UNITED STATES SECURITIES AND EXCHANGE COMMISSIONWASHINGTON, D.C. 20549FORM 10-Q
T
QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
For the Quarterly Period Ended June 30, 2014
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)300 Cadwell DriveSpringfield, Massachusetts 01104Telephone: (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)300 Cadwell DriveSpringfield, Massachusetts 01104Telephone: (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
Indicate by check mark whether the registrants have submitted electronically and posted on its corporate Web sites, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files).
Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, or a non-accelerated filer. See definition of "accelerated filer and large accelerated filer" in Rule 12b-2 of the Exchange Act. (Check one):
LargeAccelerated Filer
AcceleratedFiler
Non-acceleratedFiler
Northeast Utilities
The Connecticut Light and Power Company
NSTAR Electric Company
Public Service Company of New Hampshire
Western Massachusetts Electric Company
Indicate by check mark whether the registrants are shell companies (as defined in Rule 12b-2 of the Exchange Act):
Indicate the number of shares outstanding of each of the issuers' classes of common stock, as of the latest practicable date:
Company - Class of Stock
Outstanding as of July 31, 2014
Northeast UtilitiesCommon shares, $5.00 par value
316,385,790 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 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 Yankee Energy System, Inc.
HWP
HWP Company, formerly the Holyoke Water Power Company
MYAPC
Maine Yankee Atomic Power Company
NGS
Northeast Generation Services Company
NPT
Northern Pass Transmission LLC
NSTAR
Parent Company of NSTAR Electric, NSTAR Gas and other subsidiaries (prior to the merger with NU)
NSTAR Electric
NSTAR Electric & Gas
NSTAR Electric & Gas Corporation, a former Northeast Utilities service company (effective January 1, 2014 merged into NUSCO)
NSTAR Gas
NSTAR Gas Company
NU Enterprises
NU Enterprises, Inc., the parent company of NGS, Select Energy, Select Energy Contracting, Inc., E.S. Boulos Company and NSTAR Communications, Inc.
NU or the Company
Northeast Utilities and subsidiaries
NU parent and other companies
NU parent and other companies is comprised of NU parent, NUSCO and other subsidiaries, which primarily include NU Enterprises, 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 (effective January 1, 2014 includes the operations of NSTAR Electric & Gas)
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
CO2
Carbon dioxide
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
Millstone
Millstone Nuclear Generating station, made up of Millstone 1, Millstone 2, and Millstone 3. All three units were sold in March 2001.
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
NOx
Nitrogen oxide
NU 2013 Form 10-K
The Northeast Utilities and Subsidiaries 2013 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 Plans and non-qualified defined benefit retirement plans
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
SO2
Sulfur dioxide
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
1
Condensed Consolidated Statements of Income
3
Condensed Consolidated Statements of Comprehensive Income
Condensed Consolidated Statements of Cash Flows
4
The Connecticut Light and Power Company (Unaudited)
Condensed Balance Sheets
5
Condensed Statements of Income
7
Condensed Statements of Comprehensive Income
Condensed Statements of Cash Flows
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 Consolidated Financial Statements (Unaudited)
21
ITEM 2 – Management's Discussion and Analysis of Financial Condition and Results of Operations for the following companies:
Northeast Utilities and Subsidiaries
39
51
NSTAR Electric Company and Subsidiary
54
Public Service Company of New Hampshire and Subsidiary
56
58
ITEM 3 – Quantitative and Qualitative Disclosures About Market Risk
60
ITEM 4 – Controls and Procedures
PART II – OTHER INFORMATION
ITEM 1 – Legal Proceedings
61
ITEM 1A – Risk Factors
ITEM 2 – Unregistered Sales of Equity Securities and Use of Proceeds
ITEM 6 – Exhibits
62
SIGNATURES
64
iii
NORTHEAST UTILITIES AND SUBSIDIARIES
CONDENSED CONSOLIDATED BALANCE SHEETS
(Unaudited)
June 30,
December 31,
(Thousands of Dollars)
2014
2013
ASSETS
Current Assets:
Cash and Cash Equivalents
$
34,096
43,364
Receivables, Net
807,510
765,391
Unbilled Revenues
193,983
224,982
Fuel, Materials and Supplies
281,721
303,233
Regulatory Assets
467,156
535,791
Marketable Securities
115,987
92,427
Prepayments and Other Current Assets
168,022
121,861
Total Current Assets
2,068,475
2,087,049
Property, Plant and Equipment, Net
17,978,692
17,576,186
Deferred Debits and Other Assets:
3,339,457
3,758,694
Goodwill
3,519,401
513,986
488,515
Other Long-Term Assets
370,434
365,692
Total Deferred Debits and Other Assets
7,743,278
8,132,302
Total Assets
27,790,445
27,795,537
The accompanying notes are an integral part of these unaudited condensed consolidated financial statements.
