of $87.2 million related to PSE’s portion of the Tacoma LNG facility is reported in the PSE “Utility plant - Natural gas plant” financial statement line item as of December 31, 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. The 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. The Company records these items at the lower of cost or net realizable value 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 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 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 through December 18, 2017, was 7.77%. Effective December 19, 2017, with the Washington Commission order, the new AFUDC rate authorized is 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 $236.5 million, $239.3 million and $257.1 million $235.3 millionfor 2019, 2018, and $234.2 million for 2017, 2016 and 2015, 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.
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 and gross margin erosion due 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. Revenue is recognized under this program when 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. On December 5, 2017, the Washington Commission approved PSE’s request within the 2017 GRCgeneral 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-recognized amounts will be 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, 20172019, and 20162018, was $8.9$8.3 million and $9.8$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. Under the December 5, 2017, Washington Commission order regarding PSE’s GRC, 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. 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, which 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.
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 during the first ten years of operation. From a regulatory perspective,Before the 2017 GRC, the tax savings from these credits were intended to be refunded by PSE to its customers when monetized, used on the income tax return, through its revenue requirement as initially approved by the Washington Commission. As the Company hashad not generated taxable income and thesewith which to monetize the credits, have not been monetized, they havehad 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 waswere also recorded for PTCs not yet monetized.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 chargeincrease to revenue and deferred tax expense will be recorded as the PTCs are monetized. These entries will result in no net income impact. AtAs of December 31, 2017 $2.12019 and 2018, $67.5 million and $84.0 million of PTCs arewere estimated to be monetized through tax filings.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, 2017, 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 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 Recognition
In May 2014, the FASB issued ASU No. 2014-09, "Revenue from Contracts with Customers (Topic 606)".Recently Adopted Accounting Standards Update (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.
The standard is effective for the Company beginning January 1, 2018 and allows for two methods of adoption: application of the standard to each prior reporting period presented (full retrospective), or application of a cumulative effect on retained earnings recognized at the date of initial application (modified retrospective method). The Company will adopt the standard using the modified retrospective method. In preparation for adoption of the standard, the Company initiated a project team that met bi-weekly to make key accounting assessments related to the standard, which included the implementation of associated internal controls.
As a result of implementation of this standard, the Company has concluded there to be no impact on revenue for contracts with customers open as of January 1, 2018. The Company's revenue is 93.6% comprised of contracts with customers from rate-regulated sales of electricity and natural gas to retail customers where revenue will continue to be recognized over time as delivered. Pursuant to the new standard, the Company's current presentation of revenue on the income statement will not change; however, enhanced disclosure for revenue from contracts with customers and revenue outside the scope of ASC 606 will be disclosed.
Guidance
Lease Accounting
In February 2016, the FASB issued ASU 2016-02, "Leases (Topic 842)". The FASB issued this ASU and the related amendments to increase transparency and comparability among organizations by recognizing right-of-use (ROU) lease assets and lease liabilities on the balance sheet and disclosing key information about leasing arrangements. To meet that objective, the FASB is amendingamended the FASB Accounting Standards CodificationASC and creatingcreated 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 for the adoption of the new standard. The Company will adoptadopted ASU 2016-02 duringas of January 1, 2019, which resulted in the first quarter of fiscal year 2019. The Company expects the adoption of the standard will result in recognition of right-of-use assetsasset and liabilitieslease liability financial statement line items that have not previously been recorded which willand are material to the consolidated balance sheets. Adoption of the standard did not have a material impact on the consolidated balance sheets. For a current breakoutincome statement. The financial impact as of existing operating and capital leases, seethe date of adoption was not materially different than what has been disclosed as of December 31, 2019, in Note 8,9, "Leases", to the consolidated financial statements included in Item 8 of this report.
Statement of Cash FlowsInternal-Use Software
In August 2016,2018, the FASB issued ASU 2016-15, 2018-15, "StatementIntangibles—Goodwill and Other—Internal-Use Software (Subtopic 350-40): Customer’s Accounting for Implementation Costs Incurred in a Cloud Computing Arrangement That Is a Service Contract". These amendments align the requirements for capitalizing implementation costs incurred in a hosting arrangement that is a service contract with the requirements for capitalizing implementation costs incurred to develop or obtain internal-use software (and hosting arrangements that include an internal-use software license). The accounting for the service element of Cash Flows (Topic 230): Classification of Certain Cash Receiptsa 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 the balance sheet in the same manner as a prepayment and Cash Payments". the related amortization expense in the same expense line item on the income statement as the expense 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 FERC Docket Number AI90-1-000.
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.
Thisthis update isare effective for financial statements issuedpublic business entities for fiscal years beginning after December 15, 2017,2019, 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 will 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 2016-18,2016-13, "StatementFinancial 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. The Companyyears, with 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 adopt ASU 2016-18 duringhave no material impact on the first quarterCompany's results of fiscal year 2018 retrospectively to all periods presented by moving the presentation of restricted cash, in the statement ofoperations, cash flows, to net cash flows of total cash, cash equivalents, and restricted cash. Additionally, the Company will disclose the nature of the Company's restricted cash.or consolidated balance sheet.
Retirement Benefits
In March 2017, the FASB issued ASU 2017-07, "Compensation - Retirement Benefits (Topic 715): Improving the Presentation of Net Periodic Pension Cost and Net Periodic Postretirement Benefit Cost". The amendments require 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. The line item used in the income statement to present the other components of net benefit cost must be disclosed. Additionally, the service cost component of net benefit cost is the only eligible cost for capitalization.
This amendment is effective for fiscal years beginning after December 15, 2017, including interim periods within those years. Early adoption is permitted as of the beginning of an annual period for which financial statements (interim or annual) have not been issued or made available for issuance. The Company will adopt ASU 2017-07 during the first quarter of fiscal year 2018 by applying the amendments related to income statement activity retrospectively, and balance sheet activity prospectively. The Company’s non-service components for the year ended December 31, 2017, was a credit of $18.4 million for Puget Energy and $4.7 million for PSE. The non-service cost components are in an income position and will be presented in the other income section, upon adoption.
Stranded Tax Effects in AOCI
In FebruaryAugust 2018, the FASB issued ASU 2018-02,2018-14, "Income Statement—Reporting Comprehensive Income (Topic 220)Compensation—Retirement Benefits—Defined Benefit Plans—General (Subtopic 715-20): ReclassificationDisclosure 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 Certain Tax Effects from Accumulated Other Comprehensive Income". relevant disclosures.
The amendments in this update allow reclassification from accumulated other comprehensive income to retained earnings for stranded tax effects resulting from the Tax Cuts and Jobs Act (TCJA) and will improve the usefulness of information reported to financial statement users.
This amendment isare effective for fiscal years beginningending after December 15, 2018, including interim periods within those years.2020, for public business entities and for fiscal years ending after December 15, 2021, for all other entities. Early adoption is permitted including adoption in any interim period for reporting periods for which financial statements have not yet been issued. The Company will early adopt ASU 2018-02 during the first quarter of fiscal year 2018 through a retrospective reclassification from accumulated other comprehensive income to retained earnings.all entities. The Company is stillin the process of evaluating potential impacts of these amendments to Note 13, "Retirement Benefits" to the impactconsolidated 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 a 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 reclassificationestablished 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 retained earnings.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 take control of the natural gas but is merely an agent within the market that connects a seller to a purchaser.
Other Revenue
(3)In accordance with ASC 606, PSE separately presents revenue not collected from contracts with customers that falls under other accounting guidance.
(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, 20172019, and 20162018, 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) | | | 2017 | | 2016 |
Storm damage costs electric | | 4 to 6 years | | | | 128,508 |
| | | | 122,709 |
|
Colstrip 1 & 2 Regulatory Asset | | N/A | | | | 127,627 |
| | | | 176,804 |
|
Decoupling deferrals and interest | | | | 98,769 |
| |
|
| | 156,408 |
| | |
Decoupling 24-month revenue reserve | | | | — |
| | | | (20,847 | ) | | |
Total decoupling asset | | Less than 2 years | | | | 98,769 |
| | | | 135,561 |
|
Chelan PUD contract initiation | | 13.8 years | | | | 98,052 |
| | | | 105,140 |
|
Environmental remediation | | (a) | | | | 81,550 |
| | | | 74,557 |
|
Lower Snake River | | 19.4 years | | | | 70,975 |
| | | | 74,862 |
|
Baker Dam licensing operating and maintenance costs | | N/A | | | | 54,817 |
| | | | 61,453 |
|
Deferred Washington Commission AFUDC | | 10 years | | | | 50,301 |
| | | | 51,404 |
|
Unamortized loss on reacquired debt | | 1 to 28 years | | | | 39,674 |
| | | | 42,196 |
|
Property tax tracker | | Less than 2 years | | | | 36,517 |
| | | | 41,949 |
|
Energy conservation costs | | (a) | | | | 35,538 |
| | | | 41,027 |
|
PGA deferral of unrealized losses on derivative instruments | | N/A | | | | 26,030 |
| | | | — |
|
White River relicensing and other costs | | 3 years | | | | 19,502 |
| | | | 21,627 |
|
Generation plant major maintenance, excluding Colstrip | | 5 to 11 years | | | | 17,216 |
| | | | 13,178 |
|
Mint Farm ownership and operating costs | | 7.3 years | | | | 14,319 |
| | | | 16,319 |
|
Colstrip major maintenance | | 1.5 years | | | | 8,723 |
| | | | 6,589 |
|
Snoqualmie licensing operating and maintenance costs | | N/A | | | | 7,341 |
| | | | 8,018 |
|
Ferndale | | 1.8 years | | | | 7,295 |
| | | | 11,274 |
|
Colstrip common property | | 7.4 years | | | | 4,618 |
| | | | 5,334 |
|
PCA mechanism | | N/A | | | | 4,576 |
| | | | 4,531 |
|
Electron unrecovered loss | | 1 year | | | | 3,786 |
| | | | 7,178 |
|
Deferred income taxes(d) | | N/A | | | | — |
| | | | 71,517 |
|
PGA receivable | | 1 year | | | | — |
| | | | 2,785 |
|
Various other regulatory assets | | (a) | | | | 17,382 |
| | | | 17,173 |
|
Total PSE regulatory assets | | | | | | 953,116 |
| | | | 1,113,185 |
|
Deferred income taxes(d) | | N/A | | | | (1,012,260 | ) | | | | — |
|
Cost of removal | | (b) | | | | (389,579 | ) | | | | (369,300 | ) |
Treasury grants | | 20 years | | | | (205,775 | ) | | | | (133,709 | ) |
Production tax credits | | (c) | | | | (93,616 | ) | | | | (93,616 | ) |
Decoupling ROR excess earnings | | | | (18,400 | ) | | | | (13,300 | ) | | |
Decoupling deferrals and interest | | | | (7,896 | ) | | | | (16,448 | ) | | |
Total decoupling liability | | Less than 2 years | | | | (26,296 | ) | | | | (29,748 | ) |
PGA payable | | 1 year | | | | (16,051 | ) | | | | — |
|
Summit purchase option buy-out | | 2.8 years | | | | (4,463 | ) | | | | (6,038 | ) |
PGA deferral of unrealized gains on derivative instruments | | N/A | | | | — |
| | | | (7,517 | ) |
Various other regulatory liabilities | | (a) | | | | (10,544 | ) | | | | (13,368 | ) |
Total PSE regulatory liabilities | | | | | | (1,758,584 | ) | | | | (653,296 | ) |
PSE net regulatory assets (liabilities) | | | | | | $ | (805,468 | ) | | | | $ | 459,889 |
|
| | | | | | | | | | | | | | |
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. |
| |
(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. |
| |
(d)
| For additional information, see Note 13,"Income Taxes" to the consolidated financial statements included in Item 8 of this report. |
____________________
(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) | | | 2017 | | 2016 |
Total PSE regulatory assets | | (a) | | $ | 953,116 |
| | $ | 1,113,185 |
|
Puget Energy acquisition adjustments: | | | | |
| | |
|
Regulatory assets related to power contracts | | 1 to 20 years | | 19,454 |
| | 22,613 |
|
Various other regulatory assets | | Varies | | (8 | ) | | 517 |
|
Total Puget Energy regulatory assets | | | | 972,562 |
| | 1,136,315 |
|
Total PSE regulatory liabilities | | (a) | | (1,758,584 | ) | | (653,296 | ) |
Puget Energy acquisition adjustments: | | | | |
| | |
|
Deferred income taxes | | | | 634 |
| | — |
|
Regulatory liabilities related to power contracts | | 1 to 35 years | | (174,918 | ) | | (275,061 | ) |
Various other regulatory liabilities | | Varies | | (1,314 | ) | | (1,326 | ) |
Total Puget Energy regulatory liabilities | | | | (1,934,182 | ) | | (929,683 | ) |
Puget Energy net regulatory asset (liabilities) | | | | $ | (961,620 | ) | | $ | 206,632 |
|
_______________
| |
(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'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 $389.6$469.9 million and $369.3$424.7 million in 20172019 and 2016,2018, respectively, for the cost of removal of utility plant. These amounts are collected from PSE’s customers through depreciation rates.
General Rate Case Filing
PSE filed a GRC with the Washington Commission on June 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 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 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 13,15, 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 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.
In January 2017, PSE filed its GRC with the Washington Commission, which proposed a weighted cost of capital of 7.74%, or 6.69% after-tax, and a capital structure of 48.5% in common equity with a return on equity of 9.8%.Commission. The requested combined electric tariff changes would result in a net increase of $86.3 million or 4.1%, annually. The requested combined natural gas tariff changes would result in a net decrease of $22.3 million, or 2.4%, annually. Additionally, a depreciation study which calculates annual depreciation accruals related to utility plant was filed as part of the GRC filing. The tariffs were subsequently suspended, which means that the final rates authorized in the proceeding would go into effect on or shortly after the suspension date of December 13, 2017. PSE filed a supplemental filing in the GRC on April 3, 2017, which among other things provided updates to power costs. The requested combined electric tariff changes based on the updated supplemental filing would result in a net increase of $67.9 million, or 3.2%, annually. The requested combined natural gas tariff changes based on the updated supplemental filing would result in a net decrease of $29.3 million, or 3.2%, annually.
PSE’s GRC filing included thea required plan forto address Colstrip Units 1 and 2 closures, see Note 14, "Litigation" to the consolidated financial statements included in Item 8 of this report. The filing also requested that electric energy supply fixed costs be included in PSE’sPSE's decoupling mechanism. Additionally, PSE’s filingmechanism, and contained requests for two2 new mechanisms to address regulatory lag. PSE requested procedures for an ERF that can be used to update PSE’s delivery revenues on an expedited basis followingThe Washington Commission entered a GRC proceeding. PSE also requested approval to establish an electric cost recovery mechanism (CRM), similar to its existing natural gas CRM, which would allow PSE to obtain accelerated cost recovery on specified electric reliability projects.
On September 15, 2017, ten offinal order accepting the eleven parties to the proceeding, including PSE, filed a multi-party settlement agreement withand determined the Washington Commission. The multi-party settlement resolved some, but not all, contested issues in the case. Hearings were held on August 30, 2017 regarding the contested issues and on September 29, 2017 regarding the multi-party settlement. The settlement agreement was accepted by the Washington Commissioncase on December 5, 2017, and thenew rates became effective December 19, 2017. The settlement agreement resolved all but four of the contested issues between the settling parties. The settlement agreement providesprovided for a weighted cost of capital of 7.60%7.6%, or 6.55% after-tax, and a capital structure of 48.5% in common equity with a return on equity of 9.5%. The settlement also resulted in a combined electric tariff change that resulted in a net increase of $20.2 million, or 0.9%, annually, and a combined natural gas tariff change that resulted in a net decrease of $35.5 million, or 3.8%.
, annually.
The expected closure date for Colstrip Units 1 and 2 is July 1, 2022 and2017 GRC also re-purposed the settlement included a plan to cover the costs for the closurebenefit of these Units. As part of the settlement PSE committed to fund a Colstrip Community Transition Fund of $10.0 million of which PSE shareholders will fund $5.0 million and $5.0 million will be funded by the regulatory liability for monetized PTCs, which are PTCs used on the filed tax returns. PSE is recognizing the funding of this commitment at the time the PTC’s are accrued for use in the tax return. The settlement provided that the regulatory liability for monetized PTCs will be used for the following Colstrip costs: (i) Colstrip Community Transition Fund, (ii) recover unrecovered Colstrip plant and (iii) recover incurred decommissioning and remediation costs for Colstrip. In addition, the hydro-related treasury grants were allowed to be used to fund and recover incurred decommissioning and remediation costs for Colstrip 1 and 2 as established in RCW 80.04.350. Depreciation rates were updated which increased PSE's depreciation for Colstrip Units 1 and 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 overall 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 depreciation causedelectric 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 Colstrip regulatory assetproceeding 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 be reduceda $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 $127.6 million ascustomers 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 December 31, 2017. Finally, depreciation rates for Colstrip Units 3 and 4 were also updated, which increased PSE's depreciation to recover plant costs for those unitsrelated 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 the 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 negotiated depreciation life endingone-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 change, PSE re-measured its deferred tax balances under the new corporate tax rate. PSE filed an accounting petition on December 31, 2027.29, 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, 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 35.0% 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 contested issues were PSE’s proposed electric CRM,March 30, 2018, rate change filing did not address excess deferred taxes or the majoritydeferred balance associated with the over-collection of decoupling issues, certain portionsincome tax expense of electric$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 spread/rate design issueschange). 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 entire natural gas rate spread/rate design-related issues.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 was filed on June 20, 2019. The Washington Commission also ruled onrequired in the remaining contested issues on December 5, 2017. The Washington Commission approved, PSE's proposal to modify its earning sharing mechanism to exclude normalizing adjustmentsERF order that are requiredPSE pass back the deferred balance associated with the tax over-collection for Commission Basis Reporting purposes under Washington Administrative Code 480-90-257 (natural gas) and 480-100-257 (electric). The Washington Commission rejected PSE’s requested electric CRM.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 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 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 are recovered on a per customer basis regardless of actual consumption levels. PSE'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 during the following May to April time period. During the rate plan, which ended in December 2017, the allowed decoupling revenue per customer for the recovery of delivery system costs increased by 3.0% for the electric customers and 2.2% for the natural gas customers on January 1.
On December 5, 2017, the Washington Commission approved PSE’s request within the 2017 GRC to extend the decoupling mechanism with someseveral 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 and electric fixed production energy costs willare now be decoupled and recovered on the basis of a fixed monthly amount basis.amount. The allowed decoupling revenue will no longer increase annually on January 1 for electric and natural gas customers and these amountswill 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 Power Cost Only Rate Caseor ERF. Approved electric fixed production energy costs can also be changed in a power cost only rate case (PCORC) or ERF filing.. 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 the effective date ofbe reviewed again in PSE’s first rate case or other proceeding filed in or after 2021, unless the continuation of the mechanism is approvedor in either of those proceedings.a separate proceeding, if appropriate. PSE’s decoupling mechanism overover- and underunder- collections will still be collectible or refundable after this effective date even if the decoupling mechanism is not extended.
