The accompanying notes are an integral part of these unaudited condensed consolidated financial statements.
The accompanying notes are an integral part of these unaudited condensed consolidated financial statements.
The accompanying notes are an integral part of these unaudited condensed consolidated financial statements.
The accompanying notes are an integral part of these unaudited condensed consolidated financial statements.
The accompanying notes are an integral part of these unaudited condensed consolidated financial statements.
The number of environmental sites and related reserves for which remediation or long-term monitoring, preliminary site work or site assessment is being performed are as follows:
These reserve estimates are subjective in nature as they take into consideration several different remediation options at each specific site. The reliability and precision of these estimates can be affected by several factors, including new information concerning either the level of contamination at the site, the extent of Eversource's, CL&P's, NSTAR Electric's PSNH's, and WMECO'sPSNH's responsibility for remediation or the extent of remediation required, recently enacted laws and regulations or changes in cost estimates due to certain economic factors. It is possible that new information or future developments could require a reassessment of the potential exposure to relatedrequired environmental matters.remediation. As this information becomes available, management will continue to assess the potential exposure and adjust the reserves accordingly.
In the normal course of business, Eversource parent provides credit assurances on behalf of its subsidiaries, including CL&P, NSTAR Electric PSNH and WMECO,PSNH, in the form of guarantees.
Management does not anticipate a material impact to net income or cash flows as a result of these various guarantees and indemnifications.
The following table summarizes Eversource parent's exposure to guarantees and indemnifications of its subsidiaries and affiliates to external parties as of SeptemberJune 30, 2017:2020:
The Yankee Companies have filed complaints against the DOE in the Court of Federal Claims seeking monetary damages resulting from the DOE's failure to accept delivery of, and provide for a permanent facility to store, spent nuclear fuel pursuant to the terms of the 1983 spent fuel and high levelhigh-level waste disposal contracts between the Yankee Companies and the DOE. The court had previously awarded the Yankee Companies damages for PhasePhases I, II and III of litigation resulting from the DOE's failure to meet its contractual obligations. These Phases covered damages incurred in the years 1998 through 2012, and the awarded damages have been received by the Yankee Companies with certain amounts of the damages refunded to their customers.
The following methods and assumptions were used to estimate the fair value of each of the following financial instruments:
See Note 1D, "Summary of Significant Accounting Policies - Fair Value Measurements," for the fair value measurement policy and the fair value hierarchy.
The changes in accumulated other comprehensive income/(loss) by component, net of tax, isare as follows:
Defined benefit plan OCI amounts before reclassifications relate to actuarial gains and losses and prior service costs that arose during the year and were recognized in AOCL.AOCI. The unamortized actuarial gains and losses and prior service costs on the defined benefit plans are amortized from AOCLAOCI into Operations and Maintenance expenseOther Income, Net over the average future employee service period, and are reflected in amounts reclassified from AOCL. For further information, see Note 7, "Pension Benefits and Postretirement Benefits Other Than Pensions."AOCI.
Management's Discussion and Analysis of Financial Condition and Results of Operations
The following discussion and analysis should be read in conjunction with our unaudited condensed consolidated financial statements and related combined notes included in this combined Quarterly Report on Form 10-Q, the combined quarterly reportsQuarterly Report on Form 10-Q for the quartersquarter ended March 31, 2017 and June 30, 2017,2020, as well as the Eversource 20162019 combined Annual Report on Form 10-K. References in this combined Quarterly Report on Form 10-Q to "Eversource," the "Company," "we," "us," and "our" refer to Eversource Energy and its consolidated subsidiaries. All per-share amounts are reported on a diluted basis. The unaudited condensed consolidated financial statements of Eversource, NSTAR Electric and PSNH and the unaudited condensed financial statements of CL&P and WMECO are herein collectively referred to as the "financial statements."
The only common equity securities that are publicly traded are common shares of Eversource. The earnings and EPS of each business discussed below do not represent a direct legal interest in the assets and liabilities of such business but rather represent a direct interest in our assets and liabilities as a whole. EPS by business is a financial measure not recognized under GAAP, calculated by dividing the Net Income Attributable to Common Shareholders of each business by the weighted average diluted Eversource common shares outstanding for the period. Our earnings discussion also includes non-GAAP financial measures referencing our 2020 earnings and EPS excluding certain acquisition costs and our Q2 2019 earnings and EPS excluding the impairment charge for the NPT project.
From time to time, we make statements concerning our expectations, beliefs, plans, objectives, goals, strategies, assumptions of future events, future financial performance or growth and other statements that are not historical facts. These statements are "forward-looking statements" within the meaning of the Private Securities Litigation Reform Act of 1995. You can generally identify our forward-looking statements through the use of words or phrases such as "estimate," "expect," "anticipate," "intend," "plan," "project," "believe," "forecast," "should," "could," and other similar expressions. Forward-looking statements are based on the current expectations, estimates, assumptions or projections of management and are not guarantees of future performance. These expectations, estimates, assumptions or projections may vary materially from actual results. Accordingly, any such statements are qualified in their entirety by reference to, and are accompanied by, the following important factors that could cause our actual results to differ materially from those contained in our forward-looking statements, including, but not limited to:
disruptions in the capital markets or other events that make our access to necessary capital more difficult or costly,
other presently unknown or unforeseen factors.
Other risk factors are detailed in our reports filed with the SEC and updated as necessary, and we encourage you to consult such disclosures.
Financial Condition and Business Analysis
Executive Summary
The following items in this executive summary are explained in more detail in this combined Quarterly Report on Form 10-Q:
Results:Earnings Overview and Future Outlook:
We earned $260.4$252.2 million, or $0.82$0.75 per share, in the thirdsecond quarter of 2017,2020, and $750.6$587.0 million, or $2.36$1.75 per share, in the first nine monthshalf of 2017,2020, compared with $265.3$31.5 million, or $0.83$0.10 per share, in the thirdsecond quarter of 2016,2019, and $713.1$340.1 million, or $2.24$1.07 per share, in the first nine monthshalf of 2016.
2019. Our electric distribution segment, which includes generation, earned $157.42020 results include after-tax acquisition costs related to our planned purchase of the assets of Columbia Gas of Massachusetts (CMA) of $3.9 million, or $0.50$0.01 per share, in the thirdsecond quarter of 2017,2020, and $393.4 million, or $1.24 per share, in the first nine months of 2017, compared with $170.1 million, or $0.53 per share, in the third quarter of 2016, and $381.3 million, or $1.20 per share, in the first nine months of 2016.
Our electric transmission segment earned $99.0 million, or $0.31 per share, in the third quarter of 2017, and $289.6 million, or $0.91 per share, in the first nine months of 2017, compared with $88.4 million, or $0.28 per share, in the third quarter of 2016, and $266.6 million, or $0.84 per share, in the first nine months of 2016.
Our natural gas distribution segment had a net loss of $6.2$7.4 million, or $0.02 per share, in the thirdfirst half of 2020. Our 2019 results include an after-tax impairment charge of $204.4 million, or $0.64 per share, related to our investment in the NPT project. Excluding those acquisition costs in 2020, we earned $256.1 million, or $0.76 per share, in the second quarter of 2017,2020, and earnings of $49.1$594.4 million, or $0.15$1.77 per share, in the first nine monthshalf of 2017,2020. Excluding the NPT impairment charge in 2019, we earned $235.9 million, or $0.74 per share, in the second quarter of 2019, and $544.5 million, or $1.71 per share, in the first half of 2019.
Our electric distribution segment earned $115.0 million, or $0.34 per share, in the second quarter of 2020, and $245.1 million, or $0.73 per share, in the first half of 2020, compared with $105.4 million, or $0.33 per share, in the second quarter of 2019, and $225.4 million, or $0.71 per share, in the first half of 2019. Our natural gas distribution segment earned $3.3 million, or $0.01 per share, in the second quarter of 2020, and $87.8 million, or $0.26 per share, in the first half of 2020, compared with a net loss of $7.0$1.8 million in the second quarter of 2019, and earnings of $74.7 million, or $0.23 per share, in the first half of 2019. Our water distribution segment earned $10.4 million, or $0.03 per share, in the second quarter of 2020, and $12.5 million, or $0.04 per share, in the first half of 2020, compared with $8.0 million, or $0.02 per share, in the thirdsecond quarter of 2016,2019, and earnings of $51.9$8.8 million, or $0.16$0.03 per share, in the first nine monthshalf of 2016. 2019.
Our electric transmission segment earned $129.5 million, or $0.39 per share, in the second quarter of 2020, and $256.2 million, or $0.76 per share, in the first half of 2020, compared with a net loss of $87.4 million, or $0.27 per share, in the second quarter of 2019, and earnings of $30.9 million, or $0.10 per share in the first half of 2019. Excluding the after-tax NPT impairment charge of $204.4 million, or $0.64 per share, our electric transmission segment earned $117.0 million, or $0.37 per share, in the second quarter of 2019, and $235.3 million, or $0.74 per share, in the first half of 2019.
Eversource parent and other companies earned $10.2had net losses of $6.0 million, or $0.02 per share, in the thirdsecond quarter of 20172020, and $18.5$14.6 million, or $0.04 per share, in the first half of 2020, compared with earnings of $7.3 million, or $0.02 per share, in the second quarter of 2019, and $0.3 million in the first nine monthshalf of 2017, compared with $13.82019. Excluding acquisition costs, Eversource parent and other companies had net losses of $2.1 million, or $0.01 per share, in the thirdsecond quarter of 20162020, and $13.3$7.2 million, or $0.02 per share, in the first nine monthshalf of 2016. 2020.
We reaffirm 2020 earnings of between $3.60 per share and $3.70 per share and our long-term EPS growth rate through 2024 from our regulated utility businesses of between 5 to 7 percent.
As of the date of our filing, the outbreak of COVID-19 has not resulted in significant financial or operational impacts. We are continuing to closely monitor the COVID-19 pandemic, and we continue to operate under our pandemic response plan. However, we cannot at this time predict the impacts that the COVID-19 pandemic will have on our future financial condition, results of operations, cash flows, and our business operations.
Liquidity:
Cash flows provided by operating activities totaled $1.49$1.01 billion in the first nine monthshalf of 2017,2020, compared with $1.65 billion$924.6 million in the first nine monthshalf of 2016.2019. Investments in property, plant and equipment totaled $1.64$1.40 billion in the first nine monthshalf of 2017,2020, compared with $1.36$1.38 billion in the first nine monthshalf of 2016.2019. Cash and cash equivalents totaled $125.8$64.9 million as of SeptemberJune 30, 2017,2020, compared with $30.3$15.4 million as of December 31, 2016.2019. Our available borrowing capacity under our commercial paper programs totaled $1.61 billion as of June 30, 2020.
In 2017,the first half of 2020, we issued $2.5 billion11,960,000 common shares, which resulted in proceeds of $929.0 million, net of issuance costs.
In the first half of 2020, we issued $940 million of new long-term debt, consisting of $1.2 billion by Eversource parent, $700$400 million by NSTAR Electric, $525$350 million by CL&P,Eversource parent, and $75$190 million by YankeeNSTAR Gas. Proceeds from these new issuances were used primarily to refinance investments in eligible green expenditures at NSTAR Electric, to pay short-term borrowings at Eversource parent, and redeem long-term debtto refinance existing indebtedness, fund capital expenditures and for general corporate purposes at maturity.NSTAR Gas.
On SeptemberMay 6, 2017,2020, our Board of Trustees approved a common share dividend payment of $0.475$0.5675 per share, which was paid on September 29, 2017June 30, 2020 to shareholders of record as of September 19, 2017.May 20, 2020.
Impact of COVID-19
COVID-19 has adversely affected workers and the economy and caused significant volatility in the financial markets. Due to the inherent uncertainty of the unprecedented and rapidly evolving situation, we continue to closely monitor how COVID-19 related developments affect Eversource. As of the date of our filing and based on available information, we have not experienced, nor are we able to predict, significant impacts directly related to the pandemic that could adversely affect our current or future operations, financial position, results of operations, and cash flows. The extent of the impact to us in the future will vary and depend in large part on the duration, scope and severity of the pandemic, and the resulting impact on economic, health care and capital market conditions.
Operational: We provide a critical service to our customers and have taken extensive measures to maintain its safety and reliability. We have implemented our company-wide pandemic plan, which guides our emergency response, business continuity, and the precautionary measures we are taking to ensure the safety, health, and well-being of our employees, our customers, and our communities. We continue to adjust our company-wide pandemic plan to address various scenarios, including reduced workforce levels and limited mutual aid in the event of a significant storm event, and have implemented protective measures to mitigate the impact of COVID-19 on our workforce. We have implemented work from home policies where appropriate, resulting in nearly half of our employees working remotely. For our employees performing essential functions that are required onsite, such as field crews and system operations, we have taken significant safety measures, including establishing social distancing measures, enabling critical operations to be shifted to different control center locations if necessary, and increasing facility sanitization efforts and promoting both the availability and use of personal protective equipment.
In mid-March, we suspended non-critical work inside customer premises, which included energy audits inside our customers’ homes and businesses. These activities resumed in early July with the implementation of new health and safety guidelines for the restart of energy efficiency services to customers. As of the date of our filing, we do not expect a significant impact on our 2020 energy efficiency program spending and efforts, which assumes the resumption of energy efficiency programs throughout the second half of 2020. Actual energy efficiency spending levels will depend on the extent and duration of the pandemic.
At this time, our workforce staffing levels continue to enable us to safely and reliably deliver our critical services to customers. Through August 5, 2020, a total of 50 employees had contracted COVID-19, and a cumulative total of 772 employees had self-quarantined, of which 751 employees have returned to the workforce. The number of quarantined employees peaked at 215 in April.
We are also preparing for the re-entry of our employees working remotely. Our re-entry plan includes a multi-phase approach that is measured, cautious and gradual. The plan is informed by public health guidance with the safety of our employees and customers as our highest priority. We are in the early phases of our re-entry plan and have returned fewer than 100 remote employees back to the workplace. State and federal guidelines, external conditions, and critical business priorities continue to inform the pace of our re-entry plan. Significant health and safety measures and pandemic protocols, including social distancing requirements, the use of personal protective equipment, sanitization efforts and employee training, are in place for all employees working onsite today and specific plans have been developed for our eventual re-entry to the workplace.
In the states we serve, COVID-19 is currently spreading in a slower manner, as compared to the initial outbreak that began in mid-March, and measures used to control it, such as social distancing and face coverings, are having a positive reduction in its spread. Each of our states has seen a decrease in the infection rate and in the number of positive tests, as well as more capacity in hospitals, and improved testing availability and contact tracing.
Financial: Overall, our future financial position, results of operations, and cash flows could be negatively impacted by COVID-19 as it relates to the valuation of customer receivables, collectibility estimates and customer payment plans, elimination of late payment revenues, lower sales volumes primarily from PSNH's commercial and industrial customers, energy efficiency spending levels and incentives earned, and increased expenses for cleaning and supplies for personal protective equipment. Other potential negative financial impacts relate to market volatility on our equity and debt securities, access to, as well as cost of, capital resources, and the ability of various third-party vendors and suppliers to fulfill their obligations.
Strategic, Legislative, Regulatory, Policy
As of June 30, 2020, our allowance for uncollectible customer receivable balances of $270.0 million, of which $175.5 million relates to hardship accounts that are specifically recovered in rates charged to customers, adequately reflected the collection risk and Other Items:
On October 6, 2017, the FERC issued an order that didnet realizable value for our receivables and has not accept the NETOs June 5, 2017 filing to reinstate the base ROE of 11.14 percent with an associated ROE incentive cap of 13.5 percent. Therefore, the Companybeen materially impacted by COVID-19. We will continue to recognize transmission revenues as billed utilizing a base ROE of 10.57 percent with an incentive cap of 11.74 percent.
On October 12, 2017, PSNH filed an application withevaluate the NHPUC requesting approvaladequacy of the saleuncollectible allowance in future reporting periods based on an ongoing assessment of PSNH's thermalaccounts receivable collections, delinquency statistics, the impact on electric residential customer bills because of higher usage in July driven by warmer than normal weather, COVID-19 developments, including any potential federal legislation, and hydroelectric power generation assetsanalysis of aging-based quantitative assessments. We continue to work closely with our state regulatory commissions and consumer advocates on several customer assistance measures, including more flexible and new payment plan options in New Hampshireorder to private investorsmitigate the impact on customer rates in the future, as well as financial hardship and arrearage management programs for a combined purchase price totaling $258 million.
On October 29, 2017, a storm delivered high winds and rain, causing extensive damagethose customers who are unable to our electric distribution systems across all three states.pay their utility bills. We estimate that more than 800,000 of our electric distributiondeveloped these long-term solutions for customers were without power during or following the storm. Restoration costs cannot be estimated at this time. As a result ofin order to help minimize the extent of the damages, we expectimpact of COVID-19 on customer receivable balances and customers’ affordability in light of the storm restoration costs will be materialcurrent financial impact they may experience. Our operating companies have also eliminated late payment charges at this time.
Beginning in March 2020, Connecticut, Massachusetts and will exceed the criteria to be declared a major storm in Connecticut, New Hampshire established moratoriums on disconnections of residential and commercial customers for non-payment for utility service. In Connecticut, the moratorium on disconnections remains in place for residential customers, but the moratorium for commercial customers ended on August 1, 2020. In Massachusetts, the moratorium remains in place until it is lifted by the governor or state regulatory commission. In New Hampshire, the moratorium for both residential and commercial customers ended on July 15, 2020, however, PSNH has not yet begun to disconnect customers. As of the date of our filing, our operating companies have experienced some lower cash collections from customers because of the moratorium on disconnections and the economic slowdown resulting from the COVID-19 pandemic, primarily at our natural gas distribution businesses driven by the seasonality of their usage patterns. However, overall it is not a significant reduction in customer payments. We believe that we are developing successful mechanisms with our state regulatory commissions that allow, or will allow, us to recover our incremental costs associated with COVID-19, which include uncollectible customer receivable expenses, while balancing the impact on our customers’ bills and our operating cash flows. As such, as of the date of our filing, our reserve for uncollectible accounts has not been materially adversely impacted.
As of June 30, 2020, net incremental costs as a result of COVID-19 that we have deferred totaled $6.6 million, of which $4.1 million was related to uncollectible expense incurred at our natural gas distribution segment. In the second quarter and first half of 2020, respectively, incremental COVID-19 expenses that reduced pre-tax earnings totaled $6.2 million and $7.5 million and related to facilities and fleet cleaning, sanitizing costs and supplies for personal protective equipment. For further information on Connecticut, Massachusetts and New Hampshire COVID-19-related regulatory developments, see "Regulatory Developments and Rate Matters - COVID-19 Regulatory Dockets" included in this Management’s Discussion and Analysis.
An extended economic slowdown could result in lower demand for electricity, natural gas and/or water by our commercial and industrial customers. However, fluctuations in retail sales volumes for CL&P, NSTAR Electric, Yankee Gas, NSTAR Gas and our Connecticut water distribution business are not expected to materially impact earnings due to their respective state regulatory commission-approved distribution revenue decoupling mechanisms. Overall, we believe our risk of exposure to lower demand and resulting lost sales revenues is limited as our regulated utilities, with the exception of PSNH, are under cost-of-service rates with revenue decoupling mechanisms and a result,significant portion of uncollectible expenses are tracked for ultimate recovery. Our revenue decoupling mechanisms replace actual customer usage with a fixed annual revenue stream, and is reconciled each year as part of our annual decoupling filing in each respective jurisdiction.
As of June 30, 2020, we did not identify indicators or triggering events for impairments to our goodwill, long-lived assets, available-for-sale debt securities, or equity method investment carrying values. As of the date of our filing, based on available information and the current market trends, we do not expect an impairment to these assets for the stormremainder of 2020.
We continue to monitor Eversource parent’s and our operating companies’ ability to access the global capital and credit markets. At the onset of the pandemic in the United States, liquidity in the commercial paper credit market began to deteriorate rapidly. However, federal legislative actions, including actions taken by the Federal Reserve, have provided sufficient liquidity and stabilization of the credit markets. An extended economic slowdown could result in Eversource parent and our operating companies finding difficulty in accessing necessary capital resources and incurring higher costs for those capital resources. As of the date of our filing, based on available information and the current market trends, we believe we will continue to have access to needed liquidity and capital resources to successfully execute our projected 2020 capital expenditures and strategies. We expect our existing borrowing availability under our commercial paper programs, our existing revolving credit facilities that serve to backstop those commercial paper programs, in addition to access to the debt and equity markets, will be sufficient to meet our future liquidity and capital resource needs.
In addition, the successful execution of our timeline for developing our offshore wind projects is based on several factors, including state and federal siting and permitting approvals. We are developing mitigation plans to address permitting delays due to COVID-19 restrictions on our offshore wind projects. For further information, see "Business Development and Capital Expenditures - Offshore Wind Business" included in this Management’s Discussion and Analysis.
Pension and PBOP plan assets and obligations are remeasured annually using a December 31st measurement date. Our future pension and PBOP obligations are highly dependent on benefit plan asset returns, interest rates, and discount rates, all of which could be materially impacted by an extended economic slowdown. Should these financial metrics be negatively impacted by COVID-19 as of December 31, 2020, it could result in the underperformance of our pension and PBOP plan investments, an increase in pension and PBOP obligations and employee benefit plan costs, and in a minimum pension funding requirement due by March 31, 2022 for the 2021 Plan year. We continue to monitor federal legislative pension developments that could provide additional pension funding relief.As of the date of our filing, we are unable to determine whether the pandemic will have a material impact onto our resultsfuture pension and PBOP obligations and plan costs and minimum funding requirements. NSTAR Electric and NSTAR Gas recover qualified pension and PBOP expenses through a rate reconciling mechanism that fully tracks the change in net pension and PBOP expenses each year. Our electric transmission companies' rates provide for an annual true-up of operations.estimated to actual costs, which include pension and PBOP expenses.
Earnings Overview
Consolidated: Below is a summary of our earnings by business, which also reconciles the non-GAAP financial measuremeasures of consolidated non-GAAP earnings and EPS, as well as EPS by business, to the most directly comparable GAAP measuremeasures of consolidated Net Income Attributable to Common Shareholders and diluted EPS, for the third quarter and the first nine months of 2017 and 2016. EPS.
|
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | For the Three Months Ended September 30, | | For the Nine Months Ended September 30, |
| | 2017 | | 2016 | | 2017 | | 2016 |
| (Millions of Dollars, Except Per-Share Amounts) | Amount | | Per Share | | Amount | | Per Share | | Amount | | Per Share | | Amount | | Per Share |
Net Income Attributable to Common Shareholders (GAAP) | $ | 260.4 |
| | $ | 0.82 |
| | $ | 265.3 |
| | $ | 0.83 |
| | $ | 750.6 |
| | $ | 2.36 |
| | $ | 713.1 |
| | $ | 2.24 |
|
| Regulated Companies | $ | 250.2 |
| | $ | 0.79 |
| | $ | 251.5 |
| | $ | 0.79 |
| | $ | 732.1 |
| | $ | 2.30 |
| | $ | 699.8 |
| | $ | 2.20 |
|
| Eversource Parent and Other Companies | 10.2 |
| | 0.03 |
| | 13.8 |
| | 0.04 |
| | 18.5 |
| | 0.06 |
| | 13.3 |
| | 0.04 |
|
| Net Income Attributable to Common Shareholders (GAAP) | $ | 260.4 |
| | $ | 0.82 |
| | $ | 265.3 |
|
| $ | 0.83 |
| | $ | 750.6 |
| | $ | 2.36 |
| | $ | 713.1 |
| | $ | 2.24 |
|
|
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | For the Three Months Ended June 30, | | For the Six Months Ended June 30, |
| | 2020 | | 2019 | | 2020 | | 2019 |
| (Millions of Dollars, Except Per Share Amounts) | Amount | | Per Share | | Amount | | Per Share | | Amount | | Per Share | | Amount | | Per Share |
Net Income Attributable to Common Shareholders (GAAP) | $ | 252.2 |
| | $ | 0.75 |
| | $ | 31.5 |
| | $ | 0.10 |
| | $ | 587.0 |
| | $ | 1.75 |
| | $ | 340.1 |
| | $ | 1.07 |
|
| | | | | | | | | | | | | | | | |
| Regulated Companies (non-GAAP) | $ | 258.2 |
| | $ | 0.77 |
| | $ | 228.6 |
| | $ | 0.72 |
| | $ | 601.6 |
| | $ | 1.79 |
| | $ | 544.2 |
| | $ | 1.71 |
|
| Eversource Parent and Other Companies (non-GAAP) | (2.1 | ) | | (0.01 | ) | | 7.3 |
| | 0.02 |
| | (7.2 | ) | | (0.02 | ) | | 0.3 |
| | — |
|
| Non-GAAP Earnings | $ | 256.1 |
| | $ | 0.76 |
| | $ | 235.9 |
| | $ | 0.74 |
| | $ | 594.4 |
| | $ | 1.77 |
| | $ | 544.5 |
| | $ | 1.71 |
|
Acquisition-Related Costs (after-tax) (1) | (3.9 | ) | | (0.01 | ) | | — |
| | — |
| | (7.4 | ) | | (0.02 | ) | | — |
| | — |
|
Impairment of Northern Pass Transmission (after-tax) | — |
| | — |
| | (204.4 | ) | | (0.64 | ) | | — |
| | — |
| | (204.4 | ) | | (0.64 | ) |
Net Income Attributable to Common Shareholders (GAAP) | $ | 252.2 |
| | $ | 0.75 |
| | $ | 31.5 |
|
| $ | 0.10 |
| | $ | 587.0 |
| | $ | 1.75 |
| | $ | 340.1 |
| | $ | 1.07 |
|
(1) These costs are associated with our pending acquisition of the assets of Columbia Gas of Massachusetts.
