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 September 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 October 31, 2013
Northeast UtilitiesCommon shares, $5.00 par value
315,094,075 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
FERC ALJ
FERC Administrative Law Judge
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 – September 30, 2013 and December 31, 2012
1
Condensed Consolidated Statements of Income – Three and Nine Months Ended September 30, 2013 and 2012
3
Condensed Consolidated Statements of Comprehensive Income – Three and Nine Months Ended September 30, 2013 and 2012
Condensed Consolidated Statements of Cash Flows – Nine Months Ended September 30, 2013 and 2012
4
The Connecticut Light and Power Company (Unaudited)
Condensed Balance Sheets – September 30, 2013 and December 31, 2012
5
Condensed Statements of Income – Three and Nine Months Ended September 30, 2013 and 2012
7
Condensed Statements of Comprehensive Income – Three and Nine Months Ended September 30, 2013 and 2012
Condensed Statements of Cash Flows – Nine Months Ended September 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 (Unaudited)
21
iii
ITEM 2 – Management’s Discussion and Analysis of Financial Condition and Results of Operations for the following companies:
Northeast Utilities and Subsidiaries
41
57
NSTAR Electric Company and Subsidiary
60
Public Service Company of New Hampshire and Subsidiary
63
65
ITEM 3 – Quantitative and Qualitative Disclosures About Market Risk
67
ITEM 4 – Controls and Procedures
PART II – OTHER INFORMATION
ITEM 1 – Legal Proceedings
68
ITEM 1A – Risk Factors
ITEM 2 – Unregistered Sales of Equity Securities and Use of Proceeds
ITEM 6 – Exhibits
69
SIGNATURES
71
iv
This Page Intentionally Left Blank
v
NORTHEAST UTILITIES AND SUBSIDIARIES
CONDENSED CONSOLIDATED BALANCE SHEETS
(Unaudited)
September 30,
December 31,
(Thousands of Dollars)
2013
2012
ASSETS
Current Assets:
Cash and Cash Equivalents
$
57,941
45,748
Receivables, Net
784,498
792,822
Unbilled Revenues
174,097
216,040
Fuel, Materials and Supplies
304,698
267,713
Regulatory Assets
474,198
705,025
Prepayments and Other Current Assets
222,700
199,947
Total Current Assets
2,018,132
2,227,295
Property, Plant and Equipment, Net
17,187,896
16,605,010
Deferred Debits and Other Assets:
4,882,381
5,132,411
Goodwill
3,519,401
Marketable Securities
468,094
400,329
Derivative Assets
88,887
90,612
Other Long-Term Assets
279,527
327,766
Total Deferred Debits and Other Assets
9,238,290
9,470,519
Total Assets
28,444,318
28,302,824
The accompanying notes are an integral part of these unaudited condensed consolidated financial statements.
LIABILITIES AND CAPITALIZATION
Current Liabilities:
Notes Payable
1,343,000
1,120,196
Long-Term Debt - Current Portion
608,346
763,338
Accounts Payable
554,010
764,350
Regulatory Liabilities
224,416
134,115
Other Current Liabilities
648,658
861,691
Total Current Liabilities
3,378,430
3,643,690
Rate Reduction Bonds
-
82,139
Deferred Credits and Other Liabilities:
Accumulated Deferred Income Taxes
3,954,246
3,463,347
520,732
540,162
Derivative Liabilities
766,804
882,654
Accrued Pension, SERP and PBOP
1,808,896
2,130,497
Other Long-Term Liabilities
897,997
967,561
Total Deferred Credits and Other Liabilities
7,948,675
7,984,221
Capitalization:
Long-Term Debt
7,444,192
7,200,156
Noncontrolling Interest - Preferred Stock of Subsidiaries
155,568
Equity:
Common Shareholders' Equity:
Common Shares
1,665,098
1,662,547
Capital Surplus, Paid In
6,185,805
6,183,267
Retained Earnings
2,064,401
1,802,714
Accumulated Other Comprehensive Loss
(67,387)
(72,854)
Treasury Stock
(330,464)
(338,624)
Common Shareholders' Equity
9,517,453
9,237,050
Total Capitalization
17,117,213
16,592,774
Total Liabilities and Capitalization
2
CONDENSED CONSOLIDATED STATEMENTS OF INCOME
For the Three Months Ended September 30,
For the Nine Months Ended September 30,
(Thousands of Dollars, Except Share Information)
Operating Revenues
1,892,590
1,861,529
5,523,475
4,589,835
Operating Expenses:
Purchased Power, Fuel and Transmission
645,881
602,751
1,881,992
1,540,110
Operations and Maintenance
386,700
395,531
1,089,960
1,187,471
Depreciation
149,105
144,475
463,635
369,798
Amortization of Regulatory Assets, Net
70,046
43,835
178,668
74,851
Amortization of Rate Reduction Bonds
43,044
42,581
102,144
Energy Efficiency Programs
106,097
98,326
306,010
209,089
Taxes Other Than Income Taxes
135,499
120,662
391,846
319,559
Total Operating Expenses
1,493,328
1,448,624
4,354,692
3,803,022
Operating Income
399,262
412,905
1,168,783
786,813
Interest Expense:
Interest on Long-Term Debt
84,911
86,459
256,205
233,352
Interest on Rate Reduction Bonds
1,681
422
5,168
Other Interest
2,565
2,221
(6,044)
7,336
Interest Expense
87,476
90,361
250,583
245,856
Other Income, Net
8,945
4,324
21,655
14,904
Income Before Income Tax Expense
320,731
326,868
939,855
555,861
Income Tax Expense
109,351
117,360
325,442
199,379
Net Income
211,380
209,508
614,413
356,482
Net Income Attributable to Noncontrolling Interests
1,879
1,880
5,803
5,253
Net Income Attributable to Controlling Interest
209,501
207,628
608,610
351,229
Basic Earnings Per Common Share
0.66
1.93
1.33
Diluted Earnings Per Common Share
1.32
Dividends Declared Per Common Share
0.37
0.34
1.10
0.97
Weighted Average Common Shares Outstanding:
Basic
315,291,346
314,806,441
315,191,752
264,636,636
Diluted
316,218,239
315,805,796
316,061,131
265,353,377
CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME
Other Comprehensive Income, Net of Tax:
Qualified Cash Flow Hedging Instruments
509
516
1,539
1,455
Changes in Unrealized Gains/(Losses) on
Other Securities
(38)
217
(810)
411
Changes in Funded Status of Pension, SERP
and PBOP Benefit Plans
1,611
1,445
4,738
4,611
Other Comprehensive Income, Net of Tax
2,082
2,178
5,467
6,477
Comprehensive Income Attributable to Noncontrolling
Interests
(1,879)
(1,880)
(5,803)
(5,253)
Comprehensive Income Attributable to Controlling Interest
211,583
209,806
614,077
357,706
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS
Operating Activities:
Adjustments to Reconcile Net Income to Net Cash Flows
Provided by Operating Activities:
Deferred Income Taxes
334,225
186,181
Pension, SERP and PBOP Expense
146,803
160,209
Pension and PBOP Contributions
(338,301)
(237,123)
Regulatory Over/(Under) Recoveries, Net
66,239
(26,236)
Other
3,158
6,640
Changes in Current Assets and Liabilities:
Receivables and Unbilled Revenues, Net
(98,432)
(27,677)
(13,134)
32,887
Taxes Receivable/Accrued, Net
(28,609)
26,302
(112,512)
(208,308)
Other Current Assets and Liabilities, Net
(81,766)
(20,145)
Net Cash Flows Provided by Operating Activities
1,176,968
796,005
Investing Activities:
Investments in Property, Plant and Equipment
(1,073,759)
(1,081,750)
Proceeds from Sales of Marketable Securities
487,729
232,911
Purchases of Marketable Securities
(541,070)
(252,762)
Decrease in Special Deposits
69,259
6,199
Other Investing Activities
(1,137)
34,066
Net Cash Flows Used in Investing Activities
(1,058,978)
(1,061,336)
Financing Activities:
Cash Dividends on Common Shares
(341,720)
(267,356)
Cash Dividends on Preferred Stock
(5,802)
(5,149)
(Decrease)/Increase in Short-Term Debt
(172,000)
654,250
Issuance of Long-Term Debt
1,350,000
300,000
Retirements of Long-Term Debt
(840,600)
(267,561)
Retirements of Rate Reduction Bonds
(82,139)
(95,225)
Other Financing Activities
(13,536)
13,262
Net Cash Flows (Used in)/Provided by Financing Activities
(105,797)
332,221
Net Increase in Cash and Cash Equivalents
12,193
66,890
Cash and Cash Equivalents - Beginning of Period
6,559
Cash and Cash Equivalents - End of Period
73,449
THE CONNECTICUT LIGHT AND POWER COMPANY
CONDENSED BALANCE SHEETS
Cash
15,253
341,749
284,787
Accounts Receivable from Affiliated Companies
1,733
6,641
73,687
85,353
147,076
185,858
Materials and Supplies
58,124
64,603
61,277
26,413
698,899
653,656
6,326,225
6,152,959
2,021,974
2,158,363
88,018
91,499
86,498
2,201,491
2,335,473
9,226,615
9,142,088
The accompanying notes are an integral part of these unaudited condensed financial statements.
Notes Payable to Affiliated Companies
342,900
99,296
150,000
125,000
170,683
262,857
Accounts Payable to Affiliated Companies
46,401
52,326
Obligations to Third Party Suppliers
65,580
67,344
Accrued Taxes
60,643
60,109
81,988
32,119
94,123
96,931
78,520
125,662
1,090,838
921,644
1,471,547
1,336,105
107,964
124,319
756,437
865,571
291,257
304,696
160,368
197,434
2,787,573
2,828,125
2,591,012
2,737,790
Preferred Stock Not Subject to Mandatory Redemption
116,200
Common Stockholder's Equity:
Common Stock
60,352
1,641,487
1,640,149
940,647
839,628
(1,494)
(1,800)
Common Stockholder's Equity
2,640,992
2,538,329
5,348,204
5,392,319
6
CONDENSED STATEMENTS OF INCOME
648,420
658,111
1,841,846
1,812,218
Purchased Power and Transmission
253,152
241,046
667,266
658,743
127,104
141,913
359,759
480,286
44,786
41,863
132,356
124,451
Amortization of Regulatory Assets/(Liabilities), Net
(27)
8,656
11,223
19,912
24,544
25,237
68,211
68,205
64,979
59,687
182,676
168,667
514,538
518,402
1,421,491
1,520,264
133,882
139,709
420,355
291,954
32,845
31,429
98,163
94,646
2,439
2,162
801
6,223
35,284
33,591
98,964
100,869
3,861
2,889
10,946
8,636
102,459
109,007
332,337
199,721
36,136
34,121
113,149
63,917
66,323
74,886
219,188
135,804
CONDENSED STATEMENTS OF COMPREHENSIVE INCOME
111
333
Changes in Unrealized Gains/(Losses) on Other
Securities
(1)
14
110
119
306
347
Comprehensive Income
66,433
75,005
219,494
136,151
CONDENSED STATEMENTS OF CASH FLOWS
89,084
97,224
Pension, SERP and PBOP Expense, Net of PBOP Contributions
16,182
18,394
24,061
(13,804)
(8,759)
(10,701)
(44,523)
(21,632)
841
21,410
(101,949)
(173,107)
(29,106)
(49,750)
308,598
148,201
(294,638)
(332,323)
2,013
13,707
(292,625)
(318,616)
Cash Dividends on Common Stock
(114,000)
(100,486)
(4,169)
Issuance of Long Term Debt
400,000
(125,000)
(Decrease)/Increase in Notes Payable to Affiliates
(62,200)
314,275
Decrease in Short-Term Debt
(89,000)
(31,000)
(6,352)
(1,636)
(721)
176,984
Net Increase in Cash
15,252
6,569
Cash - Beginning of Period
Cash - End of Period
6,570
NSTAR ELECTRIC COMPANY AND SUBSIDIARY
15,470
13,695
263,055
202,025
70,279
160,176
48,570
41,377
189,754
347,081
54,105
28,086
641,233
792,440
4,923,410
4,735,297
1,538,222
1,444,870
59,267
87,382
1,597,489
1,532,252
7,162,132
7,059,989
156,000
276,000
301,650
1,650
157,375
168,611
97,992
247,061
32,049
104,668
82,521
47,539
128,846
144,433
956,433
989,962
43,493
1,463,285
1,321,026
251,005
244,224
Accrued Pension
380,688
360,932
Payable to Affiliated Companies
64,752
70,221
145,032
183,190
2,304,762
2,179,593
1,499,378
1,600,911
43,000
992,625
1,365,934
1,210,405
2,358,559
2,203,030
3,900,937
3,846,941
10
753,879
693,653
1,916,557
1,784,755
255,244
222,753
659,140
622,265
97,069
83,329
277,261
340,547
45,441
42,494
136,323
127,692
72,740
41,888
173,289
87,912
22,581
15,054
67,742
58,798
55,969
161,180
138,360
32,610
30,520
95,275
89,689
561,902
499,534
1,517,522
1,474,207
191,977
194,119
399,035
310,548
19,860
22,386
59,261
66,953
853
399
3,106
(1,324)
(4,704)
(8,011)
(16,137)
18,536
18,535
51,649
53,922
2,126
551
3,275
1,778
175,567
176,135
350,661
258,404
68,558
69,373
137,499
102,220
107,009
106,762
213,162
156,184
Bad Debt Expense
19,012
53,254
26,358
(20,250)
Pension and PBOP Expense, Net of Pension Contributions
(55,195)
1,394
Regulatory (Under)/Over Recoveries, Net
(11,299)
62,075
(48,291)
(29,154)
(80,575)
(61,528)
7,961
7,264
(6,345)
44,142
6,856
(81,292)
Accounts Receivable from/Payable to Affiliates, Net
(59,173)
(41,760)
(19,547)
58,890
317,590
432,565
(330,635)
(298,424)
37,899
25,234
575
375
(292,161)
(272,815)
(56,000)
(188,700)
(1,633)
(1,470)
(Decrease)/Increase in Notes Payable
(120,000)
104,500
200,000
(1,650)
(688)
(43,493)
(84,367)
(878)
13,336
Net Cash Flows Used in Financing Activities
(23,654)
(157,389)
1,775
2,361
9,373
11,734
PUBLIC SERVICE COMPANY OF NEW HAMPSHIRE AND SUBSIDIARY
5,604
2,493
78,464
87,164
1,182
723
31,081
39,982
Taxes Receivable
12,074
17,177
125,801
95,345
67,716
62,882
6,464
22,205
328,386
327,971
2,409,039
2,352,515
301,368
351,059
55,953
83,052
357,321
434,111
3,094,746
3,114,597
228,500
63,300
50,000
60,814
62,864
18,279
21,337
23,394
23,002
Renewable Portfolio Standards Compliance Obligations
6,701
17,383
54,315
50,950
442,003
238,836
