(1)
These amounts are included in the computation of net periodic Pension, SERP and PBOP costs. See Note 7, "Pension Benefits and Postretirement Benefits Other Than Pensions," for further information.
11.
COMMON SHARES
The following table sets forth the NU common shares and the shares of common stock of CL&P, NSTAR Electric, PSNH and WMECO that were authorized and issued and the respective per share par values:
|
|
|
|
|
|
|
|
|
|
|
Shares
|
|
|
|
|
|
Authorized as of
|
|
|
|
|
|
|
Per Share
|
|
June 30, 2014 and
|
|
Issued as of
|
|
|
Par Value
|
|
December 31, 2013
|
|
June 30, 2014
|
|
December 31, 2013
|
|
NU
|
$
|
5
|
|
380,000,000
|
|
333,327,485
|
|
333,113,492
|
|
CL&P
|
$
|
10
|
|
24,500,000
|
|
6,035,205
|
|
6,035,205
|
|
NSTAR Electric
|
$
|
1
|
|
100,000,000
|
|
100
|
|
100
|
|
PSNH
|
$
|
1
|
|
100,000,000
|
|
301
|
|
301
|
|
WMECO
|
$
|
25
|
|
1,072,471
|
|
434,653
|
|
434,653
|
As of June 30, 2014 and December 31, 2013, there were 17,108,131 and 17,796,672 NU common shares held as treasury shares, respectively. As of June 30, 2014 and December 31, 2013, NU common shares outstanding were 316,219,354 and 315,273,559, respectively.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
12.
COMMON SHAREHOLDERS' EQUITY AND NONCONTROLLING INTERESTS
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
A summary of the changes in Common Shareholders' Equity and Noncontrolling Interests of NU is as follows:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
For the Three Months Ended
|
|
|
|
|
|
|
June 30, 2014
|
|
June 30, 2013
|
|
|
|
|
|
|
|
|
|
Noncontrolling
|
|
|
|
|
Noncontrolling
|
|
|
|
|
|
|
|
|
Interest -
|
|
|
|
|
Interest -
|
|
|
|
|
|
|
Common
|
|
Preferred
|
|
Common
|
|
Preferred
|
|
|
|
|
|
|
Shareholders
'
|
|
Stock of
|
|
Shareholders
'
|
|
Stock of
|
|
|
(Millions of Dollars)
|
Equity
|
|
Subsidiaries
|
|
Equity
|
|
Subsidiaries
|
|
|
Balance as of Beginning of Period
|
$
|
9,723.9
|
|
$
|
155.6
|
|
$
|
9,345.2
|
|
$
|
155.6
|
|
|
Net Income
|
|
129.2
|
|
|
-
|
|
|
173.1
|
|
|
-
|
|
|
Dividends on Common Shares
|
|
(124.1)
|
|
|
-
|
|
|
(115.6)
|
|
|
-
|
|
|
Dividends on Preferred Stock
|
|
(1.9)
|
|
|
(1.9)
|
|
|
(2.0)
|
|
|
(2.0)
|
|
|
Issuance of Common Shares
|
|
0.2
|
|
|
-
|
|
|
0.3
|
|
|
-
|
|
|
Other Transactions, Net
|
|
23.7
|
|
|
-
|
|
|
4.2
|
|
|
-
|
|
|
Net Income Attributable to Noncontrolling Interests
|
|
-
|
|
|
1.9
|
|
|
-
|
|
|
2.0
|
|
|
Other Comprehensive Income
|
|
2.8
|
|
|
-
|
|
|
1.4
|
|
|
-
|
|
|
Balance as of End of Period
|
$
|
9,753.8
|
|
$
|
155.6
|
|
$
|
9,406.6
|
|
$
|
155.6
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
36
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
For the Six Months Ended
|
|
|
|
|
|
|
June 30, 2014
|
|
June 30, 2013
|
|
|
|
|
|
|
|
|
|
Noncontrolling
|
|
|
|
|
Noncontrolling
|
|
|
|
|
|
|
|
|
Interest -
|
|
|
|
|
Interest -
|
|
|
|
|
|
|
Common
|
|
Preferred
|
|
Common
|
|
Preferred
|
|
|
|
|
|
|
Shareholders
'
|
|
Stock of
|
|
Shareholders
'
|
|
Stock of
|
|
|
(Millions of Dollars)
|
Equity
|
|
Subsidiaries
|
|
Equity
|
|
Subsidiaries
|
|
|
Balance as of Beginning of Period
|
$
|
9,611.5
|
|
$
|
155.6
|
|
$
|
9,237.1
|
|
$
|
155.6
|
|
|
Net Income
|
|
367.1
|
|
|
-
|
|
|
403.0
|
|
|
-
|
|
|
Dividends on Common Shares
|
|
(247.9)
|
|
|
-
|
|
|
(232.1)
|
|
|
-
|
|
|
Dividends on Preferred Stock
|
|
(3.8)
|
|
|
(3.8)
|
|
|
(3.9)
|
|
|
(3.9)
|
|
|
Issuance of Common Shares
|
|
5.4
|
|
|
-
|
|
|
8.8
|
|
|
-
|
|
|
Other Transactions, Net
|
|
17.0
|
|
|
-
|
|
|
(9.7)
|
|
|
-
|
|
|
Net Income Attributable to Noncontrolling Interests
|
|
-
|
|
|
3.8
|
|
|
-
|
|
|
3.9
|
|
|
Other Comprehensive Income
|
|
4.5
|
|
|
-
|
|
|
3.4
|
|
|
-
|
|
|
Balance as of End of Period
|
$
|
9,753.8
|
|
$
|
155.6
|
|
$
|
9,406.6
|
|
$
|
155.6
|
|
13.
EARNINGS PER SHARE
Basic EPS is computed based upon the weighted average number of common shares outstanding during each period. Diluted EPS is computed on the basis of the weighted average number of common shares outstanding plus the potential dilutive effect of certain share-based compensation awards as if they were converted into common shares. There were no antidilutive share awards outstanding for the three and six months ended June 30, 2014 or for the three months ended June 30, 2013. For the six months ended June 30, 2013, there were 3,150 antidilutive share awards excluded from the computation.
The following table sets forth the components of basic and diluted EPS:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
For the Three Months Ended
|
|
For the Six Months Ended
|
|
(Millions of Dollars, except share information)
|
June 30, 2014
|
|
June 30, 2013
|
|
June 30, 2014
|
|
June 30, 2013
|
|
Net Income Attributable to Controlling Interest
|
$
|
127.4
|
|
$
|
171.0
|
|
$
|
363.3
|
|
$
|
399.1
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Weighted Average Common Shares Outstanding:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Basic
|
|
315,950,510
|
|
|
315,154,130
|
|
|
315,742,511
|
|
|
315,141,956
|
|
|
Dilutive Effect
|
|
1,162,291
|
|
|
808,489
|
|
|
1,259,950
|
|
|
840,622
|
|
|
Diluted
|
|
317,112,801
|
|
|
315,962,619
|
|
|
317,002,461
|
|
|
315,982,578
|
|
Basic EPS
|
$
|
0.40
|
|
$
|
0.54
|
|
$
|
1.15
|
|
$
|
1.27
|
|
Diluted EPS
|
$
|
0.40
|
|
$
|
0.54
|
|
$
|
1.15
|
|
$
|
1.26
|
RSUs and performance shares are included in basic weighted average common shares outstanding as of the date that all necessary vesting conditions have been satisfied. The dilutive effect of unvested RSUs and performance shares is calculated using the treasury stock method. Assumed proceeds of these units under the treasury stock method consist of the remaining compensation cost to be recognized and a theoretical tax benefit. The theoretical tax benefit is calculated as the tax impact of the intrinsic value of the units (the difference between the market value of the average units outstanding for the period, using the average market price during the period, and the grant date market value).
The dilutive effect of stock options to purchase common shares is also calculated using the treasury stock method. Assumed proceeds for stock options consist of cash proceeds that would be received upon exercise, and a theoretical tax benefit. The theoretical tax benefit is calculated as the tax impact of the intrinsic value of the stock options (the difference between the market value of the average stock options outstanding for the period, using the average market price during the period, and the exercise price).
14.
SEGMENT INFORMATION
Presentation:
NU is organized between the Electric Distribution, Electric Transmission and Natural Gas Distribution reportable segments and Other based on a combination of factors, including the characteristics of each segments' products and services, the sources of operating revenues and expenses and the regulatory environment in which each segment operates. These reportable segments represented substantially all of NU's total consolidated revenues for the three and six months ended June 30, 2014 and 2013. Revenues from the sale of electricity and natural gas primarily are derived from residential, commercial and industrial customers and are not dependent on any single customer. The Electric Distribution reportable segment includes the generation activities of PSNH and WMECO.
The remainder of NU's operations is presented as Other in the tables below and primarily consists of 1) the equity in earnings of NU parent from its subsidiaries and intercompany interest income, both of which are eliminated in consolidation, and interest expense related to the debt of NU parent, 2) the revenues and expenses of NU's service company, most of which are eliminated in consolidation, 3) the operations of CYAPC and YAEC, and 4) the results of other non-regulated subsidiaries, which are not part of its core business.
Cash flows used for investments in plant included in the segment information below are cash capital expenditures that do not include amounts incurred but not paid, cost of removal, AFUDC related to equity funds, and the capitalized portions of pension expense.
NU's reportable segments are determined based upon the level at which NU's chief operating decision maker assesses performance and makes decisions about the allocation of company resources. Each of NU's subsidiaries, including CL&P, NSTAR Electric, PSNH and WMECO, has one reportable segment. NU's operating segments and reporting units are consistent with its reportable business segments.
37
NU's segment information is as follows:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
For the Three Months Ended June 30, 2014
|
|
|
|
Electric
|
|
Natural Gas
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(Millions of Dollars)
|
Distribution
|
|
Distribution
|
|
Transmission
|
|
Other
|
|
Eliminations
|
|
Total
|
|
Operating Revenues
|
$
|
1,261.8
|
|
$
|
195.5
|
|
$
|
206.9
|
|
$
|
184.7
|
|
$
|
(171.3)
|
|
$
|
1,677.6
|
|
Depreciation and Amortization
|
|
(89.3)
|
|
|
(16.9)
|
|
|
(37.0)
|
|
|
(7.7)
|
|
|
2.3
|
|
|
(148.6)
|
|
Other Operating Expenses
|
|
(991.5)
|
|
|
(166.5)
|
|
|
(71.0)
|
|
|
(174.9)
|
|
|
168.9
|
|
|
(1,235.0)
|
|
Operating Income
|
|
181.0
|
|
|
12.1
|
|
|
98.9
|
|
|
2.1
|
|
|
(0.1)
|
|
|
294.0
|
|
Interest Expense
|
|
(47.2)
|
|
|
(8.7)
|
|
|
(28.8)
|
|
|
(9.1)
|
|
|
1.3
|
|
|
(92.5)
|
|
Other Income, Net
|
|
2.9
|
|
|
-
|
|
|
2.7
|
|
|
137.7
|
|
|
(137.8)
|
|
|
5.5
|
|
Net Income Attributable to Controlling Interest
|
$
|
83.4
|
|
$
|
2.0
|
|
$
|
43.9
|
|
$
|
133.3
|
|
$
|
(135.2)
|
|
$
|
127.4
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
For the Six Months Ended June 30, 2014
|
|
|
|
Electric
|
|
Natural Gas
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(Millions of Dollars)
|
Distribution
|
|
Distribution
|
|
Transmission
|
|
Other
|
|
Eliminations
|
|
Total
|
|
Operating Revenues
|
$
|
2,847.8
|
|
$
|
628.3
|
|
$
|
458.9
|
|
$
|
356.9
|
|
$
|
(323.7)
|
|
$
|
3,968.2
|
|
Depreciation and Amortization
|
|
(238.2)
|
|
|
(34.6)
|
|
|
(74.0)
|
|
|
(14.7)
|
|
|
4.1
|
|
|
(357.4)
|
|
Other Operating Expenses
|
|
(2,202.4)
|
|
|
(487.9)
|
|
|
(137.3)
|
|
|
(340.3)
|
|
|
318.8
|
|
|
(2,849.1)
|
|
Operating Income
|
|
407.2
|
|
|
105.8
|
|
|
247.6
|
|
|
1.9
|
|
|
(0.8)
|
|
|
761.7
|
|
Interest Expense
|
|
(94.6)
|
|
|
(17.1)
|
|
|
(54.3)
|
|
|
(18.7)
|
|
|
2.2
|
|
|
(182.5)
|
|
Other Income, Net
|
|
4.3
|
|
|
0.1
|
|
|
4.2
|
|
|
432.4
|
|
|
(433.8)
|
|
|
7.2
|
|
Net Income Attributable to Controlling Interest
|
$
|
195.6
|
|
$
|
54.1
|
|
$
|
118.8
|
|
$
|
424.9
|
|
$
|
(430.1)
|
|
$
|
363.3
|
|
Cash Flows Used for Investments in Plant
|
$
|
335.6
|
|
$
|
68.6
|
|
$
|
289.3
|
|
$
|
30.5
|
|
$
|
-
|
|
$
|
724.0
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
For the Three Months Ended June 30, 2013
|
|
|
|
Electric
|
|
Natural Gas
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(Millions of Dollars)
|
Distribution
|
|
Distribution
|
|
Transmission
|
|
Other
|
|
Eliminations
|
|
Total
|
|
Operating Revenues
|
$
|
1,221.6
|
|
$
|
154.1
|
|
$
|
247.9
|
|
$
|
220.7
|
|
$
|
(208.4)
|
|
$
|
1,635.9
|
|
Depreciation and Amortization
|
|
(152.2)
|
|
|
(16.7)
|
|
|
(34.5)
|
|
|
(21.7)
|
|
|
2.9
|
|
|
(222.2)
|
|
Other Operating Expenses
|
|
(883.3)
|
|
|
(127.0)
|
|
|
(63.6)
|
|
|
(194.9)
|
|
|
205.7
|
|
|
(1,063.1)
|
|
Operating Income
|
|
186.1
|
|
|
10.4
|
|
|
149.8
|
|
|
4.1
|
|
|
0.2
|
|
|
350.6
|
|
Interest Expense
|
|
(43.4)
|
|
|
(8.9)
|
|
|
(25.2)
|
|
|
(10.7)
|
|
|
1.3
|
|
|
(86.9)
|
|
Other Income, Net
|
|
2.2
|
|
|
0.1
|
|
|
2.8
|
|
|
232.2
|
|
|
(232.3)
|
|
|
5.0
|
|
Net Income Attributable to Controlling Interest
|
$
|
91.2
|
|
$
|
1.2
|
|
$
|
76.8
|
|
$
|
232.8
|
|
$
|
(231.0)
|
|
$
|
171.0
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
For the Six Months Ended June 30, 2013
|
|
|
|
Electric
|
|
Natural Gas
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(Millions of Dollars)
|
Distribution
|
|
Distribution
|
|
Transmission
|
|
Other
|
|
Eliminations
|
|
Total
|
|
Operating Revenues
|
$
|
2,595.8
|
|
$
|
515.9
|
|
$
|
487.4
|
|
$
|
437.8
|
|
$
|
(406.0)
|
|
$
|
3,630.9
|
|
Depreciation and Amortization
|
|
(329.1)
|
|
|
(34.1)
|
|
|
(66.3)
|
|
|
(40.8)
|
|
|
4.6
|
|
|
(465.7)
|
|
Other Operating Expenses
|
|
(1,888.3)
|
|
|
(394.3)
|
|
|
(125.8)
|
|
|
(392.2)
|
|
|
404.9
|
|
|
(2,395.7)
|
|
Operating Income
|
|
378.4
|
|
|
87.5
|
|
|
295.3
|
|
|
4.8
|
|
|
3.5
|
|
|
769.5
|
|
Interest Expense
|
|
(85.6)
|
|
|
(16.2)
|
|
|
(47.1)
|
|
|
(17.1)
|
|
|
2.9
|
|
|
(163.1)
|
|
Other Income, Net
|
|
7.1
|
|
|
0.3
|
|
|
5.5
|
|
|
554.0
|
|
|
(554.2)
|
|
|
12.7
|
|
Net Income Attributable to Controlling Interest
|
$
|
190.6
|
|
$
|
44.5
|
|
$
|
156.7
|
|
$
|
555.5
|
|
$
|
(548.2)
|
|
$
|
399.1
|
|
Cash Flows Used for Investments in Plant
|
$
|
315.3
|
|
$
|
70.9
|
|
$
|
297.4
|
|
$
|
16.7
|
|
$
|
-
|
|
$
|
700.3
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
The following table summarizes NU's segmented total assets:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Electric
|
|
Natural Gas
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(Millions of Dollars)
|
Distribution
|
|
Distribution
|
|
Transmission
|
|
Other
|
|
Eliminations
|
|
Total
|
|
As of June 30, 2014
|
$
|
16,942.5
|
|
$
|
2,753.8
|
|
$
|
6,934.1
|
|
$
|
11,566.6
|
|
$
|
(10,406.6)
|
|
$
|
27,790.4
|
|
As of December 31, 2013
|
|
17,260.0
|
|
|
2,759.7
|
|
|
6,745.8
|
|
|
11,842.4
|
|
|
(10,812.4)
|
|
|
27,795.5
|
38
NORTHEAST UTILITIES AND SUBSIDIARIES
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 First Quarter 2014 Form 10-Q, and the 2013 Annual Report on Form 10-K. References in this Form 10-Q to "NU," the "Company," "we," "us," and "our" refer to Northeast Utilities and its consolidated subsidiaries. All per share amounts are reported on a diluted basis. The unaudited condensed consolidated financial statements of NU, 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 NU. The earnings and EPS of each business discussed below do not represent a direct legal interest in the assets and liabilities allocated to 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 that is calculated by dividing the Net Income Attributable to Controlling Interest of each business by the weighted average diluted NU common shares outstanding for the year. The discussion below also includes non-GAAP financial measures referencing our second quarter and first half of 2014 and 2013 earnings and EPS excluding certain integration costs related to NU's merger with NSTAR. 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 second quarter and first half of 2014 and 2013 results without including the impact of these non-recurring items. Due to the nature and significance of these items on Net Income Attributable to Controlling Interest, we believe that the non-GAAP presentation is more representative of our financial performance and 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 Controlling Interest 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 Controlling Interest are included under "Financial Condition and Business Analysis – Overview – Consolidated" in
Management's Discussion and Analysis
, herein.