LIABILITIES AND CAPITALIZATION
Current Liabilities:
Notes Payable
905,000
1,093,000
Long-Term Debt - Current Portion
395,583
533,346
Accounts Payable
561,699
742,251
Regulatory Liabilities
359,921
204,278
Other Current Liabilities
580,605
702,776
Total Current Liabilities
2,802,808
3,275,651
Deferred Credits and Other Liabilities:
Accumulated Deferred Income Taxes
4,270,050
4,029,026
503,955
502,984
Derivative Liabilities
449,439
624,050
Accrued Pension, SERP and PBOP
825,001
896,844
Other Long-Term Liabilities
882,688
923,053
Total Deferred Credits and Other Liabilities
6,931,133
6,975,957
Capitalization:
Long-Term Debt
8,147,129
7,776,833
Noncontrolling Interest - Preferred Stock of Subsidiaries
155,568
Equity:
Common Shareholders' Equity:
Common Shares
1,666,637
1,665,351
Capital Surplus, Paid In
6,201,555
6,192,765
Retained Earnings
2,241,025
2,125,980
Accumulated Other Comprehensive Loss
(41,507)
(46,031)
Treasury Stock
(313,903)
(326,537)
Common Shareholders' Equity
9,753,807
9,611,528
Total Capitalization
18,056,504
17,543,929
Total Liabilities and Capitalization
2
CONDENSED CONSOLIDATED STATEMENTS OF INCOME
For the Three Months Ended June 30,
For the Six Months Ended June 30,
(Thousands of Dollars, Except Share Information)
Operating Revenues
1,677,614
1,635,862
3,968,204
3,630,885
Operating Expenses:
Purchased Power, Fuel and Transmission
624,211
488,302
1,602,362
1,236,111
Operations and Maintenance
373,234
357,169
724,922
703,261
Depreciation
152,207
159,553
303,014
314,530
Amortization of Regulatory Assets/(Liabilities), Net
(3,542)
54,574
54,356
108,623
Amortization of Rate Reduction Bonds
-
8,082
42,581
Energy Efficiency Programs
102,711
94,142
241,536
199,913
Taxes Other Than Income Taxes
134,803
123,464
280,335
256,345
Total Operating Expenses
1,383,624
1,285,286
3,206,525
2,861,364
Operating Income
293,990
350,576
761,679
769,521
Interest Expense:
Interest on Long-Term Debt
87,491
85,999
174,868
171,294
Other Interest
5,004
851
7,603
(8,188)
Interest Expense
92,495
86,850
182,471
163,106
Other Income, Net
5,526
4,944
7,194
12,710
Income Before Income Tax Expense
207,021
268,670
586,402
619,125
Income Tax Expense
77,774
95,606
219,319
216,093
Net Income
129,247
173,064
367,083
403,032
Net Income Attributable to Noncontrolling Interests
1,880
2,043
3,759
3,922
Net Income Attributable to Controlling Interest
127,367
171,021
363,324
399,110
Basic Earnings Per Common Share
0.40
0.54
1.15
1.27
Diluted Earnings Per Common Share
1.26
Dividends Declared Per Common Share
0.39
0.37
0.79
0.74
Weighted Average Common Shares Outstanding:
Basic
315,950,510
315,154,130
315,742,511
315,141,956
Diluted
317,112,801
315,962,619
317,002,461
315,982,578
CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME
Other Comprehensive Income, Net of Tax:
Qualified Cash Flow Hedging Instruments
510
514
1,019
1,030
Changes in Unrealized Gains/(Losses) on Other Securities
218
(591)
458
(772)
Changes in Funded Status of Pension, SERP and PBOP Benefit Plans
2,086
1,506
3,047
3,127
Other Comprehensive Income, Net of Tax
2,814
1,429
4,524
3,385
Comprehensive Income Attributable to Noncontrolling Interests
(1,880)
(2,043)
(3,759)
(3,922)
Comprehensive Income Attributable to Controlling Interest
130,181
172,450
367,848
402,495
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS
Operating Activities:
Adjustments to Reconcile Net Income to Net Cash Flows Provided by Operating Activities:
Deferred Income Taxes
133,149
256,294
Pension, SERP and PBOP Expense
47,558
97,671
Pension and PBOP Contributions