29,294
490,863
441,577
52,867
52,418
104,557
220,129
43,866
47,896
692,153
762,020
839,104
997,932
701,659
701,052
428,660
395,118
(8,833)
(9,655)
1,121,486
1,086,515
1,960,590
2,084,447
218,608
256,949
708,550
755,051
46,668
76,008
197,765
239,173
69,477
67,547
191,606
200,960
22,919
22,264
68,433
65,282
225
(6,356)
(1,745)
(6,179)
16,112
19,748
43,855
3,990
4,030
11,036
10,824
18,706
16,046
52,640
47,406
161,985
195,651
539,483
601,321
56,623
61,298
169,067
153,730
10,345
11,434
32,951
34,537
564
(154)
2,366
521
609
1,384
1,301
10,866
12,607
34,181
38,204
Other Income/(Loss), Net
792
(353)
2,454
2,237
46,549
48,338
137,340
117,763
18,196
21,106
52,797
48,037
28,353
27,232
84,543
69,726
290
291
872
(2)
(47)
24
(3)
288
302
822
898
28,641
27,534
85,365
70,624
57,066
39,108
20,427
19,508
(112,964)
(94,169)
(1,346)
1,718
Amortization of Regulatory Liabilities, Net
7,165
18,699
8,047
(4,274)
(30,456)
20,178
5,103
4,506
29,148
(18,567)
7,220
18,358
160,389
177,749
(155,676)
(161,021)
Decrease in Notes Receivable from Affiliates
55,900
22,039
2,599
(53)
(99)
(133,690)
(102,621)
(51,000)
(74,675)
Retirements of Long-term Debt
(108,950)
Increase in Notes Payable to Affiliates
165,200
44,200
(29,294)
(41,265)
456
(349)
(23,588)
(72,089)
3,111
3,039
56
3,095
WESTERN MASSACHUSETTS ELECTRIC COMPANY
3,157
49,056
47,297
29,231
164
13,046
16,192
15,513
37,854
42,370
24,570
27,352
10,195
7,963
167,111
156,852
1,352,705
1,290,498
194,744
221,752
33,195
30,342
20,246
23,625
248,185
275,719
1,768,001
1,723,069
79,800
31,900
55,000
40,432
68,141
7,521
7,103
22,400
21,037
9,416
8,404
18,718
24,809
178,287
216,394
9,352
392,360
303,111
11,914
9,686
30,791
36,099
26,503
40,148
461,568
389,044
549,617
550,270
390,645
390,412
180,618
160,577
(3,600)
(3,846)
578,529
558,009
1,128,146
1,108,279
18
121,795
112,470
361,763
333,331
38,797
32,028
111,095
105,297
26,148
24,765
70,213
75,214
9,426
7,464
27,707
22,154
(1,412)
1,021
(598)
634
4,352
7,780
13,127
12,222
9,190
28,462
19,679
7,696
5,505
20,188
15,365
92,877
84,325
264,847
251,470
28,918
28,145
96,916
81,861
5,814
5,783
17,846
17,454
272
177
1,029
417
714
777
1,550
6,231
6,769
18,800
20,033
926
685
2,349
1,965
23,613
22,061
80,465
63,793
8,588
7,977
30,424
24,385
15,025
14,084
50,041
39,408
85
84
254
253
(8)
86
246
257
15,110
14,170
50,287
39,665
79,401
30,565
11,685
(8,733)
Amortization of Regulatory (Liabilities)/Assets, Net
(544)
1,755
(32,231)
(10,482)
16,412
7,337
20,260
(28,510)
(9,857)
(9,185)
170,056
58,070
(127,352)
(218,184)
53,552
65,131
(54,042)
(65,664)
11,000
7,401
308
(120,441)
(207,409)
(30,000)
(9,431)
(55,000)
47,900
172,500
Retirement of Rate Reduction Bonds
(9,352)
(13,141)
(7)
(54)
(46,459)
149,874
3,156
535
536
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 its subsidiaries. NU's wholly owned regulated utility subsidiaries consist of 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 these 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 nine months ended September 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 and second quarter 2013 combined Quarterly Reports on Form 10-Q and the 2012 combined Annual Report on Form 10-K of NU, CL&P, NSTAR Electric, PSNH and WMECO, 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 September 30, 2013 and December 31, 2012, the results of operations and comprehensive income for the three and nine months ended September 30, 2013 and 2012, and the cash flows for the nine months ended September 30, 2013 and 2012. The results of operations and comprehensive income for the three and nine months ended September 30, 2013 and 2012, and the cash flows for the nine months ended September 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.
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 was effective beginning in the first quarter of 2013 and was applied prospectively. For further information, see Note 11, "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 was 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 that 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 ASU 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 September 30, 2013
As of December 31, 2012
NU
182.5
165.5
85.8
77.6
45.9
44.1
7.7
6.8
10.4
8.5
D.
Fair Value Measurements
Fair value measurement guidance is applied to derivative contracts recorded at fair value and to the marketable securities held in trusts. Fair value measurement guidance is also applied to investment valuations used to calculate the funded status of pension and PBOP plans 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 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 10, "Fair Value of Financial Instruments," to the financial statements.
22
E.
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 as well as 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.
F.
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 Nine Months Ended
September 30, 2013
September 30, 2012
37.5
36.4
108.9
102.0
35.5
34.4
97.3
91.5
Certain sales taxes are also collected by NU's companies that serve customers in 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.
G.
Supplemental Cash Flow Information
Non-cash investing activities include plant additions included in Accounts Payable as follows:
As of September 30, 2012
122.9
139.9
36.6
31.9
21.5
16.9
20.1
13.8
35.1
H.
Severance Benefits
In the third quarter of 2013, NU recorded severance benefit expenses of $9.2 million in connection with the partial outsourcing of information technology functions made as part of ongoing post-merger integration. As of September 30, 2013, the severance accrual totaled $14.2 million and was included in Other Current Liabilities on the accompanying balance sheet.
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.
Regulatory Assets: The components of regulatory assets are as follows:
Benefit Costs
2,256.0
2,452.1
Regulatory Assets Offsetting Derivative Liabilities
770.3
885.6
531.1
537.6
Storm Restoration Costs
621.0
547.7
Income Taxes, Net
587.5
516.2
Securitized Assets
37.4
232.6
Contractual Obligations
170.9
217.6
Buy Out Agreements for Power Contracts
76.0
92.9
Regulatory Tracker Deferrals
163.3
190.1
Asset Retirement Obligations
93.0
88.8
Other Regulatory Assets
50.1
76.2
Total Regulatory Assets
5,356.6
5,837.4
Less: Current Portion
474.2
705.0
Total Long-Term Regulatory Assets
4,882.4
5,132.4
23
Electric
509.3
824.3
199.6
103.8
563.2
781.2
223.7
116.0
Regulatory Assets Offsetting
755.3
11.6
0.3
866.2
14.9
3.0
455.9
461.5
439.4
114.0
27.9
39.7
413.9
55.8
34.5
43.5
385.3
84.8
36.5
42.1
367.5
47.1
36.2
31.0
205.1
19.7
7.8
20.0
6.4
4.6
64.0
22.8
70.1
5.9
85.9
7.0
83.6
52.5
12.2
71.4
49.3
31.1
30.7
14.7
3.7
29.4
14.2
3.5
28.7
9.2
31.7
17.2
12.6
2,169.1
1,728.0
369.1
2,344.3
1,792.0
414.0
264.2
147.1
189.8
67.7
37.9
185.9
347.1
62.9
42.4
2,022.0
1,538.2
301.4
194.7
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, Storm Sandy and the February 2013 blizzard. For PSNH, costs incurred associated with these storms are recorded in Other Long-Term Assets. The storm restoration cost regulatory asset balance at PSNH primarily reflects costs incurred for storms in 2008 and 2010, which are currently being recovered in rates. Management believes the storm restoration costs meet the criteria for specific cost recovery in Connecticut, Massachusetts and New Hampshire and as a result, are probable of recovery. Each operating company is seeking recovery of these deferred storm restoration costs through its applicable regulatory recovery process.
Regulatory Costs in Other Long-Term Assets: The Regulated companies had $95.1 million ($3.4 million for CL&P, $31.3 million for NSTAR Electric, $37.3 million for PSNH, and $7.9 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 September 30, 2013 and December 31, 2012, respectively, which were included in Other Long-Term Assets on the balance sheets. These amounts represent incurred costs for which specific recovery has not yet been approved 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
434.3
440.8
168.6
95.1
AFUDC - Transmission
68.3
70.0
Other Regulatory Liabilities
73.9
68.4
Total Regulatory Liabilities
745.1
674.3
224.4
134.1
Total Long-Term Regulatory Liabilities
520.7
540.2
31.2
247.2
49.8
44.2
240.3
51.2
73.2
51.0
10.7
22.1
39.1
14.4
20.4
19.0
55.0
4.0
9.3
56.6
4.1
30.6
31.3
15.8
2.9
16.5
32.9
3.8
2.4
190.0
333.5
76.3
34.3
156.4
291.7
75.4
82.0
82.5
23.4
22.4
32.1
47.5
23.0
21.0
108.0
251.0
52.9
11.9
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
11,735.4
11,438.2
Distribution - Natural Gas
2,352.4
2,274.2
Transmission
6,009.0
5,541.1
Generation
1,142.1
1,146.6
Electric and Natural Gas Utility
21,238.9
20,400.1
Other (1)
505.2
429.3
Property, Plant and Equipment, Gross
21,744.1
20,829.4
Less: Accumulated Depreciation
(5,331.0)
(5,065.1)
(192.9)
(171.5)
Total Accumulated Depreciation
(5,523.9)
(5,236.6)
16,220.2
15,592.8
Construction Work in Progress
967.7
1,012.2
Total Property, Plant and Equipment, Net
17,187.9
16,605.0
These assets represent unregulated property and are primarily comprised of building improvements at RRR, software, hardware and equipment at NUSCO and telecommunications assets at NSTAR Communications, Inc.
Distribution
4,836.1
4,622.7
1,569.7
746.3
4,691.3
4,539.9
1,520.1
724.2
2,969.6
1,664.5
613.2
715.8
2,796.1
1,529.7
599.2
583.7
1,121.0
21.1
1,125.5
Property, Plant and
Equipment, Gross
7,805.7
6,287.2
3,303.9
1,483.2
7,487.4
6,069.6
3,244.8
1,329.0
(1,778.7)
(1,634.5)
(1,001.7)
(265.7)
(1,698.1)
(1,540.1)
(954.0)
(252.1)
6,027.0
4,652.7
2,302.2
1,217.5
5,789.3
4,529.5
2,290.8
1,076.9
299.2
270.7
106.8
135.2
363.7
205.8
61.7
213.6
Total Property, Plant and
Equipment, Net
6,326.2
4,923.4
2,409.0
1,352.7
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 and nonderivative contracts. Many of the derivative contracts meet the definition of, and are designated as, "normal purchases or normal sales" (normal) under the applicable accounting guidance.
Derivative contracts that are not designated as normal are recorded at fair value as current or long-term Derivative Assets or Derivative Liabilities on the balance sheets. For the Regulated companies, Regulatory Assets or Regulatory Liabilities are recorded for the 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.
25
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:
Commodity Supply and
Net Amount Recorded as
Price Risk Management
Netting (1)
Derivative Asset/(Liability)
Current Derivative Assets:
Level 3:
CL&P (1)
17.3
(10.1)
7.2
0.4
1.3
Total Current Derivative Assets
8.9
Long-Term Derivative Assets:
139.5
(51.5)
88.0
0.9
Total Long-Term Derivative Assets
140.4
88.9
Current Derivative Liabilities:
Level 2:
PSNH (1)
(0.5)
0.2
(0.3)
Other (1) (2)
(7.4)
(94.1)
(1.6)
(0.1)
Total Current Derivative Liabilities
(103.7)
(103.5)
Long-Term Derivative Liabilities:
(756.4)
(10.4)
Total Long-Term Derivative Liabilities
(766.8)
17.7
(12.0)
5.7
5.5
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
As of September 30, 2013 and December 31, 2012, NU had $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 1D, "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 both CL&P and UI 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 0.2 million MWh of energy through November 2013.
WMECO has a renewable energy contract to purchase 0.1 million MWh of energy per year through 2029 with a facility that is expected to achieve commercial operation by June 2014.
As of September 30, 2013 and December 31, 2012, NU had NYMEX future contracts in order to reduce variability associated with the purchase price of approximately 10.2 million and 11.5 million MMBtu of natural gas, respectively.
As of September 30, 2013 and December 31, 2012, NU had approximately 5 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 current change in fair value, primarily recovered through rates from customers, associated with NU’s derivative contracts not designated as hedges:
Location of Amounts
Amounts Recognized on Derivatives
Recognized on Derivatives
Balance Sheet:
11.7
48.8
(25.0)
Statement of Income:
(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 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:
Additional Collateral
Fair Value Subject
Required if
to Credit Risk
Downgraded Below
Contingent Features
Investment Grade
(6.7)
13.4
(15.3)
17.4
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.