Forward-Looking Statements:
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:
·
cyber breaches, acts of war or terrorism, or grid disturbances,
·
actions or inaction of local, state and federal regulatory and taxing bodies,
·
changes in business and economic conditions, including their impact on interest rates, bad debt expense, and demand for our products and services,
·
fluctuations in weather patterns,
·
changes in laws, regulations or regulatory policy,
·
changes in levels or timing of capital expenditures,
·
disruptions in the capital markets or other events that make our access to necessary capital more difficult or costly,
·
developments in legal or public policy doctrines,
·
technological developments,
·
changes in accounting standards and financial reporting regulations,
·
actions of rating agencies, and
·
other presently unknown or unforeseen factors.
Other risk factors are detailed in our reports filed with the SEC and updated as necessary, and we encourage you to consult such disclosures.
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 Quarterly Report on Form 10-Q and in NU's 2013 Annual Report on Form 10-K. This Quarterly Report on Form 10-Q and NU's 2013 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 Condensed Consolidated Financial Statements (Unaudited)
. We encourage you to review these items.
39
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:
·
We earned $127.4 million, or $0.40 per share, in the second quarter of 2014, and $363.3 million, or $1.15 per share, in the first half of 2014, compared with $171 million, or $0.54 per share, in the second quarter of 2013 and $399.1 million, or $1.26 per share, in the first half of 2013. Excluding integration costs, we earned $131.9 million, or $0.42 per share, in the second quarter of 2014, and $373.7 million, or $1.18 per share, in the first half of 2014, compared with $172.8 million, or $0.55 per share, in the second quarter of 2013, and $402.6 million, or $1.27 per share, in the first half of 2013.
·
Our electric distribution segment, which includes generation, earned $83.4 million, or $0.26 per share, in the second quarter of 2014 and $195.6 million, or $0.62 per share, in the first half of 2014, compared with earnings of $91.2 million, or $0.29 per share, in the second quarter of 2013 and $190.6 million, or $0.60 per share, in the first half of 2013.
·
Our transmission segment earned $43.9 million, or $0.14 per share, in the second quarter of 2014 and $118.8 million, or $0.37 per share, in the first half of 2014, compared with $76.8 million, or $0.25 per share, in the second quarter of 2013 and $156.7 million, or $0.50 per share, in the first half of 2013. The decrease in the second quarter and first half of 2014 earnings, as compared to the same periods in 2013, was due primarily to the establishment of a $32.1 million after-tax reserve related to FERC ROE orders issued on June 19, 2014.
·
Our natural gas distribution segment earned $2 million, or $0.01 per share, in the second quarter of 2014 and $54.1 million, or $0.17 per share, in the first half of 2014, compared with $1.2 million in the second quarter of 2013 and $44.5 million, or $0.14 per share, in the first half of 2013.
·
NU parent and other companies had net losses of $1.9 million, or $0.01 per share, in the second quarter of 2014 and $5.2 million, or $0.01 per share, in the first half of 2014, compared with earnings of $1.8 million in the second quarter of 2013 and $7.3 million, or $0.02 per share, in the first half of 2013. Second quarter and first half 2014 results reflect $4.5 million and $10.4 million, respectively, of after-tax integration costs. Second quarter and first half 2013 results reflect $1.8 million and $3.5 million, respectively, of after-tax integration costs.
Legislative and Regulatory Items:
·
On June 9, 2014, CL&P filed an application with the PURA to amend customer rates, effective December 1, 2014. CL&P requested an increase in base distribution rates of $116.7 million. Based on the current schedule, we expect a final decision in December 2014.
·
On June 19, 2014, the FERC issued two orders in the pending base ROE complaint proceedings. The first order addressed the joint complaint filed at FERC in September 2011 by several New England parties alleging that the base ROE of 11.14 percent was unjust and unreasonable. The FERC set a single tentative base ROE of 10.57 percent for the refund period (October 1, 2011 through December 31, 2012) and the prospective period (beginning when FERC finalizes the base ROE). The second order addressed a second joint complaint filed at FERC in December 2012 by additional New England parties alleging that the base ROE was unjust and unreasonable. The complaint sought refunds for the 15-month period beginning January 1, 2013. The FERC found that the second complaint raised issues of material fact and set this complaint for settlement or trial if settlement negotiations should be unsuccessful. We recorded a series of reserves totaling $32.1 million after-tax at our electric subsidiaries to recognize the potential financial impact from the FERC's two orders for the two refund periods.
·
On July 7, 2014, Massachusetts enacted "An Act Relative to Natural Gas Leaks" (the Act). The Act establishes a uniform natural gas leak classification standard for all Massachusetts natural gas utilities and a program that accelerates the replacement of aging natural gas infrastructure. The Act also calls for the DPU to authorize natural gas utilities to design and offer programs to customers that will increase the availability, affordability and feasibility of natural gas service for new customers.
Liquidity:
·
Cash and cash equivalents totaled $34.1 million as of June 30, 2014, compared with $43.4 million as of December 31, 2013, while investments in property, plant and equipment totaled $724 million in the first half of 2014, compared with $700.3 million in the first half of 2013.
·
Cash flows provided by operating activities totaled $896.7 million in the first half of 2014, compared with $769 million in the first half of 2013. The improved operating cash flows were due primarily to approximately $126 million in DOE Phase II proceeds received by CL&P, NSTAR Electric, PSNH and WMECO on June 1, 2014 from the Yankee Companies associated with the spent nuclear fuel litigation, the absence of cash disbursements for major storm restoration costs and the decrease of $82.2 million in Pension and PBOP Plan cash contributions, partially offset by an increase in income taxes paid in the first half of 2014 ($158 million), as compared to the first half of 2013 ($16 million).
·
In the first half of 2014, we issued $650 million of new long-term debt consisting of $100 million by Yankee Gas on January 2, 2014, $300 million by NSTAR Electric on March 7, 2014, and $250 million by CL&P on April 24, 2014. These new issuances were used to repay approximately $375 million of existing long-term debt with the remainder used to pay short-term borrowings.
40
·
In the first half of 2014, we had cash dividends on common shares of $237.2 million, compared with $232 million in the first half of 2013. On May 1, 2014, our Board of Trustees approved a common dividend payment of $0.3925 per share, which was paid on June 30, 2014 to shareholders of record as of May 30, 2014.
Overview
Consolidated:
A summary of our earnings by business, which also reconciles the non-GAAP financial measures of consolidated non-GAAP earnings and EPS, as well as EPS by business, to the most directly comparable GAAP measures of consolidated Net Income Attributable to Controlling Interest and diluted EPS, for the second quarter and first half of 2014 and 2013 is as follows:
(1)
Commercial retail electric GWh sales include streetlighting and railroad retail sales.
A summary of our firm natural gas sales in million cubic feet and percentage changes, as well as percentage changes in Yankee Gas and NSTAR Gas, is as follows:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
For the Three Months Ended
June 30, 2014 Compared to 2013
|
|
For the Six Months Ended
June 30, 2014 Compared to 2013
|
|
|
Sales (million cubic feet)
|
|
Percentage
|
|
Sales (million cubic feet)
|
|
Percentage
|
|
NU – Firm Natural Gas
|
2014
|
|
2013
|
|
Increase
|
|
2014
|
|
2013
|
|
Increase
|
|
Residential
|
5,169
|
|
4,970
|
|
4.0%
|
|
24,981
|
|
21,985
|
|
13.6%
|
|
Commercial
|
6,839
|
|
6,622
|
|
3.3%
|
|
26,467
|
|
23,393
|
|
13.1%
|
|
Industrial
|
4,916
|
|
4,665
|
|
5.4%
|
|
12,393
|
|
11,494
|
|
7.8%
|
|
Total
|
16,924
|
|
16,257
|
|
4.1%
|
|
63,841
|
|
56,872
|
|
12.3%
|
|
Total, Net of Special Contracts
(1)
|
15,895
|
|
15,238
|
|
4.3%
|
|
61,445
|
|
54,660
|
|
12.4%
|
|
|
|
|
|
|
|
|
|
|
For the Three Months Ended
June 30, 2014 Compared to 2013
|
|
For the Six Months Ended
June 30, 2014 Compared to 2013
|
|
|
Sales (million cubic feet)
|
|
Sales (million cubic feet)
|
|
|
Yankee Gas
|
|
NSTAR Gas
|
|
Yankee Gas
|
|
NSTAR Gas
|
|
|
Percentage
|
|
Percentage
|
|
Percentage
|
|
Percentage
|
|
Firm Natural Gas
|
Increase/(Decrease)
|
|
Increase
|
|
Increase/(Decrease)
|
|
Increase
|
|
Residential
|
(3.4)%
|
|
9.6 %
|
|
15.8%
|
|
12.2%
|
|
Commercial
|
5.4 %
|
|
1.4 %
|
|
16.6%
|
|
10.2%
|
|
Industrial
|
5.7 %
|
|
4.5%
|
|
8.4%
|
|
6.4%
|
|
Total
|
3.3 %
|
|
5.0%
|
|
13.9%
|
|
10.6%
|
|
Total, Net of Special Contracts
(1)
|
3.7 %
|
|
|
|
14.4%
|
|
|
(1)
Special contracts are unique to the 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.
Weather, fluctuations in energy supply costs, conservation measures (including company-sponsored energy efficiency programs), and economic conditions affect customer energy usage. Industrial sales are less sensitive to temperature variations than residential and commercial sales. In our service territories, weather impacts electric sales during the summer and electric and natural gas sales during the winter (natural gas sales are more sensitive to temperature variations than electric sales). Customer heating or cooling usage may not directly correlate with historical levels or with the level of degree-days that occur. In addition, our electric and natural gas businesses are susceptible to damage from major storms and other natural events and disasters that could adversely affect our ability to provide energy.
For the second quarter of 2014, our consolidated retail electric sales, consisting of the retail electric sales of CL&P, NSTAR Electric, PSNH, and WMECO, were lower, as compared to the same period in 2013, due primarily to milder temperatures in late May and June, compared with the same periods in 2013. The second quarter of 2014 cooling degree days were 19 percent lower in Connecticut and western Massachusetts, 22 percent
lower in the Boston metropolitan area, and 24 percent lower in New Hampshire, as compared to the second quarter of 2013. Weather-normalized retail
42
electric sales (based on 30-year average temperatures) decreased 1.7 percent in the second quarter of 2014, as compared to the second quarter of 2013. We believe the decrease was due primarily to increased conservation efforts by our residential and commercial customer classes, which is driven by the energy efficiency programs sponsored by CL&P, NSTAR Electric and WMECO.
For the first half of 2014, our consolidated retail electric sales were higher, as compared to the same period in 2013, due primarily to colder weather in the first quarter of 2014. The first half 2014 heating degree days were 12 percent higher in Connecticut, New Hampshire and western Massachusetts and 9 percent
higher in the Boston metropolitan area, as compared to the first half of 2013. Weather-normalized retail electric sales (based on 30-year average temperatures) decreased 0.1 percent in the first half of 2014, as compared to the first half of 2013. We believe the decrease was due primarily to an increase in customer conservation efforts as noted above.
