UNITED STATES SECURITIES AND EXCHANGE COMMISSIONWASHINGTON, D.C. 20549FORM 10-Q
[X]
QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
For the Quarterly Period Ended June 30, 2013
OR
[ ]
TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
For the transition period from ____________ to ____________
CommissionFile Number
Registrant; State of Incorporation;Address; and Telephone Number
I.R.S. EmployerIdentification No.
1-5324
NORTHEAST UTILITIES(a Massachusetts voluntary association)One Federal StreetBuilding 111-4Springfield, Massachusetts 01105Telephone: (413) 785-5871
04-2147929
0-00404
THE CONNECTICUT LIGHT AND POWER COMPANY(a Connecticut corporation)107 Selden StreetBerlin, Connecticut 06037-1616 Telephone: (860) 665-5000
06-0303850
1-02301
NSTAR ELECTRIC COMPANY(a Massachusetts corporation)800 Boylston StreetBoston, Massachusetts 02199Telephone: (617) 424-2000
04-1278810
1-6392
PUBLIC SERVICE COMPANY OF NEW HAMPSHIRE (a New Hampshire corporation)Energy Park780 North Commercial StreetManchester, New Hampshire 03101-1134Telephone: (603) 669-4000
02-0181050
0-7624
WESTERN MASSACHUSETTS ELECTRIC COMPANY(a Massachusetts corporation)One Federal StreetBuilding 111-4Springfield, Massachusetts 01105Telephone: (413) 785-5871
04-1961130
Indicate by check mark whether the registrants (1) have filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrants were required to file such reports), and (2) have been subject to such filing requirements for the past 90 days.
Yes
No
ü
Indicate by check mark whether the registrants have submitted electronically and posted on its corporate Web sites, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files).
Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, or a non-accelerated filer. See definition of "accelerated filer and large accelerated filer" in Rule 12b-2 of the Exchange Act. (Check one):
LargeAccelerated Filer
AcceleratedFiler
Non-acceleratedFiler
Northeast Utilities
The Connecticut Light and Power Company
NSTAR Electric Company
Public Service Company of New Hampshire
Western Massachusetts Electric Company
Indicate by check mark whether the registrants are shell companies (as defined in Rule 12b-2 of the Exchange Act):
Indicate the number of shares outstanding of each of the issuers' classes of common stock, as of the latest practicable date:
Company - Class of Stock
Outstanding as of July 31, 2013
Northeast UtilitiesCommon shares, $5.00 par value
314,751,609 shares
The Connecticut Light and Power CompanyCommon stock, $10.00 par value
6,035,205 shares
NSTAR Electric CompanyCommon stock, $1.00 par value
100 shares
Public Service Company of New HampshireCommon stock, $1.00 par value
301 shares
Western Massachusetts Electric CompanyCommon stock, $25.00 par value
434,653 shares
Northeast Utilities, directly or indirectly, holds all of the 6,035,205 shares, 100 shares, 301 shares, and 434,653 shares of the outstanding common stock of The Connecticut Light and Power Company, NSTAR Electric Company, Public Service Company of New Hampshire and Western Massachusetts Electric Company, respectively.
NSTAR Electric Company, Public Service Company of New Hampshire and Western Massachusetts Electric Company each meet the conditions set forth in General Instructions H(1)(a) and (b) of Form 10-Q, and each is therefore filing this Form 10-Q with the reduced disclosure format specified in General Instruction H(2) of Form 10-Q.
GLOSSARY OF TERMS
The following is a glossary of abbreviations or acronyms that are found in this report.
CURRENT OR FORMER NU COMPANIES, SEGMENTS OR INVESTMENTS:
CL&P
CYAPC
Connecticut Yankee Atomic Power Company
Hopkinton
Hopkinton LNG Corp., a wholly owned subsidiary of NSTAR LLC
HWP
HWP Company, formerly the Holyoke Water Power Company
MYAPC
Maine Yankee Atomic Power Company
NGS
Northeast Generation Services Company and subsidiaries
NPT
Northern Pass Transmission LLC
NSTAR
Parent Company of NSTAR Electric, NSTAR Gas and other subsidiaries (prior to the merger with NU); also the term used for NSTAR LLC and its subsidiaries
NSTAR Electric
NSTAR Electric & Gas
NSTAR Electric & Gas Corporation, a Northeast Utilities service company
NSTAR Gas
NSTAR Gas Company
NSTAR LLC
Post-merger parent company of NSTAR Electric, NSTAR Gas and other subsidiaries, and successor to NSTAR
NU Enterprises
NU Enterprises, Inc., the parent company of Select Energy, NGS, NGS Mechanical, Select Energy Contracting, Inc. and E.S. Boulos Company
NU or the Company
Northeast Utilities and subsidiaries
NU parent and other companies
NU parent and other companies is comprised of NU parent, NSTAR LLC, NSTAR Electric & Gas, NUSCO and other subsidiaries, including NU Enterprises, NSTAR Communications, Inc., HWP, RRR (a real estate subsidiary), the non-energy-related subsidiaries of Yankee (Yankee Energy Services Company and Yankee Energy Financial Services Company), and the consolidated operations of CYAPC and YAEC
NUSCO
Northeast Utilities Service Company
NUTV
NU Transmission Ventures, Inc., the parent company of NPT and Renewable Properties, Inc.
PSNH
Regulated companies
NU's Regulated companies, comprised of the electric distribution and transmission businesses of CL&P, NSTAR Electric, PSNH, and WMECO, the natural gas distribution businesses of Yankee Gas and NSTAR Gas, the generation activities of PSNH and WMECO, and NPT
RRR
The Rocky River Realty Company
Select Energy
Select Energy, Inc.
WMECO
YAEC
Yankee Atomic Electric Company
Yankee
Yankee Energy System, Inc.
Yankee Companies
CYAPC, YAEC and MYAPC
Yankee Gas
Yankee Gas Services Company
REGULATORS:
DEEP
Connecticut Department of Energy and Environmental Protection
DOE
U.S. Department of Energy
DOER
Massachusetts Department of Energy Resources
DPU
Massachusetts Department of Public Utilities
EPA
U.S. Environmental Protection Agency
FERC
Federal Energy Regulatory Commission
ISO-NE
ISO New England, Inc., the New England Independent System Operator
MA DEP
Massachusetts Department of Environmental Protection
NHPUC
New Hampshire Public Utilities Commission
PURA
Connecticut Public Utilities Regulatory Authority
SEC
U.S. Securities and Exchange Commission
SJC
Supreme Judicial Court of Massachusetts
OTHER:
AFUDC
Allowance For Funds Used During Construction
AOCI
Accumulated Other Comprehensive Income/(Loss)
ARO
Asset Retirement Obligation
C&LM
Conservation and Load Management
CfD
Contract for Differences
Clean Air Project
The construction of a wet flue gas desulphurization system, known as "scrubber technology," to reduce mercury emissions of the Merrimack coal-fired generation station in Bow, New Hampshire
CPSL
Capital Projects Scheduling List
CTA
Competitive Transition Assessment
CWIP
Construction work in progress
EPS
Earnings Per Share
ERISA
Employee Retirement Income Security Act of 1974
ES
Default Energy Service
ESOP
Employee Stock Ownership Plan
ESPP
Employee Share Purchase Plan
Fitch
Fitch Ratings
FMCC
Federally Mandated Congestion Charge
FTR
Financial Transmission Rights
GAAP
Accounting principles generally accepted in the United States of America
GSC
Generation Service Charge
GSRP
Greater Springfield Reliability Project
GWh
Gigawatt-Hours
HG&E
Holyoke Gas and Electric, a municipal department of the City of Holyoke, MA
HQ
Hydro-Québec, a corporation wholly owned by the Québec government, including its divisions that produce, transmit and distribute electricity in Québec, Canada
HVDC
High voltage direct current
Hydro Renewable Energy
Hydro Renewable Energy, Inc., a wholly owned subsidiary of Hydro-Québec
IPP
Independent Power Producers
ISO-NE Tariff
ISO-NE FERC Transmission, Markets and Services Tariff
kV
Kilovolt
kW
Kilowatt (equal to one thousand watts)
kWh
Kilowatt-Hours (the basic unit of electricity energy equal to one kilowatt of power supplied for one hour)
LNG
Liquefied natural gas
LOC
Letter of Credit
LRS
Supplier of last resort service
MGP
Manufactured Gas Plant
MMBtu
One million British thermal units
Moody's
Moody's Investors Services, Inc.
MW
Megawatt
MWh
Megawatt-Hours
NEEWS
New England East-West Solution
Northern Pass
The high voltage direct current transmission line project from Canada into New Hampshire
NU Money Pool
Northeast Utilities Money Pool
NU supplemental benefit trust
The NU Trust Under Supplemental Executive Retirement Plan
NU 2012 Form 10-K
The Northeast Utilities and Subsidiaries 2012 combined Annual Report on Form 10-K as filed with the SEC
PAM
Pension and PBOP Rate Adjustment Mechanism
PBOP
Postretirement Benefits Other Than Pension
PBOP Plan
Postretirement Benefits Other Than Pension Plan that provides certain retiree health care benefits, primarily medical and dental, and life insurance benefits
PCRBs
Pollution Control Revenue Bonds
Pension Plan
Single uniform noncontributory defined benefit retirement plan
PPA
Pension Protection Act
RECs
Renewable Energy Certificates
Regulatory ROE
The average cost of capital method for calculating the return on equity related to the distribution and generation business segment excluding the wholesale transmission segment
ROE
Return on Equity
RRB
Rate Reduction Bond or Rate Reduction Certificate
RSUs
Restricted share units
S&P
Standard & Poor's Financial Services LLC
SBC
Systems Benefits Charge
SCRC
Stranded Cost Recovery Charge
SERP
Supplemental Executive Retirement Plan
Settlement Agreements
The comprehensive settlement agreements reached by NU and NSTAR with the Massachusetts Attorney General and the DOER on February 15, 2012 related to the merger of NU and NSTAR (Massachusetts settlement agreements) and the comprehensive settlement agreement reached by NU and NSTAR with both the Connecticut Attorney General and the Connecticut Office of Consumer Counsel on March 13, 2012 related to the merger of NU and NSTAR (Connecticut settlement agreement).
SIP
Simplified Incentive Plan
SS
Standard service
TCAM
Transmission Cost Adjustment Mechanism
TSA
Transmission Service Agreement
UI
The United Illuminating Company
ii
NORTHEAST UTILITIES AND SUBSIDIARIESTHE CONNECTICUT LIGHT AND POWER COMPANYNSTAR ELECTRIC COMPANY AND SUBSIDIARYPUBLIC SERVICE COMPANY OF NEW HAMPSHIRE AND SUBSIDIARYWESTERN MASSACHUSETTS ELECTRIC COMPANY
TABLE OF CONTENTS
Page
PART I - FINANCIAL INFORMATION
ITEM 1 - Unaudited Condensed Consolidated Financial Statements for the Following Companies:
Northeast Utilities and Subsidiaries (Unaudited)
Condensed Consolidated Balance Sheets – June 30, 2013 and December 31, 2012
1
Condensed Consolidated Statements of Income – Three and Six Months Ended June 30, 2013 and 2012
3
Condensed Consolidated Statements of Comprehensive Income – Three and Six Months Ended June 30, 2013 and 2012
Condensed Consolidated Statements of Cash Flows – Six Months Ended June 30, 2013 and 2012
4
The Connecticut Light and Power Company (Unaudited)
Condensed Balance Sheets – June 30, 2013 and December 31, 2012
5
Condensed Statements of Income – Three and Six Months Ended June 30, 2013 and 2012
7
Condensed Statements of Comprehensive Income – Three and Six Months Ended June 30, 2013 and 2012
Condensed Statements of Cash Flows – Six Months Ended June 30, 2013 and 2012
8
NSTAR Electric Company and Subsidiary (Unaudited)
9
11
12
Public Service Company of New Hampshire and Subsidiary (Unaudited)
13
15
16
Western Massachusetts Electric Company (Unaudited)
17
19
20
Combined Notes to Condensed Financial Statements
21
ITEM 2 – Management’s Discussion and Analysis of Financial Condition and Results of Operations for the following companies:
Northeast Utilities and Subsidiaries
41
56
NSTAR Electric Company and Subsidiary
58
Public Service Company of New Hampshire and Subsidiary
60
62
ITEM 3 – Quantitative and Qualitative Disclosures About Market Risk
64
ITEM 4 – Controls and Procedures
PART II – OTHER INFORMATION
ITEM 1 – Legal Proceedings
65
ITEM 1A – Risk Factors
ITEM 2 – Unregistered Sales of Equity Securities and Use of Proceeds
ITEM 6 – Exhibits
66
SIGNATURES
68
iv
This Page Intentionally Left Blank
v
NORTHEAST UTILITIES AND SUBSIDIARIES
CONDENSED CONSOLIDATED BALANCE SHEETS
(Unaudited)
June 30,
December 31,
(Thousands of Dollars)
2013
2012
ASSETS
Current Assets:
Cash and Cash Equivalents
$
36,055
45,748
Receivables, Net
789,410
792,822
Unbilled Revenues
193,534
216,040
Fuel, Materials and Supplies
280,600
267,713
Regulatory Assets
577,010
705,025
Prepayments and Other Current Assets
174,484
199,947
Total Current Assets
2,051,093
2,227,295
Property, Plant and Equipment, Net
16,931,448
16,605,010
Deferred Debits and Other Assets:
4,817,305
5,132,411
Goodwill
3,519,401
Marketable Securities
501,876
400,329
Derivative Assets
89,309
90,612
Other Long-Term Assets
286,460
327,766
Total Deferred Debits and Other Assets
9,214,351
9,470,519
Total Assets
28,196,892
28,302,824
The accompanying notes are an integral part of these unaudited condensed consolidated financial statements.
LIABILITIES AND CAPITALIZATION
Current Liabilities:
Notes Payable
794,500
1,120,196
Long-Term Debt - Current Portion
888,346
763,338
Accounts Payable
532,036
764,350
Regulatory Liabilities
216,422
134,115
Other Current Liabilities
650,206
861,691
Total Current Liabilities
3,081,510
3,643,690
Rate Reduction Bonds
-
82,139
Deferred Credits and Other Liabilities:
Accumulated Deferred Income Taxes
3,745,144
3,463,347
511,737
540,162
Derivative Liabilities
788,929
882,654
Accrued Pension, SERP and PBOP
1,956,726
2,130,497
Other Long-Term Liabilities
899,270
967,561
Total Deferred Credits and Other Liabilities
7,901,806
7,984,221
Capitalization:
Long-Term Debt
7,651,396
7,200,156
Noncontrolling Interest - Preferred Stock of Subsidiaries
155,568
Equity:
Common Shareholders' Equity:
Common Shares
1,664,833
1,662,547
Capital Surplus, Paid In
6,176,366
6,183,267
Retained Earnings
1,969,755
1,802,714
Accumulated Other Comprehensive Loss
(69,469)
(72,854)
Treasury Stock
(334,873)
(338,624)
Common Shareholders' Equity
9,406,612
9,237,050
Total Capitalization
17,213,576
16,592,774
Total Liabilities and Capitalization
2
CONDENSED CONSOLIDATED STATEMENTS OF INCOME
For the Three Months Ended June 30,
For the Six Months Ended June 30,
(Thousands of Dollars, Except Share Information)
Operating Revenues
1,635,862
1,628,684
3,630,885
2,728,307
Operating Expenses:
Purchased Power, Fuel and Transmission
488,302
542,014
1,236,111
937,358
Operations and Maintenance
357,169
529,977
703,261
791,940
Depreciation
159,553
144,485
314,530
225,324
Amortization of Regulatory Assets, Net
54,574
25,590
108,623
31,016
Amortization of Rate Reduction Bonds
8,082
40,752
42,581
59,100
Energy Efficiency Programs
94,142
73,489
199,913
110,762
Taxes Other Than Income Taxes
123,464
112,862
256,345
198,899
Total Operating Expenses
1,285,286
1,469,169
2,861,364
2,354,399
Operating Income
350,576
159,515
769,521
373,908
Interest Expense:
Interest on Long-Term Debt
85,999
86,925
171,294
146,892
Interest on Rate Reduction Bonds
(189)
2,056
422
3,487
Other Interest
1,040
(8,610)
5,116
Interest Expense
86,850
89,047
163,106
155,495
Other Income, Net
4,944
1,806
12,710
10,580
Income Before Income Tax Expense
268,670
72,274
619,125
228,993
Income Tax Expense
95,606
26,055
216,093
82,019
Net Income
173,064
46,219
403,032
146,974
Net Income Attributable to Noncontrolling Interests
2,043
1,880
3,922
3,373
Net Income Attributable to Controlling Interest
171,021
44,339
399,110
143,601
Basic Earnings Per Common Share
0.54
0.15
1.27
0.60
Diluted Earnings Per Common Share
1.26
Dividends Declared Per Common Share
0.37
0.34
0.74
0.63
Weighted Average Common Shares Outstanding:
Basic
315,154,130
301,047,753
315,141,956
239,551,735
Diluted
315,962,619
301,816,884
315,982,578
240,127,169
CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME
Other Comprehensive Income, Net of Tax:
Qualified Cash Flow Hedging Instruments
514
516
1,030
939
Changes in Unrealized Gains/(Losses) on Other Securities
(591)
160
(772)
194
Changes in Funded Status of Pension, SERP and PBOP
Benefit Plans
1,506
1,759
3,127
3,166
Other Comprehensive Income, Net of Tax
1,429
2,435
3,385
4,299
Comprehensive Income Attributable to Noncontrolling Interests
(2,043)
(1,880)
(3,922)
(3,373)
Comprehensive Income Attributable to Controlling Interest
172,450
46,774
402,495
147,900
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS
Operating Activities:
Adjustments to Reconcile Net Income to Net Cash Flows
Provided by Operating Activities:
Deferred Income Taxes
256,294
59,509
Pension, SERP and PBOP Expense
97,671
97,378
Pension and PBOP Contributions
(122,826)
(164,294)
Regulatory Underrecoveries, Net
(4,793)
(54,491)
Other
19,932
19,520
Changes in Current Assets and Liabilities:
Receivables and Unbilled Revenues, Net
(101,229)
83,395
10,964
40,695
Taxes Receivable/Accrued, Net
(58,350)
17,709
(127,379)
(176,533)
Other Current Assets and Liabilities, Net
(70,026)
(64,899)
Net Cash Flows Provided by Operating Activities
769,024
320,403
Investing Activities:
Investments in Property, Plant and Equipment
(700,252)
(690,376)
Proceeds from Sales of Marketable Securities
342,251
132,580
Purchases of Marketable Securities
(424,096)
(143,225)
Decrease/(Increase) in Special Deposits
65,121
(11,852)
Other Investing Activities
(843)
23,126
Net Cash Flows Used in Investing Activities
(717,819)
(689,747)
Financing Activities:
Cash Dividends on Common Shares
(232,068)
(159,708)
Cash Dividends on Preferred Stock
(3,269)
(Decrease)/Increase in Short-Term Debt
(720,500)
558,500
Issuance of Long-Term Debt
1,350,000
300,000
Retirements of Long-Term Debt
(360,635)
(267,699)
Retirements of Rate Reduction Bonds
(82,139)
(36,439)
Other Financing Activities
(11,634)
(117)
Net Cash Flows (Used in)/Provided by Financing Activities
(60,898)
391,268
Net (Decrease)/Increase in Cash and Cash Equivalents
(9,693)
21,924
Cash and Cash Equivalents - Beginning of Period
6,559
Cash and Cash Equivalents - End of Period
28,483
THE CONNECTICUT LIGHT AND POWER COMPANY
CONDENSED BALANCE SHEETS
Cash
4,267
329,090
284,787
Accounts Receivable from Affiliated Companies
1,152
6,641
82,807
85,353
173,484
185,858
Materials and Supplies
60,382
64,603
16,578
26,413
667,760
653,656
6,251,908
6,152,959
2,055,333
2,158,363
92,777
86,498
2,237,419
2,335,473
9,157,087
9,142,088
The accompanying notes are an integral part of these unaudited condensed financial statements.