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.
27
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:
$45 - $93 per MWh
2018 - 2029
$43 - $90 per MWh
2018 - 2028
$52 - $56 per MWh
2018 - 2020
$50 - $55 per MWh
Capacity Prices:
$1.40 - $10.53 per kW-Month
2017 - 2029
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 - $87 per REC
2013 - 2029
$25 - $85 per REC
2013 - 2028
$25 - $71 per REC
2013 - 2018
2014 - 2029
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 nine months ended September 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
(788.1)
(932.1)
(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:
1.2
8.3
0.8
49.6
(30.1)
Settlements
21.3
55.9
56.0
Fair Value as of End of Period
(764.8)
(902.3)
28
NSTAR Electric(1)
(775.8)
(13.1)
(0.7)
(910.7)
(15.8)
(13.5)
Net Realized/Unrealized Gains/(Losses)
Included in Regulatory Assets
(1.2)
0.5
1.5
(2.8)
1.4
9.8
21.7
1.0
22.6
(755.3)
(11.6)
(890.9)
(13.8)
(3.7)
(866.2)
(14.9)
(931.6)
(3.4)
(7.3)
45.1
(23.8)
(13.2)
3.6
65.8
2.7
64.5
2.8
NSTAR Electric amounts are included in NU consolidated from the date of the merger, April 10, 2012, through September 30, 2012.
5.
MARKETABLE SECURITIES
NU maintains a supplemental benefit trust to fund certain 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 owned by 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 $54.3 million and $47 million as of September 30, 2013 and December 31, 2012, respectively, and are included in current Marketable Securities. Net gains on these securities of $3 million and $7.3 million for the three and nine months ended September 30, 2013, respectively, were recorded in Other Income, Net on the statements of income. These amounts were net gains of $1.9 million and $4.6 million for the three and nine months ended September 30, 2012, respectively. 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)
306.1
(3.8)
303.8
Equity Securities (2)
164.0
40.9
204.9
Debt Securities
57.8
266.6
13.3
279.8
145.5
57.7
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 $403.1 million and $340.4 million as of September 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
29
and 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 September 30, 2013, the contractual maturities of available-for-sale debt securities are as follows:
Less than one year (1)
67.1
65.3
24.4
24.6
One to five years
76.6
26.4
26.3
Six to ten years
58.4
57.3
2.5
Greater than ten years
104.6
4.5
4.4
Total Debt Securities
Amounts in the Less than one year NU category include securities in the CYAPC and YAEC 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
259.2
212.5
Money Market Funds
40.0
40.2
5.2
Total Level 1
252.7
U.S. Government Issued Debt Securities
(Agency and Treasury)
74.9
69.9
16.6
18.7
Corporate Debt Securities
48.9
33.0
15.1
Asset-Backed Debt Securities
30.4
28.5
9.6
10.9
Municipal Bonds
93.7
93.8
8.8
Other Fixed Income Securities
15.9
4.9
4.3
Total Level 2
263.8
239.6
Total Marketable Securities
563.0
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.
30
6.
SHORT-TERM AND LONG-TERM DEBT
Limits: The amount of short-term borrowings that may be incurred by CL&P and WMECO is subject to periodic approval by the FERC. On July 31, 2013, the FERC approved the short-term debt application of CL&P and WMECO for issuances in the amounts of $600 million and $300 million, respectively, effective January 1, 2014 through December 31, 2015.
Credit Agreements and Commercial Paper Programs: On September 6, 2013, NU parent, CL&P, NSTAR LLC, NSTAR Gas, PSNH, WMECO and Yankee Gas amended their joint five-year $1.15 billion revolving credit facility dated July 25, 2012, by increasing the aggregate principal amount available thereunder by $300 million to $1.45 billion, extending the expiration date from July 25, 2017 to September 6, 2018, and increasing CL&P's borrowing sublimit from $300 million to $600 million. At the same time, effective September 6, 2013, the CL&P $300 million revolving credit facility was terminated.
On September 6, 2013, NSTAR Electric amended its five-year $450 million revolving credit facility dated July 25, 2012 by extending the expiration date from July 25, 2017 to September 6, 2018.
On September 6, 2013, the NU parent $1.15 billion commercial paper program was increased by $300 million to $1.45 billion.
As of September 30, 2013 and December 31, 2012, NU had approximately $1.2 billion and $1.15 billion, respectively, in short-term borrowings outstanding under the NU parent commercial paper program, which provides $263 million of available borrowing capacity as of September 30, 2013. The weighted-average interest rate on these borrowings as of September 30, 2013 and December 31, 2012 was 0.268 percent and 0.46 percent, respectively, which is generally based on money market rates. As of September 30, 2013, there were intercompany loans from NU of $342.9 million to CL&P, $228.5 million to PSNH and $79.8 million to WMECO. As of December 31, 2012, there were intercompany loans from NU of $405.1 million to CL&P, $63.3 million to PSNH, and $31.9 million to WMECO. As of September 30, 2013 and December 31, 2012, NSTAR Electric had $156 million and $276 million, respectively, in short-term borrowings outstanding under its commercial paper program, leaving $294 million and $174 million, respectively, of available borrowing capacity. The weighted-average interest rate on these borrowings as of September 30, 2013 and December 31, 2012 was 0.134 percent and 0.31 percent, respectively, which is generally based on money market rates.
Amounts outstanding under the commercial paper programs are included in Notes Payable for NU and NSTAR Electric and classified in current liabilities on the balance sheets as all borrowings are 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: 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 parent 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 were 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 using short-term debt.
On May 13, 2013, NU parent issued $750 million of Senior Notes, consisting of $300 million of Series E Senior Notes at a coupon rate of 1.45 percent that will mature on May 1, 2018 and $450 million of Series F Senior Notes 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 and the NU parent $300 million floating rate Series D Senior Notes that matured 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 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. The debentures have a coupon rate reset quarterly based on 3-month LIBOR plus a credit spread of 0.24 percent. The interest rate as of September 30, 2013 was 0.5032 percent.
On September 1, 2013, WMECO repaid at maturity, $55 million of 5.00 percent Series A Senior Notes using short-term debt.
On September 3, 2013, CL&P redeemed at par $125 million of 1.25 percent Series B 2011 PCRBs that were subject to mandatory tender for purchase using short-term debt.
On September 20, 2013, NU parent repaid at maturity, $300 million of Floating Rate Series D Senior Notes with proceeds from NU parent’s issuance on May 13, 2013 of $750 million of Series E and Series F Senior Notes.
On August 29, 2013, NSTAR Electric filed an application with the DPU requesting authorization to issue up to $800 million in long-term debt for the two-year period ending December 31, 2015.
31
On September 26, 2013, the NHPUC issued an order, effective October 8, 2013, approving PSNH's request to issue up to $315 million in long-term debt through December 31, 2014, and to refinance $89.3 million 2001 Series B PCRBs through its existing maturity of May 2021.
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 operating 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 current liabilities exceeding current assets by approximately $1.4 billion, $392 million, $315 million, $114 million and $11 million at NU, CL&P, NSTAR Electric, PSNH and WMECO, respectively, as of September 30, 2013.
As of September 30, 2013, approximately $577 million of NU's current liabilities related to long-term debt that will be paid in the next 12 months, primarily consisting of $150 million for CL&P, $302 million for NSTAR Electric and $50 million for PSNH. 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 forecasted capital investment opportunities.
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
25.6
76.7
61.1
Interest Cost
51.7
53.3
155.0
144.7
Expected Return on Plan Assets
(69.5)
(59.5)
(208.5)
(161.3)
Actuarial Loss
47.4
158.1
125.0
Prior Service Cost
1.1
2.0
6.1
Total Net Periodic Benefit Expense
61.3
66.2
184.3
175.6
Capitalized Pension Expense
18.3
19.2
54.9
49.5
4.2
11.3
11.8
14.3
35.4
(11.1)
(41.6)
(28.1)
6.5
10.3
19.5
25.5
Prior Service Credit
(1.5)
(0.9)
Net Transition Obligation Cost
3.1
9.0
8.1
20.5
Capitalized PBOP Expense
2.6
5.1
7.6
For the Three Months Ended September 30, 2013
For the Three Months Ended September 30, 2012
Electric(1)
6.3
3.3
5.4
12.1
14.5
5.8
12.9
(18.4)
(21.1)
(9.2)
(4.3)
(17.7)
(16.4)
(7.2)
(4.1)
13.9
15.7
Prior Service Cost/(Credit)
16.1
14.1
Intercompany Allocations
(2.1)
2.1
1.7
8.4
1.9
32
For the Nine Months Ended September 30, 2013
For the Nine Months Ended September 30, 2012
24.8
16.3
22.7
36.3
17.8
7.5
38.5
7.9
(55.4)
(63.3)
(26.2)
(13.0)
(52.8)
(49.2)
(12.3)
42.0
43.6
16.2
37.0
47.3
8.0
(0.4)
43.0
48.4
18.0
41.7
64.6
7.3
33.6
(6.2)
6.0
32.0
21.6
5.6
3.9
20.2
23.6
2.3
(2.5)
(1.3)
(0.6)
(2.3)
(1.1)
1.8
2.2
0.7
6.9
3.4
(7.6)
(3.9)
(1.7)
(6.8)
5.3
6.2
NSTAR Electric's pension amounts do not include SERP expense. NSTAR Electric pension amounts are included in NU consolidated from the date of the merger, April 10, 2012, through September 30, 2012.
The net periodic postretirement expense allocated to NSTAR Electric was $1.2 million and $8.5 million for the three months ended September 30, 2013 and 2012, respectively, and $3.5 million and $25.6 million for the nine months ended September 30, 2013 and 2012, respectively.
Contributions: For the nine months ended September 30, 2013, NU contributed $202.7 million to the NUSCO Pension Plan, $108.3 million of which was contributed by PSNH, and NSTAR Electric contributed $82 million to the NSTAR Pension Plan. NU contributed $53.6 million to the PBOP Plans for the nine months ended September 30, 2013.
8.
INCOME TAXES
2013 Massachusetts: On July 24, 2013, Massachusetts enacted a law that changes the income tax rate applicable to utility companies effective January 1, 2014, from 6.5 percent to 8 percent. The tax law change required NU to remeasure its deferred taxes and resulted in NU increasing its deferred tax liability with an offsetting regulatory asset of approximately $61 million at its utility companies ($46.4 million at NSTAR Electric and $9.8 million at WMECO).
2013 Federal: On September 13, 2013, the Internal Revenue Service issued final Tangible Property regulations. The final regulations are meant to simplify, clarify and make more administrable the previously issued temporary and proposed regulations. In the third quarter of 2013, CL&P recorded an after-tax valuation allowance of $10.5 million against its deferred tax assets as a result of these regulations. NU continues to evaluate the implications of these new regulations, including several new elections. Therefore, a change to the valuation allowance at CL&P could result once NU completes the review of the impact of the final regulations.
9.
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.
33
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)
77
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 $32.4 million and $34.5 million as of September 30, 2013 and December 31, 2012, respectively, and relates primarily to the natural gas business segment.
Long-Term Contractual Arrangements
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 September 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.
October - December
2014
2015
2016
2017
Thereafter
Total
Yankee Billings
13.1
17.9
6.6
Renewable Energy
49.9
50.9
51.4
52.0
626.0
831.4
Other Long-Term Renewable Energy Contracts: On September 20, 2013, NSTAR Electric and WMECO, along with two other Massachusetts utilities, signed a long-term commitment, as required by state regulation, to purchase wind power from six wind farms in Maine and New Hampshire for a combined estimated generating capacity of approximately 550 MW. Over the life of the 15- to 20-year contracts, the utilities will pay an average price of less than $0.08 per kWh. On September 19, 2013, CL&P, along with another Connecticut utility, signed long-term commitments, as required by state regulation, to purchase approximately 250 MW of wind power from a Maine wind farm and 20 MW of solar power from sites in Connecticut, at a combined average price of less than $0.08 per kWh. The table above does not include these commitments for the purchase of renewable energy, as such commitments are contingent on the future construction of the respective energy facilities.
Deferred Contractual Obligations
Spent Nuclear Fuel Litigation - DOE Phase I Damages - On May 1, 2013, CYAPC, YAEC and MYAPC filed applications with the FERC to reduce rates in their wholesale power contracts through the application of the DOE proceeds for the benefit of customers. In its June 27, 2013 order, FERC granted the proposed rate reductions, and changes to the terms of the wholesale power contracts to become effective on July 1, 2013. In accordance with the FERC order, CL&P, NSTAR Electric, PSNH and WMECO began receiving the benefit of the DOE proceeds, and the benefits have been or will be passed on to customers.
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 or cash flows from operations as a result of these various guarantees and indemnifications.
34
The following table summarizes NU's guarantees of its subsidiaries, including CL&P, NSTAR Electric, PSNH and WMECO, as of September 30, 2013:
Maximum Exposure
Subsidiary
Description
Expiration Dates
Various
Surety Bonds
2013 - 2015 (1)
New England Hydro Companies' Long-Term Debt
Unspecified
NUSCO and RRR
Lease Payments for Vehicles and Real Estate
18.8
2019 and 2024
Surety Bonds, Performance Guarantees and Insurance Bond
62.3
Surety bond expiration dates reflect termination dates, the majority of which will be renewed or extended.
The maximum exposure includes $3.8 million related to performance guarantees on wholesale purchase contracts, which expire December 31, 2013. Also included in the maximum exposure is $57.5 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 NETOs, including CL&P, NSTAR Electric, PSNH and WMECO, is unjust and unreasonable. The complainants asserted 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 ALJ after settlement negotiations were unsuccessful in August 2012.
Hearings before the FERC ALJ were held in May 2013, followed by the filing of briefs by the complainants, the Massachusetts municipal electric utilities (late interveners to the case), the FERC trial staff and the NETOs. The NETOs recommended that 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.