For WMECO, fluctuations in retail electric sales do not impact earnings due to the DPU-approved revenue decoupling mechanism. Under this decoupling mechanism, WMECO has an overall fixed annual level of distribution delivery service revenues of $132.4 million, comprised of customer base rate revenues of $125.4 million and a baseline low income discount recovery of $7 million. These two mechanisms effectively break the relationship between sales volume and revenues recognized.
Our firm natural gas sales are subject to many of the same influences as our retail electric sales. In addition, they have benefitted from historically favorable natural gas prices and customer growth across both operating companies. In the second quarter and first half of 2014, consolidated firm natural gas sales, consisting of the firm natural gas sales of Yankee Gas and NSTAR Gas, were higher, as compared to the second quarter and first half of 2013, due primarily to colder weather in the first quarter of 2014, as compared to the same period in 2013, and customer growth in the first half of 2014, as compared to the same period in 2013. The second quarter and first half of 2014 weather-normalized NU consolidated total firm natural gas sales increased 5.3 percent and 4.1 percent, respectively, as compared to the same periods in 2013.
NU Parent and Other Companies:
NU parent and other companies, which includes our competitive businesses, had net losses of $1.9 million and $5.2 million in the second quarter and first half of 2014, respectively, compared with earnings of $1.8 million and $7.3 million in the second quarter and first half of 2013, respectively. Excluding the impact of integration costs, NU parent and other companies earned $2.6 million and $5.2 million in the second quarter and first half of 2014, respectively, compared with $3.6 million and $10.8 million in the second quarter and first half of 2013, respectively. The decrease in first half of 2014 earnings was due to the absence of the favorable impact from the resolution of the state income tax audit, which provided a $5.8 million
benefit to first half of 2013 earnings.
Liquidity
Consolidated:
Cash and cash equivalents totaled $34.1 million as of June 30, 2014, compared with $43.4 million as of December 31, 2013.
On April 24, 2014, CL&P issued $250 million of 4.30 percent 2014 Series A First Mortgage Bonds, due to mature in April 2044. The proceeds, net of issuance costs, were used to repay short-term borrowings.
On April 15, 2014, NSTAR Electric repaid at maturity the $300 million of 4.875 percent debentures using short-term debt.
On July 15, 2014, PSNH repaid at maturity the $50 million of 5.25 percent Series L First Mortgage Bonds using short-term debt.
Effective July 23, 2014, NU parent, CL&P, PSNH, WMECO, NSTAR Gas and Yankee Gas amended their joint $1.45 billion revolving credit facility to extend the expiration date an additional year to September 6, 2019. The revolving credit facility is to be used primarily to backstop NU parent's $1.45 billion commercial paper program. The commercial paper program allows NU parent to issue commercial paper as a form of short-term debt. As of June 30, 2014 and December 31, 2013, NU had $710.5 million and $1.01 billion, respectively, in short-term borrowings outstanding under the NU parent commercial paper program, leaving $739.5 million and $435.5 million of available borrowing capacity as of June 30, 2014 and December 31, 2013, respectively. The weighted-average interest rate on these borrowings as of June 30, 2014 and December 31, 2013 was 0.25 percent and 0.24 percent, respectively, which is generally based on A2/P2 rated commercial paper. As of June 30, 2014, there were intercompany loans from NU of $6.4 million to CL&P, $95 million to PSNH and $15.9 million to WMECO. As of December 31, 2013, there were intercompany loans from NU of $287.3 million to CL&P and $86.5 million to PSNH.
Effective July 23, 2014, NSTAR Electric amended its $450 million revolving credit facility to extend the expiration date an additional year to September 6, 2019. This facility serves to backstop NSTAR Electric's existing $450 million commercial paper program. As of June 30, 2014 and December 31, 2013, NSTAR Electric had $194.5 million and $103.5 million, respectively, in short-term borrowings outstanding under its commercial paper program, leaving $255.5 million and $346.5 million, respectively, of available borrowing capacity as of June 30, 2014 and December 31, 2013, respectively. The weighted-average interest rate on these borrowings as of June 30, 2014 and December 31, 2013 was 0.16 percent and 0.13 percent, respectively, which is generally based on A2/P1 rated commercial paper.
Cash flows provided by operating activities totaled $896.7 million in the first half of 2014, compared with $769 million in the first half of 2013. The improved operating cash flows were due primarily to approximately $126 million in DOE Phase II Damages proceeds received by CL&P, NSTAR Electric, PSNH and WMECO on June 1, 2014 from the Yankee Companies associated with the spent nuclear fuel litigation, the absence of cash disbursements for major storm restoration costs and the decrease of $82.2 million in Pension and PBOP Plan cash contributions, partially offset by an increase in income taxes paid in the first half of 2014 ($158 million), as compared to the first half of 2013 ($16 million). For further information on the spent nuclear fuel litigation, see Note 8C, "Commitments and Contingencies – Contractual Obligations – Yankee Companies," in this combined Quarterly Report on Form 10-Q.
On April 7, 2014, Fitch affirmed the corporate credit ratings and outlook of NU, CL&P, NSTAR Electric, PSNH, WMECO and NSTAR Gas. On April 25, 2014, S&P affirmed the corporate credit ratings and revised the outlooks to positive from stable of NU, CL&P, NSTAR Electric, PSNH, WMECO, Yankee Gas and NSTAR Gas.
43
In the first half of 2014, we had cash dividends on common shares of $237.2 million, compared with $232 million in the first half of 2013. On May 1, 2014, our Board of Trustees approved a common dividend payment of $0.3925 per share, which was paid on June 30, 2014 to shareholders of record as of May 30, 2014.
In the first half of 2014, CL&P, NSTAR Electric, PSNH, and WMECO paid $85.6 million, $253 million, $33 million, and $49 million, respectively, in common dividends to NU parent.
Investments in Property, Plant and Equipment on the accompanying 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 half of 2014, investments for NU, CL&P, NSTAR Electric, PSNH, and WMECO were $724 million, $221.4 million, $213.5 million, $117.4 million, and $61.5 million, respectively.
Business Development and Capital Expenditures
Consolidated:
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 $706.2 million in the first half of 2014, compared with $644 million in the first half of 2013. These amounts included $25.5 million and $6.7 million in the first half of 2014 and 2013, respectively, related to our corporate service companies, NUSCO and RRR.
Transmission Business
:
Overall, transmission business capital expenditures increased by $9.6 million in the first half of 2014, as compared to the first half of 2013. A summary of transmission capital expenditures by company for the first half of 2014 and 2013 is as follows:
|
|
|
|
|
|
|
|
|
|
For the Six Months Ended June 30,
|
|
(Millions of Dollars)
|
|
2014
|
|
2013
|
|
CL&P
|
|
$
|
111.6
|
|
$
|
84.1
|
|
NSTAR Electric
|
|
|
70.2
|
|
|
79.3
|
|
PSNH
|
|
|
44.3
|
|
|
35.0
|
|
WMECO
|
|
|
33.1
|
|
|
41.5
|
|
NPT
|
|
|
12.4
|
|
|
22.1
|
|
Total Transmission Segment
|
|
$
|
271.6
|
|
$
|
262.0
|
NEEWS:
GSRP, the first, largest and most complicated project within the NEEWS family of projects was fully energized on November 20, 2013. As of June 30, 2014, CL&P and WMECO have placed $638.1 million in service with minimal remaining close-out activities continuing throughout the remainder of 2014.
The Interstate Reliability Project, which includes CL&P's construction of an approximately 40-mile, 345 kV overhead line from Lebanon, Connecticut to the Connecticut-Rhode Island border in Thompson, Connecticut where it will connect to transmission enhancements being constructed by National Grid in Rhode Island and Massachusetts, is the second major NEEWS project. As of May 2014, all three states have issued siting approvals. Completing all the project permit requirements, the Army Corps of Engineers issued its permit on the project in the first quarter of 2014. Project construction is underway in all three states. NU's portion of the cost is estimated to be $218 million and construction on its portion of the project is approximately 40 percent complete as of June 30, 2014. The project is expected to be placed in service by the end of 2015.
The Greater Hartford Central Connecticut Study (GHCC), which includes the reassessment of the Central Connecticut Reliability Project, continues to make progress. The final need results showed existing and worsening severe regional and local thermal overloads and voltage violations within each of the areas studied and across the interfaces of those areas. These results were presented to the ISO-NE Planning Advisory Committee in November 2013. On July 15, 2014, ISO-NE presented the preferred transmission solutions to its Planning Advisory Committee. These solutions are comprised of many 115 kV upgrades and are expected to cost approximately $350 million and be placed in service in late 2017.
Included as part of NEEWS are associated reliability related projects, $93.1 million of which have been placed in service. As of June 30, 2014, all construction on the associated reliability related projects has been completed.
Through June 30, 2014, CL&P and WMECO capitalized $292 million and $573.4 million, respectively, in costs associated with NEEWS, of which $39.2 million and $6.4 million, respectively, were capitalized in the first half of 2014.
Northern Pass:
Northern Pass is NU'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. NPT received ISO-NE approval under Section I.3.9 of the ISO tariff in 2013. By approving the project's Section I.3.9 application, ISO-NE determined that Northern Pass can reliably interconnect with the New England grid with no significant adverse effect on the reliability or operating characteristics of the regional energy grid and its participants. The $1.4 billion project is subject to comprehensive federal and state public permitting processes and is expected to be operational in the second half of 2017. The DOE continues to work on the draft Environmental Impact Statement (EIS) for Northern Pass. This includes a review of both the recommended route and various alternative routes. We expect the DOE to issue the draft EIS in late 2014. Once it is published, the DOE will commence a process of receiving written and verbal comments on the draft EIS and we expect the issuance of a final EIS in the second half of 2015. We expect to file the state permit application in January 2015 after receipt of the draft EIS.
44
Greater Boston Reliability and Boston Network Improvements:
As a result of continued analysis of the transmission needs to enhance system reliability and improve capacity in eastern Massachusetts, NSTAR Electric and PSNH expect to implement a series of new transmission initiatives over the next five years. We expect ISO-NE to select preferred solutions in the second half of 2014, and project costs to be approximately $495 million for these new initiatives.
Distribution Business
: A summary of distribution capital expenditures by company for the first half of 2014 and 2013 is as follows:
|
|
|
|
|
|
|
|
For the Six Months Ended June 30,
|
|
(Millions of Dollars)
|
2014
|
|
2013
|
|
CL&P:
|
|
|
|
|
|
|
Basic Business
|
$
|
24.3
|
|
$
|
27.8
|
|
Aging Infrastructure
|
|
74.7
|
|
|
71.3
|
|
Load Growth
|
|
34.7
|
|
|
31.8
|
|
Total CL&P
|
|
133.7
|
|
|
130.9
|
|
NSTAR Electric:
|
|
|
|
|
|
|
Basic Business
|
|
50.2
|
|
|
48.3
|
|
Aging Infrastructure
|
|
53.1
|
|
|
51.3
|
|
Load Growth
|
|
14.7
|
|
|
13.4
|
|
Total NSTAR Electric
|
|
118.0
|
|
|
113.0
|
|
PSNH:
|
|
|
|
|
|
|
Basic Business
|
|
14.1
|
|
|
8.5
|
|
Aging Infrastructure
|
|
26.5
|
|
|
20.0
|
|
Load Growth
|
|
13.1
|
|
|
10.1
|
|
Total PSNH
|
|
53.7
|
|
|
38.6
|
|
WMECO:
|
|
|
|
|
|
|
Basic Business
|
|
4.5
|
|
|
3.7
|
|
Aging Infrastructure
|
|
8.1
|
|
|
10.8
|
|
Load Growth
|
|
2.8
|
|
|
3.3
|
|
Total WMECO
|
|
15.4
|
|
|
17.8
|
|
Total - Electric Distribution (excluding Generation)
|
|
320.8
|
|
|
300.3
|
|
PSNH Generation
|
|
5.2
|
|
|
4.3
|
|
WMECO Generation
|
|
7.4
|
|
|
0.3
|
|
Total - Natural Gas
|
|
75.7
|
|
|
70.3
|
|
Total Electric and Natural Gas Distribution Segment
|
$
|
409.1
|
|
$
|
375.2
|
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, distribution 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.
FERC Regulatory Issues
FERC Base ROE Complaints:
On September 30, 2011, a complaint was filed jointly at FERC under Sections 206 and 306 of the Federal Power Act by several New England state attorneys general, state regulatory commissions, consumer advocates and other parties (the "Complainants"). The Complainants alleged that the base ROE of 11.14 percent that has been utilized since 2006 in the calculation of formula rates for transmission service under the ISO-NE Open Access Transmission Tariff by NETOs, including CL&P, NSTAR Electric, PSNH and WMECO, was unjust and unreasonable and asserted that the rate was excessive due to changes in the capital markets. Complainants sought an order to reduce the base ROE, effective October 1, 2011, and to require refunds. The FERC set the case for trial before a FERC ALJ after settlement negotiations were unsuccessful in August 2012.
On August 6, 2013, the FERC ALJ issued an initial decision finding that the base ROE in effect from October 1, 2011 through December 31, 2012 (refund period) was not reasonable, and recommended separate base ROEs for the refund period of 10.6 percent and for the period beginning when FERC issues its final decision (prospective period) of 9.7 percent, leaving policy considerations and additional adjustments to the FERC. In the third quarter of 2013, the Company recorded a series of reserves at its electric subsidiaries to recognize the potential financial impact from the FERC ALJ's initial decision for the refund period. The aggregate after-tax charge to third quarter 2013 earnings totaled $14.3 million at NU, which represented reserves of $7.7 million at CL&P, $3.4 million at NSTAR Electric, $1.4 million at PSNH and $1.8 million at WMECO.
On June 19, 2014, FERC issued an order partially affirming and partially reversing the ALJ's initial decision. FERC set a single tentative base ROE of 10.57 percent for the refund period and prospective period. FERC also modified its traditional methodology by adopting a two-step discounted cash flow analysis that it utilizes to determine the ROEs of both natural gas and oil pipeline projects. Using this methodology, FERC determined a new zone of reasonableness of 7.03 percent to 11.74 percent, and set the tentative base ROE at the 75
th
percentile of this new zone. FERC also stated that a utility's total ROE inclusive of transmission incentive ROE adders, should not exceed the top of the new zone of reasonableness produced by this methodology. FERC instituted a paper hearing on the long-term growth rate portion of the methodology, before it issues a final determination on the base ROE. On July 21, 2014, the NETOs and Complainants filed rehearing requests in this proceeding.
45
On December 27, 2012, a second complaint was filed jointly at FERC by several additional consumer groups and municipal parties, which challenged the NETOs' base ROE and sought refunds for the 15-month period beginning January 1, 2013. On June 19, 2014, the FERC issued a second order finding that the complaint raised issues of material fact, and set this complaint for trial, should settlement negotiations be unsuccessful. FERC stated that it could issue an order in this case by mid-2016. On July 21, 2014, the NETOs filed a rehearing request in this proceeding.
