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 reports on Form 10-Q for the quarters ended March 31, 2016 and June 30, 2016, as well as the Eversource
2015
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.”
Refer to the Glossary of Terms included in this combined Quarterly Report on Form 10-Q for abbreviations and acronyms used throughout this
Management’s Discussion and Analysis of Financial Condition and Results of Operations
.
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. The tabular presentations below also include non-GAAP financial measures referencing our
third
quarter and first
nine months
of
2016
and
2015
earnings and EPS excluding certain integration costs. We use these non-GAAP financial measures to evaluate and to provide details of earnings by business and to more fully compare and explain our
third
quarter and first
nine months
of 2015 results without including the impact of these items. Due to the nature and significance of these items on Net Income Attributable to Common Shareholders, we believe that the non-GAAP presentation provides additional and useful information to readers of this report in analyzing historical and future performance by business. These non-GAAP financial measures should not be considered as an alternative to reported Net Income Attributable to Common Shareholders or EPS determined in accordance with GAAP as an indicator of operating performance.
Reconciliations of the above non-GAAP financial measures to the most directly comparable GAAP measures of consolidated diluted EPS and Net Income Attributable to Common Shareholders are included under “Financial Condition and Business Analysis – Overview – Consolidated” and “Financial Condition and Business Analysis – Overview – Regulated Companies” in this
Management’s Discussion and Analysis of Financial Condition and Results of Operations
, herein.
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:
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cyber breaches, acts of war or terrorism, or grid disturbances,
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•
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actions or inaction of local, state and federal regulatory, public policy and taxing bodies,
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•
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changes in business conditions, which could include disruptive technology related to our current or future business model,
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changes in economic conditions, including impact on interest rates, tax policies, and customer demand and payment ability,
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•
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fluctuations in weather patterns,
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•
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changes in laws, regulations or regulatory policy,
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•
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changes in levels or timing of capital expenditures,
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•
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disruptions in the capital markets or other events that make our access to necessary capital more difficult or costly,
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developments in legal or public policy doctrines,
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technological developments,
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changes in accounting standards and financial reporting regulations,
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actions of rating agencies, and
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other presently unknown or unforeseen factors.
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Other risk factors are detailed in our reports filed with the SEC and updated as necessary, and we encourage you to consult such disclosures.
All such factors are difficult to predict, contain uncertainties that may materially affect our actual results and are beyond our control. You should not place undue reliance on the forward-looking statements, each speaks only as of the date on which such statement is made, and we undertake no obligation to update any forward-looking statement or statements to reflect events or circumstances after the date on which such statement is made or to reflect the occurrence of unanticipated events. New factors emerge from time to time and it is not possible for us to predict all of such factors, nor can we assess the impact of each such factor on the business or the extent to which any factor, or combination of factors, may cause actual results to differ materially from those contained in any forward-looking statements. For more information, see Item 1A, Risk Factors, included in this combined Quarterly Report on Form 10-Q and in Eversource’s
2015
combined Annual Report on Form 10-K. This combined Quarterly Report on Form 10-Q and Eversource’s
2015
combined Annual Report on Form 10-K also describe material contingencies and critical accounting policies in the accompanying
Management’s Discussion and Analysis of Financial Condition and Results of Operations and Combined Notes to Financial Statements
. We encourage you to review these items.
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:
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We earned
$265.3 million
, or
$0.83
per share, in the
third
quarter of
2016
, and
$713.1 million
, or
$2.24
per share, in the first
nine months
of
2016
, compared with
$235.9 million
, or
$0.74
per share, in the
third
quarter of
2015
, and
$696.7 million
, or
$2.19
per share, in the first
nine months
of
2015
.
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•
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Our electric distribution segment, which includes generation, earned
$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
, compared with earnings of $167.3 million, or
$0.53
per share, in the
third
quarter of
2015
, and $418.7 million, or
$1.32
per share, in the first
nine months
of
2015
.
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Our transmission segment earned
$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
, compared with
$78.0 million
, or
$0.24
per share, in the
third
quarter of
2015
, and
$225.0 million
, or
$0.70
per share, in the first
nine months
of
2015
.
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•
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Our natural gas distribution segment had a net loss of
$7.0 million
, or
$0.02
per share, in the
third
quarter of
2016
, and earnings of
$51.9 million
, or
$0.16
per share, in the first
nine months
of
2016
, compared with a net loss of $3.5 million, or
$0.01
per share, in the
third
quarter of
2015
, and earnings of $57.5 million, or
$0.18
per share, in the first
nine months
of
2015
.
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Eversource parent and other companies earned
$13.8 million
in the
third
quarter of
2016
and
$13.3 million
in the first
nine months
of
2016
, compared with a net loss of $5.9 million in the
third
quarter of
2015
and $4.5 million in the first
nine months
of
2015
.
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Liquidity:
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Cash flows provided by operating activities totaled
$1.65 billion
in the first
nine months
of
2016
, compared with
$1.35 billion
in the first
nine months
of
2015
. Investments in property, plant and equipment totaled
$1.36 billion
in the first
nine months
of
2016
, compared with
$1.18 billion
in the first
nine months
of
2015
. Cash and cash equivalents totaled
$40.1 million
as of
September 30, 2016
, compared with
$23.9 million
as of
December 31, 2015
.
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On September 7, 2016, our Board of Trustees approved a common share dividend payment of $0.445 per share, which was paid on September 30, 2016 to shareholders of record as of September 19, 2016.
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Strategic, Legislative, Regulatory, Policy and Other Items:
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In late 2015 and early 2016, NSTAR Electric, WMECO and a subsidiary of National Grid filed with the Massachusetts DPU seeking approval of contracts with Access Northeast for natural gas pipeline capacity and storage. The DPU had determined in 2015 that it had authority to approve such contracts if they were found to be in the public interest. On August 17, 2016, the Massachusetts Supreme Judicial Court vacated the DPU’s 2015 order, holding that the state’s electric utility restructuring statutes precluded the DPU from approving contracts by EDCs for natural gas capacity. In early 2016, PSNH filed with the NHPUC seeking approval of its contract with Access Northeast for natural gas pipeline capacity and storage. On October 6, 2016, contrary to a 2015 recommendation from its staff, the NHPUC ruled that it did not have authority to approve such contracts under the state’s electric utility restructuring statutes. On October 25, 2016, the Connecticut DEEP issued a notice of cancellation, without prejudice, of its natural gas capacity review process. We are currently reviewing options surrounding Access Northeast and, depending on the outcome of the potential options selected, the timing, configuration and cost of Access Northeast could change.
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On October 14, 2016, in an important foundational order for NPT, the NHPUC granted NPT public utility status, conditioned on project approval.
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On October 24, 2016, Eversource was notified that neither the NPT project nor the Clean Energy Connect project were selected in the three-state Clean Energy RFP bidding process. The Company is currently placing efforts on the next round of contracting opportunities, specifically in Massachusetts, where new legislation requires electric distribution companies to jointly solicit RFPs and enter into long-term contracts for large-scale hydro projects.
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Overview
Consolidated:
Below is a summary of our earnings by business, which also reconciles the non-GAAP financial measure of EPS by business to the most directly comparable GAAP measure of diluted EPS, for the
third
quarter and first
nine months
of
2016
and
2015
. Also included in the summary for the
third
quarter and first
nine months
of 2015 is a reconciliation of the non-GAAP financial measure of consolidated non-GAAP earnings to the most directly comparable GAAP measure of consolidated Net Income Attributable to Common Shareholders.
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For the Three Months Ended September 30,
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For the Nine Months Ended September 30,
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2016
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2015
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2016
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2015
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(Millions of Dollars, Except Per Share Amounts)
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Amount
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Per Share
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Amount
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Per Share
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Amount
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Per Share
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Amount
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Per Share
|
Net Income Attributable to
Common Shareholders (GAAP)
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$
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265.3
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$
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0.83
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$
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235.9
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$
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0.74
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$
|
713.1
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$
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2.24
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$
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696.7
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$
|
2.19
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Regulated Companies
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$
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251.5
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$
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0.79
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$
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242.2
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$
|
0.76
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$
|
699.8
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$
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2.20
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$
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702.3
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$
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2.20
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Eversource Parent and Other Companies
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13.8
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0.04
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(4.6
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)
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(0.01
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)
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13.3
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|
0.04
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2.2
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|
0.01
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Non-GAAP Earnings
|
N/A
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N/A
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|
237.6
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|
0.75
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N/A
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N/A
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704.5
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2.21
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Integration Costs (after-tax)
(1)
|
N/A
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N/A
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(1.7
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)
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(0.01
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)
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N/A
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N/A
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(7.8
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)
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(0.02
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)
|
Net Income Attributable to
Common Shareholders (GAAP)
|
$
|
265.3
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$
|
0.83
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$
|
235.9
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$
|
0.74
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$
|
713.1
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$
|
2.24
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|
$
|
696.7
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$
|
2.19
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(1)
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The
2015
integration costs were associated with our branding efforts and severance costs.
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Regulated Companies:
Our Regulated companies consist of the electric distribution, electric transmission, and natural gas distribution segments. Generation activities of PSNH and WMECO are included in our electric distribution segment. A summary of our segment earnings and EPS for the
third
quarter and first
nine months
of
2016
and
2015
is as follows:
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For the Three Months Ended September 30,
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For the Nine Months Ended September 30,
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2016
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2015
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2016
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2015
|
(Millions of Dollars, Except Per Share Amounts)
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Amount
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Per Share
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Amount
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Per Share
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Amount
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Per Share
|
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Amount
|
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Per Share
|
Electric Distribution
|
$
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170.1
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$
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0.53
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$
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167.7
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$
|
0.53
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$
|
381.3
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$
|
1.20
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$
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419.8
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$
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1.32
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Electric Transmission
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88.4
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0.28
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78.0
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0.24
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266.6
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0.84
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225.0
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0.70
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Natural Gas Distribution
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(7.0
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)
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(0.02
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)
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(3.5
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)
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(0.01
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)
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51.9
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|
0.16
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57.5
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|
0.18
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Non-GAAP Earnings
|
N/A
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|
N/A
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242.2
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|
0.76
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|
N/A
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|
N/A
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702.3
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|
2.20
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Integration Costs (after-tax)
|
N/A
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N/A
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(0.4
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)
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—
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|
N/A
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|
N/A
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(1.1
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)
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—
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Net Income - Regulated Companies
|
$
|
251.5
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|
$
|
0.79
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$
|
241.8
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|
$
|
0.76
|
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|
$
|
699.8
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$
|
2.20
|
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$
|
701.2
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$
|
2.20
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Our electric distribution segment earnings increased $2.8 million in the third quarter of 2016, as compared to the third quarter of 2015, due primarily to increased CL&P distribution revenues primarily as a result of higher rate base, and higher generation earnings. These favorable earnings impacts were partially offset by higher depreciation expense and higher property tax and other tax expense.
Our electric distribution segment earnings decreased $37.4 million in the first nine months of 2016, as compared to the first nine months of 2015, due primarily to the absence in 2016 of the resolution of NSTAR Electric’s basic service bad debt adder mechanism recorded in the first quarter of 2015 ($14.5 million), the absence in 2016 of the favorable impact associated with the NSTAR Electric and NSTAR Gas Comprehensive Settlement Agreement recorded in the first quarter of 2015 ($13 million), lower non-decoupled retail electric sales volumes due primarily to increased customer energy conservation efforts and warmer than normal weather in the first quarter of 2016, as compared to the much colder than normal temperatures in the first quarter of 2015, higher depreciation expense, and higher property tax and other tax expense. These unfavorable earnings impacts were partially offset by increased CL&P distribution revenues primarily as a result of higher rate base and the absence of an authorized ROE reduction, as stipulated in the PURA 2014 rate case decision, and higher generation earnings.
Our electric transmission segment earnings increased $10.4 million in the third quarter of 2016, as compared to the third quarter of 2015, due primarily to a higher transmission rate base as a result of increased investments in our transmission infrastructure.
Our electric transmission segment earnings increased $41.6 million in the first nine months of 2016, as compared to the first nine months of 2015, due primarily to a higher transmission rate base as a result of increased investments in our transmission infrastructure and the absence in 2016 of reserve charges of $12.4 million recorded in the first quarter of 2015 associated with the FERC ROE complaint proceedings.