On August 6, 2013, the FERC ALJ issued an initial decision, finding that the current base ROE is not reasonable under the standard application of FERC methodology, but leaving policy considerations and additional adjustments to the FERC. Using the established FERC methodology, the FERC ALJ determined that a separate base ROE should be set for the refund period and the prospective period. The FERC ALJ found those base ROEs to be 10.6 percent and 9.7 percent, respectively. The FERC may adjust the prospective period base ROE in its final decision to reflect movement in 10-year Treasury bond rates from when the case was filed (April 2013) to the date of the final decision. The parties filed briefs on this decision to the FERC, and a decision from the FERC is expected in 2014. Though NU cannot predict the ultimate outcome of this proceeding, during the third quarter of 2013, the Company recorded a series of reserves at its electric subsidiaries to recognize the potential financial impact from the FERC ALJ's initial decision for the refund period. As a result, the aggregate after-tax charge to earnings totaled $14.3 million at NU. This represents reserves of $7.7 million at CL&P, $3.4 million at NSTAR Electric, $1.4 million at PSNH and $1.8 million at WMECO.
On 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, and management is unable to predict the ultimate outcome or the estimated impacts on financial position, results of operations or cash flows, of this complaint.
Management expects the CL&P, NSTAR Electric, PSNH, and WMECO aggregate shareholder equity invested in their transmission facilities to be approximately $2.4 billion at the end of 2013. As a result, each 10 basis point change in the prospective period authorized base ROE would change annual consolidated earnings by an approximate $2.4 million.
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.
35
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.
10.
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 benchmark yields. Adjustable rate long-term debt 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
152.2
8,052.5
8,267.2
7,963.5
8,640.7
82.1
83.0
116.2
110.3
41.9
2,741.0
2,992.0
1,801.0
1,881.9
889.1
934.7
549.6
562.1
110.0
42.2
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.
36
Other Financial Instruments: Investments in marketable securities are carried at fair value. For further information, see Note 1D, "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.
11.
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 PBOPBenefit Plans
AOCI as of January 1, 2013
(57.8)
(72.9)
Other Comprehensive Income Before Reclassifications
Amounts Reclassified from AOCI
4.8
Net Other Comprehensive Income
AOCI as of September 30, 2013
(53.0)
(67.4)
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.
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
Tax Benefit
Qualified Cash Flow Hedging Instruments, Net of Tax
Pension, SERP and PBOP Benefit Plan Costs:
Amortization of Actuarial Losses
Amortization of Prior Service Cost
Total Pension, SERP and PBOP Benefit Plan Costs
Pension, SERP and PBOP Benefit Plan Costs, Net of Tax
(4.8)
Total Amount Reclassified from AOCI, Net of Tax
(6.3)
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.
12.
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 and the respective par values:
Shares
Authorized
Issued
Per Share
Par Value
380,000,000
333,019,517
332,509,383
24,500,000
6,035,205
100,000,000
100
301
1,072,471
434,653
As of September 30, 2013 and December 31, 2012, 18,137,017 and 18,455,749 NU common shares were held as treasury shares, respectively.
37
13.
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
9,406.6
9,067.6
211.4
209.5
Dividends on Common Shares
(114.9)
(107.6)
Dividends on Preferred Stock
(1.9)
Issuance of Common Shares
Other Transactions, Net
12.8
Net Income Attributable to
Noncontrolling Interests
Other Comprehensive Income
Balance - End of Period
9,517.5
9,176.9
9,237.1
4,012.7
4,015.7
614.4
356.5
Purchase Price of NSTAR
5,038.3
Other Equity Impacts of
Merger with NSTAR
(346.9)
(267.8)
(5.8)
(5.1)
10.2
Contributions to NPT
20.3
14.
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 September 30, 2013 and 2012. For the nine months ended September 30, 2013 and 2012, there were 2,100 and 5,688, respectively, antidilutive share awards excluded from the computation.
The following table sets forth the components of basic and diluted EPS:
(Millions of Dollars, except share information)
207.6
608.6
351.2
Dilutive Effect
926,893
999,355
869,379
716,741
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
38
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).
15.
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 nine months ended September 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.
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 nine months ended September 30, 2013 and 2012 is as follows:
Natural Gas
Eliminations
1,508.6
97.1
234.1
(159.7)
1,892.6
Depreciation and Amortization
(159.6)
(34.5)
(11.2)
(219.1)
Other Operating Expenses
(1,064.1)
(89.4)
(73.4)
(206.8)
159.5
(1,274.2)
Operating Income/(Loss)
284.9
(8.7)
126.2
(5.5)
399.3
Net Income/(Loss) Attributable
to Controlling Interest
156.9
58.6
313.1
(308.7)
4,104.4
613.0
721.5
650.4
(565.8)
5,523.5
(488.7)
(50.5)
(100.9)
(52.0)
(684.9)
(2,952.4)
(483.6)
(199.1)
(599.0)
564.3
(3,669.8)
663.3
78.9
421.5
1,168.8
Net Income Attributable
347.5
34.1
215.4
868.7
(857.1)
Cash Flows Used for
Investments in Plant
501.9
91.2
458.2
22.5
1,073.8
39
1,483.7
91.3
235.6
219.5
(168.6)
1,861.5
(172.6)
(12.6)
(29.7)
(17.5)
(231.3)
(1,027.4)
(77.2)
(66.3)
(216.8)
170.4
(1,217.3)
283.7
139.6
(14.8)
412.9
150.5
(4.4)
71.1
313.9
(323.5)
3,499.7
361.5
627.2
582.9
(481.5)
4,589.8
(398.1)
(32.7)
(79.5)
(39.1)
(546.8)
(2,654.4)
(292.9)
(179.5)
(614.5)
485.1
(3,256.2)
447.2
35.9
368.2
(70.7)
786.8
212.1
181.1
511.6
(561.9)
461.3
105.9
476.0
38.6
1,081.8
The following table summarizes NU's segmented total assets:
17,912.9
2,656.8
6,566.1
19,446.9
(18,138.4)
28,444.3
18,047.3
2,717.4
6,187.7
18,832.6
(17,482.2)
28,302.8
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 and Second Quarter 2013 Quarterly Reports on 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 third quarter and first nine months of 2013 and 2012 earnings and EPS excluding certain integration and merger costs related to NU's merger with NSTAR. We use these non-GAAP financial measures to evaluate and to provide details of earnings by business and to more fully compare and explain our third quarter and first nine months 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 September 30, 2013 and December 31, 2012, for the three months ended September 30, 2013 and 2012, and for the nine months ended September 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 $209.5 million, or $0.66 per share, in the third quarter of 2013, and $608.6 million, or $1.93 per share, in the first nine months of 2013, compared with $207.6 million, or $0.66 per share, in the third quarter of 2012 and $351.2 million, or $1.32 per share, in the first nine months of 2012. Excluding integration and merger-related costs, we earned $216.5 million, or $0.69 per share, in the third quarter of 2013, and $619.2 million, or $1.96 per share, in the first nine months of 2013, compared with $220.5 million, or $0.70 per share, in the third quarter of 2012, and $456.7 million, or $1.72 per share, in the first nine months of 2012.
The addition of NSTAR provided an earnings contribution of $225.6 million for the first nine months of 2013, compared to $141 million for the first nine months of 2012. Because the merger closed on April 10, 2012, NSTAR’s first quarter 2012 results are not reflected in NU’s results for the first nine months of 2012.
Our electric distribution segment, which includes generation, earned $156.9 million, or $0.50 per share, in the third quarter of 2013 and $347.5 million, or $1.10 per share, in the first nine months of 2013, compared with earnings of $150.5 million, or $0.48 per share, in the third quarter of 2012 and $212.1 million, or $0.80 per share, in the first nine months of 2012. The results for the third quarter and first nine months of 2012 reflect $0.2 million and $51 million, respectively, of after-tax merger-related costs.
Our transmission segment earned $58.6 million, or $0.18 per share, in the third quarter of 2013 and $215.4 million, or $0.68 per share, in the first nine months of 2013, compared with $71.1 million, or $0.23 per share, in the third quarter of 2012 and $181.1 million, or $0.68 per share, in the first nine months of 2012. The results for the third quarter and first nine months of 2013 reflect an after-tax reserve of $14.3 million. For further information, see the Legislative, Regulatory, Policy and Other Items section in this Executive Summary.
Our natural gas distribution segment had a net loss of $10.4 million, or $0.03 per share, in the third quarter of 2013 and earnings of $34.1 million, or $0.11 per share, in the first nine months of 2013, compared with a net loss of $4.4 million, or $0.02 per share, in the third quarter of 2012 and earnings of $8.3 million, or $0.03 per share, in the first nine months of 2012. The results for the first nine months of 2012 reflect $2.1 million of after-tax merger-related costs.
NU parent and other companies earned $4.4 million, or $0.01 per share, in the third quarter of 2013 and $11.6 million, or $0.04 per share, in the first nine months of 2013, compared with net expenses of $9.6 million, or $0.03 per share, in the third quarter of 2012 and $50.3 million, or $0.19 per share, in the first nine months of 2012. The results for the third quarter and first nine months of 2013 reflect $7 million and $10.6 million, respectively, of after-tax integration costs. The results for the third quarter and first nine months of 2012 reflect $12.7 million and $52.4 million, respectively, of after-tax merger-related costs.
Legislative, Regulatory, Policy and Other Items:
On July 1, 2013, NPT filed the DOE Presidential Permit Application Amendment. The DOE has completed its public scoping meeting process and is currently performing field work and data collection. The $1.4 billion project is expected to be operational by mid-2017.
On August 6, 2013, a FERC ALJ issued an initial decision regarding the September 2011 joint complaint filed at FERC by various New England parties concerning the base ROE earned by New England transmission owners (NETOs). The initial decision found that the current base ROE is not reasonable, but leaves policy considerations and additional adjustments to the FERC, and determined that a separate base ROE of 10.6 percent and 9.7 percent should be set for the refund period (October 1, 2011 through December 31, 2012) and the prospective period (beginning when FERC issues its final decision), respectively. The FERC may adjust the prospective period base ROE in its final decision, expected in 2014, to reflect movement in the capital markets from
42
when the case was filed in April 2013. As a result, in the third quarter of 2013, we recorded a reserve and recognized an after-tax charge of $14.3 million for the potential financial impact from the FERC ALJ's initial decision.
Liquidity:
Cash and cash equivalents totaled $57.9 million as of September 30, 2013, compared with $45.7 million as of December 31, 2012, while investments in property, plant and equipment totaled $1.1 billion in the first nine months of 2013 and 2012.
Cash flows provided by operating activities totaled $1.1 billion in the first nine months of 2013, compared with $700.8 million in the first nine months of 2012 (amounts are net of RRB payments). The improved operating cash flows were due primarily to the addition of NSTAR, a decrease in storm restoration costs and the absence in 2013 of customer bill credits and merger-related costs paid in the first nine months of 2012, partially offset by an increase in Pension Plan cash contributions.
On September 1, 2013, WMECO repaid at maturity $55 million of 5.00 percent Senior Notes using short-term debt. On September 3, 2013, CL&P redeemed at par $125 million of 1.25 percent 2011 PCRBs that were subject to mandatory tender for purchase using short-term debt. On September 20, 2013, NU parent repaid at maturity $300 million of Floating Rate Senior Notes with proceeds from NU parent’s issuance on May 13, 2013 of $750 million of Senior Notes.
The following transactions became effective on September 6, 2013: (1) NU parent and certain of its subsidiaries amended their joint five-year $1.15 billion revolving credit facility dated July 25, 2012 by increasing the aggregate principal amount available thereunder by $300 million to $1.45 billion, extending the expiration date from July 25, 2017 to September 6, 2018, and increasing CL&P's borrowing sublimit from $300 million to $600 million; (2) CL&P’s $300 million revolving credit facility was terminated; (3) NSTAR Electric amended its five-year $450 million revolving credit facility dated July 25, 2012 by extending the expiration date from July 25, 2017 to September 6, 2018; and (4) NU parent’s $1.15 billion commercial paper program was increased by $300 million to $1.45 billion.
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 third quarter and first nine months 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
0.65
217.4
0.69
597.0
1.89
454.6
1.71
NU Parent and Other Companies
0.04
0.01
22.2
0.07
Non-GAAP Earnings
216.5
220.5
0.70
619.2
1.96
456.7
1.72
Integration and Merger-Related Costs (after-tax) (2)
(7.0)
(0.03)
(12.9)
(0.04)
(10.6)
(105.5)
(0.40)
Results include the operations of NSTAR from the date of the merger, April 10, 2012, through September 30, 2012.
The third quarter and first nine months of 2013 costs related to integration costs incurred at NU parent for employee severance accruals, consulting and compensation expenses. The first nine months of 2012 after-tax merger-related costs consisted of Regulated companies’ charges of $53.1 million (for further information, see the Regulated Companies portion of this Overview section), costs of $33.2 million at NU parent related to investment advisory fees, attorney fees, and consulting costs, a $10.3 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.
In the third quarter of 2013, we recorded an after-tax charge for severance benefit expenses of $5.5 million at NU parent in connection with the partial outsourcing of information technology functions made as part of ongoing post-merger integration. Excluding the impact of these integration costs as well as other integration and merger-related costs, our third quarter 2013 earnings decreased by $4 million, as compared to the third quarter of 2012. The decrease was due primarily to the establishment of an after-tax reserve of $14.3 million related to an August 2013 initial decision from a FERC ALJ that lowers the base ROE earned by NETOs for the 15-month period ended December 31, 2012. For further information, see “FERC Regulatory Issues - FERC Base ROE Complaint” in this Management's Discussion and Analysis of Financial Condition and Results of Operations. Partially offsetting that reserve was higher transmission segment earnings as a result of increased investments in the transmission infrastructure and higher retail electric distribution revenues as a result of an increase in third quarter 2013 demand charges, as compared to third quarter 2012, and the favorable impact related to an increase in PSNH rates effective July 1, 2013 as a result of the PSNH 2010 distribution rate case settlement.