Though NU cannot predict the ultimate outcome of this proceeding, in the second quarter of 2014, the Company recorded a series of reserves at its electric subsidiaries to recognize the potential financial impact from the FERC's two orders issued on June 19, 2014 for the two refund periods. The aggregate after-tax charge to second quarter 2014 earnings totaled $32.1 million at NU, which represented reserves of $18.5 million at CL&P, $6.1 million at NSTAR Electric, $2 million at PSNH and $5.5 million at WMECO.
On July 31, 2014, the Complainants filed an additional complaint with FERC. At this time, the Company cannot determine the outcome of this complaint.
Regulatory Developments and Rate Matters
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 half of 2014, 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 NU 2013 Annual Report on Form 10-K.
Connecticut:
Distribution Rates
: On June 9, 2014, CL&P filed an application with the PURA to amend customer rates, effective December 1, 2014. CL&P requested an increase in total distribution rates of $231.5 million. The increase includes a base distribution rate increase of $116.7 million, an increase for the annual recovery of $89.5 million of previously approved 2011 and 2012 deferred storm restoration costs totaling $365 million, and an increase of $25.3 million for previously approved electric system resiliency costs. Currently, hearings are scheduled to occur in late August through September, and a final decision is expected in December 2014.
On June 17, 2014, PURA ordered CL&P to use the DOE Phase II Damages proceeds of $65.4 million received on June 1, 2014 to offset the $365 million in 2011 and 2012 deferred storm restoration costs that were approved for recovery by the PURA on March 12, 2014. For further information on the spent nuclear fuel litigation awards, see Note 8C, "Commitments and Contingencies – Contractual Obligations – Yankee Companies." As a result, CL&P will now recover approximately $300 million in storm costs from customers, which will be reflected in final rates approved by PURA at the conclusion of the current CL&P distribution rate case.
New Hampshire:
Generation
:
In 2013, the NHPUC opened a docket to investigate market conditions affecting PSNH's ES rate, how PSNH will maintain just and reasonable rates in light of those conditions, and any impact of PSNH's generation ownership on the New Hampshire competitive electric market. In a 2013 NHPUC staff report accepted by the NHPUC, the NHPUC staff recommended that the NHPUC examine whether default service rates remain sustainable on a going forward basis, define "just and reasonable" with respect to default service in the context of competitive retail markets, analyze the current and expected value of PSNH's generating units, and identify means to mitigate and address stranded cost recovery. In October 2013, the New Hampshire Legislative Oversight Committee on Electric Utility Restructuring (Oversight Committee) requested that the NHPUC conduct an analysis to determine whether it is now in the economic interest of PSNH's retail customers for PSNH to divest its interest in generation plants. On November 1, 2013, the Oversight Committee asked for a preliminary report by April 1, 2014 that would include a third party valuation of PSNH's generating assets and a report from NHPUC staff members concerning customers' economic interests in those generating assets.
On April 1, 2014, the NHPUC staff issued a "Preliminary Status Report Addressing the Economic Interest of PSNH's Retail Customers as it Relates to the Potential Divestiture of PSNH's Generating Plants," which included a consultant's analysis of the fair market value of PSNH generating assets and long-term power purchase contracts. The consultant's analysis estimated the fair market value of PSNH's generation assets to be $225 million as of December 31, 2013 and compared that amount to a stated net book value of $660 million, implying potential "stranded costs" in excess of $400 million. NHPUC staff made three recommendations: (1) that any further actions relating to PSNH's generating assets await a final decision in the Clean Air Project (scrubber) prudence proceeding; (2) that existing laws regarding divestiture, energy service, and cost recovery be harmonized; and (3) that ISO-NE provide input on the economic and reliability consequences of retirement of PSNH's coal- and oil-fired electric generating plants.
During its 2014 session, in response to the NHPUC staff report, the House and Senate passed a bill, which enacted changes to the laws governing divestiture of PSNH's generating assets. That bill requires the NHPUC to initiate a proceeding before January 1, 2015, to determine whether all or some of PSNH's generation assets should be divested. A progress report from the NHPUC must be made by March 31, 2015. The bill also changes the law to give the NHPUC express authority to order the divestiture of all or some of PSNH's generation assets if the NHPUC finds it is in the economic interest of customers to do so. The bill also clarifies the definition of "stranded costs" to include costs approved for recovery by the NHPUC in connection with the divestiture or retirement of PSNH's generation assets.
In the event of generation asset divestiture or retirement, present law, the PSNH Restructuring Settlement Agreement approved in 2000, and the Bill all require that the NHPUC provide recovery of any stranded costs by PSNH. We continue to believe all costs and generation investments are probable of recovery.
46
Legislative and Policy Matters
Massachusetts:
Gas Replacement and Expansion
:
On July 7, 2014, Massachusetts enacted "An Act Relative to Natural Gas Leaks" (the Act). The Act establishes a uniform natural gas leak classification standard for all Massachusetts natural gas utilities and a program that accelerates the replacement of aging natural gas infrastructure. The program will enable companies, including NSTAR Gas, to better manage the scheduling and costs of replacement. The Act also calls for the DPU to authorize natural gas utilities to design and offer programs to customers that will increase the availability, affordability and feasibility of natural gas service for new customers.
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 NU 2013 Form 10-K. There have been no material changes with regard to these critical accounting policies.
Other Matters
Accounting Standards Recently Adopted:
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:
Refer to Note 8B, "Commitments and Contingencies – Long-Term Contractual Arrangements," for discussion of material changes to contractual obligations.
Web Site:
Additional financial information is available through our web site at
www.nu.com
. 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 Quarterly Report on Form 10-Q.
47
RESULTS OF OPERATIONS – NORTHEAST UTILITIES AND SUBSIDIARIES
The following provides the amounts and variances in operating revenues and expense line items for the condensed consolidated statements of income for NU included in this Quarterly Report on Form 10-Q for the three and six months ended June 30, 2014 and 2013:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating Revenues and Expenses
|
|
|
Operating Revenues and Expenses
|
|
|
|
For the Three Months Ended June 30,
|
|
|
For the Six Months Ended June 30,
|
|
|
|
|
|
|
|
|
|
|
|
Increase/
|
|
|
|
|
|
|
|
|
|
|
Increase/
|
|
|
|
|
(Millions of Dollars)
|
2014
|
|
2013
|
|
(Decrease)
|
|
Percent
|
|
|
2014
|
|
2013
|
|
(Decrease)
|
|
Percent
|
|
|
Operating Revenues
|
$
|
1,677.6
|
|
$
|
1,635.9
|
|
$
|
41.7
|
|
2.5
|
%
|
|
$
|
3,968.2
|
|
$
|
3,630.9
|
|
$
|
337.3
|
|
9.3
|
%
|
|
Operating Expenses:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Purchased Power, Fuel and Transmission
|
|
624.2
|
|
|
488.3
|
|
|
135.9
|
|
27.8
|
|
|
|
1,602.4
|
|
|
1,236.1
|
|
|
366.3
|
|
29.6
|
|
|
|
Operations and Maintenance
|
|
373.2
|
|
|
357.2
|
|
|
16.0
|
|
4.5
|
|
|
|
724.9
|
|
|
703.3
|
|
|
21.6
|
|
3.1
|
|
|
|
Depreciation
|
|
152.2
|
|
|
159.5
|
|
|
(7.3)
|
|
(4.6)
|
|
|
|
303.0
|
|
|
314.5
|
|
|
(11.5)
|
|
(3.7)
|
|
|
|
Amortization of Regulatory
Assets/(Liabilities), Net
|
|
(3.5)
|
|
|
54.6
|
|
|
(58.1)
|
|
(a)
|
|
|
|
54.4
|
|
|
108.6
|
|
|
(54.2)
|
|
(49.9)
|
|
|
|
Amortization of Rate Reduction Bonds
|
|
-
|
|
|
8.1
|
|
|
(8.1)
|
|
(100.0)
|
|
|
|
-
|
|
|
42.6
|
|
|
(42.6)
|
|
(100.0)
|
|
|
|
Energy Efficiency Programs
|
|
102.7
|
|
|
94.1
|
|
|
8.6
|
|
9.1
|
|
|
|
241.5
|
|
|
199.9
|
|
|
41.6
|
|
20.8
|
|
|
|
Taxes Other Than Income Taxes
|
|
134.8
|
|
|
123.5
|
|
|
11.3
|
|
9.1
|
|
|
|
280.3
|
|
|
256.4
|
|
|
23.9
|
|
9.3
|
|
|
|
|
Total Operating Expenses
|
|
1,383.6
|
|
|
1,285.3
|
|
|
98.3
|
|
7.6
|
|
|
|
3,206.5
|
|
|
2,861.4
|
|
|
345.1
|
|
12.1
|
|
|
Operating Income
|
$
|
294.0
|
|
$
|
350.6
|
|
$
|
(56.6)
|
|
(16.1)
|
%
|
|
$
|
761.7
|
|
$
|
769.5
|
|
$
|
(7.8)
|
|
(1.0)
|
%
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(a)
|
Percent greater than 100 percent not shown as it is not meaningful.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating Revenues
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
For the Three Months Ended June 30,
|
|
|
For the Six Months Ended June 30,
|
|
|
(Millions of Dollars)
|
2014
|
|
2013
|
|
Increase/
(Decrease)
|
|
Percent
|
|
|
2014
|
|
2013
|
|
Increase/
(Decrease)
|
|
Percent
|
|
|
Electric Distribution
|
$
|
1,261.8
|
|
$
|
1,221.6
|
|
$
|
40.2
|
|
3.3
|
%
|
|
$
|
2,847.8
|
|
$
|
2,595.8
|
|
$
|
252.0
|
|
9.7
|
%
|
|
Natural Gas Distribution
|
|
195.5
|
|
|
154.1
|
|
|
41.4
|
|
26.9
|
|
|
|
628.3
|
|
|
515.9
|
|
|
112.4
|
|
21.8
|
|
|
|
Total Distribution
|
|
1,457.3
|
|
|
1,375.7
|
|
|
81.6
|
|
5.9
|
|
|
|
3,476.1
|
|
|
3,111.7
|
|
|
364.4
|
|
11.7
|
|
|
Transmission
|
|
206.9
|
|
|
247.9
|
|
|
(41.0)
|
|
(16.5)
|
|
|
|
458.9
|
|
|
487.4
|
|
|
(28.5)
|
|
(5.8)
|
|
|
|
Total Regulated Companies
|
|
1,664.2
|
|
|
1,623.6
|
|
|
40.6
|
|
2.5
|
|
|
|
3,935.0
|
|
|
3,599.1
|
|
|
335.9
|
|
9.3
|
|
|
Other and Eliminations
|
|
13.4
|
|
|
12.3
|
|
|
1.1
|
|
8.9
|
|
|
|
33.2
|
|
|
31.8
|
|
|
1.4
|
|
4.4
|
|
|
Total Operating Revenues
|
$
|
1,677.6
|
|
$
|
1,635.9
|
|
$
|
41.7
|
|
2.5
|
%
|
|
$
|
3,968.2
|
|
$
|
3,630.9
|
|
$
|
337.3
|
|
9.3
|
%
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
A summary of our retail electric sales and firm natural gas sales were as follows:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
For the Three Months Ended June 30,
|
|
|
For the Six Months Ended June 30,
|
|
|
|
|
|
|
|
|
Increase/
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2014
|
|
2013
|
|
(Decrease)
|
|
Percent
|
|
|
2014
|
|
2013
|
|
Increase
|
|
Percent
|
|
|
Retail Electric Sales in GWh
|
12,536
|
|
12,911
|
|
(375)
|
|
(2.9)
|
%
|
|
26,884
|
|
26,707
|
|
177
|
|
0.7
|
%
|
|
Firm Natural Gas Sales in Million Cubic Feet
|
16,924
|
|
16,257
|
|
667
|
|
4.1
|
|
|
63,841
|
|
56,872
|
|
6,969
|
|
12.3
|
|
Operating Revenues increased in the second quarter of 2014, as compared to the second quarter of 2013. The increase primarily reflects higher costs associated with purchasing electricity and natural gas on behalf of our customers. Fluctuations in these energy supply costs are recovered from customers in rates and therefore have no impact on earnings. Retail electric sales volumes decreased 2.9 percent from the second quarter of 2013 as a result of milder temperatures in late May and June of 2014, as well as the impact of utility-sponsored energy efficiency programs. Firm natural gas sales volume increased 4.1 percent from the second quarter of 2013 as customer growth and economic conditions in our service territory have shown steady improvement over the past year.
As noted above, our respective utility-sponsored energy efficiency programs have the impact of reducing both retail electric and firm natural gas sales. Certain utility operating companies are permitted to bill customers for lost base revenues related to reductions in sales volume as a result of their energy efficiency. In the second quarter of 2014, base electric and natural gas distribution revenues decreased $3 million, compared to the second quarter of 2013 (including the impact from the recognition of lost base revenues).
Transmission revenues decreased in the second quarter of 2014, as compared to the second quarter of 2013, due primarily to the impact of the reserves recorded during the second quarter of 2014 as a result of the FERC ROE orders issued in the FERC base ROE complaints. For further information, see "FERC Regulatory Issues - FERC Base ROE Complaints"
in this
Management's Discussion and Analysis.
Operating Revenues increased in the first half of 2014, as compared to the first half of 2013. The increase reflects higher retail electric and firm natural gas sales volumes primarily as a result of the significantly colder weather in the first quarter of 2014, as compared to the same period in 2013, and the overall impact of higher costs associated with the procurement of energy supply. Our energy supply costs were impacted by higher natural gas transportation costs which, in addition to its impact on the cost of natural gas purchased on behalf of our retail natural gas customers, had an adverse impact on the cost of purchased electric energy for our retail electric customers. Fluctuations in energy supply costs are recovered from customers in rates and therefore have no impact on earnings.
As noted above, the increase in distribution revenues reflects an increase of approximately 0.7 percent in retail electric sales and 12.3 percent in firm natural gas sales. The increase in sales volumes was driven primarily by the cold winter weather experienced throughout our service territories in the first quarter of 2014. The winter was significantly colder than both normal and the same period last year throughout New England. Weather-normalized retail electric sales (based on 30-year average temperatures) decreased 0.1 percent in the first half of 2014, as compared to the same
48
period in 2013, reflecting the impact of our utility-sponsored energy efficiency programs. Weather-normalized total firm natural gas sales increased 4.1 percent in the first half of 2014, as compared to the same period in 2013, due primarily to residential and commercial customer growth.
Certain utility operating companies are permitted to bill customers for lost base revenues related to reductions in sales volume as a result of their energy efficiency. In the first half of 2014, base electric and natural gas distribution revenues increased $38 million, compared to the first half of 2013 (including the impact from the recognition of lost base revenues).