Regulated Companies: Our Regulatedregulated companies consist ofcomprise the electric distribution, electric transmission, and natural gas distribution segments. Generation activities of PSNH and WMECO are included in our electricwater distribution segment.segments. A summary of our segment earnings and EPS for the third quarter and the first nine months of 2017 and 2016 is as follows:
|
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | For the Three Months Ended September 30, | | For the Nine Months Ended September 30, |
| | 2017 | | 2016 | | 2017 | | 2016 |
| (Millions of Dollars, Except Per-Share Amounts) | Amount | | Per Share | | Amount | | Per Share | | Amount | | Per Share | | Amount | | Per Share |
| Electric Distribution | $ | 157.4 |
| | $ | 0.50 |
| | $ | 170.1 |
| | $ | 0.53 |
| | $ | 393.4 |
| | $ | 1.24 |
| | $ | 381.3 |
| | $ | 1.20 |
|
| Electric Transmission | 99.0 |
| | 0.31 |
| | 88.4 |
| | 0.28 |
| | 289.6 |
| | 0.91 |
| | 266.6 |
| | 0.84 |
|
| Natural Gas Distribution | (6.2 | ) | | (0.02 | ) | | (7.0 | ) | | (0.02 | ) | | 49.1 |
| | 0.15 |
| | 51.9 |
| | 0.16 |
|
| Net Income - Regulated Companies | $ | 250.2 |
| | $ | 0.79 |
| | $ | 251.5 |
| | $ | 0.79 |
| | $ | 732.1 |
| | $ | 2.30 |
| | $ | 699.8 |
| | $ | 2.20 |
|
|
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | For the Three Months Ended June 30, | | For the Six Months Ended June 30, |
| | 2020 | | 2019 | | 2020 | | 2019 |
| (Millions of Dollars, Except Per Share Amounts) | Amount | | Per Share | | Amount | | Per Share | | Amount | | Per Share | | Amount | | Per Share |
| Net Income - Regulated Companies (GAAP) | $ | 258.2 |
| | $ | 0.77 |
| | $ | 24.2 |
| | $ | 0.08 |
| | $ | 601.6 |
| | $ | 1.79 |
| | $ | 339.8 |
| | $ | 1.07 |
|
| | | | | | | | | | | | | | | | |
| Electric Distribution | $ | 115.0 |
| | $ | 0.34 |
| | $ | 105.4 |
| | $ | 0.33 |
| | $ | 245.1 |
| | $ | 0.73 |
| | $ | 225.4 |
| | $ | 0.71 |
|
| Electric Transmission, excluding Northern Pass Transmission impairment (Non-GAAP) | 129.5 |
| | 0.39 |
| | 117.0 |
| | 0.37 |
| | 256.2 |
| | 0.76 |
| | 235.3 |
| | 0.74 |
|
| Natural Gas Distribution | 3.3 |
| | 0.01 |
| | (1.8 | ) | | — |
| | 87.8 |
| | 0.26 |
| | 74.7 |
| | 0.23 |
|
| Water Distribution | 10.4 |
| | 0.03 |
| | 8.0 |
| | 0.02 |
| | 12.5 |
| | 0.04 |
| | 8.8 |
| | 0.03 |
|
| Net Income - Regulated Companies (Non-GAAP) | $ | 258.2 |
| | $ | 0.77 |
| | $ | 228.6 |
| | $ | 0.72 |
| | $ | 601.6 |
| | $ | 1.79 |
| | $ | 544.2 |
| | $ | 1.71 |
|
Impairment of Northern Pass Transmission (after-tax) | — |
| | — |
| | (204.4 | ) | | (0.64 | ) | | — |
| | — |
| | (204.4 | ) | | (0.64 | ) |
| Net Income - Regulated Companies (GAAP) | $ | 258.2 |
| | $ | 0.77 |
| | $ | 24.2 |
| | $ | 0.08 |
| | $ | 601.6 |
| | $ | 1.79 |
| | $ | 339.8 |
| | $ | 1.07 |
|
Our electric distribution segment earnings decreased $12.7 million in the third quarter of 2017, as compared to the third quarter of 2016, due primarily to lower sales volumes and demand revenues driven by the mild summer weather during the third quarter of 2017, primarily at NSTAR Electric, as well as higher property tax, depreciation and interest expense.
Our electric distribution segment earnings increased $12.1$9.6 million in the second quarter of 2020, as compared to the second quarter of 2019, due primarily to base distribution rate increases at PSNH effective July 1, 2019, at CL&P effective May 1, 2020 and May 1, 2019, and at NSTAR Electric effective January 1, 2020, and higher earnings from CL&P's capital tracker mechanism due to increased electric system improvements. The earnings increase was partially offset by higher operations and maintenance expense, higher depreciation expense, and higher interest expense.
Our electric distribution segment earnings increased $19.7 million in the first nine monthshalf of 2017,2020, as compared to the first nine monthshalf of 2016,2019, due primarily to lowerbase distribution rate increases at PSNH effective July 1, 2019, at CL&P effective May 1, 2020 and May 1, 2019, and at NSTAR Electric effective January 1, 2020, and higher earnings from CL&P's capital tracker mechanism due to increased electric system improvements. The earnings increase was partially offset by higher depreciation expense, higher operations and maintenance expense, partially offset by lower sales volumes driven by the mild summer weather during the third quarter of 2017, primarily at NSTAR Electric, higher depreciation and interest expense, and lower generation earnings.the absence of the first quarter 2019 recognition of carrying charges on PSNH's 2013 through 2016 storm costs approved for recovery.
Our electric transmission segment earnings increased $10.6$216.9 million and $23.0$225.3 million in the thirdsecond quarter and first nine monthshalf of 2017,2020, respectively, as compared to the thirdsecond quarter and first nine monthshalf of 2016,2019, due primarily to the absence in 2020 of the second quarter 2019 impairment of NPT, which resulted in an after-tax charge of $204.4 million, or $0.64 per share. Excluding the NPT impairment charge, earnings increased $12.5 million and $20.9 million in the second quarter and first half of 2020, respectively, as compared to the second quarter and first half of 2019, due primarily to a higher transmission rate base as a result of our continued investment in our transmission infrastructure partially offset byand a lowerhigher benefit in the second quarter of 2017 related tofrom the annual billing and cost reconciliation filing with the FERC.
Our natural gas distribution segment results improved $0.8earnings increased $5.1 million in the thirdsecond quarter of 2017,2020, as compared to the thirdsecond quarter of 2016, and earnings decreased $2.8 million in the first nine months of 2017, as compared to the first nine months of 2016. The decrease in the first nine months of 2017 was2019, due primarily to higher depreciationearnings from capital tracker mechanisms due to continued investments in natural gas infrastructure, a base distribution rate increase at Yankee Gas effective January 1, 2020 and lower interest expense, partially offset by higher property tax expense, higher operations and maintenance expense, and lower demand revenueshigher depreciation expense.
Our natural gas distribution segment earnings increased $13.1 million in Connecticut driven by lower peak usage in 2017,the first half of 2020, as compared to 2016,the first half of 2019, due primarily to a base distribution rate increase at Yankee Gas effective January 1, 2020, higher earnings from capital tracker mechanisms due to
continued investments in natural gas infrastructure and lower interest expense, partially offset by higher operations and maintenance expense, higher depreciation expense, and higher property tax expense.
Our water distribution segment earnings increased $2.4 million and $3.7 million in the second quarter and first half of 2020, respectively, as a resultcompared to the second quarter and first half of milder winter weather.2019, due primarily to higher revenues from Connecticut's capital tracker mechanism due to increased infrastructure improvements and lower depreciation expense.
Eversource Parent and Other Companies: Eversource parent and other companies earned $10.2had increased losses of $13.3 million and $14.9 million in the third quarter of 2017 and $18.5 million in the first nine months of 2017, compared with $13.8 million in the third quarter of 2016 and $13.3 million in the first nine months of 2016. The improved year-to-date results were largely due to increased gains on investments recorded in 2017, partially offset by higher interest expense.
Electric and Natural Gas Sales Volumes: Weather, fluctuations in energy supply costs, conservation measures (including utility-sponsored energy efficiency programs), and economic conditions affect customer energy usage. Industrial sales volumes are less sensitive to temperature variations than residential and commercial sales volumes. In our service territories, weather impacts electric sales volumes during the summer and both electric and natural gas sales volumes during the winter; however, natural gas sales volumes are more sensitive to temperature variations than are electric sales volumes. Customer heating or cooling usage may not directly correlate with historical levels or with the level of degree-days that occur.
Fluctuations in retail electric sales volumes at NSTAR Electric and PSNH impact earnings ("Traditional" in the table below). For CL&P and WMECO, fluctuations in retail electric sales volumes do not impact earnings due to their respective regulatory commission approved distribution revenue decoupling mechanisms ("Decoupled" in the table below). These distribution revenues are decoupled from their customer sales volumes, which breaks the relationship between sales volumes and revenues recognized. CL&P and WMECO reconcile their annual base distribution rate recovery amounts to their respective pre-established levels of baseline distribution delivery service revenues of $1.059 billion and $132.4 million, respectively. Any difference between the allowed level of distribution revenue and the actual amount incurred during a 12-month period is adjusted through rates in the following period.
Fluctuations in natural gas sales volumes in Connecticut impact earnings ("Traditional" in the table below). In Massachusetts, fluctuations in natural gas sales volumes do not impact earnings due to the DPU-approved natural gas distribution revenue decoupling mechanism approved in the last rate case decision ("Decoupled" in the table below). These distribution revenues are decoupled from their customer sales volumes, which breaks the relationship between sales volumes and revenues recognized.
A summary of our retail electric GWh sales volumes and our firm natural gas MMcf sales volumes, as well as percentage changes, is as follows:
|
| | | | | | | | | | | | | | | | | |
| | For the Three Months Ended September 30, 2017 Compared to 2016 | | For the Nine Months Ended September 30, 2017 Compared to 2016 |
| | Sales Volumes (GWh) | | Percentage | | Sales Volumes (GWh) | | Percentage |
| Electric | 2017 | | 2016 | | Decrease | | 2017 | | 2016 | | Decrease |
| Traditional: | | | | | | | | | | | |
| Residential | 2,583 |
| | 2,910 |
| | (11.2 | )% | | 7,126 |
| | 7,407 |
| | (3.8 | )% |
| Commercial | 4,291 |
| | 4,525 |
| | (5.2 | )% | | 12,058 |
| | 12,376 |
| | (2.6 | )% |
| Industrial | 671 |
| | 696 |
| | (3.6 | )% | | 1,856 |
| | 1,948 |
| | (4.7 | )% |
| Total – Traditional | 7,545 |
| | 8,131 |
| | (7.2 | )% | | 21,040 |
| | 21,731 |
| | (3.2 | )% |
| | | | | | | | | | | | |
| Decoupled: | | | | | | | | | | | |
| Residential | 2,972 |
| | 3,398 |
| | (12.5 | )% | | 8,334 |
| | 8,750 |
| | (4.8 | )% |
| Commercial | 2,849 |
| | 3,039 |
| | (6.3 | )% | | 8,003 |
| | 8,315 |
| | (3.8 | )% |
| Industrial | 730 |
| | 776 |
| | (5.9 | )% | | 2,054 |
| | 2,170 |
| | (5.3 | )% |
| Total – Decoupled | 6,551 |
| | 7,213 |
| | (9.2 | )% | | 18,391 |
| | 19,235 |
| | (4.4 | )% |
| Total Sales Volumes | 14,096 |
| | 15,344 |
| | (8.1 | )% | | 39,431 |
| | 40,966 |
| | (3.7 | )% |
|
| | | | | | | | | | | | | | | | | |
| | For the Three Months Ended September 30, 2017 Compared to 2016 | | For the Nine Months Ended September 30, 2017 Compared to 2016 |
| | Sales Volumes (MMcf) | | Percentage | | Sales Volumes (MMcf) | | Percentage |
| Firm Natural Gas | 2017 | | 2016 | | Increase/(Decrease) | | 2017 | | 2016 | | Increase/(Decrease) |
| Traditional: | | | | | | | | | | | |
| Residential | 1,036 |
| | 956 |
| | 8.4 | % | | 10,138 |
| | 10,109 |
| | 0.3 | % |
| Commercial | 2,482 |
| | 2,350 |
| | 5.6 | % | | 14,432 |
| | 13,864 |
| | 4.1 | % |
| Industrial | 2,032 |
| | 1,964 |
| | 3.5 | % | | 7,663 |
| | 7,597 |
| | 0.9 | % |
| Total – Traditional | 5,550 |
| | 5,270 |
| | 5.3 | % | | 32,233 |
| | 31,570 |
| | 2.1 | % |
| | | | | | | | | | | | |
| Decoupled: | | | | | | | | | | | |
| Residential | 1,244 |
| | 1,308 |
| | (4.9 | )% | | 14,593 |
| | 13,848 |
| | 5.4 | % |
| Commercial | 2,314 |
| | 2,147 |
| | 7.8 | % | | 15,072 |
| | 15,019 |
| | 0.4 | % |
| Industrial | 1,270 |
| | 990 |
| | 28.3 | % | | 4,293 |
| | 4,163 |
| | 3.1 | % |
| Total – Decoupled | 4,828 |
| | 4,445 |
| | 8.6 | % | | 33,958 |
| | 33,030 |
| | 2.8 | % |
Special Contracts (1) | 1,147 |
| | 1,208 |
| | (5.0 | )% | | 3,495 |
| | 3,507 |
| | (0.3 | )% |
| Total – Decoupled and Special Contracts | 5,975 |
| | 5,653 |
| | 5.7 | % | | 37,453 |
| | 36,537 |
| | 2.5 | % |
| Total Sales Volumes | 11,525 |
| | 10,923 |
| | 5.5 | % | | 69,686 |
| | 68,107 |
| | 2.3 | % |
| |
(1)
| Special contracts are unique to the natural gas distribution customers who take service under such an arrangement and generally specify the amount of distribution revenue to be paid to Yankee Gas regardless of the customers' usage. |
For the thirdsecond quarter and the first nine monthshalf of 2017, retail electric sales volumes at our electric utilities with a traditional rate structure (NSTAR Electric and PSNH) were lower,2020, respectively, as compared to the thirdsecond quarter and first nine monthshalf of 2016. Sales volumes were negatively impacted by2019, due primarily to lower unrealized gains associated with our equity method investment in a renewable energy fund, and acquisition costs related to the mild summer weatherpending acquisition of the assets of Columbia Gas of Massachusetts of $3.9 million and $7.4 million in the thirdsecond quarter and first half of 2017, as compared to the same period in 2016, and lower customer usage driven2020, respectively, partially offset by the impact of increased customer energy conservation efforts. Cooling degree days for the first nine months of 2017 were 17.8 percent lower in the Boston metropolitan area and 24.8 percent lower in New Hampshire, as compared to the same period in 2016.
On January 28, 2016,a higher return at Eversource received approval of a three-year energy efficiency plan in Massachusetts, which includes recovery of LBR at NSTAR Electric until it is operating under a decoupled rate structure. NSTAR Electric earns LBR related to reductions in sales volumeService as a result of successful energy efficiency programs. LBR is recovered from retail customers through current rates. NSTAR Electric recognized LBR of $18.8 millionincreased investments in property, plant and $54.7 million in the third quarterequipment and first nine months of 2017, respectively, compared to $17.4 million and $44.1 million in the third quarter and first nine months of 2016, respectively.lower interest expense.
Our firm natural gas sales volumes are subject to many of the same influences as our retail electric sales volumes. In addition, they have benefited from customer growth in both of our natural gas distribution companies. Consolidated firm natural gas sales volumes were higher in the first nine months of 2017, as compared to the first nine months of 2016, due primarily to improved economic conditions across our service territories, partially offset by increased customer energy conservation efforts. The first quarter of 2017 mild winter weather was more than offset by colder than normal weather in the second quarter of 2017. Heating degree days for the first nine months of 2017 were 2.2 percent higher in Connecticut, as compared to the same period in 2016.
Major Storm: On October 29, 2017, a storm delivered high winds and rain, causing extensive damage to our electric distribution systems across all three states. We estimate that more than 800,000 of our electric distribution customers were without power during or following the storm. Restoration costs cannot be estimated at this time. As a result of the extent of the damages, we expect the storm restoration costs will be material and will exceed the criteria to be declared a major storm in Connecticut, New Hampshire, and Massachusetts and that each operating company will seek recovery of these costs through its applicable regulatory recovery process. As a result, all qualifying expenses prudently incurred during the storm will be deferred and recovered from customers. We do not expect the storm to have a material impact to the results of operations of CL&P, NSTAR Electric, PSNH or WMECO.
Liquidity
Consolidated: Cash and cash equivalents totaled $125.8$64.9 million as of SeptemberJune 30, 2017,2020, compared with $30.3$15.4 million as of December 31, 2016.2019.
Long-TermShort-Term Debt Issuances: In August 2017, CL&P issued $225 million of 4.30 percent 2014 Series A First and Refunding Mortgage Bonds due to mature in 2044. These bonds are part of the same series of CL&P’s existing 4.30 percent bonds that were initially issued in 2014. The aggregate outstanding principal amount for these bonds is now $475 million. The proceeds, net of issuance costs, were used to refinance short-term debt and fund capital expenditures and working capital.
In September 2017, Yankee Gas issued $75 million of 3.02 percent Series N First Mortgage Bonds due to mature in 2027. The proceeds, net of issuance costs, were used to repay short-term borrowings.
In October 2017, Eversource parent issued $450 million 2.75 percent Series K Senior Notes due to mature in 2022. These senior notes are part of the same series of Eversource parent’s existing 2.75 percent Series K Senior Notes that were initially issued in March 2017. The aggregate outstanding principal amount for the Series K Senior Notes is now $750 million. In addition, Eversource parent issued $450 million of 2.90 percent 2017 Series L Senior Notes due to mature in 2024. The proceeds, net of issuance costs, were used to repay short-term borrowings.
In October 2017, NSTAR Electric issued $350 million of 3.20 percent Debentures due to mature in 2027. The debentures are part of the same series of NSTAR Electric’s existing 3.20 percent Debentures that were initially issued in May 2017. The aggregate outstanding principal amount for the 3.20 percent Debentures is now $700 million. The proceeds, net of issuance costs, will be used to redeem long-term debt due to mature on November 15, 2017.
Long-Term Debt Repayments: In September 2017, CL&P repaid at maturity $100 million of 5.75 percent 2007 Series C First Mortgage Bonds and PSNH repaid at maturity $70 million of 6.15 percent 2007 Series N First Mortgage Bonds.
In October 2017, NSTAR Gas repaid at maturity $25 million of 7.04 percent Series M First Mortgage Bonds.
- Commercial Paper Programs and Credit Agreements: Eversource parent has a $1.45 billion commercial paper program allowing Eversource parent to issue commercial paper as a form of short-term debt. As of September 30, 2017 and December 31, 2016, Eversource parent had $917.0 million and approximately $1.0 billion, respectively, in short-term borrowings outstanding under the Eversource parent commercial paper program, leaving $533.0 million and $428.0 million of available borrowing capacity as of September 30, 2017 and December 31, 2016, respectively. The weighted-average interest rate on these borrowings as of September 30, 2017 and December 31, 2016 was 1.34 percent and 0.88 percent, respectively. As of September 30, 2017, there were intercompany loans from Eversource parent of $202.3 million to PSNH, and $96.9 million to WMECO. As of December 31, 2016, there were intercompany loans from Eversource parent of $80.1 million to CL&P, $160.9 million to PSNH and $51.0 million to WMECO. Eversource parent, CL&P, PSNH, WMECO, NSTAR Gas, and Yankee Gas and Aquarion Water Company of Connecticut are also parties to a five-year $1.45 billion revolving credit facility. The revolving credit facility, which terminates on September 4, 2021.December 6, 2024. The revolving credit facility serves to backstop Eversource parent's $1.45 billion commercial paper program.
NSTAR Electric has a $650 million commercial paper program allowing NSTAR Electric to issue commercial paper as a form of short-term debt. NSTAR Electric is also a party to a five-year $650 million revolving credit facility, which terminates on December 6, 2024. The revolving credit facility serves to backstop NSTAR Electric's $650 million commercial paper program.
The amount of borrowings outstanding and available under the commercial paper programs were as follows:
|
| | | | | | | | | | | | | | | | | | | | | |
| | Borrowings Outstanding as of | | Available Borrowing Capacity as of | | Weighted-Average Interest Rate as of |
| | June 30, 2020 | | December 31, 2019 | | June 30, 2020 | | December 31, 2019 | | June 30, 2020 | | December 31, 2019 |
| (Millions of Dollars) | | | | | |
| Eversource Parent Commercial Paper Program | $ | 351.5 |
| | $ | 1,224.9 |
| | $ | 1,098.5 |
| | $ | 225.1 |
| | 0.18 | % | | 1.98 | % |
| NSTAR Electric Commercial Paper Program | 142.0 |
| | 10.5 |
| | 508.0 |
| | 639.5 |
| | 0.12 | % | | 1.63 | % |
There were no borrowings outstanding on either the Eversource parent or NSTAR Electric revolving credit facilityfacilities as of SeptemberJune 30, 2017 and2020 or December 31, 2016.2019.
ExceptOn May 15, 2020, CL&P and PSNH entered into uncommitted line of credit agreements, which will expire by May 14, 2021. The CL&P agreements total $450 million and the PSNH agreements total $300 million. There are no borrowings outstanding on either the CL&P or PSNH uncommitted line of credit agreements as described below, amountsof June 30, 2020.
Amounts outstanding under the commercial paper programs are included in Notes Payable for Eversource and are classified in current liabilities on the Eversource and NSTAR Electric balance sheets, as all borrowings are outstanding for no more than 364 days at one time.
Intercompany Borrowings: Eversource parent uses its available capital resources to provide loans to its subsidiaries to assist in meeting their short-term borrowing needs. Eversource parent records intercompany interest income from its loans to subsidiaries, which is eliminated in consolidation. Intercompany loans from Eversource parent to its subsidiaries are eliminated in consolidation on Eversource's balance sheets. As of June 30, 2020, there were intercompany loans from Eversource parent to CL&P of $272.0 million, to PSNH of $119.3 million, and to a subsidiary of NSTAR Electric of $38.1 million. As of December 31, 2019, there were intercompany loans from Eversource parent to CL&P of $63.8 million, to PSNH of $27.0 million, and to a subsidiary of NSTAR Electric of $30.3 million. Intercompany loans from Eversource parent are included in Notes Payable to Eversource Parent and classified in current liabilities on the respective subsidiary's balance sheets.
Long-Term Debt:The following table summarizes long-term debt issuances and repayments:
|
| | | | | | | | | |
| (Millions of Dollars) | Issuance/(Repayment) | | Issue Date or Repayment Date | | Maturity Date | | Use of Proceeds for Issuance/
Repayment Information |
| NSTAR Electric: | | | | | | | |
| 3.95% 2020 Debentures | $ | 400.0 |
| | March 2020 | | April 2030 | | Refinanced investments in eligible green expenditures, which were previously financed in 2018 and 2019 |
| 5.10% Series E Senior Notes | (95.0 | ) | | March 2020 | | March 2020 | | Paid at maturity |
| Other: | | | | | | | |
| Eversource Parent 3.45% Series P Senior Notes | 350.0 |
| | January 2020 | | January 2050 | | Paid short-term borrowings |
| NSTAR Gas 4.46% Series N First Mortgage Bonds | (125.0 | ) | | January 2020 | | January 2020 | | Paid at maturity |
| Yankee Gas 4.87% Series K First Mortgage Bonds | (50.0 | ) | | April 2020 | | April 2020 | | Paid at maturity |
| NSTAR Gas 2.33% Series R First Mortgage Bonds | 75.0 |
| | May 2020 | | May 2025 | | Refinanced existing indebtedness, funded capital expenditures and for general corporate purposes |
| NSTAR Gas 3.15% Series S First Mortgage Bonds | 115.0 |
| | May 2020 | | May 2050 | | Refinanced existing indebtedness, funded capital expenditures and for general corporate purposes |
In June 2020, Aquarion Water Company of Massachusetts provided notice to its bondholders that it will redeem $32.2 million of long-term debt in connection with the sale to the town of Hingham, Massachusetts of its water system and treatment plant that supplies water to the towns of Hingham, Hull and North Cohasset. As a result, this debt was classified as current as of June 30, 2020.
Long-Term Debt Issuance Authorization: On January 27, 2020, the October 2017 Eversource parentDPU approved NSTAR Gas' request for authorization to issue up to $270 million in long-term debt issuances,through December 31, 2021. On July 31, 2020, the NHPUC approved PSNH's request for authorization to issue up to $200 million in long-term debt through December 31, 2020.
Rate Reduction Bonds: PSNH's RRB payments consist of principal and interest and are paid semi-annually. PSNH paid $21.6 million of RRB principal payments and $10.3 million of interest payments in the first half of 2020 and paid $30.7 million of RRB principal payments and $16.2 million of interest payments in the first half of 2019.
Common Share Issuances and 2019 Forward Sale Agreement: On June 15, 2020, Eversource completed an equity offering of 6,000,000 common shares at a price per share of $86.26. Eversource plans to use the net proceeds of whichthis offering to fund a portion of the planned purchase of the assets of CMA. The issuance of these common shares resulted in proceeds of $509.2 million, net of issuance costs.
In June 2019, Eversource completed an equity offering consisting of 5,980,000 common shares issued directly by the Company and 11,960,000 common shares issuable pursuant to a forward sale agreement with an investment bank. Under the forward sale agreement, 11,960,000 common shares were borrowed from third parties and sold by the underwriters. The forward sale agreement allowed Eversource, at its election and prior to May 29, 2020, to physically settle the forward sale agreement by issuing common shares in exchange for net proceeds at the then-applicable forward sale price specified by the agreement (initially, $71.48 per share) or, alternatively, to settle the forward sale agreement in whole or in part through the delivery or receipt of shares or cash. The forward sale price was subject to adjustment daily based on a floating interest rate factor and would decrease in respect of certain fixed amounts specified in the agreement, such as dividends.
Eversource previously issued 6,000,000 common shares under the forward sale agreement in December 2019. On March 23, 2020, Eversource physically settled a portion of the forward sale agreement by delivering 1,500,000 common shares in exchange for net proceeds of $105.7 million. Subsequently, on March 26, 2020, Eversource physically settled the remaining portion of the forward sale agreement by delivering 4,460,000 common shares in exchange for net proceeds of $314.1 million. The forward sale price used to determine the cash proceeds received by Eversource was calculated based on the initial forward sale price, as adjusted in accordance with the forward sale agreement.
The March and June 2020 common share issuances of 5,960,000 and 6,000,000, respectively, resulted in total proceeds of $929.0 million, net of issuance costs, and were reflected in shareholders' equity and as financing activities on the statement of cash flows.
Eversource used the net proceeds received upon the direct issuance of common shares and the net proceeds received upon settlement of the forward sale agreement to repay short-term borrowings outstandingdebt under the Eversource parent commercial paper program, $898.8 million of short-term debt was reclassified to Long-Term Debt as of September 30, 2017.fund capital spending and clean energy initiatives, and for general corporate purposes.
NSTAR Electric has a $450 million commercial paper program allowing NSTAR Electric to issue commercial paper as a form of short-term debt. As of September 30, 2017, NSTAR Electric had no short-term borrowings outstanding and as of December 31, 2016, NSTAR Electric had $126.5 million in short-term borrowings outstanding under its commercial paper program, leaving $450.0 million and $323.5 million of available borrowing capacity as of September 30, 2017 and December 31, 2016, respectively. The weighted-average interest rate on these borrowings as of December 31, 2016 was 0.71 percent. NSTAR Electric is a party to a five-year $450 million revolving credit facility. The revolving credit facility terminates on September 4, 2021. The revolving credit facility serves to backstop NSTAR Electric's $450 million commercial paper program. There were no borrowings outstanding on the revolving credit facility as of September 30, 2017 and December 31, 2016.
Cash Flows: Cash flows provided by operating activities totaled $1.49$1.01 billion in the first nine monthshalf of 2017,2020, compared with $1.65 billion$924.6 million in the first nine monthshalf of 2016.2019. The decreaseincrease in operating cash flows was due primarily to income tax refunds received of $37.9 million in the $200.7 million net unfavorable impactfirst half of 2020, as a result of the change incompared to income tax payments made, or refunds received, in 2017 when compared to 2016. This unfavorable impact was primarily the result of the December 2015 legislation, which extended the accelerated deduction of depreciation from 2015 to 2019. The legislation resulted in a significant refund of approximately $275 million, which we received in the first quarter of 2016. Additionally, there was an increase of $76.0$51.3 million in Pension and PBOP Plan cash contributions made in the first nine months of 2017, as compared to the same period in 2016. Partially offsetting these unfavorable impacts was the benefit related to the timing of regulatory recoveries2019 and the timing of collections and payments of ourother working capital items, includingitems. The income tax cash flow increase was driven primarily by the deferral of estimated tax payments from the second quarter of 2020 to July 2020 under COVID-19 relief legislation. Partially offsetting these favorable impacts were the timing of cash collections on our accounts receivable and cash payments made on our accounts payable.payable, the timing of collections for regulatory tracking mechanisms primarily related to transmission costs and the absence of $68.8 million in DOE Phase IV proceeds received by CYAPC and YAEC in the second quarter of 2019.