Our natural gas distribution segment earnings decreased $3.5 million in the third quarter of 2016, as compared to the third quarter of 2015, due primarily to a higher effective tax rate in 2016, partially offset by the higher return earned on the NSTAR Gas System Enhancement Program (GSEP) capital tracker mechanism effective in 2016.
Our natural gas distribution segment earnings decreased $5.6 million in the first nine months of 2016, as compared to the first nine months of 2015, due primarily to lower non-decoupled firm natural gas sales volumes driven by the warmer than normal weather in the first quarter of 2016, as compared to the much colder than normal temperatures in the first quarter of 2015, higher property tax expense and higher interest expense. Partially offsetting these unfavorable earnings impacts were lower operations and maintenance expense, the impact of the NSTAR Gas base distribution rate increase effective January 1, 2016, and the higher return earned on the NSTAR Gas GSEP capital tracker mechanism effective in 2016.
Eversource Parent and Other Companies:
Eversource parent and other companies had earnings of $13.8 million and $13.3 million in the third quarter and first nine months of 2016, respectively, compared with a net loss of $5.9 million and $4.5 million in the third quarter and first nine months of 2015, respectively. The earnings increase in the third quarter and first nine months of 2016 was due primarily to a lower effective tax rate, the absence in 2016 of integration costs, and the absence in 2016 of a bad debt reserve recorded in the third quarter of 2015 at Eversource’s unregulated business, 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 Massachusetts 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). Natural gas distribution revenues are decoupled from their customer sales volumes, where applicable, which breaks the relationship between sales volumes and revenues recognized.
A summary of our retail electric GWh sales volumes and our firm natural gas sales volumes in million cubic feet (Mcf) and percentage changes is as follows:
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For the Three Months Ended September 30, 2016 Compared to 2015
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For the Nine Months Ended September 30, 2016 Compared to 2015
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Sales Volumes (GWh)
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Percentage
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Sales Volumes (GWh)
|
|
Percentage
|
Electric
|
2016
|
|
2015
|
|
Increase/(Decrease)
|
|
2016
|
|
2015
|
|
Increase/(Decrease)
|
Traditional:
|
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Residential
|
2,910
|
|
|
2,832
|
|
|
2.8
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%
|
|
7,407
|
|
|
7,706
|
|
|
(3.9
|
)%
|
Commercial
|
4,525
|
|
|
4,583
|
|
|
(1.3
|
)%
|
|
12,376
|
|
|
12,615
|
|
|
(1.9
|
)%
|
Industrial
|
696
|
|
|
721
|
|
|
(3.5
|
)%
|
|
1,948
|
|
|
1,988
|
|
|
(2.0
|
)%
|
Total – Traditional
|
8,131
|
|
|
8,136
|
|
|
(0.1
|
)%
|
|
21,731
|
|
|
22,309
|
|
|
(2.6
|
)%
|
|
|
|
|
|
|
|
|
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|
Decoupled:
|
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|
|
|
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Residential
|
3,398
|
|
|
3,245
|
|
|
4.7
|
%
|
|
8,750
|
|
|
9,108
|
|
|
(3.9
|
)%
|
Commercial
|
3,039
|
|
|
3,030
|
|
|
0.3
|
%
|
|
8,315
|
|
|
8,524
|
|
|
(2.5
|
)%
|
Industrial
|
776
|
|
|
795
|
|
|
(2.4
|
)%
|
|
2,170
|
|
|
2,233
|
|
|
(2.8
|
)%
|
Total – Decoupled
|
7,213
|
|
|
7,070
|
|
|
2.0
|
%
|
|
19,235
|
|
|
19,865
|
|
|
(3.2
|
)%
|
Total Sales Volumes
|
15,344
|
|
|
15,206
|
|
|
0.9
|
%
|
|
40,966
|
|
|
42,174
|
|
|
(2.9
|
)%
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
For the Three Months Ended September 30, 2016 Compared to 2015
|
|
For the Nine Months Ended September 30, 2016 Compared to 2015
|
|
Sales Volumes (Mcf)
|
|
Percentage
|
|
Sales Volumes (Mcf)
|
|
Percentage
|
Firm Natural Gas
|
2016
|
|
2015
|
|
Increase/(Decrease)
|
|
2016
|
|
2015
|
|
Increase/(Decrease)
|
Traditional:
|
|
|
|
|
|
|
|
|
|
|
|
Residential
|
956
|
|
|
955
|
|
|
0.1
|
%
|
|
10,109
|
|
|
12,022
|
|
|
(15.9
|
)%
|
Commercial
|
2,350
|
|
|
2,310
|
|
|
1.7
|
%
|
|
13,864
|
|
|
15,578
|
|
|
(11.0
|
)%
|
Industrial
|
1,964
|
|
|
2,184
|
|
|
(10.1
|
)%
|
|
7,597
|
|
|
8,755
|
|
|
(13.2
|
)%
|
Total – Traditional
|
5,270
|
|
|
5,449
|
|
|
(3.3
|
)%
|
|
31,570
|
|
|
36,355
|
|
|
(13.2
|
)%
|
|
|
|
|
|
|
|
|
|
|
|
|
Decoupled:
|
|
|
|
|
|
|
|
|
|
|
|
Residential
|
1,308
|
|
|
1,531
|
|
|
(14.6
|
)%
|
|
13,848
|
|
|
17,078
|
|
|
(18.9
|
)%
|
Commercial
|
2,147
|
|
|
2,065
|
|
|
4.0
|
%
|
|
15,019
|
|
|
17,002
|
|
|
(11.7
|
)%
|
Industrial
|
990
|
|
|
977
|
|
|
1.3
|
%
|
|
4,163
|
|
|
4,670
|
|
|
(10.9
|
)%
|
Total – Decoupled
|
4,445
|
|
|
4,573
|
|
|
(2.8
|
)%
|
|
33,030
|
|
|
38,750
|
|
|
(14.8
|
)%
|
Special Contracts
(1)
|
1,208
|
|
|
1,115
|
|
|
8.3
|
%
|
|
3,507
|
|
|
3,384
|
|
|
3.6
|
%
|
Total – Decoupled and Special Contracts
|
5,653
|
|
|
5,688
|
|
|
(0.6
|
)%
|
|
36,537
|
|
|
42,134
|
|
|
(13.3
|
)%
|
Total Sales Volumes
|
10,923
|
|
|
11,137
|
|
|
(1.9
|
)%
|
|
68,107
|
|
|
78,489
|
|
|
(13.2
|
)%
|
|
|
(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 third quarter of 2016, retail electric sales volumes at our electric utilities with a traditional rate structure (NSTAR Electric and PSNH) remained relatively unchanged, as compared to the third quarter of 2015. Favorable results due to weather in the third quarter of 2016 were offset by lower customer usage driven by the impact of increased customer energy conservation efforts, including those resulting from company-sponsored energy efficiency programs, which resulted in flat traditional retail electric sales volumes. For the first nine months of 2016, retail electric sales volumes at our electric utilities with a traditional rate structure were lower, as compared to the first nine months of 2015, due primarily to lower customer usage driven by the impact of increased customer energy conservation efforts, including those resulting from company-sponsored energy efficiency programs, and the impact of warmer than normal weather in the first quarter of 2016 throughout those service territories, as compared to the much colder than normal temperatures in the first quarter of 2015. Heating degree days for the first nine months 2016 were 18.4 percent lower in the Boston metropolitan area and 17.9 percent lower in New Hampshire, as compared to the same period in 2015.
On January 28, 2016, 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 volume as a result of successful energy efficiency programs. LBR is recovered from retail customers through current rates. NSTAR Electric recognized LBR of $17.4 million and $44.1 million in the third quarter and first nine months of 2016, respectively, compared to $19 million and $46.7 million in the third quarter and first nine months of 2015, respectively.
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. In the third quarter of 2016, our consolidated firm natural gas sales volumes were lower, as compared to the third quarter of 2015. Consolidated firm natural gas sales volumes were much lower in the first nine months of 2016, as compared to the first nine months of 2015. The first nine months of 2016 firm natural gas sales volumes were negatively impacted by warmer than normal weather in the first quarter of 2016, as compared to the much colder than normal temperatures in the first quarter of 2015, throughout our natural gas service territories. Heating degree days for the first nine months of 2016 were 16.7 percent lower in Connecticut, as compared to the same period in 2015.
Liquidity
Consolidated:
Cash and cash equivalents totaled
$40.1 million
as of
September 30, 2016
, compared with
$23.9 million
as of
December 31, 2015
.
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, 2016
and
December 31, 2015
, Eversource parent had
$698.5 million
and approximately
$1.1 billion
, respectively, in short-term borrowings outstanding under the Eversource parent commercial paper program, leaving
$751.5 million
and
$351.5 million
of available borrowing capacity as of
September 30, 2016
and
December 31, 2015
, respectively. The weighted-average interest rate on these borrowings as of
September 30, 2016
and
December 31, 2015
was
0.66 percent
and
0.72 percent
, respectively. As of
September 30, 2016
, there were intercompany loans from Eversource parent of
$108.5 million
to CL&P,
$107.5 million
to PSNH, and
$48.2 million
to WMECO. As of
December 31, 2015
, there were intercompany loans from Eversource parent of
$277.4 million
to CL&P,
$231.3 million
to PSNH and
$143.4 million
to WMECO. Eversource parent, CL&P, PSNH, WMECO, NSTAR Gas and Yankee Gas are parties to a
five
-year
$1.45 billion
revolving credit facility. Effective September 26, 2016, the revolving credit facility’s termination date was extended for one additional year to 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, 2016 or December 31, 2015.
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, 2016
and
December 31, 2015
, NSTAR Electric had
$36.0 million
and
$62.5 million
, respectively, in short-term borrowings outstanding under its commercial paper program, leaving
$414.0 million
and
$387.5 million
of available borrowing capacity as of
September 30, 2016
and
December 31, 2015
, respectively. The weighted-average interest rate on these borrowings as of
September 30, 2016
and
December 31, 2015
was
0.42 percent
and
0.40 percent
, respectively. NSTAR Electric is a party to a
five
-year
$450 million
revolving credit facility. Effective September 26, 2016, the revolving credit facility’s termination date was extended for one additional year to 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, 2016 or December 31, 2015.
Short-Term Borrowing Limits:
The amount of short-term borrowings that may be incurred by NSTAR Electric is subject to periodic approval by the FERC. On August 8, 2016, the FERC granted authorization to allow NSTAR Electric to issue total short-term debt securities in an aggregate principal amount not to exceed $655 million outstanding at any one time, through October 23, 2018.
Cash Flows:
Cash flows provided by operating activities totaled
$1.65 billion
in the first
nine months
of
2016
, compared with
$1.35 billion
in the first
nine months
of
2015
. The increase in operating cash flows was due primarily to an increase in regulatory recoveries, primarily at NSTAR Electric, due to collections from customers in excess of purchased power costs, a $94.8 million net favorable impact due to the change in income tax payments made, or refunds received, a decrease of $41 million in Pension and PBOP plan cash contributions and the timing of payments related to accounts payable. Partially offsetting these favorable impacts was the timing of collections and payments related to our working capital items.
Credit Ratings:
On July 6, 2016, Fitch upgraded the corporate credit ratings by one level and changed the outlooks to stable from positive for CL&P, PSNH and WMECO. Also on July 6, 2016, Fitch changed the outlook on Eversource parent from stable to positive. On July 12, 2016, S&P changed its outlook on Eversource and its subsidiaries from stable to positive. On July 19, 2016, Moody’s upgraded PSNH’s corporate credit rating by one level and changed the outlook from positive to stable.