There is a 3.0% cap forOn February 21, 2019, the Washington Commission approved the multi-party settlement agreement which was filed within PSE’s ERF filing. As part of this settlement agreement, electric and 5.0% cap for 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 annual decoupling increases noted above and the size of decoupling deferral assets on the balance sheet,March 1, 2019.
On December 31, 2019, PSE performed an analysis as of December 31, 2017 to determine if electric and natural gas decoupling revenue deferrals would be collected from customers within 24 months of the annual period, per ASC 980-605.980. If not, for GAAP purposes only, PSE willwould need to record a reserve against the decoupling revenue and regulatory asset balance. Once the revenuereserve is forecasted to be collectedprobable of collection within 24 months from the end of the annual period, the reserve can be reversed.recognized as decoupling revenue. The analysis indicated all current deferred revenues forthat electric and natural gas deferred revenue will be collected within 24 months of the annual period; therefore, there were no adjustmentsadjustment was booked to 20172019 decoupling revenues other than to record therevenue. The previously unrecognized decoupling deferrals of $0.8 million and $20.8 million at December 31, 2018, and December 31, 2016, were recognized as decoupling revenue in the year ended December 31, 2019, and 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.
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 and $1.0 million of interest was accrued on the deferred customer balance. This compares to an under recovery of allowable costs of $3.5 million for the year ended December 31, 2018, of which 0 amounts were apportioned to customers 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 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 power, which reduced the supply of natural gas-fired generation and increased the demand for market power, increasing prices.
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 difference 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 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 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 Commission. If authorized, both the GTZ depreciation and interest on the deferral will be begin amortizing over three years in May 2020
Storm Damage Deferral Accounting
The Washington Commission issued a GRC order that defined deferrable storm events and provided that costs in excess of the annual cost threshold may be deferred for qualifying storm damage costs that meet the modified IEEEInstitute of Electrical and Electronics Engineers outage criteria for system average interruption duration index. In 2017 and 2016,For the year ended December 31, 2019, PSE incurred $30.4$39.3 million and $22.0 million, respectively, in storm-related electric transmission and distribution system restoration costs, of which $21.6the Company deferred $0.4 million wasand $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 $12.4 million was deferred in 2016.2018, 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 total qualifying cost is less than$0.5than $0.5 million will not qualify for deferral and these costs will also not count toward the 10.0$10.0 million annual cost threshold.
Washington Commission Tax Deferral Filing
The TCJA was signed into law in December of 2017. As a result of this change, PSE reviewed its deferred tax balances under the new corporate tax rate. As PSE is a regulated utility, the impact of tax rate changes on the deferred tax balance is subject to approval by the Washington Commission. Accordingly, PSE filed an accounting petition on December 29, 2017 requesting deferred accounting treatment for the impacts of tax reform. The deferral 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. The tax rate change for certain deferred tax balances that are not subject to regulatory treatment have been recorded through tax expense.
Environmental Remediation
The Company is subject to environmental laws and regulations by the federal, state and local authorities and is required to undertake certain environmental investigative and remedial efforts as a result of these laws and regulations. The Company has been named by the Environmental Protection Agency (EPA), the Washington State Department of Ecology and/or other third parties as potentially responsible at several contaminated sites and manufactured gas plant sites. 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 $38.9$41.8 million for natural gas and $8.9$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, 2017,2019, the Company’s share of future remediation costs is estimated to be approximately $28.6$31.6 million. The Company's deferred electric environmental costs are $17.6 million, $13.8$13.7 million and $14.0$14.1 million at December 31, 2017, 20162019 and 2015,2018, respectively, net of insurance proceeds. The Company's deferred natural gas environmental costs are $63.9 million, $60.7$54.8 million and $52.9$62.2 million at December 31, 2017, 20162019 and 2015,2018, respectively, net of insurance proceeds. In the 2017 GRC, which became effective December 19, 2017, the Company had its third party recoveries and remediation costs incurred as of September 30, 2016, net of a portion of insurance, approved for amortization and inclusion in rates.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, 2017,2019, approximately $645.1$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 48.0%48.4% at December 31, 2017,2019, and the EBITDA to interest expense was 5.55.3 to 1.0 for the twelve months ended December 31, 2017.2019.
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 3.73.6 to 1.0 for the twelve months ended December 31, 2017.2019.
At December 31, 2017,2019, 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) | | 2017 | | 2016 | | 2017 | | 2016 |
Distribution plant | 20-65 | | $ | 5,670,351 |
| | $ | 5,287,542 |
| | $ | 7,289,998 |
| | $ | 6,922,176 |
|
Production plant | 12-90 | | 3,068,135 |
| | 3,007,546 |
| | 3,954,057 |
| | 3,910,129 |
|
Transmission plant | 43-75 | | 1,361,495 |
| | 1,307,687 |
| | 1,471,337 |
| | 1,420,334 |
|
General plant | 5-75 | | 586,226 |
| | 541,424 |
| | 628,179 |
| | 611,237 |
|
Intangible plant (including capitalized software) | NA | | 447,568 |
| | 347,697 |
| | 438,185 |
| | 338,327 |
|
Plant acquisition adjustment | NA | | 242,826 |
| | 242,826 |
| | 282,792 |
| | 282,792 |
|
Underground storage | 25-60 | | 31,815 |
| | 30,695 |
| | 45,288 |
| | 44,206 |
|
Liquefied natural gas storage | 25-60 | | 12,628 |
| | 12,628 |
| | 14,498 |
| | 14,498 |
|
Plant held for future use | NA | | 53,428 |
| | 52,484 |
| | 53,580 |
| | 52,636 |
|
Recoverable Cushion Gas | NA | | 8,655 |
| | 8,655 |
| | 8,655 |
| | 8,655 |
|
Plant not classified | 1-125 | | 275,014 |
| | 159,345 |
| | 275,014 |
| | 159,345 |
|
Grant | NA | | — |
| | (99,100 | ) | | — |
| | (99,100 | ) |
Capital leases, net of accumulated amortization1 | 4-6 | | 1,129 |
| | 645 |
| | 1,129 |
| | 645 |
|
Less: accumulated provision for depreciation | | | (2,428,524 | ) | | (2,161,796 | ) | | (5,131,966 | ) | | (4,927,602 | ) |
Subtotal | | | $ | 9,330,746 |
| | $ | 8,738,278 |
| | $ | 9,330,746 |
| | $ | 8,738,278 |
|
Construction work in progress | NA | | 495,937 |
| | 420,278 |
| | 495,937 |
| | 420,278 |
|
Net utility plant | | | $ | 9,826,683 |
| | $ | 9,158,556 |
| | $ | 9,826,683 |
| | $ | 9,158,556 |
|
______________________________________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 $0.7 million in 2017 and $0.6 million in 2016. |
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 tables indicate the Company’s percentage ownership and the extent of the Company’s investment in jointly owned generating plants in service at December 31, 2017.2019. 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 | |
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 1 & 2 | Coal | | 50.0% | | $ | 246,510 |
| | $ | (23 | ) | | $ | (38,170 | ) | |
Colstrip Units 3 & 4 | Coal | | 25.0% | | 307,254 |
| | 1,726 |
| | (71,061 | ) | Colstrip Units 3 & 4 | Coal | | 25.00% | | | $ | 582,372 | | | $ | — | | | $ | (398,099) | |
Colstrip Units 1 – 4 Common Facilities | Coal | | various | | 83 |
| | — |
| | (31 | ) | |
Frederickson 1 | Natural Gas | | 49.85% | | 61,783 |
| | — |
| | (3,850 | ) | Frederickson 1 | Natural Gas | | 49.85 | | | 67,888 | | | — | | | (17,063) | |
Jackson Prairie | Natural Gas Storage | | 33.34% | | 31,141 |
| | 43 |
| | (6,325 | ) | 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.
|
| | | | | | | | | | | | | | | |
Puget Sound 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 1 & 2 | Coal | | 50.0% | | $ | 378,574 |
| | $ | (23 | ) | | $ | (170,234 | ) |
Colstrip Units 3 & 4 | Coal | | 25.0% | | 571,604 |
| | 1,726 |
| | (335,414 | ) |
Colstrip Units 1 – 4 Common Facilities | Coal | | various | | 252 |
| | — |
| | (199 | ) |
Frederickson 1 | Natural Gas | | 49.85% | | 67,851 |
| | — |
| | (9,917 | ) |
Jackson Prairie | Natural Gas Storage | | 33.34% | | 45,288 |
| | 43 |
| | (20,471 | ) |
Tacoma LNG | LNG | | 43.0% | | 2,667 |
| | 87,207 |
| | — |
|
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 “Asset Retirement and Environmental Obligations" (ARO).
On April 17, 2015, the U.S. Environmental Protection Agency (EPA)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 2015 and 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.
On September 6, 2016, PSE entered into two new 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, in 2016 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.
For the twelve months ended December 31, 20172019, the Company reviewed the estimated remediation costs at Colstrip and reducedincreased the Colstrip ARO liability by $5.5$4.2 million for Colstrip Units 1 and 2 and $12.7$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 closure of Colstrip 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 Colstrip Units 1 and 2, 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 $3.8 million.$12.4 million and $4.8 million, respectively. In addition, the Company recorded a new Tacoma LNG facility ARO liability of $3.0 million and $2.7 million for PSE and $2.2$4.3 million and $1.7 million for Puget LNG as of December 31, 2017.
2019 and December 31, 2018, respectively. The following table describes the changes2019 increase to the Company’sTacoma LNG facility ARO liability is primarily due to continued construction of the plant.
| | | | | | | | | | | |
Puget Energy and Puget Sound Energy | December 31, | | |
(Dollars in Thousands) | 2019 | | 2018 |
Asset retirement obligation at beginning of the period | $ | 182,203 | | | $ | 191,176 | |
New asset retirement obligation recognized in the period | — | | | 501 | |
Relief of liability | (12,449) | | | (4,750) | |
Revisions in estimated cash flows | 5,922 | | | (10,512) | |
Accretion expense | 5,677 | | | 5,788 | |
Asset retirement obligation at end of period1 | $ | 181,353 | | | $ | 182,203 | |
___________________
1.Asset retirement obligations include $4.3 million and $1.7 million for the year endedPuget LNG held only at PE as of December 31, 2017:2019, and 2018, respectively.
|
| | | | | | | |
Puget Energy and Puget Sound Energy | At December 31, |
(Dollars in Thousands) | 2017 | | 2016 |
Asset retirement obligation at beginning of the period | $ | 200,345 |
| | $ | 85,028 |
|
New asset retirement obligation recognized in the period1 | 2,881 |
| | — |
|
Liability adjustments | (3,841 | ) | | (411 | ) |
Revisions in estimated cash flows | (13,748 | ) | | 113,081 |
|
Accretion expense | 5,539 |
| | 2,647 |
|
Asset retirement obligation at end of period1 | $ | 191,176 |
| | $ | 200,345 |
|
_______________
| |
1
| New asset retirement obligations include $2.2 million ARO for Puget LNG only held at Puget Energy.
|
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, 2017 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.
(6)
(7) Long-Term Debt
The following table presents outstanding long-term debt principal amounts and due dates as of 20172019 and 2016:2018:
| | | | | | | | | | | | | | | | | | | | | | | |
(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 14,2019.
|
| | | | | | | | | | | | |
(Dollars in Thousands) | | | | At December 31, |
Series | | Type | | Due | | 2017 | | 2016 |
Puget Sound Energy: |
6.740% | | Senior Secured Note1 | | 2018 | | $ | 200,000 |
| | $ | 200,000 |
|
5.500% | | Promissory Note2
| | 2020 | | 2,412 |
| | 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 |
|
4.700% | | Senior Secured Note | | 2051 | | 45,000 |
| | 45,000 |
|
6.974% | | Junior Subordinated Note | | 2067 | | 250,000 |
| | 250,000 |
|
* | | Debt discount, issuance cost and other | | * | | (26,361 | ) | | (28,974 | ) |
Total PSE long-term debt | | 3,749,911 |
| | 3,747,298 |
|
Puget Energy: | | | | |
* | | Fair value adjustment of PSE long-term debt | | * | | (190,895 | ) | | (199,436 | ) |
* | | Revolving Credit Agreement | | 2022 | | 102,600 |
| | 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 | | * | | (3,687 | ) | | (6,269 | ) |
Total Puget Energy long-term debt | | $ | 5,457,929 |
| | $ | 5,354,073 |
|
_______________
| |
1
| 6.74% Senior Secured Note in the amount of $200.0 million is classified on the Balance Sheet as a current maturity of long-term debt as of June 15, 2017. |
| |
2
| 5.50% Promissory Note (Puget Western Note Payable) in the amount of $2.4 million was classified on the Balance Sheet as a current maturity of long-term debt from January 1, 2017 to August 13, 2017, at which time the agreement was amended and extended until August 13, 2020. The Promissory Note is currently classified as long-term debt on the Balance sheet as of September 1, 2017. |
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, 2017,2019, 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, 2017,2019, the earnings available for interest exceeded the required amount.
On 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 a 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 note indenture at an interest rate of 4.223% with a maturity date of June 15, 2048. The proceeds from the issuance were used to pay the principal 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 other general corporate expenses.
On August 30, 2019, PSE issued $450.0 million of senior notes at an interest rate of 3.250%. The notes pay interest semi-annually and are due to mature on September 15, 2049. Proceeds from the sale of the notes were used to repay outstanding short term debt under the 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) | 2018 | | 2019 | | 2020 | | 2021 | | 2022 | | Thereafter | | Total |
Maturities of: | | | | | | | | | | | | | |
PSE | $ | 200,000 |
| | $ | — |
| | $ | 2,412 |
| | $ | — |
| | $ | — |
| | $ | 3,573,860 |
| | $ | 3,776,272 |
|
Puget Energy | — |
| | — |
| | 450,000 |
| | 500,000 |
| | 552,600 |
| | 400,000 |
| | 1,902,600 |
|
Total long-term debt | $ | 200,000 |
| | $ | — |
| | $ | 452,412 |
| | $ | 500,000 |
| | $ | 552,600 |
| | $ | 3,973,860 |
| | $ | 5,678,872 |
|
(7)(8) Liquidity Facilities and Other Financing Arrangements
As of December 31, 20172019, and 2016,2018, PSE had $329.5$176.0 million and $245.8$379.3 million in short-term debt outstanding, 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 facility 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 20172019 and 20162018 was 3.5%3.4% and 3.2%3.4%, respectively. As of December 31, 2017,2019, PSE and Puget Energy had several committed credit facilities that are described below.
Puget Sound Energy
Credit Facility
In October 2017, PSE entered into a new $800.0 million credit facility which consolidates the two previous facilities into a single, smaller facility. All other features including fees, interest rate options, letter of credit, same day swingline borrowings, financial covenant and accordion feature remain substantially the same. The credit facility includes a swingline feature allowing same day availability on borrowings up to $75.0 million. The credit facility also has an expansion feature which, upon the banks' approval, would increase the total size of the facility to $1.4 billion. TheOn September 25, 2019, with no changes to the size, terms or conditions, the maturity of the unsecured revolving credit facility was extended for one year. The facility now matures in October 2022.2023.
The credit agreement is syndicated among numerous lenders and contains usual and customary affirmative and negative covenants that, among other things, places limitations on PSE's ability to transact with affiliates, make asset dispositions and investments or permit liens to exist. The credit agreement also contains 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, 2017,2019, PSE was in compliance with all applicable covenant ratios.
The credit agreement provides PSE with the ability to borrow at different interest rate options. The credit agreement 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 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 1.25% and the commitment fee is 0.175%.
As of December 31, 2017,2019, no amounts were drawn and outstanding under PSE's credit facility. No letters of credit were outstanding and $329.5$176.0 million was outstanding under the commercial paper program. Outside of the credit agreement, PSE had a $3.1$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, 2017,2019, there was no outstanding balance under the Note.
Puget Energy
Credit Facility
In October 2017, Puget Energy entered into a new $800.0 million credit facility to replace the existing facility. The terms and conditions, including fees, interest rate options, financial covenant, and expansion feature remain substantially the same. On September 25, 2019, with no changes to the size, terms or conditions, the maturity of the unsecured revolving credit facility was extended for one year. The new facility now matures in October 2022.2023. As of December 31, 2017,2019, there was $102.6$24.1 million drawn and outstanding under the facility. The Puget Energy revolving senior secured credit facility also has an expansion 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 the date of this report, the spread over LIBOR was 1.75% and the commitment fee was 0.275%.
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, 2017,2019, 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. Payments receivedwhen 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 subleases of properties were immaterial for eachTacoma LNG facility. This remeasurement resulted in an increase of the years ended 2017, 2016 and 2015.
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, | | Operating Lease Expense |
Years | |
2017 | | $ | 35,198 |
|
2016 | | 31,786 |
|
2015 | | 27,843 |
|
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 | |
_______________
1 Includes $1.0 million allocated to PLNG at PE related to the Port of Tacoma 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 table summarizestables summarize the Company’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 throughare presented in the terms of its existing contracts:following table.
| | | | | |
(Dollars in Thousands) | Operating Lease Expense |
Year Ended December 31, | |
2018 | $ | 34,093 | |
2017 | 35,198 | |
|
| | | | | | | |
(Dollars in Thousands) | Future Minimum Lease Payments |
At December 31, |
Years | Operating | | Capital |
2018 | $ | 21,371 |
| | $ | 527 |
|
2019 | 19,077 |
| | 306 |
|
2020 | 17,507 |
| | 232 |
|
2021 | 9,137 |
| | 97 |
|
2022 | 6,747 |
| | — |
|
Thereafter | 97,974 |
| | — |
|
Total minimum lease payments | $ | 171,813 |
| | $ | 1,162 |
|
(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. In November 2017, PSE implementedPSE's hedging strategy includes a risk-responsive component to its hedging strategy for the core natural gas portfolio. This strategyportfolio, 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, 2017, the Company did not have any outstanding interest rate swap instruments.