On SeptemberMay 6, 2017,2020, our Board of Trustees approved a common share dividend payment of $0.475$0.5675 per share, which was paid on September 29, 2017June 30, 2020 to shareholders of record as of September 19, 2017.May 20, 2020. In the first half of 2020, we paid cash dividends of $366.8 million and issued non-cash dividends of $11.6 million in the form of treasury shares, totaling dividends of $378.4 million. In the first half of 2019, we paid cash dividends of $323.3 million and issued non-cash dividends of $16.3 million in the form of treasury shares, totaling dividends of $339.6 million.
Eversource issues treasury shares to satisfy awards under the Company's incentive plans, shares issued under the dividend reinvestment and share purchase plan, and matching contributions under the Eversource 401k Plan.
In the first nine monthshalf of 2017,2020, CL&P, NSTAR Electric and PSNH and WMECO paid $205.2$69.5 million, $186.0 million, $23.9$196.5 million, and $28.5$22.3 million, respectively, in common stock dividends to Eversource parent.
Investments in Property, Plant and Equipment on the statements of cash flows do not include amounts incurred on capital projects but not yet paid, cost of removal, AFUDC related to equity funds, and the capitalized and deferred portions of pension and PBOP expense. In the first nine monthshalf of 2017,2020, investments for Eversource, CL&P, NSTAR Electric, and PSNH and WMECO were $1.64$1.40 billion, $621.9$407.2 million, $358.0 million, $215.5$447.5 million, and $109.2$169.2 million, respectively.
We expect the future operating cash flows of Eversource, CL&P, NSTAR Electric and PSNH, along with our existing borrowing availability and access to both debt and equity markets, will be sufficient to meet any working capital and future operating requirements, and capital investment forecasted opportunities.
Business Development and Capital Expenditures
Aquarion: On June 2, 2017, Eversource announced that it had entered into an agreement to acquire Aquarion from Macquarie Infrastructure Partners for $1.675 billion, consisting of approximately $880 million in cash and $795 million of assumed Aquarion debt. The transaction requires approval from PURA, the DPU, the NHPUC, the Maine PUC, and the Federal Communications Commission, and is also subject to a review under the Hart-Scott-Rodino Act. On June 29, 2017, Eversource and Aquarion filed joint applications with regulatory agencies in Connecticut, Massachusetts, New Hampshire and Maine requesting approval of the transaction. With the exception of Massachusetts, all state and federal regulatory agency approvals have been received and the related review period has expired. The transaction is expected to close by December 31, 2017.
Bay State Wind: Bay State Wind is a proposed offshore wind project being jointly developed by Eversource and Denmark-based Ørsted (formerly known as DONG Energy). Bay State Wind will be located in a 300-square-mile area approximately 15 to 25 miles south of Martha's Vineyard that has the ultimate potential to generate more than 2,000 MW of energy. Both Eversource and Ørsted hold a 50 percent ownership interest in Bay State Wind. In August 2016, Massachusetts passed clean energy legislation that requires EDCs to jointly solicit RFPs and enter into long-term contracts for offshore wind, creating RFP opportunities for projects like Bay State Wind. On June 29, 2017, the Bureau of Ocean Energy Management ("BOEM") approved the project’s Site Assessment Plan ("SAP"), the first BOEM approval of an offshore wind SAP in the U.S.
On June 29, 2017, the Massachusetts RFP was issued, seeking bids for a minimum of 400 MW of offshore wind capacity. The RFP states that bids of up to 800 MW would be considered, provided they demonstrate significant net economic benefits to customers. Bay State Wind submitted a Notice of Intent to Bid on July 26, 2017, and will submit a proposal by the December 20, 2017 due date.
Consolidated Capital Expenditures:Our consolidated capital expenditures, including amounts incurred but not paid, cost of removal, AFUDC, and the capitalized and deferred portions of pension and PBOP expense (all of which are non-cash factors), totaled $1.69$1.44 billion in the first nine monthshalf of 2017,2020, compared to $1.43$1.41 billion in the first nine monthshalf of 2016.2019. These amounts included $97.8$127.0 million and $87.1$97.6 million in the first nine monthshalf of 20172020 and 2016,2019, respectively, related to information technology and facilities upgrades and enhancements, primarily at Eversource Service and The Rocky River Realty Company.
Electric Transmission Business:
Our consolidated electric transmission business capital expenditures increased by $40.9$1.0 million in the first nine monthshalf of 2017,2020, as compared to the first nine monthshalf of 2016.2019. A summary of electric transmission capital expenditures by company is as follows:
| | | | For the Nine Months Ended September 30, | For the Six Months Ended June 30, |
| (Millions of Dollars) | 2017 | | 2016 | 2020 | | 2019 |
| CL&P | $ | 300.7 |
| | $ | 211.8 |
| $ | 192.7 |
| | $ | 220.6 |
|
| NSTAR Electric | 108.5 |
| | 162.6 |
| 159.9 |
| | 166.4 |
|
| PSNH | 87.4 |
| | 80.2 |
| 104.7 |
| | 59.6 |
|
| WMECO | 70.9 |
| | 75.7 |
| |
| NPT | 32.1 |
| | 28.4 |
| — |
| | 9.7 |
|
| Total Electric Transmission Segment | $ | 599.6 |
| | $ | 558.7 |
| $ | 457.3 |
| | $ | 456.3 |
|
Northern Pass: Northern Pass is a planned HVDC transmission line from the Québec-New Hampshire border to Franklin, New Hampshire and an associated alternating current radial transmission line between Franklin and Deerfield, New Hampshire. Northern Pass will interconnect at the Québec-New Hampshire border with a planned HQ HVDC transmission line.
On April 13, 2017, the New Hampshire Site Evaluation Committee ("NH SEC") commenced final adjudicative hearings that, on August 31, 2017, were extended and will result in the issuance of a final order by March 31, 2018.
On August 10, 2017, the DOE issued the final Environmental Impact Statement for Northern Pass concluding that the proposed Northern Pass route is the preferred alternative, providing substantial benefits with only minimal impacts. Siting and permitting at both the state and federal levels is well advanced and the DOE is expected to issue the Presidential Permit for Northern Pass during the fourth quarter of 2017. Northern Pass is expected to be placed in service in the second half of 2020.
In August 2016,Eastern Massachusetts enacted clean energy legislation that requires EDCs to solicit proposals jointly and enter into long-term contracts for energy, such as hydropower. The RFP was issued on March 31, 2017 and on July 27, 2017, Eversource Energy Transmission Ventures, Inc. and HQ jointly submitted proposals for Northern Pass into the Massachusetts clean energy RFP.
Greater Boston Reliability Solution: In February 2015, ISO-NE selected the Greater Boston and New Hampshire Solution (the "Solution"), proposed by Eversource and National Grid, to satisfy the requirements identified in the Greater Boston study. The Solution consistsProjects: These projects consist of a portfolio of electric transmission upgrades coveringin southern New Hampshire, and northern Massachusetts and continuing into the greater Boston metropolitan area, of which 28 upgrades are in Eversource's service territory.territory (two in New Hampshire and 26 in Massachusetts). The NH SECtwo New Hampshire upgrades, including the Merrimack Valley Reliability Project, have been placed in service, and 20 Massachusetts upgrades have been placed in service. On December 17, 2019, the Massachusetts Siting Board issued its writtena favorable decision on the Sudbury-Hudson Reliability Project, the last project requiring such approval. On January 17, 2020, the Town of Sudbury and Protect Sudbury, a community group, appealed the decision to the Massachusetts Supreme Judicial Court and oral arguments were conducted on March 17, 2020. On July 9, 2020, a similar appeal by the Town of Winchester of the Massachusetts Siting Board’s order approving the New Hampshire upgrades on October 4, 2016. We are currently pursuing the necessary regulatory and siting application approvals in Massachusetts. To date, we have received approval for two of these projects fromWakefield - Woburn Reliability Project was unanimously rejected by the Massachusetts Energy FacilitiesAppeals Court. The Court simultaneously rejected the Town’s subsequent appeal of the Siting Board.Board’s decision allowing local permitting processes to be bypassed. Construction has also begun on several smaller projects not requiring siting approval. Allour portion of the project had commenced in the Towns of Stoneham and Woburn in May 2020. The remaining upgrades are under construction and are expected to be completed by the end of 2019.placed in service in 2021. We estimate our portion of the investment in the Solution will be approximately $560$750 million, of which $186.3$466.8 million has been spent and capitalized through SeptemberJune 30, 2017.2020.
GHCCHartford-Area Transmission Projects: The Greater Hartford Central Connecticut ("GHCC")These projects which have been approved by ISO-NE, consist of 27 projects in the Hartford, Connecticut area with an expected investment of
approximately $350 million that are expected to be placed in service through 2019. Sixteenmillion. As of June 30, 2020, 26 projects have been placed in service, and eight projects areone project is in active construction.construction and is expected to be placed in service in the fourth quarter of 2020. As of SeptemberJune 30, 2017,2020, CL&P had spent and capitalized $192.3$290.8 million in costs associated with GHCC.these projects.
Seacoast Reliability Project: On April 12, 2016, PSNH filed a siting application with the NH SEC for theThe Seacoast Reliability Project consists of a 13-mile, 115kV transmission line within several New Hampshire communities, which proposes to useusing a combination of overhead, underground and underwater line designdesigns to help meet the growing demand for electricity in the Seacoast region. In June 2016,The project was placed in service on May 29, 2020 and resulted in an investment of approximately $123 million.
Ready Path Solution: The Ready Path Solution was chosen by ISO-NE as part of the NH SEC accepted our application as complete. Duefirst competitive solicitation for reliability upgrades in New England to delaysmeet the energy shortfall that will be created with the siting hearings, we now expectretirement of the NH SEC decisionMystic Generating Station in mid-2018, and thisMassachusetts in 2024. Our portion of the portfolio consists of installing new equipment at Eversource’s existing North Cambridge Substation with an estimated investment of approximately $14 million.
All project is now expectedcosts are anticipated to be completed by the end of 2019. We estimate our investment in this project to be approximately $84 million, of which,fully recoverable through September 30, 2017, PSNH had capitalized $19.7 million in costs.transmission rates.
Distribution Business:
A summary of distribution capital expenditures is as follows:
|
| | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | For the Nine Months Ended September 30, |
| (Millions of Dollars) | CL&P | | NSTAR Electric | | PSNH | | WMECO | | Total Electric | | Natural Gas | | Total Electric and Natural Gas Distribution Segment |
| 2017 | | | | | | | | | | | | | |
| Basic Business | $ | 161.8 |
| | $ | 110.3 |
| | $ | 52.5 |
| | $ | 16.4 |
| | $ | 341.0 |
| | $ | 51.3 |
| | $ | 392.3 |
|
| Aging Infrastructure | 127.4 |
| | 49.6 |
| | 63.9 |
| | 16.3 |
| | 257.2 |
| | 149.6 |
| | 406.8 |
|
Load Growth (1) | 41.0 |
| | 53.2 |
| | 14.1 |
| | (1.5 | ) | | 106.8 |
| | 30.6 |
| | 137.4 |
|
| Total Distribution | 330.2 |
| | 213.1 |
| | 130.5 |
| | 31.2 |
| | 705.0 |
| | 231.5 |
| | 936.5 |
|
Generation (2) | — |
| | 24.6 |
| | 6.7 |
| | 20.9 |
| | 52.2 |
| | — |
| | 52.2 |
|
| Total Electric and Natural Gas Distribution Segment | $ | 330.2 |
| | $ | 237.7 |
| | $ | 137.2 |
| | $ | 52.1 |
| | $ | 757.2 |
| | $ | 231.5 |
| | $ | 988.7 |
|
| | | | | | | | | | | | | | |
| 2016 | | | | | | | | | | | | | |
| Basic Business | $ | 127.0 |
| | $ | 87.7 |
| | $ | 46.8 |
| | $ | 10.7 |
| | $ | 272.2 |
| | $ | 48.9 |
| | $ | 321.1 |
|
| Aging Infrastructure | 97.4 |
| | 57.8 |
| | 61.9 |
| | 17.6 |
| | 234.7 |
| | 103.0 |
| | 337.7 |
|
Load Growth (1) | 31.9 |
| | 48.1 |
| | 11.8 |
| | (2.5 | ) | | 89.3 |
| | 28.3 |
| | 117.6 |
|
| Total Distribution | 256.3 |
| | 193.6 |
| | 120.5 |
| | 25.8 |
| | 596.2 |
| | 180.2 |
| | 776.4 |
|
| Generation | — |
| | — |
| | 8.5 |
| | — |
| | 8.5 |
| | — |
| | 8.5 |
|
| Total Electric and Natural Gas Distribution Segment | $ | 256.3 |
| | $ | 193.6 |
| | $ | 129.0 |
| | $ | 25.8 |
| | $ | 604.7 |
| | $ | 180.2 |
| | $ | 784.9 |
|
|
| | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | For the Six Months Ended June 30, |
| (Millions of Dollars) | CL&P | | NSTAR Electric | | PSNH | | Total Electric | | Natural Gas | | Water | | Total |
| 2020 | | | | | | | | | | | | | |
| Basic Business | $ | 92.8 |
| | $ | 101.9 |
| | $ | 22.1 |
| | $ | 216.8 |
| | $ | 38.3 |
| | $ | 4.9 |
| | $ | 260.0 |
|
| Aging Infrastructure | 91.0 |
| | 113.6 |
| | 45.0 |
| | 249.6 |
| | 175.8 |
| | 49.6 |
| | 475.0 |
|
| Load Growth and Other | 36.2 |
| | 51.0 |
| | 8.1 |
| | 95.3 |
| | 23.4 |
| | 0.4 |
| | 119.1 |
|
| Total Distribution | 220.0 |
| | 266.5 |
| | 75.2 |
| | 561.7 |
| | 237.5 |
| | 54.9 |
| | 854.1 |
|
| Solar | — |
| | 1.0 |
| | — |
| | 1.0 |
| | — |
| | — |
| | 1.0 |
|
| Total | $ | 220.0 |
| | $ | 267.5 |
| | $ | 75.2 |
| | $ | 562.7 |
| | $ | 237.5 |
| | $ | 54.9 |
| | $ | 855.1 |
|
| 2019 | | | | | | | | | | | | | |
| Basic Business | $ | 142.9 |
| | $ | 142.4 |
| | $ | 19.1 |
| | $ | 304.4 |
| | $ | 29.4 |
| | $ | 5.6 |
| | $ | 339.4 |
|
| Aging Infrastructure | 96.0 |
| | 96.6 |
| | 52.7 |
| | 245.3 |
| | 125.8 |
| | 42.9 |
| | 414.0 |
|
| Load Growth and Other | 32.0 |
| | 28.6 |
| | 7.1 |
| | 67.7 |
| | 26.3 |
| | 0.9 |
| | 94.9 |
|
| Total Distribution | 270.9 |
| | 267.6 |
| | 78.9 |
| | 617.4 |
| | 181.5 |
| | 49.4 |
| | 848.3 |
|
| Solar | — |
| | 4.8 |
| | — |
| | 4.8 |
| | — |
| | — |
| | 4.8 |
|
| Total | $ | 270.9 |
| | $ | 272.4 |
| | $ | 78.9 |
| | $ | 622.2 |
| | $ | 181.5 |
| | $ | 49.4 |
| | $ | 853.1 |
|
(1) For the nine months ended September 30, 2017 and September 30, 2016, WMECO had $11.0 million and $6.4 million, respectively, of total contributions in aid of construction, which were credits to capital expenditures for those periods.
(2) In 2017, NSTAR Electric and WMECO incurred capital expenditures related to the construction of solar generation facilities.
For the electric distribution business, basic business includes the purchase of meters, tools, vehicles, information technology, transformer replacements, equipment facilities, and the relocation of plant. Aging infrastructure relates to reliability and the replacement of overhead lines, plant substations, underground cable replacement, and equipment failures. Load growth and other includes requests for new business and capacity additions on distribution lines and substation additions and expansions.
For the natural gas distribution segment,business, basic business addresses daily operational needs including meters, pipe relocations due to public works projects, vehicles, and tools. Aging infrastructure projects seek to improve the reliability of the system through enhancements related to cast iron and bare steel replacement of main and services, corrosion mediation, and station upgrades. Load growth and other reflects growth in existing service territories including new developments, installation of services, and expansion.
TheFor the water distribution business, basic business addresses daily operational needs including periodic meter replacement, water main relocation, facility maintenance, and tools. Aging infrastructure relates to reliability and the replacement of water mains, regulators, storage tanks, pumping stations, wellfields, reservoirs, and treatment facilities. Load growth and other reflects growth in our service territory, including improvements of acquisitions, installation of new services, and interconnections of systems.
Pending Acquisition of Assets of Columbia Gas of Massachusetts: On February 26, 2020, Eversource and NiSource Inc. entered into an asset purchase agreement (the Agreement) pursuant to which Eversource would acquire certain assets that comprise NiSource’s local natural gas distribution segment'sbusiness in Massachusetts, which is doing business as Columbia Gas of Massachusetts (CMA). The purchase price of $1.1 billion includes a target working capital spending program increased by $51.3 million inamount that is subject to adjustment to reflect actual working capital as of the first nine months of 2017, as compared to the first nine months of 2016, primarily due to an increased investment in system replacementclosing date. Eversource would acquire approximately 330,000 residential, commercial, and reliability,industrial natural gas customers, as well as upgradesover 5,000 miles of natural gas distribution pipeline across more than 60 communities in Massachusetts.
The liabilities to be assumed by Eversource under the Agreement specifically exclude any liabilities (past or future) arising out of, or related to, the fires and explosions that occurred on September 13, 2018 in Lawrence, Andover and North Andover, Massachusetts related to the delivery of natural gas by CMA, including certain subsequent events, all as described and in the DPU's Order on Scope dated December 23, 2019 (D.P.U. 19-141) (the Greater Lawrence Incident or GLI). The liabilities to be assumed also exclude any further emergency events prior to the closing of the acquisition related to the restoration and reconstruction with respect to the GLI, including any losses arising out of, or related to, any litigation, demand, cause of action, claim, suit, investigation, proceeding, indemnification agreements or rights. Eversource is not assuming any of CMA's or NiSource Inc.'s debt obligations or notes payable.
The transaction requires approval from the DPU, the Maine Public Utilities Commission, the FERC, and the Federal Communications Commission, and the resulting rate plan requires DPU approval as well. The relevant review period under the Hart-Scott-Rodino Act has expired. On July 2, 2020, Eversource, CMA and NiSource filed an application with the DPU seeking approval of the sale of CMA assets to Eversource, which included a settlement with the Massachusetts Attorney General’s Office, the DOER, and the Low-Income Weatherization and Fuel Assistance Program Network. The application requests approval of the transaction and the related rate plan by September 30, 2020.
Eversource expects to finance the asset acquisition through a combination of debt and equity issuances in a ratio that is consistent with our LNG facilities. current consolidated capital structure. The transaction is expected to close shortly after the end of the third quarter of 2020.
Offshore Wind Business: Our offshore wind business includes ownership interests in North East Offshore and Bay State Wind, which together hold PPAs and contracts for the Revolution Wind, South Fork Wind and Sunrise Wind projects, as well as offshore leases through BOEM. Our offshore wind projects are being developed and constructed through a joint and equal partnership with Ørsted. This partnership also participates in new procurement opportunities for offshore wind energy in the Northeast U.S. On July 21, 2020, New York's second offshore wind RFP for up to 2,500 MW was issued, and we expect to participate in that RFP.
Eversource has a 50 percent ownership interest in North East Offshore, which holds the Revolution Wind and South Fork Wind projects, as well as a 257 square-mile ocean lease off the coasts of Massachusetts and Rhode Island. Eversource also has a 50 percent ownership interest in Bay State Wind, which holds the Sunrise Wind project. Bay State Wind's separate 300-square-mile ocean lease is located approximately 25 miles south of the coast of Massachusetts adjacent to the North East Offshore area. In aggregate, the Bay State Wind and the North East Offshore ocean lease sites jointly-owned by Eversource and Ørsted could eventually develop at least 4,000 MW of clean, renewable offshore wind energy. As of June 30, 2020, Eversource's total equity investment balance in its offshore wind business was $660.3 million.
We are preparing our final project designs and advancing the appropriate federal, state and local siting and permitting processes along with our offshore wind partner, Ørsted, all of which is competitively sensitive. We currently expect the LNG facility upgrades to costmake investments in our offshore wind business of approximately $200 million to $400 million during 2020, subject to advancing our final project designs and federal, state and local permitting processes.
The following table provides a summary of the Eversource and Ørsted major projects with announced contracts:
|
| | | | | | |
| Wind Project | State Servicing | Size (MW) | Term (Years) | Price per MWh | Pricing Terms | Contract Status |
| Revolution Wind | Rhode Island | 400 | 20 | $98.43 | Fixed price contract; no price escalation | Approved |
| Revolution Wind | Connecticut | 304 | 20 | (1) | Fixed price contracts; no price escalation | Approved |
| South Fork Wind | New York (LIPA) | 90 | 20 | $160.33 | 2 percent average price escalation | Approved |
| South Fork Wind | New York (LIPA) | 40 | 20 | $86.25 | 2 percent average price escalation | (3) |
| Sunrise Wind | New York (NYSERDA) | 880 | 25 | $110.37 (2) | Fixed price contract; no price escalation | Approved |
| |
(1) | The pricing for the Revolution Wind contracts in Connecticut has not been publicly disclosed. |
| |
(2) | Index Offshore Wind Renewable Energy Certificate (OREC) strike price. |
| |
(3) | The Long Island Power Authority (LIPA) agreed to expand the original 20-year PPA from 90 MW to 130 MW through an amendment to the original agreement. Negotiations are currently underway, and a final amendment is expected in 2020. |
The in-service dates for our offshore wind projects are subject to receipt of federal, state and local approvals necessary to construct and operate the projects. The federal permitting process is governed by BOEM, and state approvals are required from New York, Rhode Island and Massachusetts. Significant delays in the siting and permitting process resulting from the timeline for obtaining approval from BOEM and the state and local agencies, as well as the impact of COVID-19, could adversely impact the timing of these projects' in-service dates.
In June 2020, BOEM released its Offshore Wind Cumulative Impact Analysis as part of the Draft Supplemental Environmental Impact Statement (EIS) for a non-affiliated offshore wind project. The study assessed the environmental, social, and economic impacts of constructing 22 GW of offshore wind projects in every federal lease area along the East Coast. While this analysis was performed for the purpose of completing the permitting review of a non-affiliated project, we anticipate that this analysis has produced a replicable methodology for completing this analysis that should reduce the timeline for completing future BOEM reviews.
The South Fork Wind project has commenced the federal siting and permitting process with the filing of its Construction Operations Plan (COP) application with BOEM in October 2018. The first major milestone in the BOEM review process is an issuance of a Notice of Intent to complete an Environmental Impact Statement (NOI), which South Fork Wind has received. Although we have received BOEM's NOI for the South Fork Wind project, we are awaiting a confirmed review schedule outlining when BOEM will complete its review of the South Fork Wind COP. South Fork Wind is designated as a “Covered Project” pursuant to Title 41 of the Fixing America’s Surface Transportation Act (“FAST41”) and a Major Infrastructure Project under Section 3(e) of Executive Order 13807, which provides greater federal attention on meeting the project’s permitting timelines. South Fork Wind’s FAST41 designation is due for reauthorization in 2020.
Revolution Wind filed its COP application with BOEM in March 2020 and will seek FAST41 designation by the end of 2020. We are awaiting BOEM to outline its timeline for completing the review of the Revolution Wind COP in an NOI. The Sunrise Wind COP application is expected to be placedfiled in service in late 2019.2020.
South Fork Wind commenced the New York state sitting process in 2018. On April 8, 2020, the state of New York Administrative Law Judge granted a change to the start of the South Fork Wind evidentiary hearing schedule to September 30, 2020, due to ongoing COVID-19 work and travel restrictions. Onshore and near-shore site investigation activities occurring within New York’s jurisdiction were suspended in March 2020 due to work restrictions imposed in response to the COVID-19 pandemic. The activities that were suspended included offshore site investigations, and onshore environmental and geotechnical surveys. These activities resumed in early June following the release of revised guidance from the New York State Energy Research and Development Authority (NYSERDA). We are developing mitigation plans to address the impacts of the approximately two-month suspension of field activities due to these COVID-19 restrictions. These mitigation plans are intended to limit the impact and risk to our project timelines.
Because BOEM has not yet released a confirmed permit schedule outlining when BOEM will complete its review of the South Fork Wind COP, as well as the impacts from the COVID-19 related shut-downs in New York, these impacts will very likely delay the in-service date of the South Fork Wind project to beyond the projected end of 2022 in-service date.
We anticipate the principal state permitting applications for Revolution Wind and Sunrise Wind will be filed in Rhode Island and New York, respectively, in the second half of 2020. Sunrise Wind was subject to the same New York work restrictions as South Fork Wind between March 2020 and June 2020. For Sunrise Wind, these restrictions prevented progressing our site surveys in New York and within New York jurisdictional waters due to COVID-19 restrictions. These restrictions adversely impact the preparation of our federal and state permitting applications. At this time, we are unable to predict the potential impact of those delays on the projected in-service dates of the end of 2023 and the end of 2024 for Revolution Wind and Sunrise Wind, respectively.
FERC Regulatory Matters
FERC ROE Complaints: Four separate complaints have beenwere filed at the FERC by combinations of New England state attorneys general, state regulatory commissions, consumer advocates, consumer groups, municipal parties and other parties (collectively, the "Complainants")Complainants). In each of the first three complaints, filed on October 1, 2011, December 27, 2012, and July 31, 2014, respectively, the Complainants challenged the NETOs' base ROE of 11.14 percent that had been utilized since 2005 and sought an order to reduce it prospectively from the date of the final FERC order and for the separate 15-month complaint periods. In the fourth complaint, filed April 29, 2016, the Complainants challenged the NETOs' base ROE billed of 10.57 percent and the maximum ROE for transmission incentive ("incentive cap")(incentive cap) of 11.74 percent, asserting that these ROEs were unjust and unreasonable.
In response to appealsThe ROE originally billed during the period October 1, 2011 (beginning of the FERC decision in the first complaint filed by the NETOs and the Complainants, the U.S. Court of Appeals for the D.C. Circuit (the "Court") issued a decision on April 14, 2017 vacating and remanding the FERC's decision. The Court found that the FERC failed to make an explicit finding that the 11.14 percent base ROE was unjust and unreasonable, as required under Section 206 of the Federal Power Act, before it set a new base ROE. The Court also found that the FERC did not provide a rational connection between the record evidence and its decision to select the midpoint of the upper half of the zone of reasonableness for the new base ROE.
On May 26, 2017, the Chief Administrative Law Judge ("ALJ") issued an order that the fourth complaint will continue to trial in December 2017 with an ALJ initial decision expected in March of 2018.