Transmission revenues decreased in the first half of 2014, as compared to the first half of 2013, due primarily to the impact of the reserve recorded during the second quarter of 2014 as a result of the FERC ROE orders issued in the FERC base ROE complaints.
Purchased Power, Fuel and Transmission
increased for the three and six months ended June 30, 2014, as compared to the same periods in 2013, due primarily to the following:
|
|
|
|
|
|
|
|
Three Months Ended
|
|
Six Months Ended
|
|
(Millions of Dollars)
|
Increase/(Decrease)
|
|
Increase/(Decrease)
|
|
Electric distribution segment fuel and energy supply costs
|
$
|
139.6
|
|
$
|
334.7
|
|
Firm natural gas sales related costs
|
|
35.3
|
|
|
69.2
|
|
Transmission segment costs
|
|
(0.7)
|
|
|
(3.2)
|
|
All other (including eliminations)
|
|
3.6
|
|
|
15.7
|
|
Partially offset by:
|
|
|
|
|
|
|
Electric distribution segment purchased power and deferred fuel costs
|
|
(41.9)
|
|
|
(50.1)
|
|
|
$
|
135.9
|
|
$
|
366.3
|
Operations and Maintenance
expense includes costs that are recovered in rates through cost tracking mechanisms, which have no earnings impact (tracked costs), and costs that are recovered through base electric and natural gas distribution rates (and therefore impact earnings). Operations and Maintenance increased for the three and six months ended June 30, 2014, as compared to the same periods in 2013, due primarily to the following:
|
|
|
|
|
|
|
|
Three Months Ended
|
|
Six Months Ended
|
|
(Millions of Dollars)
|
Increase/(Decrease)
|
|
Increase/(Decrease)
|
|
Base Electric Distribution:
|
|
|
|
|
|
|
Bad debt expense
|
$
|
2.0
|
|
$
|
5.2
|
|
Implementation of a new outage restoration program at CL&P
|
|
3.7
|
|
|
3.8
|
|
Employee costs, including pension and benefit related costs
|
|
(20.2)
|
|
|
(30.9)
|
|
Storm costs
|
|
0.4
|
|
|
(4.8)
|
|
Other operations and maintenance
|
|
7.2
|
|
|
9.1
|
|
Total Base Electric Distribution
|
|
(6.9)
|
|
|
(17.6)
|
|
Total Natural Gas Distribution
|
|
(1.1)
|
|
|
3.0
|
|
Total Tracked costs (Transmission and Electric Distribution)
|
|
14.4
|
|
|
23.5
|
|
Total Distribution and Transmission
|
|
6.4
|
|
|
8.9
|
|
Other and eliminations:
|
|
|
|
|
|
|
Integration and severance costs
|
|
4.7
|
|
|
11.5
|
|
All other (including eliminations)
|
|
4.9
|
|
|
1.2
|
|
Total Operations and Maintenance
|
$
|
16.0
|
|
$
|
21.6
|
The Operations and Maintenance expenses that are recovered through base electric distribution rates (and therefore impact earnings) decreased $6.9 million and $17.6 million, respectively, for the three and six months ended June 30, 2014, as compared to the same periods in 2013. The Operations and Maintenance expenses that are recovered through cost tracking mechanisms (and therefore have no earnings impact) increased $14.4 million and $23.5 million, respectively, for the three and six months ended June 30, 2014, as compared to the same periods in 2013. These increases were primarily driven by an increase in bad debt expense ($4.2 million and $8.2 million, respectively) and higher operation and maintenance costs at the PSNH generation business due to the timing of planned outages ($4.2 million and $5.1 million, respectively) for the three and six months ended June 30, 2014, as compared to the same periods in 2013.
Depreciation
decreased for the three and six months ended June 30, 2014, as compared to the same periods in 2013, due primarily to a decrease in CYAPC and YAEC decommissioning costs ($12.5 million and $25 million, respectively), partially offset by an increase related to higher utility plant balances resulting from completed construction projects placed into service ($5 million and $10.6 million, respectively).
Amortization of Regulatory Assets/(Liabilities), Net
decreased for the three and six months ended June 30, 2014, as compared to the same periods in 2013, due primarily to the following:
|
|
|
|
|
|
|
|
Three Months Ended
|
|
Six Months Ended
|
|
(Millions of Dollars)
|
Increase/(Decrease)
|
|
Increase/(Decrease)
|
|
Recovery of stranded costs at NSTAR Electric
|
$
|
(55.1)
|
|
$
|
(86.4)
|
|
Increases in the SCRC, ES and other amortizations at PSNH
|
|
(21.5)
|
|
|
(5.8)
|
|
Amortization of previously deferred congestion costs at CL&P
|
|
19.1
|
|
|
38.3
|
|
Other
|
|
(0.6)
|
|
|
(0.3)
|
|
|
$
|
(58.1)
|
|
$
|
(54.2)
|
Amortization of Rate Reduction Bonds
decreased for the three and six months ended June 30, 2014, as compared to the same periods in 2013, due to the maturity in 2013 of RRBs of NSTAR Electric, PSNH, and WMECO.
49
Energy Efficiency Programs
increased for the three and six months ended June 30, 2014, as compared to the same periods in 2013, due primarily to an increase in energy efficiency costs in accordance with the three-year program guidelines established by the DPU at NSTAR Electric and WMECO and expanded energy conservation programs at CL&P in 2014, partially offset by a decrease in the amortization of previously deferred costs at NSTAR Electric. All costs are fully recovered through approved tracking mechanisms and therefore do not impact earnings.
Taxes Other Than Income Taxes
increased for the three and six months ended June 30, 2014, as compared to the same periods in 2013, due primarily to an increase in property taxes ($9.1 million and $16.6 million, respectively) as a result of both an increase in utility plant balances and property tax rates, and an increase in the Connecticut gross earnings tax ($2.2 million and $8.2 million, respectively) attributable to an increase in retail revenues.
Interest Expense
increased $5.6 million and $19.4 million for the three and six months ended June 30, 2014, as compared to the same periods in 2013, respectively, due primarily to the absence in 2014 of the favorable impact from the resolution of a Connecticut state income tax audit in the first quarter of 2013 ($8.8 million for the six months), lower interest income on deferred transition costs ($3.5 million and $8 million, respectively), and an increase in interest on long-term debt ($1.5 million and $3.6 million, respectively) as a result of new debt issuances in the second quarter and first half of 2014.
Other Income, Net
decreased $5.5 million in the first half of 2014, as compared to the first half of 2013, due primarily to lower unrealized gains on the assets supporting the deferred compensation plans ($5.3 million).
Income Tax Expense
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
For the Three Months Ended June 30,
|
|
|
For the Six Months Ended June 30,
|
|
|
(Millions of Dollars)
|
2014
|
|
2013
|
|
Decrease
|
|
Percent
|
|
|
2014
|
|
2013
|
|
Increase
|
|
Percent
|
|
|
Income Tax Expense
|
$
|
77.8
|
|
$
|
95.6
|
|
$
|
(17.8)
|
|
(18.6)
|
%
|
|
$
|
219.3
|
|
$
|
216.1
|
|
$
|
3.2
|
|
1.5
|
%
|
Income Tax Expense decreased for the three months ended June 30, 2014, as compared to the same period in 2013, due primarily to lower pre-tax earnings ($2.5 million) and the tax benefit impact from the reserve recorded in the second quarter of 2014 as a result of the FERC ROE orders issued in the FERC base ROE complaints ($22.1 million), partially offset by higher state taxes ($4.6 million) and various other tax impacts ($2.2 million).
Income Tax Expense increased for the six months ended June 30, 2014, as compared to the same period in 2013, due primarily to higher pre-tax earnings ($10.6 million), higher state taxes ($8.6 million), the absence of the favorable impact from the resolution of a state income tax audit in the first quarter of 2013 ($4.8 million), and various other tax impacts ($1.3 million), partially offset by the tax benefit impact from the reserve recorded as a result of the FERC ROE orders issued in the FERC base ROE complaints ($22.1 million).
50
RESULTS OF OPERATIONS – THE CONNECTICUT LIGHT AND POWER COMPANY
The following provides the amounts and variances in operating revenues and expense line items for the condensed statements of income for CL&P included in this Quarterly Report on Form 10-Q for the three and six months ended June 30, 2014 and 2013:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating Revenues and Expenses
|
|
|
Operating Revenues and Expenses
|
|
|
|
|
|
For the Three Months Ended June 30,
|
|
|
For the Six Months Ended June 30,
|
|
|
(Millions of Dollars)
|
2014
|
|
2013
|
|
Increase/
(Decrease)
|
|
Percent
|
|
|
2014
|
|
2013
|
|
Increase/
(Decrease)
|
|
Percent
|
|
|
Operating Revenues
|
$
|
587.3
|
|
$
|
569.3
|
|
$
|
18.0
|
|
3.2
|
%
|
|
$
|
1,321.9
|
|
$
|
1,193.4
|
|
$
|
128.5
|
|
10.8
|
%
|
|
Operating Expenses:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Purchased Power and Transmission
|
|
199.8
|
|
|
184.8
|
|
|
15.0
|
|
8.1
|
|
|
|
481.2
|
|
|
414.1
|
|
|
67.1
|
|
16.2
|
|
|
|
Operations and Maintenance
|
|
131.8
|
|
|
123.8
|
|
|
8.0
|
|
6.5
|
|
|
|
241.3
|
|
|
232.6
|
|
|
8.7
|
|
3.7
|
|
|
|
Depreciation
|
|
46.6
|
|
|
45.1
|
|
|
1.5
|
|
3.3
|
|
|
|
92.7
|
|
|
87.6
|
|
|
5.1
|
|
5.8
|
|
|
|
Amortization of Regulatory Assets, Net
|
|
19.6
|
|
|
0.5
|
|
|
19.1
|
|
(a)
|
|
|
|
49.5
|
|
|
11.2
|
|
|
38.3
|
|
(a)
|
|
|
|
Energy Efficiency Programs
|
|
35.3
|
|
|
20.8
|
|
|
14.5
|
|
69.7
|
|
|
|
78.0
|
|
|
43.7
|
|
|
34.3
|
|
78.5
|
|
|
|
Taxes Other Than Income Taxes
|
|
62.1
|
|
|
57.5
|
|
|
4.6
|
|
8.0
|
|
|
|
129.1
|
|
|
117.7
|
|
|
11.4
|
|
9.7
|
|
|
|
|
Total Operating Expenses
|
|
495.2
|
|
|
432.5
|
|
|
62.7
|
|
14.5
|
|
|
|
1,071.8
|
|
|
906.9
|
|
|
164.9
|
|
18.2
|
|
|
Operating Income
|
$
|
92.1
|
|
$
|
136.8
|
|
$
|
(44.7)
|
|
(32.7)
|
%
|
|
$
|
250.1
|
|
$
|
286.5
|
|
$
|
(36.4)
|
|
(12.7)
|
%
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(a) Percent greater than 100 percent not shown as it is not meaningful.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating Revenues
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
CL&P's retail sales were as follows:
|
|
|
|
|
|
|
|
|
|
|
|
|
For the Three Months Ended June 30,
|
|
|
For the Six Months Ended June 30,
|
|
|
|
|
2014
|
|
2013
|
|
Decrease
|
|
Percent
|
|
|
2014
|
|
2013
|
|
Increase
|
|
Percent
|
|
|
Retail Sales in GWh
|
5,050
|
|
5,194
|
|
(144)
|
|
(2.8)
|
%
|
|
10,999
|
|
10,875
|
|
124
|
|
1.1
|
%
|
CL&P's Operating Revenues increased in the second quarter of 2014, as compared to the same period of 2013. The increase primarily reflects higher costs associated with purchasing electricity on behalf of our customers. Fluctuations in these energy supply costs are recovered from customers in rates and therefore have no impact on earnings. Partially offsetting this increase was the impact of the reserve recorded during the second quarter of 2014 as a result of the FERC ROE orders issued in the FERC base ROE complaints. For further information, see "FERC Regulatory Issues - FERC Base ROE Complaints"
in this
Management's Discussion and Analysis.
In addition, retail sales volumes decreased 2.8 percent in the second quarter of 2014, as compared to the same period in 2013, as a result of milder temperatures in late May and June of 2014.
CL&P's Operating Revenues increased in the first half of 2014, as compared to the first half of 2013. The increase reflects higher retail sales volumes of 1.1 percent as a result of significantly colder weather in the first quarter of 2014, as compared to the same period in 2013, and the overall impact of higher costs associated with the procurement of energy supply. The energy supply costs were impacted by higher natural gas transportation costs, which had an adverse impact on the cost of purchased electric energy for our retail customers. Fluctuations in energy supply costs are recovered from customers in rates and therefore have no impact on earnings. Partially offsetting this increase was the impact of the reserve recorded during the second quarter of 2014 as a result of the FERC ROE orders issued in the FERC base ROE complaints.
Purchased Power and Transmission
increased for the three and six months ended June 30, 2014, as compared to the same periods in 2013, due primarily to the following:
|
|
|
|
|
|
|
|
Three Months Ended
|
|
Six Months Ended
|
|
(Millions of Dollars)
|
Increase/(Decrease)
|
|
Increase/(Decrease)
|
|
GSC Supply Costs
|
$
|
3.2
|
|
$
|
104.4
|
|
Transmission Costs
|
|
5.4
|
|
|
11.8
|
|
Deferred Fuel Costs
|
|
26.8
|
|
|
(29.0)
|
|
Purchased Power Costs
|
|
(15.6)
|
|
|
(15.2)
|
|
Other
|
|
(4.8)
|
|
|
(4.9)
|
|
|
$
|
15.0
|
|
$
|
67.1
|
The increase in GSC supply costs was due primarily to higher average supply prices and an increase in GSC loads as a result of an increase in retail sales and customers returning to standard offer from third party suppliers. On July 1, 2013, CL&P began to procure approximately 30 percent of GSC load. Costs associated with the remaining 70 percent of the GSC load are the contractual amounts CL&P must pay to various energy suppliers that have been awarded the right to supply standard service and supplier of last resort service load through a competitive solicitation process. The increase in transmission costs was the result of an increase in the retail transmission deferral, which reflects the actual costs of transmission service compared to estimated billed amounts. The decrease in deferred fuel costs for the six months ended June 30, 2014 was due primarily to higher average electric supply prices, as compared to the prices projected when standard service rates were set. Purchased Power and Transmission costs are included in PURA-approved tracking mechanisms and do not impact earnings.
Operations and Maintenance
expense includes costs that are recovered in rates through cost tracking mechanisms, which have no earnings impact (tracked costs), and costs that are recovered through base electric distribution rates (and therefore impact earnings). Operations and Maintenance increased in the second quarter of 2014, as compared to the same period in 2013, driven by a $5.2 million increase in tracked costs that have no earnings impact, which was primarily attributable to higher bad debt expense of $3.6 million. There was also an increase in costs that impact earnings of $2.8 million, which was primarily attributable to the implementation of a new outage restoration program of $3.7 million, higher routine vegetation management costs of $3.7 million and higher bad debt expense of $1.3 million, partially offset by lower employee costs (including pension and benefit related costs) of $8.4 million.