The following table presents the volumes, fair values and classification 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 |
| 2017 | | 2016 | | 2017 | | 2016 | | 2017 | | 2016 |
Interest rate swap derivatives3 | $0.0 | | $450.0 | | $ | — |
| | $ | — |
| | $ | — |
| | $ | 141 |
|
Electric portfolio derivatives | * | | * | | 13,391 |
| | 36,460 |
| | 49,050 |
| | 41,329 |
|
Natural gas derivatives (MMBtus)4 | 332.1 |
| | 336.4 |
| | 11,014 |
| | 26,619 |
| | 37,044 |
| | 19,101 |
|
Total derivative contracts | | |
| | $ | 24,405 |
| | $ | 63,079 |
| | $ | 86,094 |
| | $ | 60,571 |
|
Current | | | | | $ | 22,247 |
| | $ | 54,341 |
| | $ | 64,859 |
| | $ | 44,310 |
|
Long-term | | | | | 2,158 |
| | 8,738 |
| | 21,235 |
| | 16,261 |
|
Total derivative contracts | | |
| | $ | 24,405 |
| | $ | 63,079 |
| | $ | 86,094 |
| | $ | 60,571 |
|
_________________________1.Balance sheet classification: Current and Long-term Unrealized gain on derivative instruments.
| |
1
| Balance sheet classification: Current and Long-term Unrealized gain on derivative instruments. |
| |
2
| Balance sheet classification: Current and Long-term Unrealized loss on derivative instruments. |
| |
3
| Interest rate swap contracts are only held at Puget Energy and matured in January 2017. |
| |
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 166.8 million One Million British Thermal Units (MMBtus) and purchased electricity of 2.9 million megawatt hours (MWhs) at December 31, 2017 and 186.8 million MMBtus and 3.6 million MWhs at December 31, 2016. |
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, 2017 |
(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 | $ | 24,405 |
| | $ | — |
| | $ | 24,405 |
| | $ | (17,940 | ) | | $ | — |
| | $ | 6,465 |
|
Liabilities: | | | | | | | | | | | |
Energy derivative contracts | 86,094 |
| | — |
| | 86,094 |
| | (17,940 | ) | | (353 | ) | | 67,801 |
|
| | | | | | | | | | | |
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 |
|
_______________
| |
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 and matured in January 2017. |
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 | | 2017 | | 2016 | | 2015 |
Interest rate contracts: | | | | | | | | |
| | Non-hedged interest rate swap (expense) income | | $ | 28 |
| | $ | (1,062 | ) | | $ | (3,796 | ) |
| | Interest expense | | — |
| | — |
| | 560 |
|
Gas for Power Derivatives: | | | | | | | | |
Unrealized | | Unrealized gain (loss) on derivative instruments, net | | (32,492 | ) | | 62,318 |
| | (9,315 | ) |
Realized | | Electric generation fuel | | (23,195 | ) | | (39,656 | ) | | (44,648 | ) |
Power Derivatives: | | | | | | | | |
Unrealized | | Unrealized gain (loss) on derivative instruments, net1 | | 1,702 |
| | 21,477 |
| | 22,548 |
|
Realized | | Purchased electricity | | (17,873 | ) | | (21,998 | ) | | (39,137 | ) |
Total gain (loss) recognized in income on derivatives | | | | $ | (71,830 | ) | | $ | 21,079 |
| | $ | (73,788 | ) |
| 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 | | 2017 | | 2016 | | 2015 | |
Gas for Power Derivatives: | | | | | | | Gas for Power Derivatives: | | | | | | | | | |
Unrealized | | Unrealized gain (loss) on derivative instruments, net | | $ | (32,492 | ) | | $ | 62,318 |
| | $ | (9,315 | ) | Unrealized | Unrealized gain (loss) on derivative instruments, net | 16,970 | | | 23,186 | | | (32,492) | |
Realized | | Electric generation fuel | | (23,195 | ) | | (39,656 | ) | | (44,648 | ) | Realized | Electric generation fuel | 10,828 | | | 26,222 | | | (23,195) | |
Power Derivatives: | | | | | | | Power Derivatives: | | | | | | | | | |
Unrealized | | Unrealized gain (loss) on derivative instruments, net1 | | 1,702 |
| | 21,477 |
| | 22,003 |
| Unrealized | Unrealized gain (loss) on derivative instruments, net | (20,544) | | | 18,476 | | | 1,702 | |
Realized | | Purchased electricity | | (17,873 | ) | | (21,998 | ) | | (39,137 | ) | Realized | Purchased electricity | 48,686 | | | 12,240 | | | (17,873) | |
Total gain (loss) recognized in income on derivatives | | $ | (71,858 | ) | | $ | 22,141 |
| | $ | (71,097 | ) | 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 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 mitigation.
The Company monitors counterparties for significant swings in credit default swap rates, credit rating changes by external rating agencies, ownership changes or 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, 2017,2019, approximately 99.5%95.0% of the Company's energy portfolio exposure, excluding normal purchase normal sale (NPNS) transactions, is with counterparties that are rated investment grade by rating agencies and 0.5%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, 2017,2019, the Company was in a net liability position with the majority of counterparties, so the default factors of counterparties did not have a significant impact on reserves for the period. The majority of the Company's derivative contracts are with financial institutions and other utilities operating within the Western Electricity Coordinating Council. In March 2017, PSE began transactingalso transacts power futures contracts on the Intercontinental Exchange (ICE), and natural gas contracts on the ICE NGX exchange platform. Execution of these contracts on ICE requires the daily posting of margin calls as collateral through a futures and clearing agent. As of December 31, 2017,2019, PSE had cash posted as collateral of $2.6$14.8 million related to contracts executed on thisthe ICE platform. Also, as of December 31, 2017,2019, PSE has 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, 2017,2019, nor were any of PSE's counterparties required to post collateral resulting from credit rating downgrades.
The following table presents the aggregate fair value of all derivative instruments with credit-risk-related contingent features that are in a liability position and the amount of additional collateral the 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) | | 2017 | | 2016 | (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 | | $ | 3,187 |
| | $ | — |
| | $ | 3,187 |
| | $ | 4,894 |
| | $ | — |
| | $ | 4,894 |
| Credit rating2 | $ | 6,110 | | | $ | — | | | $ | 6,110 | | | $ | 574 | | | $ | — | | | $ | 574 | |
Requested credit for adequate assurance | | 37,374 |
| | — |
| | — |
| | 7,427 |
| | — |
| | — |
| Requested credit for adequate assurance | 5,253 | | | — | | | — | | | 18,495 | | | — | | | — | |
Forward value of contract3 | | 353 |
| | 2,639 |
| | — |
| | 507 |
| | — |
| | — |
| Forward value of contract3 | — | | | 14,827 | | | N/A | | | — | | | — | | | — | |
Total | | $ | 40,914 |
| | $ | 2,639 |
| | $ | 3,187 |
| | $ | 12,828 |
| | $ | — |
| | $ | 4,894 |
| 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. (10)3.Collateral requirements may vary, based on changes in the forward value of underlying transactions relative to contractually defined collateral thresholds.
(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, contract terms and prices, credit-risk adjustments, and discount factors. Additionally, for options, the Black-Scholes option valuation model and implied market volatility curves are used. Inputs used to estimate fair value in industry-standard models are categorized as Level 2 inputs as substantially all assumptions and inputs are observable in active markets throughout the full term of the instruments. On a daily basis, the Company obtains quoted forward prices for the electric and natural gas markets from an independent external pricing service.
The Company considers its electric and natural gas contracts as Level 2 derivative instruments as such contracts are commonly traded as over-the-counter forwards with indirectly observable price quotes. However, certain energy derivative instruments with maturity dates falling outside the range of observable price quotes are classified as Level 3 in the fair value hierarchy. Management's assessment is based on the trading activity in real-time and forward electric and natural gas markets. Each quarter, the Company confirms the validity of pricing-service quoted prices used to value Level 2 commodity contracts with the actual prices of commodity contracts entered into during the most recent quarter.
Assets and Liabilities with Estimated Fair Value
The 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 $48.5$51.5 million and $49.1$49.5 million at December 31, 20172019, and 2016,2018, respectively, are included in "Other property and investments" 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 Company's credit spreads as inputs, interpolating to the maturity date of each issue. The carrying values and estimated fair values were as follows:
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
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.
|
| | | | | | | | | | | | | | | | | |
Puget Energy | | | At December 31, 2017 | | At December 31, 2016 |
(Dollars in Thousands) | Level | | Carrying Value | | Fair Value | | Carrying Value | | Fair Value |
Liabilities: | | | | | | | | | |
Junior subordinated notes | 2 | | $ | 250,000 |
| | $ | 238,935 |
| | $ | 250,000 |
| | $ | 210,261 |
|
Long-term debt (fixed-rate), net of discount1 | 2 | | 5,105,329 |
| | 6,520,515 |
| | 5,091,593 |
| | 6,337,287 |
|
Long-term debt (variable-rate) | 2 | | 102,600 |
| | 102,600 |
| | 12,480 |
| | 12,480 |
|
Total | | | $ | 5,457,929 |
| | $ | 6,862,050 |
| | $ | 5,354,073 |
| | $ | 6,560,028 |
|
| | | | | | | | | |
Puget Sound Energy | | | At December 31, 2017 | | At December 31, 2016 |
(Dollars in Thousands) | Level | | Carrying Value | | Fair Value | | Carrying Value | | Fair Value |
Liabilities: | | | | | | | | | |
Junior subordinated notes | 2 | | $ | 250,000 |
| | $ | 238,935 |
| | $ | 250,000 |
| | $ | 210,261 |
|
Long-term debt (fixed-rate), net of discount2 | 2 | | 3,499,911 |
| | 4,550,130 |
| | 3,497,298 |
| | 4,360,783 |
|
Total | | | $ | 3,749,911 |
| | $ | 4,789,065 |
| | $ | 3,747,298 |
| | $ | 4,571,044 |
|
109
_______________ | |
1
| The carrying value includes debt issuances costs of $27.9 million and $33.0 million for December 31, 2017 and 2016, respectively, which are not included in fair value. |
| |
2
| The carrying value includes debt issuances costs of $24.6 million and $27.2 million for December 31, 2017 and 2016, 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 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 |
Assets: | | | | | | | | | | | |
Electric Derivative Instruments | $ | 19,282 | | | $ | 651 | | | $ | 19,933 | | | $ | 28,765 | | | $ | 4,522 | | | $ | 33,287 | |
Gas Derivative Instruments | 9,852 | | | 1,523 | | | 11,375 | | | 12,247 | | | 3,485 | | | 15,732 | |
Total derivative assets | $ | 29,134 | | | $ | 2,174 | | | $ | 31,308 | | | $ | 41,012 | | | $ | 8,007 | | | $ | 49,019 | |
Liabilities: | | | | | | | | | | | | | | | | | |
Electric Derivative Instruments | $ | 13,474 | | | $ | 4,030 | | | $ | 17,504 | | | $ | 24,124 | | | $ | 3,160 | | | $ | 27,284 | |
Gas Derivative Instruments | 8,376 | | | 241 | | | 8,617 | | | 28,660 | | | 1,812 | | | 30,472 | |
Total derivative liabilities | $ | 21,850 | | | $ | 4,271 | | | $ | 26,121 | | | $ | 52,784 | | | $ | 4,972 | | | $ | 57,756 | |
|
| | | | | | | | | | | | | | | | | | | | | | | |
Puget Energy and Puget Sound Energy | Fair Value | | Fair Value |
At December 31, 2017 | | At December 31, 2016 |
(Dollars in Thousands) | Level 2 | | Level 3 | | Total | | Level 2 | | Level 3 | | Total |
Assets: | | | | | | | | | | | |
Electric derivative instruments | $ | 9,866 |
| | $ | 3,525 |
| | $ | 13,391 |
| | $ | 30,666 |
| | $ | 5,794 |
| | $ | 36,460 |
|
Natural gas derivative instruments | 6,973 |
| | 4,041 |
| | 11,014 |
| | 23,316 |
| | 3,303 |
| | 26,619 |
|
Total derivative assets | $ | 16,839 |
| | $ | 7,566 |
| | $ | 24,405 |
| | $ | 53,982 |
| | $ | 9,097 |
| | $ | 63,079 |
|
Liabilities: | |
| | |
| | |
| | |
| | |
| | |
|
Interest rate derivative instruments1 | $ | — |
| | $ | — |
| | $ | — |
| | $ | 141 |
| | $ | — |
| | $ | 141 |
|
Electric derivative instruments | 46,623 |
| | 2,427 |
| | 49,050 |
| | 36,507 |
| | 4,822 |
| | 41,329 |
|
Natural gas derivative instruments | 34,926 |
| | 2,118 |
| | 37,044 |
| | 16,423 |
| | 2,678 |
| | 19,101 |
|
Total derivative liabilities | $ | 81,549 |
| | $ | 4,545 |
| | $ | 86,094 |
| | $ | 53,071 |
| | $ | 7,500 |
| | $ | 60,571 |
|
_______________
| |
1
| Interest rate derivative instruments are only held at Puget Energy, and matured January 2017. |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
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 | Year Ended December 31, |
Level 3 Roll-Forward Net (Liability) | 2017 | | 2016 | | 2015 |
(Dollars in Thousands) | Electric | | Gas | | Total | | Electric | | Gas | | Total | | Electric | | Gas | | Total |
Balance at beginning of period | $ | 972 |
| | $ | 625 |
| | $ | 1,597 |
| | $ | (7,345 | ) | | $ | (2,383 | ) | | $ | (9,728 | ) | | $ | (12,062 | ) | | $ | (2,040 | ) | | $ | (14,102 | ) |
Changes during period | | | | | | | | | | | | |
| |
| | |
Realized and unrealized energy derivatives: | | | | | | | | | | | | |
| |
| | |
Included in earnings1 | 2,781 |
| | — |
| | 2,781 |
| | 4,007 |
| | — |
| | 4,007 |
| | (6,432 | ) | | — |
| | (6,432 | ) |
Included in regulatory assets / liabilities | — |
| | 6,346 |
| | 6,346 |
| | — |
| | 4,312 |
| | 4,312 |
| | — |
| | 3,695 |
| | 3,695 |
|
Settlements2 | (6,549 | ) | | (6,372 | ) | | (12,921 | ) | | (1,129 | ) | | (2,679 | ) | | (3,808 | ) | | 902 |
| | (3,885 | ) | | (2,983 | ) |
Transferred into Level 3 | 523 |
| | (553 | ) | | (30 | ) | | (3,021 | ) | | — |
| | (3,021 | ) | | (787 | ) | | — |
| | (787 | ) |
Transferred out Level 3 | 3,371 |
| | 1,877 |
| | 5,248 |
| | 8,460 |
| | 1,375 |
| | 9,835 |
| | 11,034 |
| | (153 | ) | | 10,881 |
|
Balance at end of period | $ | 1,098 |
| | $ | 1,923 |
| | $ | 3,021 |
| | $ | 972 |
| | $ | 625 |
| | $ | 1,597 |
| | $ | (7,345 | ) | | $ | (2,383 | ) | | $ | (9,728 | ) |
_________________________________
| |
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 $1.5 million, $2.0 million and $(7.4) million for the years ended December 31, 2017, 2016 and 2015, respectively.
|
| |
2
| The Company had no purchases, sales or issuances during the reported periods. |
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.
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, 2017, 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, 2017:2019:
| | 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 | $3,525 | | $2,427 | | Discounted cash flow | | Power Prices (per MWh) | | $7.02 | | $28.94 | | $18.61 | |
Natural gas | $4,041 | | $2,118 | | Discounted cash flow | | Natural Gas Prices (per MMBtu) | | $1.22 | | $2.80 | | $1.54 | |
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, 2017,2019, 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 $0.9$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 20172018, decreases in forward power prices and 2016,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 2017 and 2016, due to continued decreases in forward power prices and decreases in forecasted revenue and cost estimates,2018, the following impairments were recorded to the Company's intangible asset contracts, with corresponding reductions to the regulatory liability as follows:
|
| | | | | | | | | | | | |
Puget Energy | | | | | | |
(Dollars in Thousands) | | | | | | |
Valuation Date | Contract Name | Carrying Value | | Fair Value | | Write Down |
September 30, 2017 | Wells Hydro | $ | 10,621 |
| | $ | 9,609 |
| | $ | 1,012 |
|
| | | | | | |
March 31, 2017 | Wells Hydro | 14,879 |
| | 13,067 |
| | 1,812 |
|
| Rocky Reach | 235,331 |
| | 159,818 |
| | 75,513 |
|
| Priest Rapids RP | 5,665 |
| | 2,657 |
| | 3,008 |
|
Total 2017 Impairments | | | | | | $ | 81,345 |
|
| | | | | | |
| | | | | | |
September 30, 2016 | Priest Rapids RP | $ | 18,969 |
| | $ | 6,191 |
| | $ | 12,778 |
|
| | | | | | |
March 31, 2016 | Wells Hydro | 25,193 |
| | 19,855 |
| | 5,338 |
|
Total 2016 Impairments | | | | | | $ | 18,116 |
|
| | | | | | | | | | | | | | | | | | | | |
Puget Energy | | | | | | |
(Dollars in Thousands) | | | | | | |
Valuation Date | Contract Name | Carrying Value | | Fair Value | | Write Down |
March 31, 2018 | Wells Hydro | $ | 4,302 | | | $ | 2,395 | | | $ | 1,907 | |
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 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 20172019 and 2016:2018:
| | | | | | | | | | | | | | | | | | | | | | | |
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 | Contract | Unobservable Input | Low | | High | | Average |
September 30, 2017 | Wells Hydro | Power prices (per MWh) | 14.06 | | 26.86 | | 22.24 |
| | Power contract costs per quarter (in thousands) | 4,126 | | 4,126 | | 4,126 |
| | | | | | | |
March 31, 2017 | Wells Hydro | Power prices (per MWh) | 8.76 | | 26.70 | | 20.86 |
| | Power contract costs per quarter (in thousands) | 3,965 | | 4,223 | | 4,051 |
| | | | | | | |
| Rocky Reach | Power prices (per MWh) | 8.53 | | 48.21 | | 27.69 |
| | Power contract costs per quarter (in thousands) | 5,827 | | 6,780 | | 6,150 |
| | | | | | | |
| Priest Rapids RP | Power prices (per MWh) | 13.70 | | 29.38 | | 23.14 |
| | Power contract costs per year (in thousands) | 620 | | 4,022 | | 2,306 |
| | | | | | | |
September 30, 2016 | Priest Rapids RP | Power prices (per MWh) | 24.24 | | 58.96 | | 39.31 |
| | Power contract costs per year (in thousands) | 618 | | 4,633 | | 2,472 |
| | | | | | | |
March 31, 2016 | Wells Hydro | Power prices (per MWh) | 9.46 | | 25.96 | | 21.38 |
| | Power contract costs per quarter (in thousands) | 4,100 | | 4,659 | | 4,452 |
(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 $19.2$21.7 million, $17.2$20.7 million and $16.1$19.2 million for the years 2017, 20162019, 2018, and 2015,2017, 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 6.0% of plan compensation each paycheck, and will make an additional year-end contribution equal to 1.0% of base pay.