Notes Payable to Affiliated Companies
189,300
99,296
125,000
169,254
262,857
Accounts Payable to Affiliated Companies
46,042
52,326
Obligations to Third Party Suppliers
65,206
67,344
Accrued Taxes
44,658
60,109
64,007
32,119
95,183
96,931
100,044
125,662
898,694
921,644
1,451,287
1,336,105
99,863
124,319
777,144
865,571
297,059
304,696
162,495
197,434
2,787,848
2,828,125
2,740,819
2,737,790
Preferred Stock Not Subject to Mandatory Redemption
116,200
Common Stockholder's Equity:
Common Stock
60,352
1,641,065
1,640,149
913,713
839,628
(1,604)
(1,800)
Common Stockholder's Equity
2,613,526
2,538,329
5,470,545
5,392,319
6
CONDENSED STATEMENTS OF INCOME
569,329
562,141
1,193,425
1,154,106
Purchased Power and Transmission
184,854
196,806
414,113
417,697
123,760
205,471
232,655
338,373
45,122
41,519
87,570
82,588
463
3,263
11,249
11,257
20,854
20,995
43,668
42,968
57,506
53,706
117,697
108,978
432,559
521,760
906,952
1,001,861
136,770
40,381
286,473
152,245
32,683
31,696
65,318
63,218
1,301
2,075
(1,640)
4,060
33,984
33,771
63,678
67,278
2,897
447
7,084
5,747
105,683
7,057
229,879
90,714
37,826
124
77,014
29,796
67,857
6,933
152,865
60,918
CONDENSED STATEMENTS OF COMPREHENSIVE INCOME
111
222
Changes in Unrealized Gains/(Losses) on Other
Securities
(20)
(26)
91
116
196
228
Comprehensive Income
67,948
7,049
153,061
61,146
CONDENSED STATEMENTS OF CASH FLOWS
99,045
30,874
Pension, SERP and PBOP Expense, Net of PBOP Contributions
13,826
12,030
(36,902)
(19,596)
(13,476)
(12,078)
(33,976)
38,253
(14,081)
39,985
(95,487)
(170,151)
7,548
(26,579)
178,181
47,501
(184,875)
(220,712)
884
3,460
(183,991)
(217,252)
Cash Dividends on Common Stock
(76,000)
(66,991)
(2,779)
Issuance of Long Term Debt
400,000
Decrease in Notes Payable to Affiliates
(215,800)
(53,525)
(89,000)
299,000
(6,345)
(1,432)
Net Cash Flows Provided by Financing Activities
10,076
174,273
Net Increase in Cash
4,266
4,522
Cash - Beginning of Period
Cash - End of Period
4,523
NSTAR ELECTRIC COMPANY AND SUBSIDIARY
11,165
13,695
246,292
202,025
394,242
160,176
52,637
41,377
270,813
347,081
71,624
28,086
1,046,773
792,440
4,839,707
4,735,297
1,461,875
1,444,870
59,998
87,382
1,521,873
1,532,252
7,408,353
7,059,989
253,000
276,000
301,650
1,650
148,210
168,611
423,758
247,061
Accumulated Deferred Income Taxes - Current Portion
67,567
104,668
74,435
47,539
116,473
144,433
1,385,093
989,962
43,493
1,384,219
1,321,026
249,862
244,224
Accrued Pension
379,015
360,932
Payable to Affiliated Companies
64,752
70,221
151,033
183,190
2,228,881
2,179,593
1,499,339
1,600,911
43,000
992,625
1,259,415
1,210,405
2,252,040
2,203,030
3,794,379
3,846,941
10
570,420
534,626
1,162,677
1,091,102
189,843
180,502
403,896
399,512
87,891
109,038
180,192
257,218
45,441
42,669
90,882
85,198
53,554
22,144
100,548
46,024
22,581
15,054
45,161
50,679
35,487
102,382
82,391
30,491
28,308
62,665
59,169
457,899
440,729
955,619
974,673
112,521
93,897
207,058
116,429
19,809
22,279
39,401
44,567
927
399
2,253
(2,620)
(5,597)
(6,687)
(11,433)
17,189
17,609
33,113
35,387
375
1,149
1,227
95,707
76,294
175,094
82,269
37,676
30,812
68,941
32,847
58,031
45,482
106,153
49,422
Bad Debt Expense
11,307
46,726
28,750
(16,389)
Pension and PBOP Expense, Net of Pension Contributions
(5,139)
16,822
Regulatory (Under)/Over Recoveries, Net
(33,901)
16,371
(47,574)
(25,239)
(60,174)
(19,555)
3,294
10,387
(39,813)
(29,978)
(8,686)
(64,317)
Accounts Receivable from/Payable to Affiliates, Net
(57,369)
(26,121)
(11,702)
24,899
91,630
159,411
(207,380)
(189,229)
Decrease in Special Deposits
38,429
6,867
77
(168,874)
(181,987)
(56,000)
(135,400)
(1,143)
(980)
(Decrease)/Increase in Notes Payable
(23,000)
203,000
200,000
(1,650)
(825)
(43,493)
(43,548)
74,714
22,247
Net Decrease in Cash and Cash Equivalents
(2,530)
(329)
9,373
9,044
PUBLIC SERVICE COMPANY OF NEW HAMPSHIRE AND SUBSIDIARY
2,493
83,024
87,164
690
723
36,443
39,982
Taxes Receivable
2,500
17,177
108,634
95,345
55,836
62,882
19,035
22,205
306,227
327,971
2,383,167
2,352,515
311,442
351,059
58,992
83,052
370,434
434,111
3,059,828
3,114,597
182,200
63,300
57,657
62,864
17,111
21,337
21,913
23,002
Renewable Portfolio Standards Compliance Obligations
4,500
17,383
49,369
50,950
332,750
238,836
29,294
461,976
441,577
51,039
52,418
171,622
220,129
43,736
47,896
728,373
762,020
889,051
997,932
701,468
701,052
417,307
395,118
(9,121)
(9,655)
1,109,654
1,086,515
1,998,705
2,084,447
14
216,113
255,105
489,942
498,102
50,073
82,116
151,097
163,165
62,400
68,435
122,129
133,413
22,947
21,811
45,515
43,018
Amortization of Regulatory Assets/(Liabilities), Net
1,081
2,798
(1,969)
177
4,991
13,814
19,748
27,743
3,376
3,213
7,046
6,794
16,918
15,872
33,932
31,360
161,786
208,059
377,498
405,670
54,327
47,046
112,444
92,432
10,811
11,539
22,606
23,103
(239)
786
(154)
1,802
576
460
863
692
11,148
12,785
23,315
25,597
632
549
1,662
2,590
43,811
34,810
90,791
69,425
16,617
13,578
34,602
26,931
27,194
21,232
56,189
42,494
291
582
581
(34)
(45)
(3)
257
304
534
596
27,451
21,536
56,723
43,090
25,450
17,885
14,228
13,168
(45,721)
(91,990)
Regulatory Overrecoveries, Net
4,844
3,625
Amortization of Regulatory (Liabilities)/Assets, Net
3,123
16,543
597
3,283
(13,289)
17,365
21,584
(3,776)
26,159
(14,171)
(17,743)
(5,231)
138,715
70,133
(109,565)
(120,792)
Decrease in Notes Receivable from Affiliates
55,900
22,039
3,111
(13)
(66)
(87,539)
(61,847)
(34,000)
(58,783)
Retirements of Long-term Debt
(108,985)
Increase in Notes Payable to Affiliates
118,900
78,500
(29,294)
(27,626)
(225)
(230)
Net Cash Flows Used in Financing Activities
(53,604)
(8,139)
Net (Decrease)/Increase in Cash
(2,428)
147
203
WESTERN MASSACHUSETTS ELECTRIC COMPANY
1,419
53,676
47,297
530
164
15,540
16,192
15,513
45,036
42,370
25,112
27,352
9,779
7,963
151,095
156,852
1,330,207
1,290,498
192,231
221,752
32,579
30,342
19,346
23,625
244,156
275,719
1,725,458
1,723,069
35,200
31,900
55,000
44,789
68,141
7,452
7,103
19,885
21,037
12,838
8,404
25,740
24,809
200,904
216,394
9,352
332,628
303,111
11,058
9,686
32,204
36,099
25,477
40,148
401,367
389,044
549,840
550,270
10,866
390,573
390,412
175,593
160,577
(3,685)
(3,846)
573,347
558,009
1,123,187
1,108,279
18
115,015
106,836
239,968
220,861
32,254
32,715
72,298
73,269
23,136
27,847
44,064
50,449
9,310
6,994
18,280
14,691
685
(44)
814
(387)
3,091
4,358
7,780
8,776
7,925
4,933
16,240
10,489
6,206
4,977
12,494
9,858
82,607
81,780
171,970
167,145
32,408
25,056
67,998
53,716
6,078
5,905
12,032
11,671
50
343
757
148
621
360
836
6,276
6,869
12,569
13,264
419
188
1,423
1,280
26,551
18,375
56,852
41,732
10,137
7,237
21,836
16,408
16,414
11,138
35,016
25,324
84
169
(6)
(8)
78
86
161
171
16,492
11,224
35,177
25,495
33,317
17,708
(5,094)
(17,645)
572
1,917
(8,681)
694
21,081
533
21,389
(433)
(5,166)
(7,334)
119,308
43,844
(96,051)
(152,687)
41,604
45,516
(41,961)
(45,889)
11,000
4,601
1,096
(91,807)
(140,964)
(20,000)
(9,432)
Increase in Short-Term Debt
110,000
3,300
5,400
Retirement of Rate Reduction Bonds
(9,352)
(8,813)
(31)
(35)
(26,083)
97,120
1,418
COMBINED NOTES TO CONDENSED FINANCIAL STATEMENTS (Unaudited)
Refer to the Glossary of Terms included in this combined Quarterly Report on Form 10-Q for abbreviations and acronyms used throughout the combined notes to the unaudited condensed financial statements.
1.
SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
A.
Basis of Presentation
NU is a public utility holding company primarily engaged through its wholly owned regulated utility subsidiaries in the energy delivery business. On April 10, 2012, NU acquired 100 percent of the outstanding common shares of NSTAR and NSTAR's successor, NSTAR LLC, became a direct wholly owned subsidiary of NU. NU's wholly owned regulated utility subsidiaries include CL&P, NSTAR Electric, PSNH, WMECO, Yankee Gas and NSTAR Gas. NU provides energy delivery service to approximately 3.6 million electric and natural gas customers through six regulated utilities in Connecticut, Massachusetts and New Hampshire. NU's consolidated financial information does not include NSTAR and its subsidiaries' results of operations for the three months ended March 31, 2012. The information disclosed for NSTAR Electric represents its results of operations for the three and six months ended June 30, 2013 and 2012, presented on a comparable basis.
The unaudited condensed consolidated financial statements of NU, NSTAR Electric and PSNH include the accounts of each of their respective subsidiaries. Intercompany transactions have been eliminated in consolidation. The accompanying 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."
The combined notes to the financial statements have been prepared pursuant to the rules and regulations of the SEC. Certain information and footnote disclosures included in annual financial statements prepared in accordance with GAAP have been omitted pursuant to such rules and regulations. The accompanying financial statements should be read in conjunction with the entirety of this combined Quarterly Report on Form 10-Q, the first quarter 2013 combined Quarterly Report on Form 10-Q and the 2012 combined Annual Report on Form 10-K of NU, CL&P, NSTAR Electric, PSNH and WMECO (NU 2012 Form 10-K), which were filed with the SEC. The preparation of the financial statements in conformity with GAAP requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent liabilities as of the date of the financial statements and the reported amounts of revenues and expenses during the reporting period. Actual results could differ from those estimates.
The financial statements contain, in the opinion of management, all adjustments (including normal, recurring adjustments) necessary to present fairly NU’s, CL&P's, NSTAR Electric’s, PSNH's and WMECO's financial position as of June 30, 2013 and December 31, 2012, the results of operations and comprehensive income for the three and six months ended June 30, 2013 and 2012, and the cash flows for the six months ended June 30, 2013 and 2012. The results of operations and comprehensive income for the three and six months ended June 30, 2013 and 2012, and the cash flows for the six months ended June 30, 2013 and 2012, are not necessarily indicative of the results expected for a full year. The demand for electricity and natural gas is affected by weather conditions, economic conditions, and consumer conservation (including company-sponsored energy efficiency programs). Electric energy sales and revenues are typically higher in the winter and summer months than in the spring and fall months. Natural gas sales and revenues are typically higher in the winter months than during other periods of the year.
NU consolidates CYAPC and YAEC as CL&P’s, NSTAR Electric’s, PSNH’s and WMECO’s combined ownership interest in each of these entities is greater than 50 percent. Intercompany transactions between CL&P, NSTAR Electric, PSNH and WMECO and the CYAPC and YAEC companies have been eliminated in consolidation. For CL&P, NSTAR Electric, PSNH and WMECO, the investment in CYAPC and YAEC continue to be accounted for under the equity method.
NU's utility subsidiaries are subject to the application of accounting guidance for entities with rate-regulated operations that considers the effect of regulation resulting from differences in the timing of the recognition of certain revenues and expenses from those of other businesses and industries. NU's utility subsidiaries' energy delivery business is subject to rate-regulation that is based on cost recovery and meets the criteria for application of rate-regulated accounting. See Note 2, "Regulatory Accounting," for further information.
Certain reclassifications of prior period data were made in the accompanying balance sheets for NU, PSNH and WMECO, and the statements of cash flows for all companies presented. These reclassifications were made to conform to the current period’s presentation.
NU evaluates events and transactions that occur after the balance sheet date but before financial statements are issued and recognizes in the financial statements the effects of all subsequent events that provide additional evidence about conditions that existed as of the balance sheet date and discloses, but does not recognize, in the financial statements subsequent events that provide evidence about the conditions that arose after the balance sheet date but before the financial statements are issued. See Note 6, "Short-Term and Long-Term Debt," for further information.
B.
Accounting Standards
Recently Adopted Accounting Standards: In the first quarter of 2013, NU adopted the following Financial Accounting Standards Board’s (FASB) final Accounting Standards Updates (ASU) relating to additional disclosure requirements:
Reporting of Amounts Reclassified Out of Accumulated Other Comprehensive Income: Requires entities to disclose additional information about items reclassified out of AOCI. The ASU does not change existing guidance on which items should be reclassified out of AOCI but requires disclosures about the components of AOCI and the amount of reclassification adjustments to be presented in one location. The ASU is effective beginning in the first quarter of 2013 and is applied prospectively. For further information, see Note 10, "Accumulated Other Comprehensive Income/(Loss)," to the financial statements. The ASU did not affect the calculation of net income, comprehensive income or EPS and did not have an impact on financial position, results of operations or cash flows.
Clarifying the Scope of Disclosures about Offsetting Assets and Liabilities: Clarifies the scope of the offsetting disclosure requirements under GAAP. The disclosure requirements apply to derivative instruments, do not change existing guidance on which items should be offset in the balance sheets and require disclosures about the items that are offset. The ASU is effective beginning in the first quarter of 2013 with retrospective application. For further information, see Note 4, "Derivative Instruments," to the financial statements. The ASU did not have an impact on financial position, results of operations or cash flows.
Accounting Standards Issued but not Yet Adopted: In July 2013, the FASB issued a final ASU, Presentation of an Unrecognized Tax Benefit When a Net Operating Loss Carryforward, a Similar Tax Loss, or a Tax Credit Carryforward Exists, effective January 1, 2014 with prospective application required. The ASU requires presentation of certain unrecognized tax benefits as reductions to deferred tax assets rather than as liabilities. Management is currently evaluating the balance sheet impact of implementing this standard. The standard does not impact results of operations or cash flows.
C.
Provision for Uncollectible Accounts
NU, including CL&P, NSTAR Electric, PSNH and WMECO, presents its receivables at net realizable value by maintaining a provision for uncollectible amounts. This provision is determined based upon a variety of factors, including applying an estimated uncollectible account percentage to each receivable aging category, based upon historical collection and write-off experience and management's assessment of collectibility from individual customers. Management assesses the collectibility of receivables, and if circumstances change, collectibility estimates are adjusted accordingly. Receivable balances are written off against the provision for uncollectible accounts when the accounts are terminated and these balances are deemed to be uncollectible.
The provision for uncollectible accounts, which is included in Receivables, Net on the balance sheets, was as follows:
(Millions of Dollars)
As of June 30, 2013
As of December 31, 2012
NU
186.7
165.5
87.4
77.6
46.1
44.1
7.9
6.8
10.2
8.5
D.
Restricted Cash and Other Deposits
As of June 30, 2013, NU and CL&P had $2 million and $1.4 million, respectively, of restricted cash relating to amounts held in escrow, which were included in Prepayments and Other Current Assets on the balance sheets. As of December 31, 2012, these amounts were $3.3 million, $1.3 million and $1.7 million for NU, CL&P and PSNH, respectively.
As of June 30, 2013, NU had $8.6 million of cash collateral posted not subject to master netting agreements. As of December 31, 2012, this amount was $14.6 million.
E.
Fair Value Measurements
Fair value measurement guidance is applied to derivative contracts recorded at fair value and to the marketable securities held in the NU supplemental benefit trust, WMECO's spent nuclear fuel trust and CYAPC's and YAEC's nuclear decommissioning trusts. Fair value measurement guidance is also applied to investment valuations used to calculate the funded status of NU's Pension and PBOP Plans, including NSTAR Electric's Pension Plan, and nonrecurring fair value measurements of nonfinancial assets such as goodwill and AROs.
Fair Value Hierarchy: In measuring fair value, NU uses observable market data when available and minimizes the use of unobservable inputs. Inputs used in fair value measurements are categorized into three fair value hierarchy levels for disclosure purposes. The entire fair value measurement is categorized based on the lowest level of input that is significant to the fair value measurement. NU evaluates the classification of assets and liabilities measured at fair value on a quarterly basis, and NU's policy is to recognize transfers
22
between levels of the fair value hierarchy as of the end of the reporting period. The three levels of the fair value hierarchy are described below:
Level 1 - Inputs are quoted prices (unadjusted) in active markets for identical assets or liabilities as of the reporting date. Active markets are those in which transactions for the asset or liability occur in sufficient frequency and volume to provide pricing information on an ongoing basis.
Level 2 - Inputs are quoted prices for similar instruments in active markets, quoted prices for identical or similar instruments in markets that are not active, and model-derived valuations in which all significant inputs are observable.
Level 3 - Quoted market prices are not available. Fair value is derived from valuation techniques in which one or more significant inputs or assumptions are unobservable. Where possible, valuation techniques incorporate observable market inputs that can be validated to external sources such as industry exchanges, including prices of energy and energy-related products.
Determination of Fair Value: The valuation techniques and inputs used in NU's fair value measurements are described in Note 4, "Derivative Instruments," Note 5, "Marketable Securities," and Note 9, "Fair Value of Financial Instruments," to the financial statements.
F.
Items included within Other Income, Net on the statements of income primarily consist of investment income/(loss), interest income, AFUDC related to equity funds, and equity in earnings. For CL&P, NSTAR Electric, PSNH and WMECO, equity in earnings relate to investments in CYAPC, YAEC and MYAPC and also NSTAR Electric's investment in two regional transmission companies, which are all accounted for on the equity method. On an NU consolidated basis, equity in earnings relate to the investment in MYAPC and NU's investment in two regional transmission companies.
G.
Other Taxes
Gross receipts taxes levied by the state of Connecticut are collected by CL&P and Yankee Gas from their respective customers. These gross receipts taxes are shown on a gross basis with collections in Operating Revenues and payments in Taxes Other Than Income Taxes on the statements of income as follows:
For the Three Months Ended
For the Six Months Ended
June 30, 2013
June 30, 2012
33.0
30.5
71.4
65.5
29.8
27.7
61.8
57.1
Certain sales taxes are also collected by NU's companies that serve customers in the states of Connecticut and Massachusetts as agents for state and local governments and are recorded on a net basis with no impact on the statements of income.
H.