A summary of our corporate credit ratings and outlooks by Moody’s, S&P and Fitch is as follows:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Moody’s
|
|
S&P
|
|
Fitch
|
|
Current
|
|
Outlook
|
|
Current
|
|
Outlook
|
|
Current
|
|
Outlook
|
Eversource Parent
|
Baa1
|
|
Stable
|
|
A
|
|
Positive
|
|
BBB+
|
|
Positive
|
CL&P
|
Baa1
|
|
Stable
|
|
A
|
|
Positive
|
|
A-
|
|
Stable
|
NSTAR Electric
|
A2
|
|
Stable
|
|
A
|
|
Positive
|
|
A
|
|
Stable
|
PSNH
|
A3
|
|
Stable
|
|
A
|
|
Positive
|
|
A-
|
|
Stable
|
WMECO
|
A2
|
|
Stable
|
|
A
|
|
Positive
|
|
A-
|
|
Stable
|
A summary of the current credit ratings and outlooks by Moody’s, S&P and Fitch for senior unsecured debt of Eversource parent, NSTAR Electric, and WMECO and senior secured debt of CL&P and PSNH is as follows:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Moody’s
|
|
S&P
|
|
Fitch
|
|
Current
|
|
Outlook
|
|
Current
|
|
Outlook
|
|
Current
|
|
Outlook
|
Eversource Parent
|
Baa1
|
|
Stable
|
|
A-
|
|
Positive
|
|
BBB+
|
|
Positive
|
CL&P
|
A2
|
|
Stable
|
|
A+
|
|
Positive
|
|
A+
|
|
Stable
|
NSTAR Electric
|
A2
|
|
Stable
|
|
A
|
|
Positive
|
|
A+
|
|
Stable
|
PSNH
|
A1
|
|
Stable
|
|
A+
|
|
Positive
|
|
A+
|
|
Stable
|
WMECO
|
A2
|
|
Stable
|
|
A
|
|
Positive
|
|
A
|
|
Stable
|
On September 7, 2016, our Board of Trustees approved a common share dividend payment of $0.445 per share, which was paid on September 30, 2016 to shareholders of record as of September 19, 2016.
In the first
nine months
of
2016
, we paid cash dividends on common shares of
$423.5 million
, compared with
$397.4 million
in the first
nine months
of
2015
.
In the first
nine months
of
2016
, CL&P, NSTAR Electric, PSNH, and WMECO paid
$149.7 million
,
$278.3 million
,
$58.2 million
, and
$28.5 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 portions of pension expense. In the first
nine months
of
2016
, investments for Eversource, CL&P, NSTAR Electric, PSNH, and WMECO were
$1.36 billion
,
$438.5 million
,
$327.7 million
,
$215.8 million
, and
$104.8 million
, respectively.
Business Development and Capital Expenditures
Our consolidated capital expenditures, including amounts incurred but not paid, cost of removal, AFUDC, and the capitalized portions of pension expense (all of which are non-cash factors), totaled
$1.43 billion
in the first
nine months
of
2016
, compared to
$1.26 billion
in the first
nine months
of
2015
. These amounts included
$87.1 million
and
$58.6 million
in the first
nine months
of
2016
and
2015
, respectively, related to information technology and facilities upgrades and enhancements, primarily at Eversource Service and The Rocky River Realty Company.
Natural Gas Transmission Business:
Access Northeast
: Access Northeast is a natural gas pipeline and storage project (the Project) being developed jointly by Eversource, Spectra Energy Partners, LP (Spectra) and National Grid plc (National Grid), through Algonquin Gas Transmission, LLC (AGT). The Project
will enhance the Algonquin and Maritimes & Northeast pipeline systems using existing routes and will include two new LNG storage tanks and liquefaction and vaporization facilities in Acushnet, Massachusetts that will be connected to the Algonquin natural gas pipeline. The Project is expected to be capable of delivering approximately 900 million cubic feet of additional natural gas per day to New England on peak demand days. Eversource and Spectra each own a 40 percent interest in the Project, with the remaining 20 percent interest owned by National Grid. The total projected cost for both the pipeline and the LNG storage facilities is expected to be approximately $3 billion, with projected in-service dates commencing in November 2018. The Project is subject to FERC and other federal and state regulatory approvals.
As part of the Project’s development, AGT sought to secure long-term natural gas transmission capacity contracts with many of the electric distribution companies (EDCs) of New England. In Connecticut, on June 2, 2016, the DEEP issued an RFP for natural gas pipeline capacity and storage. Proposals were submitted on June 29, 2016. On October 25, 2016, the DEEP canceled this RFP process without prejudice. The DEEP retains its authority to issue future RFPs to procure natural gas resources for the purpose of providing more reliable electric service for the benefit of the Connecticut customers and to meet the state’s energy and environmental goals and policies.
On June 30, 2016, a subsidiary of National Grid filed with the Rhode Island Public Utilities Commission (RIPUC) seeking approval of its contract with AGT for natural gas pipeline capacity and storage. The RIPUC has placed a stay on the docket and asked National Grid for a status update in January 2017. On September 14, 2016, the Maine PUC issued an order to move forward with a contract with AGT for natural gas pipeline capacity, contingent upon the participation by EDCs in other New England states.
In late 2015 and early 2016, NSTAR Electric, WMECO and a subsidiary of National Grid filed with the Massachusetts DPU seeking approval of contracts with AGT for natural gas pipeline capacity and storage. The DPU had determined in 2015 that it had authority to approve such contracts if they were found to be in the public interest. On August 17, 2016, the Massachusetts Supreme Judicial Court vacated the DPU’s 2015 order, holding that the state’s electric utility restructuring statutes precluded the DPU from approving contracts by EDCs for natural gas capacity.
On February 18, 2016, PSNH filed with the NHPUC seeking approval of its contract with AGT for natural gas pipeline capacity and storage. On October 6, 2016, contrary to a 2015 recommendation from its staff, the NHPUC ruled that it did not have authority to approve such contracts under the state’s electric utility restructuring statutes.
Eversource, Spectra and National Grid are currently reviewing options surrounding the Project, with respect to the impact of the decisions from both the Massachusetts Supreme Judicial Court and the NHPUC, in order to help bring needed additional natural gas transmission and storage capacity to New England. The timing, configuration and cost of the Project could change, depending on the outcome of the potential options selected. At this time, we cannot predict the outcome of the potential options selected. At this time, we cannot predict the outcome of the potential options selected and, as a result, the potential impacts on our financial position, results of operations, or cash flows.
Electric Transmission Business:
Our consolidated electric transmission business capital expenditures
increased
by
$37.1 million
in the first
nine months
of
2016
, as compared to the first
nine months
of
2015
. A summary of electric transmission capital expenditures by company is as follows:
|
|
|
|
|
|
|
|
|
|
For the Nine Months Ended September 30,
|
(Millions of Dollars)
|
2016
|
|
2015
|
CL&P
|
$
|
211.8
|
|
|
$
|
146.9
|
|
NSTAR Electric
|
162.6
|
|
|
158.9
|
|
PSNH
|
80.2
|
|
|
115.2
|
|
WMECO
|
75.7
|
|
|
72.9
|
|
NPT
|
28.4
|
|
|
27.7
|
|
Total Electric Transmission Segment
|
$
|
558.7
|
|
|
$
|
521.6
|
|
GHCC
: The Greater Hartford Central Connecticut (GHCC) solutions, which have been approved by ISO-NE, consist of 27 projects with an expected investment of approximately $350 million that are expected to be placed in service from 2016 through 2018. Seven projects have been placed in service, and 8 projects are in active construction. As of September 30, 2016, CL&P had capitalized $93 million in costs associated with GHCC.
Northern Pass
:
Northern Pass is Eversource’s 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 July 21, 2015, the DOE issued the draft Environmental Impact Statement (EIS) for Northern Pass representing a key milestone in the permitting process. The DOE completed the comment period on the draft EIS on April 4, 2016, and is expected to issue the final EIS in the first quarter of 2017. On August 18, 2015, NPT announced the Forward NH Plan, including a commitment to allocate $200 million to projects associated with economic development, tourism, community betterment, and clean energy innovations to benefit the state of New Hampshire.
On June 10, 2016, Northern Pass executed a settlement agreement with the NHPUC Staff regarding its petition to operate as a public utility once the project is fully permitted. On October 14, 2016, in an important foundational order for the Northern Pass project, the NHPUC approved the settlement agreement and granted NPT public utility status, conditioned on project approval. Additionally, on June 28, 2016, as part of the Forward NH Plan, PSNH filed a power purchase agreement (PPA) with the NHPUC. The PPA, combined with the Forward NH Plan, is expected to deliver over $1 billion of energy cost savings and other benefits over the contract term to New Hampshire customers. The Forward NH Plan and the PPA are both commitments that are contingent upon the Northern Pass transmission line going into commercial operation.
The New Hampshire Site Evaluation Committee (NH SEC) is currently in process of formal siting. The NH SEC is expected to issue an order on NPT no later than September 2017 and the project is expected to be operational by the end of 2019. On January 28, 2016, NPT bid into the three-state Clean Energy RFP process. For further information on the RFP process, see “Regulatory Developments and Rate Matters – General – Clean Energy RFP” in this
Management’s Discussion and Analysis of Financial Condition and Results of Operations.
Greater Boston Reliability Solutions
:
In February 2015, ISO-NE selected Eversource’s and National Grid’s proposed Greater Boston and New Hampshire Solution (Solution) to satisfy the requirements identified in the Greater Boston study. The Solution consists of a portfolio of some 40 electric transmission upgrades covering southern New Hampshire and northern Massachusetts in the Merrimack Valley and continuing into the greater Boston metropolitan area, of which 27 are in Eversource’s service territory. The NH SEC issued its written order approving the New Hampshire upgrades on October 4, 2016. We are currently pursuing the necessary regulatory and siting application approvals in Massachusetts. Construction has begun on several of the smaller projects not requiring siting approval. All upgrades are expected to be completed by the end of 2019. We estimate our portion of the investment in the Solution will be approximately $565 million, of which approximately $91 million has been capitalized through September 30, 2016.
Seacoast Reliability Project
: On April 12, 2016, PSNH filed a siting application with the NH SEC for the Seacoast Reliability Project, a 13-mile transmission line within several New Hampshire communities, which proposes to use a combination of overhead, underground and underwater line design to help meet the growing demand for electricity in the Seacoast region. In June 2016, the NH SEC accepted our application as complete and we expect the NH SEC decision by mid-2017. This project is expected to be completed by the end of 2018. We estimate our investment in this project will be approximately $77 million, of which approximately $11 million has been capitalized through September 30, 2016.
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
|
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
|
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
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2015
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Basic Business
|
$
|
87.8
|
|
|
$
|
75.2
|
|
|
$
|
37.8
|
|
|
$
|
12.2
|
|
|
$
|
213.0
|
|
|
$
|
35.1
|
|
|
$
|
248.1
|
|
Aging Infrastructure
|
120.0
|
|
|
69.8
|
|
|
33.9
|
|
|
13.5
|
|
|
237.2
|
|
|
71.8
|
|
|
309.0
|
|
Load Growth
|
29.6
|
|
|
30.5
|
|
|
15.8
|
|
|
4.6
|
|
|
80.5
|
|
|
25.9
|
|
|
106.4
|
|
Total Distribution
|
237.4
|
|
|
175.5
|
|
|
87.5
|
|
|
30.3
|
|
|
530.7
|
|
|
132.8
|
|
|
663.5
|
|
Generation
|
—
|
|
|
—
|
|
|
15.9
|
|
|
—
|
|
|
15.9
|
|
|
—
|
|
|
15.9
|
|
Total Electric and Natural Gas Distribuion Segment
|
$
|
237.4
|
|
|
$
|
175.5
|
|
|
$
|
103.4
|
|
|
$
|
30.3
|
|
|
$
|
546.6
|
|
|
$
|
132.8
|
|
|
$
|
679.4
|
|
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 includes requests for new business and capacity additions on distribution lines and substation additions and expansions. For the natural gas distribution segment, 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 reflects growth in existing service territories including new developments, installation of services, and expansion.
The natural gas distribution segment’s capital spending program increased by $47.4 million in the first nine months of 2016, as compared to the first nine months of 2015, as a result of an increase in the replacement of aging pipeline, upgrades to our LNG facilities, and the favorable weather conditions in 2016 allowing for more capital spending on replacement and customer expansion.