2.For employees grandfathered under the Final Average Earning retirement plan formula, PSE will match 55.0% of an employee’s contribution up to 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:match: 100% match on the first 3.0% of pay contributed and 50.0% match on the next 3.0% of pay contributed. Ancontributed, such that an employee who contributes 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 4.0% 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 4.0% 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 4.0% contribution either into the 401(k) plan or into an account in the Cash Balance retirement plan. The Company’sCompany'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 pay creditsemployer contributions of 4.0% of eligible pay each year. They will also receive interest credits like other participantsyear in the cash balance pension formula of the defined benefit pension or 401k plan account. Those employees receiving contributions in the cash balance formula plan also receive interest credits, which are at least 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, 20172019, and 2016:2018:
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
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) | 2017 | | 2016 | | 2017 | | 2016 | | 2017 | | 2016 |
Change in benefit obligation: | | | | | | | | | | | |
Benefit obligation at beginning of period | $ | 652,607 |
| | $ | 643,088 |
| | $ | 51,734 |
| | $ | 51,279 |
| | $ | 11,194 |
| | $ | 13,946 |
|
Service cost | 20,081 |
| | 18,913 |
| | 913 |
| | 1,085 |
| | 72 |
| | 93 |
|
Interest cost | 28,373 |
| | 28,689 |
| | 2,285 |
| | 2,325 |
| | 500 |
| | 533 |
|
Actuarial loss (gain) | 40,945 |
| | 1,545 |
| | 2,722 |
| | 106 |
| | 725 |
| | (2,262 | ) |
Benefits paid | (40,594 | ) | | (38,730 | ) | | (1,900 | ) | | (3,061 | ) | | (1,137 | ) | | (1,264 | ) |
Medicare part D subsidy received | — |
| | — |
| | — |
| | — |
| | 100 |
| | 148 |
|
Administrative expense | (931 | ) | | (898 | ) | | — |
| | — |
| | — |
| | — |
|
Benefit obligation at end of period | $ | 700,481 |
| | $ | 652,607 |
| | $ | 55,754 |
| | $ | 51,734 |
| | $ | 11,454 |
| | $ | 11,194 |
|
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
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) | 2017 | | 2016 | | 2017 | | 2016 | | 2017 | | 2016 |
Change in plan assets: | | | | | | | | | | | |
Fair value of plan assets at beginning of period | $ | 620,260 |
| | $ | 598,865 |
| | $ | — |
| | $ | — |
| | $ | 7,200 |
| | $ | 7,203 |
|
Actual return on plan assets | 107,836 |
| | 37,022 |
| | — |
| | — |
| | 784 |
| | 926 |
|
Employer contribution | 18,000 |
| | 24,000 |
| | 1,900 |
| | 3,061 |
| | 291 |
| | 335 |
|
Benefits paid | (40,594 | ) | | (38,730 | ) | | (1,900 | ) | | (3,061 | ) | | (1,137 | ) | | (1,264 | ) |
Administrative expense | (1,142 | ) | | (897 | ) | | — |
| | — |
| | — |
| | — |
|
Fair value of plan assets at end of period | $ | 704,360 |
| | $ | 620,260 |
| | $ | — |
| | $ | — |
| | $ | 7,138 |
| | $ | 7,200 |
|
Funded status at end of period | $ | 3,879 |
| | $ | (32,347 | ) | | $ | (55,754 | ) | | $ | (51,734 | ) | | $ | (4,316 | ) | | $ | (3,994 | ) |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
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) | 2017 | | 2016 | | 2017 | | 2016 | | 2017 | | 2016 |
Amounts recognized in Statement of Financial Position consist of: | | | | | | | | | | | |
Noncurrent assets | $ | 3,879 |
| | $ | — |
| | $ | — |
| | $ | — |
| | $ | — |
| | $ | — |
|
Current liabilities | — |
| | — |
| | (5,486 | ) | | (1,911 | ) | | (317 | ) | | (325 | ) |
Noncurrent liabilities | — |
| | (32,347 | ) | | (50,268 | ) | | (49,823 | ) | | (3,999 | ) | | (3,669 | ) |
Net assets (liabilities) | $ | 3,879 |
| | $ | (32,347 | ) | | $ | (55,754 | ) | | $ | (51,734 | ) | | $ | (4,316 | ) | | $ | (3,994 | ) |
|
| | | | | | | | | | | | | | | | | | | | | | | |
Puget Energy and Puget Sound Energy | Qualified Pension Benefits | | SERP Pension Benefits | | Other Benefits |
(Dollars in Thousands) | 2017 | | 2016 | | 2017 | | 2016 | | 2017 | | 2016 |
Pension Plans with an Accumulated Benefit Obligation in excess of Plan Assets: | | | | | | | | | | | |
Projected benefit obligation | $ | 700,481 |
| | $ | 652,607 |
| | $ | 55,754 |
| | $ | 51,734 |
| | $ | 11,454 |
| | $ | 11,194 |
|
Accumulated benefit obligation | 688,908 |
| | 641,855 |
| | 52,681 |
| | 47,639 |
| | 11,367 |
| | 11,092 |
|
Fair value of plan assets | 704,360 |
| | 620,260 |
| | — |
| | — |
| | 7,138 |
| | 7,200 |
|
The following tables summarize Puget Energy's and PSE's pension benefit amounts recognized in AOCI for the years ended December 31, 20172019, and 2016:2018:
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
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) | 2017 | | 2016 | | 2017 | | 2016 | | 2017 | | 2016 | (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) | $ | 37,693 |
| | $ | 56,588 |
| | $ | 10,689 |
| | $ | 9,043 |
| | $ | (3,386 | ) | | $ | (4,190 | ) | Net loss (gain) | $ | 217,502 | | | $ | 229,819 | | | $ | 16,473 | | | $ | 11,450 | | | $ | (364) | | | $ | (3,857) | |
Prior service cost (credit) | (7,843 | ) | | (9,822 | ) | | 204 |
| | 246 |
| | — |
| | — |
| Prior service cost (credit) | (3,086) | | | (4,659) | | | 1,276 | | | 1,609 | | | — | | | — | |
Total | $ | 29,850 |
| | $ | 46,766 |
| | $ | 10,893 |
| | $ | 9,289 |
| | $ | (3,386 | ) | | $ | (4,190 | ) | 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) | 2017 | | 2016 | | 2017 | | 2016 | | 2017 | | 2016 |
Amounts recognized in Accumulated Other Comprehensive Income consist of: | |
| | |
| | |
| | |
| | |
| | |
|
Net loss (gain) | $ | 185,277 |
| | $ | 217,143 |
| | $ | 13,134 |
| | $ | 11,978 |
| | $ | (4,901 | ) | | $ | (5,994 | ) |
Prior service cost (credit) | (6,232 | ) | | (7,806 | ) | | 208 |
| | 251 |
| | — |
| | — |
|
Total | $ | 179,045 |
| | $ | 209,337 |
| | $ | 13,342 |
| | $ | 12,229 |
| | $ | (4,901 | ) | | $ | (5,994 | ) |
The following tables summarize Puget Energy's and PSE's net periodic benefit cost for the years ended December 31, 2017, 20162019, 2018, and 2015:2017.
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
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) | 2017 | | 2016 | | 2015 | | 2017 | | 2016 | | 2015 | | 2017 | | 2016 | | 2015 |
Components of net periodic benefit cost: | | | | | | | | | | | | | | | | | |
Service cost | $ | 20,081 |
| | $ | 18,913 |
| | $ | 21,287 |
| | $ | 913 |
| | $ | 1,085 |
| | $ | 1,108 |
| | $ | 72 |
| | $ | 93 |
| | $ | 112 |
|
Interest cost | 28,373 |
| | 28,689 |
| | 28,088 |
| | 2,285 |
| | 2,325 |
| | 2,281 |
| | 500 |
| | 533 |
| | 621 |
|
Expected return on plan assets | (47,784 | ) | | (46,619 | ) | | (45,038 | ) | | — |
| | — |
| | — |
| | (461 | ) | | (446 | ) | | (531 | ) |
Amortization of prior service cost (credit) | (1,980 | ) | | (1,980 | ) | | (1,980 | ) | | 42 |
| | 42 |
| | 42 |
| | — |
| | — |
| | — |
|
Amortization of net loss (gain) | — |
| | — |
| | 3,887 |
| | 1,077 |
| | 911 |
| | 1,641 |
| | (402 | ) | | (386 | ) | | (130 | ) |
Net periodic benefit cost | $ | (1,310 | ) | | $ | (997 | ) | | $ | 6,244 |
| | $ | 4,317 |
| | $ | 4,363 |
| | $ | 5,072 |
| | $ | (291 | ) | | $ | (206 | ) | | $ | 72 |
|
|
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
Puget Sound Energy | Qualified Pension Benefits | | SERP Pension Benefits | | Other Benefits |
(Dollars in Thousands) | 2017 | | 2016 | | 2015 | | 2017 | | 2016 | | 2015 | | 2017 | | 2016 | | 2015 |
Components of net periodic benefit cost: | | | | | | | | | | | | | | | | | |
Service cost | $ | 20,081 |
| | $ | 18,913 |
| | $ | 21,287 |
| | $ | 913 |
| | $ | 1,085 |
| | $ | 1,108 |
| | $ | 72 |
| | $ | 93 |
| | $ | 112 |
|
Interest cost | 28,373 |
| | 28,689 |
| | 28,088 |
| | 2,285 |
| | 2,325 |
| | 2,281 |
| | 500 |
| | 533 |
| | 621 |
|
Expected return on plan assets | (47,862 | ) | | (46,814 | ) | | (45,462 | ) | | — |
| | — |
| | — |
| | (461 | ) | | (446 | ) | | (531 | ) |
Amortization of prior service cost (credit) | (1,573 | ) | | (1,573 | ) | | (1,573 | ) | | 44 |
| | 44 |
| | 44 |
| | — |
| | — |
| | 3 |
|
Amortization of net loss (gain) | 13,048 |
| | 15,257 |
| | 20,555 |
| | 1,565 |
| | 1,330 |
| | 2,120 |
| | (641 | ) | | (632 | ) | | (406 | ) |
Net periodic benefit cost | $ | 12,067 |
| | $ | 14,472 |
| | $ | 22,895 |
| | $ | 4,807 |
| | $ | 4,784 |
| | $ | 5,553 |
| | $ | (530 | ) | | $ | (452 | ) | | $ | (201 | ) |
The following tables summarize Puget Energy's and PSE's benefit obligations recognized in other comprehensive income (OCI) for the years ended December 31, 20172019, and 2016:2018:
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
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) | 2017 | | 2016 | | 2017 | | 2016 | | 2017 | | 2016 |
Other changes (pre-tax) in plan assets and benefit obligations recognized in other comprehensive income: | | | | | | | | | | | |
Net loss (gain) | $ | (18,896 | ) | | $ | 11,141 |
| | $ | 2,722 |
| | $ | 106 |
| | $ | 403 |
| | $ | (2,742 | ) |
Amortization of net (loss) gain | — |
| | — |
| | (1,076 | ) | | (910 | ) | | 401 |
| | 385 |
|
Amortization of prior service (cost) credit | 1,980 |
| | 1,980 |
| | (42 | ) | | (42 | ) | | — |
| | — |
|
Total change in other comprehensive income for year | $ | (16,916 | ) | | $ | 13,121 |
| | $ | 1,604 |
| | $ | (846 | ) | | $ | 804 |
| | $ | (2,357 | ) |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
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) | 2017 | | 2016 | | 2017 | | 2016 | | 2017 | | 2016 |
Other changes (pre-tax) in plan assets and benefit obligations recognized in other comprehensive income: | | | | | | | | | | | |
Net loss (gain) | $ | (18,817 | ) | | $ | 11,336 |
| | $ | 2,722 |
| | $ | 106 |
| | $ | 452 |
| | $ | (2,742 | ) |
Amortization of net (loss) gain | (13,048 | ) | | (15,257 | ) | | (1,565 | ) | | (1,330 | ) | | 641 |
| | 631 |
|
Amortization of prior service (cost) credit | 1,573 |
| | 1,573 |
| | (44 | ) | | (44 | ) | | — |
| | — |
|
Total change in other comprehensive income for year | $ | (30,292 | ) | | $ | (2,348 | ) | | $ | 1,113 |
| | $ | (1,268 | ) | | $ | 1,093 |
| | $ | (2,111 | ) |
The estimated net (loss) gain and prior service cost (credit) for the pension plans that will be amortized from Accumulated Other Comprehensive Income (AOCI) into net periodic benefit cost in 2018 by PSE are $(14.5) million and $1.6 million, respectively. The estimated net (loss) gain for the SERP that will be amortized from AOCI into net periodic benefit cost in 2018 is $(2.1) million.2020 by PSE include a $18.6 million net loss and a $1.6 million credit, respectively. The estimated net (loss) gain and prior service cost (credit) for the SERP that will be amortized from AOCI into net periodic benefit cost in 20182020 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 AOCI into net periodic benefit cost in 20182020 is $0.6a net loss of $0.2 million. For Puget Energy, the overall amounts expected to be amortized from AOCI into net period benefit cost in 20182020 is $(1.1)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, 20182020, are expected to be at least $18.0 million, $5.5$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 | 2017 | | 2016 | | 2015 | | 2017 | | 2016 | | 2015 | | 2017 | | 2016 | | 2015 | Benefit Obligation Assumptions | 2019 | | 2018 | | 2017 | | 2019 | | 2018 | | 2017 | | 2019 | | 2018 | | 2017 |
Discount rate | 4.00 | % | | 4.50 | % | | 4.65 | % | | 4.00 | % | | 4.50 | % | | 4.65 | % | | 4.00 | % | | 4.50 | % | | 4.65 | % | 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 | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | 6.80 |
| | 8.80 |
| | 7.20 |
| |
Medical trend rate1 | | Medical trend rate1 | — | | | — | | | — | | | — | | | — | | | — | | | N/A | | | 7.60 | | | 6.80 | |
Benefit Cost Assumptions | | | | | | | | | | | | | | | | | | Benefit Cost Assumptions | | | | | | | | | | | | | | | | | | | | | | | | | | |
Discount rate | 4.50 | % | | 4.65 | % | | 4.25 | % | | 4.50 | % | | 4.65 | % | | 4.25 | % | | 4.50 | % | | 4.65 | % | | 4.25 | % | Discount rate | 4.40 | | | 4.40 | | | 4.50 | | | 4.40 | | | 4.40 | | | 4.50 | | | 4.40 | | | 4.40 | | | 4.50 | |
Return on plan assets | 7.45 |
| | 7.75 |
| | 7.75 |
| | — |
| | — |
| | — |
| | 6.75 |
| | 6.75 |
| | 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 | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | 9.50 |
| | 5.30 |
| | 7.20 |
| |
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 6.80% in 2018 grading down to 4.10% in 2019. A 1.0% change in the assumed medical inflation rate would have the following effects:obligation.
|
| | | | | | | | | | | | | | | |
| 2017 | | 2016 |
(Dollars in Thousands) | 1% Increase | | 1% Decrease | | 1% Increase | | 1% Decrease |
Effect on post-retirement benefit obligation | $ | 23 |
| | $ | (22 | ) | | $ | 38 |
| | $ | (35 | ) |
Effect on service and interest cost components | 1 |
| | (1 | ) | | 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 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) | 2018 |
| | 2019 |
| | 2020 |
| | 2021 |
| | 2022 |
| | 2023-2027 |
|
Qualified Pension total benefits | $ | 42,600 |
| | $ | 43,400 |
| | $ | 44,800 |
| | $ | 45,700 |
| | $ | 46,900 |
| | $ | 246,500 |
|
SERP Pension total benefits | 5,486 |
| | 6,001 |
| | 4,684 |
| | 1,728 |
| | 4,577 |
| | 37,394 |
|
Other Benefits total with Medicare Part D subsidy | 911 |
| | 885 |
| | 852 |
| | 811 |
| | 863 |
| | 3,748 |
|
Other Benefits total without Medicare Part D subsidy | 1,172 |
| | 1,155 |
| | 1,131 |
| | 1,097 |
| | 1,070 |
| | 4,844 |
|
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, 20172019, and 2016:2018:
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| 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, 2017 | | As of December 31, 2016 |
(Dollars in Thousands) | Level 1 |
| | Level 2 | | Total | | Level 1 | | Level 2 | | Total |
Assets: | | | | | | | | | | | |
Mutual Funds | $ | 117,796 |
| | $ | — |
| | $ | 117,796 |
| | $ | 181,212 |
| | $ | — |
| | $ | 181,212 |
|
Common Stock | 209,504 |
| | — |
| | 209,504 |
| | 154,255 |
| | — |
| | 154,255 |
|
Government Securities | 18,316 |
| | 23,782 |
| | 42,098 |
| | 18,754 |
| | 16,197 |
| | 34,951 |
|
Corporate Bonds | — |
| | 34,588 |
| | 34,588 |
| | — |
| | 38,543 |
| | 38,543 |
|
Cash and cash equivalents | 2,684 |
| | 9,304 |
| | 11,988 |
| | — |
| | — |
| | — |
|
Subtotal | $ | 348,300 |
| | $ | 67,674 |
| | 415,974 |
| | $ | 354,221 |
| | $ | 54,740 |
| | 408,961 |
|
Investments measured at NAV1 |
| |
| | 237,427 |
| |
| |
| | 222,819 |
|
Net (payable) receivable | | | | | 50,959 |
| | | | | | (9,894 | ) |
Total assets |
| |
| | $ | 704,360 |
| |
| |
| | $ | 621,886 |
|
_______________________________________
| |
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 primarily consist of common/collective trust funds and two partnerships held as of December 31, 2017. |
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, 2017 | | As of December 31, 2016 |
(Dollars in Thousands) | Level 1 | | Level 2 | | Total | | Level 1 | | Level 2 | | Total |
Assets: | | | | | | | | | | | |
Mutual fund1 | $ | 7,089 |
| | $ | — |
| | $ | 7,089 |
| | $ | 7,182 |
| | $ | — |
| | $ | 7,182 |
|
Investments measured at NAV2 | | | | | 49 |
| | | | | | 80 |
|
Total assets |
| |
|
| | $ | 7,138 |
| |
|
| |
|
| | $ | 7,262 |
|
_______________
| |
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, 2017. |
| |
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 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 a common/collective trust fund as of December 31, 2017. |
(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) | 2017 | | 2016 | | 2015 |
| (Dollars in Thousands) | 2019 | | 2018 | | 2017 |
Charged to operating expenses: | | | | | | Charged to operating expenses: | | | | | |
Current: | | | | | | Current: | | | | | |
Federal | $ | 1,127 |
| | $ | — |
| | $ | — |
| Federal | $ | 9,424 | | | $ | 10,382 | | | $ | 1,127 | |
State | 17 |
| | 20 |
| | — |
| State | 164 | | | 263 | | | 17 | |
Deferred: | |
| | |
| | | Deferred: | | | | | | | | |
Federal | 254,420 |
| | 140,315 |
| | 91,968 |
| Federal | 7,357 | | | 19,451 | | | 254,420 | |
State | (421 | ) | | (131 | ) | | (192 | ) | State | 128 | | | (4) | | | (421) | |
Total income tax expense | $ | 255,143 |
| | $ | 140,204 |
| | $ | 91,776 |
| 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) | 2017 | | 2016 | | 2015 | (Dollars in Thousands) | 2019 | | 2018 | | 2017 |
Charged to operating expenses: | | | | | | Charged to operating expenses: | | | | | |
Current: | | | | | | Current: | | | | | |
Federal | $ | 1,127 |
| | $ | — |
| | $ | — |
| Federal | $ | 18,093 | | | $ | 19,283 | | | $ | 1,127 | |
State | 17 |
| | 20 |
| | — |
| State | 570 | | | 438 | | | 17 | |
Deferred: | |
| | |
| | |
| Deferred: | | | | | | | | |
Federal | 210,842 |
| | 175,327 |
| | 125,900 |
| Federal | 20,485 | | | 30,979 | | | 210,842 | |
State | — |
| | — |
| | — |
| State | — | | | — | | | — | |
Total income tax expense | $ | 211,986 |
| | $ | 175,347 |
| | $ | 125,900 |
| 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) | 2017 | | 2016 | | 2015 |
Income taxes at the statutory rate | $ | 148,847 |
| | $ | 158,586 |
| | $ | 116,534 |
|
Increase (decrease): | |
| | |
| | |
Production tax credit1 | — |
| | (12,925 | ) | | (19,470 | ) |
Utility plant differences | — |
| | 3,966 |
| | 5,671 |
|
Treasury grant amortization | (9,537 | ) | | (9,788 | ) | | (8,807 | ) |
Tax reform | 117,185 |
| | — |
| | — |
|
Other - net | (1,352 | ) | | 365 |
| | (2,152 | ) |
Total income tax expense | $ | 255,143 |
| | $ | 140,204 |
| | $ | 91,776 |
|
Effective tax rate | 60.0 | % | | 30.9 | % | | 27.6 | % |
| | Puget Sound Energy | Year Ended December 31, | Puget Sound Energy | Year Ended December 31, | |
(Dollars in Thousands) | 2017 | | 2016 | | 2015 | (Dollars in Thousands) | 2019 | | 2018 | | 2017 |
Income taxes at the statutory rate | $ | 185,430 |
| | $ | 194,572 |
| | $ | 150,531 |
| Income taxes at the statutory rate | $ | 69,735 | | | $ | 77,251 | | | $ | 185,430 | |
Increase (decrease): | |
| | |
| | |
| Increase (decrease): | | | | | | | | |
Production tax credit1 | — |
| | (12,925 | ) | | (19,470 | ) | |
Utility plant differences | — |
| | 3,966 |
| | 5,671 |
| |
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 | (9,537 | ) | | (9,788 | ) | | (8,807 | ) | Treasury grant amortization | (7,870) | | | (4,861) | | | (9,537) | |
Tax reform | 36,328 |
| | — |
| | — |
| Tax reform | — | | | — | | | 36,328 | |
Other - net | (235 | ) | | (478 | ) | | (2,025 | ) | |
Other–net | | Other–net | 2,174 | | | 3,915 | | | 4,271 | |
Total income tax expense | $ | 211,986 |
| | $ | 175,347 |
| | $ | 125,900 |
| Total income tax expense | $ | 39,148 | | | $ | 50,700 | | | $ | 211,986 | |
Effective tax rate | 40.0 | % | | 31.5 | % | | 29.3 | % | 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, 20172019, and 20162018, 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 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 | |
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. PSE’s PTC carryforwards expire from 2033 through 2036. Puget Energy’s net operating loss carryforwards expire from 2027 through 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.