(40,640)
(122,826)
Regulatory Over/(Under) Recoveries, Net
164,388
(4,793)
Amortization of Regulatory Assets, Net
Proceeds from DOE Damages Claim, Net
125,658
Other
(9,359)
19,932
Changes in Current Assets and Liabilities:
Receivables and Unbilled Revenues, Net
(57,570)
(101,229)
26,633
10,964
Taxes Receivable/Accrued, Net
(62,900)
(58,350)
(112,954)
(127,379)
Other Current Assets and Liabilities, Net
(41,753)
(70,026)
Net Cash Flows Provided by Operating Activities
896,663
769,024
Investing Activities:
Investments in Property, Plant and Equipment
(724,043)
(700,252)
Proceeds from Sales of Marketable Securities
256,309
342,251
Purchases of Marketable Securities
(257,168)
(424,096)
Decrease in Special Deposits
2,894
65,121
Other Investing Activities
579
(843)
Net Cash Flows Used in Investing Activities
(721,429)
(717,819)
Financing Activities:
Cash Dividends on Common Shares
(237,161)
(232,068)
Cash Dividends on Preferred Stock
Decrease in Short-Term Debt
(213,000)
(720,500)
Issuance of Long-Term Debt
650,000
1,350,000
Retirements of Long-Term Debt
(376,650)
(360,635)
Retirements of Rate Reduction Bonds
(82,139)
Other Financing Activities
(3,932)
(11,634)
Net Cash Flows Used in Financing Activities
(184,502)
(60,898)
Net Decrease in Cash and Cash Equivalents
(9,268)
(9,693)
Cash and Cash Equivalents - Beginning of Period
45,748
Cash and Cash Equivalents - End of Period
36,055
THE CONNECTICUT LIGHT AND POWER COMPANY
CONDENSED BALANCE SHEETS
Cash
10,486
7,237
359,636
319,670
Accounts Receivable from Affiliated Companies
85,134
13,777
95,491
92,401
109,951
150,943
Materials and Supplies
49,525
54,606
56,238
53,082
766,461
691,716
6,592,833
6,451,259
1,392,529
1,663,147
196,935
174,380
1,589,464
1,837,527
8,948,758
8,980,502
The accompanying notes are an integral part of these unaudited condensed financial statements.
Notes Payable to NU Parent
6,400
287,300
312,000
150,000
189,171
201,047
Accounts Payable to Affiliated Companies
44,031
56,531
Obligations to Third Party Suppliers
59,312
73,914
Accrued Taxes
52,900
37,186
143,457
93,961
85,611
92,233
94,204
97,530
987,086
1,089,702
1,610,662
1,510,586
86,677
93,757
445,342
617,072
66,543
95,895
154,001
163,588
2,363,225
2,480,898
2,679,591
2,591,208
Preferred Stock Not Subject to Mandatory Redemption
116,200
Common Stockholder's Equity:
Common Stock
60,352
1,753,668
1,682,047
989,786
961,482
(1,150)
(1,387)
Common Stockholder's Equity
2,802,656
2,702,494
5,598,447
5,409,902
6
CONDENSED STATEMENTS OF INCOME
587,324
569,329
1,321,938
1,193,425
Purchased Power and Transmission
199,785
184,854
481,165
414,113
131,762
123,760
241,276
232,655
46,581
45,122
92,712
87,570
19,615
463
49,546
11,249
35,296
20,854
77,991
43,668
62,159
57,506
129,111
117,697
495,198
432,559
1,071,801
906,952
92,126
136,770
250,137
286,473
34,639
32,683
67,548
65,318
2,831
1,301
4,165
(1,640)
37,470
33,984
71,713
63,678
3,130
2,897
4,202
7,084
57,786
105,683
182,626
229,879
20,401
37,826
65,942
77,014
37,385
67,857
116,684
152,865
CONDENSED STATEMENTS OF COMPREHENSIVE INCOME
111
222
(20)
(26)
118
91
237
196
Comprehensive Income
37,503
67,948
116,921
153,061
CONDENSED STATEMENTS OF CASH FLOWS
43,253
99,045
Pension, SERP and PBOP Expense, Net of PBOP Contributions
5,973
13,826
18,156
(36,902)
Proceeds from DOE Damages Claim
65,370
(3,428)
(13,476)
(129,209)
(33,976)
27,679
(14,081)
(26,995)
(95,487)
15,705
7,548
275,446
178,181
(221,365)
(184,875)
1,575
884
(219,790)
(183,991)
Cash Dividends on Common Stock
(85,600)
(76,000)
(2,779)
Issuance of Long Term Debt