Supplemental Cash Flow Information
Non-cash investing activities include plant additions included in Accounts Payable as follows:
As of June 30, 2012
109.5
166.3
28.3
45.1
33.4
22.7
15.5
25.7
17.0
56.5
2.
REGULATORY ACCOUNTING
The rates charged to the customers of NU's Regulated companies are designed to collect each company's costs to provide service, including a return on investment. Therefore, the accounting policies of the Regulated companies reflect the application of accounting guidance for entities with rate-regulated operations and reflect the effects of the rate-making process.
Management believes it is probable that each of the Regulated companies will recover their respective investments in long-lived assets, including regulatory assets. If management were to determine that it could no longer apply the accounting guidance applicable to rate-regulated enterprises to any of the Regulated companies' operations, or that management could not conclude it is probable that costs would be recovered from customers in future rates, the costs would be charged to net income in the period in which the determination is made.
23
Regulatory Assets: The components of regulatory assets are as follows:
Benefit Costs
2,256.7
2,452.1
Regulatory Assets Offsetting Derivative Liabilities
793.3
885.6
527.5
537.6
Storm Restoration Costs
636.3
547.7
Income Taxes, Net
529.8
516.2
Securitized Assets
97.1
232.6
Contractual Obligations
126.4
217.6
Buy Out Agreements for Power Contracts
81.7
92.9
Regulatory Tracker Deferrals
194.5
190.1
Asset Retirement Obligations
91.5
88.8
Other Regulatory Assets
59.5
76.2
Total Regulatory Assets
5,394.3
5,837.4
Less: Current Portion
577.0
705.0
Total Long-Term Regulatory Assets
4,817.3
5,132.4
Electric
525.6
783.7
205.9
107.1
563.2
781.2
223.7
116.0
Regulatory Assets Offsetting
775.8
13.1
1.5
0.7
866.2
14.9
3.0
452.9
461.5
445.7
119.1
30.1
41.4
413.9
55.8
34.5
43.5
379.8
46.2
36.6
31.4
367.5
47.1
36.2
31.0
205.1
19.7
7.8
20.1
6.7
4.8
64.0
22.8
75.5
6.2
85.9
7.0
21.5
100.8
44.0
26.4
12.2
49.3
31.9
30.2
14.5
3.6
29.4
14.2
3.5
7.4
28.4
21.8
27.9
16.9
12.6
2,228.8
1,732.7
367.2
237.2
2,344.3
1,792.0
414.0
264.2
173.5
270.8
45.0
185.9
347.1
62.9
42.4
2,055.3
1,461.9
311.4
192.2
2,158.4
1,444.9
351.1
221.8
Storm Restoration Costs: The storm restoration cost deferrals relate to costs incurred at CL&P, NSTAR Electric, PSNH and WMECO that each company expects to collect from customers. The storm restoration cost regulatory asset balance at CL&P, NSTAR Electric and WMECO primarily reflects costs incurred for Tropical Storm Irene, the October 2011 snowstorm, Hurricane Sandy and the February 2013 blizzard. For PSNH, costs incurred associated with these storms are recorded in Other Long-Term Assets. Management believes the storm restoration costs meet the criteria for specific cost recovery in Connecticut, New Hampshire and Massachusetts and, as a result, are probable of recovery. Each operating company will seek recovery of these deferred storm restoration costs through its applicable regulatory recovery process.
Regulatory Costs in Other Long-Term Assets: The Regulated companies had $81.8 million ($3.7 million for CL&P, $27.3 million for NSTAR Electric, $37.4 million for PSNH, and $7.4 million for WMECO) and $69.9 million ($3.9 million for CL&P, $25.4 million for NSTAR Electric, $35.7 million for PSNH, and $1.4 million for WMECO) of additional regulatory costs as of June 30, 2013 and December 31, 2012, respectively, which were included in Other Long-Term Assets on the balance sheets. These amounts represent incurred costs that have not yet been approved for recovery by the applicable regulatory agency. Management believes it is probable that these costs will ultimately be approved and recovered from customers.
Regulatory Liabilities: The components of regulatory liabilities are as follows:
Cost of Removal
437.1
440.8
164.9
95.1
AFUDC - Transmission
68.5
70.0
Other Regulatory Liabilities
57.6
68.4
Total Regulatory Liabilities
728.1
674.3
216.4
134.1
Total Long-Term Regulatory Liabilities
511.7
540.2
24
34.7
246.0
50.3
44.2
240.3
51.2
66.0
42.9
17.6
19.2
39.1
14.4
20.4
19.0
55.2
4.0
9.3
56.6
4.1
8.0
5.0
2.5
16.5
32.9
3.8
2.4
163.9
324.3
72.9
156.4
291.7
75.4
30.7
74.4
21.9
19.9
32.1
47.5
23.0
21.0
99.9
249.9
51.0
11.1
124.3
244.2
52.4
9.7
3.
PROPERTY, PLANT AND EQUIPMENT AND ACCUMULATED DEPRECIATION
The following tables summarize the NU, CL&P, NSTAR Electric, PSNH and WMECO investments in utility property, plant and equipment by asset category:
Distribution - Electric
11,630.2
11,438.2
Distribution - Natural Gas
2,315.4
2,274.2
Transmission
5,883.6
5,541.1
Generation
1,147.9
1,146.6
Electric and Natural Gas Utility
20,977.1
20,400.1
Other (1)
504.6
429.3
Property, Plant and Equipment, Gross
21,481.7
20,829.4
Less: Accumulated Depreciation
(5,251.5)
(5,065.1)
(186.6)
(171.5)
Total Accumulated Depreciation
(5,438.1)
(5,236.6)
16,043.6
15,592.8
Construction Work in Progress
887.8
1,012.2
Total Property, Plant and Equipment, Net
16,931.4
16,605.0
(1)
These assets represent unregulated property and are primarily comprised of building improvements at RRR, software and equipment at NUSCO and telecommunications equipment at NSTAR Communications, Inc.
Distribution
4,780.7
4,598.8
1,549.8
739.6
4,691.3
4,539.9
1,520.1
724.2
2,954.9
1,602.3
612.4
668.9
2,796.1
1,529.7
599.2
583.7
1,126.8
21.1
1,125.5
Property, Plant and
Equipment, Gross
7,735.6
6,201.1
3,289.0
1,429.6
7,487.4
6,069.6
3,244.8
1,329.0
(1,755.9)
(1,602.0)
(988.1)
(264.2)
(1,698.1)
(1,540.1)
(954.0)
(252.1)
5,979.7
4,599.1
2,300.9
1,165.4
5,789.3
4,529.5
2,290.8
1,076.9
272.2
240.6
82.3
164.8
363.7
205.8
61.7
213.6
Total Property, Plant and
Equipment, Net
6,251.9
4,839.7
2,383.2
1,330.2
6,153.0
4,735.3
2,352.5
1,290.5
4.
DERIVATIVE INSTRUMENTS
The Regulated companies purchase and procure energy and energy-related products for their customers, which are subject to price volatility. The costs associated with supplying energy to customers are recoverable through customer rates. The Regulated companies manage the risks associated with the price volatility of energy and energy-related products through the use of derivative contracts, many of which meet the definition of and are designated as "normal purchases or normal sales" (normal) under the applicable accounting guidance, and the use of nonderivative contracts.
Derivative contracts that are not recorded as normal are recorded at fair value as current or long-term Derivative Assets or Derivative Liabilities on the accompanying balance sheets. For the Regulated companies, Regulatory Assets or Regulatory Liabilities are recorded for the changes in fair values of derivatives, as costs are recovered from, or refunded to, customers in their respective energy supply rates. For NU's remaining unregulated wholesale marketing contracts, changes in fair values of derivatives are included in Net Income. The costs and benefits of derivative contracts that meet the definition of normal are recognized in Operating Expenses or Operating Revenues on the statements of income, as applicable, as electricity or natural gas is delivered.
The gross fair values of derivative assets and liabilities with the same counterparty are offset and reported as net Derivative Assets or Derivative Liabilities, with current and long-term portions, on the balance sheets. Cash collateral posted or collected under master netting agreements is recorded as an offset to the derivative asset or liability. The following tables present the gross fair values of contracts categorized by risk type and the net amounts recorded as current or long-term derivative asset or liability:
25
Commodity Supply and
Net Amount Recorded as
Price Risk Management
Netting (1)
Derivative Asset/(Liability) (2)
Current Derivative Assets:
Level 2:
0.4
Level 3:
CL&P (1)
17.4
(10.2)
7.2
Total Current Derivative Assets
19.3
9.1
Long-Term Derivative Assets:
143.2
(53.9)
89.3
Total Long-Term Derivative Assets
Current Derivative Liabilities:
PSNH (1)
(1.5)
Other (1) (3)
(10.3)
(95.2)
(1.6)
(0.4)
Total Current Derivative Liabilities
(109.0)
Long-Term Derivative Liabilities:
(777.1)
(11.5)
(0.3)
Total Long-Term Derivative Liabilities
(788.9)
0.2
17.7
(12.0)
5.7
5.5
23.4
11.4
159.7
(69.1)
90.6
(19.9)
0.6
(19.3)
(96.9)
(1.0)
(117.8)
(117.2)
(0.2)
(865.6)
(13.9)
(3.0)
(882.7)
Amounts represent derivative assets and liabilities which NU has elected to record net on the balance sheets. These amounts are subject to master netting agreements or similar agreements for which the right of offset exists.
26
(2)
Current derivative assets are included in Prepayments and Other Current Assets on the balance sheets. NU, NSTAR Electric and WMECO current derivative liabilities are included in Other Current Liabilities and NSTAR Electric and WMECO long-term derivative liabilities are included in Other Long-Term Liabilities on the balance sheets.
As of June 30, 2013 and December 31, 2012, NU had $2.1 million and $4.1 million, respectively, of cash posted related to these contracts, which was not offset against the derivative liability and is recorded as Prepayments and Other Current Assets on the balance sheets.
For further information on the fair value of derivative contracts, see Note 1E, "Summary of Significant Accounting Policies - Fair Value Measurements," to the financial statements.
Derivatives Not Designated as Hedges
Commodity Supply and Price Risk Management: As required by regulation, CL&P has capacity-related contracts with generation facilities. These contracts and similar UI contracts have an expected capacity of 787 MW. CL&P has a sharing agreement with UI, with 80 percent of each contract allocated to CL&P and 20 percent allocated to UI. The capacity contracts extend through 2026 and obligate the utilities to make or receive payments on a monthly basis to or from the generation facilities based on the difference between a set capacity price and the forward capacity market price received in the ISO-NE capacity markets. In addition, CL&P has a contract to purchase 0.1 million MWh of energy per year through 2020.
NSTAR Electric has a renewable energy contract to purchase 0.1 million MWh of energy per year through 2018. NSTAR Electric also has a capacity related contract for up to 35 MW per year that extends through 2019.
PSNH has electricity procurement contracts to purchase 0.3 million MWh of energy through November 2013.
WMECO has a renewable energy contract to purchase 0.1 million MWh of energy per year through 2028 with a facility that is expected to achieve commercial operation by November 2013.
NU has NYMEX future contracts in order to reduce variability associated with the purchase price of approximately 6.2 million MMBtu of natural gas.
As of June 30, 2013 and December 31, 2012, NU had approximately 2 thousand MWh and 24 thousand MWh, respectively, of supply volumes remaining in its unregulated wholesale portfolio when expected sales are compared with supply contracts.
The following table presents the realized and unrealized gains/(losses) associated with NU’s derivative contracts not designated as hedges (See Level 3 tables in the "Valuations using significant unobservable inputs" section for CL&P, NSTAR Electric and WMECO gains and losses on derivative contracts):
Location of Amounts
Amounts Recognized on Derivatives
Recognized on Derivatives
Balance Sheet:
22.2
(40.8)
50.1
(33.5)
Statement of Income:
0.5
0.8
Credit Risk
Certain of NU’s derivative contracts contain credit risk contingent features. These features require NU to maintain investment grade credit ratings from the major rating agencies and to post collateral for contracts in a net liability position over specified credit limits. The following summarizes the fair value of derivative contracts that were in a net liability position and subject to credit risk contingent features, the fair value of cash collateral, and the additional collateral that would be required to be posted by NU if the unsecured debt credit ratings of NU parent were downgraded to below investment grade as of June 30, 2013 and December 31, 2012:
Additional Collateral
Fair Value Subject
Required if
to Credit Risk
Downgraded Below
Contingent Features
Collateral Posted
Investment Grade
(9.7)
(15.3)
Fair Value Measurements of Derivative Instruments
Valuation of Derivative Instruments: Derivative contracts classified as Level 2 in the fair value hierarchy relate to the financial contracts for natural gas futures, forward contracts to purchase energy at PSNH and the remaining unregulated wholesale marketing sourcing contracts. Prices are obtained from broker quotes and are based on actual market activity. The contracts are valued using the mid-point of the bid-ask spread. Valuations of these contracts also incorporate discount rates using the yield curve approach.
27
The fair value of derivative contracts classified as Level 3 utilizes significant unobservable inputs. The fair value is modeled using income techniques, such as discounted cash flow approaches adjusted for assumptions relating to exit price. Significant observable inputs for valuations of these contracts include energy and energy-related product prices in future years for which quoted prices in an active market exist. Fair value measurements categorized in Level 3 of the fair value hierarchy are prepared by individuals with expertise in valuation techniques, pricing of energy and energy-related products, and accounting requirements. The future power and capacity prices for periods that are not quoted in an active market or established at auction are based on available market data and are escalated based on estimates of inflation to address the full time period of the contract.
Valuations of derivative contracts using discounted cash flow methodology include assumptions regarding the timing and likelihood of scheduled payments and also reflect non-performance risk, including credit, using the default probability approach based on the counterparty's credit rating for assets and the company's credit rating for liabilities. Valuations incorporate estimates of premiums or discounts that would be required by a market participant to arrive at an exit price, using historical market transactions adjusted for the terms of the contract.
The following is a summary of NU’s, including CL&P’s, NSTAR Electric’s and WMECO’s, Level 3 derivative contracts and the range of the significant unobservable inputs utilized in the valuations over the duration of the contracts:
Range
Period Covered
Energy Prices:
$44 - $93 per MWh
2018 - 2028
$43 - $90 per MWh
$51 - $56 per MWh
2018 - 2020
$50 - $55 per MWh
Capacity Prices:
$1.40 - $10.53 per kW-Month
2017 - 2028
2016 - 2028
$1.40 - $9.51 per kW-Month
2017 - 2026
$1.40 - $9.83 per kW-Month
2016 - 2026
$1.40 - $3.39 per kW-Month
2017 - 2019
2016 - 2019
Forward Reserve:
NU, CL&P
$3.00 per kW-Month
2013 - 2024
$0.35 - $0.90 per kW-Month
REC Prices:
$25 - $85 per REC
2013 - 2028
$25 - $71 per REC
2013 - 2018
Exit price premiums of 10 percent through 32 percent are also applied on these contracts and reflect the most recent market activity available for similar type contracts.
Significant increases or decreases in future power or capacity prices in isolation would decrease or increase, respectively, the fair value of the derivative liability. Any increases in the risk premiums would increase the fair value of the derivative liabilities. Changes in these fair values are recorded as a regulatory asset or liability and would not impact net income.
Valuations using significant unobservable inputs: The following tables present changes for the three and six months ended June 30, 2013 and 2012 in the Level 3 category of derivative assets and derivative liabilities measured at fair value on a recurring basis. The derivative assets and liabilities are presented on a net basis. The fair value as of January 1, 2012 reflects a reclassification of remaining unregulated wholesale marketing sourcing contracts that had previously been presented as a portfolio along with the unregulated wholesale marketing sales contract as Level 3 under the highest and best use valuation premise. These contracts are now classified within Level 2 of the fair value hierarchy.
Derivatives, Net:
Fair Value as of Beginning of Period
(833.1)
(901.5)
(878.6)
(962.2)
Liabilities Assumed due to Merger with NSTAR
(5.4)
Transfer to Level 2
32.2
Net Realized/Unrealized Gains/(Losses) Included in:
1.3
(0.7)
7.1
(42.6)
48.9
(35.4)
Settlements
18.1
31.3
Fair Value as of End of Period
(788.1)
(932.1)
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NSTAR Electric(1)
(819.6)
(13.6)
(1.8)
(899.6)
(12.3)
Net Realized/Unrealized Gains/(Losses)
Included in Regulatory Assets
(0.5)
1.1
(31.8)
(9.6)
(1.2)
1.0
20.7
(0.8)
(775.8)
(13.1)
(910.7)
(15.8)
(13.5)
(866.2)
(14.9)
(931.6)
(3.4)
(7.3)
46.3
2.3
(21.0)
(6.2)
1.6
41.9
(2.2)
NSTAR Electric amounts are included in NU consolidated from the date of the merger, April 10, 2012, through June 30, 2012.
5.
MARKETABLE SECURITIES
NU maintains a supplemental benefit trust to fund certain of NU’s non-qualified executive retirement benefit obligations and WMECO maintains a spent nuclear fuel trust to fund WMECO’s prior period spent nuclear fuel liability, each of which hold marketable securities. These trusts are not subject to regulatory oversight by state or federal agencies. NU's marketable securities also include legally restricted trusts for the decommissioning of nuclear power plants that are part of CYAPC and YAEC.
The Company elects to record mutual funds purchased by the NU supplemental benefit trust at fair value. As such, any change in fair value of these mutual funds is reflected in Net Income. These mutual funds, classified as Level 1 in the fair value hierarchy, totaled $51.3 million and $47 million as of June 30, 2013 and December 31, 2012, respectively, and are included in current Marketable Securities. Net gains on these securities of $0.1 million and $4.3 million for the three and six months ended June 30, 2013, respectively, were recorded in Other Income, Net on the statements of income. These amounts were net losses of $0.5 million and net gains of $2.7 million for the three and six months ended June 30, 2012. Dividend income is recorded when dividends are declared and is recorded in Other Income, Net on the statements of income. All other marketable securities are accounted for as available-for-sale.
Available-for-Sale Securities: The following is a summary of NU's available-for-sale securities held in the NU supplemental benefit trust, WMECO's spent nuclear fuel trust and CYAPC's and YAEC's nuclear decommissioning trusts. These securities are recorded at fair value and included in current and long-term Marketable Securities on the balance sheets.
Pre-Tax
Amortized
Unrealized
Cost
Gains(1)
Losses(1)
Fair Value
Debt Securities (2)
333.4
6.5
339.2
Equity Securities (2)
163.7
42.2
Debt Securities
57.8
(0.1)
57.7
266.6
13.3
279.8
145.5
20.0
0.1
Unrealized gains and losses on debt securities for the NU supplemental benefit trust and WMECO spent nuclear fuel trust are recorded in AOCI and Other Long-Term Assets, respectively, on the balance sheets.
NU's amounts include CYAPC's and YAEC's marketable securities held in nuclear decommissioning trusts of $440 million and $340.4 million as of June 30, 2013 and December 31, 2012, respectively, the majority of which are legally restricted and can only be used for the decommissioning of the nuclear power plants owned by these companies. In the first quarter of 2013, CYAPC and
29
YAEC received cash from the DOE related to the litigation of storage costs for spent nuclear fuel, which was invested in the nuclear decommissioning trusts. Unrealized gains and losses for the nuclear decommissioning trusts are offset in Other Long-Term Liabilities on the balance sheets, with no impact on the statement of income. All of the equity securities accounted for as available-for-sale securities are held in these trusts.
Unrealized Losses and Other-than-Temporary Impairment: There have been no significant unrealized losses, other-than-temporary impairments or credit losses for the NU supplemental benefit trust, the WMECO spent nuclear fuel trust, and the trusts held by CYAPC and YAEC. Factors considered in determining whether a credit loss exists include the duration and severity of the impairment, adverse conditions specifically affecting the issuer, and the payment history, ratings and rating changes of the security. For asset-backed debt securities, underlying collateral and expected future cash flows are also evaluated.