Excluding the impacts of integration and merger-related costs, our first nine months of 2013 earnings increased by $162.5 million, as compared to the first nine months of 2012, due primarily to the inclusion of NSTAR effective April 10, 2012 (NSTAR provided an earnings contribution of $225.6 million for the first nine months of 2013, compared to $141 million for the first nine months of 2012), lower overall operations and maintenance costs, higher retail electric and firm natural gas sales, higher transmission segment earnings
43
as a result of increased investments in the transmission infrastructure, and the favorable impact from the resolution of a state income tax audit in the first quarter of 2013. Partially offsetting these favorable earnings impacts were higher depreciation and property tax expense and the establishment of the $14.3 million after-tax reserve related to the August 2013 FERC ALJ initial decision.
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 third quarter and first nine months of 2013 and 2012 is as follows:
For the Three MonthsEnded September 30,
For the Nine MonthsEnded September 30,
Electric Distribution
150.7
263.1
Natural Gas Distribution
Total - Regulated Companies
Merger-Related Costs (after-tax) (2)
(53.1)
Net Income - Regulated Companies
217.2
401.5
The first nine months of 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 previously deferred storm restoration costs associated with Tropical Storm Irene and the October 2011 snowstorm, and a $1.9 million charge related to change in control costs and other compensation costs.
The third quarter 2013 electric distribution segment earnings increased, as compared to the third quarter of 2012, due primarily to higher retail electric distribution revenues as a result of an increase in third quarter 2013 demand charges, as compared to third quarter 2012, and the favorable impact related to an increase in PSNH rates effective July 1, 2013 as a result of the PSNH 2010 distribution rate case settlement. Partially offsetting these favorable earnings impacts were higher depreciation and property tax expense as well as lower retail electric sales as a result of cooler summer weather in the third quarter of 2013, as compared to the same period in 2012.
Excluding $51 million of 2012 after-tax merger-related costs, the first nine months of 2013 electric distribution segment earnings increased, as compared to the first nine months of 2012, 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. The first nine months of 2013 results were also favorably impacted by PSNH rate increases effective July 1, 2012 and July 1, 2013 as a result of the 2010 distribution rate case settlement. Partially offsetting these favorable earnings impacts were higher depreciation and property tax expense.
The third quarter 2013 transmission segment earnings decreased, as compared to the third quarter of 2012, due primarily to the establishment of the $14.3 million after-tax reserve related to the August 2013 FERC ALJ initial decision. Partially offsetting that reserve was increased investments in the transmission infrastructure, including GSRP, which was 98 percent complete as of September 30, 2013.
The first nine months of 2013 transmission segment earnings increased, as compared to the first nine months of 2012, due primarily to the inclusion of NSTAR Electric transmission business’ earnings, increased investments in the transmission infrastructure, including GSRP, and the favorable impact from the resolution of a state income tax audit in the first quarter of 2013, partially offset by the $14.3 million after-tax reserve related to the August 2013 FERC ALJ initial decision.
The third quarter 2013 natural gas distribution segment earnings decreased, as compared to the third quarter of 2012, due primarily to the recognition of higher depreciation and property tax expense at NSTAR Gas and higher overall operations and maintenance costs.
Excluding $2.1 million of 2012 after-tax merger-related costs, the first nine months of 2013 natural gas distribution segment earnings increased, as compared to the first nine months of 2012, due primarily to the inclusion of NSTAR Gas’ earnings, higher firm natural gas sales due primarily to colder weather in the first quarter of 2013, as compared to the first quarter of 2012, the favorable impact related to an increase in Yankee Gas rates effective July 1, 2012 as a result of the Yankee Gas 2011 rate case decision, and lower interest expense, partially offset by the recognition of higher depreciation and property tax expense at NSTAR Gas.
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, 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, as well as percentage changes in Yankee Gas and NSTAR Gas, for the third quarter and first nine months of 2013, as compared to the same periods in 2012, is as follows:
44
For the Three Months EndedSeptember 30, 2013 Compared to 2012
For the Nine Months EndedSeptember 30, 2013 Compared to 2012
Sales (GWh)
Percentage
NU – Electric
Percentage Decrease
Increase/(Decrease)
Residential
6,102
6,217
(1.8)%
16,625
16,296
2.0 %
Commercial (2)
7,616
7,721
(1.4)%
21,064
21,008
0.3 %
Industrial
1,529
1,563
(2.2)%
4,265
4,393
(2.9)%
15,247
15,501
(1.6)%
41,954
41,697
0.6 %
September 30, 2013 Compared to 2012
NSTARElectric
PercentageDecrease
PercentageIncrease/(Decrease)
PercentageIncrease
(2.7)%
(2.5)%
2.9 %
0.8 %
2.1%
1.3 %
(1.1)%
(1.9)%
(0.3)%
(1.7)%
0.4 %
0.1 %
0.7%
(0.7)%
(5.2)%
(1.2)%
(5.4)%
(3.3)%
1.5%
(2.1)%
0.9 %
1.4%
(0.1)%
Results include retail electric sales of NSTAR Electric from January 1, 2012 through September 30, 2012 for comparative purposes only.
Commercial retail electric GWh sales include streetlighting and railroad retail sales.
Sales (million cubic feet)
NU – Firm Natural Gas
Percentage Increase
2,407
2,413
24,392
20,124
21.2%
Commercial
4,673
4,230
10.5 %
28,066
24,524
14.4%
4,093
4,053
1.0 %
15,588
15,387
1.3%
11,173
10,696
4.5 %
68,046
60,035
13.3%
Total, Net of Special Contracts (2)
10,155
9,462
7.3 %
64,815
55,341
17.1%
For the Three Months Ended September 30, 2013 Compared to 2012
For the Nine Months Ended September 30, 2013 Compared to 2012
NSTAR Gas (3)
Increase
9.0 %
(6.4)%
23.0 %
20.0%
6.5 %
14.6 %
15.4 %
13.6%
11.1 %
(2.8)%
2.7 %
7.0 %
16.4%
7.6 %
17.9 %
Results include firm natural gas sales of NSTAR Gas from January 1, 2012 through September 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 from January 1, 2012 through September 30, 2012 has been provided for comparative purposes only.
Weather, fluctuations in energy supply costs, conservation measures (including company-sponsored energy efficiency programs), and economic conditions affect customer energy usage. Industrial sales are less sensitive to temperature variations than residential and commercial sales. 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. In addition, our electric and natural gas businesses are impacted by variations in weather and are susceptible to damage from major storms and other natural events and disasters that could adversely affect our ability to provide energy.
For the third quarter of 2013, our consolidated retail electric sales were lower, as compared to the same period in 2012, due primarily to a decrease in residential sales as a result of cooler summer weather in the third quarter of 2013, as compared to the same period in 2012. For the first nine months 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.
45
For the third quarter of 2013, actual retail electric sales for CL&P, NSTAR Electric and WMECO decreased while actual retail electric sales for PSNH reflected a slight increase, as compared to the same period in 2012. Cooling degree days were eight percent lower than last year in Connecticut and western Massachusetts, two percent lower than last year in the Boston metropolitan area, and 11 percent lower than last year in New Hampshire. On a weather-normalized basis (based on 30-year average temperatures), retail electric sales for CL&P, NSTAR Electric and WMECO decreased, while retail electric sales for PSNH increased, for the third quarter of 2013, as compared to the same period in 2012, with the NU combined consolidated total retail electric sales decreasing by 0.3 percent. We believe the decrease was due primarily to increased conservation efforts among all our customer classes, primarily at NSTAR Electric as a result of company sponsored energy efficiency programs.
For the first nine months of 2013, actual retail electric sales for CL&P, NSTAR Electric and PSNH increased while actual retail electric sales for WMECO remained relatively unchanged, as compared to the same period in 2012. Actual retail electric 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 nine months 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 the same period in 2012. On a weather-normalized basis, retail electric sales for CL&P and PSNH increased, while retail electric sales for NSTAR Electric and WMECO decreased, for the first nine months of 2013, as compared to the same period in 2012, with the NU combined consolidated total retail electric sales remaining relatively unchanged, assuming NSTAR Electric had been part of the NU electric distribution system for all periods.
For WMECO, fluctuations in retail electric sales do not impact earnings due to the DPU-approved revenue decoupling mechanism. Under this decoupling mechanism, WMECO has an overall fixed annual level of distribution delivery service revenues of $132.4 million comprised of customer base rate revenues of $125.4 million and a baseline low income discount recovery of $7 million. These two mechanisms effectively break the relationship between sales volume and revenues recognized.
Our 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 third quarter and first nine months of 2013, actual and weather-normalized firm natural gas sales increased, as compared to the same periods in 2012. Third quarter actual and weather-normalized firm natural gas sales were higher due primarily to residential customer growth, incremental natural gas conversions, the migration of interruptible customers switching to firm service rates, and the addition of gas-fired distributed generation, all of which was primarily in the Yankee Gas service territory. The first nine months of 2013 actual firm natural gas sales were higher due primarily to colder weather in the first quarter of 2013, as compared to the same period in 2012, assuming NSTAR Gas had been part of the NU combined natural gas distribution system for all periods. On a weather-normalized basis, the NU combined consolidated total firm natural gas sales increased 3.6 percent in the first nine months of 2013, as compared to the same period in 2012, due primarily to residential customer growth, incremental natural gas conversions, the migration of interruptible customers switching to firm service rates, and the addition of gas-fired distributed generation, all of which was primarily in the 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 $4.4 million and $11.6 million in the third quarter and first nine months of 2013, respectively, compared with net expenses of $9.6 million and $50.3 million in the third quarter and first nine months of 2012, respectively. Excluding the impact of integration and merger-related costs, NU parent and other companies earned $11.4 million and $22.2 million in the third quarter and first nine months of 2013, respectively, compared with earnings of $3.1 million and $2.1 million in the third quarter and first nine months of 2012, respectively. Improved results were due primarily to a lower effective tax rate and, for the first nine months of 2013, the inclusion of NSTAR Communications.
Liquidity
Consolidated: Cash and cash equivalents totaled $57.9 million as of September 30, 2013, compared with $45.7 million as of December 31, 2012.
On July 31, 2013, the FERC approved CL&P’s and WMECO’s short-term debt application requesting 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.
On September 1, 2013, WMECO repaid at maturity $55 million of 5.00 percent Series A Senior Notes using short-term debt.
On September 20, 2013, NU parent repaid at maturity $300 million of Floating Rate Series D Senior Notes with proceeds from NU parent’s issuance on May 13, 2013 of $750 million of Series E and Series F Senior Notes.
On September 6, 2013, NU parent, CL&P, NSTAR LLC, NSTAR Gas, PSNH, WMECO and Yankee Gas amended their joint five-year $1.15 billion revolving credit facility dated July 25, 2012 by increasing the aggregate principal amount available thereunder by $300 million to $1.45 billion, extending the expiration date from July 25, 2017 to September 6, 2018, and increasing CL&P's borrowing
46
sublimit from $300 million to $600 million. At the same time, effective September 6, 2013, the CL&P $300 million revolving credit facility was terminated.
Cash flows provided by operating activities totaled $1.1 billion in the first nine months of 2013, compared with $700.8 million in the same period of 2012 (all amounts are net of RRB payments, which are included in financing activities on the accompanying 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 $93 million in cash disbursements for storm restoration costs in the first nine months of 2013 associated primarily with the February blizzard, as compared to cash disbursements for storm restoration costs in the first nine months 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 nine months of 2012 at CL&P, NSTAR Electric, NSTAR Gas and WMECO related to customer bill credits and the absence in 2013 of $34 million of merger-related costs in the first nine months of 2012. Partially offsetting these favorable cash flow impacts were a $97.4 million increase in Pension Plan cash contributions, an increase in coal and fuel inventories, and changes in traditional working capital amounts principally due to the changes in timing of accounts receivable and accounts payable.
We paid common dividends of $341.7 million in the first nine months of 2013, compared with $267.4 million in the same period of 2012. On September 4, 2013, our Board of Trustees approved a common dividend payment of $0.3675 per share, which was paid on September 30, 2013 to shareholders of record as of September 16, 2013.
In the first nine months of 2013, CL&P, NSTAR Electric, PSNH, and WMECO paid $114 million, $56 million, $51 million, and $30 million, respectively, in common dividends to their respective parent company.
Investments in Property, Plant and Equipment on the accompanying statements of cash flows do not include amounts incurred on capital projects but not yet paid, cost of removal, AFUDC related to equity funds, and the capitalized portions of pension expense. In the first nine months of 2013, investments for NU, CL&P, NSTAR Electric, PSNH, and WMECO were $1.1 billion, $294.6 million, $330.6 million, $155.7 million, and $127.4 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 $1.1 billion in the first nine months of 2013, compared with $1.1 billion in the same period of 2012. These amounts included $14.7 million and $30.9 million in the first nine months of 2013 and 2012, respectively, related to our corporate service companies, NUSCO and RRR.
Transmission Business: Overall, transmission business capital expenditures decreased by $47.7 million in the first nine months of 2013, as compared to the same period of 2012, due primarily to the WMECO portion of GSRP nearing completion, partially offset by the addition of NSTAR Electric's capital expenditures. A summary of transmission capital expenditures by company for the first nine months of 2013 and 2012 is as follows:
133.5
148.2
140.0
79.4
58.0
44.5
62.0
179.3
21.8
Total Transmission Segment
425.5
473.2
Results include transmission capital expenditures of NSTAR Electric from the date of the merger, April 10, 2012, through September 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 currently completing its last major construction phase and, with the new 345 kV circuit in service, is already providing reliability and economic benefits to customers. We expect the project to be fully placed in service in late 2013 with a total cost approximately six percent lower than budget. As of September 30, 2013, the project was approximately 98 percent complete and CL&P and WMECO had placed $534 million in service.
47
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. The Connecticut and Rhode Island portions of the project have been approved. We now have all state environmental approvals and expect a siting approval decision in Massachusetts in the second quarter of 2014. Our portion of the cost is expected to be $218 million and the project is expected to be placed in service in late 2015.