51
Operations and Maintenance increased in the first half of 2014, as compared to the same period in 2013, driven by a $9.6 million increase in costs that have no earnings impact, primarily attributable to higher bad debt expense of $7.2 million. Partially offsetting this increase was a decrease in costs that impact earnings of $0.9 million, primarily attributable to lower employee costs (including pension and benefit related costs) of $13.1 million, partially offset by the implementation of a new outage restoration program of $3.8 million, higher bad debt expense of $2.9 million and higher routine vegetation management costs of $3.4 million.
Depreciation
increased for the three and six months ended June 30, 2014, as compared to the same periods in 2013, due primarily to higher utility plant balances resulting from completed construction projects placed into service.
Amortization of Regulatory Assets, Net
increased for the three and six months ended June 30, 2014, as compared to the same periods in 2013, due primarily to an increase in amortization expense related to previously deferred congestion charges.
Energy Efficiency Programs
increased for the three and six months ended June 30, 2014, as compared to the same periods in 2013, due primarily to expanded energy conservation programs in 2014. All costs are fully recovered through PURA-approved tracking mechanisms and therefore do not impact earnings.
Taxes Other Than Income Taxes
increased for the three and six months ended June 30, 2014, as compared to the same periods in 2013, due primarily to an increase in property taxes as a result of both an increase in utility plant balances and property tax rates ($3.9 million and $7.8 million, respectively). In addition, there was an increase in the Connecticut gross earnings tax attributable to an increase in retail revenues ($1.1 million and $4.7 million, respectively).
Interest Expense
increased $3.5 million and $8 million for the three and six months ended June 30, 2014, as compared to the same periods in 2013, respectively, due primarily to the absence in 2014 of the favorable impact from the resolution of a state income tax audit in the first quarter of 2013 ($6 million for the six months), an increase in other interest ($1 million and $2.2 million, respectively) and an increase in interest on long-term debt ($2 million and $2.2 million, respectively).
Other Income, Net
decreased $2.9 million in the first six months of 2014, as compared to the same period in 2013, due primarily to lower unrealized gains on the assets supporting the deferred compensation plans ($1.4 million) and lower AFUDC-Equity ($1.2 million).
Income Tax Expense
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
For the Three Months Ended June 30,
|
|
|
For the Six Months Ended June 30,
|
|
|
(Millions of Dollars)
|
2014
|
|
2013
|
|
Decrease
|
|
Percent
|
|
|
2014
|
|
2013
|
|
Decrease
|
|
Percent
|
|
|
Income Tax Expense
|
$
|
20.4
|
|
$
|
37.8
|
|
$
|
(17.4)
|
|
(46.0)
|
%
|
|
$
|
65.9
|
|
$
|
77.0
|
|
$
|
(11.1)
|
|
(14.4)
|
%
|
Income Tax Expense decreased for the three and six months ended June 30, 2014, as compared to the same periods in 2013, due primarily to lower pre-tax earnings ($5.8 million and $4.2 million, respectively) and the tax benefit impact from the FERC ROE orders issued in the second quarter of 2014 ($12.8 million for the three and six months), partially offset by the absence in 2014 of the state audit closure benefit impact ($2.9 million for the six months) and various other tax impacts ($1.2 million and $3.0 million, respectively).
EARNINGS SUMMARY
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
For the Three Months Ended June 30,
|
|
|
For the Six Months Ended June 30,
|
|
|
(Millions of Dollars)
|
2014
|
|
2013
|
|
Decrease
|
|
Percent
|
|
|
2014
|
|
2013
|
|
Decrease
|
|
Percent
|
|
|
Net Income
|
$
|
37.4
|
|
$
|
67.9
|
|
$
|
(30.5)
|
|
(44.9)
|
%
|
|
$
|
116.7
|
|
$
|
152.9
|
|
$
|
(36.2)
|
|
(23.7)
|
%
|
CL&P's second quarter 2014 earnings were lower than the same period in 2013 due primarily to the establishment of an $18.5 million after-tax reserve related to the June 2014 FERC ROE orders, lower retail sales as a result of milder temperatures in late May and June of 2014, as compared to the same period in 2013, higher property tax expense, increased interest expense relating to an April 2014 financing, and higher depreciation expense. Partially offsetting these unfavorable earnings impacts were increased investments in the transmission infrastructure.
For the six months ended June 30, 2014, CL&P's earnings decreased, as compared to the same period in 2013, due primarily to the establishment of the after-tax reserve related to the June 2014 FERC ROE orders, higher property tax expense and increased interest expense relating to an April 2014 financing. Partially offsetting these unfavorable earnings impacts were higher retail electric sales as a result of colder weather in the first quarter of 2014 and increased investments in the transmission infrastructure.
52
LIQUIDITY
CL&P had cash flows provided by operating activities of $275.4 million in the first half of 2014, compared with $178.2 million in the first half of 2013. The improved cash flows were due primarily to $65.4 million in DOE Phase II Damages proceeds received on June 1, 2014 from the Yankee Companies associated with the spent nuclear fuel litigation, the absence of cash disbursements for major storm restoration costs and an increase in regulatory overrecoveries
,
partially offset by income tax payments of $3.8 million in the first half of 2014, as compared to income tax refunds of $6 million in the first half of 2013, and an unfavorable cash flow impact relating to the timing of accounts receivable payments made to affiliated companies in the second quarter of 2014.
Investments in Property, Plant and Equipment on the accompanying 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 half of 2014, investments for CL&P were $221.4 million.
On April 24, 2014, CL&P issued $250 million of 4.30 percent 2014 Series A First Mortgage Bonds, due to mature in April 2044. The proceeds, net of issuance costs, were used to repay short-term borrowings.
Effective July 23, 2014, NU parent and certain of its subsidiaries, including CL&P, amended their joint $1.45 billion revolving credit facility to extend the expiration date an additional year to September 6, 2019. The revolving credit facility is to be used primarily to backstop NU parent's $1.45 billion commercial paper program. The commercial paper program allows NU parent to issue commercial paper as a form of short-term debt to its subsidiaries, including CL&P. As of June 30, 2014 and December 31, 2013, there were intercompany loans from NU parent of $6.4 million and $287.3 million, respectively, to CL&P.
Additional financing activities in the first half of 2014 included $85.6 million in common stock dividends paid to NU parent.
On April 7, 2014, Fitch affirmed the corporate credit rating and outlook of CL&P. On April 25, 2014, S&P affirmed the corporate credit rating and revised the outlook to positive from stable of CL&P.
53
RESULTS OF OPERATIONS – NSTAR ELECTRIC COMPANY AND SUBSIDIARY
The following provides the amounts and variances in operating revenues and expense line items for the condensed consolidated statements of income for NSTAR Electric included in this Quarterly Report on Form 10-Q for the six months ended June 30, 2014 and 2013:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating Revenues and Expenses
|
|
|
|
For the Six Months Ended June 30,
|
|
|
(Millions of Dollars)
|
2014
|
|
2013
|
|
Increase/
|
|
Percent
|
|
|
(Decrease)
|
|
|
Operating Revenues
|
$
|
1,227.7
|
|
$
|
1,162.7
|
|
$
|
65.0
|
|
5.6
|
%
|
|
Operating Expenses:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Purchased Power and Transmission
|
|
562.0
|
|
|
403.9
|
|
|
158.1
|
|
39.1
|
|
|
|
Operations and Maintenance
|
|
164.9
|
|
|
180.2
|
|
|
(15.3)
|
|
(8.5)
|
|
|
|
Depreciation
|
|
93.6
|
|
|
90.9
|
|
|
2.7
|
|
3.0
|
|
|
|
Amortization of Regulatory Assets, Net
|
|
14.1
|
|
|
100.5
|
|
|
(86.4)
|
|
(86.0)
|
|
|
|
Amortization of Rate Reduction Bonds
|
|
-
|
|
|
15.0
|
|
|
(15.0)
|
|
(100.0)
|
|
|
|
Energy Efficiency Programs
|
|
88.6
|
|
|
102.4
|
|
|
(13.8)
|
|
(13.5)
|
|
|
|
Taxes Other Than Income Taxes
|
|
64.6
|
|
|
62.7
|
|
|
1.9
|
|
3.0
|
|
|
|
|
Total Operating Expenses
|
|
987.8
|
|
|
955.6
|
|
|
32.2
|
|
3.4
|
|
|
Operating Income
|
$
|
239.9
|
|
$
|
207.1
|
|
$
|
32.8
|
|
15.8
|
%
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating Revenues
|
|
|
|
|
|
|
|
|
|
|
|
NSTAR Electric's retail sales were as follows:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
For the Six Months Ended June 30,
|
|
|
|
|
|
|
2014
|
|
2013
|
|
Decrease
|
|
Percent
|
|
|
|
Retail Sales in GWh
|
|
10,183
|
|
10,198
|
|
(15)
|
|
(0.1)
|
%
|
|
NSTAR Electric's Operating Revenues increased in the first half of 2014, as compared to the first half of 2013. The increase primarily reflects the overall impact of higher costs associated with the procurement of energy supply. Our energy supply costs were impacted by higher natural gas transportation costs, which had an adverse impact on the cost of purchased electric energy for our retail customers. Fluctuations in energy supply costs are recovered from customers in rates and therefore have no impact on earnings. Partially offsetting this increase was the impact of the reserve recorded during the second quarter of 2014 as a result of the FERC ROE orders issued in the FERC base ROE complaints. For further information, see "FERC Regulatory Issues - FERC Base ROE Complaints"
in this
Management's Discussion and Analysis.
Additionally, stranded cost recovery revenues decreased during the period, reflecting the full collection in 2013 of previously deferred costs, as well as the full amortization of RRBs. Base distribution revenues were relatively flat in the first half of 2014, as compared to the same period in 2013, reflecting comparable sales, which was due primarily to colder weather in the first quarter of 2014 offset by milder temperatures in late May and June of 2014 and customer savings due to the impact of its energy efficiency programs. NSTAR Electric is permitted to bill customers for lost base revenues related to reductions in sales volume as a result of their energy efficiency. In the first half of 2014, base distribution revenues increased $5.4 million, compared to the first half of 2013 (including the impact from the recognition of lost base revenues).
Purchased Power and Transmission
increased in the first half of 2014, as compared to the first half of 2013, due primarily to the following:
|
|
|
|
(Millions of Dollars)
|
Six Months Ended
Increase/(Decrease)
|
|
Basic Service Costs
|
$
|
115.4
|
|
Transmission Costs
|
|
26.4
|
|
Purchased Power Costs
|
|
20.1
|
|
Deferred Fuel Costs
|
|
(3.8)
|
|
|
$
|
158.1
|
The increase in Basic Service costs was primarily related to higher average supply prices. The increase in transmission costs was due primarily to higher RNS expense, and the increase in purchased power costs was due primarily to higher congestion charges. The decrease in deferred fuel costs was due primarily to higher average electricity supply prices, as compared to the prices projected when Basic Service rates were set. Purchased Power and Transmission costs are included in DPU-approved tracking mechanisms and do not impact earnings.
Operations and Maintenance
expense includes costs that are recovered in rates through cost tracking mechanisms, which have no earnings impact (tracked costs), and costs that are recovered through base electric distribution rates (and therefore impact earnings). Operations and Maintenance decreased in the first half of 2014, as compared to the first half of 2013, driven by a $21.5 million reduction in costs that impact earnings (primarily attributable to lower employee costs and benefit costs of $15.7 million and lower storm costs of $3 million. Partially offsetting this decrease was an increase in costs that have no earnings impact of $6.2 million (primarily attributable to higher storm costs of $3 million).
Depreciation
increased in the first half of 2014, as compared to the first half of 2013, due primarily to higher utility plant balances resulting from completed construction projects placed into service.
Amortization of Regulatory Assets, Net
decreased in the first half of 2014, as compared to the first half of 2013, due primarily to a decrease in the recovery of previously deferred stranded costs.
Amortization of Rate Reduction Bonds
decreased in the first half of 2014, as compared to the first half of 2013, due to the maturity of the RRBs in March 2013.
54
Energy Efficiency Programs
decreased in the first half of 2014, as compared to the first half of 2013, due primarily to a decrease in the amortization of previously deferred costs. All costs are fully recovered through DPU-approved tracking mechanisms and therefore do not impact earnings.
Taxes Other Than Income Taxes
increased in the first half of 2014, as compared to the first half of 2013, due to an increase in property taxes as a result of an increase in utility plant balances, partially offset by lower average municipal property tax rates.
Interest Expense
increased $8.6 million in the first half of 2014, as compared to the first half of 2013, due primarily to lower interest income on deferred transition costs ($8 million), as well as an increase in interest on long-term debt.
Other Income/(Loss), Net
decreased $1.4 million in the first half of 2014, as compared to the first half of 2013, due primarily to lower unrealized gains on the assets supporting the deferred compensation plans.
Income Tax Expense
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
For the Six Months Ended June 30,
|
|
(Millions of Dollars)
|
2014
|
|
2013
|
|
Increase
|
|
Percent
|
|
|
Income Tax Expense
|
$
|
79.7
|
|
$
|
68.9
|
|
$
|
10.8
|
|
15.7
|
%
|
Income Tax Expense increased in the first half of 2014, as compared to the same period in 2013, due primarily to higher pre-tax earnings ($11.6 million) and higher state taxes ($3.5 million), partially offset by the tax benefit impact from the FERC ROE orders issued in the second quarter of 2014 ($4.1 million).
EARNINGS SUMMARY
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
For the Six Months Ended June 30,
|
|
|
(Millions of Dollars)
|
2014
|
|
2013
|
|
Increase
|
|
Percent
|
|
|
Net Income
|
$
|
118.2
|
|
$
|
106.2
|
|
$
|
12.0
|
|
11.3
|
%
|
In the first half of 2014, NSTAR Electric's earnings increased, as compared to the same period in 2013, due primarily to lower operations and maintenance expenses attributed to lower employee costs, benefit costs and lower storm costs. Partially offsetting these favorable earnings impacts were the establishment of a $6.1 million after-tax reserve related to the June 2014 FERC ROE orders and higher depreciation and property tax expenses.
LIQUIDITY
NSTAR Electric had cash flows provided by operating activities of $387.7 million in the first half of 2014, compared with $91.6 million in the first half of 2013. The increase in operating cash flows was due primarily to the absence of cash disbursements for major storm restoration costs associated with the February 2013 blizzard, the timing of collections of accounts receivables from affiliated companies, $29.1 million in DOE Phase II Damages proceeds received on June 1, 2014 from the Yankee Companies associated with the spent nuclear fuel litigation, a decrease in income tax payments in the first half of 2014, as compared to the first half of 2013, and the absence of Pension Plan cash contributions in the first half of 2014, as compared to the first half of 2013. These favorable cash flow impacts were partially offset by the absence of costs recovered in rates related to the RRBs that were fully amortized in the first quarter of 2013.