Realized Gains and Losses: Realized gains and losses on available-for-sale securities are recorded in Other Income, Net for the NU supplemental benefit trust, Other Long-Term Assets for the WMECO spent nuclear fuel trust, and offset in Other Long-Term Liabilities for CYAPC and YAEC. NU utilizes the specific identification basis method for the NU supplemental benefit trust securities and the average cost basis method for the WMECO spent nuclear fuel trust and the CYAPC and YAEC nuclear decommissioning trusts to compute the realized gains and losses on the sale of available-for-sale securities.
Contractual Maturities: As of June 30, 2013, the contractual maturities of available-for-sale debt securities are as follows:
Less than one year (1)
102.4
25.1
One to five years
73.7
74.5
23.7
23.6
Six to ten years
57.9
59.0
Greater than ten years
99.4
103.3
5.4
Total Debt Securities
Amounts in the Less than one year NU category include securities in the nuclear decommissioning trusts, which are restricted and are classified in long-term Marketable Securities on the balance sheets.
Fair Value Measurements: The following table presents the marketable securities recorded at fair value on a recurring basis by the level in which they are classified within the fair value hierarchy:
As of
December 31, 2012
Level 1:
Mutual Funds and Equities
257.2
212.5
Money Market Funds
77.4
40.2
5.2
Total Level 1
334.6
252.7
U.S. Government Issued Debt Securities
(Agency and Treasury)
81.6
69.9
16.6
18.7
Corporate Debt Securities
46.5
Asset-Backed Debt Securities
29.9
28.5
10.5
10.9
Municipal Bonds
89.1
93.8
11.6
Other Fixed Income Securities
14.7
4.3
Total Level 2
261.8
239.6
52.9
52.5
Total Marketable Securities
596.4
492.3
U.S. government issued debt securities are valued using market approaches that incorporate transactions for the same or similar bonds and adjustments for yields and maturity dates. Corporate debt securities are valued using a market approach, utilizing recent trades of the same or similar instrument and also incorporating yield curves, credit spreads and specific bond terms and conditions. Asset-backed debt securities include collateralized mortgage obligations, commercial mortgage backed securities, and securities collateralized by auto loans, credit card loans or receivables. Asset-backed debt securities are valued using recent trades of similar instruments, prepayment assumptions, yield curves, issuance and maturity dates and tranche information. Municipal bonds are valued using a market approach that incorporates reported trades and benchmark yields. Other fixed income securities are valued using pricing models, quoted prices of securities with similar characteristics, and discounted cash flows.
6.
SHORT-TERM AND LONG-TERM DEBT
Credit Agreements and Commercial Paper Programs: As of June 30, 2013 and December 31, 2012, NU had $541.5 million and $1.15 billion, respectively, in short-term borrowings outstanding under its commercial paper program, which provides $608.5 million of available borrowing capacity as of June 30, 2013. The weighted-average interest rate on these borrowings as of June 30, 2013 and December 31, 2012 was 0.3 percent and 0.46 percent, respectively, which is generally based on money market rates. As of June 30, 2013, there were inter-company loans from NU of $189.3 million to CL&P, $182.2 million to PSNH and $35.2 million to WMECO. As of
30
December 31, 2012, there were inter-company loans from NU of $405.1 million to CL&P, $63.3 million to PSNH, and $31.9 million to WMECO. As of June 30, 2013 and December 31, 2012, NSTAR Electric had $253 million and $276 million, respectively, in short-term borrowings outstanding under its commercial paper program, leaving $197 million and $174 million, respectively, of available borrowing capacity. The weighted-average interest rate on these borrowings as of June 30, 2013 and December 31, 2012 was 0.22 percent and 0.31 percent, respectively, which is generally based on money market rates.
Amounts outstanding under the commercial paper program are included in Notes Payable for NU and NSTAR Electric and classified in current liabilities on the balance sheets as management anticipates that all borrowings under these credit facilities will be outstanding for no more than 364 days at one time. Intercompany loans from NU to CL&P, PSNH and WMECO are included in Notes Payable to Affiliated Companies and classified in current liabilities on the balance sheets.
Long-Term Debt Issuances: On January 15, 2013, CL&P issued $400 million of Series A First and Refunding Mortgage Bonds with a coupon rate of 2.5 percent and a maturity date of January 15, 2023. The proceeds, net of issuance costs, were used to pay short-term borrowings outstanding under the CL&P credit agreement and the NU commercial paper program. Therefore, as of December 31, 2012, CL&P's credit agreement borrowings of $89 million and intercompany loans related to the commercial paper program of $305.8 million have been classified as Long-Term Debt on the balance sheet.
On May 1, 2013, PSNH redeemed at par approximately $109 million of the 2001 Series C PCRBs that were due to mature in 2021 with short-term debt.
On May 13, 2013, NU parent issued $750 million of Senior Notes, consisting of $450 million of Series F Senior Notes at a coupon rate of 2.80 percent that will mature on May 1, 2023 and $300 million of Series E Senior Notes at a coupon rate of 1.45 percent that will mature on May 1, 2018. Part of the proceeds, net of issuance costs, was used to repay the NU parent $250 million Series C Senior Notes at a coupon rate of 5.65 percent that matured on June 1, 2013. In addition, part of the net proceeds will be used to repay the NU parent $300 million floating rate Series D Senior Notes due to mature on September 20, 2013. The remaining net proceeds were used to repay commercial paper borrowings and for other general corporate purposes.
On May 17, 2013, NSTAR Electric issued $200 million of three-year floating rate debentures with an initial interest rate of 0.5141 percent due to mature on May 17, 2016. The proceeds, net of issuance costs, were used to repay commercial paper borrowings and for general corporate purposes.
Working Capital: NU, CL&P, NSTAR Electric, PSNH and WMECO use their available capital resources to fund their respective construction expenditures, meet debt requirements, pay costs, including storm-related costs, pay dividends and fund other corporate obligations, such as pension contributions. The current growth in NU’s transmission construction expenditures utilizes a significant amount of cash for projects that have a long-term return on investment and recovery period. In addition, NU’s Regulated companies operate in an environment where recovery of its electric and natural gas distribution construction expenditures takes place over an extended period of time. This impacts the timing of the revenue stream designed to fully recover the total investment plus a return on the equity portion of the cost and related financing costs. These factors have resulted in NU’s current liabilities exceeding current assets by approximately $1 billion, $231 million, $338 million, $27 million and $50 million at NU, CL&P, NSTAR Electric, PSNH and WMECO, respectively, as of June 30, 2013.
As of June 30, 2013, approximately $857 million of NU's current liabilities related to long-term debt will be paid in the next 12 months, primarily consisting of $300 million for NU parent, $125 million for CL&P, $302 million for NSTAR Electric and $55 million for WMECO. NU, with its strong credit ratings, has several options available in the financial markets to repay or refinance these maturities with the issuance of new long-term debt. NU, CL&P, NSTAR Electric, PSNH and WMECO will reduce their short-term borrowings with cash received from operating cash flows and/or with the issuance of new long-term debt, as deemed appropriate given capital requirements and maintenance of NU's credit rating and profile. Management expects the future operating cash flows of NU, CL&P, NSTAR Electric, PSNH and WMECO along with the access to financial markets, will be sufficient to meet any future operating requirements and capital investment forecasted opportunities.
31
7.
PENSION BENEFITS AND POSTRETIREMENT BENEFITS OTHER THAN PENSIONS
The components of net periodic benefit expense for the Pension Plans (including the SERP Plans) and PBOP Plans, the portion of pension and PBOP amounts capitalized related to employees working on capital projects, and intercompany allocations not included in the net periodic benefit expense are as follows:
Pension and SERP
Service Cost
24.6
51.1
38.1
Interest Cost
51.9
53.2
103.5
91.3
Expected Return on Plan Assets
(68.6)
(59.4)
(139.0)
(101.9)
Actuarial Loss
52.6
47.4
105.5
Prior Service Cost
2.0
2.1
Total Net Periodic Benefit Expense
61.5
123.2
109.0
Capitalized Pension Expense
30.3
3.7
4.5
13.9
(11.3)
(27.7)
(17.0)
4.7
13.0
15.2
Prior Service Credit
(1.1)
Net Transition Obligation Cost
3.1
5.9
4.9
19.5
16.3
30.6
Capitalized PBOP Expense
9.8
For the Three Months Ended June 30, 2013
For the Three Months Ended June 30, 2012
Electric(1)
6.3
7.3
3.2
1.2
2.9
12.1
12.9
6.1
2.6
(18.4)
(20.2)
(9.2)
(4.4)
(17.7)
(16.3)
(7.2)
(4.1)
14.6
15.9
2.7
Prior Service Cost/(Credit)
0.9
14.1
Related Intercompany
Allocations
11.3
10.7
1.7
8.9
1.9
For the Six Months Ended June 30, 2013
For the Six Months Ended June 30, 2012
12.4
15.1
5.8
24.2
29.0
11.9
25.6
29.5
5.3
(36.9)
(42.2)
(16.8)
(8.7)
(35.2)
(32.8)
(8.2)
28.0
29.1
10.8
24.5
31.6
( 0.1)
0.3
1.8
28.6
32.3
12.7
27.6
43.1
22.1
21.3
14.0
11.8
3.9
13.4
32
(2.5)
(1.3)
(0.6)
(2.3)
1.4
4.6
(5.0)
(2.6)
(4.5)
8.3
NSTAR Electric pension amounts are included in NU consolidated from the date of the merger, April 10, 2012, through June 30, 2012. NSTAR Electric's pension amounts do not include SERP expense.
The net periodic postretirement expense allocated to NSTAR Electric was a benefit of $2 million and an expense of $8 million for the three months ended June 30, 2013 and 2012, respectively, and an expense of $2.3 million and $17 million for the six months ended June 30, 2013 and 2012, respectively.
Contributions: For the six months ended June 30, 2013, NU contributed $75.7 million to the NUSCO Pension Plan, $44.2 million of which was contributed by PSNH, and NSTAR Electric contributed $22.9 million to the NSTAR Pension Plan. NU contributed $24.2 million to the PBOP Plans for the six months ended June 30, 2013.
8.
COMMITMENTS AND CONTINGENCIES
Environmental Matters
General: NU, CL&P, NSTAR Electric, PSNH and WMECO are subject to environmental laws and regulations intended to mitigate or remove the effect of past operations and improve or maintain the quality of the environment. These laws and regulations require the removal or the remedy of the effect on the environment of the disposal or release of certain specified hazardous substances at current and former operating sites. NU, CL&P, NSTAR Electric, PSNH and WMECO have an active environmental auditing and training program and believe that they are substantially in compliance with all enacted laws and regulations.
The number of environmental sites and reserves related to these sites for which remediation or long-term monitoring, preliminary site work or site assessment are being performed are as follows:
Reserve
Number of Sites
(in millions)
71
38.4
39.4
Included in the NU number of sites and reserve amounts above are former MGP sites that were operated several decades ago and manufactured gas from coal and other processes, which resulted in certain by-products remaining in the environment that may pose a potential risk to human health and the environment. The reserve balance related to these former MGP sites was $33.7 million and $34.5 million as of June 30, 2013 and December 31, 2012, respectively, and relates primarily to the natural gas business segment.
Long-Term Contractual Arrangements
For information regarding long-term contractual obligations as of December 31, 2012, see Note 12B, "Commitments and Contingencies – Long-Term Contractual Arrangements," of the NU 2012 Form 10-K.
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Yankee Billings: As a result of the change in forecasted life of spent nuclear fuel decommissioning obligations, as well as proceeds received from the DOE in January 2013 arising from the spent nuclear fuel litigation, estimated future annual costs of Yankee Billings as of June 30, 2013 are reflected in the table below.
Renewable Energy: Renewable energy contracts include non-cancelable commitments under contracts of CL&P for the purchase of energy and capacity from renewable energy facilities.
July - December
2014
2015
2016
2017
Thereafter
Total
Yankee Billings
18.5
3.3
Renewable Energy
49.4
49.9
50.4
607.0
812.3
Guarantees and Indemnifications
NU parent, or NSTAR LLC, as applicable, provides credit assurances on behalf of its subsidiaries, including CL&P, NSTAR Electric, PSNH and WMECO, in the form of guarantees in the normal course of business.
NU provided guarantees and various indemnifications on behalf of external parties as a result of the sales of former subsidiaries of NU Enterprises, with maximum exposures either not specified or not material.
NU also issued a guaranty under which, beginning at the time the Northern Pass Transmission line goes into commercial operation, NU will guarantee the financial obligations of NPT under the TSA in an amount not to exceed $25 million. NU's obligations under the guaranty expire upon the full, final and indefeasible payment of the guaranteed obligations.
Management does not anticipate a material impact to Net Income as a result of these various guarantees and indemnifications.
The following table summarizes NU's guarantees of its subsidiaries, including CL&P, NSTAR Electric, PSNH and WMECO, as of June 30, 2013:
Maximum
Exposure
Subsidiary
Description
Expiration Dates
Various
Surety Bonds
2013 - 2015 (1)
NE Hydro Companies' Long-Term Debt
Unspecified
NUSCO and RRR
Lease Payments for Vehicles and Real Estate
2019 and 2024
Surety Bonds, Performance Guarantees and Insurance Bond
65.4
Surety bond expiration dates reflect termination dates, the majority of which will be renewed or extended.
The maximum exposure includes $5.9 million related to performance guarantees on wholesale purchase contracts, which expire December 31, 2013. Also included in the maximum exposure is $58.5 million relating to surety bonds covering ongoing projects, which expire upon project completion. The remaining $1 million is related to an insurance bond with no expiration date that is billed annually.
Many of the underlying contracts that NU parent guarantees, as well as certain surety bonds, contain credit ratings triggers that would require NU parent to post collateral in the event that the unsecured debt credit ratings of NU, or NSTAR LLC, as applicable, are downgraded.
FERC Base ROE Complaint
On September 30, 2011, several New England state attorneys general, state regulatory commissions, consumer advocates and other parties filed a joint complaint with the FERC under Sections 206 and 306 of the Federal Power Act alleging that the base ROE used in calculating formula rates for transmission service under the ISO-NE Open Access Transmission Tariff by New England transmission owners (NETOs), including CL&P, NSTAR Electric, PSNH and WMECO, is unjust and unreasonable. The complainants are asserting that the current 11.14 percent rate, which became effective in 2006, is excessive due to changes in the capital markets and are seeking an order to reduce the rate, which would be effective October 1, 2011. In response, the NETOs filed testimony and analysis based on standard FERC methodology and precedent, demonstrating that the base ROE of 11.14 percent remained just and reasonable. The FERC set the case for trial before a FERC administrative law judge after settlement negotiations were unsuccessful in August 2012.
34
In April 2013, the complainants, the Massachusetts municipal electric utilities (late intervenors to the case), and the FERC trial staff updated their respective base ROE analyses, which demonstrated a base ROE of approximately 8.9 percent. Also in April 2013, the NETOs filed an updated analysis that continues to demonstrate that the current base ROE of 11.14 percent remains within an updated range of reasonableness of 7.3 percent to 13.2 percent.
On June 6, 2013, following hearings that were held in May 2013, the NETOs, the complainants, the Massachusetts municipal electric utilities, and the FERC trial staff filed initial briefs. Reply briefs were filed on June 28, 2013. The NETOs demonstrated the current base ROE of 11.14 percent should remain in effect for the refund period (October 1, 2011 through December 31, 2012) and the prospective period (beginning when FERC issues its final decision). The complainants, the Massachusetts municipal electric utilities, and the FERC trial staff each recommended a base ROE of 9 percent or below. The trial judge’s recommended decision is due by September 10, 2013. A decision from FERC commissioners is expected in 2014.
On December 27, 2012, several additional parties filed a separate complaint concerning the NETOs' base ROE with the FERC. This complaint seeks to reduce the NETOs’ base ROE effective January 1, 2013, effectively extending the refund period for an additional 15 months, and to consolidate this complaint with the joint complaint filed on September 30, 2011. The NETOs have asked the FERC to reject this complaint. The FERC has not yet acted on this request.
Management cannot at this time predict the ultimate outcome of this proceeding or the estimated impacts on the financial position, results of operations or cash flows of CL&P, NSTAR Electric, PSNH and WMECO.
DPU Safety and Reliability Programs - CPSL
Since 2006, NSTAR Electric has been recovering incremental costs related to the DPU-approved Safety and Reliability Programs. From 2006 through 2011, cumulative costs associated with the CPSL program resulted in an incremental revenue requirement to customers of approximately $83 million. These amounts included incremental operations and maintenance costs and the related revenue requirement for specific capital investments relative to the CPSL programs.
On May 28, 2010, the DPU issued an order on NSTAR Electric’s 2006 CPSL cost recovery filing (the May 2010 Order). In October 2010, NSTAR Electric filed a reconciliation of the cumulative CPSL program activity for the periods 2006 through 2009 with the DPU in order to determine a proposed rate adjustment. The DPU allowed the proposed rates to go into effect January 1, 2011, subject to final reconciliation of CPSL program costs through a future DPU proceeding. In February 2013, NSTAR Electric updated the October 2010 filing with final activity through 2011. NSTAR Electric recorded its 2006 through 2011 revenues under the CPSL programs based on the May 2010 Order.
NSTAR Electric cannot predict the timing of a final DPU order related to its CPSL filings for the period 2006 through 2011. While management does not believe that any subsequent DPU order would result in revenues that are materially different than the amounts already recognized, it is reasonably possible that an order could have a material impact on NSTAR Electric’s results of operations, financial position and cash flows.
Basic Service Bad Debt Adder
In accordance with a generic DPU order, electric utilities in Massachusetts recover the energy-related portion of bad debt costs in their Basic Service rates. In 2007, NSTAR Electric filed its 2006 Basic Service reconciliation with the DPU proposing an adjustment related to the increase of its Basic Service bad debt charge-offs. The DPU issued an order approving the implementation of a revised Basic Service rate but instructed NSTAR Electric to reduce distribution rates by an amount equal to the increase in its Basic Service bad debt charge-offs. This adjustment to NSTAR Electric’s distribution rates would eliminate the fully reconciling nature of the Basic Service bad debt adder.
In 2010, NSTAR Electric filed an appeal of the DPU’s order with the SJC. In 2012, the SJC vacated the DPU order and remanded the matter to the DPU for further review.
NSTAR Electric deferred approximately $34 million of costs associated with energy-related bad debt as a regulatory asset through 2011 as NSTAR Electric had concluded that it was probable that these costs would ultimately be recovered from customers. Due to the delays and duration of the proceedings, NSTAR Electric concluded that while an ultimate outcome on the matter in its favor remained "more likely than not," it could no longer be deemed "probable." As a result, NSTAR Electric recognized a reserve related to the regulatory asset in the first quarter of 2012. NSTAR Electric will continue to maintain the reserve until the ultimate outcome of the proceeding has been concluded with the DPU.
9.
FAIR VALUE OF FINANCIAL INSTRUMENTS
The following methods and assumptions were used to estimate the fair value of each of the following financial instruments:
Preferred Stock, Long-Term Debt and Rate Reduction Bonds: The fair value of CL&P's and NSTAR Electric’s preferred stock is based upon pricing models that incorporate interest rates and other market factors, valuations or trades of similar securities and cash flow projections. The fair value of fixed-rate long-term debt securities and RRBs is based upon pricing models that incorporate quoted market prices for those issues or similar issues adjusted for market conditions, credit ratings of the respective companies and treasury
35
benchmark yields. Adjustable rate securities are assumed to have a fair value equal to their carrying value. The fair values provided in the tables below are classified as Level 2 within the fair value hierarchy. Carrying amounts and estimated fair values are as follows:
Carrying
Fair
Amount
Value
Preferred Stock Not
Subject to Mandatory Redemption
155.6
154.3
152.2
8,539.7
8,841.1
7,963.5
8,640.7
82.1
83.0
116.2
112.0
43.0
42.3
2,865.8
3,115.1
1,801.0
1,904.9
889.1
949.1
604.8
627.5
110.0
2,862.8
3,295.4
1,602.6
1,818.8
997.9
1,088.0
605.3
660.4
43.9
29.3
29.6
9.4
9.5
Derivative Instruments: Derivative instruments are carried at fair value. For further information, see Note 4, "Derivative Instruments," to the financial statements.