Greater Hartford Central Connecticut Study (GHCC): GHCC, which includes the reassessment of the Central Connecticut Reliability Project, continues to make progress. In August 2012, ISO-NE presented its preliminary reliability needs assessment for GHCC to the ISO-NE Planning Advisory Committee. The results showed existing and worsening severe regional and local thermal overloads and voltage violations within and across each of the four study areas. ISO-NE is expected to confirm the preferred transmission solutions in the first half of 2014, which are likely to include many 115 kV upgrades. We continue to expect that the specific future projects being identified to address these reliability concerns will cost approximately $300 million.
Included as part of NEEWS are associated reliability related projects, approximately $82 million of which have been placed in service and approximately $12 million of which are in various phases of construction and will continue to go into service through 2013.
Through September 30, 2013, CL&P and WMECO had capitalized $242 million and $556 million, respectively, in costs associated with NEEWS, of which $30.1 million and $37.6 million, respectively, were capitalized during the first nine months of 2013.
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 September 30, 2013, NSTAR Electric had capitalized $91.3 million in costs associated with the Cape Cod projects, of which $55.4 million was capitalized during the first nine months 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. The $1.4 billion project is subject to comprehensive federal and state public permitting processes and is expected to be operational by mid-2017. On July 1, 2013, NPT filed the DOE Presidential Permit Application Amendment. The DOE has completed its public scoping meeting process and is currently performing field work and data collection.
48
Distribution Business: A summary of distribution capital expenditures by company for the first nine months of 2013 and 2012 is as follows:
CL&P:
Basic Business
42.7
55.5
Aging Infrastructure
116.6
133.2
Load Growth
56.9
Total CL&P
216.2
246.5
NSTAR Electric:
84.6
75.0
Total NSTAR Electric
182.1
115.8
PSNH:
13.7
33.3
14.0
Total PSNH
64.2
63.4
WMECO:
16.7
Total WMECO
27.7
29.1
Total - Electric Distribution (excluding Generation)
490.2
454.8
Total - Natural Gas
126.3
111.9
Other Distribution
Total Electric and Natural Gas
616.9
566.9
PSNH Generation:
Total PSNH Generation
29.0
WMECO Generation
Total Distribution Segment
623.3
596.4
Results include the electric and natural gas distribution capital expenditures of NSTAR from the date of the merger, April 10, 2012, through September 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.
WMECO Solar Project: On September 4, 2013, the DPU approved WMECO's proposal to build a third solar generation facility and expand its solar energy portfolio from 6 MW to 8 MW. On October 22, 2013, WMECO announced it would install a 3.9 MW solar generation facility on a site in East Springfield, Massachusetts. The facility is expected to be completed in mid-2014 with an estimated cost of approximately $15 million. WMECO currently has two solar generation facilities in operation. The 1.8 MW solar facility in Pittsfield, Massachusetts has been operating since October 2010 and the 2.3 MW solar facility in Springfield, Massachusetts has been generating electricity since November 2011.
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 NETOs, including CL&P, NSTAR Electric, PSNH and WMECO, is unjust and unreasonable. The complainants asserted 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 ALJ after settlement negotiations were unsuccessful in August 2012.
49
We expect the CL&P, NSTAR Electric, PSNH, and WMECO aggregate shareholder equity invested in their transmission facilities to be approximately $2.4 billion at the end of 2013. As a result, each 10 basis point change in the prospective period authorized base ROE would change annual consolidated earnings by an approximate $2.4 million.
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 nine months 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 September 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
462.0
490.7
64.9
63.6
128.5
33.5
35.8
595.8
94.6
690.4
The magnitude of these storm restoration costs met the criteria for cost deferral in Connecticut, Massachusetts, and New Hampshire, 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 is seeking recovery of its estimated deferred storm restoration costs through its applicable regulatory recovery process.
Connecticut 2013 Storm Filing: In March 2013, CL&P filed a request with PURA for approval to recover storm restoration costs associated with five major storms, all of which occurred in 2011 and 2012. CL&P's deferred storm restoration costs associated with these major storms totaled $462 million. Of that amount, approximately $414 million is subject to recovery in rates after giving effect to CL&P’s agreement to forego the recovery of $40 million of previously deferred storm restoration costs as well as an existing storm reserve fund balance of approximately $8 million. CL&P is seeking to recover the $414 million, plus carrying costs, in its distribution rates over a six-year period beginning on December 1, 2014, in accordance with the PURA-approved Connecticut settlement agreement. In September 2013, PURA completed hearings to review the March 2013 filing. Currently CL&P is in the briefing stage of the PURA review process with the proposed schedule providing a final PURA decision regarding the recovery of these storm restoration costs in late-January 2014.
WMECO SRRCA Mechanism: In February 2011, at the time of the last base distribution rate case, WMECO established a Storm Reserve Recovery Cost Adjustment (SRRCA) mechanism to recover the restoration costs associated with seven major storms, which occurred between June 2008 and May 2010, and to allow WMECO to request approval to recover qualified incremental major storm restoration costs over a five-year period. WMECO began recovering the restoration costs of these seven major storms effective February 1, 2011, subject to further review and reconciliation. On October 31, 2011, WMECO requested approval to recover the restoration costs of four additional major storms, all of which occurred in 2011 and included Tropical Storm Irene. WMECO began recovering the restoration costs of these four major storms effective January 1, 2012, subject to further review and reconciliation. The
50
DPU consolidated its review of the restoration costs for these eleven major storms into a single proceeding. Hearings were conducted in early April 2013, followed by the submission of initial and reply briefs in May and June 2013. Collectively, WMECO is requesting that the DPU approve the recovery of storm restoration costs totaling $24 million for these eleven storms.
Massachusetts 2013 Storm Filings: In March 2013, NSTAR Electric filed a request with the DPU for approval to recover approximately $35 million in storm restoration costs, plus carrying costs, related to Tropical Storm Irene and the October 2011 snowstorm. NSTAR Electric is seeking to recover these costs in its distribution rates over a five-year period beginning on January 1, 2014 in accordance with the DPU-approved Massachusetts comprehensive merger settlement agreement. Hearings were conducted in early August 2013, followed by the submission of simultaneous initial briefs on August 28, 2013 and simultaneous reply briefs on September 6, 2013.
On August 30, 2013, WMECO filed its annual SRRCA filing for restoration costs incurred for the October 2011 snowstorm ($23 million) and Storm Sandy ($4 million) for a total of $27 million. WMECO is seeking to recover these costs in its distribution rates over a five-year period beginning on January 1, 2014.
DPU Storm Penalties: In December 2012, in separate orders issued by the DPU, NSTAR Electric and WMECO received penalties related to the investigation into the electric utilities’ responses to Tropical Storm Irene and the October 2011 snowstorm. The DPU ordered penalties of $4.1 million and $2 million for NSTAR Electric and WMECO, respectively, which have been refunded to their customers. In December 2012, NSTAR Electric and WMECO each filed appeals with the SJC arguing the DPU penalties should be vacated. A briefing schedule has been established, with NSTAR Electric and WMECO’s initial briefs due to be submitted on November 5, 2013 and the Massachusetts Attorney General's response brief due 30 days later. Oral arguments are scheduled for March 2014.
Long-Term Wind Contracts: NSTAR Electric and WMECO, along with two other Massachusetts utilities, signed a long-term commitment, as required by regulation, to purchase wind power from six wind farms in Maine and New Hampshire for a combined estimated generating capacity of approximately 550 MW. These contracts were filed jointly with the DPU on September 20, 2013. Over the life of the 15- to 20-year contracts, the utilities will pay an average price of less than $0.08 per kWh. The projects are in various stages of permitting or development and are expected to begin operation between 2014 and 2016.
On September 19, 2013, CL&P, along with another Connecticut utility, signed long-term commitments, as required by regulation, to purchase approximately 250 MW of wind power from a Maine wind farm and 20 MW of solar power from sites in Connecticut, at a combined average price of less than $0.08 per kWh. On October 23, 2013, PURA issued a final decision accepting the contracts. The two projects are expected to be operational by the end of 2016. For further information, see "Legislative and Policy Matters – 2013 Connecticut Legislation" in this Management’s Discussion and Analysis.
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 Comprehensive Energy Strategy (CES) and the recently enacted Connecticut 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 which are 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 into Connecticut. On July 16, 2013, DEEP issued a determination letter finding the expansion plan was consistent with the CES and requesting certain modifications to be made. On July 26, 2013, the natural gas distribution companies submitted their responses to DEEP and PURA. PURA has conducted hearings on the expansion plan, has concluded briefing, and intends to issue a final decision approving or modifying the expansion plan on November 21, 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:
PSNH Generation: On July 15, 2013, the NHPUC accepted from the NHPUC Staff 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, define "just and reasonable" with respect to default service in the context of competitive retail markets, analyze the current and expected value of PSNH’s generating units, and identify means to mitigate and address stranded cost recovery. On September 18, 2013 the NHPUC issued a Request for Proposal to hire a valuation expert to determine the value of PSNH's generation assets and entitlements. The expert will be announced in early November 2013 with a final valuation report due no later than 180 days after the date the expert is hired. No further schedule has been announced. At this time, we cannot predict the outcome of this review. We continue to believe all costs and generation investments are probable of recovery. Our current PSNH generation rate base is approximately $750 million.
51
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 remain open to conduct 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 approved permanent rates.
The NHPUC has issued a series of orders ruling on the scope of its inquiry and discovery issues. In September 2013, PSNH filed an appeal with the New Hampshire Supreme Court regarding the scope of the docket and is awaiting a Supreme Court decision on whether it will accept the case for review at this time. The NHPUC has suspended its docket pending action by the Supreme Court. We continue to believe that we were prudent in the undertaking and completion of the Clean Air Project. 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: Connecticut Governor Malloy signed into law two significant energy bills that were enacted by the legislature during the 2013 session. The first law, Public Act 13-298, implemented a number of the recommendations proposed in the CES. Public Act 13-298 authorized the filing of a plan to expand natural gas service to Connecticut residents that currently do not have access to natural gas. For further information on Yankee Gas’ filing, see “Regulatory Developments and Rate Matters – Connecticut – Yankee Gas” in this Management's Discussion and Analysis of Financial Condition and Results of Operations. The law also required PURA to implement decoupling for each of Connecticut’s electric and natural gas utilities in their next respective rate cases. PURA is required to implement decoupling for electric utilities that reconciles actual revenues to allowed revenues. For natural gas distribution companies, the decoupling mechanism is required to 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). Finally, the law allows electric distribution companies to recover their costs as well as lost revenues from various state energy policy initiatives, including expanded energy efficiency programs.
The second law, 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 Renewable Portfolio Standard (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 law 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.
On September 26, 2013, DEEP issued a final determination that authorized the state’s electric distribution companies to enter into long term power purchase agreements for a total of 270 MW of Class I renewable generation from two projects. On October 23, 2013, PURA issued a final decision accepting the contracts presented by the electric distribution companies. On October 21, 2013, DEEP issued a Request for Proposal seeking proposals for energy and RECs from private developers for up to 4 percent of the state’s electric distribution companies’ load (estimated to be between 100 MW to 150 MW) of Class I renewable energy resources for biomass, landfill gas and run off river hydropower projects from new or existing facilities. Proposals are due to DEEP on November 18, 2013.
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
52
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 9B, "Commitments and Contingencies – Long-Term Contractual Arrangements," for discussion of material contractual obligations.
Web Site: Additional financial information is available through our web site at www.nu.com.
53
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 nine months ended September 30, 2013 and 2012:
Operating Revenues and Expenses
Increase/
(Decrease)
Percent
2012 (a)
%
933.7
645.9
602.8
43.1
7.1
1,882.0
1,540.1
341.9
386.7
395.5
(8.8)
(2.2)
1,090.0
1,187.4
(97.4)
(8.2)
149.1
144.5
3.2
463.6
369.8
25.4
43.8
26.2
59.8
178.7
(b)
(43.0)
(100.0)
42.6
102.1
(58.3)
106.1
98.3
306.0
209.1
96.9
46.3
135.5
120.7
14.8
12.3
391.8
319.6
72.2
1,493.3
1,448.6
44.7
4,354.7
3,803.0
551.7
(13.6)
(3.3)
382.0
48.6
(a) The 2012 results include the operations of NSTAR from the date of the merger, April 10, 2012, through September 30, 2012.
(b) Percent greater than 100 percent not shown as it is not meaningful.
24.9
604.7
251.5
69.6
Total Distribution
1,605.7
1,575.0
4,717.4
3,861.2
856.2
94.3
15.0
Total Regulated Companies
1,839.8
1,810.6
29.2
1.6
5,438.9
4,488.4
950.5
21.2
Other and Eliminations
52.8
101.4
(16.8)
(16.6)
Total Operating Revenues
A summary of our retail electric sales and firm natural gas sales were as follows:
Retail Electric Sales in GWh
(254)
Firm Natural Gas Sales in Million Cubic Feet
477
8,011
(a) Results include the retail electric sales of NSTAR Electric and the firm natural gas sales of NSTAR Gas from January 1, 2012
through September 30, 2012 for comparative purposes only.
Our Operating Revenues increased $31.1 million in the third quarter of 2013, as compared to the third quarter of 2012, due primarily to:
A $3.6 million increase in base electric distribution revenues, net of applicable eliminations, despite a 1.6 percent decrease in retail electric sales. The increase in revenue was primarily driven by an NHPUC-approved distribution rate increase at PSNH effective July 1, 2013 as a result of the 2010 distribution rate case settlement and higher demand revenue. The decrease in retail electric sales was primarily driven by slightly cooler summer weather experienced in the third quarter of 2013, as compared to the same period in 2012, and the impact of company-sponsored energy efficiency programs.
A $24.8 million increase in transmission revenues, net of applicable eliminations, as a result of the recovery of higher transmission expenses and continuing investments in our transmission infrastructure. The increase was partially offset by the establishment of a reserve related to an August 2013 initial decision from a FERC ALJ that lowers the base ROE earned by New England transmission owners for the 15-month period ended December 31, 2012. For further information, see “FERC Regulatory Issues - FERC Base ROE Complaint” in this Management's Discussion and Analysis of Financial Condition and Results of Operations.