FERC Regulatory Matters
FERC ROE Complaints:
Four separate complaints have been filed at FERC by combinations of New England state attorneys general, state regulatory commissions, consumer advocates, consumer groups, municipal parties and other parties. Each complaint challenges the NETOs’ previous base ROE of 11.14 percent or current base ROE of 10.57 percent and seeks to reduce it both for the four separate 15-month complaint periods and prospectively.
The FERC ordered a 10.57 percent base ROE for the first complaint period and prospectively from October 16, 2014, and that a utility’s total or maximum ROE for any incentive projects shall not exceed the top of the new zone of reasonableness, which was set at 11.74 percent. We have refunded all amounts associated with the first complaint period.
The Company has recorded reserves across the complaint periods at its electric subsidiaries. In the first nine months of 2015, the Company recognized an after-tax charge to earnings (excluding interest) of $12.4 million, of which $7.9 million was recorded at CL&P, $1.4 million at NSTAR Electric, $0.6 million at PSNH, and $2.5 million at WMECO.
On March 22, 2016, the FERC ALJ issued an initial decision on the second and third complaints. For the second complaint period, the FERC ALJ recommended a zone of reasonableness of 7.12 percent to 10.42 percent and a base ROE of 9.59 percent. For the third complaint period, the FERC ALJ recommended a zone of reasonableness of 7.04 percent to 12.19 percent and a base ROE of 10.90 percent. The FERC ALJ also affirmed that the maximum ROE for transmission incentive projects should be the top of the zone of reasonableness. The NETOs filed briefs on April 21, 2016, in which the NETOs identified corrections and requested changes that should be made to the FERC ALJ’s recommendations. A final FERC order is expected in late 2016 or early 2017. The final FERC order will determine both the base ROE and the maximum ROE for transmission incentive projects for the two complaint periods.
We have not recorded any additional reserves to reflect the ROEs recommended in the FERC ALJ initial decision. We do not believe any ROE outcome is more likely than the ROEs used to record our current reserves (a base ROE of 10.57 percent and a maximum ROE for transmission incentive projects of 11.74 percent). We are unable to predict the outcome of the final FERC order on the second and third complaints, and therefore, we believe that our current ROEs and reserves are appropriate at this time.
The impact of a 10 basis point change to our existing base ROE of 10.57 percent would affect Eversource’s after-tax earnings by approximately $3 million for each of the 15-month second and third complaint periods. If we adjusted our reserves based on the recommendations in the FERC ALJ initial decision (for both the base ROE and maximum ROE for transmission incentive projects) for the second and third complaints, then it would result in an after-tax increase of approximately $34 million and an after-tax decrease of approximately $8 million, respectively, to our existing reserves.
For the
fourth complaint, filed April 29, 2016, certain municipal utilities claimed the current base ROE of 10.57 percent and the incentive cap of 11.74 percent are unjust and unreasonable. The NETOs answered on June 3, 2016 and requested that FERC dismiss the complaint. On September 20, 2016, FERC issued an order establishing hearing and settlement judge procedures
and set a 15-month complaint period beginning April 29, 2016. We cannot at this time predict the ultimate outcome of this proceeding or the estimated impacts on the financial position, results of operations or cash flows of Eversource, CL&P, NSTAR Electric, PSNH and WMECO. A FERC ALJ initial decision could be received in 2017.
Regulatory Developments and Rate Matters
General:
Clean Energy RFP
:
Pursuant to clean energy goals established in three New England states (Connecticut, Massachusetts and Rhode Island), in November 2015, the DEEP and the Massachusetts and Rhode Island EDCs, including NSTAR Electric and WMECO, issued an RFP for clean energy resources (including Class I renewable generation and large hydroelectric generation) to a wide range of potentially interested bidders. The RFP solicited offers for clean energy and the transmission to deliver that energy to the three states. In late January 2016, bidders submitted project proposals, among which were the Northern Pass and Clean Energy Connect projects. On October 24, 2016, Eversource was notified that neither project was selected.
The Company is currently placing efforts on the next round of contracting opportunities, which it believes both NPT and the Clean Energy Connect projects would meet the legislative requirements. In August 2016, Massachusetts enacted legislation that requires electric distribution companies to jointly solicit RFPs and enter into long-term contracts for large-scale hydro projects. The law requires an RFP to take place in the spring of 2017. For further information on this legislation, see “Legislative and Policy Matters - Massachusetts” in this “
Management’s Discussion and Analysis of Financial Condition and Results of Operations.
”
Electric and Natural Gas Base Distribution Rates:
The Regulated 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 months
of
2016
, changes made to the Regulated 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
2015
Form 10-K.
Massachusetts:
October 2016 DPU Storm Order
: On October 7, 2016, the DPU issued a final decision on WMECO’s storm cost filing that sought to recover $27 million of storm restoration costs associated with the October 2011 snowstorm and Storm Sandy in 2012. The DPU approved the majority of the costs, with the disallowed amounts and other items included in a filed motion for reconsideration.
New Hampshire:
Generation Asset Sale
: 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. In addition, PSNH will not seek a general distribution rate increase effective before July 1, 2017 and will contribute $5 million to create a clean energy fund, which will not be recoverable from its customers. In the first nine months of 2015, PSNH recorded the $5 million contribution as a long-term liability and an increase to Operations and Maintenance expense on the statements of income.
On July 1, 2016, the NHPUC approved the Agreement in an order that, among other things, instructs PSNH to begin the process to divest its generation assets. The NHPUC selected an auction adviser to assist with the divestiture, and a final plan and auction process will be determined by the NHPUC in the fourth quarter of 2016. Upon completion of the divestiture process, all remaining stranded costs will be recovered via bonds that will be secured by a non-bypassable charge or through recoveries in rates billed to PSNH’s customers.
We believe that full recovery of PSNH’s generation assets is probable through a combination of cash flows during the remaining operating period, sales proceeds upon divestiture, and recovery of stranded costs in future rates.
As of September 30, 2016, PSNH’s energy service rate base was approximately $640 million. This rate base will be reduced by the amount of generation assets that are divested.
Legislative and Policy Matters
Massachusetts:
On August 8, 2016, in conjunction with efforts to shape comprehensive energy legislation, “An Act to Promote Energy Diversity” became law in Massachusetts, which requires electric distribution companies to jointly solicit RFPs and enter into 15- to 20-year contracts for at least 1,600 MW of offshore wind and up to an additional 1,200 MW of hydropower or other renewable sources, such as land-based wind or solar, provided that reasonable proposals have been received.
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
2015
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 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
2015
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’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 nine
months ended
September 30, 2016
and
2015
included in this combined Quarterly Report on Form 10-Q:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
For the Three Months Ended September 30,
|
|
For the Nine Months Ended September 30,
|
(Millions of Dollars)
|
2016
|
|
2015
|
|
Increase/(Decrease)
|
|
Percent
|
|
2016
|
|
2015
|
|
Increase/(Decrease)
|
|
Percent
|
Operating Revenues
|
$
|
2,039.7
|
|
|
$
|
1,933.1
|
|
|
$
|
106.6
|
|
|
5.5
|
%
|
|
$
|
5,862.5
|
|
|
$
|
6,263.6
|
|
|
$
|
(401.1
|
)
|
|
(6.4
|
)%
|
Operating Expenses:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Purchased Power, Fuel and Transmission
|
665.8
|
|
|
702.6
|
|
|
(36.8
|
)
|
|
(5.2
|
)
|
|
2,001.9
|
|
|
2,549.8
|
|
|
(547.9
|
)
|
|
(21.5
|
)
|
Operations and Maintenance
|
324.7
|
|
|
327.3
|
|
|
(2.6
|
)
|
|
(0.8
|
)
|
|
965.6
|
|
|
977.3
|
|
|
(11.7
|
)
|
|
(1.2
|
)
|
Depreciation
|
181.3
|
|
|
167.9
|
|
|
13.4
|
|
|
8.0
|
|
|
531.8
|
|
|
495.4
|
|
|
36.4
|
|
|
7.3
|
|
Amortization of Regulatory Assets/(Liabilities), Net
|
43.9
|
|
|
(16.8
|
)
|
|
60.7
|
|
|
(a)
|
|
|
56.2
|
|
|
42.6
|
|
|
13.6
|
|
|
31.9
|
|
Energy Efficiency Programs
|
149.1
|
|
|
132.1
|
|
|
17.0
|
|
|
12.9
|
|
|
406.0
|
|
|
380.6
|
|
|
25.4
|
|
|
6.7
|
|
Taxes Other Than Income Taxes
|
165.0
|
|
|
150.8
|
|
|
14.2
|
|
|
9.4
|
|
|
479.2
|
|
|
439.2
|
|
|
40.0
|
|
|
9.1
|
|
Total Operating Expenses
|
1,529.8
|
|
|
1,463.9
|
|
|
65.9
|
|
|
4.5
|
|
|
4,440.7
|
|
|
4,884.9
|
|
|
(444.2
|
)
|
|
(9.1
|
)
|
Operating Income
|
509.9
|
|
|
469.2
|
|
|
40.7
|
|
|
8.7
|
|
|
1,421.8
|
|
|
1,378.7
|
|
|
43.1
|
|
|
3.1
|
|
Interest Expense
|
99.9
|
|
|
92.5
|
|
|
7.4
|
|
|
8.0
|
|
|
298.6
|
|
|
279.6
|
|
|
19.0
|
|
|
6.8
|
|
Other Income, Net
|
13.6
|
|
|
5.2
|
|
|
8.4
|
|
|
(a)
|
|
|
23.7
|
|
|
23.9
|
|
|
(0.2
|
)
|
|
(0.8
|
)
|
Income Before Income Tax Expense
|
423.6
|
|
|
381.9
|
|
|
41.7
|
|
|
10.9
|
|
|
1,146.9
|
|
|
1,123.0
|
|
|
23.9
|
|
|
2.1
|
|
Income Tax Expense
|
156.4
|
|
|
144.1
|
|
|
12.3
|
|
|
8.5
|
|
|
428.2
|
|
|
420.7
|
|
|
7.5
|
|
|
1.8
|
|
Net Income
|
267.2
|
|
|
237.8
|
|
|
29.4
|
|
|
12.4
|
|
|
718.7
|
|
|
702.3
|
|
|
16.4
|
|
|
2.3
|
|
Net Income Attributable to Noncontrolling Interests
|
1.9
|
|
|
1.9
|
|
|
—
|
|
|
—
|
|
|
5.6
|
|
|
5.6
|
|
|
—
|
|
|
—
|
|
Net Income Attributable to Common Shareholders
|
$
|
265.3
|
|
|
$
|
235.9
|
|
|
$
|
29.4
|
|
|
12.5
|
%
|
|
$
|
713.1
|
|
|
$
|
696.7
|
|
|
$
|
16.4
|
|
|
2.4
|
%
|
|
|
(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)
|
2016
|
|
2015
|
|
Increase/(Decrease)
|
|
Percent
|
|
2016
|
|
2015
|
|
Increase/(Decrease)
|
|
Percent
|
Electric Distribution
|
$
|
1,623.4
|
|
|
$
|
1,543.7
|
|
|
$
|
79.7
|
|
|
5.2
|
%
|
|
$
|
4,362.6
|
|
|
$
|
4,686.5
|
|
|
$
|
(323.9
|
)
|
|
(6.9
|
)%
|
Natural Gas Distribution
|
99.2
|
|
|
106.2
|
|
|
(7.0
|
)
|
|
(6.6
|
)
|
|
622.3
|
|
|
799.6
|
|
|
(177.3
|
)
|
|
(22.2
|
)
|
Electric Transmission
|
306.8
|
|
|
270.4
|
|
|
36.4
|
|
|
13.5
|
|
|
892.5
|
|
|
787.2
|
|
|
105.3
|
|
|
13.4
|
|
Other and Eliminations
|
10.3
|
|
|
12.8
|
|
|
(2.5
|
)
|
|
(19.5
|
)
|
|
(14.9
|
)
|
|
(9.7
|
)
|
|
(5.2
|
)
|
|
53.6
|
|
Total Operating Revenues
|
$
|
2,039.7
|
|
|
$
|
1,933.1
|
|
|
$
|
106.6
|
|
|
5.5
|
%
|
|
$
|
5,862.5
|
|
|
$
|
6,263.6
|
|
|
$
|
(401.1
|
)
|
|
(6.4
|
)%
|
A summary of our retail electric GWh sales volumes and our firm natural gas sales volumes in Mcf were as follows:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
For the Three Months Ended September 30,
|
|
For the Nine Months Ended September 30,
|
|
2016
|
|
2015
|
|
Increase/(Decrease)
|
|
Percent
|
|
2016
|
|
2015
|
|
Decrease
|
|
Percent
|
Electric
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Traditional
|
8,131
|
|
|
8,136
|
|
|
(5
|
)
|
|
(0.1
|
)%
|
|
21,731
|
|
|
22,309
|
|
|
(578
|
)
|
|
(2.6
|
)%
|
Decoupled
|
7,213
|
|
|
7,070
|
|
|
143
|
|
|
2.0
|
|
|
19,235
|
|
|
19,865
|
|
|
(630
|
)
|
|
(3.2
|
)
|
Total Electric
|
15,344
|
|
|
15,206
|
|
|
138
|
|
|
0.9
|
|
|
40,966
|
|
|
42,174
|
|
|
(1,208
|
)
|
|
(2.9
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Firm Natural Gas
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Traditional
|
5,270
|
|
|
5,449
|
|
|
(179
|
)
|
|
(3.3
|
)
|
|
31,570
|
|
|
36,355
|
|
|
(4,785
|
)
|
|
(13.2
|
)
|
Decoupled and Special Contracts
|
5,653
|
|
|
5,688
|
|
|
(35
|
)
|
|
(0.6
|
)
|
|
36,537
|
|
|
42,134
|
|
|
(5,597
|
)
|
|
(13.3
|
)
|
Total Firm Natural Gas
|
10,923
|
|
|
11,137
|
|
|
(214
|
)
|
|
(1.9
|
)%
|
|
68,107
|
|
|
78,489
|
|
|
(10,382
|
)
|
|
(13.2
|
)%
|
Three Months Ended:
Operating Revenues, which primarily consist of base electric and natural gas distribution revenues and tracked revenues further described below, increased by
$106.6 million
for the three months ended September 30, 2016, as compared to the same period in 2015.