Other Financial Instruments: Investments in marketable securities are carried at fair value. For further information, see Note 1E, "Summary of Significant Accounting Policies - Fair Value Measurements," and Note 5, "Marketable Securities," to the financial statements.
The carrying value of other financial instruments included in current assets and current liabilities, including cash and cash equivalents and special deposits, approximates their fair value due to the short-term nature of these instruments.
10.
ACCUMULATED OTHER COMPREHENSIVE INCOME/(LOSS)
The changes in accumulated other comprehensive income/(loss) by component, net of tax, is as follows:
Unrealized Gains/(Losses) on Available-for-Sale Securities
Pension, SERP and PBOP
AOCI as of January 1, 2013
(16.4)
(57.8)
(72.9)
Other Comprehensive Income Before Reclassifications
Amounts Reclassified from AOCI
Net Other Comprehensive Income
3.4
AOCI as of June 30, 2013
(15.4)
(54.7)
(69.5)
NU's qualified cash flow hedging instruments represent interest rate swap agreements on debt issuances that were settled in prior years. The settlement amount was recorded in AOCI and is being amortized into Net Income over the term of the underlying debt instrument. CL&P, PSNH and WMECO continue to amortize interest rate swaps settled in prior years from AOCI into Interest Expense over the remaining life of the associated long-term debt, which are not material to their respective financial statements.
36
The following table sets forth the amounts reclassified from AOCI by component and the affected line item on the statements of income:
Amount Reclassified
Statements of Income
from AOCI
Line Item Impacted
(1.7)
Tax Benefit
Qualified Cash Flow Hedging Instruments, Net of Tax
Pension, SERP and PBOP Benefit Plan Costs:
Amortization of Actuarial Losses
(4.7)
Amortization of Prior Service Cost
Total Pension, SERP and PBOP Benefit Plan Costs
(4.8)
Pension, SERP and PBOP Benefit Plan Costs, Net of Tax
(3.1)
Total Amount Reclassified from AOCI, Net of Tax
(2.0)
These AOCI 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 CL&P, NSTAR Electric, PSNH and WMECO common stock authorized and issued as of June 30, 2013 and December 31, 2012 and the respective par values:
Shares
Authorized
Issued
Per Share
Par Value
380,000,000
332,966,638
332,509,383
24,500,000
6,035,205
100,000,000
100
301
1,072,471
434,653
As of June 30, 2013 and December 31, 2012, 18,251,317 and 18,455,749 NU common shares were held as treasury shares, 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:
Noncontrolling
Interest -
Common
Preferred
Non-
Shareholders'
Stock of
Controlling
Equity
Subsidiaries
Interest
Balance - Beginning of Period
9,345.2
4,068.3
4,071.7
173.1
Purchase Price of NSTAR
5,038.3
Other Equity Impacts of
Merger with NSTAR
Dividends on Common Shares
(115.6)
(107.6)
Dividends on Preferred Stock
(1.9)
Issuance of Common Shares
Other Transactions, Net
4.2
Net Income Attributable to
Noncontrolling Interests
Other Comprehensive Income
Balance - End of Period
9,406.6
9,067.6
37
9,237.1
4,012.7
4,015.7
403.0
147.0
(232.1)
(160.2)
(3.9)
(3.3)
8.8
Contributions to NPT
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 if certain share-based compensation awards are converted into common shares. There were no antidilutive share awards outstanding for the three months ended June 30, 2013. For the six months ended June 30, 2013, there were 3,150 share awards excluded from the computation as these awards were antidilutive. For the three and six months ended June 30, 2012, there were 17,065 and 8,533, respectively, antidilutive share awards excluded from the calculation.
The following table sets forth the components of basic and diluted EPS:
(Millions of Dollars, except share information)
171.0
44.3
399.1
143.6
Dilutive Effect
808,489
769,131
840,622
575,434
Basic EPS
Diluted EPS
On April 10, 2012, NU issued approximately 136 million common shares as a result of the merger with NSTAR, which are reflected in weighted average common shares outstanding for all periods presented.
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 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 segments represented substantially all of NU's total consolidated revenues for the three and six month periods ended June 30, 2013 and 2012. 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 segment includes the generation activities of PSNH and WMECO.
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Other operations in the tables below 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 income and expense related to the cash and debt of NU parent and NSTAR LLC, respectively, 2) the revenues and expenses of NU's service companies, most of which are eliminated in consolidation, 3) the operations of CYAPC and YAEC, and 4) the results of other subsidiaries, which are comprised of NU Enterprises, NSTAR Communications, Inc., RRR (a real estate subsidiary), the non-energy-related subsidiaries of Yankee and the remaining operations of HWP.
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 the combined Electric Distribution, Electric Transmission and Natural Gas Distribution segments, 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. Therefore, separate Transmission and Distribution information is not disclosed for CL&P, NSTAR Electric, PSNH or WMECO. NU’s operating segments and reporting units are consistent with its reportable business segments.
NSTAR amounts are included in NU consolidated as of April 10, 2012.
NU's segment information for the three and six month periods ended June 30, 2013 and 2012 is as follows:
Natural Gas
Eliminations
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)
(222.2)
Other Operating Expenses
(883.3)
(127.0)
(63.6)
(194.9)
205.7
(1,063.1)
186.1
10.4
149.8
350.6
(43.4)
(8.9)
(25.2)
(10.7)
(86.9)
Interest Income
230.8
(230.7)
Income Tax (Expense)/Benefit
(52.4)
(49.8)
(95.6)
92.5
232.8
(231.0)
Net Income Attributable
to Noncontrolling Interests
(2.1)
to Controlling Interest
91.2
76.8
2,595.8
515.9
487.4
437.8
(406.0)
3,630.9
(329.1)
(34.1)
(66.3)
(465.7)
(1,888.3)
(394.3)
(125.8)
(392.2)
404.9
(2,395.7)
378.4
87.5
295.3
769.5
(85.6)
(16.2)
(47.1)
(17.1)
(163.1)
(3.2)
551.1
(551.0)
(106.8)
(27.1)
13.8
(216.1)
193.1
44.5
158.1
555.5
(548.2)
(1.4)
190.6
156.7
Total Assets (as of)
18,138.7
2,706.2
6,429.7
18,776.1
(17,853.8)
28,196.9
Cash Flows Used for
Investments in Plant
315.3
70.9
297.4
16.7
700.3
39
1,229.9
133.5
228.7
230.2
(193.6)
1,628.7
(153.3)
(12.4)
(28.6)
(210.8)
(1,004.8)
(115.8)
(65.5)
(263.0)
190.7
(1,258.4)
Operating Income/(Loss)
71.8
134.6
(50.5)
159.5
(44.8)
(8.8)
(26.2)
(11.1)
(89.0)
Other Income/(Loss), Net
117.9
(6.9)
25.0
(26.1)
Net Income/(Loss)
20.9
64.4
82.7
(119.7)
Net Income/(Loss) Attributable
63.7
2,016.0
272.5
391.6
363.4
(315.2)
2,728.3
(225.4)
(20.1)
(21.6)
(315.4)
(1,627.0)
(218.0)
(113.2)
(397.8)
317.0
(2,039.0)
163.6
34.4
228.6
(56.0)
373.9
(77.9)
(14.3)
(45.8)
(20.4)
(155.5)
(2.7)
240.5
(240.4)
(28.3)
(7.6)
(75.6)
(82.0)
111.4
197.7
(238.4)
15,161.3
2,432.7
5,327.7
20,614.1
(16,029.5)
27,506.3
305.7
59.7
297.2
27.8
690.4
40
NORTHEAST UTILITIES AND SUBSIDIAIRIES
Management's Discussion and Analysis ofFinancial 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 2013 Form 10-Q, and the 2012 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, including NSTAR LLC and its subsidiaries for the periods after April 10, 2012. 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 period. The discussion below also includes non-GAAP financial measures referencing our second quarter and first half of 2013 and 2012 earnings and EPS excluding certain impacts 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 2013 and 2012 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, 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:
·
the possibility that expected merger synergies will not be realized or will not be realized within the expected time period,
cyber breaches, acts of war or terrorism, or grid disturbances,
actions or inaction by local, state and federal regulatory and taxing bodies,
changes in business and economic conditions, including their impact on interest rates, collectability of receivables, and demand for our products and services,
fluctuations in weather patterns,
changes in laws, regulations or regulatory policy,
changes in levels and 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 2012 Form 10-K. This Quarterly Report on Form 10-Q and NU’s 2012 Form 10-K also describe material contingencies and critical accounting policies in the accompanying Management’s Discussion and Analysis and Combined Notes to Condensed Consolidated Financial Statements (Unaudited). We encourage you to review these items.
Financial Condition and Business Analysis
Merger with NSTAR:
On April 10, 2012, we completed our merger with NSTAR. Unless otherwise noted, the results of NSTAR LLC and its subsidiaries, hereinafter referred to as "NSTAR," are included in NU’s financial position, results of operations and cash flows as of June 30, 2013 and December 31, 2012, for the three months ended June 30, 2013 and 2012, and for the six months ended June 30, 2013, throughout this Management's Discussion and Analysis of Financial Condition and Results of Operations.
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 $171.0 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, compared with $44.3 million, or $0.15 per share, in the second quarter of 2012 and $143.6 million, or $0.60 per share, in the first half of 2012. Excluding integration and merger-related costs, we earned $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, compared with $135.8 million, or $0.45 per share, in the second quarter of 2012, and $236.2 million, or $0.98 per share, in the first half of 2012.
The addition of NSTAR provided an earnings contribution of $123.9 million for the first half of 2013, compared to $35.9 million for the first half of 2012. Due to the timing of the merger closing, April 10, 2012, NSTAR’s first quarter 2012 results are not reflected in NU’s results for the first half of 2012.
Our electric distribution segment, which includes generation, earned $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, compared with earnings of $19.7 million, or $0.07 per share, in the second quarter of 2012 and $61.7 million, or $0.26 per share, in the first half of 2012. Second quarter and first half 2012 results reflect $50.8 million of after-tax merger-related costs.
Our transmission segment earned $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, compared with $63.7 million, or $0.21 per share, in the second quarter of 2012 and $110 million, or $0.45 per share, in the first half of 2012.
Our natural gas distribution segment earned $1.2 million in the second quarter of 2013 and $44.5 million, or $0.14 per share, in the first half of 2013, compared with a net loss of $2.1 million, or $0.01 per share, in the second quarter of 2012 and earnings of $12.6 million, or $0.05 per share, in the first half of 2012. Second quarter and first half 2012 results reflect $2.1 million of after-tax merger-related costs.
NU parent and other companies earned $1.8 million in the second quarter of 2013 and $7.3 million, or $0.02 per share, in the first half of 2013, compared with net expenses of $37 million, or $0.12 per share, in the second quarter of 2012 and $40.7 million, or $0.16 per share, in the first half of 2012. Second quarter and first half 2013 results reflect $1.8 million and $3.5 million, respectively, of after-tax integration-related costs. Second quarter and first half 2012 results reflect $38.6 million and $39.7 million, respectively, of after-tax merger-related costs.
Legislative, Regulatory, Policy and Other Items:
On June 5, 2013, Connecticut Governor Malloy signed into law a bill that codified a number of the recommendations proposed in the Connecticut comprehensive energy strategy (CES) and requires PURA to implement decoupling for each of Connecticut’s electric and natural gas utilities in their next respective rate cases.
On June 27, 2013, we proposed a new route for the northernmost section of the Northern Pass transmission line and on July 1, 2013, we filed the new route in an amended application with the DOE. The $1.4 billion project is subject to comprehensive federal and state public permitting processes and is expected to be operational by mid-2017.
42
Liquidity:
Cash and cash equivalents totaled $36.1 million as of June 30, 2013, compared with $45.7 million as of December 31, 2012, while cash capital expenditures totaled $700.3 million in the first half of 2013, compared with $690.4 million in the first half of 2012.
Cash flows provided by operating activities totaled $686.9 million in the first half of 2013, compared with $284 million in the first half of 2012 (amounts are net of RRB payments). The improved operating cash flows were due primarily to a decrease in storm restoration costs, the addition of NSTAR, a decrease in Pension Plan cash contributions, the absence in 2013 of the first half of 2012 customer bill credits and merger-related costs.
On May 13, 2013, NU parent issued $750 million of Senior Notes, consisting of $300 million at a coupon rate of 1.45 percent that will mature on May 1, 2018 and $450 million at a coupon rate of 2.80 percent that will mature on May 1, 2023. Part of the proceeds, net of issuance costs, was used to repay the NU parent $250 million Series C Senior Notes at a coupon rate of 5.65 percent that matured on June 1, 2013. On May 17, 2013, NSTAR Electric issued $200 million of three-year floating rate Debentures that will mature on May 17, 2016.
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 2013 and 2012 is as follows:
(Millions of Dollars, Except
2012 (1)
Per Share Amounts)
Net Income Attributable to Controlling Interest (GAAP)
Regulated Companies
169.2
134.2
0.44
391.8
1.24
0.98
NU Parent and Other Companies
0.01
0.03
Non-GAAP Earnings
172.8
0.55
135.8
0.45
402.6
236.2
Integration and Merger-Related Costs (after-tax) (2)
(0.01)
(91.5)
(0.30)
(3.5)
(92.6)
(0.38)
Results include the operations of NSTAR from the date of the merger, April 10, 2012, through June 30, 2012.
The second quarter and first half of 2013 costs related to integration costs incurred at NU parent for consulting and compensation expenses. The first half 2012 after-tax merger-related costs consisted of Regulated companies’ charges of $52.9 million (for further information, see Regulated Companies portion of this Overview section), transaction and integration-related costs of $21.1 million at NU parent related to investment advisory fees, attorney fees, and consulting costs, a $9.7 million charge related to change in control costs and other compensation costs at NU parent and NSTAR LLC, and an $8.9 million charge at NU parent for the establishment of a fund to advance Connecticut energy goals related to the Connecticut settlement agreement.
Excluding the impacts of integration and merger-related costs, our second quarter 2013 earnings increased by $37 million, as compared to the second quarter of 2012, due primarily to lower overall operations and maintenance costs, higher transmission segment earnings as a result of increased investments in the transmission infrastructure, and higher retail electric and firm natural gas sales. Partially offsetting these favorable earnings impacts were higher depreciation and property tax expense.
Excluding the impacts of integration and merger-related costs, our first half 2013 earnings increased by $166.4 million, as compared to the first half of 2012, due primarily to the inclusion of NSTAR, effective April 10, 2012, lower overall operations and maintenance costs, higher retail electric and firm natural gas sales, higher transmission segment earnings as a result of increased investments in the transmission infrastructure, and a favorable impact of $13.6 million, or $0.04 per share, from the first quarter 2013 resolution of a state income tax audit. Partially offsetting these favorable earnings impacts were higher depreciation and property tax expense.
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Regulated Companies: Our Regulated companies consist of the electric distribution, transmission and natural gas distribution segments. Generation activities of PSNH and WMECO are included in our electric distribution segment. A summary of our segment earnings for the second quarter and first half of 2013 and 2012 is as follows:
For the Three MonthsEnded June 30,
For the Six MonthsEnded June 30,
Electric Distribution
70.5
112.5
Natural Gas Distribution
Total - Regulated Companies
Merger-Related Costs (after-tax) (2)
(52.9)
Net Income - Regulated Companies
81.3
184.3
The second quarter and first half 2012 after-tax merger-related costs consisted of $27.6 million in charges ($46 million pre-tax) at CL&P, NSTAR Electric, NSTAR Gas and WMECO for customer bill credits related to the Connecticut and Massachusetts settlement agreements, a $23.6 million charge ($40 million pre-tax) related to the Connecticut settlement agreement, whereby CL&P agreed to forego recovery of deferred storm costs associated with Tropical Storm Irene and the October 2011 snowstorm, and a $1.7 million charge related to change in control costs and other compensation costs.
Excluding $50.8 million of 2012 after-tax merger-related costs, the higher second quarter 2013 electric distribution segment earnings, as compared to the second quarter of 2012, were due primarily to lower overall operations and maintenance costs and higher retail electric sales resulting from higher residential sales as a result of warmer than normal weather in the Boston area in the second quarter of 2013, as compared to the second quarter of 2012. The second quarter 2013 results were also favorably impacted by the PSNH 2010 distribution rate case settlement. As a result of the settlement, the PSNH rates increased effective July 1, 2012. Partially offsetting these favorable earnings impacts were higher depreciation and property tax expense.
Excluding $50.8 million of 2012 after-tax merger-related costs, the higher first half 2013 electric distribution segment earnings, as compared to the first half of 2012, were due primarily to the inclusion of NSTAR Electric distribution business’ earnings, lower overall operations and maintenance costs and higher retail electric sales due primarily to colder weather in the first quarter of 2013, as compared to the first quarter of 2012. First half 2013 results were also favorably impacted by the PSNH 2010 distribution rate case settlement. Partially offsetting these favorable earnings impacts were higher depreciation and property tax expense. For further information regarding NSTAR Electric’s earnings, see "Results of Operations – NSTAR Electric Company and Subsidiary – Earnings Summary" in this Management's Discussion and Analysis of Financial Condition and Results of Operations.
The higher second quarter 2013 transmission segment earnings, as compared to the second quarter of 2012, were due primarily to increased investments in the transmission infrastructure, including GSRP, which is under construction in western Massachusetts and northern Connecticut.
The higher first half 2013 transmission segment earnings, as compared to the first half of 2012, were due primarily to the inclusion of NSTAR Electric transmission business’ earnings, increased investments in the transmission infrastructure, including GSRP, which is under construction in western Massachusetts and northern Connecticut, and the favorable impact from the first quarter 2013 resolution of a state income tax audit.
Excluding $2.1 million of 2012 after-tax merger-related costs, the higher second quarter 2013 natural gas distribution segment earnings, as compared to the second quarter of 2012, were due primarily to the favorable impact of the Yankee Gas 2011 rate case decision resulting in the additional increase to annualized rates effective July 1, 2012 and higher firm natural gas sales due to colder weather in the second quarter of 2013, as compared to the second quarter of 2012, partially offset by higher depreciation expense and property tax expense.
Excluding $2.1 million of 2012 after-tax merger-related costs, the higher first half 2013 natural gas distribution segment earnings, as compared to the first half of 2012, were due primarily to the inclusion of NSTAR Gas’ earnings, higher firm natural gas sales due to colder weather in the first half of 2013, as compared to the first half of 2012, the favorable impact of the Yankee Gas 2011 rate case decision, and lower interest expense, partially offset by higher depreciation expense and property tax expense.
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A summary of our retail electric GWh sales and percentage changes, assuming NSTAR Electric had been part of the NU electric distribution system for all periods under consideration, as well as percentage changes in CL&P, NSTAR Electric, PSNH and WMECO retail electric GWh sales, and our firm natural gas sales in million cubic feet and percentage changes, assuming NSTAR Gas had been part of the NU natural gas distribution system for all periods under consideration, as well as percentage changes in Yankee Gas and NSTAR Gas, for the second quarter and first half of 2013, as compared to the same periods in 2012, is as follows:
For the Three Months EndedJune 30, 2013 Compared to 2012
For the Six Months EndedJune 30, 2013 Compared to 2012
Sales (GWh)
Percentage
NU – Electric
Increase/
(Decrease)
Increase/(Decrease)
Residential
4,720
4,636
1.8 %
10,523
10,079
4.4 %
Commercial
6,754
6,710
0.7 %
13,448
13,287
1.2 %
Industrial
1,437
1,490
(3.5)%
2,736
2,830
(3.3)%
12,911
12,836
0.6 %
26,707
26,196
1.9 %
For the Three Months Ended June 30, 2013 Compared to 2012
For the Six Months Ended June 30, 2013 Compared to 2012
NSTARElectric
PercentageIncrease/(Decrease)
PercentageIncrease
2.0 %
1.6 %
0.8 %
5.8 %
3.1 %
3.4 %
0.5 %
1.3 %
(0.1)%
(6.3)%
(3.7)%
(5.5)%
(4.4)%
(2.3)%
0.3 %
(0.2)%
2.5 %
1.4 %
0.9 %
Results include retail electric sales of NSTAR Electric from January 1, 2012 through June 30, 2012 for comparative purposes only.