The remaining increase was due primarily to higher revenues from the Company’s reconciling costs recovery mechanisms. Revenues related to cost recovery mechanisms vary from period to period based on the timing of collections of the costs incurred. These revenues had no material impact on earnings.
Our Operating Revenues increased $933.7 million for the nine months ended September 30, 2013, as compared to the same period in 2012. The primary driver of the increase was the absence of NSTAR in the first quarter of 2012. During the first quarter of 2013, the
54
former operating subsidiaries of NSTAR contributed approximately $800 million of operating revenues. In the absence of NSTAR, our Operating Revenues increased approximately $134 million due primarily to:
A $24.1 million increase in base electric distribution revenues, net of applicable eliminations, reflecting a 0.6 percent increase in retail electric sales. The increase in sales volumes was driven primarily by the colder winter weather experienced throughout our service territories in early 2013, as compared to the same period in 2012. In addition, the increase in revenues resulted from the NHPUC-approved distribution rate increases at PSNH effective July 1, 2012 and July 1, 2013 as a result of the 2010 distribution rate case settlement. These positive impacts on revenue were partially offset by the impact of our company-sponsored energy efficiency programs.
A $31.5 million increase in transmission revenues, net of applicable eliminations, as a result of the recovery of higher transmission expenses and continuing investments in our transmission infrastructure. The increase was partially offset by the establishment of a reserve related to the FERC ALJ initial decision in the third quarter of 2013.
A $20 million increase in firm natural gas revenues. This increase was driven by the colder winter weather in early 2013, as compared to the same period in 2012.
Purchased Power, Fuel and Transmission increased for the three and nine months ended September 30, 2013, as compared to the same periods in 2012, due primarily to the following:
Three Months EndedIncrease/(Decrease)
Nine Months EndedIncrease/(Decrease)
The addition of NSTAR's operations
n/a
321.4
Transmission segment costs
50.3
Electric distribution segment deferred fuel costs
27.5
29.9
Firm natural gas sales related costs
24.2
Partially offset by:
Electric distribution segment fuel and energy supply costs
(3.1)
(46.7)
RECs and emission allowances
(18.7)
(28.2)
Other and eliminations
(9.0)
Operations and Maintenance decreased for the three and nine months ended September 30, 2013, as compared to the same periods in 2012, due primarily to the following:
Three Months Ended
Nine Months Ended
The addition of NSTAR’s operations
123.6
Absence of merger and settlement agreement costs
(148.2)
Electric distribution segment costs
(39.5)
NU’s unregulated contracting business costs
(7.5)
(7.8)
General and administrative costs
(6.6)
Customer EIA incentives
(6.1)
Natural gas segment costs
4.7
(7.7)
Depreciation increased for the three and nine months ended September 30, 2013, as compared to the same periods in 2012, due primarily to the addition of NSTAR ($54.2 million for the nine months) and an increase as a result of the consolidation of CYAPC and YAEC ($13.7 million for the nine 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.
Amortization of Regulatory Assets, Net increased for the three and nine months ended September 30, 2013, as compared to the same periods in 2012, due primarily to the following:
45.8
Recovery of transition costs at NSTAR Electric
31.5
77.1
Amortization related to CL&P’s SBC and CTA
(9.9)
(14.0)
55
Amortization of Rate Reduction Bonds decreased for the three and nine months ended September 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 nine months).
Energy Efficiency Programs increased for the three and nine months ended September 30, 2013, as compared to the same periods in 2012, due primarily to the addition of NSTAR's operations ($68.6 million for the nine 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-approved tracking mechanisms and therefore do not impact earnings.
Taxes Other Than Income Taxes increased for the three and nine months ended September 30, 2013, as compared to the same periods in 2012, due primarily to the addition of NSTAR's operations ($37.8 million for the nine 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 nine months ended September 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 and lower Interest on RRBs and lower Interest on Long-Term Debt.
Other Income increased for the three and nine months ended September 30, 2013, as compared to the same period in 2012, due primarily to higher gains on the NU supplemental benefit trust and an increase related to officer insurance policies.
Decrease
109.4
117.4
(8.0)
325.4
199.4
126.0
63.2
Income Tax Expense decreased for the three months ended September 30, 2013, as compared to the same period in 2012, due primarily to lower pre-tax earnings ($9.4 million), lower state taxes and various other impacts ($5.4 million), state audit impacts ($1.1 million), partially offset by prior year merger impacts ($8.3 million).
Income Tax Expense increased for the nine months ended September 30, 2013, as compared to the same period in 2012, due primarily to higher pre-tax earnings ($73 million), prior year Connecticut and Massachusetts settlement agreement impacts ($41 million), prior year merger impacts ($22.8 million), partially offset by various other impacts ($4.8 million).
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 nine months ended September 30, 2013 and 2012:
648.4
658.1
(9.7)
1,841.8
1,812.2
253.1
241.0
5.0
667.3
658.7
8.6
127.1
141.9
359.7
480.3
(120.6)
(25.1)
44.8
132.3
124.5
8.7
11.2
19.9
(43.7)
24.5
25.2
68.2
65.0
59.7
182.7
514.5
518.4
1,421.4
1,520.2
(98.8)
(6.5)
133.9
139.7
(4.2)
420.4
292.0
128.4
44.0
CL&P's retail sales were as follows:
Retail Sales in GWh
6,119
6,235
(116)
16,993
16,843
150
CL&P's Operating Revenues decreased $9.7 million for the three months ended September 30, 2013, as compared to the same period in 2012, due primarily to:
A $2.1 million decrease in base distribution revenues reflecting a 1.9 percent decrease in retail sales. This decrease was due primarily to slightly cooler summer weather in 2013, as compared to the summer weather in 2012.
A $7.8 million decrease in transmission revenues reflecting the establishment of a reserve related to the FERC ALJ initial decision in the third quarter of 2013. The decrease was partially offset by recovery of higher transmission expenses and continuing transmission infrastructure investments.
CL&P’s Operating Revenues increased $29.6 million for the nine months ended September 30, 2013, as compared to the same period in 2012, due primarily to:
A $9.4 million increase in base distribution revenues reflecting a 0.9 percent increase in retail sales. This increase was due primarily to the colder winter weather experienced in early 2013, as compared to the same period in 2012.
An $8.7 million increase in transmission revenues reflecting recovery of higher transmission expenses and continuing transmission infrastructure investments. The increase was partially offset by the establishment of a reserve related to the FERC ALJ initial decision in the third quarter of 2013.
The remaining increase was due primarily to higher collections of costs through reconciling cost mechanisms. These revenues are fully reconciled to the related costs. Therefore this increase in revenues had no impact on earnings.
Purchased Power and Transmission increased for the three and nine months ended September 30, 2013, as compared to the same periods in 2012, due primarily to the following:
Transmission Costs
32.5
Deferred Fuel Costs
CfD Costs
GSC Supply Costs
(20.0)
(45.0)
Purchased Power Contracts
(4.5)
(10.7)
The decrease in GSC supply costs was due primarily to lower average supply prices, partially offset by an increase in GSC sales. On July 1, 2013, CL&P began to procure approximately thirty percent of GSC load. Costs associated with the remaining seventy percent of the GSC load 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. All GSC supply costs are included in PURA approved tracking mechanisms and do not impact earnings.
Operations and Maintenance decreased for the three and nine months ended September 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 ($1.8 million and $6.8 million, respectively) and lower distribution costs related to customer EIA incentives ($6.1 million and $5.8 million, respectively). Also contributing to the decrease was the absence in 2013 of the amortization of a regulatory deferral allowed in the 2010 rate case decision ($4 million for the nine months), lower routine vegetation management costs ($3.5 million for the nine months), the absence of amortization of the PBOP transition obligation ($1.5 million and $4.6 million, respectively), and lower routine distribution maintenance costs ($0.7 million for the nine months). Partially offsetting the third quarter 2013 decrease was higher routine vegetation management costs ($1.8 million for the third quarter) and higher routine distribution maintenance costs ($1.8 million for the third quarter).
Depreciation increased for the three and nine months ended September 30, 2013, as compared to the same periods in 2012, due primarily to higher utility plant balances resulting from completed construction projects placed into service related to CL&P's capital programs.
Amortization of Regulatory Assets, Net decreased for the three and nine months ended September 30, 2013, as compared to the same periods in 2012, due primarily to lower retail SBC revenues ($7.4 million and $18.7 million, respectively), lower SBC transition costs ($0.3 million and $5.4 million, respectively), lower CTA revenues ($3.8 million and $9.8 million, respectively) and lower CTA transition costs ($5.9 million and $11.8 million, respectively). Partially offsetting these decreases was an increase related to a DOE refund ($11.9 million for the third quarter).
Taxes Other Than Income Taxes increased for the three and nine months ended September 30, 2013, as compared to the same periods in 2012, due primarily to an increase in the Connecticut gross earnings tax attributable to an increase in gross earnings ($1.1 million and $5.8 million, respectively), 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 ($3.9 million and $7.3 million, respectively).
Interest Expense increased for the three months ended September 30, 2013, as compared to the same period in 2012, due primarily to higher interest on long-term debt. Interest Expense decreased for the nine months ended September 30, 2013, as compared to the same period in 2012, due primarily to a decrease in other interest as a result of 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.
Other Income increased for the three and nine months ended September 30, 2013, as compared to the same periods in 2012, due primarily to higher gains on the NU supplemental benefit trust.
36.1
113.1
63.9
49.2
77.0
Income Tax Expense increased for the nine months ended September 30, 2013, as compared to the same period in 2012, due primarily to higher pre-tax earnings ($22.6 million), the absence in 2013 of the impact of costs recognized as a result of the Connecticut settlement agreement ($26.6 million), and higher state taxes ($3.4 million), partially offset by state audit impacts ($2.9 million).
EARNINGS SUMMARY
Income Before Merger-Related Costs
66.3
219.2
174.2
Merger-Related Costs (after-tax) (1)
(38.4)
135.8
The first nine months of 2012 after-tax merger-related costs consisted of charges related to the Connecticut settlement agreement, including $14.8 million ($25 million pre-tax) for customer bill credits and $23.6 million ($40 million pre-tax) whereby CL&P agreed to forego recovery of deferred storm costs associated with Tropical Storm Irene and the October 2011 snowstorm.
CL&P’s third quarter 2013 earnings were lower than the same period in 2012 due primarily to the establishment of a $7.7 million after-tax reserve related to the August 2013 FERC ALJ initial decision, higher depreciation and property tax expense and lower retail electric sales as a result of slightly cooler summer weather in 2013, as compared to the summer weather in 2012. Partially offsetting these unfavorable earnings impacts were increased investments in the transmission infrastructure.
Excluding merger-related costs, CL&P’s first nine months of 2013 earnings were $45 million higher than the same period in 2012 due primarily to increased investments in the transmission infrastructure, 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. Partially offsetting these favorable earnings impacts were higher depreciation and property tax expense.
58
LIQUIDITY
CL&P had cash flows provided by operating activities of $308.6 million in the first nine months of 2013, compared with $148.2 million in the first nine months of 2012. The improved cash flows were due primarily to the absence in the first nine months of 2013 of $164.3 million in cash disbursements for storm costs associated with Tropical Storm Irene and the October 2011 snowstorm in the first nine months 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 payments of $41.2 million in the first nine months of 2013, compared with income tax refunds of $39 million in the first nine months of 2012, and the change in traditional working capital amounts primarily due to the changes in timing of accounts receivable collections.
Investments in Property, Plant and Equipment on the accompanying statements of cash flows do not include amounts incurred on capital projects but not yet paid, cost of removal, AFUDC related to equity funds, and the capitalized portions of pension expense. CL&P’s investments totaled $294.6 million in the first nine months of 2013, compared with $332.3 million in the first nine months 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.
On July 31, 2013, the FERC approved CL&P’s short-term debt application requesting the authorization to issue total short-term borrowings up to a maximum of $600 million. The authorization is effective January 1, 2014 through December 31, 2015.
On September 3, 2013, CL&P redeemed at par $125 million of the 1.25 percent Series B 2011 PCRBs that were subject to mandatory tender for purchase using short-term debt.
On September 6, 2013, NU parent and certain of its subsidiaries amended their joint five-year $1.15 billion revolving credit facility dated July 25, 2012 by increasing the aggregate principal amount available thereunder by $300 million to $1.45 billion, extending the expiration date from July 25, 2017 to September 6, 2018, and increasing CL&P's borrowing sublimit from $300 million to $600 million. At the same time, effective September 6, 2013, the CL&P $300 million revolving credit facility was terminated.
Other financing activities in the first nine months of 2013 included $114 million in common stock dividends to NU parent.
59
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 nine months ended September 30, 2013 and 2012:
1,916.6
1,784.8
131.8
7.4
659.1
622.3
36.8
277.3
340.6
(18.6)
136.3
127.7
6.7
173.3
87.9
85.4
97.2
(52.6)
(77.7)
161.2
138.4
95.3
89.7
1,517.6
1,474.3
43.3
399.0
310.5
88.5
NSTAR Electric's retail sales were as follows:
16,204
16,189
NSTAR Electric’s Operating Revenues increased $131.8 million for the nine months ended September 30, 2013, as compared to the same period in 2012, due primarily to:
A $6.5 million increase in base distribution revenues reflecting a 0.1 percent increase in retail sales. The increase in sales volume was due primarily to a greater number of cooling degree days during the summer of 2013 and heating degree days in early 2013, as compared to the same periods in 2012. This favorable impact was partially offset by reductions due to NSTAR Electric’s customer funded energy efficiency programs.
Transmission revenues remained comparable to 2012 reflecting recovery of higher transmission expenses and continuing transmission infrastructure investments, offset by the establishment of a reserve related to the FERC ALJ initial decision in the third quarter of 2013.
The remaining increase primarily reflects a higher level of collections related to NSTAR Electric's energy supply and company-sponsored energy efficiency programs. These revenues are fully reconciled to the related costs. Therefore this increase in revenues had no material impact on earnings.