Base electric distribution revenues
: Base electric distribution segment revenues increased $7.8 million due primarily to a higher rate base resulting from the 2015 PURA ADIT settlement agreement that is being collected from customers in distribution rates at CL&P ($5.4 million) and the absence of an authorized ROE reduction in 2015, as stipulated in the PURA 2014 rate case decision, at CL&P ($1.1 million).
Fluctuations in CL&P’s, WMECO’s and NSTAR Gas’ sales volumes do not impact the level of base distribution revenue realized or earnings due to their respective regulatory commission approved revenue decoupling mechanisms. The revenue decoupling mechanisms permit recovery of a base amount of distribution revenues and break the relationship between sales volumes and revenues recognized. Revenue decoupling mechanisms result in the recovery of our approved base distribution revenue requirements.
Tracked distribution revenues:
Tracked revenues consist of certain costs that are recovered from customers in rates through regulatory commission-approved cost tracking mechanisms and therefore have 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, tracked revenues include certain incentives earned and carrying charges. Tracked electric distribution segment revenues increased as a result of an increase in retail electric transmission charges ($45 million), an increase in federally mandated congestion charges ($40.5 million), an increase in energy efficiency program revenues ($17.4 million), an increase in stranded cost recovery charges ($13.6 million) and an increase in net metering for distributed generation revenues ($10.8 million), partially offset by decreases in energy supply costs ($60.4 million), driven by decreased average retail rates. In addition, as a result of a change to the amounts collected in the system benefits charge, CL&P’s calculated rate base increased, providing an increase to distribution revenues that impacted earnings of $8.2 million.
The third quarter 2016 tracked natural gas distribution segment revenues decreased as a result of decreases in natural gas supply costs ($5.4 million) and a decrease in energy efficiency program revenues ($2.5 million).
Electric transmission revenues:
The electric transmission segment revenues increased by $36.4 million due primarily to the recovery of higher revenue requirements associated with ongoing investments in our transmission infrastructure.
Nine Months Ended:
Operating Revenues decreased by
$401.1 million
for the nine months ended September 30, 2016, as compared to the same period in 2015.
Base electric and natural gas distribution revenues
: Base electric distribution segment revenues increased by $5.6 million due primarily to a higher rate base resulting from the 2015 PURA ADIT settlement agreement that is being collected from customers in distribution rates at CL&P ($16.1 million) and the absence of an authorized ROE reduction in 2015, as stipulated in the PURA 2014 rate case decision, at CL&P ($3.3 million), partially offset by a 2.6 percent decrease in non-decoupled retail electric sales volumes due primarily to increased customer energy conservation efforts and warmer than normal weather in the first quarter of 2016, as compared to the much colder than normal temperatures in the first quarter of 2015 ($13.8 million).
Contributing to the decrease in operating revenues in the first nine months of 2016 was the absence of an $11 million benefit related to the Comprehensive Settlement Agreement associated with the recovery of LBR related to 2009 through 2011 energy efficiency programs recorded at NSTAR Electric in the first quarter of 2015.
Firm natural gas base distribution segment revenues decreased $9.2 million due primarily to a 13.2 percent decrease in traditional firm natural gas sales volumes as a result of warmer than normal weather experienced in the first quarter of 2016, as compared to much colder than normal temperatures in the first quarter of 2015, partially offset by the impact of the NSTAR Gas base distribution rate increase effective January 1, 2016.
Tracked distribution revenues:
Tracked electric distribution segment revenues decreased as a result of decreases in energy supply costs ($570.3 million), driven by decreased average retail rates and lower sales volumes, partially offset by an increase in retail electric transmission charges ($82.9 million), an increase in federally mandated congestion charges ($70.4 million), an increase in energy efficiency program revenues ($45.2 million), an increase in stranded cost recovery charges ($29.5 million) and an increase in net metering for distributed generation revenues ($25.7 million). In addition, as a result of a change to the amounts collected in the system benefits charge, CL&P’s calculated rate base increased, providing an increase to distribution revenues that impacted earnings of $17.5 million.
The first nine months of 2016 tracked natural gas distribution segment revenues decreased as a result of decreases in natural gas supply costs ($143.2 million) driven by decreased average rates and lower sales volumes, and a decrease in energy efficiency program revenues ($25.5 million).
Electric transmission revenues:
The electric transmission segment revenues increased by $105.3 million due primarily to the recovery of higher revenue requirements associated with ongoing investments in our transmission infrastructure and the absence in 2016 of a $20 million reserve charge recorded in the first quarter of 2015 associated with the March 2015 FERC ROE order.
Other:
Other revenues decreased due primarily to the sale of Eversource’s unregulated contracting business on April 13, 2015 ($11.4 million).
Purchased Power, Fuel and Transmission
expense includes costs associated with purchasing electricity and natural gas on behalf of our customers. These energy supply costs are recovered from customers in rates through cost tracking mechanisms, which have no impact on earnings (tracked costs). Purchased Power, Fuel and Transmission expense decreased for the three and nine months ended September 30, 2016, as compared to the same periods in 2015, due primarily to the following:
|
|
|
|
|
|
|
|
|
(Millions of Dollars)
|
Three Months Ended
Increase/(Decrease)
|
|
Nine Months Ended
Increase/(Decrease)
|
Electric Distribution
|
$
|
(98.5
|
)
|
|
$
|
(551.3
|
)
|
Natural Gas Distribution
|
(6.3
|
)
|
|
(142.2
|
)
|
Transmission
|
68.0
|
|
|
145.6
|
|
Total Purchased Power, Fuel and Transmission
|
$
|
(36.8
|
)
|
|
$
|
(547.9
|
)
|
The decrease in purchased power expense at the electric distribution business was driven by lower prices associated with the procurement of energy supply and a decrease in the amount of electricity generated by PSNH facilities for both the three and nine months ended September 30, 2016, as compared to the same periods in 2015, as well as lower sales volumes for the nine months ended September 30, 2016, as compared to the same period in 2015. The decrease in purchased power expense at the natural gas distribution business was due to lower sales volumes and lower average natural gas prices. The increase in transmission costs was primarily the result of an increase in costs billed by ISO-NE that support regional grid investment.
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 decreased for the three and nine months ended September 30, 2016, as compared to the same periods in 2015, due primarily to the following:
|
|
|
|
|
|
|
|
|
(Millions of Dollars)
|
Three Months Ended
Increase/(Decrease)
|
|
Nine Months Ended
Increase/(Decrease)
|
Base Electric Distribution:
|
|
|
|
Absence of 2015 resolution of basic service bad debt adder mechanism at NSTAR Electric
|
$
|
—
|
|
|
$
|
24.2
|
|
Storm restoration costs
|
5.0
|
|
|
11.3
|
|
Vegetation management costs
|
1.1
|
|
|
5.7
|
|
Employee-related expenses, including labor and benefits
|
(8.4
|
)
|
|
(13.7
|
)
|
Absence of 2015 contribution to create clean energy fund in connection with the generation divestiture agreement at PSNH
|
—
|
|
|
(5.0
|
)
|
Other operations and maintenance
|
3.5
|
|
|
1.1
|
|
Total Base Electric Distribution
|
1.2
|
|
|
23.6
|
|
Total Base Natural Gas Distribution:
|
|
|
|
Employee-related expenses, including labor and benefits
|
(0.1
|
)
|
|
(11.9
|
)
|
Other operations and maintenance
|
2.3
|
|
|
5.3
|
|
Total Base Natural Gas Distribution
|
2.2
|
|
|
(6.6
|
)
|
Total Tracked costs (Electric Distribution, Electric Transmission and Natural Gas Distribution)
|
13.9
|
|
|
21.6
|
|
Other and eliminations:
|
|
|
|
Integration costs
|
(2.9
|
)
|
|
(13.4
|
)
|
Absence of Eversource’s unregulated electrical contracting business due to sale in April 2015, net
|
(3.3
|
)
|
|
(13.9
|
)
|
Eversource Parent and Other Companies
|
(5.6
|
)
|
|
(10.1
|
)
|
Eliminations
|
(8.1
|
)
|
|
(12.9
|
)
|
Total Operations and Maintenance
|
$
|
(2.6
|
)
|
|
$
|
(11.7
|
)
|
Depreciation
expense increased for the three and nine months ended September 30, 2016, as compared to the same periods in 2015, due primarily to higher utility plant in service balances.
Amortization of Regulatory Assets/(Liabilities), Net
expense (the costs of which are tracked) include the deferral of energy supply and energy-related costs included in certain regulatory-approved tracking mechanisms, and the amortization of certain costs. The deferral adjusts expense to match the corresponding revenues. Amortization of Regulatory Assets/(Liabilities), Net, increased for the three and nine months ended September 30, 2016, as compared to the same periods in 2015, due primarily to the 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 supply and energy-related costs at CL&P, NSTAR Electric, PSNH and WMECO, which are the primary drivers in amortization, are recovered from customers in rates and have no impact on earnings. The increase in Amortization of Regulatory Assets/(Liabilities), Net for the nine months ended September 30, 2016 includes the absence in 2016 of the $11.7 million benefit recorded in the first quarter of 2015 at NSTAR Electric in connection with the Comprehensive Settlement Agreement associated with the CPSL program filings.
Energy Efficiency Programs
expense (the costs of which are tracked) increased for the three and nine months ended September 30, 2016, as compared to the same periods in 2015, due primarily to deferral adjustments at NSTAR Electric, partially offset by deferral adjustments for the natural gas businesses, which reflect the actual costs of energy efficiency programs compared to the estimated amounts billed to customers, and the timing of the recovery of energy efficiency costs incurred in accordance with the three-year program guidelines established by the DPU. The deferrals adjust expense to match the energy efficiency programs revenue. The costs for various 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 increased for the three and nine months ended September 30, 2016, as compared to the same periods in 2015, due primarily to an increase in property taxes as a result of higher utility plant balances and an increase in gross earnings taxes (the costs of which are tracked).
Interest Expense
increased for the three and nine months ended September 30, 2016, as compared to the same periods in 2015, due primarily to higher interest on long-term debt ($9.5 million and $25.7 million, respectively) as a result of new debt issuances, partially offset by an increase in AFUDC borrowed funds ($1.4 million and $2.9 million, respectively).