|
| | | | | | | |
Puget Energy | At December 31, |
(Dollars in Thousands) | 2017 |
| | 2016 |
|
Utility plant and equipment | $ | 2,034,328 |
| | $ | 1,880,782 |
|
Regulatory asset for income taxes | — |
| | 72,038 |
|
Fair value of debt instruments | 38,777 |
| | 67,444 |
|
Pensions and other compensation | 46,338 |
| | 77,230 |
|
Other deferred tax liabilities | 86,933 |
| | 119,050 |
|
Subtotal deferred tax liabilities | 2,206,376 |
| | 2,216,544 |
|
Net operating loss carryforward | (212,168 | ) | | (352,827 | ) |
Net regulatory liability for income taxes | (1,011,626 | ) | | — |
|
Production tax credit carryforward | (187,617 | ) | | (190,999 | ) |
Regulatory liability on production tax credit | (49,873 | ) | | (101,787 | ) |
Net other deferred tax assets | 1,776 |
| | — |
|
Subtotal deferred tax assets | (1,459,508 | ) | | (645,613 | ) |
Total net deferred tax liabilities | $ | 746,868 |
| | $ | 1,570,931 |
|
|
| | | | | | | |
Puget Sound Energy | At December 31, |
(Dollars in Thousands) | 2017 |
| | 2016 |
|
Utility plant and equipment | $ | 2,034,328 |
| | $ | 1,880,782 |
|
Regulatory asset for income taxes | — |
| | 71,517 |
|
Other, net deferred tax liabilities | 86,933 |
| | 113,938 |
|
Subtotal deferred tax liabilities | 2,121,261 |
| | 2,066,237 |
|
Net regulatory liability for income taxes | (1,012,260 | ) | | — |
|
Net operating loss carryforward | — |
| | (41,061 | ) |
Production tax credit carryforward | (187,617 | ) | | (190,999 | ) |
Regulatory liability on production tax credit | (49,873 | ) | | (101,787 | ) |
Net other deferred tax assets | (2,038 | ) | | — |
|
Subtotal deferred tax assets | (1,251,788 | ) | | (333,847 | ) |
Total net deferred tax liabilities | $ | 869,473 |
| | $ | 1,732,390 |
|
Federal Income Tax Law Changes
On December 22, 2017, President Trump signed into law legislation referred to as the “Tax Cuts and Jobs Act” (the TCJA).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% percent to 21.0% percent.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 September 27,December 31, 2017, and continues normalization requirements for accelerated depreciation benefits. For Puget Energy, TCJA provides for full expensing of property acquired after September 27, 2017 and limits a deduction for interest expense to 30.0% percent of adjusted taxable income (which resembles earnings before interest, taxes, depreciation and amortization or “EBITDA”).
Under generally accepted accounting principles (US GAAP)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 PSE, the change in deferred taxes is 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 theirits 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 the year,2017, before tax reform, was a $71.5 million asset. As a result of tax reform, the balance iswas a liability of $1,012.3 million which represents the excess deferred taxes that will eventually be refunded to customers.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 amortizedreversed over the remaining lives of the related assets.assets using ARAM. The remainder of the net regulatory liability of $92.5$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. The income statement impactFor 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 the regulatory deferred tax will comeplant-related items using ARAM in the future when the Washington Commission issues a final order. The timing for that is unknown but will likely occur in 2018.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 deferred taxes.balances. The regulatory liability owed to customers for PTCs, which previously reduced revenue upon generation of the PTCs, was also revalued at the TCJAs 21 percent rate.new rate of 21.0%. The change in the liability owed to customers for PTCs due to TCJA 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 theirits 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) which. The guidance clarifies accounting for
income taxes under ASC 740 if information is not yet available or complete and provides for up to a one year period in which to complete the required analysesanalysis and accounting (the measurement period). SAB 118 describes three scenarios (or “buckets”) associated with a company’s status of accounting for income tax reform: (1) a company is complete with its accounting for certain effects of tax reform, (2) a company is able to determine a reasonable estimate for certain effects of tax reform and records that estimate as a provisional amount, or (3) a company is not able to determine a reasonable estimate and therefore continues to apply ASC 740, based on the provisions of the tax laws that were in effect immediately prior to the TCJA being enacted. The Company has completed the required analysis and accounting for substantially all the effects of the TCJA's enactment and have made a reasonable estimate as to the other effects, and have reflected the measurement and accounting of the effects in the 2017 consolidated financial statements. The items reflected as provisional amounts include tax depreciation and amortization and other book to tax differences. PSE has accounted for these items based on its interpretation of the TCJA. Further interpretive guidance on the TCJA from the IRS, U.S. Treasury Department, or the Joint Committee on Taxation may require adjustments to PSE's accounting. In accordance with SAB 118, adjustments, if any, will be recorded in 2018. The Company did not identify any effects on the TCJA for which they were not able to either complete the required analysis or make a reasonable estimate.additional adjustments required.
The Company calculates its deferred tax assets and liabilities under ASC 740, “Income Taxes” (ASC 740). ASC 740 requires recording deferred tax balances, at the currently enacted tax rate, on assets and liabilities that are reported differently for income tax purposes than for financial reporting purposes. The utilization of deferred tax assets requires sufficient taxable income in future years. ASC 740 requires a valuation allowance on deferred tax assets when it is more likely than not that the deferred tax assets will not be realized. The Company’s PTC carryforwards expire from 2027 through 2037. The Company’s net operating loss carryforwards expire from 2029 through 2036. No valuation allowance has been provided for PTC or net operating loss carryforwards.
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, 20172019, and 2016,2018, 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 20142016 through 2017.2019. 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. 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 and Talen Energy 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. The Washington Commission allows full recovery in 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 utility 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 as of December 31, 2016.
Depreciation rates were updated in the GRC effective December 19, 2017, where PSE's depreciation increased for Colstrip Units 1 and 2 to recover plant costs to the expected shutdown date. The increase inAdditionally, PSE has accelerated the depreciation caused theof Colstrip Units 13 and 2 regulatory asset4, per the terms of the GRC settlement, to be reduced to $127.6 million as of December 31, 2017.2027. 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. Colstrip Units 3 and 4, which are newer and more efficient, are not affected by2 at the settlement, and allegations in the lawsuit against Colstrip Units 3 and 4 were dismissed as partend of the settlementyear due to operational losses associated with the Sierra Club. While PSE has estimated the ARO forUnits. 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 may 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 on September 20, 2016, seeking updecommissioning costs associated with Unit 4 during PSE's operation. The agreement is subject to $3.2 million in fines from PSE. As of September 30, 2016, PSE accrued $3.2 million for the fine. On March 28, 2017, pipeline safety regulators and PSE reached a settlement in response to the complaint. As part of the agreement, PSE agreed to pay a penalty of $2.8 million, of which $1.3 million was suspended on condition that PSE complete a comprehensive inspection and remediation program. On June 19, 2017,approval by the Washington Commission approvedand the settlement without conditionsMontana Public Service Commission. Additionally, PSE has agreed to enter into a power purchase agreement with NorthWestern Energy for 90 MW through 2025 to facilitate the transition, and adoptedsell a portion of its dedicated Colstrip transmission system, conditioned upon regulatory approval. PSE expects external parties to intervene on the reduced penaltycontingent purchase agreement for Colstrip Unit 4. For accounting purposes, management has evaluated the applicable held for sale criteria as of $2.8 million,December 31, 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 which $1.3 million was suspended. On June 30,this report.
Regional Haze Rule
In January 2017, PSE paid the penalty it had previously accrued. However, litigation is still pending regarding damage and personal injury claims.
Coal Combustion Residuals
On April 17, 2015, the EPA published a final rule, effective October 19, 2015, that regulates CCR's under the Resource Conservation and Recovery Act, Subtitle D. The EPA issued another rule, effective October 4, 2016, extending certain compliance deadlines under the CCR rule. 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 changesrevisions to the Company's Colstrip operationsRegional 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 those changes were reviewed byPSE is unable to predict the Company andoutcome. Challenges to the plant operator2017 Regional Haze Revision Rule are pending in abeyance in the second quarterU.S. Court of 2015. PSE had previously recognized a legal obligation underAppeals for the EPA rules to disposeD.C. Circuit, pending resolution of coal ash material at Colstrip in 2003. Due to the CCR rule, additional disposal costs were added toEPA’s reconsideration of the ARO.rule.
Clean Air Act 111(d)/EPA Clean Power PlanAffordable 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 onin October 23, 2015. The rule was 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. OnIn March 31, 2017, thethen EPA Administrator, Scott Pruitt, signed a notice of withdrawal of the proposed CPP federal plan and model trading rules and, onin October 10, 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 is currently accepting comment on the proposal.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 still reviewingevaluating the final ACE rule to determine its impact on operations pending the outcome of these developments.the proposed Colstrip Unit 4 sale to NorthWestern Energy.
Washington Clean Air Rule
The 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 5.0% every three years. Entities must reduce their carbon emissions, or purchase emission reduction units (ERUs), as defined under the rule, from others.
The CAR covers natural gas distributors and subjects them to an emissions reduction pathway based on the indirect emissions of their customers. The 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 a 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. On December 15, 2017,In March 2018, the Thurston County Superior Court invalidated the CAR. A final court order is pending andThe Department of Ecology appealed the Superior Court decision in May 2018. As a result of the meantime,appeal, direct review to the Washington State DepartmentSupreme 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 Ecology (WDOE), submitted a brief requesting severability, which would makenatural gas for use by customers. The court ruled, however, that the rule can be severed and is valid for industriesdirect emitters including electric utilities with direct emissions. This would apply to The Company's electric utility thermal generation unitspermitted air emission sources, but not to its natural gas utility. Appeals could be filedremanded the case back to the Thurston County Courtto determine which parts of Appeals after the court's final order, including its ruling on severability.rule survive. Meanwhile, the federal court litigation has been held in abeyance pending resolution of the state case.
Other Proceedings
The Company is also involved in litigation relating to claims arising out of its operations in the normal course of business. The Company has recorded reserves of $2.4 million and $0.7 million relating to these claims as of December 31, 2017 and 2016, respectively.
(15)(16) Commitments and Contingencies
For the year ended December 31, 2017,2019, approximately 13.3%10.2% of the Company’s energy output was obtained at an average cost of approximately $0.022$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 substantially through substantially 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) | 2017 |
| | 2016 |
| | 2015 |
|
PUD contract costs | $ | 73,827 |
| | $ | 77,667 |
| | $ | 72,833 |
|
As of December 31, 2017,2019, 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 2018 Costs | | 2018 Debt Service Costs | | Interest included in 2018 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 |
| | $ | 29,135 |
| | $ | 10,105 |
| | $ | 5,354 |
| | $ | 84,269 |
| Rock Island Project | 2031 | | 25.0 | % | | 156 | | $ | 34,180 | | | $ | 11,499 | | | $ | 5,681 | | | $ | 96,956 | |
Rocky Reach Project | 2031 | | 25.0 |
| | 325 |
| | 28,800 |
| | 5,796 |
| | 2,548 |
| | 39,563 |
| Rocky Reach Project | 2031 | | 25.0 | | | 325 | | 31,190 | | | 4,940 | | | 2,129 | | | 33,317 | |
Douglas County PUD: | | | | | |
| | | | | | | | | Douglas County PUD: | | | | | | | | | | | | | | | | | | |
Wells Project1 | 2028 | | 29.9 |
| | 251 |
| | 11,002 |
| | 4,695 |
| | 1,379 |
| | 49,629 |
| Wells Project1 | 2028 | | 27.1 | | | 228 | | 43,004 | | | — | | | — | | | — | |
Grant County PUD: | | | | | |
| | | | | | | | | Grant County PUD: | | | | | | | | | | | | | | | | | | |
Priest Rapids Development | 2052 | | 0.6 |
| | 6 |
| | 2,050 |
| | 1,231 |
| | 1,231 |
| | 13,723 |
| Priest Rapids Development | 2052 | | 0.6 | | | 6 | | 1,831 | | | 1,085 | | | 586 | | | 12,793 | |
Wanapum Development | 2052 | | 0.6 |
| | 7 |
| | 2,050 |
| | 1,231 |
| | 1,231 |
| | 13,723 |
| Wanapum Development | 2052 | | 0.6 | | | 7 | | 1,831 | | | 1,085 | | | 586 | | | 12,793 | |
Total | | | | 745 |
| | $ | 73,037 |
| | $ | 23,058 |
| | $ | 11,743 |
| | $ | 200,907 |
| 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. |
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, contracts with non-utilities and short term electric supply contracts.wholesale market transactions. These contracts have varying terms and may include escalation and termination provisions.
| | (Dollars in Thousands) | 2018 |
| | 2019 |
| | 2020 |
| | 2021 |
| | 2022 |
| | Thereafter |
| | Total |
| (Dollars in Thousands) | 2020 | | 2021 | | 2022 | | 2023 | | 2024 | | Thereafter | | Total |
Columbia River projects | $ | 82,200 |
| | $ | 97,890 |
| | $ | 95,704 |
| | $ | 91,862 |
| | $ | 91,018 |
| | $ | 708,499 |
| | $ | 1,167,173 |
| Columbia River projects | $ | 121,680 | | | $ | 111,125 | | | $ | 103,879 | | | $ | 103,377 | | | $ | 102,976 | | | $ | 609,912 | | | $ | 1,152,949 | |
Other utilities | 1,257 |
| | 888 |
| | — |
| | — |
| | — |
| | — |
| | 2,145 |
| |
Non-utility contracts | 206,233 |
| | 233,776 |
| | 238,016 |
| | 244,962 |
| | 244,906 |
| | 1,128,466 |
| | 2,296,359 |
| |
Short-term electric supply contracts | 70,786 |
|
| 140 |
| | — |
|
| — |
|
| — |
|
| — |
| | 70,926 |
| |
| 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 | $ | 360,476 |
| | $ | 332,694 |
| | $ | 333,720 |
| | $ | 336,824 |
| | $ | 335,924 |
| | $ | 1,836,965 |
| | $ | 3,536,603 |
| 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 14.512.5 million, 13.014.1 million and 11.214.5 million MWhs of firm energy at a cost of approximately $456.4$550.6 million, $402.5$508.2 million and $373.8$456.4 million for the years 2019, 2018, and 2017, 2016 and 2015, 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 1 year to 2725 years, provide that the Company must pay a fixed demand charge each month, regardless of actual usage. The Company incurred demand charges for 20172019 for firm transportation, storage and peaking services for its natural gas customers of $121.4$125.1 million. The Company incurred demand charges in 20172019 for firm transportation and storage services for the natural gas supply for its combustion turbines in the amount of $41.8$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) | 2018 |
| | 2019 |
| | 2020 |
| | 2021 |
| | 2022 |
| | Thereafter |
| | Total |
|
Natural gas supply | $ | 245,669 |
| | $ | 193,458 |
| | $ | 163,818 |
| | $ | 145,662 |
| | $ | 109,401 |
| | $ | — |
| | $ | 858,008 |
|
Firm transportation service | 154,170 |
| | 154,204 |
| | 141,962 |
| | 126,319 |
| | 125,335 |
| | 310,428 |
| | 1,012,418 |
|
Firm storage service | 8,328 |
| | 8,899 |
| | 7,908 |
| | 3,108 |
| | 1,619 |
| | 857 |
| | 30,719 |
|
Short-term natural gas supply contracts | 55,774 |
|
| 13,818 |
| | 1,651 |
|
| — |
|
| — |
|
| — |
| | 71,243 |
|
Total | $ | 463,941 |
| | $ | 370,379 |
| | $ | 315,339 |
| | $ | 275,089 |
| | $ | 236,355 |
| | $ | 311,285 |
| | $ | 1,972,388 |
|
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) | 2018 |
| | 2019 |
| | 2020 |
| | 2021 |
| | 2022 |
| | Thereafter |
| | Total |
|
Energy production service contracts | $ | 28,674 |
| | $ | 27,939 |
| | $ | 28,639 |
| | $ | 29,415 |
| | $ | 30,142 |
| | $ | 165,689 |
| | $ | 310,498 |
|
Automated meter reading system | 48,245 |
| | 44,842 |
| | 43,951 |
| | 44,497 |
| | 45,168 |
| | 187,698 |
| | 414,401 |
|
Total | $ | 76,919 |
| | $ | 72,781 |
| | $ | 72,590 |
| | $ | 73,912 |
| | $ | 75,310 |
| | $ | 353,387 |
| | $ | 724,899 |
|
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 prior to its acquisition by Kaiser Permanente, and as a result, PSE paid Group Health a total of $3.9 million, $23.3 million and $20.3 million for medical coverage foridentified no material related party transactions during the year ended December 31, 2017, 20162019 and 2015. Kaiser Permanente is not considered a related party to PSE.December 31, 2018.
Kimberly Harris, the President and Chief Executive Officer and a director of Puget Energy and PSE, is married to Kyle Branum, who as of January 2017 is a partner at Summit Law Group, which provides legal services to PSE. In 2017 Summit Law Group was paid $0.8 million for legal services provided to PSE and Mr. Branum was among the lawyers at Summit Law Group
who provided such legal services. This work was performed under the supervision of PSE's General Counsel. Through 2016, Mr. Branum was a principal at the law firm Riddell Williams P.S., which provided legal services to PSE. In 2016 and 2015, Riddell Williams was paid $1.0 million and $1.8 million, respectively.