250,000
400,000
Decrease in Notes Payable to NU Parent
(280,900)
(215,800)
Capital Contribution from NU Parent
70,000
(89,000)
(3,128)
(6,345)
Net Cash Flows (Used in)/Provided by Financing Activities
(52,407)
10,076
Net Increase in Cash
3,249
4,266
Cash - Beginning of Period
Cash - End of Period
4,267
NSTAR ELECTRIC COMPANY AND SUBSIDIARY
12,975
8,021
230,039
209,711
27,264
40,514
41,368
51,635
44,236
178,640
204,144
1,012
36,710
514,815
571,454
5,147,239
5,043,887
1,020,990
1,235,156
64,963
60,624
1,085,953
1,295,780
6,748,007
6,911,121
194,500
103,500
4,700
301,650
150,615
207,559
69,949
75,707
44,308
7,946
54,434
50,128
89,161
53,958
109,048
110,464
716,715
910,912
1,377,432
1,466,835
260,480
253,108
150,151
118,010
Payable to Affiliated Companies
64,172
129,837
142,214
1,917,900
2,044,339
1,792,702
1,499,417
43,000
992,625
1,285,065
1,420,828
2,277,690
2,413,453
4,113,392
3,955,870
10
561,513
570,420
1,227,701
1,162,677
242,907
189,843
561,989
403,896
78,981
87,891
164,905
180,192
46,915
45,441
93,540
90,882
(1,517)
53,554
14,147
100,548
15,054
40,255
50,679
88,584
102,382
32,458
30,491
64,610
62,665
439,999
457,899
987,775
955,619
121,514
112,521
239,926
207,058
19,732
19,809
40,489
39,401
960
(2,620)
1,263
(6,288)
20,692
17,189
41,752
33,113
Other Income/(Loss), Net
(246)
375
(277)
1,149
100,576
95,707
197,897
175,094
40,447
37,676
79,681
68,941
60,129
58,031
118,216
106,153
Adjustments to Reconcile Net Income to Net Cash Flows Provided by Operating Activities
(21,724)
28,750
Pension and PBOP Expense, Net of Contributions
(8,281)
(5,139)
63,955
(33,901)
29,113
Bad Debt Expense
12,272
11,307
(29,142)
(47,574)
(31,746)
(60,174)
(7,399)
3,294
65,692
(39,813)
(21,511)
(8,686)
Accounts Receivable from/Payable to Affiliates, Net
107,363
(57,369)
3,158
(11,702)
387,653
91,630
(213,508)
(207,380)
581
38,429
(5)
77
(212,932)
(168,874)
(253,000)
(56,000)
(980)
(1,143)
Increase/(Decrease) in Notes Payable
91,000
(23,000)
300,000
200,000
(301,650)
(1,650)
(43,493)
(5,137)
(169,767)
74,714
Net Increase/(Decrease) in Cash and Cash Equivalents
4,954
(2,530)
13,695
11,165
PUBLIC SERVICE COMPANY OF NEW HAMPSHIRE AND SUBSIDIARY
337
130
69,646
76,331
90
36,971
38,344
Taxes Receivable
45,957
2,180
120,723
128,736
95,270
92,194
21,770
21,920
390,728
359,925
2,519,921
2,467,556
187,592
219,346
53,779
39,891
241,371
259,237
3,152,020
3,086,718
95,000
86,500
50,000
58,910
82,920
18,760
22,040
36,627
20,643
25,397
28,596
35,440
51,729
320,134
342,428
563,291
500,166
50,843
51,723
Accrued SERP and PBOP
15,055
15,272
46,598
46,247
675,787
613,408
999,157
999,006
702,652
701,911
462,233
438,515
(7,943)
(8,550)
1,156,942
1,131,876
2,156,099
2,130,882
14
211,626
216,113
511,458
489,942
68,349
50,073
183,595
151,097
70,249
62,400
132,462
122,129
24,464
22,947
48,679
45,515
(20,393)
1,081
(7,831)
(1,969)
4,991
19,748
3,292
3,376
7,131
7,046
16,635
16,918
34,348
33,932
162,596
161,786
398,384
377,498
49,030
54,327
113,074
112,444
11,390
10,811
22,916
22,606
(391)
55
709
10,999
11,148
22,971
23,315
946
632
1,212
1,662
38,977
43,811
91,315
90,791
14,897
16,617
34,597
34,602
24,080
27,194
56,718
56,189
291
582
(34)
26
(45)
(3)
303
257
607
534
24,383
27,451
57,325
56,723
61,093
25,450
14,228
(833)
(45,721)
Regulatory Overrecoveries, Net
18,849
4,844
Amortization of Regulatory Liabilities, Net
13,103
4,386
3,123
3,500
597
8,013
(13,289)
(55,243)
21,584
(7,146)
26,159
(4,166)
(17,743)
142,371
138,715
(117,387)
(109,565)
(Increase)/Decrease in Special Deposits
22,039
(56)
(13)
(117,488)
(87,539)