Effective July 23, 2014, NSTAR Electric amended its $450 million revolving credit facility to extend the expiration date an additional year to September 6, 2019. This facility serves to backstop NSTAR Electric's existing $450 million commercial paper program. As of June 30, 2014 and December 31, 2013, NSTAR Electric had $194.5 million and $103.5 million, respectively, in short-term borrowings outstanding under its commercial paper program, leaving $255.5 million and $346.5 million, respectively, of available borrowing capacity. The weighted-average interest rate on these borrowings as of June 30, 2014 and December 31, 2013 was 0.16 percent and 0.13 percent, respectively, which is generally based on A2/P1 rated commercial paper.
55
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 for the condensed consolidated statements of income for PSNH included in this Quarterly Report on Form 10-Q for the six months ended June 30, 2014 and 2013:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating Revenues and Expenses
|
|
|
|
|
|
|
For the Six Months Ended June 30,
|
|
|
|
|
|
|
|
|
|
|
|
|
Increase/
|
|
|
|
|
|
(Millions of Dollars)
|
2014
|
|
2013
|
|
(Decrease)
|
|
Percent
|
|
|
|
Operating Revenues
|
$
|
511.5
|
|
$
|
489.9
|
|
$
|
21.6
|
|
4.4
|
%
|
|
|
Operating Expenses:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Purchased Power, Fuel and Transmission
|
|
183.6
|
|
|
151.1
|
|
|
32.5
|
|
21.5
|
|
|
|
|
Operations and Maintenance
|
|
132.5
|
|
|
122.1
|
|
|
10.4
|
|
8.5
|
|
|
|
|
Depreciation
|
|
48.7
|
|
|
45.5
|
|
|
3.2
|
|
7.0
|
|
|
|
|
Amortization of Regulatory Assets/(Liabilities), Net
|
|
(7.8)
|
|
|
(2.0)
|
|
|
(5.8)
|
|
(a)
|
|
|
|
|
Amortization of Rate Reduction Bonds
|
|
-
|
|
|
19.8
|
|
|
(19.8)
|
|
(100.0)
|
|
|
|
|
Energy Efficiency Programs
|
|
7.1
|
|
|
7.1
|
|
|
-
|
|
-
|
|
|
|
|
Taxes Other Than Income Taxes
|
|
34.3
|
|
|
33.9
|
|
|
0.4
|
|
1.2
|
|
|
|
|
|
Total Operating Expenses
|
|
398.4
|
|
|
377.5
|
|
|
20.9
|
|
5.5
|
|
|
|
Operating Income
|
$
|
113.1
|
|
$
|
112.4
|
|
$
|
0.7
|
|
0.6
|
%
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(a) Percent greater than 100 percent not shown as it is not meaningful.
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating Revenues
|
|
|
|
|
|
|
|
|
|
PSNH's retail sales were as follows:
|
|
|
|
|
|
|
|
|
|
|
|
For the Six Months Ended June 30,
|
|
|
|
|
2014
|
|
2013
|
|
Increase
|
|
Percent
|
|
|
Retail Sales in GWh
|
3,909
|
|
3,837
|
|
72
|
|
1.9
|
%
|
PSNH's Operating Revenues increased in the first half of 2014, as compared to the first half of 2013, due primarily to an increase of 1.9 percent in retail sales as a result of the colder weather in the first quarter of 2014, as compared to the same period in 2013. The average daily temperature in New Hampshire in the first quarter of 2014 was over five degrees lower than the first quarter of 2013. In addition, revenues increased due to the overall impact of higher costs associated with the procurement of energy supply. The energy supply costs were impacted by higher natural gas transportation costs, which had an adverse impact on the cost of purchased electric energy for our retail customers. Fluctuations in energy supply costs are recovered from customers in rates and therefore have no impact on earnings. Also reflected in the revenue increase were increases of $6.4 million related to NHPUC-approved distribution rate increases effective July 1, 2013 and increases in transmission revenues as a result of the recovery of higher transmission expenses including ongoing investments in our transmission infrastructure, partially offset by the impact of the reserve recorded during the second quarter of 2014 as a result of the FERC ROE orders issued in the FERC base ROE complaints. For further information, see "FERC Regulatory Issues - FERC Base ROE Complaints"
in this
Management's Discussion and Analysis.
Purchased Power, Fuel and Transmission
increased in the first half of 2014, as compared to the first half of 2013, due primarily to the following:
|
|
|
|
(Millions of Dollars)
|
Increase/(Decrease)
|
|
Generation Fuel Costs
|
$
|
35.2
|
|
Renewable Energy Costs
|
|
9.9
|
|
Transmission Costs
|
|
4.7
|
|
Purchased Power Costs
|
|
(19.2)
|
|
Other
|
|
1.9
|
|
|
$
|
32.5
|
The increase in generation fuel costs was due primarily to an increase in the amount of electricity generated by PSNH facilities. The increase in renewable energy costs was a result of lower regional greenhouse gas initiative auction proceeds, partially offset by lower renewable energy requirements set by the NHPUC. The increase in transmission costs was as a 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
.
The decrease in purchased power costs was a result of additional customer migration to third party suppliers. Purchased Power, Fuel and Transmission costs are included in NHPUC-approved tracking mechanisms and do not impact earnings.
Operations and Maintenance
expense includes costs that are recovered in rates through cost tracking mechanisms, which have no earnings impact (tracked costs), and costs that are recovered through base electric distribution rates (and therefore impact earnings). Operations and Maintenance increased in the first half of 2014, as compared to the first half of 2013, driven by an $8 million increase in costs that have no earnings impact (primarily attributable to higher operations and maintenance costs at the generation business of $5.1 million due to the timing of planned outages and higher bad debt expense of $1 million, partially offset by lower employee costs, including pension and benefit related costs, of $2.4 million). Additionally, there was an increase in costs that impact earnings of $2.4 million.
Depreciation
increased in the first half of 2014, as compared to the first half of 2013, due primarily to higher utility plant balances resulting from completed construction projects placed into service.
Amortization of Regulatory Assets/(Liabilities), Net
increased in the first half of 2014, as compared to the first half of 2013, due primarily to increases in the stranded cost recovery charge, default energy service, and other amortizations of $1.7 million, $0.2 million, and $3.9 million, respectively.
56
Amortization of Rate Reduction Bonds
decreased in the first half of 2014, as compared to the first half of 2013, due to the maturity of the RRBs in May 2013.
Income Tax Expense
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
For the Six Months Ended June 30,
|
|
(Millions of Dollars)
|
2014
|
|
2013
|
|
Change
|
|
Percent
|
|
|
Income Tax Expense
|
$
|
34.6
|
|
$
|
34.6
|
|
$
|
-
|
|
-
|
%
|
Income Tax Expense was relatively flat in the first half of 2014, as compared to the first half of 2013, due primarily to higher pre-tax earnings ($1.5 million), offset by the tax benefit impact from the FERC ROE orders issued in the second quarter of 2014 ($1.5 million).
EARNINGS SUMMARY
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
For the Six Months Ended June 30,
|
|
|
(Millions of Dollars)
|
2014
|
|
2013
|
|
Increase
|
|
Percent
|
|
|
Net Income
|
$
|
56.7
|
|
$
|
56.2
|
|
$
|
0.5
|
|
0.1
|
%
|
In the first half of 2014, PSNH's earnings increased, as compared to the same period in 2013, due primarily to higher distribution retail revenues, which were favorably impacted by the PSNH annualized distribution rate increases effective July 1, 2013, and higher retail electric sales. Partially offsetting these favorable earnings impacts were the establishment of a $2 million after-tax reserve related to the June 2014 FERC ROE orders, and higher depreciation expense.
LIQUIDITY
PSNH had cash flows provided by operating activities of $142.4 million in the first half of 2014, compared with $138.7 million in the first half of 2013. The improved cash flows were due to $13.1 million in DOE Phase II Damages proceeds received on June 1, 2014 from the Yankee Companies associated with the spent nuclear fuel litigation, the absence of approximately $45 million in NUSCO Pension Plan cash contributions in the first half of 2014, and the favorable impact of the 2010 rate case settlement related to the additional increase to annualized rates that was effective July 1, 2013
.
These favorable cash flow impacts were partially offset by income tax payments of $28.8 million in the first half of 2014, compared with income tax refunds of $12.1 million in the first half of 2013, and the absence of costs recovered in rates related to the RRBs that were fully amortized in the second quarter of 2013.
57
RESULTS OF OPERATIONS – WESTERN MASSACHUSETTS ELECTRIC COMPANY
The following provides the amounts and variances in operating revenues and expense line items for the condensed statements of income for WMECO included in this Quarterly Report on Form 10-Q for the six months ended June 30, 2014 and 2013:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating Revenues and Expenses
|
|
|
|
For the Six Months Ended June 30,
|
|
|
|
|
|
|
Increase/
|
|
|
|
|
(Millions of Dollars)
|
2014
|
|
2013
|
|
(Decrease)
|
|
Percent
|
|
|
Operating Revenues
|
$
|
245.7
|
|
$
|
240.0
|
|
$
|
5.7
|
|
2.4
|
%
|
|
Operating Expenses:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Purchased Power and Transmission
|
|
87.1
|
|
|
72.3
|
|
|
14.8
|
|
20.5
|
|
|
|
Operations and Maintenance
|
|
46.3
|
|
|
44.1
|
|
|
2.2
|
|
5.0
|
|
|
|
Depreciation
|
|
20.6
|
|
|
18.3
|
|
|
2.3
|
|
12.6
|
|
|
|
Amortization of Regulatory Assets, Net
|
|
0.7
|
|
|
0.8
|
|
|
(0.1)
|
|
(12.5)
|
|
|
|
Amortization of Rate Reduction Bonds
|
|
-
|
|
|
7.8
|
|
|
(7.8)
|
|
(100.0)
|
|
|
|
Energy Efficiency Programs
|
|
22.1
|
|
|
16.2
|
|
|
5.9
|
|
36.4
|
|
|
|
Taxes Other Than Income Taxes
|
|
16.5
|
|
|
12.5
|
|
|
4.0
|
|
32.0
|
|
|
|
|
Total Operating Expenses
|
|
193.3
|
|
|
172.0
|
|
|
21.3
|
|
12.4
|
|
|
Operating Income
|
$
|
52.4
|
|
$
|
68.0
|
|
$
|
(15.6)
|
|
(22.9)
|
%
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating Revenues
|
|
|
|
|
|
|
|
|
|
|
WMECO's retail sales were as follows:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
For the Six Months Ended June 30,
|
|
|
|
|
|
2014
|
|
2013
|
|
Decrease
|
|
Percent
|
|
|
Retail Sales in GWh
|
|
1,793
|
|
1,798
|
|
(5)
|
|
(0.2)
|
%
|
WMECO's Operating Revenues increased in the first half of 2014, as compared to the first half of 2013, due primarily to a $3.9 million increase in revenues that impacts earnings due to the reversal of a previously established wholesale billing adjustment. The remaining increase primarily reflects a higher level of recovery related to WMECO's energy supply and energy efficiency programs. These revenues are fully reconciled to the related costs. Therefore this increase in revenues had no material impact on earnings. Partially offsetting this increase was the impact of the reserve recorded during the second quarter of 2014 as a result of the FERC ROE orders issued in the FERC base ROE complaints. For further information, see "FERC Regulatory Issues - FERC Base ROE Complaints"
in this
Management's Discussion and Analysis.
Base distribution revenues were relatively flat in the first half of 2014, as compared to the same period in 2013. Fluctuations in WMECO's kWh sales have no impact on earnings, as its revenues are decoupled from sales volumes and changes in revenues are primarily related to changes in its cost tracking mechanisms.
Purchased Power and Transmission
increased in the first half of 2014, as compared to the first half of 2013, due primarily to an increase in supplier contract prices and an increase in customers returning to default service from third party suppliers ($13.9 million)
and an increase in transmission costs ($5.7 million) as a 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. Partially offsetting this increase was the impact of the change in deferred fuel costs ($2.4 million) due primarily to higher average electric supply prices, as compared to the prices projected when basic service rates were set. Purchased Power and Transmission costs are included in DPU-approved tracking mechanisms and do not impact earnings.
Operations and Maintenance
expense includes costs that are recovered in rates through cost tracking mechanisms, which have no earnings impact (tracked costs), and costs that are recovered through base electric distribution rates (and therefore impact earnings). Operations and Maintenance increased in the first half of 2014, as compared to the first half of 2013, driven by a $2.5 million increase in costs that impact earnings (primarily attributable to an increase in workers' compensation claims of $1.9 million and higher bad debt expense of $0.8 million). Partially offsetting this increase was a decrease in costs that have no earnings impact of $0.3 million.
Depreciation
increased in the first half of 2014, as compared to the first half of 2013, due primarily to higher utility plant balances resulting from completed construction projects placed into service.
Amortization of Rate Reduction Bonds
decreased in the first half of 2014, as compared to the first half of 2013, due to the maturity of the RRBs in June 2013.
Energy Efficiency Programs
increased in the first half of 2014, as compared to the first half of 2013, due primarily to an increase in energy efficiency costs in accordance with the three-year program guidelines established by the DPU. All costs are fully recovered through DPU-approved tracking mechanisms and therefore do not impact earnings.
Taxes Other Than Income Taxes
increased in the first half of 2014, as compared to the first half of 2013, due primarily to an increase in property taxes as a result of both an increase in utility plant balances and property tax rates.
Income Tax Expense
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
For the Six Months Ended June 30,
|
|
(Millions of Dollars)
|
2014
|
|
2013
|
|
Decrease
|
|
Percent
|
|
|
Income Tax Expense
|
$
|
16.1
|
|
$
|
21.8
|
|
$
|
(5.7)
|
|
(26.1)
|
%
|
Income Tax Expense decreased in the first half of 2014, as compared to the first half of 2013, due primarily to the tax benefit impact from the FERC ROE orders issued in the second quarter of 2014 ($3.6 million) and lower pre-tax earnings ($2.3 million).
58
EARNINGS SUMMARY
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
For the Six Months Ended June 30,
|
|
(Millions of Dollars)
|
2014
|
|
2013
|
|
Decrease
|
|
Percent
|
|
|
Net Income
|
$
|
25.1
|
|
$
|
35.0
|
|
$
|
(9.9)
|
|
(28.3)
|
%
|
In the first half of 2014, WMECO's earnings decreased, as compared to the same period in 2013, due primarily to the establishment of a $5.5 million after-tax reserve related to the June 2014 FERC ROE orders, an increase in workers' compensation claims, and higher depreciation and property tax expense. Partially offsetting these unfavorable earnings impacts were an increase in generation earnings and a decrease in other interest expense.