Other Income, Net
increased for the three months ended September 30, 2016, as compared to the same period in 2015, due primarily to higher AFUDC related to equity funds ($2.8 million), an increase related to officer insurance policies ($1.9 million), and an increase in net gains related to the deferred compensation plans ($0.8 million).
Income Tax Expense
increased for the three months ended September 30, 2016, as compared to the same period in 2015, due primarily to higher pre-tax earnings ($14.3 million), higher state income taxes ($3.4 million), and items that impact our tax rate as a result of regulatory treatment (flow-through items) and permanent differences ($2.4 million), partially offset by the true up of the return to provision impacts and a higher tax benefit from a reduction in tax reserves ($7.6 million).
Income Tax Expense increased for the nine months ended September 30, 2016, as compared to the same period in 2015, due primarily to higher pre-tax earnings ($9 million), higher state income taxes ($5.9 million), and flow-through items and permanent differences ($3.5 million), partially offset by the true up of the return to provision impacts and a higher tax benefit from a reduction in tax reserves ($7.6 million), and the excess tax benefit due to the adoption of new accounting guidance related to share-based payment transactions ($2.9 million).
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
September 30, 2016
and
2015
included in this combined Quarterly Report on Form 10-Q:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
For the Three Months Ended September 30,
|
|
For the Nine Months Ended September 30,
|
(Millions of Dollars)
|
2016
|
|
2015
|
|
Increase/
(Decrease)
|
|
Percent
|
|
2016
|
|
2015
|
|
Increase/
(Decrease)
|
|
Percent
|
Operating Revenues
|
$
|
760.0
|
|
|
$
|
704.3
|
|
|
$
|
55.7
|
|
|
7.9
|
%
|
|
$
|
2,175.1
|
|
|
$
|
2,175.7
|
|
|
$
|
(0.6
|
)
|
|
—
|
%
|
Operating Expenses:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Purchased Power and Transmission
|
253.5
|
|
|
274.8
|
|
|
(21.3
|
)
|
|
(7.8
|
)
|
|
760.6
|
|
|
861.6
|
|
|
(101.0
|
)
|
|
(11.7
|
)
|
Operations and Maintenance
|
123.0
|
|
|
122.3
|
|
|
0.7
|
|
|
0.6
|
|
|
356.4
|
|
|
358.3
|
|
|
(1.9
|
)
|
|
(0.5
|
)
|
Depreciation
|
57.7
|
|
|
54.8
|
|
|
2.9
|
|
|
5.3
|
|
|
172.2
|
|
|
159.9
|
|
|
12.3
|
|
|
7.7
|
|
Amortization of Regulatory Assets/(Liabilities), Net
|
23.4
|
|
|
(22.9
|
)
|
|
46.3
|
|
|
(a)
|
|
|
30.3
|
|
|
17.9
|
|
|
12.4
|
|
|
69.3
|
|
Energy Efficiency Programs
|
44.4
|
|
|
42.6
|
|
|
1.8
|
|
|
4.2
|
|
|
118.0
|
|
|
119.4
|
|
|
(1.4
|
)
|
|
(1.2
|
)
|
Taxes Other Than Income Taxes
|
81.9
|
|
|
71.6
|
|
|
10.3
|
|
|
14.4
|
|
|
227.9
|
|
|
201.7
|
|
|
26.2
|
|
|
13.0
|
|
Total Operating Expenses
|
583.9
|
|
|
543.2
|
|
|
40.7
|
|
|
7.5
|
|
|
1,665.4
|
|
|
1,718.8
|
|
|
(53.4
|
)
|
|
(3.1
|
)
|
Operating Income
|
176.1
|
|
|
161.1
|
|
|
15.0
|
|
|
9.3
|
|
|
509.7
|
|
|
456.9
|
|
|
52.8
|
|
|
11.6
|
|
Interest Expense
|
36.1
|
|
|
36.7
|
|
|
(0.6
|
)
|
|
(1.6
|
)
|
|
108.6
|
|
|
109.5
|
|
|
(0.9
|
)
|
|
(0.8
|
)
|
Other Income, Net
|
3.7
|
|
|
2.4
|
|
|
1.3
|
|
|
54.2
|
|
|
10.9
|
|
|
8.6
|
|
|
2.3
|
|
|
26.7
|
|
Income Before Income Tax Expense
|
143.7
|
|
|
126.8
|
|
|
16.9
|
|
|
13.3
|
|
|
412.0
|
|
|
356.0
|
|
|
56.0
|
|
|
15.7
|
|
Income Tax Expense
|
57.1
|
|
|
46.6
|
|
|
10.5
|
|
|
22.5
|
|
|
155.4
|
|
|
127.8
|
|
|
27.6
|
|
|
21.6
|
|
Net Income
|
$
|
86.6
|
|
|
$
|
80.2
|
|
|
$
|
6.4
|
|
|
8.0
|
%
|
|
$
|
256.6
|
|
|
$
|
228.2
|
|
|
$
|
28.4
|
|
|
12.4
|
%
|
Operating Revenues
CL&P’s retail sales volumes were as follows:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
For the Three Months Ended September 30,
|
|
For the Nine Months Ended September 30,
|
|
2016
|
|
2015
|
|
Increase
|
|
Percent
|
|
2016
|
|
2015
|
|
Decrease
|
|
Percent
|
Retail Sales Volumes in GWh
|
6,225
|
|
|
6,103
|
|
|
122
|
|
|
2.0
|
%
|
|
16,541
|
|
|
17,123
|
|
|
(582
|
)
|
|
(3.4
|
)%
|
Three Months Ended:
CL&P’s Operating Revenues, which consist of base distribution revenues and tracked revenues further described below, increased by $55.7 million for the three months ended September 30, 2016, as compared to the same period in 2015.
Base distribution revenues increased by $6.5 million due to a higher rate base resulting from the 2015 PURA ADIT settlement agreement that is being collected from customers in distribution rates ($5.4 million) and the absence of an authorized ROE reduction, as stipulated in the PURA 2014 rate case decision, recorded in the third quarter of 2015 ($1.1 million).
Fluctuations in 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, tracked revenues include certain incentives earned and carrying charges. Tracked distribution revenues increased primarily as a result of an increase in federally mandated congestion charges ($40.5 million), an increase in competitive transition assessment charges ($9.7 million) and an increase in retail transmission charges ($9.6 million). In addition, as a result of a change to the amounts collected in the system benefits charge, CL&P’s calculated rate base increased, providing an increase to distribution revenues that impacted earnings of $8.2 million. Partially offsetting these increases was a decrease in energy supply costs ($27.1 million) driven by decreased average retail rates.
Transmission revenues increased by $13.1 million due primarily to higher revenue requirements associated with ongoing investments in our transmission infrastructure.
Nine Months Ended:
CL&P’s Operating Revenues decreased by $0.6 million for the nine months ended September 30, 2016, as compared to the same period in 2015.
Base distribution revenues increased by $19.4 million due to a higher rate base resulting from the 2015 PURA ADIT settlement agreement that is being collected from customers in distribution rates ($16.1 million) and the absence of an authorized ROE reduction, as stipulated in the PURA 2014 rate case decision, recorded in the first nine months of 2015 ($3.3 million).
Tracked distribution revenues decreased primarily as a result of a decrease in energy supply costs ($187.1 million) driven by decreased average retail rates and lower sales volumes. Partially offsetting this decrease was an increase in retail transmission charges ($27.4 million), an increase in federally mandated congestion charges ($70.4 million) and an increase in competitive transition assessment charges ($24 million). In addition, as a result of a change to the amounts collected in the system benefits charge, CL&P’s calculated rate base increased, providing an increase to distribution revenues that impacted earnings of $17.5 million.
Transmission revenues increased by $49.3 million due primarily to higher revenue requirements associated with ongoing investments in our transmission infrastructure and the absence in 2016 of a $12.5 million reserve charge recorded in the first quarter of 2015 associated with the March 2015 FERC ROE order.
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 PURA-approved cost tracking mechanisms, which have no impact on earnings (tracked costs). Purchased Power and Transmission expense decreased for the three and nine months ended September 30, 2016, as compared to the same periods in 2015, due primarily to the following:
|
|
|
|
|
|
|
|
|
(Millions of Dollars)
|
Three Months Ended
Increase/(Decrease)
|
|
Nine Months Ended
Increase/(Decrease)
|
Purchased Power Costs
|
$
|
(37.0
|
)
|
|
$
|
(149.7
|
)
|
Transmission Costs
|
15.7
|
|
|
48.7
|
|
Total Purchased Power and Transmission
|
$
|
(21.3
|
)
|
|
$
|
(101.0
|
)
|
Included in purchased power costs are the costs associated with CL&P’s generation services charge (GSC) and deferred energy supply costs. The GSC 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 three months ended September 30, 2016, compared to the same period in 2015, was due primarily to the deferral adjustment of energy supply costs, which can fluctuate from period to period based upon the timing of costs incurred and the related rate changes to recover these costs. The decrease in purchased power costs for the nine months ended September 30, 2016, compared to the same period in 2015, was due primarily to a decrease in the prices of standard offer supply, as well as lower sales volumes. The increase in transmission costs was primarily the result of an increase in costs billed by ISO-NE that support regional grid investment.
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 three months ended September 30, 2016, as compared to the same period in 2015, driven by a $2.1 million increase in tracked costs, which was primarily attributable to higher transmission expenses, partially offset by a $1.4 million decrease in non-tracked costs, which was primarily attributable to lower public liability claims.
Operations and Maintenance expense decreased for the nine months ended September 30, 2016, as compared to the same period in 2015, driven by a $4.2 million decrease in non-tracked costs, which was primarily attributable to lower public liability claims, lower employee-related expenses, reimbursement of legal fees in the second quarter of 2016, and the absence in 2016 of integration costs recorded in the first nine months of 2015, partially offset by higher storm restoration costs. Tracked costs, which have no earnings impact, increased $2.3 million, which was primarily attributable to higher transmission expenses partially offset by lower bad debt expense.
Depreciation
expense increased for the three and nine months ended September 30, 2016, as compared to the same periods in 2015, due primarily to higher utility plant in service balances.
Amortization of Regulatory Assets/(Liabilities), Net
expense (the costs of which are tracked) includes the deferral of energy supply and energy-related costs and the amortization of storm and other costs. Amortization of Regulatory Assets/(Liabilities), Net increased for the three and nine months ended September 30, 2016, as compared to the same periods in 2015, due primarily 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. The deferral adjusts expense to match the corresponding revenues. Energy supply and energy-related costs, which are the primary drivers in amortization, are recovered from customers in rates and have no impact on earnings.
Taxes Other Than Income Taxes
expense increased for the three and nine months ended September 30, 2016, as compared to the same periods in 2015, due primarily to an increase in property taxes as a result of higher utility plant balances and an increase in gross earnings taxes (the costs of which are tracked).
Income Tax Expense
increased for the three months ended September 30, 2016, as compared to the same period in 2015, due primarily to higher pre-tax earnings ($5.9 million), higher state income taxes ($0.8 million), and items that impact our tax rate as a result of regulatory treatment (flow-through items) and permanent differences ($4.3 million), partially offset by the true up of the return to provision impacts and a lower tax benefit from a reduction in tax reserves ($0.5 million).
Income Tax Expense increased for the nine months ended September 30, 2016, as compared to the same period in 2015, due primarily to higher pre-tax earnings ($19.6 million), higher state income taxes ($2.5 million), and flow-through items and permanent differences ($6.9 million), partially offset by the true up of the return to provision impacts and a lower tax benefit from a reduction in tax reserves ($0.5 million), and the excess tax benefit due to the adoption of new accounting guidance related to share-based payment transactions ($0.9 million).
EARNINGS SUMMARY
CL&P’s earnings increased $6.4 million for the three months ended September 30, 2016, as compared to the same period in 2015, due primarily to an increase in transmission earnings driven by a higher transmission rate base, and higher distribution revenues as a result of higher rate base and the absence of an authorized ROE reduction, as stipulated in the PURA 2014 rate case decision. These favorable earnings impacts were partially offset by a higher effective tax rate, higher property and other taxes expense, and higher depreciation expense.