(33,000)
(34,000)
Increase in Notes Payable to NU Parent
8,500
118,900
(108,985)
(29,294)
(176)
(225)
(24,676)
(53,604)
Net Increase/(Decrease) in Cash
207
(2,428)
2,493
65
WESTERN MASSACHUSETTS ELECTRIC COMPANY
1,709
49,404
49,018
4,445
47,607
15,617
16,562
15,228
432
36,251
43,024
19,408
26,628
10,730
10,479
152,792
193,750
1,418,673
1,381,060
120,303
146,088
38,640
31,243
50,438
40,679
209,381
218,010
1,780,846
1,792,820
15,900
28,502
62,961
7,533
9,230
Accrued Interest
7,524
7,525
44,745
19,858
57
13,098
Counterparty Deposits
188
7,688
16,518
20,629
120,967
140,989
423,013
396,933
10,317
13,873
2,805
3,911
39,121
28,619
475,256
443,336
628,932
629,389
10,866
391,035
390,743
157,134
181,014
(3,344)
(3,517)
555,691
579,106
1,184,623
1,208,495
18
108,289
115,015
245,698
239,968
37,619
32,254
87,050
72,298
23,686
23,136
46,265
44,064
9,310
20,638
18,280
343
685
741
814
3,091
7,780
10,249
7,925
22,114
16,240
8,396
6,206
16,479
12,494
90,610
82,607
193,287
171,970
17,679
32,408
52,411
67,998
6,104
6,078
12,165
12,032
603
198
537
6,707
6,276
12,353
12,569
594
419
1,168
1,423
11,566
26,551
41,226
56,852
4,548
10,137
16,106
21,836
7,018
16,414
25,120
35,016
84
169
(6)
(8)
86
78
173
161
7,104
16,492
25,293
35,177
15,234
33,317
28,115
(5,094)
18,073
1,462
572
44,859
(8,681)
(19,555)
21,081
(26,494)
21,389
(11,587)
(5,166)
96,606
119,308
(61,470)
(96,051)
44,449
41,604
(44,754)
(41,961)
4,601
(61,775)
(91,807)
(49,000)
(20,000)
3,300
Retirement of Rate Reduction Bonds
(9,352)
(22)
(31)
(33,122)
(26,083)
1,418
1,419
COMBINED NOTES TO CONDENSED CONSOLIDATED 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 consolidated 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. 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.
The unaudited condensed consolidated financial statements of NU, NSTAR Electric and PSNH include the accounts of each of their respective subsidiaries. Intercompany transactions have been eliminated in consolidation. The accompanying unaudited condensed consolidated financial statements of NU, NSTAR Electric and PSNH and the unaudited condensed financial statements of CL&P and WMECO are herein collectively referred to as the "financial statements."
The combined notes to the financial statements have been prepared pursuant to the rules and regulations of the SEC. Certain information and footnote disclosures included in annual financial statements prepared in accordance with GAAP have been omitted pursuant to such rules and regulations. The accompanying financial statements should be read in conjunction with the entirety of this combined Quarterly Report on Form 10-Q, the first quarter 2014 combined Quarterly Report on Form 10-Q and the 2013 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 June 30, 2014 and December 31, 2013, the results of operations and comprehensive income for the three and six months ended June 30, 2014 and 2013, and the cash flows for the six months ended June 30, 2014 and 2013. The results of operations and comprehensive income for the three and six months ended June 30, 2014 and 2013, and the cash flows for the six months ended June 30, 2014 and 2013 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 of the NU financial statements. For CL&P, NSTAR Electric, PSNH and WMECO, the investments 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, CL&P, NSTAR Electric and PSNH, and in the statements of income for NU, NSTAR Electric, PSNH and WMECO. These reclassifications were made to conform to the current period presentation.