(17)(18) Segment Information
Puget Energy and PSE operate one1 reportable 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.
(18)
(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, 2017, 20162019, 2018, and 2015,2017, respectively:
| | Puget Energy | Net unrealized gain (loss) and prior service cost on pension plans | | Net unrealized gain (loss) on energy derivative instruments | | | 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, 2014 | $ | (36,710 | ) | | $ | (333 | ) | | $ | (37,043 | ) | |
Other comprehensive income (loss) before reclassifications | 7,196 |
| | — |
| | 7,196 |
| |
Amounts reclassified from accumulated other comprehensive income (loss), net of tax | 2,248 |
| | 333 |
| | 2,581 |
| |
Net current-period other comprehensive income (loss) | 9,444 |
| | 333 |
| | 9,777 |
| |
Balance at December 31, 2015 | $ | (27,266 | ) | | $ | — |
| | $ | (27,266 | ) | |
Other comprehensive income (loss) before reclassifications | (5,528 | ) | | — |
| | (5,528 | ) | |
Amounts reclassified from accumulated other comprehensive income (loss), net of tax | (918 | ) | | — |
| | (918 | ) | |
Net current-period other comprehensive income (loss) | (6,446 | ) | | — |
| | (6,446 | ) | |
Balance at December 31, 2016 | $ | (33,712 | ) | | $ | — |
| | $ | (33,712 | ) | Balance at December 31, 2016 | $ | (33,712) | | | | | $ | (33,712) | |
Other comprehensive income (loss) before reclassifications | 10,251 |
| | — |
| | 10,251 |
| Other comprehensive income (loss) before reclassifications | 10,251 | | | | | 10,251 | |
Amounts reclassified from accumulated other comprehensive income (loss), net of tax | (821 | ) | | — |
| | (821 | ) | Amounts reclassified from accumulated other comprehensive income (loss), net of tax | (821) | | | | | (821) | |
Net current-period other comprehensive income (loss) | 9,430 |
| | — |
| | 9,430 |
| Net current-period other comprehensive income (loss) | 9,430 | | | | | 9,430 | |
Balance at December 31, 2017 | $ | (24,282 | ) | | $ | — |
| | $ | (24,282 | ) | Balance at December 31, 2017 | $ | (24,282) | | | | | $ | (24,282) | |
Other comprehensive income (loss) before reclassifications | | Other comprehensive income (loss) before reclassifications | (48,870) | | | | | (48,870) | |
Amounts reclassified from accumulated other comprehensive income (loss), net of tax | | 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) | | Net current-period other comprehensive income (loss) | (52,920) | | | | | (52,920) | |
Balance at December 31, 2018 | | Balance at December 31, 2018 | $ | (77,202) | | | | | $ | (77,202) | |
Other comprehensive income (loss) before reclassifications | | Other comprehensive income (loss) before reclassifications | (7,337) | | | | | (7,337) | |
Amounts reclassified from accumulated other comprehensive income (loss), net of tax | | Amounts reclassified from accumulated other comprehensive income (loss), net of tax | 390 | | | | | 390 | |
| Net current-period other comprehensive income (loss) | | Net current-period other comprehensive income (loss) | (6,947) | | | | | (6,947) | |
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, 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 | ) |
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 | ) |
Details about the reclassifications out of AOCI (loss) for the years ended December 31, 2017, 20162019, 2018, and 2015,2017, 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) | |
| 2017 |
| | 2016 | | 2015 | | 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) | | (675 | ) | | (525 | ) | | (5,397 | ) | Amortization of net gain (loss) | (a) | (2,142) | | | (3,431) | | | (675) | |
| Total before tax | | 1,263 |
| | 1,413 |
| | (3,459 | ) | | Total before tax | $ | (494) | | | $ | (1,494) | | | $ | 1,263 | |
| Tax (expense) or benefit | | (442 | ) | | (495 | ) | | 1,211 |
| | Tax (expense) or benefit | 104 | | | 314 | | | (442) | |
| Net of Tax | | 821 |
| | 918 |
| | (2,248 | ) | | Net of Tax | (390) | | | (1,180) | | | 821 | |
Net unrealized gain (loss) on energy derivative instruments: | | | | | | | |
Commodity contracts: Electric derivatives | Purchased electricity | | — |
| | — |
| | (512 | ) | |
| | Tax (expense) or benefit | | — |
| | — |
| | 179 |
| |
| Net of Tax | | — |
| | — |
| | (333 | ) | |
Total reclassification for the period | Net of Tax | | $ | 821 |
| | $ | 918 |
| | $ | (2,581 | ) | 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," to the consolidated financial statements included in item 8 of this report 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) |
| 2017 |
| | 2016 | | 2015 |
Net unrealized gain (loss) and prior service cost on pension plans: | | | | | | | |
Amortization of prior service cost | (a) | | $ | 1,529 |
| | $ | 1,529 |
| | $ | 1,526 |
|
Amortization of net gain (loss) | (a) | | (13,972 | ) | | (15,955 | ) | | (22,268 | ) |
| Total before tax | | (12,443 | ) | | (14,426 | ) | | (20,742 | ) |
| Tax (expense) or benefit | | 4,355 |
| | 5,049 |
| | 7,260 |
|
| Net of tax | | (8,088 | ) | | (9,377 | ) | | (13,482 | ) |
Net unrealized gain (loss) on energy derivative instruments: | | | | | | | |
Commodity contracts: Electric derivatives | Purchased electricity | | — |
| | — |
| | (1,055 | ) |
| Tax (expense) or benefit | | — |
| | — |
| | 369 |
|
| Net of Tax | | — |
| | — |
| | (686 | ) |
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 | | $ | (8,405 | ) | | $ | (9,694 | ) | | $ | (14,485 | ) |
_______________
| |
(a)
| These AOCI components are included in the computation of net periodic pension cost, see Note 12, "Retirement Benefits," to the consolidated financial statements included in item 8 of this report 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 | 2017 Quarter |
(Unaudited; Dollars in Thousands) | First |
| | Second |
| | Third |
| | Fourth |
|
Operating revenue | $ | 1,077,232 |
| | $ | 719,767 |
| | $ | 660,377 |
| | $ | 1,002,900 |
|
Operating income | 271,727 |
| | 130,030 |
| | 99,044 |
| | 259,696 |
|
Net income (loss) | 127,550 |
| | 35,275 |
| | 12,836 |
| | (467 | ) |
| | | | | | | | | | | | | | | | | | | | | | | |
| 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 | |
|
| | | | | | | | | | | | | | | |
| 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 |
|
|
| | | | | | | | | | | | | | | |
Puget Sound Energy | 2017 Quarter |
(Unaudited; Dollars in Thousands) | First |
| | Second |
| | Third |
| | Fourth |
|
Operating revenue | $ | 1,077,232 |
| | $ | 719,767 |
| | $ | 660,377 |
| | $ | 1,002,900 |
|
Operating income | 268,431 |
| | 126,800 |
| | 96,369 |
| | 257,009 |
|
Net income (loss) | 143,092 |
| | 50,654 |
| | 29,100 |
| | 97,208 |
|
|
| | | | | | | | | | | | | | | |
| 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 |
|
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, |
| 2017 | | 2016 | | 2015 |
Non-utility expense and other | $ | (1,466 | ) | | $ | (5,252 | ) | | $ | (1,617 | ) |
Other income (deductions): | |
| | |
| | |
|
Equity in earnings of subsidiary | 323,568 |
| | 385,838 |
| | 309,603 |
|
Non-hedged interest rate swap expense | 28 |
| | (1,062 | ) | | (3,796 | ) |
Interest income | 1,039 |
| | 2 |
| | 63 |
|
Interest expense | (106,072 | ) | | (104,600 | ) | | (100,114 | ) |
Income taxes | (41,903 | ) | | 37,973 |
| | 37,040 |
|
Net income (loss) | 175,194 |
| | 312,899 |
| | 241,179 |
|
Comprehensive income (loss) | $ | 184,624 |
| | $ | 306,453 |
| | $ | 250,956 |
|
See accompanying notes to the condensed financial statements.
Puget Energy
Condensed Balance Sheets
(Dollars in Thousands)
| | | December 31, | | December 31, | |
| 2017 | | 2016 | | 2019 | | 2018 |
Assets: | | | | Assets: | | | |
Investment in subsidiaries | $ | 3,721,553 |
| | $ | 3,571,550 |
| 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 | 751 |
| | 397 |
| Cash | 947 | | 2,067 |
Receivables from affiliates1 | 78,570 |
| | 213 |
| Receivables from affiliates1 | 180,527 | | 138,714 |
Total current assets | 79,321 |
| | 610 |
| Total current assets | 181,474 | | | 140,781 |
Long-term assets: | |
| | |
| Long-term assets: | | | |
Deferred income taxes | 208,889 |
| | 309,812 |
| Deferred income taxes | 235,428 | | 221,660 |
Other | 3,196 |
| | 521 |
| Other | 2,056 | | 2,040 |
Total long-term assets | 212,085 |
| | 310,333 |
| Total long-term assets | 237,484 | | 223,700 |
Total assets | $ | 5,669,472 |
| | $ | 5,539,006 |
| Total assets | $ | 6,229,089 | | | $ | 5,841,341 | |
Capitalization and liabilities: | |
| | |
| Capitalization and liabilities: | | | |
Common equity | $ | 3,750,030 |
| | $ | 3,688,713 |
| Common equity | $ | 4,000,299 | | | $ | 3,860,728 | |
Long-term debt | 1,892,672 |
| | 1,808,828 |
| Long-term debt | 1,752,644 | | | 1,954,205 |
Total capitalization | 5,642,702 |
| | 5,497,541 |
| Total capitalization | 5,752,943 | | | 5,814,933 | |
Current liabilities: | |
| | |
| Current liabilities: | | | |
Account Payable | 1,042 |
| | 15,801 |
| Account Payable | 208 | | 260 |
Current maturities of long-term debt | | Current maturities of long-term debt | 450,000 | | — |
Interest | 25,728 |
| | 25,523 |
| Interest | 25,938 | | 26,148 |
Unrealized loss on derivative instruments | — |
| | 141 |
| |
Total current liabilities | 26,770 |
| | 41,465 |
| Total current liabilities | 476,146 | | | 26,408 | |
Long-term liabilities: | |
| | |
| |
Total long-term liabilities | — |
| | — |
| |
Commitments and contingencies (Note 3) | | | | |
Commitments and contingencies (Note 16) | | Commitments and contingencies (Note 16) | | | |
Total capitalization and liabilities | $ | 5,669,472 |
| | $ | 5,539,006 |
| 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, |
| 2017 | | 2016 | | 2015 |
Operating activities: | | | | | |
Net cash provided by (used in) operating activities | 139,005 |
| | $ | 145,719 |
| | $ | 171,576 |
|
Investing activities: | |
| | |
| | |
|
Investment in subsidiaries | (24,222 | ) | | — |
| | (28,900 | ) |
(Increase) decrease in loan to subsidiary | (78,155 | ) | | — |
| | 28,933 |
|
Other | (437 | ) | | (6,078 | ) | | (5,632 | ) |
Net cash provided by (used in) investing activities | (102,814 | ) | | (6,078 | ) | | (5,599 | ) |
Financing activities: | |
| | |
| | |
|
Dividends paid | (123,307 | ) | | (148,965 | ) | | (263,059 | ) |
Issuance of bond | — |
| | — |
| | 400,000 |
|
Issuance/redemption of term-loan and other long-term debt | 90,120 |
| | 12,480 |
| | (299,000 | ) |
Issue costs and others | (2,650 | ) | | (3,398 | ) | | (3,341 | ) |
Net cash provided by (used in) by financing activities | (35,837 | ) | | (139,883 | ) | | (165,400 | ) |
Increase (decrease) in cash | 354 |
| | (242 | ) | | 577 |
|
Cash at beginning of year | 397 |
| | 639 |
| | 62 |
|
Cash at end of year | $ | 751 |
| | $ | 397 |
| | $ | 639 |
|
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 $320.1$292.9 million, $380.6$317.2 million and $304.2$320.1 million for the years ended December 31, 2017, 20162019, 2018, and 2015,2017, respectively, and business combination accounting adjustments under ASC 805 recorded at Puget Energy for PSE of $3.9$2.9 million, $5.2$4.7 million and $5.4$3.9 million for the years ended December 31, 2017, 20162019, 2018, and 2015,2017, respectively. Investment in subsidiaries includes Puget Energy business combination accounting adjustments under ASC 805 that are recorded 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, 2017 | | | | | | | |
Accounts deducted from assets on balance sheet: | | | | | | | |
Allowance for doubtful accounts receivable | $ | 9,798 |
| | $ | 26,266 |
| | $ | 27,163 |
| | $ | 8,901 |
|
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 |
|
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, 20172019, 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 quarter ended December 31, 20172019, 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, 2017.2019.
Puget Energy’s effectiveness of internal control over financial reporting as of December 31, 20172019, 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, 2017,2019, 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 quarter ended December 31, 20172019, 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 new/updated systems were used in preparing financial information for the year ended December 31, 2017. 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 were being conducted to enable management to evaluate the design and effectiveness of internal controls during 2017.
During 2017, PSE implemented internal controls covering the evaluation and assessment of revenue contracts related to the adoption of the new revenue recognition standard as of January 1, 2018. PSE does not anticipate significant changes to internal controls over financial reporting as a result of the adoption of this new standard.
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, 2017.2019
PSE’s effectiveness of internal control over financial reporting as of December 31, 20172019, 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
Departure of Directors and Certain Officers; Appointment of Certain Officers; Compensatory Arrangements of Certain OfficersNone.
Effective February 28, 2018, the sole shareholders of Puget Sound Energy and PSE (together, the Companies") appointed and elected Christopher Hind to the Boards of Directors of the Companies (the "Boards"). Mr. Hind was appointed to replace David MacMillan, who resigned from the Boards effective January 18, 2018. Initially, Mr. Hind will not be appointed to any committees of the Board.
Mr. Hind is currently the Senior Principal, Private Infrastructure with Canada Pension Plan Investment Board ("CPPIB"), which position he has held since January 2016. Prior to that, Mr. Hind served as a Managing Director, Investment Banking, at CIBC from October 1997 to January 2016. Mr. Hind also currently serves on the board of directors of Transportadora de Gas del Peru S.A., the largest transporter of natural gas and natural gas liquids in Peru.
Mr. Hind was selected by CPPIB and pursuant to the Amended 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, but will be reimbursed for out-of-pocket expenses.
PART III
ITEM 10. DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE
Board of Directors
As of March 1, 2018, elevenFebruary 21, 2020, twelve directors constitute Puget Energy’s Board of Directors and twelvethirteen 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 58,60, has been a director on the boards of PSE since June 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.
Andrew ChapmanKenton Bradbury, age 62,50, has been a director on the boards of both Puget Energy and PSE since February 2009. Mr. Chapmaneffective April 17, 2019. He is currently the Vice PresidentManaging Director of MacquarieOMERS Infrastructure and Real AssetsManagement Inc., a division of the Macquarie Group, which position he has held since 2006.2015. Prior to joiningthat, Mr. Bradbury served as a director of Infracapital, the Macquarie Group, Mr. Chapman wasinfrastructure investment arm of M&G Investments, and served as Senior Vice President – Strategy &of Infrastructure and Regulation at E.ON in Germany. Mr. Bradbury will not receive any director compensation from the Companies for American Water from 2005 to 2006 and Regional Managinghis service as an Owner Director from 2003 to 2004. Mr. Chapman also servedon the Boards, but will be reimbursed for out-of-pocket expenses.
Richard 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. Chapman representsDinneny will not receive any director compensation from the Company’s Macquarie affiliated investorsCompanies 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.
Barbara Gordon, age 59,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.Humanity, a non-profit organization (2016-2018). Prior to that time, Ms. Gordon previously served as Executive Vice President and Chief Customer Officer of Bellevue-based Apptio, a developer of technology business management software (2016-2017). Prior to that time, Ms. Gordon served as, 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.
Kimberly HarrisChristopher Hind, age 53, is50, 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, and serves as chair of the American Gas Association.
Christopher Hind, age 48, has been elected a director on the boards of both Puget Energy and PSE effective February 28, 2018. He is currently the Senior Principal, Private Infrastructure with Canada Pension Plan Investment Board ("CPPIB")(CPPIB), an investment management organization, which position he has held since January 2016. Prior to that, Mr. Hind served as a Managing Director, Investment Banking, at CIBC, a financial institution, from October 1997 to January 2016. Mr. Hind also currently serves on the board of directors of Transportadora de Gas del Peru S.A., the largest transporter of natural gas and natural gas liquids in Peru. Mr. Hind was selected by CPPIB and pursuant to the Amended 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, but will be reimbursed for out-of-pocket expenses.
Steven W. Hooper, age 64, is66, has been 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., 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 39,58, 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 53,52, has been a director on the boards of both Puget Energy and PSE effective January 3, 2020. Ms. Kipp has also been elected President and Chief Executive officer since February 2009, as a representativeJanuary 3, 2020, and was President of the Company’s Macquarie affiliated investors consistent with the Puget Energy and PSE bylaws. Mr. Leslie is currently an Executive Director of Macquarie Group Limited, which position he has held since 2005,from August 2019 to December 2019. Prior to that time Ms. Kipp served as President, of Macquarie Infrastructure and Real Assets Inc., and since 2006 Chief Executive Officer and Director of Macquarie Infrastructure Partners Inc. Mr. LeslieEl Paso Electric Company (El Paso) from May 2017 to August 2019. Prior to that she served as Chief Executive Officer and director of El Paso from December 2015 to May 2017, and President of El Paso from 2014 to 2015. Ms. Kipp also servesserved as a director on the board of Cleco Power, LLC. In additionSenior Vice President, General Counsel and Chief Compliance Officer at El Paso from 2010 to his management and banking skills, Mr. Leslie provides the Puget Energy and PSE boards the benefit of his experience with electric utilities, gas distribution systems and other aspects of the infrastructure sector.2014.
Paul McMillan,age 63,65, 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 69,71, 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 43, 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 63,65, 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, Karl KuchelPaul McMillan and Paul McMillanTom King are the members of the Audit Committee. The Board has determined that Andrew Chapman and Paul McMillan meetmeets 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.
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 2017,2019, 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 20172019, 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. (FW Cook)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 FW Cook,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, based on the compensation philosophy and taking into consideration information provided by FW Cook.Meridian and other relevant factors.