CL&P’s earnings increased $28.4 million for the nine months ended September 30, 2016, as compared to the same period in 2015, due primarily to an increase in transmission earnings driven by a higher transmission rate base as well as the absence in 2016 of the 2015 FERC ROE complaint proceedings reserve charge, higher distribution revenues as a result of higher rate base and the absence of an authorized ROE reduction, as stipulated in the PURA 2014 rate case decision, and lower operations and maintenance expense. These favorable earnings impacts were partially offset by higher property and other taxes expense, a higher effective tax rate and higher depreciation expense.
LIQUIDITY
Cash totaled $8.6 million as of September 30, 2016, compared with $1.1 million as of December 31, 2015.
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, 2016 and December 31, 2015 was
0.66 percent
and
0.72 percent
, respectively. As of September 30, 2016 and December 31, 2015, there were intercompany loans from Eversource parent to CL&P of
$108.5 million
and
$277.4 million
, respectively.
Eversource parent, and certain of its subsidiaries, including CL&P, are parties to a
five
-year
$1.45 billion
revolving credit facility. Effective September 26, 2016, the revolving credit facility’s termination date was extended for one additional year to September 4, 2021. There were no borrowings outstanding on the revolving credit facility as of September 30, 2016 or December 31, 2015.
CL&P had cash flows provided by operating activities of $614.4 million for the nine months ended September 30, 2016, as compared to $421.8 million in the same period of 2015. The increase in operating cash flows was due primarily to a $124.7 million favorable impact due to the change in income tax payments made or refunds received during 2016, as compared to 2015, as well as the favorable impact of the timing of regulatory recoveries, primarily related to purchased power costs. Also contributing to the increase in cash flows was an increase in distribution rates due to higher rate base. Partially offsetting these favorable impacts was the timing of collections and payments related to our working capital items, including accounts receivable and accounts payable.
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 totaled $438.5 million for the nine months ended September 30, 2016.
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, 2016
and
2015
included in this combined Quarterly Report on Form 10-Q:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
For the Nine Months Ended September 30,
|
(Millions of Dollars)
|
2016
|
|
2015
|
|
Increase/(Decrease)
|
|
Percent
|
Operating Revenues
|
$
|
1,986.0
|
|
|
$
|
2,134.7
|
|
|
$
|
(148.7
|
)
|
|
(7.0
|
)%
|
Operating Expenses:
|
|
|
|
|
|
|
|
|
|
Purchased Power and Transmission
|
764.9
|
|
|
984.0
|
|
|
(219.1
|
)
|
|
(22.3
|
)
|
Operations and Maintenance
|
279.9
|
|
|
228.8
|
|
|
51.1
|
|
|
22.3
|
|
Depreciation
|
159.2
|
|
|
146.8
|
|
|
12.4
|
|
|
8.4
|
|
Amortization of Regulatory Assets/(Liabilities), Net
|
18.3
|
|
|
(10.6
|
)
|
|
28.9
|
|
|
(a)
|
|
Energy Efficiency Programs
|
212.9
|
|
|
164.8
|
|
|
48.1
|
|
|
29.2
|
|
Taxes Other Than Income Taxes
|
101.8
|
|
|
95.8
|
|
|
6.0
|
|
|
6.3
|
|
Total Operating Expenses
|
1,537.0
|
|
|
1,609.6
|
|
|
(72.6
|
)
|
|
(4.5
|
)
|
Operating Income
|
449.0
|
|
|
525.1
|
|
|
(76.1
|
)
|
|
(14.5
|
)
|
Interest Expense
|
62.2
|
|
|
57.2
|
|
|
5.0
|
|
|
8.7
|
|
Other Income, Net
|
7.6
|
|
|
3.6
|
|
|
4.0
|
|
|
(a)
|
|
Income Before Income Tax Expense
|
394.4
|
|
|
471.5
|
|
|
(77.1
|
)
|
|
(16.4
|
)
|
Income Tax Expense
|
154.5
|
|
|
187.4
|
|
|
(32.9
|
)
|
|
(17.6
|
)
|
Net Income
|
$
|
239.9
|
|
|
$
|
284.1
|
|
|
$
|
(44.2
|
)
|
|
(15.6
|
)%
|
(a) Percent greater than 100 not shown as it is not meaningful.
Operating Revenues
NSTAR Electric’s retail sales volumes were as follows:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
For the Nine Months Ended September 30,
|
|
2016
|
|
2015
|
|
Decrease
|
|
Percent
|
Retail Sales Volumes in GWh
|
15,746
|
|
|
16,260
|
|
|
(514
|
)
|
|
(3.2
|
)%
|
NSTAR Electric’s Operating Revenues, which consist of base distribution revenues and tracked revenues further described below, decreased by $148.7 million for the nine months ended September 30, 2016, as compared to the same period in 2015.
Base distribution revenues
: Base distribution revenues, excluding LBR, decreased $15.9 million in the first nine months of 2016, driven by a 3.2 percent decrease in sales volumes due primarily to increased customer energy conservation efforts, including those resulting from company-sponsored energy efficiency programs, and the impact of the warmer than normal weather in the first quarter of 2016, as compared to much colder than normal temperatures in the first quarter of 2015. NSTAR Electric is allowed to recover LBR related to reductions in sales volumes as a result of successful energy efficiency programs.
Also contributing to the decrease in operating revenues in the first nine months of 2016 was the absence of an $11 million benefit recorded in the first quarter of 2015 related to the Comprehensive Settlement Agreement associated with the recovery of LBR related to 2009 through 2011 energy efficiency programs.
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 costs, retail transmission charges, energy efficiency program costs, net metering for distributed generation and transition cost recovery revenues. In addition, tracked revenues include certain incentives earned and carrying charges. Tracked distribution revenues decreased primarily as a result of a decrease in energy supply costs ($295.8 million) driven by decreased average retail rates and lower sales volumes. Partially offsetting this decrease was an increase in retail transmission charges ($55.1 million), an increase in cost recovery related to energy efficiency programs ($47.8 million) and an increase in net metering revenues ($23 million).
Transmission revenues increased by $25.2 million due primarily to the recovery of higher revenue requirements associated with ongoing investments in our transmission infrastructure and the absence in 2016 of a $2.4 million reserve charge recorded in the first quarter of 2015 associated with the March 2015 FERC ROE order.
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 DPU-approved cost tracking mechanisms, which have no impact on earnings (tracked costs). Purchased Power and Transmission expense decreased for the nine months ended September 30, 2016, as compared to the same period in 2015, due primarily to the following:
|
|
|
|
|
(Millions of Dollars)
|
Increase/(Decrease)
|
Purchased Power Costs
|
$
|
(297.3
|
)
|
Transmission Costs
|
78.2
|
|
Total Purchased Power and Transmission
|
$
|
(219.1
|
)
|
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 increase in transmission costs was primarily the result of an increase 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 increased for the nine months ended September 30, 2016, as compared to the same period in 2015, driven by a $33.6 million increase in non-tracked costs, which was primarily attributable to the absence in 2016 of the resolution of the basic service bad debt adder mechanism recorded in the first quarter of 2015 ($24.2 million), higher vegetation management expense and higher storm restoration costs. Additionally, there was a $17.5 million increase in tracked costs, which have no earnings impact, that was primarily attributable to higher employee-related expenses due to increased current year collections of a prior year pension and PBOP costs underrecovery and higher bad debt expense.
Depreciation
expense increased for the nine months ended September 30, 2016, as compared to the same period in 2015, due primarily to higher utility plant in service balances.
Amortization of Regulatory Assets/(Liabilities), Net
reflects the absence in 2016 of an $11.7 million benefit recognized in the first quarter of 2015 relating to the Comprehensive Settlement Agreement, and the deferral adjustment of certain costs that exceeded billed revenues for the nine months ended September 30, 2016, as compared to the same period in 2015. The deferral adjusts expense to match the corresponding revenues. These deferred costs, which can fluctuate from period to period based on the timing of costs incurred and related rate changes to recover these costs, are recovered from customers in rates and have no impact on earnings.
Energy Efficiency Programs
expense (the costs of which are tracked) increased for the nine months ended September 30, 2016, as compared to the same period in 2015, due primarily to the deferral adjustment, which reflects the actual costs billed to energy efficiency programs compared to the amount billed to customers and the timing of the recovery of energy efficiency costs incurred in accordance with the three-year program guidelines established by the DPU. The deferral adjusts expense to match the energy efficiency programs revenue.
Taxes Other Than Income Taxes
expense increased for the nine months ended September 30, 2016, as compared to the same period in 2015, due primarily to an increase in property taxes as a result of higher utility plant balances.
Other Income, Net
increased for the nine months ended September 30, 2016, as compared to the same period in 2015, due primarily to higher AFUDC on equity funds ($4.1 million).
Interest Expense
increased for the nine months ended September 30, 2016, as compared to the same period in 2015, due primarily to higher interest on long-term debt ($8.2 million) as a result of new debt issuances, partially offset by an increase in AFUDC borrowed funds ($2 million).
Income Tax Expense
decreased for the nine months ended September 30, 2016, as compared to the same period in 2015, due primarily to lower pre-tax earnings ($27.4 million), lower state income taxes ($4.6 million), items that impact our tax rate as a result of regulatory treatment (flow-through items) ($1.5 million), and the excess tax benefit due to the adoption of new accounting guidance related to share-based payment transactions ($1 million), partially offset by other items ($1.6 million).
EARNINGS SUMMARY
NSTAR Electric’s earnings decreased $44.2 million for the nine months ended September 30, 2016, as compared to the same period in 2015, due primarily to the absence in 2016 of both the 2015 resolution of the basic service bad debt adder mechanism ($14.5 million) and the 2015 favorable impact associated with the Comprehensive Settlement Agreement ($13 million), lower retail sales volumes, higher depreciation expense, and higher operations and maintenance expense. These unfavorable earnings impacts were partially offset by an increase in transmission earnings, which was driven by a higher transmission rate base as well as the absence in 2016 of the 2015 FERC ROE complaint proceedings reserve charge.
LIQUIDITY
NSTAR Electric had cash flows provided by operating activities of $564.3 million for the nine months ended September 30, 2016, as compared to $502.3 million in the same period of 2015. The increase in operating cash flows was due primarily to an increase in regulatory recoveries due to collections from customers in excess of purchased power costs costs and energy efficiency programs. In addition, the timing of accounts payable payments had a favorable impact on operating cash flows. Partially offsetting these favorable impacts was a $43.3 million reduction in income tax refunds in 2016, as compared to the same period in 2015 and an increase in Pension Plan contributions of $15.8 million in 2016, as compared to 2015 and changes related to working capital items.
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, 2016
and
2015
included in this combined Quarterly Report on Form 10-Q:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
For the Nine Months Ended September 30,
|
(Millions of Dollars)
|
2016
|
|
2015
|
|
Increase/(Decrease)
|
|
Percent
|
Operating Revenues
|
$
|
727.8
|
|
|
$
|
761.1
|
|
|
$
|
(33.3
|
)
|
|
(4.4
|
)%
|
Operating Expenses:
|
|
|
|
|
|
|
|
|
|
|
|
Purchased Power, Fuel and Transmission
|
155.7
|
|
|
200.5
|
|
|
(44.8
|
)
|
|
(22.3
|
)
|
Operations and Maintenance
|
187.2
|
|
|
200.1
|
|
|
(12.9
|
)
|
|
(6.4
|
)
|
Depreciation
|
86.5
|
|
|
78.0
|
|
|
8.5
|
|
|
10.9
|
|
Amortization of Regulatory Assets, Net
|
14.5
|
|
|
29.2
|
|
|
(14.7
|
)
|
|
(50.3
|
)
|
Energy Efficiency Programs
|
10.9
|
|
|
11.0
|
|
|
(0.1
|
)
|
|
(0.9
|
)
|
Taxes Other Than Income Taxes
|
64.5
|
|
|
61.4
|
|
|
3.1
|
|
|
5.0
|
|
Total Operating Expenses
|
519.3
|
|
|
580.2
|
|
|
(60.9
|
)
|
|
(10.5
|
)
|
Operating Income
|
208.5
|
|
|
180.9
|
|
|
27.6
|
|
|
15.3
|
|
Interest Expense
|
37.4
|
|
|
34.6
|
|
|
2.8
|
|
|
8.1
|
|
Other Income, Net
|
1.0
|
|
|
2.3
|
|
|
(1.3
|
)
|
|
(56.5
|
)
|
Income Before Income Tax Expense
|
172.1
|
|
|
148.6
|
|
|
23.5
|
|
|
15.8
|
|
Income Tax Expense
|
66.3
|
|
|
56.1
|
|
|
10.2
|
|
|
18.2
|
|
Net Income
|
$
|
105.8
|
|
|
$
|
92.5
|
|
|
$
|
13.3
|
|
|
14.4
|
%
|
Operating Revenues
PSNH’s retail sales volumes were as follows:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
For the Nine Months Ended September 30,
|
|
2016
|
|
2015
|
|
Decrease
|
|
Percent
|
Retail Sales Volumes in GWh
|
5,985
|
|
|
6,049
|
|
|
(64
|
)
|
|
(1.1
|
)%
|
PSNH’s Operating Revenues, which consist of base distribution revenues and tracked revenues further described below, decreased by $33.3 million for the nine months ended September 30, 2016, as compared to the same period in 2015.