B.
Accounting Standards
Recently Adopted Accounting Standards: On January 1, 2014, as required, NU prospectively adopted the Financial Accounting Standards Board's (FASB) final Accounting Standards Updates (ASU) that required presentation of certain unrecognized tax benefits as reductions to deferred tax assets. Implementation of this guidance had an immaterial impact on the balance sheets and no impact on the results of operations or cash flows of NU, CL&P, NSTAR Electric, PSNH and WMECO.
Accounting Standards Issued but not Yet Adopted: In May 2014, the FASB issued ASU 2014-09, Revenue from Contracts with Customers, effective January 1, 2017, which amends existing revenue recognition guidance and is required to be applied retrospectively (either to each reporting period presented or cumulatively at the date of initial application). Management is reviewing the requirements of the new ASU, however the ASU's impact is not expected to have a material impact on the financial statements of NU, CL&P, NSTAR Electric, PSNH and WMECO.
C.
Provision for Uncollectible Accounts
NU, including CL&P, NSTAR Electric, PSNH and WMECO, presents its receivables at estimated net realizable value by maintaining a provision for uncollectible accounts. This provision is determined based upon a variety of factors, including the application of an estimated uncollectible percentage to each receivable aging category. The estimate is based upon historical collection and write-off experience and management's assessment of collectibility from individual customers. Management continuously assesses the collectibility of receivables, and adjusts collectibility estimates based on actual experience. Receivable balances are written off against the provision for uncollectible accounts when the accounts are terminated and these balances are deemed to be uncollectible. The provision for uncollectible accounts, which is included in Receivables, Net on the balance sheets, was as follows:
(Millions of Dollars)
As of June 30, 2014
As of December 31, 2013
NU
197.4
171.3
91.8
82.0
44.4
41.7
9.2
7.4
12.9
10.0
D.
Fair Value Measurements
Fair value measurement guidance is applied to derivative contracts that are not elected or designated as "normal purchases or normal sales" (normal) 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 9, "Fair Value of Financial Instruments," to the financial statements.
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. Investment income/(loss) primarily relates to debt and equity securities held in trust. For further information, see Note 5, "Marketable Securities," to the financial statements. 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 Six Months Ended
June 30, 2014
June 30, 2013
35.2
33.0
79.6
71.4
30.9
29.8
66.5
61.8
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.
22
G.
Supplemental Cash Flow Information
Non-cash investing activities include plant additions included in Accounts Payable as follows:
As of June 30, 2013
125.5
109.5
54.0
28.3
21.6
33.4
14.8
15.5
9.9
17.0
In the first half of 2014, as a result of awards issued to the Yankee Companies for spent nuclear fuel lawsuits against the DOE described in Note 8C, "Commitments and Contingencies - Contractual Obligations - Yankee Companies," NU recognized total proceeds of $125.7 million, which were net of $80.6 million in proceeds CY and YAEC returned to non-affiliated member companies.
H.
Severance Benefits
NU recorded severance benefit expenses of $1.4 million and $5.7 million associated with the partial outsourcing of information technology functions and ongoing post-merger integration for the three and six months ended June 30, 2014, respectively. As of June 30, 2014 and December 31, 2013, the severance accrual totaled $9.3 million and $14.7 million, respectively, and was included in Other Current Liabilities on the balance sheets.
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 follow 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
1,146.7
1,240.2
431.4
638.0
Income Taxes, Net
631.8
626.2
Storm Restoration Costs
503.9
589.6
Goodwill-related
515.7
525.9
Regulatory Tracker Mechanisms
275.1
323.4
Contractual Obligations - Yankee Companies
128.4
154.2
Buy Out Agreements for Power Contracts
56.7
70.2
Other Regulatory Assets
117.0
126.8
Total Regulatory Assets
3,806.7
4,294.5
Less: Current Portion
467.2
535.8
Total Long-Term Regulatory Assets
3,339.5
3,758.7
Electric
251.9
81.6
46.2
297.7
496.7
100.6
57.3
424.6
6.3
630.4
7.7
426.2
81.4
38.0
40.8
415.5
84.0
40.3
43.7
328.0
107.2
34.7
34.0
397.8
109.3
38.8
442.8
451.5
8.1
131.8
87.9
20.7
8.0
169.5
83.3
32.6
52.0
4.7
64.7
5.5
63.7
54.7
36.0
14.9
64.6
55.9
38.1
16.7
1,502.5
1,199.6
282.9
156.6
1,814.0
1,439.3
311.5
189.1
110.0
178.6
95.3
36.3
150.9
204.1
92.2
43.0
1,392.5
1,021.0
187.6
120.3
1,663.1
1,235.2
219.3
146.1
Benefit Costs: For information related to the Regulated companies' pension and other postretirement benefits, see Note 7, "Pension Benefits and Postretirement Benefits Other Than Pensions."