Sales (million cubic feet)
NU – Firm Natural Gas
Percentage Increase
4,970
4,000
24.2 %
21,985
17,712
24.1%
6,622
6,155
7.6 %
23,393
20,293
15.3%
4,665
4,732
(1.4)%
11,494
11,334
1.4%
16,257
14,887
9.2 %
56,872
49,339
Total, Net of Special Contracts (2)
15,238
13,502
12.9 %
54,660
45,879
19.1%
NSTAR Gas (3)
Increase
21.5 %
26.4%
24.8 %
23.7%
8.8 %
6.6%
17.5 %
13.4%
(1.5)%
(1.1)%
(3.2)%
15.5%
7.2 %
11.6%
12.5 %
18.1%
14.1 %
20.4 %
Results include firm natural gas sales of NSTAR Gas from January 1, 2012 through June 30, 2012 for comparative purposes only.
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.
NSTAR Gas’ sales data for the three and six months ended June 30, 2013 compared to 2012 has been provided for comparative purposes only.
Weather, fluctuations in fuel costs, conservation measures (including company-sponsored energy efficiency programs), and economic conditions affect the level of sales to our customers. Industrial sales are less sensitive to temperature variations than residential and commercial sales. Weather impacts electric sales primarily during the summer and natural gas sales during the winter in our service territories (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, particularly when weather patterns experienced are consistently colder or warmer. In addition, our electric and natural gas businesses are sensitive to variations in daily weather, are highly influenced by New England’s seasonal weather variations, and are susceptible to damage from major storms and other natural events and disasters that could adversely affect our ability to provide energy.
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For the second quarter of 2013, our consolidated retail electric sales were higher, as compared to the same period in 2012, due primarily to an increase in residential sales as a result of warmer than normal weather in the Boston area in the second quarter of 2013, as compared to the second quarter of 2012. For the first half of 2013, our consolidated retail electric sales were higher, as compared to the same period in 2012, due primarily to the colder weather in the first quarter of 2013, as compared to the first quarter of 2012.
For the second quarter of 2013, actual retail electric sales for CL&P, NSTAR Electric and PSNH increased, as compared to the same period in 2012, while actual retail electric sales for WMECO remained relatively unchanged for the same period under consideration. Cooling degree days were five percent lower than last year in Connecticut and western Massachusetts, 13 percent higher than last year in the Boston area, and one percent lower than last year in New Hampshire. On a weather-normalized basis (based on 30-year average temperatures), retail electric sales for our four operating companies increased for the second quarter of 2013, as compared to the same period in 2012, with the NU combined consolidated total retail electric sales increasing by approximately one percent due primarily to economic recovery in the NU service territory.
For the first half of 2013, actual and weather-normalized retail electric sales for each of our four electric companies increased, as compared to the same period in 2012. Actual sales increased due primarily to the colder weather in the first quarter of 2013, as compared to the first quarter of 2012. For the first half of 2013, heating degree days were 22 percent higher in Connecticut and western Massachusetts, 21 percent higher in the Boston metropolitan area, and 15 percent higher in New Hampshire, as compared to 2012. On a weather-normalized basis, the NU combined consolidated total retail electric sales remained relatively unchanged in the first half of 2013, as compared to the first half of 2012, assuming NSTAR Electric had been part of the NU electric distribution system for all periods under consideration.
For WMECO, the 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 consolidated firm natural gas sales are subject to many of the same influences as our retail electric sales, but have benefitted from favorable natural gas prices and customer growth across all three customer classes. In the second quarter and first half of 2013, actual and weather-normalized sales increased, as compared to the same periods in 2012. Second quarter actual firm natural gas sales were higher due to the colder weather in the second quarter of 2013, as compared to the same period in 2012. First half of 2013 actual firm natural gas sales were higher due primarily to the colder weather in the first half of 2013, as compared to the first half of 2012, assuming NSTAR Gas had been part of the NU combined natural gas distribution system for all periods under consideration. On a weather-normalized basis, the NU combined consolidated total firm natural gas sales increased 4.4 percent and 3.1 percent in the second quarter and first half of 2013, respectively, as compared to the same periods in 2012, due primarily to customer growth, lower cost of natural gas when compared to the cost of other energy sources, the migration of interruptible customers switching to firm service rates, and the addition of gas-fired distributed generation in Yankee Gas’ service territory.
NU Parent and Other Companies: NU parent and other companies (which includes NSTAR LLC from the date of the merger, April 10, 2012, and our competitive businesses held by NU Enterprises) earned $1.8 million and $7.3 million in the second quarter and first half of 2013, respectively, compared with net losses of $37 million and $40.7 million in the second quarter and first half of 2012, respectively. Excluding the impact of integration and merger-related costs, NU parent and other companies earned $3.6 million and $10.8 million in the second quarter and first half of 2013, respectively, compared with earnings of $1.6 million and net losses of $1 million in the second quarter and first half of 2012, respectively. Improved results were due primarily to a lower effective tax rate and for the first half of 2013, the inclusion of NSTAR Communications.
Liquidity
Consolidated: Cash and cash equivalents totaled $36.1 million as of June 30, 2013, compared with $45.7 million as of December 31, 2012.
On May 17, 2013, NSTAR Electric issued $200 million of three-year floating rate Debentures with an initial interest rate of 0.5141 percent that will mature on May 17, 2016. The proceeds, net of issuance costs, were used to repay commercial paper borrowings and for general corporate purposes.
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On July 31, 2013, the FERC approved CL&P’s and WMECO’s short-term debt application requesting the authorization to issue total short-term borrowings up to a maximum of $600 million and $300 million, respectively. The authorization is effective January 1, 2014 through December 31, 2015.
NU, CL&P, NSTAR Electric, PSNH and WMECO use their available capital resources to fund their respective construction expenditures, meet debt requirements, pay costs, including storm-related costs, pay dividends and fund other corporate obligations, such as pension contributions. The current growth in NU’s transmission construction expenditures utilizes a significant amount of cash for projects that have a long-term return on investment and recovery period. In addition, NU’s Regulated companies operate in an environment where recovery of its electric and natural gas distribution construction expenditures takes place over an extended period of time. This impacts the timing of the revenue stream designed to fully recover the total investment plus a return on the equity portion of the cost and related financing costs. These factors have resulted in NU’s current liabilities exceeding current assets by approximately $1 billion, $231 million, $338 million, $27 million and $50 million at NU, CL&P, NSTAR Electric, PSNH, and WMECO, respectively, as of June 30, 2013.
As of June 30, 2013, approximately $857 million of NU's current liabilities related to long-term debt will be paid in the next 12 months, primarily consisting of $300 million for NU parent, $125 million for CL&P, $302 million for NSTAR Electric, and $55 million for WMECO. NU, with its strong credit ratings, has several options available in the financial markets to repay or refinance these maturities with the issuance of new long-term debt. NU, CL&P, NSTAR Electric, PSNH, and WMECO will reduce their short-term borrowings with cash received from operating cash flows and/or with the issuance of new long-term debt, as deemed appropriate given our capital requirements and maintenance of our credit rating and profile. Management expects the future operating cash flows of NU and its subsidiaries, along with the access to financial markets, will be sufficient to meet any future operating requirements and capital investment forecasted opportunities.
Cash flows provided by operating activities totaled $686.9 million in the first half of 2013, compared with $284 million in the first half of 2012 (all amounts are net of RRB payments, which are included in financing activities on the accompanying consolidated statements of cash flows). The improved operating cash flows were due primarily to the addition of NSTAR, which contributed $138.1 million of operating cash flows (net of RRB payments) in the first quarter of 2013, a decrease of approximately $100 million in cash disbursements for storm costs in the first half of 2013 associated primarily with the February blizzard, as compared to cash disbursements in the first half of 2012 associated primarily with Tropical Storm Irene and the October 2011 snowstorm, the absence in 2013 of $73 million in cash disbursements in the first half of 2012 at CL&P, NSTAR Electric, NSTAR Gas and WMECO related to customer bill credits, a reduction of Pension Plan contributions of approximately $35 million, and the absence in 2013 of the first half of 2012 merger-related costs of approximately $29 million. Partially offsetting these favorable impacts was negative cash flow impacts associated with increased coal and fuel inventories and changes in traditional working capital amounts principally due to the changes in timing of accounts receivable and accounts payable.
There have been no changes to our current credit ratings and outlooks by Moody's, S&P and Fitch for senior unsecured debt of NU parent, NSTAR Electric, and WMECO and senior secured debt of CL&P and PSNH since the issuance of the NU 2012 Form 10-K. A summary of the corporate credit ratings and outlooks by Moody's, S&P and Fitch is as follows:
Current
Outlook
NU Parent
Baa2
Stable
A-
BBB+
A2
A
We paid common dividends of $232 million in the first half of 2013, compared with $159.7 million in the first half of 2012. On April 2, 2013, our Board of Trustees approved a common dividend payment of $0.3675 per share, which was paid on June 28, 2013 to shareholders of record as of May 31, 2013.
In the first half of 2013, CL&P, NSTAR LLC, PSNH, and WMECO paid $76 million, $68 million, $34 million, and $20 million, respectively, in common dividends to NU parent.
On March 15, 2013, NSTAR Electric made its final principal and interest payment on approximately $675 million of RRBs that were issued in March 2005. On May 1, 2013, PSNH made its final principal and interest payment on approximately $525 million of RRBs that were issued in April 2001. On June 1, 2013, WMECO made its final principal and interest payment on approximately $155 million of RRBs that were issued in May 2001. As a result, NSTAR Electric, PSNH and WMECO will no longer recover any payments from customers associated with these RRBs. The full amortization of these RRBs will reduce NSTAR Electric’s, PSNH’s and WMECO’s cash flows provided by operating activities in 2013, compared with 2012, but will have no impact on operating cash flows net of RRB payments.
Cash capital expenditures included in 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
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portions of pension expense. In the first half of 2013, cash capital expenditures for NU, CL&P, NSTAR Electric, PSNH, and WMECO were $700.3 million, $184.9 million, $207.4 million, $109.6 million, and $96.1 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 $644 million in the first half of 2013, compared with $714 million in the first half of 2012. These amounts included $6.7 million and $20 million in the first half of 2013 and 2012, respectively, related to our corporate service companies, NUSCO and RRR.
Transmission Business: Overall, transmission business capital expenditures decreased by $39.3 million in the first half of 2013, as compared to the first half of 2012. The first half 2013 results reflect a decrease at WMECO related to the construction of GSRP nearing completion offset by the addition of NSTAR Electric's capital expenditures and an increase at NPT. A summary of transmission capital expenditures by company for the first half of 2013 and 2012 is as follows:
84.1
91.1
79.3
29.2
35.0
41.5
136.4
Total Transmission Segment
262.0
301.3
Results include transmission capital expenditures of NSTAR Electric from the date of the merger, April 10, 2012, through June 30, 2012.
NEEWS: GSRP, a project that involves the construction of 115 kV and 345 kV overhead lines by CL&P and WMECO from Ludlow, Massachusetts to Bloomfield, Connecticut, is the first, largest and most complicated project within the NEEWS family of projects. The $718 million project is expected to be fully placed in service in late 2013. If all events surrounding completion of the project continue at their current state, the total cost will be approximately five percent lower. As of June 30, 2013, the project was approximately 97 percent complete and CL&P and WMECO had placed $490 million in service.
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, is our second major NEEWS project. All siting applications have been filed by CL&P and National Grid. Earlier this year, the Connecticut Siting Council approved the Connecticut portion of the project. On June 14, 2013, the Rhode Island Energy Facility Siting Board issued a final decision and order approving the Rhode Island portion of the project. A decision in Massachusetts is expected between the end of 2013 and early 2014. Our portion of the construction costs is expected to be $218 million and the project is expected to be placed in service in late 2015.
Included as part of NEEWS are associated reliability related projects, approximately $72 million of which have been placed in service and approximately $22 million of which are in various phases of construction and will continue to go into service through 2013.
Through June 30, 2013, CL&P and WMECO had capitalized $235 million and $545 million, respectively, in costs associated with NEEWS, of which $23.4 million and $26.7 million, respectively, were capitalized in the first half of 2013.
Greater Hartford Central Connecticut Project (GHCC): In August 2012, ISO-NE presented its preliminary needs analysis for the GHCC to the ISO-NE Planning Advisory Committee. The results showed severe regional and local thermal overloads and voltage violations within and across each of the four study areas now and in the near future. ISO-NE is expected to identify the preferred transmission solutions in late 2013 or early 2014, which are likely to include many 115-kV upgrades. We expect that the specific future projects being identified to address these reliability concerns will cost approximately $300 million.
Cape Cod Reliability Projects: Transmission projects serving Cape Cod in the Southeastern Massachusetts (SEMA) reliability region consist of an expansion and upgrade of NSTAR Electric's existing transmission infrastructure including construction of a new 345 kV transmission line that crosses the Cape Cod Canal and associated 115 kV upgrades in the center of Cape Cod (Lower SEMA Transmission Project) and related 115 kV projects (Mid-Cape Project). All regulatory licensing and permitting is complete for the Lower SEMA Transmission Project and construction commenced in September 2012. The new 345 kV line was placed into service on June 25, 2013. Additional 115 kV line upgrades are expected to be completed in late 2013. The Mid-Cape Project is scheduled to be completed in 2017. The aggregate estimated construction costs for the Cape Cod projects are expected to be approximately $150 million. Through June 30, 2013, NSTAR Electric had capitalized $72.5 million in costs associated with the Cape Cod projects, of which $40.1 million was capitalized in the first half of 2013.
Northern Pass: Northern Pass is NPT's planned HVDC transmission line from the Québec-New Hampshire border to Franklin, New Hampshire and an associated alternating current radial transmission line between Franklin and Deerfield, New Hampshire. Northern Pass will interconnect at the Québec-New Hampshire border with a planned HQ HVDC transmission line. On June 27, 2013, we
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proposed a new route for the northernmost section of the Northern Pass transmission line and on July 1, 2013, we filed the new route in an amended application with the DOE. The $1.4 billion project is subject to comprehensive federal and state public permitting processes and is expected to be operational by mid-2017.
Distribution Business: A summary of distribution capital expenditures by company for the first half of 2013 and 2012 is as follows:
CL&P:
Basic Business
Aging Infrastructure
71.3
95.2
Load Growth
31.8
42.7
Total CL&P
130.9
182.0
NSTAR Electric:
48.3
51.3
Total NSTAR Electric
113.0
59.1
PSNH:
10.3
23.2
10.1
9.6
Total PSNH
38.6
WMECO:
7.5
8.4
Total WMECO
17.8
Total - Electric Distribution (excluding Generation)
300.3
303.7
Total - Natural Gas
70.1
60.9
Other Distribution
Total Electric and Natural Gas
370.6
365.0
PSNH Generation:
5.1
Total PSNH Generation
27.3
WMECO Generation
Total Distribution Segment
375.2
392.6
Results include the electric and natural gas distribution capital expenditures of NSTAR from the date of the merger, April 10, 2012, through June 30, 2012.
For the electric distribution business, basic business includes the purchase of meters, tools, vehicles, information technology, transformer replacements, equipment facilities, and the relocation of plant. Aging infrastructure relates to reliability and the replacement of overhead lines, plant substations, underground cable replacement, and equipment failures. Load growth includes requests for new business and capacity additions on distribution lines and substation additions and expansions.
FERC Regulatory Issues
FERC Base ROE Complaint: On September 30, 2011, several New England state attorneys general, state regulatory commissions, consumer advocates and other parties filed a joint complaint with the FERC under Sections 206 and 306 of the Federal Power Act alleging that the base ROE used in calculating formula rates for transmission service under the ISO-NE Open Access Transmission Tariff by New England transmission owners (NETOs), including CL&P, NSTAR Electric, PSNH and WMECO, is unjust and unreasonable. The complainants are asserting that the current 11.14 percent rate, which became effective in 2006, is excessive due to changes in the capital markets and are seeking an order to reduce the rate, which would be effective October 1, 2011. In response, the NETOs filed testimony and analysis based on standard FERC methodology and precedent, demonstrating that the base ROE of 11.14 percent remained just and reasonable. The FERC set the case for trial before a FERC administrative law judge after settlement negotiations were unsuccessful in August 2012.
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As of June 30, 2013, CL&P, NSTAR Electric, PSNH, and WMECO had approximately $2.1 billion of aggregate shareholder equity invested in their transmission facilities. As a result, each 10 basis point change in the authorized base ROE would change annual consolidated earnings by an approximate $2.1 million. We cannot at this time predict the ultimate outcome of this proceeding or the estimated impacts on the financial position, results of operations or cash flows of CL&P, NSTAR Electric, PSNH, and WMECO.
FERC Order No. 1000: In 2012, ISO-NE and a majority of the NETOs, including CL&P, NSTAR Electric, PSNH and WMECO, made a comprehensive compliance filing as required by FERC Order No. 1000 and Order No. 1000-A. The compliance filing sought to preserve the NETO's right to build transmission facilities needed for reliability and the existing reliability planning process in New England, based on the FERC’s previous approval of their rights under the Transmission Operating Agreement with ISO-NE, and the superiority of the current planning process, which has resulted in major transmission construction, large reliability benefits and reduction of market costs. Per the FERC's orders, the NETOs also submitted a secondary process and rule changes in the event the FERC were to reject the primary filing. The filing also contained a new process for public policy transmission planning that incorporates opportunities for competingprojects and cost allocation among the supporting states, which had lead roles in selecting public policy projects. Protests to the compliance filing were submitted by various stakeholders that were responded to by ISO-NE and NETOs.
On May 17, 2013, the FERC issued an order on compliance. Three out of the five FERC commissioners found that, while it had previously approved a right of first refusal for the NETOs to build transmission for reliability, the public interest requires competition for the construction of transmission. FERC rejected ISO-NE and NETOs' primary filing, which sought to preserve the existing transmission planning process. FERC largely accepted the NETOs' and ISO-NE's secondary competitive transmission process, but required additional modifications to make the process more transparent. The approved process preserves the NETOs' right to build projects that are needed for reliability within three years, and projects that are upgrades to the NETOs' existing facilities. FERC also rejected portions of the public policy transmission planning process that gave the states, rather than ISO-NE, control over public policy identification, project selection and cost allocation. FERC recently granted NETOs and ISO-NE an extension of time to make a further compliance filing by November 15, 2013 in order to thoroughly develop the revised rules and review them with stakeholders. In mid-June 2013, ISO-NE and NETOs sought rehearing from the FERC on the rejection of the current transmission planning process for reliability, and certain of the required modifications.
In July 2013, ISO-NE, NYISO and PJM jointly filed an agreement containing protocols that address FERC's requirements for interregional transmission planning. The protocols establish a standing interregional committee at the ISO/RTO level to exchange planning data and information for the joint study and evaluation of potential interregional transmission projects. ISO-NE and NETOs filed corresponding changes to the ISO-NE tariff, and provisions to allocate the costs of selected interregional transmission projects based on the type of project (reliability or public policy) and the benefits to the region by displacing a higher cost regional project.
We cannot predict the final outcome or impact on our transmission segment as the rules regarding transmission planning, transition, competitive solicitations and cost allocation are still being developed and will need to be approved by the FERC. However, the rules around short-term reliability needs, transition and system upgrades suggest that most projects in our near-term capital program are likely to remain unaffected. Long-term reliability and public policy needs are likely to be met through competitive processes, and may introduce new risks and opportunities.
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. Other than as described below, for the first half of 2013, 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 2012 Form 10-K.