Base distribution revenues
: Base distribution revenues increased $2.1 million due primarily to a $4.4 million increase as a result of distribution rate increases effective July 1, 2015 and July 1, 2016. Partially offsetting this increase was a 1.1 percent decrease in sales volumes due primarily to increased customer energy conservation efforts, including those resulting from company-sponsored energy efficiency programs, and the impact of the warmer than normal weather in the first quarter of 2016, as compared to much colder than normal temperatures in the first quarter of 2015.
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 costs and costs associated with the generation of electricity for customers, retail transmission charges, energy efficiency program costs and stranded cost recovery revenues. In addition, tracked revenues include certain incentives earned and carrying charges. Tracked distribution revenues decreased primarily as a result of a decrease in energy supply costs and a reduction in wholesale generation revenues for the nine months ended September 30, 2016, as compared to the same period of 2015 ($39.6 million), driven by lower sales volumes. In addition, stranded cost recovery and retail transmission charges decreased by $6.4 million and $3 million, respectively, for the nine months ended September 30, 2016, as compared to the same period in 2015.
Transmission revenues increased by $17.2 million due primarily to higher revenue requirements associated with ongoing investments in our transmission infrastructure and the absence in 2016 of a $1 million reserve charge recorded in the first quarter of 2015 associated with the March 2015 FERC ROE order.
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 NHPUC-approved cost tracking mechanisms, which have no impact on earnings (tracked costs). Purchased Power, Fuel and Transmission expense decreased for the nine months ended September 30, 2016, as compared to the same period in 2015, due primarily to the following:
|
|
|
|
|
(Millions of Dollars)
|
Increase/(Decrease)
|
Purchased Power and Generation Fuel Costs
|
$
|
(56.9
|
)
|
Transmission Costs
|
12.1
|
|
Total Purchased Power, Fuel and Transmission
|
$
|
(44.8
|
)
|
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 decrease in purchased power and generation fuel costs was due primarily to a decrease in the amount of electricity generated by PSNH facilities. The increase in transmission costs was primarily the result of an increase in costs billed by ISO-NE that support regional grid investment.
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, 2016, as compared to the same period in 2015, driven by a $9.9 million decrease in non-tracked costs that was primarily attributable to the absence in 2016 of a $5 million contribution recorded in the second quarter of 2015 to create a clean energy fund in connection with the generation divestiture agreement, and lower employee-related expenses. Additionally, there was a $3 million decrease in tracked costs that was primarily attributable to lower contractor costs due to the timing of planned outages at PSNH’s generation facilities partially offset by higher transmission expenses, which have no earnings impact.
Depreciation
expense increased for the nine months ended September 30, 2016, as compared to the same period in 2015, due primarily to higher utility plant in service balances.
Amortization of Regulatory Assets, Net
expense (the costs of which are tracked) includes the deferral of energy supply costs and the amortization of certain costs, which are recovered from customers in rates and have no impact on earnings. The decrease for the nine months ended September 30, 2016, as compared to the same period in 2015, was due primarily to a decrease in the default energy service charge. The deferral adjusts expense to match the corresponding revenues.
Taxes Other Than Income Taxes
expense increased for the nine months ended September 30, 2016, as compared to the same period in 2015, due primarily to an increase in property taxes as a result of higher utility plant balances.
Income Tax Expense
increased for the nine months ended September 30, 2016, as compared to the same period in 2015, due primarily to higher pre-tax earnings ($8.2 million), higher state taxes ($1.2 million), and items that impact our tax rate as a result of regulatory treatment (flow-through items) and permanent differences ($1.2 million), partially offset by other items ($0.3 million) and the excess tax benefit due to the adoption of new accounting guidance related to share-based payment transactions ($0.4 million).
EARNINGS SUMMARY
PSNH’s earnings increased $13.3 million for the nine months ended September 30, 2016, as compared to the same period in 2015, due primarily to an increase in transmission earnings, which was driven by a higher transmission rate base as well as the absence in 2016 of the 2015 FERC ROE complaint proceedings reserve charge, higher generation earnings, lower operations and maintenance expense, and the impact of the distribution rate increases effective July 1, 2015 and July 1, 2016. These favorable earnings impacts were partially offset by higher depreciation expense and lower retail sales volumes.
LIQUIDITY
PSNH had cash flows provided by operating activities of $306 million for the nine months ended September 30, 2016, as compared to $243.9 million in the same period of 2015. The increase in operating cash flows was due primarily to the favorable impact of the timing of payments related to our accounts payable. In addition, income tax refunds of $41.3 million were received in 2016, compared to income tax payments of $5 million the same period in 2015. Partially offsetting these favorable impacts were an increase in Pension Plan contributions of $15.8 million in 2016 and the use of fuel inventories.
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, 2016
and
2015
included in this combined Quarterly Report on Form 10-Q:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
For the Nine Months Ended September 30,
|
(Millions of Dollars)
|
2016
|
|
2015
|
|
Increase/(Decrease)
|
|
Percent
|
Operating Revenues
|
$
|
368.5
|
|
|
$
|
403.2
|
|
|
$
|
(34.7
|
)
|
|
(8.6
|
)%
|
Operating Expenses:
|
|
|
|
|
|
|
|
|
|
|
|
Purchased Power and Transmission
|
104.4
|
|
|
149.2
|
|
|
(44.8
|
)
|
|
(30.0
|
)
|
Operations and Maintenance
|
68.0
|
|
|
61.7
|
|
|
6.3
|
|
|
10.2
|
|
Depreciation
|
34.4
|
|
|
32.4
|
|
|
2.0
|
|
|
6.2
|
|
Amortization of Regulatory Assets, Net
|
3.3
|
|
|
11.2
|
|
|
(7.9
|
)
|
|
(70.5
|
)
|
Energy Efficiency Programs
|
33.6
|
|
|
32.7
|
|
|
0.9
|
|
|
2.8
|
|
Taxes Other Than Income Taxes
|
30.4
|
|
|
28.4
|
|
|
2.0
|
|
|
7.0
|
|
Total Operating Expenses
|
274.1
|
|
|
315.6
|
|
|
(41.5
|
)
|
|
(13.1
|
)
|
Operating Income
|
94.4
|
|
|
87.6
|
|
|
6.8
|
|
|
7.8
|
|
Interest Expense
|
18.3
|
|
|
19.0
|
|
|
(0.7
|
)
|
|
(3.7
|
)
|
Other Income, Net
|
0.1
|
|
|
2.4
|
|
|
(2.3
|
)
|
|
(95.8
|
)
|
Income Before Income Tax Expense
|
76.2
|
|
|
71.0
|
|
|
5.2
|
|
|
7.3
|
|
Income Tax Expense
|
30.1
|
|
|
28.6
|
|
|
1.5
|
|
|
5.2
|
|
Net Income
|
$
|
46.1
|
|
|
$
|
42.4
|
|
|
$
|
3.7
|
|
|
8.7
|
%
|
Operating Revenues
WMECO’s retail sales volumes were as follows:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
For the Nine Months Ended September 30,
|
|
2016
|
|
2015
|
|
Decrease
|
|
Percent
|
Retail Sales Volumes in GWh
|
2,695
|
|
|
2,742
|
|
|
(47
|
)
|
|
(1.7
|
)%
|
WMECO’s Operating Revenues, which consist of base distribution revenues and tracked revenues further described below, decreased by $34.7 million for the nine months ended September 30, 2016, as compared to the same period in 2015.
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 costs, retail transmission charges, energy efficiency program costs, low income assistance programs, and restructuring and stranded cost recovery revenues. In addition, tracked revenues include certain incentives earned and carrying charges. Tracked revenues decreased due primarily to a decrease in energy supply costs ($47.8 million) driven by decreased average retail rates and lower sales volumes.
Transmission revenues increased by $13.6 million due primarily to the absence in 2016 of a $4.1 million reserve charge recorded in the first quarter of 2015 associated with the March 2015 FERC ROE order and higher revenue requirements associated with ongoing investments in our transmission infrastructure.
Purchased Power and Transmission
expense includes costs associated with the purchasing of energy supply on behalf of WMECO’s customers. These energy supply costs are recovered from customers in DPU-approved cost tracking mechanisms, which have no impact on earnings (tracked costs). Purchased Power and Transmission expense decreased for the nine months ended September 30, 2016, as compared to the same period in 2015, due primarily to the following:
|
|
|
|
|
(Millions of Dollars)
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Increase/(Decrease)
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Purchased Power Costs
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$
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(51.3
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)
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Transmission Costs
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6.5
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Total Purchased Power and Transmission
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$
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(44.8
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)
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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 was due primarily to lower prices associated with the procurement of energy supply and lower sales volumes. The increase in transmission costs was primarily the result of an increase in costs billed by ISO-NE that support regional grid investment.
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, 2016, as compared to the same period in 2015, driven by a $3.7 million increase in tracked costs, which have no earnings impact, that was primarily attributable to higher transmission expenses and the deferral of RECs generated and sold by the WMECO solar program, and an increase of $2.6 million in non-tracked costs that was primarily attributable to higher employee-related expenses and higher public liability claims.
Depreciation
expense increased for the nine months ended September 30, 2016, as compared to the same period in 2015, due primarily to higher utility plant in service balances.
Amortization of Regulatory Assets, Net
expense (the costs of which are tracked) decreased for the nine months ended September 30, 2016, as compared to the same period in 2015, due to the timing of refunds or recovery of tracked costs from customers in rates. These costs have no impact on earnings.
Taxes Other Than Income Taxes
expense increased for the nine months ended September 30, 2016, as compared to the same period in 2015, due primarily to an increase in property taxes as a result of higher utility plant balances.
Other Income, Net
decreased for the nine months ended September 30, 2016, as compared to the same period in 2015, due primarily to lower AFUDC on equity funds ($1.4 million) and a decrease in net gains related to the deferred compensation plans ($0.3 million).
Income Tax Expense
increased for the nine months ended September 30, 2016, as compared to the same period in 2015, due primarily to higher pre-tax earnings ($1.9 million), partially offset by other items ($0.2 million) and the excess tax benefit due to the adoption of new accounting guidance related to share-based payment transactions ($0.2 million).
EARNINGS SUMMARY
WMECO’s earnings increased $3.7 million for the nine months ended September 30, 2016, as compared to the same period in 2015, due primarily to an increase in transmission earnings, which was driven by the absence in 2016 of the 2015 FERC ROE complaint proceedings reserve charge as well as a higher transmission rate base, and lower interest expense on long-term debt. These favorable earnings impacts were partially offset by higher operations and maintenance expense, higher property and other taxes expense, and higher depreciation expense.
LIQUIDITY
WMECO had cash flows provided by operating activities of $124.8 million for the nine months ended September 30, 2016, as compared to $68 million in the same period of 2015. The increase in operating cash flows was due primarily to the timing of collections of accounts receivable and an increase of $21 million in income tax refunds in 2016, as compared to the same period in 2015.