Storm Restoration Costs: On March 12, 2014, the PURA approved recovery of $365 million of deferred storm restoration costs associated with five major storms that occurred in 2011 and 2012. CL&P will recover the $365 million with carrying charges in its distribution rates over a six-year period beginning December 1, 2014. On June 17, 2014, the PURA ordered CL&P to use the DOE Phase II Damages proceeds of $65.4 million to offset the $365 million in 2011 and 2012 deferred storm restoration costs, which are reflected in the deferred storm restoration costs regulatory asset.
23
For further information on the DOE Phase II Damages proceeds received from the Yankee Companies, see Note 8C, "Commitments and Contingencies - Contractual Obligations - Yankee Companies," to the financial statements.
Regulatory Costs in Other Long-Term Assets: The Regulated companies had $64.5 million ($3.4 million for CL&P, $33.9 million for NSTAR Electric, and $12 million for WMECO) and $65.1 million ($7.3 million for CL&P, $33.4 million for NSTAR Electric, and $10.1 million for WMECO) of additional regulatory costs as of June 30, 2014 and December 31, 2013, respectively, that were included in Other Long-Term Assets on the balance sheets. These amounts represent incurred costs for which recovery has not yet been specifically approved by the applicable regulatory agency. However, based on regulatory policies or past precedent on similar costs, management believes it is probable that these costs will ultimately be approved and recovered from customers in rates.
Regulatory Liabilities: The components of regulatory liabilities are as follows:
Cost of Removal
435.3
435.1
305.2
151.2
AFUDC - Transmission
67.4
68.1
Other Regulatory Liabilities
56.0
52.9
Total Regulatory Liabilities
863.9
707.3
359.9
204.3
Total Long-Term Regulatory Liabilities
504.0
503.0
22.8
255.7
48.7
29.1
250.0
49.7
143.2
60.2
34.8
45.1
95.6
21.9
21.1
54.2
4.0
4.1
9.3
3.9
0.7
8.4
31.1
1.0
3.4
230.2
349.7
87.4
55.0
187.8
307.1
72.3
33.8
143.5
89.2
36.6
44.7
94.0
20.6
19.9
86.7
260.5
50.8
10.3
93.8
253.1
51.7
13.9
As a result of two FERC orders issued on June 19, 2014 in the pending base ROE complaint proceedings described in Note 8E, "Commitments and Contingencies – FERC Base ROE Complaints," in the second quarter of 2014, the Company recorded a series of reserves at its electric subsidiaries to recognize the potential financial impact of these rulings. The aggregate pre-tax charge totaled $54.7 million at NU, which represented reserves of $31.4 million at CL&P, $10.3 million at NSTAR Electric, $3.8 million at PSNH and $9.2 million at WMECO. As of June 30, 2014, the cumulative reserves totaled $79.3 million at NU, $44.7 million at CL&P, $16.2 million at NSTAR Electric, $6.2 million at PSNH and $12.2 million at WMECO. As of December 31, 2013, as a result of the FERC ALJ initial decision in the third quarter of 2013, the Company had an aggregate pre-tax reserve of $24.6 million at NU, which represented reserves of $13.3 million at CL&P, $5.9 million at NSTAR Electric, $2.4 million at PSNH and $3 million at WMECO. These reserves were recorded in each electric subsidiary's respective transmission regulatory tracker mechanism and as a reduction of operating revenues.
As a result of awards issued to the Yankee Companies for spent nuclear fuel lawsuits against the DOE described in Note 8C, "Commitments and Contingencies - Contractual Obligations - Yankee Companies," the Yankee Companies returned the DOE Phase II Damages proceeds to the member companies, including CL&P, NSTAR Electric, PSNH, and WMECO, for the benefit of their respective customers, effective June 1, 2014. CL&P's refund obligation to customers of $65.4 million was recorded as an offset to the deferred storm restoration costs regulatory asset, as directed by PURA. NSTAR Electric's, PSNH's and WMECO's refund obligation to customers of $29.1 million, $13.1 million and $18.1 million, respectively, was recorded as a regulatory liability in each electric subsidiary's respective regulatory tracker mechanisms.