In 2017,2019, 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 strategy as approved by the Board and aligns executive interests with those of investors and customers. The Committee believes that a significant portion of each executive’s compensation should be “at risk” and earned 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 program 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 | |
|
|
|
|
|
|
|
|
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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|
|
|
|
|
|
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 |
|
|
|
|
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-
terminationpost-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 fixed 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 2017 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 2017 base salaries, target annual incentives and target long-term incentive awards, 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 2016 Energy Services Survey, comprised of utility and other companies similar in size and scope of operations to PSE. The 23 companies in the custom market survey cut used to inform target compensation decisions for 2017 were:
|
| | | | | | | | | |
Custom Survey Peer Group | | | | | | | | |
1. | AGL Resources | | 9. | | LLG&E and KU Energy | | 17. | | Southwest Gas |
2. | Alliant Energy | | 10. | | MDU Resources Group | | 18. | | Teco Energy |
3. | Ameren | | 11. | | OGE Energy | | 19. | | UGI |
4. | Atmos Energy | | 12. | | Oncor Electric Delivery | | 20. | | UNS Energy |
5. | Avista | | 13. | | Pinnacle West Capital | | 21. | | Vectren |
6. | Black Hills | | 14. | | PNM Resources | | 22. | | WEC Energy Group |
7. | CMS Energy | | 15. | | Portland General Electric | | 23. | | Westar Energy |
8. | CPS Energy | | 16. | | SCANA | | | | |
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 16 companies, all but three of which overlapped with companies included in the market survey data. The 2016 median revenue of the executive compensation peers was $3.4 billion, which was comparable to PSE’s annual revenues of $3.1 billion at the time the peer group was developed. The peer companies included in the Company’s executive compensation benchmarking peer group to inform 2017 compensation decisions are shown below:
|
| | | | | | | | | |
Proxy Peer Group | | | | | | | | |
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 | | | | |
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
differ from those typically found in the market. In addition to the foregoing market data, the Committee generally also received advice from FW Cook in connection with 2017 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 20172019
The Committee reviewed the base salaries of the Named Executive Officers in early 20172019 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, 2017.2019. Base salaries for 20172019 generally remained at the 50th percentile of market among the comparator group. The annual salary for Ms. Harris is unchanged from 2016, given that her current base salary was slightly higher thanaligns with the market 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. Doyle who did not receive an increase and Mr. Secrist whoMs. 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 | | 2016 Base Salary | | 2017 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 | | 511,396 | | 511,396 | | — | Daniel A. Doyle |
| 521,000 | |
| 531,420 | |
| 2 |
Steve R. Secrist | | 388,327 | | 403,861 | | 4 | Steve R. Secrist |
| 445,000 | |
| 462,800 | |
| 4 |
Marla D. Mellies | | 308,755 | | 318,019 | | 3 | Marla D. Mellies |
| 360,000 | |
| 392,400 | |
| 9 |
Philip K. Bussey | | 306,510 | | 312,640 | | 2 | |
20172019 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 2017,2019, 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 20172019 were the same as those in 20162018 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 2017,2019, 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 employee safety measure functions similarly to the nine SQIs in determining the funding of the annual incentive plan. That is, if the safety measure is not achieved, annual incentive funding will be decreased by 10%, in the same way as a missed SQI. The safety performance measure contains three targets which must all be satisfied for the safety measure to be treated as met.The three targets for 20172019 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 2017.
0.49
•All employees complete an online defensive driving training. 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 and SAIDI function similarly to the eight 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.
In 2017,2019, 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. The safety measure and eight out of nine SQIAll customer service measures were met for 2017. For2019, but the one SQIsafety measure below the WUTCwas not met, and EBITDA finished at 96.4% of target, System Average Interruption Duration Index (SAIDI)so funding was less than 100%, the Board considered the measure met for incentive purposes based on PSE's performance and recent changes in the measure by the Washington Commission. For 2018 and future years, Company performance on SAIDI will continue to be measured as part of the annual incentive plan, based on performance targets approved by the Board and will function as one of the 10 measures. All 10 customer service and safety measures were met or deemed met.described further below.
Funding levels for 2017 at maximum, target, and threshold are shown in the table below: |
| | | | | | | | |
Annual Incentive Performance Payout Scale and Actual Performance |
Performance | 2017 EBITDA (In Millions) | | SQI & Safety* | | Funding Level |
Maximum | $ | 1,733.9 |
| | 10/10 | | 200 | % |
Target | 1,284.4 |
| | 10/10 | | 100 |
|
Threshold | 1,156.0 |
| | 6/10 | | 30 |
|
2017 Actual Performance | $ | 1,318.3 |
| | 10/10 | | 113.2 | % |
_______________
| |
*
| Combined SQI & Safety results of 6/10 or better and minimum EBITDA of $1,156 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, but made no adjustments. 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.
20172019 Corporate Goals
In 2017,2019, 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 20172019 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.
20172019 Annual Incentive Plan Results
AchievementFor 2019, achievement of the corporate goals for 2017under the annual incentive plan was at 102.6%96.4% of target for EBITDA, and deemed fully9/10 measures met for SQI, safety, and safetySAIDI achievement. PSE EBITDA was $1,318.3$1,293.2 million, and SQI, SAIDI and safety achievement was 109 out of 10, leading to a funding level for 20172019 of 113.2%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 2017,2019, individual target incentive levels for the annual incentive plan varied by executive officer as a percentage of 20172019 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 20162018 levels, except for Mr. Doyle'sMs. Kipp who joined the Company in 2019 and whose target whichannual incentive opportunity was increased to 55%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, 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 2017.2019. 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 20172019 achievement of the corporate goals. The Board approved the incentive amounts shown below, which will be paid in March 2018:2020:
| | Name | | Target Incentive (% of Base Salary) | | 2017 Actual Incentive Paid | | 2017 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% | | $ | 1,069,740 |
| | 119 | % | Kimberly J. Harris |
| 100% |
|
| | | $ | 740,000 | |
|
| | 74% | | |
Mary E. Kipp | | Mary E. Kipp | | 90* | | 190,920 | | | 67* | |
Daniel A. Doyle | | 55 | | 286,556 |
| | 56 |
| Daniel A. Doyle | 65 | |
| | | 255,613 | |
|
| 48 |
|
Steve R. Secrist | | 45 | | 205,727 |
| | 51 |
| Steve R. Secrist | 65 | |
| | | 222,607 | |
|
| 48 |
|
Marla D. Mellies | | 45 | | 161,999 |
| | 51 |
| Marla D. Mellies | 65 | |
| | | 226,493 | |
|
| 58 |
|
Philip K. Bussey | | 45 | | 159,259 |
| | 51 |
| |
_____________
* 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.
2017-20192019-2021 Long-Term Incentive Plan Target Awards and Performance Goals
Consistent with prior years, target LTI Plan awards for the 2017-20192019-2021 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 2017-20192019-2021 performance cycle were 265% 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 2016-20182018-2020 performance cycle, except forwith the exception of Ms. Harris. The Board approved an increaseKipp who joined the Company in Ms. Harris’ target award from 220% to 265% to provide a target award that was market competitive.2019. The total number of target LTI Plan units granted to a Named Executive Officer for the 2017-20192019-2021 performance cycle is equal to the applicable percentage of salary (converted to dollars) divided by the per unit value at the beginning of the performance cycle, including for Ms. Kipp, which was $52.37.$81.86. Details of the number of units granted and expected values at target, threshold and maximum performance levels can be found in the “2017“2019 Grants of Plan-Based Awards” table below. Target Total Return is set annually by the Board prior to the grant date, and was set at 9.8% for the 2017-2019 performance cycle. Target ROE remains based on the ROE target in the Board’s approved budget for each year. Prior outstanding LTIPLTI Plan 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 Plan target awards under the Total Return component that could be earned based on three-year performance duringCommittee, also approved Ms. Kipp’s participation in the 2017-2019 performance cycle. Payout percentages will be linearly interpolated ifcycle at a target amount of 110% of 2019 base salary and in the 2018-2020 performance falls between the values shown below: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 began prior to her commencement of employment and are intended to incentivize performance in such performance 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 | | 88.6 |
90% of Target | | 77.1 |
89.1% of Target | | 75.0 |
85% of Target | | 59.0 |
80% of Target | | 39.5 |
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 2016-2018 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 2016-2018 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 | | 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 | | — |
Long-Term Incentive Plan Performance 2015-20172017-2019 Performance Cycle Results and Payouts
The 2015-20172017-2019 performance cycle has now ended. Amounts payable as a result of award vesting are shown in the following table:
•Performance on Total Return in 20172019 was 29.1%-1.2%, which was significantly higherlower than target, reflecting an increaseTotal Return growth in valuation due to market transactions during 2017.2018.
•Performance on the Total Return component for the three-year performance cycle was a compounded annual rate of 14.93%19.9%, above target and at the maximum of the funding scale. The Total Return Component funded at 200% of target units.
•Performance on the ROE component of the grant was an average of 102.2%110.7% of target. The ROE component funded at 160.7% of target for funding at 112.8%units.
| | | | | | | | | | | | | | | | | | | | | | | | | | |
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 |
| 200% |
| 22,770.5/45,541 |
| 22,770.5/36,592.2 | | $ | 6,642,111 | |
Mary E. Kipp | | 110 | | 5,778.2/11,556.3 | | 5,778.2/9,285.5 | | 1,685,478 | |
Daniel A. Doyle |
| 95 |
| 4,638.5/9,277 |
| 4,638.5/7,454.1 | | 1,353,042 | |
Steve R. Secrist |
| 95 |
| 3,663.0/7,326 |
| 3,663.0/5,886.4 | | 1,068,490 | |
Marla D. Mellies |
| 95 |
| 2,884.5/5,769 |
| 2,884.5/4,635.4 | | 841,403 | |
______________
1Target LTI Plan incentive is a percentage of 2017 base salary when the grants were made in 2017 with a unit price of $52.37, except that Ms. Kipp’s target is a percentage of 2019 base salary equal to 50% of target units.LTI % of 220% with a per unit price of $81.86.
|
| | | | | | | | | | |
Name | | Target Incentive (% of Base Salary)1 | | Total Return Component Units Granted/Paid | | ROE Component Units Granted/Paid | | 2015-2017 Actual LTIP Paid2 |
Kimberly J. Harris | | 200% | | 20,211/40,422 | | 20,211/22,798 | | $ | 4,274,305 |
|
Daniel A. Doyle | | 95% | | 5,296/10,592 | | 5,296/5,973.9 | | 1,120,020 |
|
Steve R. Secrist | | 95% | | 3,871.5/7,743 | | 3,871.5/4,367.1 | | 818,760 |
|
Marla D. Mellies | | 95% | | 3,197.5/6,395 | | 3,197.5/3,606.8 | | 676,220 |
|
Philip K. Bussey | | 95% | | 3,174.5/6,349 | | 3,174.5/3,580.8 | | 671,356 |
|
______________
| |
1
| Target LTI Plan incentive is a percentage of 2015 base salary when the grants were made in 2015. |
| |
2
| 2015-2017 actual LTI Plan amount payable is equal to the unit price $67.6122017-2019 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, 2017, 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 (% of Target) | | Payout (% of Target) | | Total Projected Payout (based on performance as of 12/31/2017) |
2016-2018 | | 67% Complete | | 15.3% | | 200% | | 102.2% | | 118.4% | | 159.4% |
2017-2019 | | 33% Complete | | 15.2% | | 200% | | 102.7% | | 115.1% | | 157.6% |
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 “2017“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 “2017“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, 2017.2019.
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 2017.2019. 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. With theAs a result of changes in federal tax law enactedeffective in 2018, the Company will becomeis now subject to IRS section 162(m) limitations on company deductions for. Section 162(m) limits the tax deductibility of compensation paid to certain executive pay. Based on current understanding ofofficers, 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 2017,2019, 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, 20172019, for filing with the SEC.
Compensation and Leadership
Development Committee of
Puget Energy, Inc.
Puget Sound Energy, Inc.
Christopher Trumpy, ChairSteven Zucchet, chair, joined Committee May 1, 2019
Scott Armstrong (served beginning March 1, 2017)
Christopher Leslie
Etienne MiddletonBarbara 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, 20172019, (and for prior years where applicable) with respect to the Named Executive Officers during 2017.2019. 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, 2017.2019. 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 |
Kimberly J. Harris | 2017 | $ | 900,000 |
| $ | 50,940 |
| | | $ | 5,293,105 |
| $ | 1,523,783 |
| $ | 20,338 |
| $ | 7,788,166 |
|
President and Chief | 2016 | $ | 900,000 |
| $ | 269,595 |
| $ | — |
| $ | — |
| $ | 2,615,706 |
| $ | 650,281 |
| $ | 20,338 |
| $ | 4,455,920 |
|
Executive Officer5 | 2015 | 900,000 |
| — |
| — |
| — |
| 2,245,875 |
| 157,077 |
| 25,032 |
| 3,327,984 |
|
Daniel A. Doyle | 2017 | $ | 511,396 |
| | | | $ | 1,406,575 |
| $ | 483,109 |
| $ | 56,801 |
| $ | 2,457,881 |
|
Senior Vice President, | 2016 | $ | 508,322 |
| $ | 18,299 |
| $ | — |
| $ | — |
| $ | 742,885 |
| $ | 370,670 |
| $ | 49,836 |
| $ | 1,690,012 |
|
Chief Financial Officer6 | 2015 | 493,488 |
| — |
| — |
| — |
| 609,770 |
| 360,012 |
| 51,487 |
| 1,514,757 |
|
Steve R. Secrist | 2017 | $ | 400,690 |
| | | | $ | 1,024,487 |
| $ | 576,802 |
| $ | 46,033 |
| $ | 2,048,012 |
|
Senior Vice President, | 2016 | $ | 383,085 |
| $ | 50,510 |
| $ | — |
| $ | — |
| $ | 549,678 |
| $ | 268,972 |
| $ | 41,344 |
| $ | 1,293,589 |
|
General Counsel, Chief Ethics & Compliance Officer7 | 2015 | 360,721 |
| — |
| — |
| — |
| 297,862 |
| 95,399 |
| 23,861 |
| 777,843 |
|
Marla D. Mellies | 2017 | $ | 316,128 |
| | | | $ | 838,219 |
| $ | 478,905 |
| $ | 34,531 |
| $ | 1,667,783 |
|
Senior Vice President, | 2016 | $ | 306,901 |
| $ | 20,588 |
| $ | — |
| $ | — |
| $ | 447,014 |
| $ | 279,975 |
| $ | 30,414 |
| $ | 1,084,892 |
|
Chief Administrative Officer8 | 2015 | 297,651 |
| — |
| — |
| — |
| 387,201 |
| 143,686 |
| 30,941 |
| 859,479 |
|
Philip K. Bussey | 2017 | $ | 311,388 |
| | | | $ | 830,615 |
| $ | 465,653 |
| $ | 26,989 |
| $ | 1,634,645 |
|
Senior Vice President, Chief Customer Officer9 | 2016 | $ | 304,668 |
| $ | 12,186 |
| $ | — |
| $ | — |
| $ | 448,226 |
| $ | 305,837 |
| $ | 25,503 |
| $ | 1,096,420 |
|
| 2015 | 296,367 |
| — |
| — |
| — |
| 378,286 |
| 408,937 |
| 23,792 |
| 1,107,382 |
|
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
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 | 2019 | $ | 989,799 | | $ | — | | $ | — | | $ | — | | $ | 7,382,111 | | $ | 3,373,594 | | $ | 28,864 | | $ | 11,774,368 | |
President and Chief | 2018 | 939,823 | | 45,220 | | — | — | 6,593,310 | | 445,343 | | 20,888 | | 8,044,584 | |
Executive Officer5 | 2017 | 900,001 | | 50,940 | | — | — | 5,293,105 | | 1,523,783 | | 20,338 | | 7,788,167 | |
Mary E. Kipp, President6 | 2019 | 252,540 | | — | | — | — | 1,876,398 | | — | | 813,893 | | 2,942,831 | |
Daniel A. Doyle | 2019 | 521,399 | | — | | — | — | 1,608,655 | | 964,614 | | 63,555 | | 3,158,223 | |
Senior Vice President | 2018 | 519,039 | | — | | — | — | 1,718,288 | | 489,180 | | 60,657 | | 2,787,164 | |
Chief Financial Officer7 | 2017 | 511,396 | | — | | — | — | 1,406,575 | | 483,109 | | 56,801 | | 2,457,881 | |
Steve R. Secrist | 2019 | 459,165 | | — | | — | — | 1,291,097 | | 786,634 | | 53,517 | | 2,590,413 | |
Senior Vice President | 2018 | 436,600 | | — | | — | — | 1,335,367 | | 273,059 | | 46,850 | | 2,091,876 | |
General Counsel, Chief Ethics & Compliance Officer8 | 2017 | 400,690 | | — | | — | — | 1,024,487 | | 576,802 | | 46,033 | | 2,048,012 | |
Marla D. Mellies | 2019 | 382,671 | | 37,749 | | — | — | 1,030,148 | | 866,607 | | 44,728 | | 2,361,903 | |
Senior Vice President | 2018 | 351,428 | | 33,415 | — | — | 1,065,467 | | 378,398 | | 38,778 | | 1,867,486 | |
Chief Administrative Officer9 | 2017 | 316,128 | | — | | — | — | 838,219 | | 478,905 | | 34,531 | | 1,667,783 | |
_______________
| |
1
| For 2017, reflects individual performance above target as described in the "Compensation Discussion and Analysis," section titled "2017 Annual Incentive Plan Results" in the amount of: Ms. Harris, $50,940. For 2016, also included additional incentive paid based on review of 2015 results for SQIs 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 in the amount of: Ms. Harris, $183,600; Mr. Secrist, $35,648; Ms. Mellies, $7,085. |
| |
2
| For 2017, reflects annual cash incentive compensation paid under the 2017 Goals and Incentive Plan and cash incentive compensation paid under the LTI Plan for the 2015-2017 performance cycle. Cash incentive amounts were paid in early 2018 or deferred at the executive's election. The 2017 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 2018. |
| |
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 2017, updated interest rates and mortality assumptions have generally increased the actuarial value of the underlying retirement benefits relative to assumptions for 2016. Information regarding these pension plans is set forth in further detail under “2017 Pension Benefits.” The change in pension value amounts for 2017 are: Ms. Harris, $1,520,618; Mr. Doyle, $483,109; Mr. Secrist, $576,802, Ms. Mellies, $478,462; and Mr. Bussey, $465,653. Also included in this column are the portions of Deferred Compensation Plan earnings that are considered above market. These amounts for 2017 are: Ms. Harris, $3,165; Mr. Doyle, $0; Mr. Secrist, $0; Ms. Mellies, $443; and Mr. Bussey, $0. See the “2017 Nonqualified Deferred Compensation” table for all Deferred Compensation Plan earnings. |
| |
4
| All Other Compensation for 2017 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 and retired effective January 8, 2018. |
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 |
| | 48,516 |
| | 5,785 |
| Daniel A. Doyle |
| | 2,500 |
|
| | 53,851 |
|
| | 7,204 | |
Steve R. Secrist | | 1,300 |
| | 40,416 |
| | 4,317 |
| Steve R. Secrist |
| | 1,370 |
|
| | 46,822 |
|
| | 5,325 | |
Marla D. Mellies | | 1,263 |
| | 29,981 |
| | 3,287 |
| Marla D. Mellies |
| | 493 |
|
| | 39,097 |
|
| | 5,138 | |
Philip K. Bussey | | 1,440 |
| | 18,850 |
| | 6,699 |
| |
_______________
| |
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 2017 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, $18,850; Mr. Secrist $18,850 ; Ms. Mellies, $18,850; and Mr. Bussey, $18,850 Company contributions to the Deferred Compensation Plan are as follows: Ms. Harris, $0; Mr. Doyle, $29,666; Mr. Secrist, $21,566; Ms. Mellies, $11,131; 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.