A summary of the four separate complaints and the base ROEs pertinent to those complaints are as follows:
|
| | | | | | |
| Complaint | 15-Month Time Period of Complaint (Beginning as of Complaint Filing Date) | Original Base ROE Authorized by FERC at Time of Complaint Filing Date (1) | Base ROE Subsequently Authorized by FERC for First Complaint Period and also Effective from October 16, 2014 through April 14, 2017 (1) | Reserve (Pre-Tax and Excluding Interest) as of September 30, 2017 (in millions) | | FERC ALJ Recommendation of Base ROE on Second and Third Complaints (Issued March 22, 2016) |
| First | 10/1/2011 - 12/31/2012 | 11.14% | 10.57% | $— | (2) | N/A |
| Second | 12/27/2012 - 3/26/2014 | 11.14% | N/A | 39.1 | (3) | 9.59% |
| Third | 7/31/2014 - 10/30/2015 | 11.14% | 10.57% | — | | 10.90% |
| Fourth | 4/29/2016 - 7/28/2017 | 10.57% | 10.57% | — | | N/A |
(1) The billed ROE (base plus incentives) between October 1, 2011 andperiod) through October 15, 2014 was withinconsisted of a rangebase ROE of 11.14 percent and incentives up to 13.1 percent. On October 16, 2014, the FERC set the base ROE at 10.57 percent and the incentive cap at 11.74 percent for the first complaint period andperiod. This was also effective fromfor all prospective billings to customers beginning October 16, 2014 through2014. This FERC order was vacated on April 14, 2017 by the date on whichU.S. Court of Appeals for the Court vacated this FERC order.D.C. Circuit (the Court).
(2) CL&P, NSTAR Electric, PSNH and WMECO have refunded allAll amounts associated with the first complaint period totaling $38.9have been refunded. Eversource has recorded a reserve of $39.1 million (pre-tax and excluding interest) at Eversource (consistingfor the second complaint period as of $22.4 million at CL&P, $8.4 million at NSTAR Electric, $2.8 million at PSNH,June 30, 2020 and $5.3 million at WMECO), reflecting both the base ROE and incentive cap prescribed by the FERC order.
(3) TheDecember 31, 2019. This reserve represents the difference between the ROEs billed rates during the second complaint period and a 10.57 percent base ROE and 11.74 percent incentive cap. The reserve consisted of $21.4 million for CL&P, $8.5$14.6 million for NSTAR Electric and $3.1 million for PSNH and $6.1 million for WMECO as of SeptemberJune 30, 2017.2020 and December 31, 2019.
On June 5, 2017, the NETOs, including Eversource, submitted a filing to the FERC to reinstate the base ROE of 11.14 percent with an associated ROE incentive cap of 13.5 percent effective June 8, 2017, as these were the last ROEs lawfully in effect for transmission billing purposes prior to the FERC order vacated by the Court on April 14, 2017. On October 6, 2017, the FERC did not accept the NETOs filing, temporarily leaving in place the ROEs (10.57 percent base ROE with an 11.74 percent incentive cap ROE) set in the first complaint proceeding until the FERC addresses the Court’s decision.
On October 5, 201716, 2018, FERC issued an order on all four complaints describing how it intends to address the issues that were remanded by the Court. FERC proposed a new framework to determine (1) whether an existing ROE is unjust and unreasonable and, if so, (2) how to calculate a replacement ROE. Initial briefs were filed by the NETOs, Complainants and FERC Trial Staff on January 11, 2019 and reply briefs were filed a serieson March 8, 2019. The NETOs' brief was supportive of motions, requesting that the FERC dismissoverall ROE methodology determined in the four complaint proceedings. Alternatively, ifOctober 16, 2018 order provided the FERC does not dismisschange the proceedings,proposed methodology or alter its implementation in a manner that has a material impact on the results.
The FERC order included illustrative calculations for the first complaint using FERC's proposed frameworks with financial data from that complaint. Those illustrative calculations indicated that for the first complaint period, for the NETOs, requested thatwhich FERC concludes are of average financial risk, the preliminary just and reasonable base ROE is 10.41 percent and the preliminary incentive cap on total ROE is 13.08 percent.
If the results of the illustrative calculations were included in a final FERC order for each of the complaint periods, then a 10.41 percent base ROE and a 13.08 percent incentive cap would not have a significant impact on our financial statements for all of the complaint periods. These preliminary calculations are not binding and do not represent what we believe to be the most likely outcome of a final FERC order.
On November 21, 2019, FERC issued Opinion No. 569 affecting the two pending transmission ROE complaints against the Midcontinent ISO (MISO) transmission owners, in which FERC adopted a new methodology for determining base ROEs. Various parties sought rehearing. On December 23, 2019, the NETOs filed supplementary materials in the NETOs' four pending cases to respond to this new methodology because of the uncertainty of the applicability to the NETOs’ cases.
On May 21, 2020, the FERC consolidate allissued its order in Opinion No. 569-A on the rehearing of the MISO transmission owners' cases, in which FERC again changed its methodology for determining the MISO transmission owners' base ROEs. Various parties have appealed the MISO transmission owners' opinion. This new methodology differs significantly from the methodology proposed by FERC in its October 16, 2018 order to determine the NETOs' base ROEs in its four pending cases.
Given the significant uncertainty regarding the applicability of the FERC opinions in the MISO transmission owners' two complaint cases to the NETOs' pending four complaint proceedings for expeditious resolution and/or stay the trial in the fourth complaint proceeding and resolve it based on the standards set in the April 14, 2017 Court decision.
At this time, the Company cannot reasonably estimate a range of gain or loss for the complaint proceedings. The April 14, 2017 Court decision did not provide acases, Eversource concluded that there is no reasonable basis for a change to the reserve balance of $39.1 million (pre-tax, excluding interest) for the second complaint period, and the Company has not changed its reserve or recognized ROEs for any of the complaint periods.
Management cannotperiods at this time predict the ultimate effecttime. As well, Eversource cannot reasonably estimate a range of the Court decisionany gain or future FERC action onloss for any of the four complaint periods or the estimated impacts on the financial position, results of operations or cash flows of proceedings at this time.
Eversource, CL&P, NSTAR Electric and PSNH or WMECO.currently record revenues at the 10.57 percent base ROE and incentive cap at 11.74 percent established in the October 16, 2014 FERC order.
The average impactA change of a 10 basis point changepoints to the base ROE used to establish the reserves would impact Eversource's after-tax earnings by an average of approximately $3 million for each of the four 15-month complaint periods wouldperiods.
FERC Notice of Inquiry on ROE: On March 21, 2019, FERC issued a Notice of Inquiry (NOI) seeking comments from all stakeholders on FERC's policies for evaluating ROEs for electric public utilities, and interstate natural gas and oil pipelines. On June 26, 2019, the NETOs jointly filed comments supporting the methodology established in the FERC’s October 16, 2018 order with minor enhancements going forward. The NETOs jointly filed reply comments in the FERC ROE NOI on July 26, 2019. On May 12, 2020, the NETOs filed supplemental comments in the NOI ROE docket. At this time, Eversource cannot predict how this proceeding will affect Eversource's after-tax earnings by approximately $3 million.its transmission ROEs.
FERC Notice of Inquiry and Proposed Rulemaking on Transmission Incentives: On March 21, 2019, FERC issued an NOI seeking comments on FERC's policies for implementing electric transmission incentives. On June 26, 2019, Eversource filed comments requesting that FERC retain policies that have been effective in encouraging new transmission investment and remain flexible enough to attract investment in new and emerging transmission technologies. Eversource filed reply comments on August 26, 2019. On March 20, 2020, FERC issued a Notice of Proposed Rulemaking (NOPR) on transmission incentives. The NOPR intends to revise FERC’s electric transmission incentive policies to reflect competing uses of transmission due to generation resource mix, technological innovation and shifts in load patterns. FERC proposes to grant transmission incentives based on measurable project economics and reliability benefits to consumers rather than its current project risks and challenges framework. On July 1, 2020, Eversource filed comments generally supporting the NOPR. At this time, Eversource cannot predict how these proceedings will affect its transmission incentives.
FERC Transmission Rate Settlement: On December 28, 2015, FERC initiated a proceeding to review the NETOs' regional and local transmission formula rates due to a lack of transparency, finding that the formula rates appeared to lack sufficient details to determine how costs are derived and recovered in rates. Parties have been engaged in further settlement negotiations and reached an agreement in principle on October 22, 2019. On June 15, 2020, the NETOs (including CL&P, NSTAR Electric and WMECO Merger FERC Filings: On January 13, 2017, Eversource made two filingsPSNH) filed an uncontested Settlement Agreement with FERC, which was signed by all six New England state regulatory commissions, New England States Committee on Electricity, New England Municipals and all the NETOs. The Settlement Agreement proposes to implement a new regional and local rate structure effective on January 1, 2021, establishes annual formula rate transparency procedures effective June 15, 2021 and contains a rate moratorium through December 31, 2024. There is no time requirement under which the FERC must issue an order, which is required for the new formula rate template to go into effect.
U.S. Federal Corporate Income Taxes: Local and regional transmission service rates do not currently reflect amortization of excess ADIT (EDIT) balances that resulted from the Tax Cuts and Job Act (the Act). On November 15, 2018, FERC issued a Policy Statement and a separate Notice of Proposed Rulemaking addressing accounting and rate issues related to ADIT changes resulting from the proposed merger of WMECO into NSTAR ElectricAct. On November 21, 2019, FERC issued its final rule requiring public utilities with an anticipated effective date of December 31, 2017. Onetransmission formula rates to make adjustments to ADIT and EDIT. On July 30, 2020, Eversource submitted its filing requests FERC approval ofin compliance with FERC's final rule to address the merger, andEDIT resulting from the other filing requests FERC approval of NSTAR Electric's assumption of WMECO's short-term debt obligations. The FERC approved the merger on March 2, 2017 and will act on the assumption of debt filing by the end of 2017.Act.
Regulatory Developments and Rate Matters
Electric, and Natural Gas and Water Utility Base Distribution Rates:
The Regulatedregulated companies’ distribution rates are set by their respective state regulatory commissions, and their tariffs include mechanisms for periodically adjusting their rates for the recovery of specific incurred costs. Other than as described below, for the first nine monthshalf of 2017,2020, changes made to the Regulatedregulated companies’ rates did not have a material impact on their earnings, financial position, or cash flows. For further information, see "Financial Condition and Business Analysis – Regulatory Developments and Rate Matters" included in Item 7, "Management’s Discussion and Analysis of Financial Condition and Results of Operations," of the Eversource 20162019 Form 10-K.
COVID-19 Regulatory Dockets: Beginning in March 2020, Connecticut, Massachusetts and New Hampshire established moratoriums on disconnections of residential and commercial customers for non-payment for utility service. In Connecticut, the moratorium for residential customers will remain in place until the declared COVID-19 state of emergency is lifted by the governor or state regulatory commission, but ended on August 1, 2020 for commercial customers. In New Hampshire, the moratorium on residential and commercial utility disconnections ended on July 15, 2020, however PSNH has not yet begun to disconnect customers. In Massachusetts, although several utilities petitioned the state regulatory commission on May 29, 2020 to extend the moratorium until September 1, 2020 for commercial customers and November 15, 2020 for residential customers, the commission has not acted on that petition, and therefore, the moratorium will remain in place until it is lifted by the governor or commission.
In Connecticut, PURA opened a docket to address COVID-19 developments, including issuing orders on March 18, 2020, April 29, 2020 and May 15, 2020 that authorized electric, natural gas and water utilities to establish a regulatory asset for COVID-19 uncollectible customer receivable expenses and costs associated with the related orders. PURA’s April 29, 2020 order, as supplemented on May 15, 2020, also allowed the inclusion of working capital costs in the regulatory asset, and authorized electric, natural gas and water utilities to establish a payment plan program designed to assist any customer who requests financial assistance during the COVID-19 pandemic. On July 10, 2020, PURA denied a request from a coalition of large industrial customers to reduce or suspend certain electric and natural gas charges during the COVID-19 pandemic.
Connecticut:
OnIn Massachusetts, on April 20, 2017, PURA approved17, 2020, a coalition of electric, natural gas and water utilities submitted a comprehensive proposal to the joint request of CL&P,DPU that would enable the Connecticut Office of Consumer Counselstate’s utilities to provide flexible payment arrangements to those customers who need financial assistance, while simultaneously maintaining the financial integrity necessary to continue to conduct and finance utility operations through appropriate ratemaking treatment and the establishment of a regulatory asset for COVID-19 related expenses, including uncollectible customer receivable expenses, among other proposals. On May 11, 2020, the DPU opened an inquiry into establishing policies and practices regarding customer assistance and ratemaking measures for electric and natural gas companies in response to the effects of COVID-19. On June 26, 2020, the DPU approved a COVID-19 customer outreach plan.
Consistent with the above-described developments in Connecticut Attorney Generaland Massachusetts, Eversource continues to amendwork closely with the deadlineNHPUC on COVID-19 developments impacting our New Hampshire electric and water utilities, including the proposed establishment of flexible payment plan options for those customers who need financial assistance in order to establish newmitigate the size of the uncollectible customer receivable balances that would be borne by all customers in the future.
For information on COVID-19-related regulatory deferrals recorded and COVID-19 charges incurred, see "Impact of COVID-19" included in this Management’s Discussion and Analysis.
Storm Event:
On August 4, 2020, Tropical Storm Isaias caused extensive and catastrophic damage to our electric distribution system and significant customer outages, primarily in Connecticut. In terms of customer outages, this storm was one of the worst in CL&P’s history. As the restoration process is currently underway, costs cannot be estimated at this time. Management expects the costs to meet the criteria for specific cost recovery and, as a result, does not expect the storm costs incurred to have a material impact to the results of operations of Eversource or CL&P. CL&P expects to seek recovery of these anticipated deferred storm costs through its applicable regulatory recovery process.
Connecticut:
CL&P Rate Suspension: On July 31, 2020, PURA temporarily suspended its June 26, 2020 approval of certain delivery rate components effective July 1, 2020, and ordered CL&P to restore rates to those in effect as of June 30, 2020. PURA ordered that it will reexamine the administrative changes to the energy and transmission adjustment clauses provisionally permitted by its June 26, 2020 letter. PURA indicated that this was due to the convergence of a number of recent events, including the COVID-19 crisis and its corresponding effect on customer energy usage, as well as the warmer than normal weather in July. PURA intends to reexamine rates to ensure that CL&P is not over-collecting revenues in the 2012 Connecticut merger settlement agreementshort-term. These rates, the Revenue Decoupling Mechanism Charge, the Transmission Adjustment Clause charge, the Non-Bypassable Federally Mandated Congestion Charge, and the Electric System Improvements Tracker charge, are adjusted periodically and reconciled annually in accordance with the policies and procedures of the PURA, with any differences refunded to, or recovered from, "no later than December 1, 2017" to "no later than July 1, 2018."customers. We do not expect the delay in changes of the rates will have a material impact on our financial position, results of operations or cash flows.
Massachusetts:
NSTAR Gas Rate Case: On October 27, 2017, CL&PNovember 8, 2019, NSTAR Gas filed its application with the DPU, which sought a letter of intent with PURA to request adistribution rate increase of $255.8 million, $45 million and $36 million effective May 1, 2018, 2019, and 2020, respectively.
Massachusetts:
Eversource and NSTAR Electric Boston Harbor Civil Action: On July 15, 2016, the United States Attorney on behalf of the United States Army Corps of Engineers filed a civil action in the United States District Court for the District of Massachusetts under provisions of the Rivers and Harbors Act of 1899 and the Clean Water Act against NSTAR Electric, Harbor Electric Energy Company, a wholly-owned subsidiary of NSTAR Electric ("HEEC"), and the Massachusetts Water Resources Authority (together with NSTAR Electric and HEEC, the "Defendants"). The action alleged that the Defendants failed to comply with certain permitting requirements related to the placement of the HEEC-owned electric distribution cable beneath Boston Harbor. The action sought an order to compel HEEC to comply with cable depth requirements in the United States Army Corps of Engineers' permit or alternatively to remove the electric distribution cable and cease unauthorized work in U.S. waterways. The action also sought civil penalties and other costs.
After substantial negotiations, the parties reached a settlement whereby HEEC will install a new 115kV distribution cable across Boston Harbor to Deer Island, utilizing a different route, and will remove portions of the existing cable. Upon the installation and completion of the new cable and the removal of the portions of the existing cable, all issues surrounding the current permit from the United States Army Corps of Engineers are expected to be resolved, and such litigation is expected to be dismissed with prejudice.
In 2017, as a result of the settlement, NSTAR Electric expensed $4.9 million (pre-tax) of previously incurred capitalized costs associated with engineering work performed on the existing cable that will no longer be used. In addition, NSTAR Electric agreed to provide a rate base credit of $17.5 million to the Massachusetts Water Resources Authority for the new cable. This negotiated credit will result in the initial $17.5 million of construction costs on the new cable to be expensed as incurred. Construction of the new cable is expected to be completed in 2019.
Massachusetts RFPs: On March 31, 2017, pursuant to a comprehensive energy law enacted in 2016, "An Act to Promote Energy Diversity," (the "Act") the Massachusetts EDCs, including NSTAR Electric and WMECO, and the DOER issued a joint RFP for 9.45 terawatt hours of clean energy per year, such as hydropower, land-based wind or solar. The RFP seeks proposals for long-term contracts of 15 to 20 years to provide the state's electric distribution companies with clean energy generation. The proposal submission due date was July 27, 2017. Contracts will be selected in January 2018, with an expectation to submit executed long-term contracts to the DPU for final approval in April 2018. On July 27, 2017, Eversource Energy Transmission Ventures, Inc. and HQ jointly submitted proposals for Northern Pass into the Massachusetts clean energy RFP. Northern Pass is expected to be placed in service in the second half of 2020.
On June 29, 2017, pursuant to the Act, the Massachusetts EDCs, including NSTAR Electric and WMECO, and the DOER issued a joint RFP for long-term contracts for offshore wind energy projects, seeking bids for a minimum of 400 MW of offshore wind capacity. The Offshore Wind Energy RFP states that bids of up to 800 MW would be considered, provided they demonstrate significant net economic benefits to customers. Bay State Wind submitted a Notice of Intent to Bid on July 26, 2017 and will submit a proposal by the December 20, 2017 due date.
NSTAR Electric and WMECO Rate Case: On January 17, 2017, NSTAR Electric and WMECO jointly filed an application (the "Joint Applicants") with the DPU for approval of a combined $96 million increase in base distribution rates, effective January 1, 2018.$38.0 million. As part of this filing, NSTAR Gas also proposed to continue its ongoing Gas System Enhancement Program (GSEP), include the Joint Applicants are presenting a grid-wise performance plan, including the implementation ofGSEP investments since 2015 into base rates, and implement a performance-based rate-making mechanism in conjunction with a grid modernization base commitment of $400 million in incremental capital investment over a period of five years, commencing January 1, 2018. In addition, the Joint Applicants proposed to streamline and align rate classifications between NSTAR Electric and WMECO, and requested a revenue decoupling rate mechanism for NSTAR Electric. WMECO has a revenue decoupling mechanism in place. The DPU will also be reviewing the proposed December 31, 2017 merger of NSTAR Electric and WMECO as part of the rate case.ratemaking plan. A final decision from the DPU is expected in late 2017,by October 30, 2020, with new rates anticipated to be effective JanuaryNovember 1, 2018.2020.
New Hampshire:
Generation Divestiture: Distribution Rates:On June 10, 2015, Eversource and PSNH entered into the 2015 Public Service Company of New Hampshire Restructuring and Rate Stabilization Agreement (the "Agreement") with the New Hampshire Office of Energy and Planning, certain members of the NHPUC staff, the Office of Consumer Advocate, two State Senators, and several other parties. Under the terms of the Agreement, PSNH agreed to divest its generation assets, subject to NHPUC approval. The Agreement provided for a resolution of issues pertaining to PSNH's generation assets in pending regulatory proceedings before the NHPUC. The Agreement provided for the Clean Air Project prudence proceeding to be resolved and all remaining Clean Air Project costs to be included in rates effective January 1, 2016. As part of the Agreement, PSNH agreed to forego recovery of $25 million of the equity return related to the Clean Air Project.
On July 1, 2016, the NHPUC approved the Agreement in an order that, among other things, instructed PSNH to begin the process of divesting its generation assets. The NHPUC selected an auction adviser to assist with the divestiture, and the final plan and auction process were approved by the NHPUC in November 2016.
On October 11, 2017, PSNH entered into two Purchase and Sale Agreements ("Agreements") to sell its thermal and hydroelectric generation assets to private investors at purchase prices of $175 million and $83 million, respectively, subject to adjustments as set forth in each Agreement.
On October 12, 2017,April 26, 2019, PSNH filed an application with the NHPUC requestingfor approval of a temporary annual base distribution rate increase, effective July 1, 2019. On June 27, 2019, the Agreements. We expectNHPUC approved a settlement agreement that was reached by PSNH, the NHPUC Staff, the Office of the Consumer Advocate, and another settling party, to receive approvalsimplement a temporary annual base distribution rate increase of $28.3 million. Although new rates were implemented on August 1, 2019 to customers, the provisions of the temporary base distribution rate increase were effective July 1, 2019. The settlement agreement also permits PSNH to recover approximately $68.5 million in unrecovered storm costs over a five-year period beginning August 1, 2019, with debt carrying charges, which is included in the temporary rate increase.
On May 28, 2019, PSNH filed an application with the NHPUC for a permanent increase in base distribution rates of approximately $70 million, effective July 1, 2020, which includes the temporary rate increase request. The temporary rates are subject to reconciliation based on the outcome of the permanent rate case now before the NHPUC. The NHPUC is permitted up to twelve months to adjudicate the permanent rate application from the date of filing. On April 24, 2020, Governor Sununu issued an emergency order, which extends the maximum adjudication period by six months, for a maximum of 18 months. A decision by the NHPUC and other necessary regulatory agencies by late December 2017 or early 2018, with the transactions to be completed shortly thereafter. Upon completion, full recovery of PSNH's generation assets will occur through a combination of cash flows during the remaining operating period, sales proceeds, and recovery of stranded costs via bonds that will be secured by a non-bypassable charge or through recoveries in future rates billed to PSNH's customers.
As of September 30, 2017, PSNH's energy service rate base balance was approximately $594 million, and the carrying value of PSNH's total generation assets subject to divestiture was approximately $767 million.
Legislative and Policy Matters
On August 11, 2017, Massachusetts issued final legislation, pursuant to Executive Order 569, which established volumetric limits on multiple greenhouse emission sources to ensure reductions are realized by deadlines establishedis now expected in the Massachusetts Global Warming Solutions Act enactedfourth quarter of 2020. Temporary rates will remain in 2008. Under this legislation,effect with a reconciliation of permanent rates retroactive to July 1, 2019 once permanent rates are set.
Audit Report of Generation Asset Divestiture-Related Costs: On May 15, 2020, the initial target date for reduction in greenhouse gas emissions has been establishedNHPUC Audit Staff issued a final report on the audit of PSNH’s generation asset divestiture-related costs and resulting securitized and stranded costs. The findings in the yearaudit report as well as other aspects of the divestiture process were further investigated by NHPUC Staff through the discovery phase, which was completed in July. Technical sessions and settlement discussions will continue through the third quarter of 2020 and a final decision is expected by the end of 2020. The legislation is not expectedWe continue to have a material impact onbelieve the financial statementsamounts deferred are probable of Eversource, NSTAR Electric or WMECO.recovery.
Critical Accounting Policies
The preparation of financial statements in conformity with GAAP requires management to make estimates, assumptions and, at times, difficult, subjective or complex judgments. Changes in these estimates, assumptions and judgments, in and of themselves, could materially impact our financial position, results of operations or cash flows. Our management communicates to and discusses with the Audit Committee of our Board of Trustees significant matters relating to critical accounting policies. Our critical accounting policies that we believed were the most critical in nature were reported in the Eversource 20162019 Form 10-K. There have been no material changes with regard to these critical accounting policies.
Other Matters
Accounting Standards: For information regarding new accounting standards, see Note 1B, "Summary of Significant Accounting Policies –Accounting– Accounting Standards," to the financial statements.
Contractual Obligations and Commercial Commitments: There have been no material contractual obligations identified and no material changes
with regard to the contractual obligations and commercial commitments previously disclosed in the Eversource 20162019 Form 10-K.
Web Site: Additional financial information is available through our website at www.eversource.com. We make available through our website a link to the SEC's EDGAR website (http://www.sec.gov/edgar/searchedgar/companysearch.html), at which site Eversource's, CL&P's, NSTAR Electric's PSNH's and WMECO'sPSNH's combined Annual Reports on Form 10-K, combined Quarterly Reports on Form 10-Q, Current Reports on Form 8-K and any amendments to those reports may be reviewed. Information contained on the Company's website or that can be accessed through the website is not incorporated into and does not constitute a part of this combined Quarterly Report on Form 10-Q.