LIQUIDITY
WMECO had cash flows provided by operating activities of $96.6 million in the first half of 2014, compared with $119.3 million in the first half of 2013. The decrease in operating cash flows was due primarily to income tax payments of $16.9 million in the first half of 2014, compared with income tax refunds of $32.4 million in the first half of 2013 and the absence of costs recovered in rates related to the RRBs that were fully amortized in the second quarter of 2013, partially offset by the receipt of $18.1 million in DOE Phase II Damages proceeds received on June 1, 2014 from the Yankee Companies associated with the spent nuclear fuel litigation and an increase in regulatory overrecoveries.
59
ITEM 3.
QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
Market Risk Information
Commodity Price Risk Management:
Our Regulated companies enter into energy contracts to serve our customers and the economic impacts of those contracts are passed on to our customers. Accordingly, the Regulated companies have no exposure to loss of future earnings or fair values due to these market risk-sensitive instruments. NU's Energy Supply Risk Committee, comprised of senior officers, reviews and approves all large scale energy related transactions entered into by its Regulated companies.
Other Risk Management Activities
Interest Rate Risk Management:
We manage our interest rate risk exposure in accordance with our written policies and procedures by maintaining a mix of fixed and variable rate long-term debt.
Credit Risk Management:
Credit risk relates to the risk of loss that we would incur as a result of non-performance by counterparties pursuant to the terms of our contractual obligations. We serve a wide variety of customers and transact with suppliers that include IPPs, industrial companies, gas and electric utilities, oil and gas producers, financial institutions, and other energy marketers. Margin accounts exist within this diverse group, and we realize interest receipts and payments related to balances outstanding in these margin accounts. This wide customer and supplier mix generates a need for a variety of contractual structures, products and terms that, in turn, require us to manage the portfolio of market risk inherent in those transactions in a manner consistent with the parameters established by our risk management process.
If the respective unsecured debt ratings of NU or its subsidiaries were reduced to below investment grade by either Moody's or S&P, certain of NU's contracts would require additional collateral in the form of cash to be provided to counterparties and independent system operators. NU would have been and remains able to provide that collateral.
For further information on cash collateral deposited and posted with counterparties as well as any cash collateral netted against the fair value of the related derivative contracts, see Note 4, "Derivative Instruments," to the financial statements.
We have provided additional disclosures regarding interest rate risk management and credit risk management in Part II, Item 7A, "Quantitative and Qualitative Disclosures about Market Risk," in NU's 2013 Form 10-K, which is incorporated herein by reference. There have been no additional risks identified and no material changes with regard to the items previously disclosed in the NU 2013 Form 10-K.
ITEM 4.
CONTROLS AND PROCEDURES
Management, on behalf of NU, CL&P, NSTAR Electric, PSNH and WMECO, evaluated the design and operation of the disclosure controls and procedures as of June 30, 2014 to determine whether they are effective in ensuring that the disclosure of required information is made timely and in accordance with the Securities Exchange Act of 1934 and the rules and regulations of the SEC. This evaluation was made under management's supervision and with management's participation, including the principal executive officers and principal financial officer as of the end of the period covered by this Quarterly Report on Form 10-Q. There are inherent limitations of disclosure controls and procedures, including the possibility of human error and the circumventing or overriding of the controls and procedures. Accordingly, even effective disclosure controls and procedures can only provide reasonable assurance of achieving their control objectives. The principal executive officers and principal financial officer have concluded, based on their review, that the disclosure controls and procedures of NU, CL&P, NSTAR Electric, PSNH and WMECO are effective to ensure that information required to be disclosed by us in reports filed under the Securities Exchange Act of 1934 (i) is recorded, processed, summarized, and reported within the time periods specified in SEC rules and regulations and (ii) is accumulated and communicated to management, including the principal executive officers and principal financial officer, as appropriate to allow timely decisions regarding required disclosures.
There have been no changes in internal controls over financial reporting for NU, CL&P, NSTAR Electric, PSNH and WMECO during the quarter ended June 30, 2014 that have materially affected, or are reasonably likely to materially affect, internal controls over financial reporting.
60
PART II. OTHER INFORMATION
ITEM 1.
LEGAL PROCEEDINGS
We are parties to various legal proceedings. We have identified these legal proceedings in Part I, Item 3, "Legal Proceedings," and elsewhere in our 2013 Form 10-K, which disclosures are incorporated herein by reference. There have been no additional material legal proceedings identified and no material changes with regard to the legal proceedings previously disclosed in our 2013 Form 10-K.
ITEM 1A.
RISK FACTORS
We are subject to a variety of significant risks in addition to the matters set forth under "Forward-Looking Statements," in Item 2, "Management's Discussion and Analysis of Financial Condition and Results of Operations," of this Quarterly Report on Form 10-Q. We have identified a number of these risk factors in Part I, Item 1A, "Risk Factors," in our 2013 Form 10-K, which risk factors are incorporated herein by reference. These risk factors should be considered carefully in evaluating our risk profile. There have been no additional risk factors identified and no material changes with regard to the risk factors previously disclosed in our 2013 Form 10-K.
ITEM 2.
UNREGISTERED SALES OF EQUITY SECURITIES AND USE OF PROCEEDS
The following table discloses purchases of our common shares made by us or on our behalf for the periods shown below. The common shares purchased consist of open market purchases made by the Company or an independent agent. These share transactions related to the Company's Long-Term Incentive Plans.
|
|
|
|
|
|
|
|
|
|
|
Period
|
|
Total Number
of Shares
Purchased
|
|
|
Average
Price
Paid per
Share
|
Total Number of
Shares Purchased
as Part of Publicly
Announced Plans or
Programs
|
Approximate Dollar
Value of Shares that
May Yet Be Purchased
Under the Plans and
Programs (at month end)
|
|
|
April 1 – April 30, 2014
|
|
-
|
|
$
|
-
|
-
|
-
|
|
|
May 1 – May 31, 2014
|
|
-
|
|
|
-
|
-
|
-
|
|
|
June 1 – June 30, 2014
|
|
208,608
|
|
|
46.93
|
-
|
-
|
|
|
Total
|
|
208,608
|
|
$
|
46.93
|
-
|
-
|
61
ITEM 6.
EXHIBITS
Each document described below is filed herewith, unless designated with an asterisk (*), which exhibits are incorporated by reference by the registrant under whose name the exhibit appears.
|
|
|
|
Exhibit No.
|
|
Description
|
|
|
|
|
|
Listing of Exhibits (NU)
|
|
|
|
|
|
12
|
|
Ratio of Earnings to Fixed Charges
|
|
|
|
|
|
31
|
|
Certification of Thomas J. May, Chairman, President and Chief Executive Officer of NU, required by Rule 13a - 14(a)/15d - 14(a) of the Securities Exchange Act of 1934, as amended, as adopted pursuant to Section 302 of the Sarbanes-Oxley Act of 2002, dated August 1, 2014
|
|
|
|
|
|
31.1
|
|
Certification of James J. Judge, Executive Vice President and Chief Financial Officer of NU, required by Rule 13a - 14(a)/15d - 14(a) of the Securities Exchange Act of 1934, as amended, as adopted pursuant to Section 302 of the Sarbanes-Oxley Act of 2002, dated August 1, 2014
|
|
|
|
|
|
32
|
|
Certification of Thomas J. May, Chairman, President and Chief Executive Officer of NU, and James J. Judge, Executive Vice President and Chief Financial Officer of NU, pursuant to 18 U.S.C. Section 1350 as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, dated August 1, 2014
|
|
|
|
|
|
Listing of Exhibits (CL&P)
|
|
|
|
|
|
*4.1
|
|
Supplemental Indenture (2014 Series A Bond) between CL&P and Deutsche Bank Trust Company Americas, as Trustee dated as of April 1, 2014 (Exhibit 4.1, CL&P Current Report on Form 8-K filed April 29, 2014, File No. 000-00404)
|
|
|
|
|
|
12
|
|
Ratio of Earnings to Fixed Charges
|
|
|
|
|
|
31
|
|
Certification of Leon J. Olivier, Chief Executive Officer of CL&P, required by Rule 13a - 14(a)/15d - 14(a) of the Securities Exchange Act of 1934, as amended, as adopted pursuant to Section 302 of the Sarbanes-Oxley Act of 2002, dated August 1, 2014
|
|
|
|
|
|
31.1
|
|
Certification of James J. Judge, Executive Vice President and Chief Financial Officer of CL&P, required by Rule 13a - 14(a)/15d - 14(a) of the Securities Exchange Act of 1934, as amended, as adopted pursuant to Section 302 of the Sarbanes-Oxley Act of 2002, dated August 1, 2014
|
|
|
|
|
|
32
|
|
Certification of Leon J. Olivier, Chief Executive Officer of CL&P, and James J. Judge, Executive Vice President and Chief Financial Officer of CL&P, pursuant to 18 U.S.C. Section 1350 as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, dated August 1, 2014
|
|
|
|
|
|
Listing of Exhibits (NSTAR Electric)
|
|
|
|
|
|
12
|
|
Ratio of Earnings to Fixed Charges
|
|
|
|
|
|
31
|
|
Certification of Leon J. Olivier, Chief Executive Officer of NSTAR Electric, required by Rule 13a - 14(a)/15d - 14(a) of the Securities Exchange Act of 1934, as amended, as adopted pursuant to Section 302 of the Sarbanes-Oxley Act of 2002, dated August 1, 2014
|
|
|
|
|
|
31.1
|
|
Certification of James J. Judge, Executive Vice President and Chief Financial Officer of NSTAR Electric, required by Rule 13a - 14(a)/15d - 14(a) of the Securities Exchange Act of 1934, as amended, as adopted pursuant to Section 302 of the Sarbanes-Oxley Act of 2002, dated August 1, 2014
|
|
|
|
|
|
32
|
|
Certification of Leon J. Olivier, Chief Executive Officer of NSTAR Electric, and James J. Judge, Executive Vice President and Chief Financial Officer of NSTAR Electric, pursuant to 18 U.S.C. Section 1350 as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, dated August 1, 2014
|
62
|
|
|
|
Listing of Exhibits (PSNH)
|
|
|
|
|
|
12
|
|
Ratio of Earnings to Fixed Charges
|
|
|
|
|
|
31
|
|
Certification of Leon J. Olivier, Chief Executive Officer of PSNH, required by Rule 13a - 14(a)/15d - 14(a) of the Securities Exchange Act of 1934, as amended, as adopted pursuant to Section 302 of the Sarbanes-Oxley Act of 2002, dated August 1, 2014
|
|
|
|
|
|
31.1
|
|
Certification of James J. Judge, Executive Vice President and Chief Financial Officer of PSNH, required by Rule 13a - 14(a)/15d - 14(a) of the Securities Exchange Act of 1934, as amended, as adopted pursuant to Section 302 of the Sarbanes-Oxley Act of 2002, dated August 1, 2014
|
|
|
|
|
|
32
|
|
Certification of Leon J. Olivier, Chief Executive Officer of PSNH, and James J. Judge, Executive Vice President and Chief Financial Officer of PSNH, pursuant to 18 U.S.C. Section 1350 as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, dated August 1, 2014
|
|
|
|
|
|
Listing of Exhibits (WMECO)
|
|
|
|
|
|
12
|
|
Ratio of Earnings to Fixed Charges
|
|
|
|
|
|
31
|
|
Certification of Leon J. Olivier, Chief Executive Officer of WMECO, required by Rule 13a - 14(a)/15d - 14(a) of the Securities Exchange Act of 1934, as amended, as adopted pursuant to Section 302 of the Sarbanes-Oxley Act of 2002, dated August 1, 2014
|
|
|
|
|
|
31.1
|
|
Certification of James J. Judge, Executive Vice President and Chief Financial Officer of WMECO, required by Rule 13a - 14(a)/15d - 14(a) of the Securities Exchange Act of 1934, as amended, as adopted pursuant to Section 302 of the Sarbanes-Oxley Act of 2002, dated August 1, 2014
|
|
|
|
|
|
32
|
|
Certification of Leon J. Olivier, Chief Executive Officer of WMECO, and James J. Judge, Executive Vice President and Chief Financial Officer of WMECO, pursuant to 18 U.S.C. Section 1350 as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, dated August 1, 2014
|
Listing of Exhibits (NU, CL&P, NSTAR Electric, PSNH, WMECO)
|
|
|
101.INS
|
XBRL Instance Document
|
|
|
|
|
101.SCH
|
XBRL Taxonomy Extension Schema
|
|
|
|
|
101.CAL
|
XBRL Taxonomy Extension Calculation
|
|
|
|
|
101.DEF
|
XBRL Taxonomy Extension Definition
|
|
|
|
|
101.LAB
|
XBRL Taxonomy Extension Labels
|
|
|
|
|
101.PRE
|
XBRL Taxonomy Extension Presentation
|
63
SIGNATURE
Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the Registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
NORTHEAST UTILITIES
|
|
|
|
|
|
|
August 1, 2014
|
|
By:
|
/s/
Jay S. Buth
|
|
|
|
|
Jay S. Buth
|
|
|
|
|
Vice President, Controller and Chief Accounting Officer
|
|
|
|
|
|
|
|
|
|
|
SIGNATURE
Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the Registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
THE CONNECTICUT LIGHT AND POWER COMPANY
|
|
|
|
|
|
|
August 1, 2014
|
|
By:
|
/s/
Jay S. Buth
|
|
|
|
|
Jay S. Buth
|
|
|
|
|
Vice President, Controller and Chief Accounting Officer
|
|
|
|
|
|
|
|
|
|
|
SIGNATURE
Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the Registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
NSTAR ELECTRIC COMPANY
|
|
|
|
|
|
|
August 1, 2014
|
|
By:
|
/s/
Jay S. Buth
|
|
|
|
|
Jay S. Buth
|
|
|
|
|
Vice President, Controller and Chief Accounting Officer
|
|
|
|
|
|
|
|
|
|
|
64
SIGNATURE
Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the Registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
PUBLIC SERVICE COMPANY OF NEW HAMPSHIRE
|
|
|
|
|
|
|
August 1, 2014
|
|
By:
|
/s/
Jay S. Buth
|
|
|
|
|
Jay S. Buth
|
|
|
|
|
Vice President, Controller and Chief Accounting Officer
|
|
|
|
|
|
|
|
|
|
|
SIGNATURE
Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the Registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
WESTERN MASSACHUSETTS ELECTRIC COMPANY
|
|
|
|
|
|
|
August 1, 2014
|
|
By:
|
/s/
Jay S. Buth
|
|
|
|
|
Jay S. Buth
|
|
|
|
|
Vice President, Controller and Chief Accounting Officer
|
|
|
|
|
|
|
|
|
|
|
65