Major Storms:
2013, 2012 and 2011 Major Storms: In 2013, 2012 and 2011, CL&P, NSTAR Electric, PSNH and WMECO each experienced significant storms that impacted their service territories, including Tropical Storm Irene, the October 2011 snowstorm, Storm Sandy, and the February 2013 blizzard. As of June 30, 2013, the estimated storm restoration costs deferred for future recovery for major storms that occurred during these time periods at CL&P, NSTAR Electric, PSNH, and WMECO were as follows:
2012 and 2011
465.9
495.4
67.5
132.9
33.6
35.9
36.0
600.9
99.3
700.2
The magnitude of these storm restoration costs met the criteria for cost deferral in Connecticut, New Hampshire, and Massachusetts and as a result, the storms had no material impact on the results of operations of CL&P, NSTAR Electric, PSNH and WMECO. We believe our response to all of these storms was prudent and therefore we believe it is probable that CL&P, NSTAR Electric, PSNH and WMECO will be allowed to recover the deferred storm restoration costs. Each operating company will seek recovery of its estimated deferred storm restoration costs through its applicable regulatory recovery process.
Connecticut - Yankee Gas: On June 14, 2013, Yankee Gas and other Connecticut natural gas distribution companies filed a comprehensive joint natural gas infrastructure expansion plan (expansion plan) with DEEP and PURA in response to Connecticut Governor Malloy’s CES and the recently enacted Connecticut legislation pursuant to Public Act 13-298, "An Act Concerning Implementation of Connecticut’s Comprehensive Energy Strategy and Various Revisions to the Energy Statutes." The expansion plan describes how the natural gas distribution companies expect to add approximately 280,000 new natural gas heating customers over the next 10 years, 82,000 of those for Yankee Gas. The expansion plan outlines a set of comprehensive recommendations, several of them already incorporated into Public Act 13-298. Key recommendations include providing more flexibility in the process of adding new customers, establishing new regulatory tools to help fund conversion costs over time, providing for mechanisms for timely recovery of capital investments made by natural gas distribution companies and allowing utilities to secure additional pipeline capacity coming into Connecticut. On July 16, 2013, DEEP issued a determination letter finding the expansion plan was essentially consistent with the CES and requested some modifications to be made. On July 26, 2013, the natural gas distribution companies submitted their responses to DEEP and PURA. A decision by PURA is expected by October 2013. For further information on the Connecticut legislation, see "Legislative and Policy Matters – 2013 Connecticut Legislation" in this Management’s Discussion and Analysis.
New Hampshire:
Distribution Rates: On June 27, 2013 the NHPUC approved an increase to distribution rates of $12.6 million, effective July 1, 2013. The increase, which is consistent with the NHPUC approved 2010 distribution rate case settlement, consists primarily of $7.7 million associated with net plant additions and a $5 million increase to the current level of funding for the Major Storm Cost reserve.
PSNH Generation: On June 7, 2013, the NHPUC staff issued a "Report on Investigation into Market Conditions, Default Service Rate, Generation Ownership and Impact on the Competitive Electricity Market." The report recommended that the NHPUC open a proceeding to examine whether default service rates remain sustainable on a going forward basis, what "just and reasonable" means with respect to default service in the context of competitive retail markets, analysis of the current and expected value of PSNH’s generating units, and means to mitigate and address stranded cost recovery. Possible solutions explored as part of the NHPUC staff’s study include sale of PSNH’s generation assets to competitive third parties, retirement of the generation assets, and transfer of the generation assets to a new competitive affiliate of PSNH. On July 15, 2013, the NHPUC issued an order accepting the report, as well as comments from PSNH and other parties, and ordered NHPUC staff to engage through a competitive bid process a valuation expert to determine the value of PSNH's generation assets and entitlements. At this time, we cannot predict the outcome of this review, but believe all costs and generation investments are probable of recovery.
Clean Air Project Prudence Proceeding: In November 2011, the NHPUC opened a docket to review the Clean Air Project including the establishment of temporary rates for near-term recovery of Clean Air Project costs, a prudence review of PSNH's overall construction program, and establishment of permanent rates for recovery of prudently incurred Clean Air Project costs. In April 2012, the NHPUC issued an order authorizing temporary rates to recover a significant portion of the Clean Air Project costs. The docket will continue for a comprehensive prudence review of the Clean Air Project and the establishment of a permanent rate. The temporary rates will remain in effect until a permanent rate allowing full recovery of all prudently incurred costs is approved. At that time, the NHPUC will reconcile recoveries collected under the temporary rates with final approved rates.
The NHPUC has issued a series of orders ruling on the scope of its inquiry and discovery issues. The most recent order, dated July 15, 2013, established a procedural schedule with hearings set for late 2013. While the NHPUC continues to review the costs incurred to complete the Clean Air Project, we continue to believe that we were prudent in the undertaking and completion of the Clean Air Project.
51
However, we cannot predict with certainty the outcome of the Clean Air Project prudence review, but believe all costs were incurred appropriately and are probable of recovery.
Legislative and Policy Matters
2013 Connecticut Legislation: On June 5, 2013, Connecticut Governor Malloy signed into law two significant energy bills. The first bill, codified as Public Act 13-298, implemented a number of the recommendations proposed in the CES. Public Act 13-298 provided legislation authorizing the filing of a plan to expand natural gas service to Connecticut residents that currently do not have access to natural gas. The legislation required local natural gas distribution companies in Connecticut to file, by June 15, 2013, a plan to expand the natural gas system. The legislation also requires PURA to implement decoupling for each of Connecticut’s electric and natural gas utilities in their next respective rate cases. PURA is to implement decoupling for electric utilities that reconciles actual revenues to allowed revenues. For natural gas distribution companies, the decoupling mechanism shall be a mechanism that does not remove the incentive to support the expansion of natural gas use pursuant to the CES, such as a mechanism that decouples distribution revenue based on a use-per-customer basis.
The second bill, codified as Public Act 13-303, "An Act Concerning Connecticut’s Clean Energy Goals," allows DEEP to conduct a process to procure from renewable energy generators, under long-term contracts with the electric distribution companies, additional renewable generation to help Connecticut meet its RPS. Large scale hydropower facilities located in the New England Power Pool Generation Information System (NEPOOL GIS) geographic eligibility area or an area abutting the northern boundary of the NEPOOL GIS geographic eligibility area are eligible to bid into DEEP's process. If Connecticut experiences a material shortfall in reaching its RPS goals, such hydropower, under certain conditions, can be used to alleviate such shortfall, up to five percent of RPS requirements in 2020. The legislation also requires DEEP to develop a schedule to assign a gradually reducing renewable energy credit value for all Class I biomass or landfill generation facilities. Such reduced credit values will not apply to biogas or anaerobic digestion facilities, or to facilities that have a long-term contract in place. The commissioner of DEEP may adjust such changes to the values of renewable energy credits, if such adjustment is appropriate given the availability of other Class I renewable energy sources.
2013 Massachusetts Legislation: On July 24, 2013, the Massachusetts legislature enacted a law that changes the income tax rate applicable to utility companies effective January 1, 2014. The law changes the income tax rate for electric and gas companies from 6.5 percent to 8 percent.
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 NU’s 2012 Form 10-K. There have been no material changes with regard to these critical accounting policies.
Other Matters
Accounting Standards: For information regarding new accounting standards, see Note 1B, "Summary of Significant Accounting Policies – Accounting Standards."
Contractual Obligations and Commercial Commitments: Refer to Note 8B, "Commitments and Contingencies – Long-Term Contractual Obligations," for discussion of material contractual obligations.
Web Site: Additional financial information is available through our web site at www.nu.com.
52
RESULTS OF OPERATIONS – NORTHEAST UTILITIES AND SUBSIDIARIES
The following table 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, 2013 and 2012:
Operating Revenues and Expenses
2012 (a)
Percent
%
902.6
33.1
488.3
542.0
(53.7)
(9.9)
1,236.1
937.4
298.7
357.2
529.9
(172.7)
(32.6)
703.3
791.9
(88.6)
(11.2)
144.5
15.0
314.5
225.3
89.2
39.6
54.6
(b)
108.6
8.1
40.8
(32.7)
(80.1)
42.6
(16.5)
(27.9)
94.1
73.5
20.6
199.9
110.8
80.4
123.5
112.9
10.6
256.4
198.9
57.5
28.9
1,285.3
1,469.2
(183.9)
(12.5)
2,861.4
2,354.4
507.0
191.1
395.6
(a) The 2012 results include the operations of NSTAR from the date of the merger, April 10, 2012, through June 30, 2012.
(b) Percent greater than 100 percent not shown as it is not meaningful.
(8.3)
579.8
28.8
15.4
243.4
Total Distribution
1,375.7
1,363.4
12.3
3,111.7
2,288.5
823.2
95.8
Total Regulated Companies
1,623.6
1,592.1
31.5
3,599.1
2,680.1
919.0
34.3
Other and Eliminations
(24.3)
(66.4)
48.2
(34.0)
Total Operating Revenues
A summary of our retail electric sales and firm natural gas sales were as follows:
Retail Electric Sales in GWh
75
511
Firm Natural Gas Sales in Million Cubic Feet
1,370
9.2
7,533
15.3
(a)
Results include the retail electric sales of NSTAR Electric and the firm natural gas sales of NSTAR Gas from January 1, 2012 through June 30, 2012 for comparative purposes only.
Our Operating Revenues increased in the second quarter of 2013, as compared to the second quarter of 2012, due primarily to the following:
Higher electric distribution segment revenues related to the portions that are included in regulatory commission approved tracking mechanisms that recover certain incurred costs and do not impact earnings. The tracking mechanisms allow for rates to be changed periodically with overcollections refunded to customers or undercollections recovered from customers in future periods. The tracked electric distribution revenues increased due primarily to higher retail transmission revenues ($44.3 million) and higher energy efficiency related revenues ($22.5 million). Partially offsetting these increases were lower generation service revenues ($26.6 million) and the absence of the sale of oil to an external buyer ($20.8 million) in the second quarter of 2012, which resulted in a benefit to PSNH customers through lower ES rates and did not impact earnings.
The portion of electric distribution segment revenues that impacts earnings increased $4.7 million due primarily to an increase resulting from the favorable impact of the PSNH 2010 rate case settlement related to the additional increase to annualized rates that was effective July 1, 2012 and an increase in sales volume.
An increase in natural gas segment revenues due primarily to an increase in firm natural gas sales volume.
Improved transmission segment revenues resulting from a higher level of investment in transmission infrastructure and the recovery of higher overall expenses, which are tracked and result in a related increase in revenues. The increase in expenses
53
is directly related to the increase in transmission plant including costs associated with higher property taxes, depreciation and operation and maintenance expenses.
Our Operating Revenues increased in the first half of 2013, as compared to the first half of 2012, due primarily to the addition of NSTAR, effective April 10, 2012, which included first quarter 2013 electric distribution revenues of approximately $530 million, transmission revenues of approximately $60 million, natural gas revenues of approximately $200 million and other revenues of approximately $10 million, and the consolidation of CYAPC and YAEC revenues of approximately $15 million. Excluding the impact of the addition of NSTAR's operations and the consolidation of CYAPC and YAEC, our Operating Revenues increased due to the following:
Higher electric distribution segment revenues related to the portions that are included in regulatory commission approved tracking mechanisms that recover certain incurred costs and do not impact earnings. The tracking mechanisms allow for rates to be changed periodically with overcollections refunded to customers or undercollections recovered from customers in future periods. The tracked electric distribution revenues increased due primarily to higher retail transmission revenues ($78.9 million), higher energy related revenues ($24.3 million), higher energy efficiency related revenues ($26.1 million), and higher federally mandated congestion charge delivery-related revenues ($15.2 million). Partially offsetting these increases were lower generation service revenues ($35.5 million) and the absence of the sale of oil to an external buyer ($20.8 million) in the second quarter of 2012, which resulted in a benefit to PSNH customers through lower ES rates and did not impact earnings.
An increase in natural gas segment revenues due primarily to an increase in firm natural gas sales volume related to colder weather in the first quarter of 2013, as compared to the first quarter of 2012.
The portion of electric distribution segment revenues that impacts earnings increased $20.5 million due primarily to an increase resulting from the favorable impact of the PSNH 2010 rate case settlement related to the additional increase to annualized rates that was effective July 1, 2012 and an increase in sales volume.
Improved transmission segment revenues resulting from a higher level of investment in transmission infrastructure and the recovery of higher overall expenses, which are tracked and result in a related increase in revenues. The increase in expenses is directly related to the increase in transmission plant including costs associated with higher property taxes, depreciation and operation and maintenance expenses.
Purchased Power, Fuel and Transmission decreased in the second quarter of 2013, as compared to the same period in 2012, and increased for the first half of 2013, as compared to the same period in 2012, due primarily to the following:
Three Months EndedIncrease/(Decrease)
Six Months EndedIncrease/(Decrease)
The addition of NSTAR's operations
n/a
321.4
Lower costs related to RECs and energy purchase costs at PSNH
(41.4)
Lower GSC supply costs, partially offset by deferred fuel and CfD
costs at CL&P
(21.9)
(14.4)
Lower transmission costs at WMECO
(4.3)
An increase related to higher firm natural gas sales
An increase in transmission costs, partially offset by a decrease in
Basic Service costs at NSTAR Electric
Other and eliminations
(12.2)
Operations and Maintenance decreased for the three and six months ended June 30, 2013, as compared to the same periods in 2012, due primarily to the following:
Three Months Ended
Six Months Ended
The addition of NSTAR’s operations
123.6
Partially offset by:
Absence of merger and settlement agreement costs
(146.4)
(148.2)
Electric distribution segment costs
(26.5)
General and administrative costs
(11.8)
Transmission segment costs
(9.4)
Natural gas segment costs
(6.1)
Depreciation increased for the three and six months ended June 30, 2013, as compared to the same periods in 2012, due primarily to the addition of NSTAR's utility plant balances ($54.2 million for the six months) and an increase as a result of the consolidation of CYAPC and YAEC ($13.7 million for the six months). Excluding the impact of NSTAR and the consolidation of CYAPC and YAEC, depreciation increased due primarily to higher utility plant balances resulting from completed construction projects placed into service.
54
Amortization of Regulatory Assets, Net increased for the three and six months ended June 30, 2013, as compared to the same periods in 2012, due primarily to the addition of NSTAR’s amortization ($45.8 million for the six months) and an increase in the recovery of transition costs at NSTAR Electric ($31.4 million).
Amortization of RRBs decreased for the three and six months ended June 30, 2013, as compared to the same periods in 2012, due primarily to the maturity of NSTAR Electric's, PSNH's, and WMECO's RRBs in 2013, partially offset by the addition of NSTAR Electric’s amortization ($15.1 million for the six months).
Energy Efficiency Programs increased for the three and six months ended June 30, 2013, as compared to the same periods in 2012, due primarily to the addition of NSTAR's operations ($68.6 million for the six months), as well as an increase in energy efficiency costs in accordance with the three-year program guidelines established by the DPU at NSTAR Electric and WMECO. All costs are fully recovered through DPU tracking mechanisms and therefore do not impact earnings.
Taxes Other Than Income Taxes increased for the three and six months ended June 30, 2013, as compared to the same periods in 2012, due primarily to the addition of NSTAR's operations ($37.8 million for the six months). In addition, there was an increase in property taxes as a result of an increase in Property, Plant and Equipment related to our regulated capital programs and an increase in the property tax rates, and an increase in the Connecticut gross earnings tax attributable to an increase in gross earnings.
Interest Expense increased for the six months ended June 30, 2013, as compared to the same period in 2012, due primarily to the addition of NSTAR’s operations ($22 million), partially offset by a decrease in Other Interest due primarily to a favorable impact from the resolution of a state income tax audit in the first quarter of 2013.
95.6
26.1
69.5
216.1
82.0
(a) Percent greater than 100 percent is not shown as it is not meaningful.
Income Tax Expense increased for the three months ended June 30, 2013, as compared to the same period in 2012, due primarily to higher pre-tax earnings ($17.1 million), prior year settlement agreement impacts ($41.0 million), and prior year merger impacts ($14.5 million), partially offset by state and other impacts ($3.1 million).
Income Tax Expense increased for the first half of 2013, as compared to the same period in 2012, due primarily to higher pre-tax earnings ($81.5 million), prior year settlement agreement impacts ($41.0 million), prior year merger impacts ($14.5 million), and state and other impacts ($1.9 million), partially offset by state audit impacts ($4.8 million).
55
RESULTS OF OPERATIONS – THE CONNECTICUT LIGHT AND POWER COMPANY
The following table 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, 2013 and 2012:
569.3
562.1
1,193.4
1,154.1
39.3
184.8
196.8
414.1
417.7
(3.6)
(0.9)
123.8
205.4
(81.6)
(39.7)
338.4
(105.8)
(31.3)
8.7
87.6
82.6
(2.8)
(84.8)
11.2
20.8
43.7
53.7
117.7
432.5
521.7
(89.2)
906.9
1,001.9
(95.0)
(9.5)
136.8
40.4
96.4
286.5
134.3
88.2
(a) Percent greater than 100 percent not shown as it is not meaningful.
CL&P's retail sales were as follows:
Retail Sales in GWh
5,194
5,181
10,875
10,608
267
CL&P's Operating Revenues increased in the three and six months ended June 30, 2013, as compared to the same periods of 2012, due primarily to:
A $21.1 million and $47.8 million increase, respectively, in distribution revenues related to the portions that are included in PURA approved tracking mechanisms that recover certain incurred costs and do not impact earnings. The tracking mechanisms allow for rates to be changed periodically with overcollections refunded to customers or undercollections recovered from customers in future periods. The tracked distribution revenues increased due primarily to higher retail transmission revenues ($23.1 million and $51.2 million, respectively), higher federally mandated congestion charge delivery-related revenues ($6.6 million and $15.2 million, respectively) and higher competitive transition assessment revenues ($3 million and $6.3 million, respectively). Partially offsetting these increases were lower generation service revenues ($7.7 million and $17.8 million, respectively) and lower combined public benefits charge revenues ($6.1 million and $11.3 million, respectively).
An $11.8 million and $16.6 million increase, respectively, in transmission revenues resulting from an increased level of investment in transmission infrastructure and the recovery of higher overall expenses, which are subject to tracking mechanisms or processes and result in a related increase in revenues. The increase in expenses is directly related to the increase in transmission plant, including costs associated with higher property taxes, depreciation, and operation and maintenance expenses.
A $1.3 million and $11.5 million increase, respectively, in the portion of distribution revenues that impacts earnings due primarily to a 0.3 percent and 2.5 percent, respectively, increase in sales volume due primarily to colder weather in the first quarter of 2013, as compared to the first quarter of 2012.
Purchased Power and Transmission decreased in the three and six months ended June 30, 2013, as compared to the same periods in 2012, due primarily to the following:
GSC Supply Costs
(9.3)
(25.0)
Purchased Power Contracts
Transmission Costs
(5.9)
12.0
Deferred Fuel Costs
CfD Costs
The decrease in GSC supply costs was due primarily to lower average supply prices. The GSC supply costs are the contractual amounts CL&P must pay to various suppliers that have been awarded the right to supply SS and LRS load through a competitive solicitation process. These costs are included in PURA approved tracking mechanisms and do not impact earnings.
Operations and Maintenance decreased for the three and six months ended June 30, 2013, as compared to the same periods in 2012, due primarily to the absence in 2013 of costs recognized in the second quarter of 2012 as a result of the Connecticut settlement agreement (established a $40 million storm fund reserve and provided a $25 million bill credit to customers). In addition, there were lower general and administrative expenses ($6.4 million and $11.4 million, respectively), lower distribution vegetation management costs, and the absence in 2013 of the amortization of a regulatory deferral allowed in the 2010 rate case decision ($2 million and $4 million, respectively), partially offset by an increase in distribution maintenance expense ($3.7 million for the three months).
Taxes Other Than Income Taxes increased in the first half of 2013, as compared to the first half of 2012, due primarily to an increase in the Connecticut gross earnings tax attributable to an increase in gross earnings ($4.8 million) and an increase in property taxes as a result of an increase in Property, Plant and Equipment related to CL&P’s capital program and an increase in the property tax rates ($3.5 million).
Interest Expense decreased for the six months ended June 30, 2013, as compared to the same period in 2012, due primarily to a decrease in Other Interest due primarily to a favorable impact from the resolution of a state income tax audit in the first quarter of 2013 and lower interest on short term loans, partially offset by higher Interest on Long-term Debt.