RESULTS OF OPERATIONS – EVERSOURCE ENERGY AND SUBSIDIARIES
The following provides the amounts and variances in operating revenues and expense line items in the statements of income for Eversource for the three and ninesix months ended SeptemberJune 30, 20172020 and 20162019 included in this combined Quarterly Report on Form 10-Q:
| | | | For the Three Months Ended September 30, | | For the Nine Months Ended September 30, | For the Three Months Ended June 30, | | For the Six Months Ended June 30, |
| (Millions of Dollars) | 2017 | | 2016 | | Increase/
(Decrease) | | Percent | | 2017 | | 2016 | | Increase/
(Decrease) | | Percent | 2020 | | 2019 | | Increase/
(Decrease) | | 2020 | | 2019 | | Increase/
(Decrease) |
| Operating Revenues | $ | 1,988.5 |
| | $ | 2,039.7 |
| | $ | (51.2 | ) | | (2.5 | )% | | $ | 5,856.5 |
| | $ | 5,862.5 |
| | $ | (6.0 | ) | | (0.1 | )% | $ | 1,953.1 |
| | $ | 1,884.5 |
| | $ | 68.6 |
| | $ | 4,326.9 |
| | $ | 4,300.3 |
| | $ | 26.6 |
|
| Operating Expenses: | |
| | |
| | |
| | |
| | | | |
| | |
| | |
| |
| | |
| | |
| | | | |
| | |
|
| Purchased Power, Fuel and Transmission | 651.8 |
| | 665.8 |
| | (14.0 | ) | | (2.1 | ) | | 1,955.1 |
| | 2,001.9 |
| | (46.8 | ) | | (2.3 | ) | 630.1 |
| | 620.9 |
| | 9.2 |
| | 1,506.7 |
| | 1,595.8 |
| | (89.1 | ) |
| Operations and Maintenance | 300.4 |
| | 324.7 |
| | (24.3 | ) | | (7.5 | ) | | 933.4 |
| | 965.6 |
| | (32.2 | ) | | (3.3 | ) | 332.1 |
| | 328.0 |
| | 4.1 |
| | 674.1 |
| | 663.6 |
| | 10.5 |
|
| Depreciation | 194.5 |
| | 181.3 |
| | 13.2 |
| | 7.3 |
| | 571.2 |
| | 531.8 |
| | 39.4 |
| | 7.4 |
| 240.5 |
| | 219.1 |
| | 21.4 |
| | 476.7 |
| | 434.0 |
| | 42.7 |
|
| Amortization of Regulatory Assets, Net | 41.8 |
| | 43.9 |
| | (2.1 | ) | | (4.8 | ) | | 58.1 |
| | 56.2 |
| | 1.9 |
| | 3.4 |
| |
| Amortization | | 23.4 |
| | 38.9 |
| | (15.5 | ) | | 73.2 |
| | 109.9 |
| | (36.7 | ) |
| Energy Efficiency Programs | 129.2 |
| | 149.1 |
| | (19.9 | ) | | (13.3 | ) | | 391.8 |
| | 406.0 |
| | (14.2 | ) | | (3.5 | ) | 115.4 |
| | 105.8 |
| | 9.6 |
| | 263.7 |
| | 246.0 |
| | 17.7 |
|
| Taxes Other Than Income Taxes | 168.2 |
| | 165.0 |
| | 3.2 |
| | 1.9 |
| | 479.6 |
| | 479.2 |
| | 0.4 |
| | 0.1 |
| 178.0 |
| | 181.2 |
| | (3.2 | ) | | 359.7 |
| | 365.7 |
| | (6.0 | ) |
| Impairment of Northern Pass Transmission | | — |
| | 239.6 |
| | (239.6 | ) | | — |
| | 239.6 |
| | (239.6 | ) |
| Total Operating Expenses | 1,485.9 |
| | 1,529.8 |
| | (43.9 | ) | | (2.9 | ) | | 4,389.2 |
| | 4,440.7 |
| | (51.5 | ) | | (1.2 | ) | 1,519.5 |
| | 1,733.5 |
| | (214.0 | ) | | 3,354.1 |
| | 3,654.6 |
| | (300.5 | ) |
| Operating Income | 502.6 |
| | 509.9 |
| | (7.3 | ) | | (1.4 | ) | | 1,467.3 |
| | 1,421.8 |
| | 45.5 |
| | 3.2 |
| 433.6 |
| | 151.0 |
| | 282.6 |
| | 972.8 |
| | 645.7 |
| | 327.1 |
|
| Interest Expense | 108.7 |
| | 99.9 |
| | 8.8 |
| | 8.8 |
| | 319.5 |
| | 298.6 |
| | 20.9 |
| | 7.0 |
| 134.2 |
| | 132.7 |
| | 1.5 |
| | 268.9 |
| | 264.5 |
| | 4.4 |
|
| Other Income, Net | 21.2 |
| | 13.6 |
| | 7.6 |
| | 55.9 |
| | 56.3 |
| | 23.7 |
| | 32.6 |
| | (a) |
| 30.2 |
| | 45.9 |
| | (15.7 | ) | | 54.3 |
| | 76.9 |
| | (22.6 | ) |
| Income Before Income Tax Expense | 415.1 |
| | 423.6 |
| | (8.5 | ) | | (2.0 | ) | | 1,204.1 |
| | 1,146.9 |
| | 57.2 |
| | 5.0 |
| 329.6 |
| | 64.2 |
| | 265.4 |
| | 758.2 |
| | 458.1 |
| | 300.1 |
|
| Income Tax Expense | 152.8 |
| | 156.4 |
| | (3.6 | ) | | (2.3 | ) | | 447.9 |
| | 428.2 |
| | 19.7 |
| | 4.6 |
| 75.5 |
| | 30.8 |
| | 44.7 |
| | 167.4 |
| | 114.2 |
| | 53.2 |
|
| Net Income | 262.3 |
| | 267.2 |
| | (4.9 | ) | | (1.8 | ) | | 756.2 |
| | 718.7 |
| | 37.5 |
| | 5.2 |
| 254.1 |
| | 33.4 |
| | 220.7 |
| | 590.8 |
| | 343.9 |
| | 246.9 |
|
| Net Income Attributable to Noncontrolling Interests | 1.9 |
| | 1.9 |
| | — |
| | — |
| | 5.6 |
| | 5.6 |
| | — |
| | — |
| 1.9 |
| | 1.9 |
| | — |
| | 3.8 |
| | 3.8 |
| | — |
|
| Net Income Attributable to Common Shareholders | $ | 260.4 |
| | $ | 265.3 |
| | $ | (4.9 | ) | | (1.8 | )% | | $ | 750.6 |
| | $ | 713.1 |
| | $ | 37.5 |
| | 5.3 | % | $ | 252.2 |
| | $ | 31.5 |
| | $ | 220.7 |
| | $ | 587.0 |
| | $ | 340.1 |
| | $ | 246.9 |
|
(a) Percent greater than 100 not shown as it is not meaningful.
Operating Revenues
A summary of our Operating Revenues by segment is as follows:
|
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | For the Three Months Ended September 30, | | For the Nine Months Ended September 30, |
| (Millions of Dollars) | 2017 | | 2016 | | Increase/
(Decrease) | | Percent | | 2017 | | 2016 | | Increase/
(Decrease) | | Percent |
| Electric Distribution | $ | 1,547.1 |
| | $ | 1,623.4 |
| | $ | (76.3 | ) | | (4.7 | )% | | $ | 4,224.2 |
| | $ | 4,362.6 |
| | $ | (138.4 | ) | | (3.2 | )% |
| Natural Gas Distribution | 109.2 |
| | 99.2 |
| | 10.0 |
| | 10.1 |
| | 698.8 |
| | 622.3 |
| | 76.5 |
| | 12.3 |
|
| Electric Transmission | 328.5 |
| | 306.8 |
| | 21.7 |
| | 7.1 |
| | 970.0 |
| | 892.5 |
| | 77.5 |
| | 8.7 |
|
| Other and Eliminations | 3.7 |
| | 10.3 |
| | (6.6 | ) | | (64.1 | ) | | (36.5 | ) | | (14.9 | ) | | (21.6 | ) | | (a) |
|
| Total Operating Revenues | $ | 1,988.5 |
| | $ | 2,039.7 |
| | $ | (51.2 | ) | | (2.5 | )% | | $ | 5,856.5 |
| | $ | 5,862.5 |
| | $ | (6.0 | ) | | (0.1 | )% |
(a) Percent greater than 100 not shown as it is not meaningful.
Sales Volumes:A summary of our retail electric GWh sales volumes, and our firm natural gas MMcf sales volumes, in MMcf wereand our water MG sales volumes, and percentage changes, is as follows:
|
| | | | | | | | | | | | | | | | | | | | | | | |
| | For the Three Months Ended September 30, | | For the Nine Months Ended September 30, |
| | 2017 | | 2016 | | Increase/ (Decrease) | | Percent | | 2017 | | 2016 | | Increase/ (Decrease) | | Percent |
| Electric | | | | | | | | | | | | | | | |
| Traditional | 7,545 |
| | 8,131 |
| | (586 | ) | | (7.2 | )% | | 21,040 |
| | 21,731 |
| | (691 | ) | | (3.2 | )% |
| Decoupled | 6,551 |
| | 7,213 |
| | (662 | ) | | (9.2 | ) | | 18,391 |
| | 19,235 |
| | (844 | ) | | (4.4 | ) |
| Total Electric | 14,096 |
| | 15,344 |
| | (1,248 | ) | | (8.1 | ) | | 39,431 |
| | 40,966 |
| | (1,535 | ) | | (3.7 | ) |
| | | | | | | | | | | | | | | | |
| Firm Natural Gas | | | | | |
| | | | | | | | |
| | |
| Traditional | 5,550 |
| | 5,270 |
| | 280 |
| | 5.3 |
| | 32,233 |
| | 31,570 |
| | 663 |
| | 2.1 |
|
| Decoupled and Special Contracts | 5,975 |
| | 5,653 |
| | 322 |
| | 5.7 |
| | 37,453 |
| | 36,537 |
| | 916 |
| | 2.5 |
|
| Total Firm Natural Gas | 11,525 |
| | 10,923 |
| | 602 |
| | 5.5 | % | | 69,686 |
| | 68,107 |
| | 1,579 |
| | 2.3 | % |
|
| | | | | | | | | | | | | | | | | | | | | | | | | | |
| | Electric | | Firm Natural Gas | | Water |
| | Sales Volumes (GWh) | | Percentage
Increase/(Decrease) | | Sales Volumes (MMcf) | | Percentage
Increase/(Decrease) | | Sales Volumes (MG) | | Percentage
Increase |
| Three Months Ended June 30: | 2020 | | 2019 | | | 2020 | | 2019 | | | 2020 | | 2019 | |
| Traditional | 1,789 |
| | 1,757 |
| | 1.8 | % | | — |
| | — |
| | — | % | | 482 |
| | 459 |
| | 5.0 | % |
Decoupled and Special Contracts (1) | 9,658 |
| | 9,853 |
| | (2.0 | )% | | 18,506 |
| | 18,191 |
| | 1.7 | % | | 5,185 |
| | 4,834 |
| | 7.3 | % |
| Total Sales Volumes | 11,447 |
| | 11,610 |
| | (1.4 | )% | | 18,506 |
| | 18,191 |
| | 1.7 | % | | 5,667 |
| | 5,293 |
| | 7.1 | % |
| | | | | | | | | | | | | | | | | | |
| Six Months Ended June 30: | | | | | | | | | | | | | | | | | |
| Traditional | 3,695 |
| | 3,724 |
| | (0.8 | )% | | — |
| | — |
| | — | % | | 916 |
| | 910 |
| | 0.7 | % |
Decoupled and Special Contracts (1) | 20,123 |
| | 21,037 |
| | (4.3 | )% | | 57,568 |
| | 63,358 |
| | (9.1 | )% | | 9,557 |
| | 9,212 |
| | 3.7 | % |
| Total Sales Volumes | 23,818 |
| | 24,761 |
| | (3.8 | )% | | 57,568 |
| | 63,358 |
| | (9.1 | )% | | 10,473 |
| | 10,122 |
| | 3.5 | % |
| |
(1) | Special contracts are unique to Yankee Gas natural gas distribution customers who take service under such an arrangement and generally specify the amount of distribution revenue to be paid to Yankee Gas regardless of the customers' usage. |
Three Months Ended:
Operating Revenues, which primarily consist of baseWeather, fluctuations in energy supply costs, conservation measures (including utility-sponsored energy efficiency programs), and economic conditions affect customer energy usage and water consumption. Industrial sales volumes are less sensitive to temperature variations than residential and commercial sales volumes. In our service territories, weather impacts both electric and water sales volumes during the summer and both electric and natural gas distribution revenues and tracked revenues further described below, decreased by $51.2 million forsales volumes during the three months ended September 30, 2017, as compared to the same period in 2016.
Base electric andwinter; however, natural gas distribution revenues: Base electric distribution segment revenues, excluding LBR, decreased $21.0 million for the three months ended September 30, 2017, as compared to the same period in 2016, due primarily to a decrease in sales volumes and lower demand revenues driven byare more sensitive to temperature variations than electric sales volumes. Customer heating or cooling usage may not directly correlate with historical levels or with the mild summer weather during the third quarterlevel of 2017 at NSTAR Electric and PSNH. LBR increased $1.5 million for the three months ended September 30, 2017, as compared to the same period in 2016. degree-days that occur.
Base natural gas distribution revenues remained relatively unchanged for the three months ended September 30, 2017, as compared to the same period in 2016.
Fluctuations in retail electric sales volumes at PSNH impact earnings ("Traditional" in the table above). For CL&P's, WMECO's&P, NSTAR Electric, Yankee Gas, NSTAR Gas and NSTAR Gas'our Connecticut water distribution business, fluctuations in retail sales volumes do not materially impact the level of base distribution revenue realized or earnings due to their respective regulatory commission approved revenue decoupling mechanisms. Thecommission-approved distribution revenue decoupling mechanisms permit recovery of a base amount of("Decoupled" in the table above). These distribution revenues and breakare decoupled from their customer sales volumes, which breaks the relationship between sales volumes and revenues recognized. Revenue decoupling mechanisms result
Operating Revenues: Operating Revenues by segment increased/(decreased) for the three and six months ended June 30, 2020, as compared to the same periods in 2019, as follows:
|
| | | | | | | |
| (Millions of Dollars) | Three Months Ended | | Six Months Ended |
| Electric Distribution | $ | 54.4 |
| | $ | 26.0 |
|
| Natural Gas Distribution | 3.5 |
| | (16.8 | ) |
| Electric Transmission | 27.1 |
| | 56.2 |
|
| Water Distribution | 1.8 |
| | 3.2 |
|
| Other | 33.0 |
| | 69.5 |
|
| Eliminations | (51.2 | ) | | (111.5 | ) |
| Total Operating Revenues | $ | 68.6 |
| | $ | 26.6 |
|
Electric and Natural Gas Distribution Revenues:
Base Distribution Revenues:
Base electric distribution revenues increased $32.1 million and $63.9 million for the three and six months ended June 30, 2020, as compared to the same periods in 2019, respectively, due primarily to the impact of a PSNH temporary base distribution rate increase effective July 1, 2019, which includes recovery of our approvedstorm costs and certain other items that do not impact earnings, CL&P's base distribution revenue requirements. rate increases effective May 1, 2020 and May 1, 2019, which include recovery of storm costs and certain other items that do not impact earnings, and an NSTAR Electric base distribution rate increase effective January 1, 2020.
Base natural gas distribution revenues increased $3.4 million and $12.0 million for the three and six months ended June 30, 2020, as compared to the same periods in 2019, respectively, due primarily to a base distribution rate increase at Yankee Gas effective January 1, 2020.
Tracked Distribution Revenues:Tracked distribution revenues: Tracked revenues consist of certain costs that are recovered from customers in retail rates through regulatory commission-approved cost tracking mechanisms and therefore, haverecovery of these costs has no impact on earnings. Costs recovered through cost tracking mechanisms include energy supply procurement costs and other energy-related costs for our electric and natural gas customers, retail transmission charges, energy efficiency program costs, and restructuring and stranded cost recovery revenues. In addition, certainHowever, tracked revenues do include certain incentives earned, return on rate base, and carrying charges that are billed in rates to customers. Tracked natural gas distribution segment revenues increased as a result of an increase incustomers, which do impact earnings. Costs recovered through cost tracking mechanisms include, among others, energy supply and natural gas supply procurement and other energy-related costs, ($7.6 million) and an increase inelectric retail transmission charges, energy efficiency program revenues ($2.2 million). Trackedcosts, electric distribution revenues decreased as a result of a decrease in retail electric transmission charges ($39.8 million), a decrease inrestructuring and stranded cost recovery revenues ($16.9 million)(including securitized RRB charges), a decrease in energy efficiency program revenues ($13.9 million) and a decrease inadditionally for NSTAR Electric, pension rate adjustment mechanisms ($7.1 million). Partially offsetting these decreases were increases in tracked electric distribution revenues related to electric energy supply costs ($7.3 million), revenues related to renewable energy requirements ($10.8 million),and PBOP benefits and net metering for distributed generation. Tracked revenues ($7.0 million)also include wholesale market sales transactions, such as sales of energy and federally-mandated congestion charges ($2.8 million).
Electric transmission revenues: The electric transmission segment revenues increased by $21.7 million due primarily toenergy-related products into the recovery of higher revenue requirements associated with ongoing investments in our transmission infrastructure.
Other: Other revenues decreased due primarily toISO-NE wholesale electricity market and the sale of Eversource's unregulated telecommunication business on December 31, 2016 ($5.0 million).RECs to various counterparties.
Nine Months Ended:
Operating Revenues decreased by $6.0 millionTracked distribution revenues increased/(decreased) for the ninethree and six months ended SeptemberJune 30, 2017,2020, as compared to the same periodperiods in 2016. 2019, due primarily to the following:
Base electric and natural gas distribution revenues: Base |
| | | | | | | | | | | | | | | |
| | Electric Distribution | | Natural Gas Distribution |
| (Millions of Dollars) | Three Months Ended | | Six Months Ended | | Three Months Ended | | Six Months Ended |
| Retail Tariff Tracked Revenues: | | | | | | | |
| Energy supply procurement | $ | (31.3 | ) | | $ | (142.3 | ) | | $ | (6.9 | ) | | $ | (34.9 | ) |
| Other distribution tracking mechanisms | 26.6 |
| | 25.7 |
| | 12.0 |
| | 22.8 |
|
| Wholesale Market Sales Revenue | 21.1 |
| | 60.7 |
| | (4.3 | ) | | (12.9 | ) |
The decrease in energy supply procurement within electric distribution segmentwas driven primarily by lower average prices for the three month period and lower average sales volumes and lower average prices for the six month period. The increase in wholesale market sales revenue within electric distribution was due primarily to a new zero-carbon PPA entered into by CL&P in 2019, as required by regulation, from which the energy purchased from Millstone Nuclear Power Station (Millstone) was sold into the market beginning in the fourth quarter of 2019.
Electric Transmission Revenues: Electric transmission revenues excluding LBR, decreased $13.2increased $27.1 million and $56.2 million for the ninethree and six months ended SeptemberJune 30, 2017,2020, as compared to the same periodperiods in 2016,2019, due primarily to continued investment in our transmission infrastructure and a decreasehigher benefit from the annual billing and cost reconciliation filing with FERC.
Other Revenues and Eliminations: Other revenues primarily include the revenues of Eversource's service company, most of which are eliminated in sales volumes driven byconsolidation. Eliminations are also primarily related to the mild summer weather duringEversource electric transmission revenues that are derived from ISO-NE regional transmission charges to the third quarterdistribution businesses of 2017 atCL&P, NSTAR Electric and PSNH. LBR increased $10.6 million forPSNH that recover the nine months ended September 30, 2017, as compared tocosts of the same period in 2016. wholesale transmission business.
Base natural gas distribution revenues remained relatively unchanged for the nine months ended September 30, 2017, as compared to the same period in 2016. The impact of higher firm natural gas sales volumes was offset by lower demand revenues in Connecticut driven by lower peak usage in 2017, as compared to 2016.
Tracked distribution revenues: Tracked natural gas distribution segment revenues increased as a result of an increase in natural gas supply costs ($57.8 million) and an increase in energy efficiency program revenues ($17.1 million). Tracked electric distribution revenues decreased as a result of a decrease in electric energy supply costs ($81.0 million), driven by decreased average retail prices and lower sales volumes, a decrease in retail electric transmission charges ($45.9 million), a decrease in transition and stranded cost recovery revenues ($33.1 million), a decrease in pension rate adjustment mechanisms ($16.2 million), and a decrease in energy efficiency program revenues ($8.8 million). Partially offsetting these decreases were increases in tracked electric distribution revenues related to federally-mandated congestion charges ($23.0 million), net metering revenues ($22.4 million) and revenues related to renewable energy requirements and the sale of PSNH's RECs ($14.7 million).
Electric transmission revenues: The electric transmission segment revenues increased by $77.5 million due primarily to the recovery of higher revenue requirements associated with ongoing investments in our transmission infrastructure.
Other: Other revenues decreased due primarily to the sale of Eversource's unregulated telecommunication business on December 31, 2016 ($15.0 million).
Purchased Power, Fuel and Transmissionexpense includes costs associated with purchasing electricity and natural gas on behalf of our customers. These energyelectric and natural gas supply costs are recovered from customers in rates through commission-approved cost tracking mechanisms, which have no impact on earnings (tracked costs). Total Purchased Power, Fuel and Transmission expense decreasedincreased/(decreased) for the three and ninesix months ended SeptemberJune 30, 2017,2020, as compared to the same periods in 2016,2019, due primarily to the following:
|
| | | | | | | |
| (Millions of Dollars) | Three Months Ended Increase/(Decrease) | | Nine Months Ended
Increase/(Decrease) |
| Electric Distribution | $ | (0.4 | ) | | $ | (109.1 | ) |
| Natural Gas Distribution | 7.0 |
| | 50.1 |
|
| Transmission | (20.6 | ) | | 12.2 |
|
| Total Purchased Power, Fuel and Transmission | $ | (14.0 | ) | | $ | (46.8 | ) |
|
| | | | | | | |
| (Millions of Dollars) | Three Months Ended | | Six Months Ended |
| Purchased Power Costs | $ | 47.1 |
| | $ | 23.1 |
|
| Natural Gas Costs | (10.9 | ) | | (45.8 | ) |
| Transmission Costs | (3.9 | ) | | (18.2 | ) |
| Eliminations | (23.1 | ) | | (48.2 | ) |
| Total Purchased Power, Fuel and Transmission | $ | 9.2 |
| | $ | (89.1 | ) |
The decreaseincrease in purchased power expense at the electric distribution business for the ninethree months ended SeptemberJune 30, 2017,2020, as compared to the same period in 2016,2019, was driven primarily by the impact of energy purchases from the new Millstone PPA, partially offset by lower prices associated withexpense related to the procurement of energy supply andresulting from lower sales volumes.average prices. The increase in purchased power expense at the electric distribution business for the six months ended June 30, 2020, as compared to the same period in 2019, was driven primarily by the impact of energy purchases from the new Millstone PPA, partially offset by lower expense related to the procurement of energy supply resulting from lower average sales volumes and lower average prices.
The decrease in natural gas supply costs at our natural gas distribution business for each of the periods presentedthree months ended June 30, 2020, as compared to the same period in 2019, was due primarily to lower average prices, partially offset by higher average sales volumes. The decrease in natural gas pricessupply costs for the six months ended June 30, 2020, as compared to the same period in 2019, was due primarily to lower average sales volumes and higher sales volumes. lower average prices.
The decrease in transmission costs for the three months ended SeptemberJune 30, 2017,2020, as compared to the same period in 2016,2019, was primarily the result of a decrease in the retail transmission cost deferral, which reflects the actual costs of transmission service compared to estimated amounts billed to customers. The increase in transmission costs for the nine months ended September 30, 2017, as compared to the same period in 2016,This was primarily the result ofpartially offset by an increase in costs billed by ISO-NE that support regional grid investment, and Local Network Service charges, which reflectreflects the cost of transmission service provided by Eversource over our local transmission network and an increase in costs billed by ISO-NE that support regional grid investments.
The decrease in transmission costs for the six months ended June 30, 2020, as compared to the same period in 2019, was primarily the result of a decrease in the retail transmission cost deferral, and a decrease in costs billed by ISO-NE that support regional grid investments. This was partially offset by an increase in Local Network Service charges, which reflects the cost of transmission service provided by Eversource over our local transmission network.
Operations and Maintenance expense includes tracked costs and costs that are part of base electric, natural gas and water distribution rates with changes impacting earnings (non-tracked costs). Operations and Maintenance expense increased/(decreased) for the three and six months ended June 30, 2020, as compared to the same periods in 2019, due primarily to the following: |
| | | | | | | |
| (Millions of Dollars) | Three Months Ended | | Six Months Ended |
| Base Electric Distribution (Non-Tracked Costs): | | | |
| Employee-related expenses, including labor and benefits | $ | (7.4 | ) | | $ | (9.8 | ) |
| Operations-related expenses, including vegetation management, storm restoration, vehicles, and outside services | 12.5 |
| | 4.5 |
|
| Shared corporate costs (including computer software depreciation at Eversource Service) | 5.6 |
| | 10.8 |
|
| COVID-19 Costs | 5.5 |
| | 6.7 |
|
| Other non-tracked operations and maintenance | (3.1 | ) |
| (1.0 | ) |
| Total Base Electric Distribution (Non-Tracked Costs) | 13.1 |
|
| 11.2 |
|
| Base Natural Gas Distribution (Non-Tracked Costs) | 1.2 |
| | 2.4 |
|
| Water Distribution | 0.2 |
| | (0.1 | ) |
| Tracked Costs (Electric Distribution, Electric Transmission and Natural Gas Distribution) | (3.4 | ) |
| 7.3 |
|
| Other and eliminations: | | | |
| Eversource Parent and Other Companies - other operations and maintenance | 18.7 |
| | 45.1 |
|
| Acquisition costs related to our planned purchase of the assets of CMA | 5.4 |
| | 10.3 |
|
| Eliminations | (31.1 | ) | | (65.7 | ) |
| Total Operations and Maintenance | $ | 4.1 |
|
| $ | 10.5 |
|
Depreciation expense increased for the three and six months ended June 30, 2020, as compared to the same periods in 2019, due to higher utility plant in service balances.
Amortization expense includes the deferral of energy supply, energy-related costs and other costs that are included in certain regulatory commission-approved cost tracking mechanisms, and the amortization of certain costs as those costs are collected in rates. This deferral adjusts expense to match the corresponding revenues. Energy supply and energy-related costs are recovered from customers in rates and have no impact on earnings. Amortization decreased for the three and six months ended June 30, 2020, as compared to the same periods in 2019, due primarily to the under recovery of energy purchases related to the Millstone PPA and deferral of energy supply and energy-related costs at CL&P, partially offset by an increase in storm cost recovery at PSNH.
Energy Efficiency Programs expense increased for the three and six months ended June 30, 2020, as compared to the same periods in 2019, due primarily to the deferral adjustment at CL&P, PSNH and NSTAR Gas, which reflects the actual costs of energy efficiency programs compared to the amounts billed to customers and the timing of the recovery of energy efficiency costs. The increase was partially offset by a decrease in spending on certain large energy efficiency projects in 2020 compared to 2019 at NSTAR Electric due to timing. The costs for the majority of the state energy policy initiatives and expanded energy efficiency programs are recovered from customers in rates and have no impact on earnings.
Taxes Other Than Income Taxes expense decreased for the three and six months ended June 30, 2020, as compared to the same periods in 2019, due primarily to a decrease of $10.7 million and $21.4 million related to CL&P's remittance of energy efficiency funds to the State of Connecticut, respectively. Energy efficiency funds collected from customers after July 1, 2019 are no longer subject to remittance to the State of Connecticut. The decrease is partially offset by an increase in property taxes as a result of higher utility plant balances.
Interest Expense increased for the three and six months ended June 30, 2020, as compared to the same periods in 2019, due primarily to an increase in interest on long-term debt as a result of new debt issuances ($6.6 million and $13.4 million, respectively) and an increase in interest expense on regulatory deferrals ($1.5 million and $3.2 million, respectively). Partially offsetting these increases were a decrease in interest on notes payable ($6.5 million and $8.8 million, respectively) and an increase in AFUDC related to debt funds and other capitalized interest ($0.4 million and $3.5 million, respectively).
Other Income, Net decreased for the three and six months ended June 30, 2020, as compared to the same periods in 2019, due primarily to a decrease in equity in earnings related to Eversource's equity method investments ($20.0 million and $21.1 million, respectively), partially offset by an increase related to pension, SERP and PBOP non-service income components ($4.9 million and $10.3 million, respectively).
Other Income, Net further decreased for the six month period due to the absence in 2020 of the recognition of the equity component of the carrying charges related to PSNH storm costs recorded in interest income in the first quarter of 2019 ($5.2 million), and investment losses in 2020, as compared to investment income in 2019 driven by market volatility ($3.1 million).
Income Tax Expense increased for the three months ended June 30, 2020, as compared to the same period in 2019, due primarily to higher pre-tax earnings ($5.4 million), higher state taxes ($3.0 million), by the absence in 2020 of the impairment of NPT ($35.2 million), and an increase in items that impact our tax rate as a result of regulatory treatment (flow-through items) and permanent differences ($2.5 million), partially offset by an increase in share-based payment excess tax benefits ($0.4 million) and an increase in amortization of EDIT ($1.0 million).
Income Tax Expense increased for the six months ended June 30, 2020, as compared to the same period in 2019, due primarily to higher pre-tax earnings ($12.7 million), higher state taxes ($8.0 million), by the absence in 2020 of the impairment of NPT ($35.2 million), and an increase in flow-through items and permanent differences ($5.1 million), partially offset by an increase in share-based payment excess tax benefits ($5.1 million) and an increase in amortization of EDIT ($2.7 million).