20172.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 20172019 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 | | 1/1/2017 | | | | $ | 270,000 |
| | $ | 900,000 |
| | $ | 1,800,000 |
| Annual Incentive1 |
| 1/1/2019 |
| |
| $ | 300,000 | |
| $ | 1,000,000 | |
| $ | 2,000,000 | |
LTI Plan 2017-20192 | | 3/2/2017 | | 45,451 |
| | 590,120 |
| | 3,156,902 |
| | 6,614,375 |
| |
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 | | 1/1/2017 | | | | $ | 84,380 |
| | $ | 281,268 |
| | $ | 562,536 |
| Annual Incentive1 |
| 1/1/2019 |
| |
| $ | 103,627 | |
| $ | 345,423 | |
| $ | 690,846 | |
LTI Plan 2017-20192 | | 3/2/2017 | | 9,277 |
| | 120,211 |
| | 643,082 |
| | 1,347,391 |
| |
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 | | 1/1/2017 | | | | $ | 54,521 |
| | $ | 181,737 |
| | $ | 363,475 |
| Annual Incentive1 |
| 1/1/2019 |
|
| |
| $ | 90,246 | | | $ | 300,820 | |
| $ | 601,640 | |
LTI Plan 2017-20192 | | 3/2/2017 | | 7,326 |
| | 94,930 |
| | 507,838 |
| | 1,064,028 |
| |
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 | | 1/1/2017 | | | | $ | 42,933 |
| | $ | 143,109 |
| | $ | 286,217 |
| Annual Incentive1 |
| 1/1/2019 |
|
| |
| $ | 76,518 | |
| $ | 255,060 | | | $ | 510,120 | |
LTI Plan 2017-20192 | | 3/2/2017 | | 5,769 |
| | 74,755 |
| | 399,907 |
| | 837,890 |
| |
Philip K. Bussey | | | | | | | | | | | |
Annual Incentive1 | | 1/1/2017 | | | | $ | 41,379 |
| | $ | 137,930 |
| | $ | 275,859 |
| |
LTI Plan 2017-20192 | | 3/2/2017 | | 5,671 |
| | 73,485 |
| | 393,114 |
| | 823,656 |
| |
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 2017 Goals and Incentive Plan had dual funding triggers in 2017 of $1,156 million EBITDA and SQI performance of 6/10. Payment would be $0 if either trigger is not met. The threshold estimate assumes $1,156 million EBITDA and SQI/Safety measure performance at 6/10. The target estimate assumes $1,284.4 million EBITDA and SQI/Safety measure performance at 10/10. The maximum estimate assumes $1,733.9 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 2017-2019 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.
2017
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 | | 18.7 |
| | $ | 469,525 |
| | $ | — |
| 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 | | 18.7 |
| | 9,449,499 |
| | — |
|
| Restoration Plan |
| 0.3 |
|
| | — |
|
| — | |
|
Daniel A. Doyle | | Retirement Plan | | 6.1 |
| | 183,734 |
| | — |
| Daniel A. Doyle |
| Retirement Plan |
| 8.1 |
|
| | 269,865 |
|
| — | |
|
| | SERP | | 6.1 |
| | 1,766,273 |
| | — |
|
| SERP |
| 8.1 |
|
| | 3,133,936 |
|
| — | |
|
Steve R. Secrist | | Retirement Plan | | 28.6 |
| | 547,704 |
| | — |
| Steve R. Secrist |
| Retirement Plan |
| 30.6 |
|
| | 672,138 |
|
| — | |
|
| | SERP | | 28.6 |
| | 2,700,486 |
| | — |
|
| SERP |
| 30.6 |
|
| | 3,635,745 |
|
| — | |
|
Marla D. Mellies | | Retirement Plan | | 12.2 |
| | 340,322 |
| | — |
| Marla D. Mellies |
| Retirement Plan |
| 14.2 |
|
| | 436,224 |
|
| — | |
|
| | SERP | | 12.2 |
| | 1,940,490 |
| | — |
|
| SERP |
| 14.2 |
|
| | 3,088,940 |
|
| — | |
|
Philip K. Bussey | | Retirement Plan | | 11.3 |
| | 375,495 |
| | — |
| |
| | SERP | | 11.3 |
| | 2,038,638 |
| | — |
| |
_______________
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, 2017 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 4.00%, and the post-retirement mortality assumption is based on the 2018 417(e) unisex mortality table. Annuity benefits are converted to lump sum amounts at retirement based on assumed future 417(e) segment rates of 1.75%, 3.76%, and 4.66% (the 24-month average of the underlying rates as of September 2017). These assumptions are consistent with the ones used for the Retirement Plan and the SERP for financial reporting purposes for 2017. 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, 2016 for the benefits earned as of that date using the assumptions used for financial reporting purposes for 2016. These assumptions included assumed cash balance interest credits of 4.0%, a discount assumption of 4.50% and post-retirement mortality assumption based on the 2017 417(e) unisex mortality table. Annuity benefits were converted to lump sum amounts at retirement based on assumed future 417(e) segment rates of 1.52%, 3.80% and 4.79% (the 24-month average of the underlying rates as of September 2016). Other assumptions used to determine the value as of December 31, 2016 were the same as those used for December 31, 2017.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, 2017. Each SERP-eligible Named Executive Officer was vested in his or her SERP benefits as of December 31, 2017. | $ | 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 | | $ | 13,102,472 |
|
Daniel A. Doyle | | 1,954,612 |
|
Steve R. Secrist | | 3,428,163 |
|
Marla D. Mellies | | 2,292,468 |
|
Philip K. Bussey | | 2,058,726 |
|
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 2017,2019, the limit was $270,000.$280,000. For 2018,2020, the limit is $275,000.$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 20172019 and 2018,2020, 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, 2017,2019, 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 “2017“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.
2017
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 20172019 and year-end account balances under the Deferred Compensation Plan.
| | Name | | Executive Contributions in 20171 | | Registrant Contributions in 20172 | | Aggregate Earnings in 20173 | | Aggregate Withdrawals/ Distributions | | Aggregate Balance at December 31, 20174 |
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 | | $ | — |
| | $ | — |
| | $ | 12,727 |
| | $ | — |
| | $ | 324,915 |
| Kimberly J. Harris |
| | $ | — | |
|
| | $ | — | |
|
| | $ | 13,694 | |
|
| | $ | — | |
|
| | $ | 351,927 | |
|
Mary E. Kipp | | Mary E. Kipp | | 64,500 | | | — | | | 870 | | | — | | | 65,370 | | |
Daniel A. Doyle | | 27,866 |
| | 29,666 |
| | 84,406 |
| | — |
| | 940,709 |
| Daniel A. Doyle |
| | 32,101 | |
|
| | 34,301 |
|
| 167,665 | | |
| | — | |
|
| | 1,219,744 | |
|
Steve R. Secrist | | 32,355 |
| | 21,566 |
| | 5,222 |
| | — |
| | 98,893 |
| Steve R. Secrist |
| | 39,762 | | |
| | 27,272 |
|
| | 24,361 | |
|
| | — | |
|
| | 245,900 | |
|
Marla D. Mellies | | 10,706 |
| | 11,131 |
| | 16,833 |
| | — |
| | 168,591 |
| 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 2017. Deferred salary amounts are: Ms. Harris, $0; Mr. Doyle, $27,866; Mr. Secrist, $32,355; Ms. Mellies, $10,706; 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. The amounts are also included in the applicable column of the Summary Compensation Table for 2017. |
| |
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 2017. |
| |
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 2017. |
| |
4
| Of the amounts in this column, the amounts in the table below have also been reported in the Summary Compensation Table for 2017, 2016 and 2015. |
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 2017 | | Reported for 2016 | | Reported for 2015 |
Kimberly J. Harris | | $ | 3,165 |
| | $ | 4,033 |
| | $ | 3,259 |
|
Daniel A. Doyle | | 57,531 |
| | 273,509 |
| | 259,782 |
|
Steve R. Secrist | | 53,922 |
| | 39,223 |
| | — |
|
Marla D. Mellies | | 22,280 |
| | 15,428 |
| | 17,869 |
|
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 20172019 calendar year returns of these tracking funds were:
|
| | | | | | | |
Vanguard Total Bond Market Index |
| 3.57 | %8.73% |
Vanguard 500 Index |
| 21.67 | 31.46 |
Vanguard Money Market Index |
| 0.81 | 2.14 |
Interest Crediting Fund (pre-2012 deferrals) |
| 4.14 | 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 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 2017,2019, 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, 2017.2019. 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 (and awards not assumed or substituted) | | 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 | | 8,846,802 |
| | 8,846,802 |
| | — |
| | 8,846,802 |
| | 8,846,802 |
| 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 | | — |
| | 29,788 |
| | — |
| | 29,788 |
| | 29,788 |
| 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 | | $ | 8,846,802 |
| | $ | 14,276,590 |
| | $ | — |
| | $ | 8,876,590 |
| | $ | 11,876,590 |
| 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 | | 2,175,280 |
| | 2,175,280 |
| | — |
| | 2,175,280 |
| | 2,175,280 |
| 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 | | — |
| | — |
| | — |
| | — |
| | 1,073,932 |
| Supplemental Life Insurance |
| — | | |
| — | | |
| — | | |
| — | | |
| 1,222,266 | |
Total Estimated Incremental Value | | $ | 2,175,280 |
| | $ | 2,175,280 |
| | $ | — |
| | $ | 2,175,280 |
| | $ | 3,249,212 |
| 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 | | 1,629,983 |
| | 1,629,983 |
| | — |
| | 1,629,983 |
| | 1,629,983 |
| 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 | | — |
| | — |
| | — |
| | — |
| | 767,336 |
| Supplemental Life Insurance |
| — | | |
| — | | |
| — | | |
| — | | |
| 1,064,440 | |
Total Estimated Incremental Value | | $ | 1,629,983 |
| | $ | 1,629,983 |
| | $ | — |
| | $ | 1,629,983 |
| | $ | 2,397,319 |
| 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) | | — |
| | 1,383,383 |
| | — |
| | — |
| | — |
| Cash Severance (salary and/or annual incentive) |
| — | | |
| 1,942,380 | |
| — | | |
| — | | |
| — | | |
Long Term Incentive Plan | | 1,319,202 |
| | 1,319,202 |
| | — |
| | 1,319,202 |
| | 1,319,202 |
| Long Term Incentive Plan |
| 1,563,151 | |
| 1,563,151 | |
| — | | |
| 1,563,151 | |
| 1,563,151 | |
SERP (additional years of credited service)1 | | — |
| | 447,342 |
| | — |
| | — |
| | — |
| SERP (additional years of credited service)1 |
| — | | |
| 430,688 | |
| — | | |
| — | | |
| — | | |
Benefits (continuation)2 | | — |
| | 42,756 |
| | — |
| | 42,756 |
| | 42,756 |
| Benefits (continuation)2 |
| — | | |
| 48,853 | |
| — | | |
| 48,853 | |
| 48,853 | |
Supplemental Life Insurance | | — |
| | — |
| | — |
| | — |
| | 604,236 |
| Supplemental Life Insurance |
| — | | |
| — | | |
| — | | |
| 0 | |
| 902,520 | |
Total Estimated Incremental Value | | $ | 1,319,202 |
| | $ | 3,192,683 |
| | $ | — |
| | $ | 1,361,958 |
| | $ | 1,966,194 |
| 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 | | 1,307,720 |
| | 1,307,720 |
| | — |
| | 1,307,720 |
| | 1,307,720 |
| |
SERP (additional years of credited service)1 | | — |
| | — |
| | — |
| | — |
| | — |
| |
Benefits (continuation)2 | | — |
| | — |
| | — |
| | — |
| | — |
| |
Supplemental Life Insurance | | — |
| | — |
| | — |
| | — |
| | 594,016 |
| |
Total Estimated Incremental Value | | $ | 1,307,720 |
|
| $ | 1,307,720 |
|
| $ | — |
|
| $ | 1,307,720 |
|
| $ | 1,901,736 |
| |
_______________
| |
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, 2017. 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 2017,2019, our last completed fiscal year:
•The annual total compensation of our CEO, as reported in the 20172019 Summary Compensation Table, was $7,788,167.$11,774,369.
•The median of the annual total compensation of all our employees (excluding our CEO) was $117,999$125,510.
As a result, for 20172019 the ratio of annual total compensation of our Chief Executive Officer and President, to the median of our annual total compensation of all employees was 66:94:1.
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 20172019 to all individuals, excluding our CEO, who were employed by us on December 31, 2017,2019, which totaled approximately 3,1603,148 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 2017,2019, we calculated annual total compensation for such employee for 20172019 using the same methodology we use for our named executive officers as set forth in the 20172019 Summary Compensation Table in accordance with the requirements of Item 402 (c)(2)(x) of Regulation S-K. Annual total compensation for 20172019 for our median employee included annual salary, annual incentives, and company contributions towards benefits including retirement. Annual total compensation for 20172019 for our CEO consists of the amount reported in the "Total" column of our 20172019 Summary Compensation Table.
Director Compensation for Fiscal Year 20172019
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 20172019 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, Karl Kuchel, 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 20172019 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 Earnings1 | | Total | Name |
| Fees Earned | | Nonqualified Deferred Compensation Earnings1 | | Total |
Scott Armstrong | | $ | — |
| | $ | 146,400 |
| | $ | 146,400 |
| Scott Armstrong |
| $ | 192,500 | |
| $ | — | |
| $ | 192,500 | |
Melanie Dressel2 | | 30,700 |
| | — |
| | 30,700 |
| |
Barbara Gordon | | 18,333 |
| | | | 18,333 |
| Barbara Gordon |
| 170,000 | |
| — | | | 170,000 | |
Steve Hooper | | — |
| | 187,033 |
| | 187,033 |
| Steve Hooper |
| — | |
| 231,400 | |
| 231,400 | |
David MacMillan3 | | 155,200 |
| | — |
| | 155,200 |
| |
Thomas King | | Thomas King |
| 87,000 | |
| — | |
| 87,000 | |
Paul McMillan | | 139,600 |
| | — |
| | 139,600 |
| Paul McMillan |
| 185,000 | |
| — | |
| 185,000 | |
Mary O. McWilliams | | 134,800 |
| | — |
| | 134,800 |
| Mary O. McWilliams |
| 170,000 | |
| — | |
| 170,000 | |
Christopher Trumpy | | 144,400 |
| | — |
| | 144,400 |
| Christopher Trumpy |
| 185,800 | |
| — | |
| 185,800 | |
_______________
| |
1
| Represents earnings accrued on deferred compensation considered to be above market. |
| |
2
| Melanie Dressel’s service as a member of the Board of Directors ended upon her death as of February 19, 2017. |
| |
3
| David MacMillan resigned from his position as a member of the Board of Directors, effective as of January 18, 2018. |
1.Represents earnings accrued on deferred compensation considered to be above market.
Nonemployee
Non-employee Director Compensation Program
The 2017 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 20172019 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 2017, 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 and Scott Armstrong areis the only independent board membersmember to defer any director fees during 2017.2019.
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, 20172019, 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, 2017.2019.
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, 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 (bcIMC), PIP2PX (Pad) Ltd. (PIP2PX) and PIP2GV (Pad) Ltd. (PIP2GV and together with MIP, 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 is 125 West 55th Street, Level 22, New York, NY 10019.
•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 prior to its acquisition by Kaiser Permanente. PSE made no payments to Group Health, as all payments were made after its acquisition by Kaiser Permanente for medical coverage for the year ended December 31, 2017.
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 is a partner at Summit Law Group, which provides legal services to PSE. In 2017, Summit Law Group was paid $0.8$0.7 million for legal services provided to PSE in 2019, and Mr. Branum was among the lawyers at Summit Law Group who provided such legal services. This work was performed under the supervision of PSE's General Counsel.
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), Scott Armstrong (member of the Board of PSE and added to the Board of Puget Energy at the November, 2017, Board Meeting), and Barbara 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 former Board member Melanie Dressel serve (or served) as directors or officers of, or otherwise have/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. 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, 20172019, and 20162018 were as follows:
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| 2019 | | | 2018 | |
(Dollars in Thousands) | Puget Energy | | PSE | | Puget Energy | | PSE | (Dollars in Thousands) | Puget Energy | | PSE | | Puget Energy | | PSE |
Audit fees1 | $ | 2,777 |
| | $ | 2,546 |
| | $ | 2,597 |
| | $ | 2,397 |
| Audit fees1 | $ | 2,630 | | | $ | 2,378 | | | $ | 2,695 | | | $ | 2,495 | |
Audit related fees2 | 22 |
| | 22 |
| | 47 |
| | 47 |
| Audit related fees2 | 114 | | | 114 | | | 204 | | 204 |
Tax fees3 | — |
| | — |
| | — |
| | — |
| Tax fees3 | — | | | — | | | — | | | — |
Other fees4 | 337 |
| | 337 |
| | 383 |
| | 383 |
| Other fees4 | 52 | | | 52 | | | 204 | | 204 |
Total | $ | 3,136 |
| | $ | 2,905 |
| | $ | 3,027 |
| | $ | 2,827 |
| 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 2017 fees are estimated and include an aggregate amount of $1.7 million billed to Puget Energy and $1.6 million to PSE through December 2017. |
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| Consists of work performed in connection with registration statements and other regulatory audits. |
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| Consists of tax consulting and tax return reviews. |
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| 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 20172019 and 2016,2018, 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, 2017, 20162019, 2018, and 2015,2017, 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.
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 Puget Sound Energy’s Registration Statement on Form S-3, filed March 13, 2009, Registration No. 333-157960). |
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| 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.
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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. |
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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. 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. |
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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). |
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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. 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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*** | 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). |
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*** | 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). |
*** | 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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| | 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). |
| | 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). |
| | 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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| | Credit Agreement dated October 25, 2017, among Puget Sound Energy, Inc., as Borrower, Mizuho Bank, Ltd., as Administrative Agent, and the lenders party thereto. (incorporated by reference to Exhibits 10.2 to Puget Sound Energy's Current Report on Form 8-K, filed October 31, 2017, Commission file No. 1-4393). |
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* | 23.1 | | |
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* | 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, 2017,2018, filed on March 1, 2018,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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** | Management contract, compensatory plan or arrangement. |
*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. | |
| 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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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 |
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Date: | March 1, 2018 | | Date: | March 1, 2018 |
Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons onperson son 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. HarrisMary E. Kipp | President and | March 1, 2018February 21, 2020 |
(Kimberly J. Harris)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/ Andrew ChapmanKenton Bradbury | Director |
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(Andrew Chapman)Kenton Bradbury) |
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/s/ Steven W. Hooper | Director |
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(Steven W. Hooper) |
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/s/ Karl KuchelTom King | Director |
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(Karl Kuchel)Tom King) |
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/s/ Christopher J. LeslieRichard Dinneny | Director | |
(Christopher J. Leslie)Richard Dinneny) | | |
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/s/ Barbara Gordon | Director of PSE only | |
(Barbara Gordon) | | |
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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/ Etienne Middleton | Director | |
(Etienne Middleton) | | |
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/s/ Christopher Trumpy | Director |
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(Christopher Trumpy) |
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/s/ Christopher HindMartijn Verwoest | Director | |
(Christopher Hind)Martijn Verwoest) | | |
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/s/ Steven Zucchet | Director |
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(Steven Zucchet) |
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