37.8
37.7
77.0
47.2
(a) Percent greater than 100 percent not shown since it is not meaningful.
Income Tax Expense increased for the three and six months ended June 30, 2013, as compared to the same periods in 2012, due primarily to higher pre-tax earnings ($11.8 million and $24.6 million, respectively) and the absence in 2013 of the impact of costs recognized as a result of the Connecticut settlement agreement ($26.6 million for both periods), partially offset by state audit impacts ($2.9 million for the six months).
LIQUIDITY
CL&P had cash flows provided by operating activities of $178.2 million in the first half of 2013, compared with $47.5 million in the first half of 2012. The improved cash flows were due primarily to the absence in the first half of 2013 of $154.4 million in cash disbursements for storm costs associated with Tropical Storm Irene and the October 2011 snowstorm in the first half of 2012, the absence of approximately $27 million in 2012 CL&P customer bill credits associated with the October 2011 snowstorm and the absence of approximately $25 million in 2012 CL&P customer bill credits associated with the Connecticut settlement agreement. Partially offsetting improved cash flows were income tax refunds of $6 million in the first half of 2013, compared with income tax refunds of $32.6 million in the first half of 2012, and the change in traditional working capital amounts principally due to the changes in timing of accounts receivable.
Cash capital expenditures included 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. CL&P’s cash capital expenditures totaled $184.9 million in the first half of 2013, compared with $220.7 million in the first half of 2012.
On January 15, 2013, CL&P issued $400 million of 2.5 percent first mortgage bonds that will mature on January 15, 2023. The proceeds, net of issuance costs, were used to repay CL&P’s December 31, 2012 revolving credit facility borrowings of $89 million and intercompany loans related to NU's commercial paper program borrowings of $305.8 million.
Other financing activities in the first half of 2013 included $76 million in common stock dividends to NU parent.
CL&P uses available capital resources to fund its construction expenditures, meet debt requirements, pay costs, including storm-related costs, pay dividends and fund other corporate obligations. The current growth in CL&P’s transmission construction expenditures utilizes a significant amount of cash for projects that have a long-term return on investment and recovery period. In addition, CL&P operates in an environment where recovery of its electric construction expenditures takes place over an extended period of time. This impacts the timing of the revenue stream designed to fully recover the total investment plus a return on the equity portion of the cost and related financing costs. These factors have resulted in CL&P’s current liabilities exceeding current assets by approximately $231 million as of June 30, 2013.
As of June 30, 2013, approximately $125 million of CL&P's current liabilities relates to long-term debt that will be paid in the next 12 months. CL&P, with its strong credit ratings, has several options available in the financial markets to repay or refinance this maturity with the issuance of new long-term debt. CL&P will reduce its short-term borrowings with cash received from operating cash flows or with the issuance of new long-term debt, as deemed appropriate given its capital requirements and maintenance of its credit rating and profile. Management expects the future operating cash flows of CL&P, along with the access to financial markets, will be sufficient to meet any future operating requirements and capital investment forecasted opportunities.
57
RESULTS OF OPERATIONS – NSTAR ELECTRIC COMPANY AND SUBSIDIARY
The following table 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, 2013 and 2012:
1,162.7
1,091.1
71.6
6.6
403.9
399.5
4.4
180.2
(77.0)
(29.9)
90.9
85.2
100.5
46.0
54.5
45.2
(30.2)
(66.8)
82.4
24.3
62.7
59.2
955.6
974.7
(19.1)
207.1
116.4
90.7
77.9
NSTAR Electric's retail sales were as follows:
10,198
10,054
144
NSTAR Electric's Operating Revenues increased in the first half of 2013, as compared to the first half of 2012, due primarily to:
A $66.7 million increase in distribution revenues related to the portions that are included in DPU approved tracking mechanisms that recover certain incurred costs and do not impact earnings. The tracking mechanisms allow for rates to be changed periodically with overcollections refunded to customers or undercollections recovered from customers in future periods. This increase primarily related to higher retail transmission revenues ($30.6 million), higher energy efficiency program revenues ($25.7 million), higher transition revenues ($19.7 million), and higher PAM revenues ($4.6 million), partially offset by lower Basic Service revenues ($13.9 million).
A $4.9 million increase in the portion of distribution revenues that impacts earnings due primarily to a 1.4 percent increase in retail sales.
Purchased Power and Transmission increased in the first half of 2013, as compared to the first half of 2012, due primarily to the following:
24.1
Basic Service Costs
(20.9)
The increase in transmission costs was due primarily to a higher regional rate leading to higher regional network service costs, as well as higher forward capacity market reliability charges. The decrease in Basic Service costs was due primarily to lower average supply prices. These costs are included in DPU approved tracking mechanisms and do not impact earnings.
Operations and Maintenance decreased in the first half of 2013, as compared to the first half of 2012, due primarily to the absence of the cumulative adjustment recorded in 2012 to establish a reserve against the regulatory asset related to Basic Service bad debt costs ($28 million). In addition, first quarter 2012 adjustments were recognized for changes in accounting estimates related primarily to the allowance for doubtful accounts, workers’ compensation, employee medical benefits, and general liability claims ($18.7 million). In addition, a bill credit to customers ($15 million) was recorded in the second quarter of 2012 as a result of the Massachusetts settlement agreement. Also contributing to the decrease in costs was a March 2012 substation fire in the Back Bay/Prudential area of Boston ($10.1 million) and lower general and administrative costs ($2.2 million).
Amortization of Regulatory Assets, Net, increased in the first half of 2013, as compared to the first half of 2012, due primarily to an increase in the recovery of transition costs.
Amortization of Rate Reduction Bonds decreased in the first half of 2013, as compared to the first half of 2012, due to the maturity of the RRBs in March 2013.
Energy Efficiency Programs increased in the first half of 2013, as compared to the first half of 2012, 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 tracking mechanisms and therefore do not impact earnings.
44.6
(5.2)
(11.7)
Interest on RRBs
2.2
(81.8)
(6.7)
(11.4)
41.2
35.4
(6.5)
Interest Expense decreased in the first half of 2013, as compared to the first half of 2012, due primarily to lower average long-term bond rates, partially offset by lower regulatory interest income primarily from deferred transition costs.
68.9
32.8
36.1
Income Tax Expense increased in the first half of 2013, as compared to the first half of 2012, due primarily to higher pre-tax earnings including state tax impacts ($30.5 million) and the absence in 2013 of the impact of costs recognized in the second quarter of 2012 as a result of the Massachusetts settlement agreement ($5.9 million).
CAPITAL EXPENDITURES
A summary of capital expenditures, including amounts incurred but not paid, cost of removal, AFUDC, and the capitalized portions of pension expense, is as follows:
60.5
Distribution:
82.8
114.3
192.3
174.8
NSTAR Electric had cash flows provided by operating activities of $48.1 million in the first half of 2013, compared with $115.9 million in the first half of 2012 (amounts are net of RRB payments, which are included in financing activities). The decrease in operating cash flows was due primarily to an increase in cash disbursements for storm costs in the first half of 2013 associated with the February 2013 blizzard, as compared to cash disbursements for storm costs in the first half of 2012 associated with Tropical Storm Irene and the October 2011 snowstorm, and a $16.7 million increase in pension contributions in the first half of 2013, as compared to the first half of 2012. The change in traditional working capital amounts, principally due to the changes in timing of accounts receivable, also contributed to the decrease in operating cash flows. Partially offsetting the negative cash flow impact was the absence in 2013 of $15 million in bill credits provided to customers in connection with the Massachusetts settlement agreement in the first half of 2012.
59
RESULTS OF OPERATIONS – PUBLIC SERVICE COMPANY OF NEW HAMPSHIRE AND SUBSIDIARY
The following table 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, 2013 and 2012:
489.9
498.1
151.1
163.2
(12.1)
(7.4)
122.1
133.4
(8.5)
45.5
19.8
(7.9)
(28.5)
33.9
377.5
405.7
(28.2)
(7.0)
112.4
92.4
21.6
PSNH's retail sales were as follows:
3,837
3,761
76
PSNH's Operating Revenues decreased in the first half of 2013, as compared to the first half of 2012, due primarily to the absence of the sale of oil to an external buyer ($20.8 million) in the second quarter of 2012, which resulted in a benefit to customers through lower ES rates and did not impact earnings. This decrease was partially offset by the following:
An $8.4 million increase in the portion of distribution revenues that impacts earnings due primarily to the favorable impact of the 2010 rate case settlement related to the additional increase to annualized rates that was effective July 1, 2012, and a 2 percent increase in sales volume due primarily to colder than normal weather in the first quarter of 2013, as compared to the first quarter of 2012.
A $6.1 million increase in distribution revenues related to the portions that are included in NHPUC approved tracking mechanisms that recover certain incurred costs and do not impact earnings. The tracking mechanisms allow for rates to be changed periodically with overcollections refunded to customers or undercollections recovered from customers in future periods. This increase was due primarily to higher energy related revenues ($15.4 million) and higher retail transmission revenues ($7.3 million). These higher revenues were partially offset by lower stranded cost recovery revenues ($18 million).
A $3 million increase in transmission revenues resulting from an increased level of investment in transmission infrastructure and the recovery of higher overall expenses, which are tracked and result in a related increase in revenues. The increase in expenses is directly related to the increase in transmission plant, including costs associated with higher property taxes, depreciation, and operation and maintenance expenses.
Purchased Power, Fuel and Transmission decreased in the first half of 2013, as compared to the first half of 2012, due primarily to a decrease in costs related to RECS, partially offset by an increase in fuel costs resulting from an increase in sales and an increase in transmission costs resulting from an increase in regional transmission rates leading to higher RNS costs.
Operations and Maintenance decreased in the first half of 2013, as compared to the first half of 2012, due primarily to lower general and administrative costs ($4.6 million), a decrease in RRB charges that are included in NHPUC approved tracking mechanisms ($2.7 million), and lower transmission maintenance costs ($1.5 million).
Amortization of Rate Reduction Bonds decreased in the first half of 2013, as compared to the first half of 2012, due to the maturity of RRBs in May 2013.
Taxes Other Than Income Taxes increased in the first half of 2013, as compared to the first half of 2012, due primarily to an increase in property taxes as a result of an increase in Property, Plant and Equipment related to PSNH’s capital program and an increase in the property tax rates.
Interest Expense decreased in the first half of 2013, as compared to the first half of 2012, due primarily to lower Interest on Rate Reduction Bonds due to the maturity of the RRBs in May 2013.
34.6
26.9
7.7
Income Tax Expense increased in the first half of 2013, as compared to the first half of 2012, due primarily to higher pre-tax earnings ($7.5 million) and higher state taxes ($1.1 million).
PSNH had cash flows provided by operating activities of $109.4 million in the first half of 2013, compared with $42.5 million in the first half of 2012 (amounts are net of RRB payments, which are included in financing activities). The improved cash flows were due primarily to a reduction in NUSCO Pension Plan contributions of $43.5 million in the first half of 2013, as compared to the first half of 2012, income tax refunds of $12.1 million in the first half of 2013, compared with income tax payments of $13.7 million in the first half of 2012, the absence of $7.7 million of cash disbursements for storm costs associated with Tropical Storm Irene and the October 2011 snowstorm in the first half of 2012, the favorable impact of the 2010 rate case settlement related to the additional increase to annualized rates that was effective July 1, 2012 and the change in traditional working capital amounts principally due to the changes in timing of accounts payable. Offsetting these positive cash flow impacts were increased coal and fuel inventories in the first half of 2013 creating a negative cash flow impact of $15.2 million, as compared to reduced coal and fuel inventories in the first half of 2012 creating a positive cash flow impact of $17.7 million, and changes in the timing of other current assets and liabilities.
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RESULTS OF OPERATIONS – WESTERN MASSACHUSETTS ELECTRIC COMPANY
The following table 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, 2013 and 2012:
240.0
220.9
19.1
8.6
72.3
73.3
(6.3)
18.3
Amortization of Regulatory Assets/
(Liabilities), Net
16.2
54.3
12.5
9.9
26.3
172.0
167.2
68.0
14.3
26.6
WMECO's retail sales were as follows:
1,798
1,781
WMECO's Operating Revenues increased in the first half of 2013, as compared to the first half of 2012, due primarily to:
A $14.5 million increase in transmission revenues resulting from an increased level of investment in transmission infrastructure, primarily related to the NEEWS projects, and the recovery of higher overall expenses, which are tracked and result in a related increase in revenues. The increase in expenses is directly related to the increase in transmission plant, including costs associated with higher property taxes, depreciation, and operation and maintenance expenses.
An $8.9 million increase in distribution revenues related to the portions that are included in DPU approved tracking mechanisms that recover certain incurred costs and do not impact earnings. The tracking mechanisms allow for rates to be changed periodically with overcollections refunded to customers or undercollections recovered from customers in future periods. Included in these amounts are Basic Service, pension, transition and energy efficiency program costs.
Operations and Maintenance decreased in the first half of 2013, as compared to the first half of 2012, due primarily to the absence in 2013 of bill credits to customers ($3 million) made in the second quarter of 2012 as a result of the Massachusetts settlement agreement. In addition, there were lower general and administrative expenses ($2.3 million), lower customer uncollectible expenses ($1.1 million) and lower routine distribution maintenance expenses ($0.8 million). Partially offsetting these decreases was an increase in pension costs ($2.3 million), which are recovered through DPU approved tracking mechanisms and have no earnings impact.
Depreciation increased in the first half of 2013, as compared to the first half of 2012, due primarily to higher utility plant balances resulting from completed construction projects placed into service related to WMECO's capital programs.
Energy Efficiency Programs increased in the first half of 2013, as compared to the first half of 2012, due primarily to an increase in expenses attributable to an increase in spending in accordance with the three-year program guidelines established by the DPU. All costs are fully recovered through DPU tracking mechanisms and therefore do not impact earnings.
Taxes Other Than Income Taxes increased in the first half of 2013, as compared to the first half of 2012, due primarily to an increase in property taxes as a result of an increase in Property, Plant and Equipment related to WMECO’s capital program and an increase in the property tax rates.
16.4
Income Tax Expense increased in the first half of 2013, as compared to the first half of 2012, due primarily to higher pre-tax earnings ($4.2 million) and the absence in 2013 of the impact of costs recognized as a result of the Massachusetts settlement agreement ($1.2 million).
WMECO had cash flows provided by operating activities of $110 million in the first half of 2013, compared with $35 million in the first half of 2012 (amounts are net of RRB payments, which are included in financing activities). The improved cash flows were due primarily to income tax refunds of $32.4 million in the first half of 2013, compared with income tax refunds of $1.5 million in the first half of 2012, the absence in the first half of 2013 of $14.7 million in cash disbursements for storm costs made in the first half of 2012, the absence of $3 million in bill credits to customers associated with the Massachusetts settlement agreement, and changes in traditional working capital amounts principally due to the changes in timing of accounts payable.
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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. The remaining unregulated wholesale portfolio held by Select Energy includes contracts that are market risk-sensitive, including a wholesale energy sales contract through December 2013 with an agency comprised of municipalities. As Select Energy's contract volumes are winding down, and as the wholesale energy sales contract is substantially hedged against price risks, we have limited exposure to commodity price risks. We have not entered into any energy contracts for trading purposes.
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 suppliers that include independent power producers, 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 our unsecured debt ratings were reduced to below investment grade by either Moody’s or S&P, certain of our contracts would require additional collateral to be provided to counterparties and independent system operators. If such an event occurred as of June 30, 2013, we would have been required to provide additional collateral. We would have been and remain 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 2012 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 2012 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, 2013 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, 2013, other than changes resulting from the April 10, 2012 merger with NSTAR, that have materially affected, or are reasonably likely to materially affect, internal controls over financial reporting.
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 2012 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 2012 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 Item 1A, "Risk Factors," in our 2012 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 2012 Form 10-K.
ITEM 2.
UNREGISTERED SALES OF EQUITY SECURITIES AND USE OF PROCEEDS
The following table discloses purchases of shares of our common stock made by us or on our behalf for the periods shown below.
Period
Total Number of Shares Purchased
Average Price Paid per Share
Total Number of Shares Purchased asPart of Publicly Announced Plans or Programs
Approximate DollarValue of Shares thatMay Yet Be Purchased Under the Plans and Programs (at month end)
April 1 – April 30, 2013
6,332
44.23
May 1 – May 31, 2013
12,407
44.65
June 1 – June 30, 2013
88,714
40.50
107,453
41.20
ITEM 6.
EXHIBITS
Each document described below is incorporated by reference by the registrant(s) listed to the files identified, unless designated with a (*), which exhibits are filed herewith.
Exhibit No.
Listing of Exhibits (NU)
Fifth Supplemental Indenture, dated as of May 1, 2013, between NU and The Bank of New York Mellon Trust Company, N.A., as Trustee, establishing the terms of the Senior Notes, Series E, due 2018, and the Senior Notes, Series F, due 2023 (Incorporated by reference to Exhibit 4.1, NU Current Report on Form 8-K filed May 16, 2013, File No. 001-05324)
*12
Ratio of Earnings to Fixed Charges
*31
Certification of Thomas J. May, President and Chief Executive Officer of Northeast Utilities, 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 2, 2013
*31.1
Certification of James J. Judge, Executive Vice President and Chief Financial Officer of Northeast Utilities, 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 2, 2013
*32
Certification of Thomas J. May, President and Chief Executive Officer of Northeast Utilities and James J. Judge, Executive Vice President and Chief Financial Officer of Northeast Utilities, pursuant to 18 U.S.C. Section 1350 as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, dated August 2, 2013
Listing of Exhibits (CL&P)
Certification of Leon J. Olivier, Chief Executive Officer of The Connecticut Light and Power Company, 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 2, 2013
Certification of James J. Judge, Executive Vice President and Chief Financial Officer of The Connecticut Light and Power Company, 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 2, 2013
Certification of Leon J. Olivier, Chief Executive Officer of The Connecticut Light and Power Company and James J. Judge, Executive Vice President and Chief Financial Officer of The Connecticut Light and Power Company, pursuant to 18 U.S.C. Section 1350 as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, dated August 2, 2013
Listing of Exhibits (NSTAR Electric)
Form of Floating Rate Debentures due 2016. (Incorporated by reference to Exhibit 4, NSTAR Electric Company Current Report on Form 8-K filed May 22, 2013, File No. 001-02301)
Certification of Leon J. Olivier, Chief Executive Officer of NSTAR Electric Company, 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 2, 2013
Certification of James J. Judge, Executive Vice President and Chief Financial Officer of NSTAR Electric Company, 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 2, 2013
Certification of Leon J. Olivier, Chief Executive Officer of NSTAR Electric Company and James J. Judge, Executive Vice President and Chief Financial Officer of NSTAR Electric Company, pursuant to 18 U.S.C. Section 1350 as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, dated August 2, 2013
Listing of Exhibits (PSNH)
Certification of Leon J. Olivier, Chief Executive Officer of Public Service Company of New Hampshire, 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 2, 2013
Certification of James J. Judge, Executive Vice President and Chief Financial Officer of Public Service Company of New Hampshire, 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 2, 2013
Certification of Leon J. Olivier, Chief Executive Officer of Public Service Company of New Hampshire and James J. Judge, Executive Vice President and Chief Financial Officer of Public Service Company of New Hampshire, pursuant to 18 U.S.C. Section 1350 as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, dated August 2, 2013
Listing of Exhibits (WMECO)
Certification of Leon J. Olivier, Chief Executive Officer of Western Massachusetts Electric Company, 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 2, 2013
Certification of James J. Judge, Executive Vice President and Chief Financial Officer of Western Massachusetts Electric Company, 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 2, 2013
Certification of Leon J. Olivier, Chief Executive Officer of Western Massachusetts Electric Company and James J. Judge, Executive Vice President and Chief Financial Officer of Western Massachusetts Electric Company, pursuant to 18 U.S.C. Section 1350 as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, dated August 2, 2013
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
67
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 2, 2013
By:
/s/
Jay S. Buth
Vice President, Controller and
Chief Accounting Officer
NSTAR ELECTRIC COMPANY
PUBLIC SERVICE COMPANY OF NEW HAMPSHIRE
69