RESULTS OF OPERATIONS –
THE CONNECTICUT LIGHT AND POWER COMPANY
NSTAR ELECTRIC COMPANY AND SUBSIDIARY
PUBLIC SERVICE COMPANY OF NEW HAMPSHIRE AND SUBSIDIARIES
The following provides the amounts and variances in operating revenues and expense line items in the statements of income for CL&P, NSTAR Electric and PSNH for the six months ended June 30, 2020 and 2019 included in this combined Quarterly Report on Form 10-Q:
|
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | For the Six Months Ended June 30, |
| | CL&P | | NSTAR Electric | | PSNH |
| (Millions of Dollars) | 2020 | | 2019 | | Increase/
(Decrease) | | 2020 | | 2019 | | Increase/ (Decrease) | | 2020 | | 2019 | | Increase/ (Decrease) |
| Operating Revenues | $ | 1,717.1 |
| | $ | 1,590.1 |
| | $ | 127.0 |
| | $ | 1,394.8 |
| | $ | 1,479.5 |
| | $ | (84.7 | ) | | $ | 531.6 |
| | $ | 517.3 |
| | $ | 14.3 |
|
| Operating Expenses: | |
| | |
| | |
| | | | | | |
| | | | | | |
|
| Purchased Power and Transmission | 690.1 |
| | 566.4 |
| | 123.7 |
| | 434.7 |
| | 558.5 |
| | (123.8 | ) | | 176.7 |
| | 199.3 |
| | (22.6 | ) |
| Operations and Maintenance | 270.2 |
| | 264.0 |
| | 6.2 |
| | 238.1 |
| | 221.9 |
| | 16.2 |
| | 101.1 |
| | 105.4 |
| | (4.3 | ) |
| Depreciation | 158.2 |
| | 147.8 |
| | 10.4 |
| | 157.9 |
| | 145.6 |
| | 12.3 |
| | 49.1 |
| | 46.2 |
| | 2.9 |
|
| Amortization of Regulatory Assets, Net | 0.9 |
| | 48.0 |
| | (47.1 | ) | | 46.6 |
| | 45.8 |
| | 0.8 |
| | 31.7 |
| | 19.5 |
| | 12.2 |
|
| Energy Efficiency Programs | 67.8 |
| | 46.8 |
| | 21.0 |
| | 125.4 |
| | 142.6 |
| | (17.2 | ) | | 18.2 |
| | 12.9 |
| | 5.3 |
|
| Taxes Other Than Income Taxes | 162.8 |
| | 178.5 |
| | (15.7 | ) | | 99.4 |
| | 93.1 |
| | 6.3 |
| | 40.1 |
| | 38.0 |
| | 2.1 |
|
| Total Operating Expenses | 1,350.0 |
| | 1,251.5 |
| | 98.5 |
| | 1,102.1 |
| | 1,207.5 |
| | (105.4 | ) | | 416.9 |
| | 421.3 |
| | (4.4 | ) |
| Operating Income | 367.1 |
| | 338.6 |
| | 28.5 |
| | 292.7 |
| | 272.0 |
| | 20.7 |
| | 114.7 |
| | 96.0 |
| | 18.7 |
|
| Interest Expense | 76.7 |
| | 72.7 |
| | 4.0 |
| | 64.0 |
| | 56.1 |
| | 7.9 |
| | 29.1 |
| | 28.3 |
| | 0.8 |
|
| Other Income, Net | 10.4 |
| | 6.7 |
| | 3.7 |
| | 25.4 |
| | 21.7 |
| | 3.7 |
| | 6.8 |
| | 10.0 |
| | (3.2 | ) |
| Income Before Income Tax Expense | 300.8 |
| | 272.6 |
| | 28.2 |
| | 254.1 |
| | 237.6 |
| | 16.5 |
| | 92.4 |
| | 77.7 |
| | 14.7 |
|
| Income Tax Expense | 64.8 |
| | 57.3 |
| | 7.5 |
| | 56.2 |
| | 53.9 |
| | 2.3 |
| | 21.2 |
| | 18.1 |
| | 3.1 |
|
| Net Income | $ | 236.0 |
| | $ | 215.3 |
| | $ | 20.7 |
| | $ | 197.9 |
| | $ | 183.7 |
| | $ | 14.2 |
| | $ | 71.2 |
| | $ | 59.6 |
| | $ | 11.6 |
|
Operating Revenues
Sales Volumes: A summary of our retail electric GWh sales volumes is as follows:
|
| | | | | | | | | | | |
| | For the Six Months Ended June 30, |
| | 2020 | | 2019 | | Decrease | | Percentage Decrease |
| CL&P | 9,520 |
| | 9,953 |
| | (433 | ) | | (4.4 | )% |
| NSTAR Electric | 10,603 |
| | 11,084 |
| | (481 | ) | | (4.3 | )% |
| PSNH | 3,695 |
| | 3,724 |
| | (29 | ) | | (0.8 | )% |
Fluctuations in retail electric sales volumes at PSNH impact earnings. For CL&P and NSTAR Electric, fluctuations in retail electric sales volumes do not impact earnings due to their respective regulatory commission-approved distribution revenue decoupling mechanisms.
Operating Revenues: Operating Revenues, which consist of base distribution revenues and tracked revenues further described below, increased $127.0 million at CL&P and $14.3 million at PSNH, and decreased $84.7 million at NSTAR Electric, for the six months ended June 30, 2020, as compared to the same period in 2019.
Base Distribution Revenues:
CL&P's distribution revenues increased $22.8 million due primarily to the impact of its base distribution rate increases effective May 1, 2020 and May 1, 2019, which includes recovery of storm costs and certain other items that do not impact earnings.
NSTAR Electric's distribution revenues increased $14.9 million due primarily to the impact of its base distribution rate increase effective January 1, 2020.
PSNH's distribution revenues increased $26.2 million due primarily to the impact of its temporary base distribution rate increase effective July 1, 2019, which includes recovery of storm costs and certain other items that do not impact earnings.
Tracked Revenues: Tracked distribution revenues consist of certain costs that are recovered from customers in retail rates through regulatory commission-approved cost tracking mechanisms and therefore, recovery of these costs has no impact on earnings. However, tracked revenues do include certain incentives earned, return on rate base, and carrying charges that are billed in rates to customers, which do impact earnings. Costs recovered through cost tracking mechanisms include, among others, energy supply procurement and other energy-related costs, retail transmission charges, energy efficiency program costs, electric restructuring and stranded cost recovery revenues (including securitized RRB charges), and additionally for NSTAR Electric, pension and PBOP benefits and net metering for distributed generation. Tracked revenues also include wholesale market sales transactions, such as sales of energy and energy-related products into the ISO-NE wholesale electricity market and the sale of RECs to various counterparties.
Tracked revenues increased/(decreased) for the six months ended June 30, 2020, as compared to the same period in 2019, due primarily to the following:
|
| | | | | | | | | | | |
| (Millions of Dollars) | CL&P | | NSTAR Electric | | PSNH |
| Retail Tariff Tracked Revenues: | | | | | |
| Energy supply procurement | $ | (46.1 | ) | | $ | (79.1 | ) | | $ | (17.1 | ) |
| CL&P FMCC | 40.8 |
| | — |
| | — |
|
| Other distribution tracking mechanisms | 16.0 |
| | (33.2 | ) | | 2.1 |
|
| Wholesale Market Sales Revenue | 78.2 |
| | (14.0 | ) | | (3.5 | ) |
The decreases in energy supply procurement at CL&P and NSTAR Electric reflect both lower average sales volumes and lower average prices and at PSNH reflect lower average prices for the six months ended June 30, 2020, as compared to the same period in 2019.
Revenues from CL&P's other distribution tracking mechanisms include higher earnings from its capital tracker mechanism due to increased electric system improvements. CL&P's wholesale market sales revenue increased due primarily to energy sold in the wholesale market resulting from energy purchased from the new Millstone PPA.
Transmission Revenues: Transmission revenues increased $20.0 million at CL&P, $24.8 million at NSTAR Electric, and $11.4 million at PSNH for the six months ended June 30, 2020, as compared to the same period in 2019, due primarily to continued investment in our transmission infrastructure and a higher benefit from the annual billing and cost reconciliation filing with FERC.
Eliminations: Eliminations are primarily related to the Eversource electric transmission revenues that are derived from ISO-NE regional transmission charges to the distribution businesses of CL&P, NSTAR Electric and PSNH that recover the costs of the wholesale transmission business. The impact of eliminations decreased revenues by $6.1 million at CL&P, $15.6 million at NSTAR Electric and $3.9 million at PSNH for the six months ended June 30, 2020, as compared to the same period in 2019.
Purchased Power and Transmission expense includes costs associated with purchasing electricity on behalf of CL&P, NSTAR Electric and PSNH's customers. These energy supply costs are recovered from customers in rates through commission-approved cost tracking mechanisms, which have no impact on earnings (tracked costs). Purchased Power and Transmission expense increased/(decreased) for the six months ended June 30, 2020, as compared to the same period in 2019, due primarily to the following:
|
| | | | | | | | | | | |
| (Millions of Dollars) | CL&P | | NSTAR Electric | | PSNH |
| Purchased Power Costs | $ | 149.0 |
| | $ | (102.3 | ) | | $ | (23.6 | ) |
| Transmission Costs | (17.3 | ) | | (5.9 | ) | | 5.0 |
|
| Eliminations | (8.0 | ) | | (15.6 | ) | | (4.0 | ) |
| Total Purchased Power and Transmission | $ | 123.7 |
| | $ | (123.8 | ) | | $ | (22.6 | ) |
Purchased Power Costs: Included in purchased power costs are the costs associated with providing electric generation service supply to all customers who have not migrated to third party suppliers and the cost of energy purchase contracts, as required by regulation.
The increase at CL&P was due primarily to the new Millstone PPA energy purchases, partially offset by lower expense related to the procurement of energy supply resulting from lower average sales volumes and lower average prices.
The decrease at NSTAR Electric was due primarily to lower expense related to the procurement of energy supply resulting from lower average sales volumes and lower average prices.
The decrease at PSNH was due primarily to lower expense related to the procurement of energy supply resulting from lower average prices.
Transmission Costs: Included in transmission costs are charges that recover the cost of transporting electricity over high-voltage lines from generation facilities to substations, including costs allocated by ISO-NE to maintain the wholesale electric market.
The decrease in transmission costs at CL&P and NSTAR Electric was due primarily to a reduction to the retail transmission cost deferral, which reflects the actual costs of transmission service compared to estimated amounts billed to customers and a decrease in costs billed by ISO-NE that support regional grid investments. This was partially offset by an increase in Local Network Service charges, which reflects the cost of transmission service provided by Eversource over our local transmission network.
The increase in transmission costs at PSNH was primarily the result of an increase in Local Network Service charges and an increase in costs billed by ISO-NE that support regional grid investments. This was partially offset by a decrease in the retail transmission cost deferral.
Operations and Maintenance expense includes tracked costs and costs that are part of base electric and natural gas distribution rates with changes impacting earnings (non-tracked costs). Operations and Maintenance expense decreasedincreased/(decreased) for the three and ninesix months ended SeptemberJune 30, 2017,2020, as compared to the same periodsperiod in 2016,2019, due primarily to the following:
|
| | | | | | | |
| (Millions of Dollars) | Three Months Ended Increase/(Decrease) | | Nine Months Ended Increase/(Decrease) |
| Base Electric Distribution: | | | |
| Employee-related expenses, including labor and benefits | $ | (15.0 | ) | | $ | (46.2 | ) |
| Bad debt expense | (2.6 | ) | | (15.3 | ) |
| Shared corporate costs (including computer software depreciation at Eversource Service) | 5.4 |
| | 15.0 |
|
| Storm restoration costs | (4.0 | ) | | 3.1 |
|
| Boston Harbor civil action settlement charge recorded in the second quarter of 2017 | — |
| | 4.9 |
|
| Other operations and maintenance | 9.1 |
| | 15.7 |
|
| Total Base Electric Distribution | (7.1 | ) | | (22.8 | ) |
| Total Base Natural Gas Distribution: | | | |
| Shared corporate costs (including computer software depreciation at Eversource Service) | 1.2 |
| | 3.6 |
|
| Other operations and maintenance | (4.1 | ) | | (1.5 | ) |
| Total Base Natural Gas Distribution | (2.9 | ) | | 2.1 |
|
| Total Tracked costs (Electric Distribution, Electric Transmission and Natural Gas Distribution) | (5.5 | ) | | 7.2 |
|
| Other and eliminations: | | | |
| Eversource Parent and Other Companies | (1.1 | ) | | 0.8 |
|
| Eliminations | (7.7 | ) | | (19.5 | ) |
| Total Operations and Maintenance | $ | (24.3 | ) | | $ | (32.2 | ) |
|
| | | | | | | | | | | |
| (Millions of Dollars) | CL&P | | NSTAR Electric | | PSNH |
| Base Electric Distribution (Non-Tracked Costs): | | | | | |
| Employee-related expenses, including labor and benefits | $ | 0.7 |
| | $ | (7.8 | ) | | $ | (2.7 | ) |
| Operations-related expenses, including vegetation management, storm restoration, vehicles, and outside services | (0.5 | ) | | 0.6 |
| | 4.4 |
|
| Shared corporate costs (including computer software depreciation at Eversource Service) | 4.3 |
| | 5.1 |
| | 1.4 |
|
| COVID-19 Costs | 2.8 |
| | 2.8 |
| | 1.1 |
|
| Other non-tracked operations and maintenance | (3.3 | ) | | 1.4 |
| | 0.9 |
|
| Total Base Electric Distribution (Non-Tracked Costs) | 4.0 |
| | 2.1 |
| | 5.1 |
|
| Tracked Costs: | | | | | |
| Transmission expenses | (4.7 | ) | | 3.9 |
| | (1.3 | ) |
| Other tracked operations and maintenance | 6.9 |
| | 10.2 |
| | (8.1 | ) |
| Total Tracked Costs | 2.2 |
| | 14.1 |
| | (9.4 | ) |
| Total Operations and Maintenance | $ | 6.2 |
| | $ | 16.2 |
| | $ | (4.3 | ) |
Depreciation expense increased for the three and ninesix months ended SeptemberJune 30, 2017,2020, as compared to the same periodsperiod in 2016,2019, for CL&P, NSTAR Electric and PSNH due primarily to higher utilitynet plant in service balances.
Amortization of Regulatory Assets, Net expense includes the deferral of energy supply, and energy-related costs and other costs that are included in certain regulatory-approved cost tracking mechanisms, and the amortization of certain costs. Thecosts as those costs are collected in rates. This deferral adjusts expense to match the corresponding revenues. Energy supply and energy-related costs are recovered from customers in rates and have no impact on earnings. Amortization of Regulatory Assets, Net increased/decreased for the threesix months ended SeptemberJune 30, 2017 and increased for the nine months ended September 30, 2017,2020, as compared to the same periodsperiod in 2016,2019, due primarily to the following:
The decrease at CL&P was due primarily to the under recovery of energy purchases related to the Millstone PPA and deferral of energy supply and energy-related costs, which can fluctuate from period to period based on the timing of costs incurred and the related rate changes to recover these costs. Energy
The increase at PSNH was due to an increase in storm cost recovery, partially offset by the deferral of energy supply and energy-relatedenergy related costs.
Energy Efficiency Programs expenseincludes costs at CL&P, NSTAR Electric, PSNHof various state energy policy initiatives and WMECO, which are the primary drivers in amortization,expanded energy efficiency programs that are recovered from customers in rates, andmost of which have no impact on earnings.
Energy Efficiency Programs expenseincreased/decreased for the three and ninesix months ended SeptemberJune 30, 2017,2020, as compared to the same periodsperiod in 2016,2019, due primarily to deferral adjustmentsthe following:
The increase at CL&P NSTAR Electric and WMECO, partially offset byPSNH was due to the deferral adjustments at the natural gas businesses,adjustment, which reflect thereflects actual costs of energy efficiency programs compared to the estimated amounts billed to customers. The deferral adjusts costs incurred to match energy efficiency revenue billed to customers and the timing of the recovery of energy efficiency costs.
The costs for various state policy initiatives are recovered from customersdecrease at NSTAR Electric was due to the timing of spending on certain large energy efficiency projects in rates and have no impact on earnings.2020, as compared to 2019.
Interest Expense increasedTaxes Other Than Income Taxes increased/decreased for the three and ninesix months ended SeptemberJune 30, 2017,2020, as compared to the same periodsperiod in 2016,2019, due primarily to the following:
The decrease at CL&P was related to a $21.4 million decrease in the remittance of energy efficiency funds to the State of Connecticut. Energy efficiency funds collected from customers after July 1, 2019 are no longer subject to remittance to the State of Connecticut. The decrease was partially offset by higher property taxes as a result of higher utility plant balances.
The increases at NSTAR Electric and PSNH were due to higher property taxes as a result of higher utility plant balances.
Interest Expense increased for the six months ended June 30, 2020, as compared to the same period in 2019, due primarily to the following:
The increase at CL&P was due to higher interest on long-term debt ($5.8 million and $15.9 million, respectively) as a result of new5.0 million), partially offset by an increase in AFUDC related to debt issuances,funds ($0.3 million).
| |
| • | Theincrease at NSTAR Electric was due to higher interest on long-term debt ($7.5 million), an increase in interest expense on regulatory deferrals ($3.5 million), and a decrease in AFUDC related to debt funds ($0.6 million). Partially offsetting these increases was a decrease in interest on notes payable ($2.6 million). |
The increase at PSNH was due to higher interest on short-termlong-term debt ($2.4 million1.9 million), partially offset by a decrease on RRB interest expense ($0.7 million) and $4.8 million, respectively)a decrease in interest expense on regulatory deferrals ($0.6 million).
Other Income, Net increasedincreased/decreased for the three and ninesix months ended SeptemberJune 30, 2017,2020, as compared to the same periodsperiod in 2016,2019, due primarily to increased gains on investments ($4.2 million and $24.9 million, respectively), primarilythe following:
The increase at CL&P was due to an increase related to Eversource's investmentpension, SERP and PBOP non-service income components ($3.7 million) and an increase in a renewable energy fund, market value changesAFUDC related to the deferred compensation plansequity funds ($2.9 million2.1 million), partially offset by investment losses in 2020, as compared to investment income in 2019 driven by market volatility ($3.0 million).
The increase at NSTAR Electric was due to an increase related to pension, SERP and $5.1 million, respectively)PBOP non-service income components ($2.6 million) and higheran increase in AFUDC related to equity funds ($1.2 millionmillion), partially offset by higher investment losses driven by market volatility ($0.7 million).
The decrease at PSNH was due to the absence in 2020 of the recognition of the equity component of the carrying charges related to storm costs recorded in interest income in 2019 ($5.2 million) and $5.0 million, respectively)investment losses in 2020, as compared to investment income in 2019 driven by market volatility ($0.4 million). Partially offsetting these decreases were an increase related to pension, SERP and PBOP non-service income components ($1.5 million) and an increase in AFUDC related to equity funds ($1.5 million).
Income Tax Expense decreased increased for the threesix months ended SeptemberJune 30, 2017,2020, as compared to the same period in 2016,2019, due primarily to lowerthe following:
The increase at CL&P was due primarily to higher pre-tax earnings ($2.45.9 million), higher state taxes ($1.0 million) and by items that impact our tax rate as a result of regulatory treatment (flow-through items) and permanent differences ($1.22.4 million), partially offset by an increase in share-based payment excess tax benefits ($1.8 million).
The increase at NSTAR Electric was due primarily to higher pre-tax earnings ($3.5 million) and higher state taxes ($1.1 million), partially offset by items that impact our tax rate as a result of regulatory treatment (flow-through items) and permanent differences ($0.5 million), and an increase in share-based payment excess tax benefits ($1.8 million).
Income Tax ExpenseThe increase at PSNH was due primarily to higher pre-tax earnings ($3.0 million) and higher state taxes ($0.9 million), partially offset by an increase in share-based payment excess tax benefits ($0.6 million) and in items that impact our tax rate as a result of regulatory treatment (flow-through items) and permanent differences ($0.2 million).
EARNINGS SUMMARY
CL&P's earnings increased $20.7 millionfor the ninesix months ended SeptemberJune 30, 2017,2020, as compared to the same period in 2016,2019, due primarily to an increase in transmission earnings driven by a higher pre-taxtransmission rate base, the base distribution rate increases effective May 1, 2020 and May 1, 2019, and higher earnings ($20.6 million),from its capital tracker mechanism due to increased electric system improvements. The earnings increase was partially offset by higher depreciation expense, higher operations and maintenance expense, and higher interest expense.
NSTAR Electric's earnings increased $14.2 million for the six months ended June 30, 2020, as compared to the same period in 2019, due primarily to the base distribution rate increase effective January 1, 2020 and an increase in transmission earnings driven by a higher transmission rate base. The earnings increase was partially offset by higher depreciation expense, higher interest expense, and higher property tax expense.
PSNH's earnings increased $11.6 million for the six months ended June 30, 2020, as compared to the same period in 2019, due primarily to the temporary base distribution rate increase effective July 1, 2019, and an increase in transmission earnings driven by a higher transmission rate base. The earnings increase was partially offset by the absence of a tax credit in 2017 ($2.4 million),the first quarter 2019 recognition of carrying charges on its 2013 through 2016 storm costs approved for recovery and higher state taxes ($1.3 million), partially offsetoperations and maintenance expense.
LIQUIDITY
Cash Flows: CL&P had cash flows provided by flow-through itemsoperating activities of $282.9 million for the six months ended June 30, 2020, as compared to $345.6 million in the same period of 2019. The decrease in operating cash flows was due primarily to the timing of cash payments made on our accounts payable and permanent differences ($4.6 million).the timing of cash collections on our accounts receivable and regulatory tracking mechanisms. Partially offsetting these unfavorable impacts were income tax refunds received of $26.4 million in the first half of 2020, as compared to income tax payments of $3.9 million in the same period in 2019 driven primarily by the deferral of estimated tax payments from the second quarter of 2020 to July 2020 under COVID-19 relief legislation.
NSTAR Electric had cash flows provided by operating activities of $212.8 million for the six months ended June 30, 2020, as compared to $251.5 million in the same period of 2019. The decrease in operating cash flows was due primarily to the timing of collections for regulatory tracking mechanisms primarily related to transmission costs and the timing of cash collections on our accounts receivable. Partially offsetting these unfavorable impacts were the timing of cash payments made on our accounts payable and income tax refunds received of $10.9 million in the first half of 2020, as compared to income tax payments of $10.9 million in the same period in 2019 driven by the deferral of estimated tax payments under COVID-19 relief legislation.
PSNH had cash flows provided by operating activities of $118.8 million for the six months ended June 30, 2020, as compared to $121.7 million in the same period of 2019. The decrease in operating cash flows was due primarily to income tax payments of $4.8 million in the first half of 2020, as compared to income tax refunds received of $11.8 million in the same period in 2019, the timing of REC inventories and the timing of cash collections on our accounts receivable. Partially offsetting these unfavorable impacts were the temporary base distribution rate increase effective July 1, 2019 and the timing of cash payments on our accounts payable and other working capital items.
For further information on CL&P's, NSTAR Electric's and PSNH's liquidity and capital resources, see "Liquidity" and "Business Development and Capital Expenditures" included in this Management's Discussion and Analysis of Financial Condition and Results of Operations.
RESULTS OF OPERATIONS – THE CONNECTICUT LIGHT AND POWER COMPANY
The following provides the amounts and variances in operating revenues and expense line items in the statements of income for CL&P for the three and nine months ended SeptemberJune 30, 20172020 and 20162019 included in this combined Quarterly Report on Form 10-Q:
| | | | For the Three Months Ended September 30, | | For the Nine Months Ended September 30, | For the Three Months Ended June 30, |
| (Millions of Dollars) | 2017 | | 2016 | | Increase/
(Decrease) | | Percent | | 2017 | | 2016 | | Increase/ (Decrease) | | Percent | 2020 | | 2019 | | Increase/(Decrease) |
| Operating Revenues | $ | 774.8 |
| | $ | 760.0 |
| | $ | 14.8 |
| | 1.9 | % | | $ | 2,173.6 |
| | $ | 2,175.1 |
| | $ | (1.5 | ) | | (0.1 | )% | $ | 817.4 |
| | $ | 740.8 |
| | $ | 76.6 |
|
| Operating Expenses: | |
| | |
| | |
| | |
| | |
| | |
| | |
| | |
| |
| | |
| | |
|
| Purchased Power and Transmission | 259.0 |
| | 253.5 |
| | 5.5 |
| | 2.2 |
| | 711.2 |
| | 760.6 |
| | (49.4 | ) | | (6.5 | ) | 315.4 |
| | 246.5 |
| | 68.9 |
|
| Operations and Maintenance | 123.1 |
| | 123.0 |
| | 0.1 |
| | 0.1 |
| | 359.8 |
| | 356.4 |
| | 3.4 |
| | 1.0 |
| 134.6 |
| | 133.4 |
| | 1.2 |
|
| Depreciation | 63.7 |
| | 57.7 |
| | 6.0 |
| | 10.4 |
| | 184.3 |
| | 172.2 |
| | 12.1 |
| | 7.0 |
| 79.7 |
| | 74.6 |
| | 5.1 |
|
| Amortization of Regulatory Assets, Net | 34.6 |
| | 23.4 |
| | 11.2 |
| | 47.9 |
| | 58.8 |
| | 30.3 |
| | 28.5 |
| | 94.1 |
| |
| Amortization of Regulatory (Liabilities)/Assets, Net | | (5.7 | ) | | 12.4 |
| | (18.1 | ) |
| Energy Efficiency Programs | 37.7 |
| | 44.4 |
| | (6.7 | ) | | (15.1 | ) | | 106.5 |
| | 118.0 |
| | (11.5 | ) | | (9.7 | ) | 32.3 |
| | 20.8 |
| | 11.5 |
|
| Taxes Other Than Income Taxes | 79.2 |
| | 81.9 |
| | (2.7 | ) | | (3.3 | ) | | 223.4 |
| | 227.9 |
| | (4.5 | ) | | (2.0 | ) | 80.0 |
| | 86.4 |
| | (6.4 | ) |
| Total Operating Expenses | 597.3 |
| | 583.9 |
| | 13.4 |
| | 2.3 |
| | 1,644.0 |
| | 1,665.4 |
| | (21.4 | ) | | (1.3 | ) | 636.3 |
| | 574.1 |
| | 62.2 |
|
| Operating Income | 177.5 |
| | 176.1 |
| | 1.4 |
| | 0.8 |
| | 529.6 |
| | 509.7 |
| | 19.9 |
| | 3.9 |
| 181.1 |
| | 166.7 |
| | 14.4 |
|
| Interest Expense | 36.3 |
| | 36.1 |
| | 0.2 |
| | 0.6 |
| | 106.6 |
| | 108.6 |
| | (2.0 | ) | | (1.8 | ) | 38.7 |
| | 36.9 |
| | 1.8 |
|
| Other Income, Net | 7.5 |
| | 3.7 |
| | 3.8 |
| | (a) |
| | 14.1 |
| | 10.9 |
| | 3.2 |
| | 29.4 |
| 8.5 |
| | 2.9 |
| | 5.6 |
|
| Income Before Income Tax Expense | 148.7 |
| | 143.7 |
| | 5.0 |
| | 3.5 |
| | 437.1 |
| | 412.0 |
| | 25.1 |
| | 6.1 |
| 150.9 |
| | 132.7 |
| | 18.2 |
|
| Income Tax Expense | 52.6 |
| | 57.1 |
| | (4.5 | ) | | (7.9 | ) | | 159.5 |
| | 155.4 |
| | 4.1 |
| | 2.6 |
| 33.6 |
| | 27.9 |
| | 5.7 |
|
| Net Income | $ | 96.1 |
| | $ | 86.6 |
| | $ | 9.5 |
| | 11.0 | % | | $ | 277.6 |
| | $ | 256.6 |
| | $ | 21.0 |
| | 8.2 | % | $ | 117.3 |
| | $ | 104.8 |
| | $ | 12.5 |
|
(a) Percent greater than 100 not shown as it is not meaningful.