Purchased Power and Transmission increased for the nine months ended September 30, 2013, as compared to the same period in 2012, due primarily to the following:
39.2
Basic Service Costs
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 increase in deferred fuel costs was due primarily to lower average supply prices, as compared to the prices projected when Basic Service customer rates were set. 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 for the nine months ended September 30, 2013, as compared to the same period in 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).
Depreciation increased for the nine months ended September 30, 2013, as compared to the same period in 2012, due primarily to higher utility plant balances resulting from completed construction projects placed into service related to NSTAR Electric’s capital programs.
Amortization of Regulatory Assets, Net increased for the nine months ended September 30, 2013, as compared to the same period in 2012, due primarily to an increase in the recovery of transition costs.
Amortization of Rate Reduction Bonds decreased for the nine months ended September 30, 2013, as compared to the same period in 2012, due to the maturity of the RRBs in March 2013.
Energy Efficiency Programs increased for the nine months ended September 30, 2013, as compared to the same period in 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-approved tracking mechanisms and therefore do not impact earnings.
Taxes Other Than Income Taxes increased for the nine months ended September 30, 2013, as compared to the same period in 2012, due to higher municipal property taxes as a result of an increase in Property, Plant and Equipment related to the company’s regulated capital programs.
Interest Expense decreased for the nine months ended September 30, 2013, as compared to the same period in 2012, due primarily to lower average long-term bond rates, partially offset by a higher level of average debt outstanding. Lower regulatory interest income was primarily from deferred transition costs.
137.5
102.2
35.3
Income Tax Expense increased for the nine months ended September 30, 2013, as compared to the same period in 2012, due primarily to higher pre-tax earnings ($30.2 million) and the absence in 2013 of the impact of costs recognized as a result of the Massachusetts settlement agreement ($5.9 million), partially offset by other impacts ($0.9 million).
213.2
167.0
(10.8)
156.2
The 2012 after-tax merger-related costs consisted of a $15 million pre-tax charge for customer bill credits related to the Massachusetts settlement agreement and a $2.7 million pre-tax charge related to compensation costs.
Excluding merger-related costs, NSTAR Electric’s 2013 earnings were $46.2 million higher than the same period in 2012 due primarily to the absence of 2012 adjustments recorded to establish a reserve against the regulatory asset related to Basic Service bad debt costs ($17 million), and for changes in accounting estimates related primarily to the allowance for doubtful accounts, workers’ compensation, employee medical benefits, and general liability claims ($11.4 million). Also contributing to the increase was a March 2012 substation fire in the Back Bay/Prudential area of Boston ($7.2 million), a reserve recorded relating to lost base revenues based on 2012 developments during hearings in the merger proceeding ($3.7 million), and the establishment of a reserve in the third quarter of 2013 related to the August 2013 FERC ALJ initial decision ($3.4 million).
61
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:
110.7
Distribution:
40.8
119.1
11.1
171.0
322.1
281.7
NSTAR Electric had cash flows provided by operating activities of $274.1 million for the first nine months of 2013, compared with $348.2 million for the first nine months 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 for the first nine months of 2013 associated with the February 2013 blizzard, as compared to cash disbursements for storm costs for the first nine months of 2012, associated with Tropical Storm Irene and the October 2011 snowstorm, and a $57 million increase in pension contributions for the first nine months of 2013, as compared to the same period of 2012. The change in traditional working capital amounts, principally due to the changes in timing of accounts receivable collections, also contributed to the decrease in operating cash flows. Partially offsetting the negative cash flow impacts was the absence in 2013 of $15 million in bill credits provided to customers in the second quarter of 2012 in connection with the Massachusetts settlement agreement.
62
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 nine months ended September 30, 2013 and 2012:
708.6
755.0
(46.4)
197.8
239.1
(41.3)
(17.3)
191.6
201.0
(9.4)
(4.7)
72.6
(24.2)
(55.1)
11.0
10.8
52.7
539.5
601.3
(61.8)
(10.3)
169.1
153.7
15.4
10.0
PSNH's retail sales were as follows:
5,971
5,888
83
PSNH's Operating Revenues decreased $46.4 million for the nine months ended September 30, 2013, as compared to the same period in 2012, due primarily to:
A $12.5 million increase in base distribution revenues reflecting a 1.4 percent increase in retail sales. PSNH experienced strong sales in early 2013 due to colder winter weather than what was experienced in early 2012. In addition, revenue was positively impacted by an increase of $8.6 million related to NHPUC-approved distribution rate increases effective July 1, 2012 and July 1, 2013 as a result of the 2010 distribution rate case settlement.
A $2 million increase in transmission revenues reflecting recovery of higher transmission expenses and continuing transmission infrastructure investments. The increase was mostly offset by the establishment of a reserve related to the FERC ALJ initial decision in the third quarter of 2013.
These increases were more than offset by a decrease of approximately $61 million related to PSNH's cost recovery mechanisms. The primary reason for this decrease was the reduction of recoveries related to PSNH’s RRBs, which were fully collected during the first half of 2013. This reduction had no impact on earnings.
Purchased Power, Fuel and Transmission decreased for the nine months ended September 30, 2013, as compared to the same period in 2012, due primarily to a decrease in costs related to RECs and a decrease in fuel costs resulting from an increase in customer migration to third party suppliers, which resulted in a decrease in load obligation and an increase in RGGI auction proceeds, which offset the cost of fuel. These decreases were partially offset by an increase in transmission costs resulting from an increase in regional transmission rates leading to higher RNS costs.
Operations and Maintenance decreased for the nine months ended September 30, 2013, as compared to the same period in 2012, due primarily to a decrease in RRB charges that are included in NHPUC-approved tracking mechanisms ($2.8 million), a decrease in vegetation management costs ($2.0 million), the absence in 2013 of PBOP transition obligation amortization ($1.9 million), lower general and administrative costs ($1.8 million) and lower routine generation and transmission maintenance costs ($1.3 million and $1.2 million, respectively). These decreases were partially offset by an increase in routine distribution overhead line maintenance costs ($4.4 million).
Amortization of Regulatory Liabilities, Net increased expenses for the nine months ended September 30, 2013, as compared to the same period in 2012, due primarily to an increase in the ES and TCAM amortization ($13.4 million and $3.2 million, respectively), partially offset by a decrease in the SCRC amortization ($11.3 million).
Amortization of Rate Reduction Bonds decreased for the nine months ended September 30, 2013, as compared to the same period in 2012, due to the maturity of the RRBs in May 2013.
Taxes Other Than Income Taxes increased for the nine months ended September 30, 2013, as compared to the same period in 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 $4 million for the nine months ended September 30, 2013, as compared to the same period in 2012, due primarily to lower Interest on Rate Reduction Bonds as a result of the maturity of the RRBs in May 2013.
48.0
Income Tax Expense increased for the nine months ended September 30, 2013, as compared to the same period in 2012, due primarily to higher pre-tax earnings ($6.9 million), partially offset by lower state taxes and other impacts ($2.1 million).
For the nine months ended September 30, 2013, PSNH’s earnings were $14.8 million higher than the same period in 2012 due primarily to higher distribution retail revenues and higher generation earnings. The nine months of 2013 distribution retail revenues were favorably impacted by the PSNH rate increases effective July 1, 2012 and July 1, 2013 as a result of the 2010 distribution rate case settlement, and higher weather-normalized retail electric sales (1.8 percent). Partially offsetting these favorable earnings impacts were higher depreciation and property tax expense.
PSNH had cash flows provided by operating activities of $131.1 million for the nine months ended September 30, 2013, compared with $136.5 million for the same period in 2012 (amounts are net of RRB payments, which are included in financing activities). The decrease in cash flows was due primarily to an increase in NUSCO Pension Plan contributions of $20.6 million for the nine months ended September 30, 2013, as compared to the same period in 2012, and an increase in coal and fuel inventories for the nine months ended September 30, 2013 creating a negative cash flow impact of $30.9 million, as compared to a reduction in coal and fuel inventories for the nine months ended September 30, 2012 creating a positive cash flow impact of $23.1 million. Partially offsetting these decreases were income tax refunds of $8.7 million for the nine months ended September 30, 2013, compared to income tax payments of $9.3 million for the same period in 2012, the absence of $8.7 million of 2012 cash disbursements for storm costs associated with Tropical Storm Irene and the October 2011 snowstorm, the favorable impacts related to the distribution rate increases effective July 1, 2012 and July 1, 2013 as a result of the 2010 distribution rate case settlement, and the change in traditional working capital amounts principally due to the changes in timing of accounts payable payments.
64
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 nine months ended September 30, 2013 and 2012:
361.8
333.3
111.1
105.3
70.2
75.2
(5.0)
25.3
Amortization of Regulatory (Liabilities)/
Assets, Net
(a)
(5.3)
(40.5)
264.9
251.4
13.5
81.9
(a) Percent greater than 100 percent not shown as it is not meaningful.
WMECO's retail sales were as follows:
2,786
2,788
WMECO’s Operating Revenues increased $28.5 million for the nine months ended September 30, 2013, as compared to the same period in 2012, due primarily to:
WMECO’s base distribution revenues are decoupled from its sales volumes. Therefore, its 2013 distribution revenues are consistent with 2012.
A $19.8 million increase in transmission revenues reflecting recovery of higher transmission expenses and continuing transmission infrastructure investments, primarily related to the NEEWS project. The increase was partially offset by the establishment of a reserve related to the FERC ALJ initial decision in the third quarter of 2013.
The remaining increase primarily reflects a higher level of collections related to WMECO’s energy supply and company-sponsored energy efficiency programs. These revenues are fully reconciled to the related costs. Therefore this increase in revenues had no material impact on earnings.
Purchased Power and Transmission increased for the nine months ended September 30, 2013, as compared to the same period in 2012, due primarily to an increase in supplier contract prices.
Operations and Maintenance decreased for the nine months ended September 30, 2013, as compared to the same period in 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 ($2.2 million), lower customer uncollectible expenses ($1.8 million) and lower routine distribution maintenance expenses ($1.1 million). Partially offsetting these decreases was an increase in pension costs ($3.3 million), which was recovered through DPU-approved tracking mechanisms and had no earnings impact.
Depreciation increased for the nine months ended September 30, 2013, as compared to the same period in 2012, due primarily to higher utility plant balances resulting from completed construction projects placed into service related to WMECO's capital programs.
Amortization of Rate Reduction Bonds decreased for the nine months ended September 30, 2013, as compared to the same period in 2012, due to the maturity of the RRBs in June 2013.
Energy Efficiency Programs increased for the nine months ended September 30, 2013, as compared to the same period in 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-approved tracking mechanisms and therefore do not impact earnings.
Taxes Other Than Income Taxes increased for the nine months ended September 30, 2013, as compared to the same period in 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.
Income Tax Expense increased for the nine months ended September 30, 2013, as compared to the same period in 2012, due primarily to higher pre-tax earnings ($4.8 million) and the absence in 2013 of the impact of costs recognized as a result of the Massachusetts settlement agreement ($1.2 million).
For the nine months ended September 30, 2013, excluding $1.8 million in 2012 of after-tax merger-related costs, WMECO’s earnings were $8.8 million higher, as compared to the same period in 2012, due primarily to higher transmission earnings as a result of an increased level of investment in transmission infrastructure, primarily related to the NEEWS project, and lower overall operations and maintenance costs. Partially offsetting these favorable earnings impacts were higher depreciation and property tax expense.
WMECO had cash flows provided by operating activities of $160.7 million for the nine months ended September 30, 2013, compared with $44.9 million for the same period in 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 $64.4 million for the nine months ended September 30, 2013, compared with income tax refunds of $12.9 million for the same period in 2012, the absence for the nine months ended September 30, 2013 of $14.7 million in cash disbursements made for storm costs in 2012, the absence of $3 million in bill credits provided to customers in the second quarter of 2012 associated with the Massachusetts settlement agreement, and changes in traditional working capital amounts principally due to the changes in timing of accounts payable payments.
66
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 September 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 September 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 September 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 Numberof SharesPurchased
AveragePricePaid perShare
Total Number ofShares PurchasedasPart of PubliclyAnnounced Plans orPrograms
Approximate DollarValue of Shares thatMay Yet Be PurchasedUnder the Plans andPrograms (at month end)
July 1 – July 31, 2013
August 1 – August 31, 2013
September 1 – September 30, 2013
101,000
41.19
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)
*12
Ratio of Earnings to Fixed Charges
*31
Certification of Thomas J. May, Chairman, 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 November 4, 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 November 4, 2013
*32
Certification of Thomas J. May, Chairman, 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 November 4, 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 November 4, 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 November 4, 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 November 4, 2013
Listing of Exhibits (NSTAR Electric)
First Amendment to Credit Agreement, dated September 6, 2013, by and among NSTAR Electric Company and Barclays Bank PLC, as Administrative Agent, and other lenders named therein. (Exhibit 4.2 to NSTAR Electric Company Current Report on Form 8-K filed on September 12, 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 November 4, 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 November 4, 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 November 4, 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 November 4, 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 November 4, 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 November 4, 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 November 4, 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 November 4, 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 November 4, 2013
Listing of Exhibits (NU, CL&P, PSNH, WMECO)
First Amendment to Credit Agreement, dated September 6, 2013, by and among Northeast Utilities and its subsidiaries, The Connecticut Light and Power Company, NSTAR Gas Company, NSTAR LLC, Public Service Company of New Hampshire, Western Massachusetts Electric Company and Yankee Gas Services Company, and Bank of America, N.A., as Administrative Agent, and other lenders named therein (Exhibit 4.1 to NU Current Report on Form 8-K filed on September 12, 2013, File No. 001-05324.)
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
70
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
November 4, 2013
By:
/s/
Jay S. Buth
Vice President, Controller and
Chief Accounting Officer
NSTAR ELECTRIC COMPANY
PUBLIC SERVICE COMPANY OF NEW HAMPSHIRE
72