Operating Revenues
Sales Volumes:CL&P's retail electric GWh sales volumes were as follows:4,579 and 4,602 for the three months ended June 30, 2020 and 2019, respectively, resulting in a decrease of 0.5 percent. Fluctuations in retail electric sales volumes do not impact earnings due to its PURA-approved distribution revenue decoupling mechanism.
|
| | | | | | | | | | | | | | | | | | | | | | | |
| | For the Three Months Ended September 30, | | For the Nine Months Ended September 30, |
| | 2017 | | 2016 | | Decrease | | Percent | | 2017 | | 2016 | | Decrease | | Percent |
| Retail Sales Volumes in GWh | 5,644 |
| | 6,225 |
| | (581 | ) | | (9.3 | )% | | 15,812 |
| | 16,541 |
| | (729 | ) | | (4.4 | )% |
Three Months Ended:
CL&P'sOperating Revenues: Operating Revenues, which consist of base distribution revenues and tracked revenues further described below, increased by $14.8$76.6 million for the three months ended SeptemberJune 30, 2017,2020, as compared to the same period in 2016.2019.
Fluctuations in Base Distribution Revenues: CL&P's sales volumes do not impact the level of base distribution revenue realized or earnings due to the PURA-approved revenue decoupling mechanism. CL&P's revenue decoupling mechanism permits recovery of a base amount of distribution revenues ($1.059 billion annually) and breaks the relationship between sales volumes and revenues recognized. The revenue decoupling mechanism results in the recovery of approved base distribution revenue requirements.
Fluctuations in the overall level of operating revenues are primarily related to tracked revenues. Tracked revenues consist of certain costs that are recovered from customers in rates through PURA-approved cost tracking mechanisms and therefore, have no impact on earnings. Costs recovered through cost tracking mechanisms include energy supply procurement and other energy-related costs, retail transmission charges, energy efficiency program costs and restructuring and stranded cost recovery revenues. In addition, certain tracked revenues include incentives earned and carrying charges that are billed in rates to customers. Tracked distribution revenues increased primarily as a result of an increase in energy supply costs ($27.1 million) driven by increased average retail prices. Partially offsetting this increase was a decrease in stranded cost recovery revenues ($7.6 million) and a decrease in retail transmission charges ($7.6 million).
Transmission revenues increased by $6.3$9.4 million due primarily to the impact of its base distribution rate increases effective May 1, 2020 and May 1, 2019, which includes recovery of higher revenue requirements associated with ongoing investments in our transmission infrastructure.storm costs and certain other items that do not impact earnings.
Nine Months Ended:
CL&P's Operating Revenues decreased by $1.5 millionTracked Revenues: Tracked revenues increased/(decreased) for the ninethree months ended SeptemberJune 30, 2017,2020, as compared to the same period in 2016.2019, due primarily to the following:
Tracked distribution revenues decreased primarily as a result of a decrease in energy supply costs ($25.0 million) driven by decreased average retail prices and lower sales volumes. In addition, there was a $17.8 million decrease in stranded cost recovery revenues. Partially offsetting these decreases was an increase in federally-mandated congestion charges ($23.0 million). |
| | | |
| (Millions of Dollars) | |
| Retail Tariff Tracked Revenues | |
| Energy supply procurement | $ | (5.7 | ) |
| FMCC | 23.4 |
|
| Other distribution tracking mechanisms | 13.4 |
|
| Wholesale Market Sales Revenue | 27.2 |
|
Transmission Revenues: Transmission revenues increased by $27.2$8.7 million due primarily to higher revenue requirements associated with ongoing investmentscontinued investment in our transmission infrastructure.infrastructure and a higher benefit from the annual billing and cost reconciliation filing with FERC.
Eliminations: Eliminations are primarily related to transmission revenues derived from ISO-NE regional transmission charges to the distribution business that recover the costs of the wholesale transmission business. The impact of eliminations decreased revenues by $0.6 million.
Purchased Power and Transmission expense includes costs associated with purchasing electricity on behalf of CL&P's customers. These energy supply costs are recovered from customers in rates through PURA-approved cost tracking mechanisms, which have no impact on earnings (tracked costs). Total Purchased Power and Transmission expense increasedincreased/(decreased) for the three months ended SeptemberJune 30, 2017, and decreased for the nine months ended September 30, 2017, as compared to the same periods in 2016, due primarily to the following:
|
| | | | | | | |
| (Millions of Dollars) | Three Months Ended Increase/(Decrease) | | Nine Months Ended Increase/(Decrease) |
| Purchased Power Costs | $ | 5.7 |
| | $ | (68.1 | ) |
| Transmission Costs | (0.2 | ) | | 18.7 |
|
| Total Purchased Power and Transmission | $ | 5.5 |
| | $ | (49.4 | ) |
Included in purchased power costs are the costs associated with CL&P's GSC, CTA and FMCC tracking mechanisms and deferred energy supply costs. The increase in purchased power costs for the three months ended September 30, 2017,2020, as compared to the same period in 2016,2019, due primarily to the following:
|
| | | |
| (Millions of Dollars) | |
| Purchased Power Costs | $ | 77.8 |
|
| Transmission Costs | (6.5 | ) |
| Eliminations | (2.4 | ) |
| Total Purchased Power and Transmission | $ | 68.9 |
|
The increase in purchased power costs was due primarily to GSC-related purchased power expenses. The GSC recovers energy-related costs incurred as a resultthe new Millstone PPA energy purchases, partially offset by lower expense related to the procurement of providing electric generation serviceenergy supply to all customers who have not migrated to third party suppliers.resulting from lower average prices. The decrease in purchased powertransmission costs for the nine months ended September 30, 2017, as compared to the same period in 2016, was due primarily to a decrease in the price of standard offer supply also associated with the GSC, and lower sales volumes. The increase in transmission costs for the nine months ended September 30, 2017, as comparedreduction to the same period in 2016, was primarily the result of an increaseretail transmission cost deferral and a decrease in costs billed by ISO-NE that support regional grid investment, and Local Network Service charges, which reflect the cost of transmission service.investments. This was partially offset by a decreasean increase in the retail transmission cost deferral, which reflects the actual costs of transmission service compared to estimated amounts billed to customers.Local Network Service charges.
Operations and Maintenance expense includes tracked costs and costs that are part of base distribution rates with changes impacting earnings (non-tracked costs). Operations and Maintenance expense increasedincreased/(decreased) for the three months ended SeptemberJune 30, 2017,2020, as compared to the same period in 2016, driven by a $0.4 million increase in non-tracked costs, which was2019, due primarily attributable to higher shared corporate costs, partially offset by lower employee-related expenses, lower storm restoration costs and lower vegetation management costs. The increase in non-tracked costs was partially offset by a $0.3 million decrease in tracked costs, which was primarily attributable to lower tracked system resiliency, lower bad debt expense and lower employee-related costs, partially offset by higher transmission expenses.the following:
Operations and Maintenance |
| | | |
| (Millions of Dollars) | |
| Base Electric Distribution (Non-Tracked Costs): | |
| Operations-related expenses, including vegetation management, vehicles, and outside services | $ | (4.4 | ) |
| Storm Restoration Costs | 2.6 |
|
| COVID-19 Costs | 2.4 |
|
| Other non-tracked operations and maintenance | 1.9 |
|
| Total Base Electric Distribution (Non-Tracked Costs) | 2.5 |
|
| Total Tracked Costs | (1.3 | ) |
| Total Operations and Maintenance | $ | 1.2 |
|
Depreciation expense increased for the ninethree months ended SeptemberJune 30, 2017,2020, as compared to the same period in 2016, driven by a $6.5 million increase in tracked costs, which was primarily attributable to higher transmission expenses, partially offset by lower tracked bad debt expense. Non-tracked costs decreased $3.0 million, which was primarily attributable to lower employee-related expenses, lower bad debt expense and lower vegetation management costs, partially offset by higher shared corporate costs, higher storm restoration costs, and higher system resiliency project costs.
Depreciation expense increased for the three and nine months ended September 30, 2017, as compared to the same periods in 2016,2019, due primarily to a higher utilitynet plant in service balances. balance.
Amortization of Regulatory (Liabilities)/Assets, Net expense includes the deferral of energy supply, and energy-related costs and other costs that are included in certain regulatory-approved cost tracking mechanisms, and the amortization of certain costs whichas those costs are collected in rates. This deferral adjusts expense to match the corresponding revenues. Energy supply and energy-related costs are recovered from customers in rates and have no impact on earnings. The deferral adjusts expense to match the corresponding revenues. The increaseAmortization of Regulatory (Liabilities)/Assets, Net decreased at CL&P for the three and nine months ended SeptemberJune 30, 2017,2020, as compared to the same periodsperiod in 2016, was2019, due primarily to the fluctuationunder recovery of energy purchases related to the Millstone PPA and to the deferral adjustment of energy supply and energy-related costs, which can fluctuate from period to period based on the timing of costs incurred and related rate changes to recover these costs.
Energy Efficiency Programs expense decreasedincludes costs of various state energy policy initiatives and expanded energy efficiency programs that are recovered from customers in rates, most of which have no impact on earnings. Energy Efficiency Programs expenseincreased for the three and nine months ended SeptemberJune 30, 2017,2020, as compared to the same periodsperiod in 2016,2019, due primarily to the deferral adjustment, which reflects the actual costcosts of energy efficiency programs compared to the estimated amounts billed to customers and the timing of the recovery of energy efficiency costs. The deferral adjusts costs incurred to match energy efficiency revenue billed to customers. The costs for various state policy initiatives are recovered from customers in rates and have no impact on earnings.
Taxes Other Than Income Taxes expensedecreased for the three and nine months ended September 30, 2017, as compared to the same periods in 2016, due primarily to a decrease in gross earnings taxes, partially offset by an increase in property taxes due to higher plant balances. Gross earnings taxes are tracked costs and have no impact on earnings.
Income Tax Expense decreased for the three months ended SeptemberJune 30, 2017,2020, as compared to the same period in 2016,2019, due primarily to a decrease of $10.7 million related to the true-upremittance of energy efficiency funds to the returnState of Connecticut. Energy efficiency funds collected from customers after July 1, 2019 are no longer subject to provision impactsremittance to the State of Connecticut. The decrease was partially offset by higher property taxes as a result of higher utility plant balances.
Interest Expense increased at CL&P for the three months ended June 30, 2020, as compared to the same period in 2019, due primarily to an increase in interest expense on long-term debt ($4.71.6 million).
Other Income, Net increased for the three months ended June 30, 2020, as compared to the same period in 2019, due primarily to investment income in 2020, as compared to investment losses in 2019 driven by market volatility ($2.3 million) and an increase related to pension, SERP and PBOP non-service income components ($1.8 million).
Income Tax Expense increased for the three months ended June 30, 2020, as compared to the same period in 2019, due primarily to higher pre-tax earnings ($3.8 million), higher state taxes ($0.4 million) and by items that impact our tax rate as a result of regulatory treatment (flow-through items) and permanent differences ($1.5 million), partially offset by higher pre-tax.
EARNINGS SUMMARY
CL&P's earnings ($1.7 million).
Income Tax Expense increased $12.5 millionfor the ninethree months ended SeptemberJune 30, 2017,2020, as compared to the same period in 2016, due primarily to higher pre-tax earnings ($8.8 million) and higher state taxes ($2.6 million), partially offset by the true-up of the return to provision impacts ($4.7 million) and flow-through items and permanent differences ($2.6 million).
EARNINGS SUMMARY
CL&P's earnings increased $9.5 millionfor the three months ended September 30, 2017, as compared to the same period in 2016, due primarily to a lower effective tax rate, an increase in transmission earnings driven by a higher transmission rate base, and higher distribution revenues due in part to a higher rate base for the system resiliency program, partially offset by higher depreciation expense.
CL&P's earnings increased $21.0 million for the nine months ended September 30, 2017, as compared to the same period in 2016,2019, due primarily to an increase in transmission earnings driven by a higher transmission rate base, the base distribution rate increases effective May 1, 2020 and May 1, 2019, and higher distribution revenuesearnings from its capital tracker mechanism due in part to a higher rate base for theincreased electric system resiliency program, and lower non-tracked operations and maintenance expense. These favorableimprovements. The earnings impacts wereincrease was partially offset by higher depreciation expense.
LIQUIDITY
Cash totaled $9.4 million as of September 30, 2017, compared with $6.6 million as of December 31, 2016.
CL&P had cash flows provided by operating activities of $623.3 million for the nine months ended September 30, 2017, as compared to $614.4 million in the same period of 2016. The increase in operating cash flows was due primarily to the favorable impact of the timing of regulatory recoveries and the timing of collections and payments of our working capital items, including accounts receivable and accounts payable. Partially offsetting these favorable impacts were the income tax payments of $19.8 million made in 2017, compared to the income tax refunds of $128.5 million received in 2016.
Eversource parent has a $1.45 billion commercial paper program allowing Eversource parent to issue commercial paper as a form of short-term debt, with intercompany loans to certain subsidiaries, including CL&P. The weighted-average interest rate on the commercial paper borrowings as of September 30, 2017 and December 31, 2016 was 1.34 percent and 0.88 percent, respectively. There were no intercompany loans from Eversource parent to CL&P as of September 30, 2017. As of December 31, 2016, there were intercompany loans from Eversource parent to CL&P of $80.1 million. Eversource parent, and certain of its subsidiaries, including CL&P, are parties to a five-year $1.45 billion revolving credit facility. The revolving credit facility terminates on September 4, 2021. The revolving credit facility serves to backstop Eversource parent's $1.45 billion commercial paper program. There were no borrowings outstanding on the revolving credit facility as of September 30, 2017 and December 31, 2016.
In August 2017, CL&P issued $225 million of 4.30 percent 2014 Series A First and Refunding Mortgage Bonds due to mature in 2044. These bonds are part of the same series of CL&P’s existing 4.30 percent bonds that were initially issued in 2014. The aggregate outstanding principal amount for these bonds is now $475 million. The proceeds, net of issuance costs, were used to refinance short-term debt and fund capital expenditures and working capital.
In September 2017, CL&P repaid at maturity $100 million of 5.75 percent 2007 Series C First Mortgage Bonds.
Investments in Property, Plant and Equipment on the statements of cash flows do not include amounts incurred on capital projects but not yet paid, cost of removal, AFUDC related to equity funds, and the capitalized portions of pension expense. CL&P's investments in property, plant and equipment totaled $621.9 million for the nine months ended September 30, 2017.
RESULTS OF OPERATIONS – NSTAR ELECTRIC COMPANY AND SUBSIDIARY
The following provides the amounts and variances in operating revenues and expense, line items in the statements of income for NSTAR Electric for the nine months ended September 30, 2017 and 2016 included in this combined Quarterly Report on Form 10-Q:
|
| | | | | | | | | | | | | | |
| | For the Nine Months Ended September 30, |
| (Millions of Dollars) | 2017 | | 2016 | | Increase/
(Decrease) | | Percent |
| Operating Revenues | $ | 1,913.5 |
| | $ | 1,986.0 |
| | $ | (72.5 | ) | | (3.7 | )% |
| Operating Expenses: | | | | | |
| | |
|
| Purchased Power and Transmission | 689.8 |
| | 764.9 |
| | (75.1 | ) | | (9.8 | ) |
| Operations and Maintenance | 266.2 |
| | 279.9 |
| | (13.7 | ) | | (4.9 | ) |
| Depreciation | 167.6 |
| | 159.2 |
| | 8.4 |
| | 5.3 |
|
| Amortization of Regulatory Assets, Net | 17.8 |
| | 18.3 |
| | (0.5 | ) | | (2.7 | ) |
| Energy Efficiency Programs | 198.8 |
| | 212.9 |
| | (14.1 | ) | | (6.6 | ) |
| Taxes Other Than Income Taxes | 99.0 |
| | 101.8 |
| | (2.8 | ) | | (2.8 | ) |
| Total Operating Expenses | 1,439.2 |
| | 1,537.0 |
| | (97.8 | ) | | (6.4 | ) |
| Operating Income | 474.3 |
| | 449.0 |
| | 25.3 |
| | 5.6 |
|
| Interest Expense | 70.0 |
| | 62.2 |
| | 7.8 |
| | 12.5 |
|
| Other Income, Net | 8.7 |
| | 7.6 |
| | 1.1 |
| | 14.5 |
|
| Income Before Income Tax Expense | 413.0 |
| | 394.4 |
| | 18.6 |
| | 4.7 |
|
| Income Tax Expense | 161.3 |
| | 154.5 |
| | 6.8 |
| | 4.4 |
|
| Net Income | $ | 251.7 |
| | $ | 239.9 |
| | $ | 11.8 |
| | 4.9 | % |
Operating Revenues
NSTAR Electric's retail sales volumes were as follows:
|
| | | | | | | | | | | |
| | For the Nine Months Ended September 30, |
| | 2017 | | 2016 | | Decrease | | Percent |
| Retail Sales Volumes in GWh | 15,204 |
| | 15,746 |
| | (542 | ) | | (3.4 | )% |
NSTAR Electric's Operating Revenues, which consist of base distribution revenues and tracked revenues further described below, decreased by $72.5 million for the nine months ended September 30, 2017, as compared to the same period in 2016.
Base distribution revenues: Base distribution revenues, excluding LBR, decreased $11.2 million for the nine months ended September 30, 2017, as compared to the same period in 2016, as a result of lower sales volumes in 2017, as compared to 2016 driven by the mild summer weather during the third quarter of 2017. LBR increased $10.6 million for the nine months ended September 30, 2017, as compared to the same period in 2016.
Tracked revenues: Tracked revenues consist of certain costs that are recovered from customers in rates through DPU-approved cost tracking mechanisms and therefore, have no impact on earnings. Costs recovered through cost tracking mechanisms include energy supply procurement and other energy-related costs, retail transmission charges, energy efficiency program costs, net metering for distributed generation and transition cost recovery revenues. In addition, certain tracked revenues include incentives earned and carrying charges that are billed in rates to customers. Tracked distribution revenues decreased primarily as a result of a decrease in energy supply costs ($44.1 million) driven by decreased average retail prices and lower sales volumes, a decrease in retail transmission charges ($53.9 million), a decrease in the pension rate adjustment mechanism ($14.7 million), and a decrease in transition cost recovery revenues ($11.9 million). Partially offsetting these decreases were an increase in net metering revenues ($20.2 million) and an increase in revenues related to renewable energy requirements ($23.4 million).
Transmission revenues increased by $20.6 million due primarily to the recovery of higher revenue requirements associated with ongoing investments in our transmission infrastructure.
Purchased Power and Transmission expense includes costs associated with purchasing electricity on behalf of NSTAR Electric's customers. These energy supply costs are recovered from customers in rates through DPU-approved cost tracking mechanisms, which have no impact on earnings (tracked costs). Total Purchased Power and Transmission expense decreased for the nine months ended September 30, 2017, as compared to the same period in 2016, due primarily to the following:
|
| | | |
| (Millions of Dollars) | Decrease |
| Purchased Power Costs | $ | (42.3 | ) |
| Transmission Costs | (32.8 | ) |
| Total Purchased Power and Transmission | $ | (75.1 | ) |
Included in purchased power costs are the costs associated with NSTAR Electric's basic service charge and deferred energy supply costs. The basic service charge recovers energy-related costs incurred as a result of providing electric generation service supply to all customers who have not migrated to third party suppliers. The decrease in purchased power costs was due primarily to lower prices associated with the procurement of energy supply and lower sales volumes. The decrease in transmission costs was primarily the result of a decrease in the retail transmission cost deferral, which reflects the actual costs of transmission service compared to estimated amounts billed to customers.
Operations and Maintenance expense includes tracked costs and costs that are part of base distribution rates with changes impacting earnings (non-tracked costs). Operations and Maintenance expense decreased for the nine months ended September 30, 2017, as compared to the same period in 2016, driven by a $13.0 million decrease in non-tracked costs, which was primarily attributable to lower employee-related expenses, lower bad debt expense and lower storm restoration costs, partially offset by higher shared corporate costs, a $4.9 million charge recorded in the second quarter of 2017 related to the Boston Harbor civil action settlement, and higher vegetation management costs. Tracked costs decreased $0.7 million, which was primarily attributable to lower tracked employee-related expenses, partially offset by higher transmission expenses and higher tracked bad debt expense.
Depreciation expense increased for the nine months ended September 30, 2017, as compared to the same period in 2016, due primarily to higher utility plant in service balances.
Energy Efficiency Programs expense decreased for the nine months ended September 30, 2017, as compared to the same period in 2016, due primarily to the deferral adjustment, which reflects the actual cost of energy efficiency programs compared to the estimated amounts billed to customers and the timing of the recovery of energy efficiency costs. The deferral adjusts costs incurred to match energy efficiency revenue billed to customers. The costs for various state policy initiatives are recovered from customers in rates and have no impact on earnings.
Taxes Other Than Income Taxes expense decreased for the nine months ended September 30, 2017, as compared to the same period in 2016, due primarily to a decrease in property tax rates and lower employment-related taxes.
Interest Expense increased for the nine months ended September 30, 2017, as compared to the same period in 2016, due primarily to new debt issuances.
Income Tax Expense increased for the nine months ended September 30, 2017, as compared to the same period in 2016, due primarily to higher pre-tax earnings ($6.9 million), partially offset by items that impact our tax rate as a result of regulatory treatment (flow-through items) and permanent differences ($0.1 million).
EARNINGS SUMMARY
NSTAR Electric's earnings increased $11.8 million for the nine months ended September 30, 2017, as compared to the same period in 2016, due primarily to lower operations and maintenance expense, and lower property tax expense, partially offset by lower sales volumes driven by the mild summer weather during the third quarter of 2017, and higher interest and depreciation expense.
LIQUIDITY
NSTAR Electric had cash flows provided by operating activities of $413.0 million for the nine months ended September 30, 2017, as compared to $564.3 million in the same period of 2016. The decrease in operating cash flows was due primarily to a decrease in regulatory recoveries, which were significantly impacted by the timing of collections of purchased power and transmission costs, an increase of $56.3 million in Pension and PBOP Plan cash contributions, and the income tax payments of $23.9 million made in 2017, compared to the income tax refunds of $28.1 million received in 2016. Partially offsetting these decreases was a favorable impact related to the timing of collections of accounts receivable.
NSTAR Electric has a $450 million commercial paper program allowing NSTAR Electric to issue commercial paper as a form of short-term debt. As of September 30, 2017, NSTAR Electric had no short-term borrowings outstanding and as of December 31, 2016, NSTAR Electric had $126.5 million in short-term borrowings outstanding under its commercial paper program, leaving $450.0 million and $323.5 million of available borrowing capacity as of September 30, 2017 and December 31, 2016, respectively. The weighted-average interest rate on these borrowings as of December 31, 2016 was 0.71 percent. NSTAR Electric is a party to a five-year $450 million revolving credit facility. The revolving credit facility terminates on September 4, 2021. The revolving credit facility serves to backstop NSTAR Electric's $450 million commercial paper program. There were no borrowings outstanding on the revolving credit facility as of September 30, 2017 and December 31, 2016.
RESULTS OF OPERATIONS – PUBLIC SERVICE COMPANY OF NEW HAMPSHIRE AND SUBSIDIARY
The following provides the amounts and variances in operating revenues and expense line items in the statements of income for PSNH for the nine months ended September 30, 2017 and 2016 included in this combined Quarterly Report on Form 10-Q:
|
| | | | | | | | | | | | | | |
| | For the Nine Months Ended September 30, |
| (Millions of Dollars) | 2017 | | 2016 | | Increase/
(Decrease) | | Percent |
| Operating Revenues | $ | 733.6 |
| | $ | 727.8 |
| | $ | 5.8 |
| | 0.8 | % |
| Operating Expenses: | |
| | |
| | |
| | |
|
| Purchased Power, Fuel and Transmission | 179.3 |
| | 155.7 |
| | 23.6 |
| | 15.2 |
|
| Operations and Maintenance | 191.2 |
| | 187.2 |
| | 4.0 |
| | 2.1 |
|
| Depreciation | 95.3 |
| | 86.5 |
| | 8.8 |
| | 10.2 |
|
| Amortization of Regulatory (Liabilities)/Assets, Net | (10.7 | ) | | 14.5 |
| | (25.2 | ) | | (a) |
|
| Energy Efficiency Programs | 11.0 |
| | 10.9 |
| | 0.1 |
| | 0.9 |
|
| Taxes Other Than Income Taxes | 67.0 |
| | 64.5 |
| | 2.5 |
| | 3.9 |
|
| Total Operating Expenses | 533.1 |
| | 519.3 |
| | 13.8 |
| | 2.7 |
|
| Operating Income | 200.5 |
| | 208.5 |
| | (8.0 | ) | | (3.8 | ) |
| Interest Expense | 38.7 |
| | 37.4 |
| | 1.3 |
| | 3.5 |
|
| Other Income, Net | 2.9 |
| | 1.0 |
| | 1.9 |
| | (a) |
|
| Income Before Income Tax Expense | 164.7 |
| | 172.1 |
| | (7.4 | ) | | (4.3 | ) |
| Income Tax Expense | 65.1 |
| | 66.3 |
| | (1.2 | ) | | (1.8 | ) |
| Net Income | $ | 99.6 |
| | $ | 105.8 |
| | $ | (6.2 | ) | | (5.9 | )% |
(a) Percent greater than 100 not shown as it is not meaningful.
Operating Revenues
PSNH's retail sales volumes were as follows:
|
| | | | | | | | | | | |
| | For the Nine Months Ended September 30, |
| | 2017 | | 2016 | | Decrease | | Percent |
| Retail Sales Volumes in GWh | 5,835 |
| | 5,985 |
| | (150 | ) | | (2.5 | )% |
PSNH's Operating Revenues, which consist of base distribution revenues and tracked revenues further described below, increased by $5.8 million for the nine months ended September 30, 2017, as compared to the same period in 2016.
Base distribution revenues: Base distribution revenues decreased $2.0 million for the nine months ended September 30, 2017, as compared to the same period in 2016, due primarily to a 2.5 percent decrease in sales volumes driven by the mild summer weather during the third quarter of 2017.
Tracked revenues: Tracked revenues consist of certain costs that are recovered from customers in rates through NHPUC-approved cost tracking mechanisms and therefore, have no impact on earnings. Costs recovered through cost tracking mechanisms include energy supply procurement and energy-related costs, costs associated with the generation of electricity for customers, retail transmission charges, energy efficiency program costs and stranded cost recovery revenues. In addition, certain tracked revenues include incentives earned and carrying charges that are billed in rates to customers. Tracked distribution revenues decreased primarily as a result of a decrease in revenues related to the timing of the sale of RECs ($15.3 million) and a decrease in the energy service rate ($5.1 million). Partially offsetting these decreases was an increase in retail transmission charges ($7.2 million) and an increase in wholesale generation revenues ($4.0 million).
Transmission revenues increased by $17.6 million due primarily to the recovery of higher revenue requirements associated with ongoing investments in our transmission infrastructure.
Purchased Power, Fuel and Transmission expense includes costs associated with PSNH's generation of electricity, as well as purchasing electricity on behalf of its customers. These generation and energy supply costs are recovered from customers in rates through NHPUC-approved cost tracking mechanisms, which have no impact on earnings (tracked costs). Total Purchased Power, Fuel and Transmission expense increased for the nine months ended September 30, 2017, as compared to the same period in 2016, due primarily to the following:
|
| | | |
| (Millions of Dollars) | Increase |
| Purchased Power and Generation Fuel Costs | $ | 5.1 |
|
| Transmission Costs | 18.5 |
|
| Total Purchased Power, Fuel and Transmission | $ | 23.6 |
|
In order to meet the demand of customers who have not migrated to third party suppliers, PSNH procures power through power supply contracts and spot purchases in the competitive New England wholesale power market and/or produces power through its own generation. The increase in purchased power and generation fuel costs was due primarily to higher purchased power energy expenses that are recovered as a component of the Energy Service rate, and Regional Greenhouse Gas Initiative related expenses recovered in the SCRC. The increase in transmission costs was primarily the result of an increase in costs billed by ISO-NE that support regional grid investment, and Local Network Service charges, which reflect the cost of transmission service, as well as the retail transmission cost deferral, which reflects actual costs of transmission service compared to estimated amounts billed to customers.
Operations and Maintenance expense includes tracked costs and costs that are part of base distribution rates with changes impacting earnings (non-tracked costs). Operations and Maintenance expense increased for the nine months ended September 30, 2017, as compared to the same period in 2016, driven by a $2.1 million increase in tracked costs, which was primarily attributable to higher transmission expenses, partially offset by lower employee-related expenses. Non-tracked costs increased by $1.9 million, which was primarily attributable to higher shared corporate costs and higher vegetation management costs, partially offset by lower employee-related expenses.
Depreciation expense increased for the nine months ended September 30, 2017, as compared to the same period in 2016, due primarily to higher utility plant in service balances.
Amortization of Regulatory (Liabilities)/Assets, Net expense includes the deferral of energy supply and energy-related costs and the amortization of certain costs, which are recovered from customers in rates and have no impact on earnings. The deferral adjusts expense to match the corresponding revenues. The decrease for the nine months ended September 30, 2017, as compared to the same period in 2016, was due primarily to the fluctuation of the deferral, which can fluctuate from period to period based on the timing of costs incurred and related rate changes to recover these costs.
Taxes Other Than Income Taxes expense increased for the nine months ended September 30, 2017, as compared to the same period in 2016, due primarily to an increase in property taxes due to higher plant balances.
Income Tax Expense decreased for the nine months ended September 30, 2017, as compared to the same period in 2016, due primarily to lower pre-tax earnings ($2.6 million) and items that impact our tax rate as a result of regulatory treatment (flow-through items) and permanent differences ($1.0 million), partially offset by the absence of a tax credit in 2017 ($2.4 million).
EARNINGS SUMMARY
PSNH's earnings decreased $6.2 million for the nine months ended September 30, 2017, as compared to the same period in 2016, due primarily to lower generation earnings, higher property tax and depreciation expense and lower sales volumes driven by the mild summer weather during the third quarter of 2017. These unfavorable earnings impacts were partially offset by an increase in transmission earnings driven by a higher transmission rate base.
LIQUIDITY
PSNH had cash flows provided by operating activities of $264.0 million for the nine months ended September 30, 2017, as compared to $306.0 million in the same period of 2016. The decrease in operating cash flows was due primarily to the income tax payments of $11.8 million made in 2017, compared to the income tax refunds of $41.3 million received in 2016. Partially offsetting this decrease was $16.2 million of lower Pension Plan contributions made in 2017, as compared to 2016, and the favorable impacts related to the timing of regulatory recoveries.
RESULTS OF OPERATIONS – WESTERN MASSACHUSETTS ELECTRIC COMPANY
The following provides the amounts and variances in operating revenues and expense line items in the statements of income for WMECO for the nine months ended September 30, 2017 and 2016 included in this combined Quarterly Report on Form 10-Q:
|
| | | | | | | | | | | | | | |
| | For the Nine Months Ended September 30, |
| (Millions of Dollars) | 2017 | | 2016 | | Increase/ (Decrease) | | Percent |
| Operating Revenues | $ | 377.2 |
| | $ | 368.5 |
| | $ | 8.7 |
| | 2.4 | % |
| Operating Expenses: | |
| | |
| | |
| | |
|
| Purchased Power and Transmission | 109.6 |
| | 104.4 |
| | 5.2 |
| | 5.0 |
|
| Operations and Maintenance | 65.8 |
| | 68.0 |
| | (2.2 | ) | | (3.2 | ) |
| Depreciation | 36.8 |
| | 34.4 |
| | 2.4 |
| | 7.0 |
|
| Amortization of Regulatory Assets/(Liabilities), Net | (0.6 | ) | | 3.3 |
| | (3.9 | ) | | (a) |
|
| Energy Efficiency Programs | 29.7 |
| | 33.6 |
| | (3.9 | ) | | (11.6 | ) |
| Taxes Other Than Income Taxes | 31.4 |
| | 30.4 |
| | 1.0 |
| | 3.3 |
|
| Total Operating Expenses | 272.7 |
| | 274.1 |
| | (1.4 | ) | | (0.5 | ) |
| Operating Income | 104.5 |
| | 94.4 |
| | 10.1 |
| | 10.7 |
|
| Interest Expense | 18.8 |
| | 18.3 |
| | 0.5 |
| | 2.7 |
|
| Other Income, Net | 1.4 |
| | 0.1 |
| | 1.3 |
| | (a) |
|
| Income Before Income Tax Expense | 87.1 |
| | 76.2 |
| | 10.9 |
| | 14.3 |
|
| Income Tax Expense | 34.7 |
| | 30.1 |
| | 4.6 |
| | 15.3 |
|
| Net Income | $ | 52.4 |
| | $ | 46.1 |
| | $ | 6.3 |
| | 13.7 | % |
(a) Percent greater than 100 not shown as it is not meaningful.
Operating Revenues
WMECO's retail sales volumes were as follows:
|
| | | | | | | | | | | |
| | For the Nine Months Ended September 30, |
| | 2017 | | 2016 | | Decrease | | Percent |
| Retail Sales Volumes in GWh | 2,579 |
| | 2,695 |
| | (116 | ) | | (4.3 | )% |
WMECO's Operating Revenues, which consist of base distribution revenues and tracked revenues further described below, increased by $8.7 million for the nine months ended September 30, 2017, as compared to the same period in 2016.
Fluctuations in WMECO's sales volumes do not impact the level of base distribution revenue realized or earnings due to the DPU-approved revenue decoupling mechanism. WMECO's revenue decoupling mechanism permits recovery of a base amount of distribution revenues ($132.4 million annually) and breaks the relationship between sales volumes and revenues recognized. The revenue decoupling mechanism results in the recovery of approved base distribution revenue requirements.
Fluctuations in the overall level of operating revenues are primarily related to tracked revenues. Tracked revenues consist of certain costs that are recovered from customers in rates through DPU-approved cost tracking mechanisms and therefore, have no impact on earnings. Costs recovered through cost tracking mechanisms include energy supply procurement and other energy-related costs, retail transmission charges, energy efficiency program costs, low income assistance programs, and restructuring and stranded cost recovery revenues. In addition, certain tracked revenues include incentives earned and carrying charges that are billed in rates to customers. Tracked distribution revenues decreased due primarily to a decrease in energy supply costs ($10.8 million) driven by decreased average retail prices and lower sales volumes, partially offset by increases in revenues related to renewable energy requirements ($6.6 million).
Transmission revenues increased by $12.0 million due primarily to the recovery of higher revenue requirements associated with ongoing investments in our transmission infrastructure.
Purchased Power and Transmission expense includes costs associated with purchasing electricity on behalf of WMECO's customers. These energy supply costs are recovered from customers in rates through DPU-approved cost tracking mechanisms, which have no impact on earnings (tracked costs). Total Purchased Power and Transmission expense increased for the nine months ended September 30, 2017, as compared to the same period in 2016, due primarily to the following:
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| | | |
| (Millions of Dollars) | Increase/(Decrease) |
| Purchased Power Costs | $ | (2.6 | ) |
| Transmission Costs | 7.8 |
|
| Total Purchased Power and Transmission | $ | 5.2 |
|
Included in purchased power costs are the costs associated with WMECO's basic service charge and deferred energy supply costs. The basic service charge recovers energy-related costs incurred as a result of providing electric generation service supply to all customers who have not migrated to third party suppliers. The decrease in purchased power costs for the nine months ended September 30, 2017, as compared to the same period in 2016, was due primarily to lower prices associated with the procurement of energy supply and lower sales volumes. The increase in transmission costs for the nine months ended September 30, 2017, as compared to the same period in 2016, was primarily the result of an increase in costs billed by ISO-NE that support regional grid investment, and Local Network Service charges, which reflect the cost of transmission service, as well as the retail transmission cost deferral, which reflects actual costs of transmission service compared to estimated amounts billed to customers.
Operations and Maintenance expense includes tracked costs and costs that are part of base distribution rates with changes impacting earnings (non-tracked costs). Operations and Maintenance expense decreased for the nine months ended September 30, 2017, as compared to the same period in 2016, driven by a decrease in non-tracked costs of $1.9 million, which was primarily attributable to lower employee-related expenses, partially offset by higher shared corporate costs. Tracked costs also decreased by $0.3 million, which was primarily attributable to lower tracked employee-related expenses, and a lower deferral adjustment for RECs generated and sold by the WMECO solar program, partially offset by higher transmission expenses.
Depreciation expense increased for the nine months ended September 30, 2017, as compared to the same period in 2016, due primarily to higher utility plant in service balances.
Amortization of Regulatory Assets/(Liabilities), Net expense decreased for the nine months ended September 30, 2017, as compared to the same period in 2016, due to the timing of refunds or recovery of tracked costs to/from customers in rates. These costs have no impact on earnings.
Energy Efficiency Programs expense decreased for the nine months ended September 30, 2017, as compared to the same period in 2016, due primarily to the deferral adjustment, which reflects the actual cost of energy efficiency programs compared to the estimated amounts billed to customers and the timing of the recovery of energy efficiency costs. The deferral adjusts costs incurred to match energy efficiency revenue billed to customers. The costs for various state policy initiatives are recovered from customers in rates and have no impact on earnings.
Income Tax Expense increased for the nine months ended September 30, 2017, as compared to the same period in 2016, due primarily to higher pre-tax earnings ($3.8 million) and items that impact our tax rate as a result of regulatory treatment (flow-through items) and permanent differences ($0.8 million).
EARNINGS SUMMARY
WMECO's earnings increased $6.3 million for the nine months ended September 30, 2017, as compared to the same period in 2016, due primarily to an increase in transmission earnings driven by a higher transmission rate base, and lower operations and maintenance expense.
LIQUIDITY
WMECO had cash flows provided by operating activities of $92.0 million for the nine months ended September 30, 2017, as compared to $124.8 million in the same period of 2016. The decrease in operating cash flows was due primarily to the income tax payments of $2.0 million made in 2017, compared to the income tax refunds of $21.6 million received in 2016, and the unfavorable impacts related to the timing of collections and payments of our working capital items, including accounts receivable. Partially offsetting these unfavorable impacts was the benefit related to the timing of regulatory recoveries.
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| ITEM 3. | QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK |
Market Risk Information
Commodity Price Risk Management: Our Regulatedregulated companies enter into energy contracts to serve our customers, and the economic impacts of those contracts are passed on to our customers. Accordingly, the Regulatedregulated companies have no exposure to loss of future earnings or fair values due to these market risk-sensitive instruments. Eversource's Energy Supply Risk Committee, comprised of senior officers, reviews and approves all large scalelarge-scale energy related transactions entered into by its Regulatedregulated companies.
Other Risk Management Activities
Interest Rate Risk Management: We manage our interest rate risk exposure in accordance with our written policies and procedures by maintaining a mix of fixed and variable rate long-term debt. procedures.
Credit Risk Management: Credit risk relates to the risk of loss that we would incur as a result of non-performance by counterparties pursuant to the terms of our contractual obligations. We serve a wide variety of customers and transact with suppliers that include IPPs, industrial companies, natural gas and electric utilities, oil and natural gas producers, financial institutions, and other energy marketers. Margin accounts exist within this diverse group, and we realize interest receipts and payments related to balances outstanding in these margin accounts. This wide customer and supplier mix generates a need for a variety of contractual structures, products and terms that, in turn, require us to manage the portfolio of market risk inherent in those transactions in a manner consistent with the parameters established by our risk management process.
Our Regulatedregulated companies are subject to credit risk from certain long-term or high-volume supply contracts with energy marketing companies. Our Regulatedregulated companies manage the credit risk with these counterparties in accordance with established credit risk practices and monitor contractingcontracting risks, including credit risk. As of SeptemberJune 30, 2017,2020, our Regulatedregulated companies did not holdheld collateral (letters of credit)credit or cash) of $15.0 million from counterparties related to our standard service contracts. As of SeptemberJune 30, 2017,2020, Eversource had $24.5$29.6 million of cash postedposted with ISO-NE related to energy transactions.
We have provided additional disclosures regarding interest rate risk management and credit risk management in Part II, Item 7A, "Quantitative and Qualitative Disclosures about Market Risk," in Eversource's 20162019 Form 10-K, which is incorporated herein by reference. There have been no additional risks identified and no material changes with regard to the items previously disclosed in the Eversource 20162019 Form 10-K.
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| ITEM 4. | CONTROLS AND PROCEDURES |
Management, on behalf of Eversource, CL&P, NSTAR Electric PSNH and WMECO,PSNH, evaluated the design and operation of the disclosure controls and procedures as of SeptemberJune 30, 20172020 to determine whether they are effective in ensuring that the disclosure of required information is made timely and in accordance with the Securities Exchange Act of 1934 and the rules and regulations of the SEC. This evaluation was made under management's supervision and with management's participation, including the principal executive officer and principal financial officer as of the end of the period covered by this Quarterly Report on Form 10-Q. There are inherent limitations of disclosure controls and procedures, including the possibility of human error and the circumventing or overriding of the controls and procedures. Accordingly, even effective disclosure controls and procedures can only provide reasonable assurance of achieving their control objectives. The principal executive officer and principal financial officer have concluded, based on their review, that the disclosure controls and procedures of Eversource, CL&P, NSTAR Electric PSNH and WMECOPSNH are effective to ensure that information required to be disclosed by us in reports filed under the Securities Exchange Act of 1934 (i) is recorded, processed, summarized, and reported within the time periods specified in SEC rules and regulations and (ii) is accumulated and communicated to management, including the principal executive officer and principal financial officer, as appropriate to allow timely decisions regarding required disclosures.
During the third quarter of 2017, Eversource implemented a new supply chain management system resulting in a material change in internal controls over financial reporting. This new supply chain system consisted of both modern software tools and revised processes that consolidated and standardized all supply chain processes and practices across all of Eversource, including CL&P, NSTAR Electric, PSNH, and WMECO. Pre-implementation testing and post-implementation reviews were conducted by management to ensure that internal controls surrounding the system implementation process, the applications, and the closing process were properly designed to prevent material financial statement errors. Such procedures included the review of required documents, user acceptance testing, change management procedures, access controls, data migration strategies and reconciliations, application interface testing and other standard application controls.
Except as described above, thereThere have been no changes in internal controls over financial reporting for Eversource, CL&P, NSTAR Electric PSNH and WMECOPSNH during the quarter ended SeptemberJune 30, 20172020 that have materially affected, or are reasonably likely to materially affect, internal controls over financial reporting.
PART II. OTHER INFORMATION
We are parties to various legal proceedings. We have disclosed thesecertain legal proceedings in Part I, Item 3, "Legal Proceedings," and elsewhere in our 20162019 Form 10-K. These disclosures are incorporated herein by reference.
On May 22, 2017, each of the Yankee Companies filed subsequent lawsuits against the DOE in the Court of Federal Claims seeking damages totaling approximately $100 million for CYAPC, YAEC and MYAPC, covering the years from 2013 to 2016 (“DOE Phase IV”). The DOE Phase IV trial is expected to begin in 2018. For a further discussion of the Yankee Companies v. U.S. Department of Energy, see Part I, Item 3, “Legal Proceedings” of our 2016 Form 10-K.
Other than as set forth above, thereThere have been no additional material legal proceedings identified and no further material changes with regard to the legal proceedings previously disclosed in our 20162019 Form 10-K.
We are subject to a variety of significant risks in addition to the matters set forth under "Forward-Looking Statements,"our forward-looking statements section in Item 2, "Management's Discussion and Analysis of Financial Condition and Results of Operations," of this Quarterly Report on Form 10-Q. We have identified a number of these risk factors in Part I, Item 1A, "Risk Factors," in our 20162019 Form 10-K, which risk factors are incorporated herein by reference. These risk factors should be considered carefully in evaluating our risk profile. ThereThe following risk factor should be read in conjunction with the risk factors described in the 2019 Form 10-K.
The global pandemic of the 2019 novel coronavirus (COVID-19) has resulted in widespread disruption to the many systems and processes of daily life, as well as the overall economic market and outlook, which could cause various unfavorable impacts to our customers, vendors, employees, regulators, and operations and could adversely affect our financial position, results of operations and cash flows.
We are responding to COVID-19 by taking steps to mitigate the potential risks to Eversource posed by its spread. We provide a critical service to our customers, which means it is paramount that we keep our employees who operate our businesses safe and minimize unnecessary risk of exposure to COVID-19. We have updated and implemented our company-wide pandemic plan to address specific aspects of the COVID-19 pandemic. This plan guides our emergency response, business continuity, and the precautionary measures we are taking on behalf of employees and our customers. As part of our pandemic plan, we are taking extra precautions to mitigate an adverse material impact to the following risk factors that we believe could continue to be impacted by COVID-19:
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| • | Cybersecurity attacks: We have seen a consistent volume of perimeter scanning for vulnerabilities throughout the COVID-19 time frame, which is higher than pre-COVID-19 volumes. This scanning can be leveraged to compromise a system. We have also seen increased phishing attempts targeted at our employees by outside parties to gain control of our systems and network. We continue to implement strong cybersecurity measures and have increased the education of our employees and contractors to ensure that our systems remain functional in order to both serve our operational needs with a remote workforce and to ensure uninterrupted service to our customers. We also continuously review and update our response plans to include responding to an event while in a remote work environment. |
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| • | Access to, or cost of, capital resources: We utilize the commercial paper market extensively for our short-term borrowing needs. At the onset of the pandemic in the United States, there had been reduced liquidity in the commercial paper credit market. However, federal legislative actions, as well as increased liquidity and the reduction in the federal funds rate by the Federal Reserve, have enabled the credit markets to function. We continue to monitor the ability for us to access the global capital and credit markets; however, if we are unable to access these markets, then our financial condition may be adversely affected. |
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| • | Actions of regulators: We continue to work closely with our state regulatory commissions and consumer advocates on several customer assistance measures, including more flexible and new payment plan options in order to mitigate the impact on customer rates in the future, as well as financial hardship and arrearage management programs for those customers who are unable to pay their utility bills. We developed these long-term solutions for customers in order to help minimize the extent of the impact of COVID-19 on customer receivable balances and customers’ affordability in light of the adverse financial impact they may experience. We believe that we are developing successful mechanisms with our state regulatory commissions to recover our costs associated with COVID-19, while balancing the impact on our customers’ bills. |
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| • | Timing of strategic development opportunities: The successful execution of our timeline for developing our offshore wind projects is based on several factors, including state and federal siting and permitting approvals. Between March 2020 and June 2020, COVID-19-related work restrictions prohibited work in New York and within New York jurisdictional waters. Those restrictions delayed offshore site investigations, and onshore environmental and geotechnical surveys, which could adversely impact our project siting and permit filing timelines. On April 8, 2020, the state of New York Administrative Law Judge granted a change to the start of the South Fork Wind evidentiary hearing schedule to September 30, 2020, due to ongoing COVID-19 work and travel restrictions. Although we are unable to predict the impact of those delays on our offshore wind projects at this time, we are currently developing mitigation plans to address permitting delays due to COVID-19 restrictions on our offshore wind projects. Similarly, we are unable to assess the potential impact that a reintroduction of these work restrictions in response to a future increase in COVID-19 infections would have on our projects. |
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| • | Suppliers and Vendors: We have instituted measures to ensure our supply chain remains open to us; however, there could be global shortages that will impact our maintenance, capital programs, and storm response that we currently cannot anticipate. |
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| • | Loss of key personnel: We continue to adjust our pandemic plan to address various scenarios including reduced workforce levels and limited mutual aid in the event of a significant storm event. We have implemented remote work arrangements for our workforce by enabling nearly half of our employees to work from home and taking extra precautions for our field-based employees. We have taken significant safety measures to ensure adequate social distancing for our field crews to safely provide essential services to our customers. We have also adopted protocols to ensure the safety and health of those employees who work onsite in critical facilities. We continue to monitor COVID-19 developments affecting our workforce and will take additional precautions that we determine are necessary in order to mitigate the impacts. Although to date our workforce continues to be able to safely and reliably deliver our critical services to customers, we are unable to predict the extent of the impact of COVID-19 on our employees. |
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| • | Impact to Benefit Plans: As of June 30, 2020, under the Pension Protection Act, the funded status of our pension plan was approximately 99 percent. The pension and PBOP plans' funded status is highly dependent on benefit plan asset returns, interest rates, and discount rates, all of which could be materially impacted by an extended economic slowdown. Should these financial metrics be negatively impacted by COVID-19 as of December 31, 2020, it could result in the underperformance of our pension and PBOP plan investments, an increase in pension and PBOP obligations and employee benefit plan costs, and in a minimum pension funding requirement due by March 31, 2022 for the 2021 Plan year. We continue to monitor federal legislative pension developments that could provide additional pension funding relief. |
We are currently unable to estimate the potential impact of COVID-19 to our financial position, results of operations and cash flows.
Other than as set forth above, there have been no additional risk factors identified and no material changes with regard to the risk factors previously disclosed in our 20162019 Form 10-K.
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| ITEM 2. | UNREGISTERED SALES OF EQUITY SECURITIES AND USE OF PROCEEDS |
The following table discloses purchases of our common shares made by us or on our behalf for the periods shown below. The common shares purchased consist of open market purchases made by the Company or an independent agent. These share transactions related to shares awarded under the Company's Incentive Plan and Dividend Reinvestment Plan and matching contributions under the Eversource 401k Plan.
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| Period | Total Number of Shares Purchased | Average Price Paid per Share | Total Number of Shares Purchased as Part of Publicly Announced Plans or Programs | Approximate Dollar Value of Shares that May Yet Be Purchased Under the Plans and Programs (at month end) |
| July 1 - July 31, 2017 | 99,090 |
| $ | 60.76 |
| — |
| — |
|
| August 1 - August 31, 2017 | 4,802 |
| 62.08 |
| — |
| — |
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| September 1 - September 30, 2017 | 74,148 |
| 60.77 |
| — |
| — |
|
| Total | 178,040 |
| $ | 60.80 |
| — |
| — |
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| | | | | | | | | |
| Period | Total Number of Shares Purchased | Average Price Paid per Share | Total Number of Shares Purchased as Part of Publicly Announced Plans or Programs | Approximate Dollar Value of Shares that May Yet Be Purchased Under the Plans and Programs (at month end) |
| April 1 - April 30, 2020 | — |
| $ | — |
| — |
| — |
|
| May 1 - May 31, 2020 | 108 |
| 75.69 |
| — |
| — |
|
| June 1 - June 30, 2020 | 2,309 |
| 83.35 |
| — |
| — |
|
| Total | 2,417 |
| $ | 83.01 |
| — |
| — |
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Each document described below is filed herewith, unless designated with an asterisk (*), which exhibits are incorporated by reference by the registrant under whose name the exhibit appears.
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| | Exhibit No. | | Description |
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| | Listing of Exhibits (Eversource) |
| | 31 | | |
| | | | Thirteen Supplemental Indenture of Mortgage and Deed of Trust between Yankee Gas Services Company and The Bank of New York Mellon Trust Company, N.A., successor as Trustee to The Bank of New York, as successor to Fleet National Bank (formerly known as The Connecticut National Bank), dated as of September 1, 2017
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| | | Ratio of Earnings to Fixed Charges |
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| | | Certification by the Chief Executive Officer of Eversource Energy pursuant to Section 302 of the Sarbanes-Oxley Act of 2002 |
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| | | | |
| | Listing of Exhibits (CL&P) |
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* | 31 | | Supplemental Indenture (2017 Series A Bonds) between CL&P and Deutsche Bank Trust Company Americas, as Trustee dated as of August 1, 2017 (incorporated by reference to Exhibit 4.1, CL&P Current Report on Form 8-K filed August 23, 2017, File No. 000-00404)
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| | | |
| | | Ratio of Earnings to Fixed Charges |
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| | | Certification by the Chairman of The Connecticut Light and Power Company pursuant to Section 302 of the Sarbanes-Oxley Act of 2002 |
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| | | | |
| | | | |
| | Listing of Exhibits (NSTAR Electric Company) |
| | 31 | | |
| | | | Ratio of Earnings to Fixed Charges |
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| | | Certification by the Chairman of NSTAR Electric Company pursuant to Section 302 of the Sarbanes-Oxley Act of 2002 |
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| | | | |
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| | | | |
| | | | |
| | Listing of Exhibits (PSNH) |
| | 31 | | |
| | | | Ratio of Earnings to Fixed Charges |
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| | | Certification by the Chairman of Public Service Company of New Hampshire pursuant to Section 302 of the Sarbanes-Oxley Act of 2002 |
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| Listing of Exhibits (WMECO) |
| | | |
| | | Ratio of Earnings to Fixed Charges |
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| | | Certification by the Chairman of Western Massachusetts Electric Company pursuant to Section 302 of the Sarbanes-Oxley Act of 2002 |
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| | | Certification by the Chief Financial Officer of Western Massachusetts Electric Company pursuant to Section 302 of the Sarbanes-Oxley Act of 2002 |
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| | | Certification by the Chairman and the Chief Financial Officer of Western Massachusetts Electric Company pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002 |
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| | Listing of Exhibits (Eversource, CL&P, NSTAR Electric, PSNH, WMECO) |
| | | PSNH) |
| | 101.INS | | Inline XBRL Instance Document - the instance document does not appear in the interactive data file because its XBRL tags are embedded within the inline XBRL document |
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| | 101.SCH | | Inline XBRL Taxonomy Extension Schema |
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| | 101.CAL | | Inline XBRL Taxonomy Extension Calculation |
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| | 101.DEF | | Inline XBRL Taxonomy Extension Definition |
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| | 101.LAB | | Inline XBRL Taxonomy Extension Labels |
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| | 101.PRE | | Inline XBRL Taxonomy Extension Presentation |
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| 104 | | The cover page from the Quarterly Report on Form 10-Q for the quarter ended June 30, 2020, formatted in Inline XBRL |
SIGNATURE
Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the Registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.
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| | | EVERSOURCE ENERGY |
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November 3, 2017August 7, 2020 | | By: | /s/ Jay S. Buth |
| | | | Jay S. Buth |
| | | | Vice President, Controller and Chief Accounting Officer |
SIGNATURE
Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the Registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.
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| | | |
| | | THE CONNECTICUT LIGHT AND POWER COMPANY |
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November 3, 2017August 7, 2020 | | By: | /s/ Jay S. Buth |
| | | | Jay S. Buth |
| | | | Vice President, Controller and Chief Accounting Officer |
SIGNATURE
Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the Registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.
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| | | |
| | | NSTAR ELECTRIC COMPANY |
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November 3, 2017August 7, 2020 | | By: | /s/ Jay S. Buth |
| | | | Jay S. Buth |
| | | | Vice President, Controller and Chief Accounting Officer |
SIGNATURE
Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the Registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.
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| | | |
| | | PUBLIC SERVICE COMPANY OF NEW HAMPSHIRE |
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November 3, 2017August 7, 2020 | | By: | /s/ Jay S. Buth |
| | | | Jay S. Buth |
| | | | Vice President, Controller and Chief Accounting Officer |
SIGNATURE
Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the Registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.
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| | | |
| | WESTERN MASSACHUSETTS ELECTRIC COMPANY |
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November 3, 2017 | | By: | /s/ Jay S. Buth |
| | | Jay S. Buth |
| | | Vice President, Controller and Chief Accounting Officer |