24
3.
PROPERTY, PLANT AND EQUIPMENT AND ACCUMULATED DEPRECIATION
The following tables summarize the investments in utility property, plant and equipment by asset category:
Distribution - Electric
12,145.0
11,950.2
Distribution - Natural Gas
2,467.4
2,425.9
Transmission
6,508.0
6,412.5
Generation
1,167.9
1,152.3
Electric and Natural Gas Utility
22,288.3
21,940.9
Other (1)
506.5
508.7
Property, Plant and Equipment, Gross
22,794.8
22,449.6
Less: Accumulated Depreciation
(5,575.8)
(5,387.0)
(207.7)
(196.2)
Total Accumulated Depreciation
(5,783.5)
(5,583.2)
17,011.3
16,866.4
Construction Work in Progress
967.4
709.8
Total Property, Plant and Equipment, Net
17,978.7
17,576.2
(1)
These assets represent unregulated property and are primarily comprised of building improvements, computer software, hardware and equipment and telecommunications assets at NU's unregulated companies.
Distribution
5,035.2
4,754.4
1,629.1
766.3
4,930.7
4,694.7
1,608.2
756.6
3,108.1
1,798.9
713.5
841.1
3,071.9
1,772.3
695.7
826.4
1,134.0
33.9
1,131.2
8,143.3
6,553.3
3,476.6
1,641.3
8,002.6
6,467.0
3,435.1
1,604.1
(1,867.9)
(1,700.6)
(1,045.3)
(283.7)
(1,804.1)
(1,631.3)
(1,021.8)
(271.5)
6,275.4
4,852.7
2,431.3
1,357.6
6,198.5
4,835.7
2,413.3
1,332.6
317.4
294.5
88.6
61.1
252.8
208.2
54.3
48.5
6,592.8
5,147.2
2,519.9
1,418.7
6,451.3
5,043.9
2,467.6
1,381.1
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 and qualify for accrual accounting under the applicable accounting guidance. 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.
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 to offset the fair values of derivatives, as costs are recovered from, or refunded to, customers in their respective energy supply rates. For NU's unregulated wholesale marketing contracts that expired on December 31, 2013, changes in fair values of derivatives were included in Net Income.
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 amount 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 2:
NU (1)
0.4
(0.1)
0.3
Level 3:
NU, CL&P (1)
16.4
(4.8)
11.6
Long-Term Derivative Assets:
111.7
(17.0)
94.7
Current Derivative Liabilities:
(0.7)
0.2
(0.5)
(87.8)
(85.6)
(2.2)
Long-Term Derivative Liabilities:
(449.4)
(445.3)
(4.1)
1.9
(0.3)
1.6
18.4
(9.8)
8.6
CL&P (1)
17.1
7.3
1.2
116.2
(42.2)
74.0
113.6
(93.7)
(92.2)
(1.5)
(624.1)
(617.1)
(7.0)
Amounts represent derivative assets and liabilities that NU 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.
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, along with UI, has capacity-related contracts with generation facilities. 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 combined capacity of these contracts is 787 MW. 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 and a capacity-related contract to purchase up to 35 MW per year through 2019.
As of June 30, 2014 and December 31, 2013, NU had NYMEX future contracts in order to reduce variability associated with the purchase price of approximately 6.6 million and 9.1 million MMBtu of natural gas, respectively.
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:
Amounts Recognized on Derivatives
Balance Sheets:
Regulatory Assets and Liabilities
111.6
22.2
166.0
50.1
Statements of Income:
0.5
0.8
Credit Risk
Certain of NU's derivative contracts contain credit risk contingent features. These features require NU to maintain investment grade credit ratings from the major rating agencies and to post collateral for contracts in a net liability position over specified credit limits. As of June 30, 2014, NSTAR Gas had derivative contracts in a net liability position that were subject to credit risk contingent features. If NSTAR Gas' credit rating was downgraded below investment grade, NU would have been required to post approximately $0.6 million in collateral. As of December 31, 2013, there were no derivative contracts in a net liability position that were subject to credit risk contingent features.
Valuation of Derivative Instruments
Derivative contracts classified as Level 2 in the fair value hierarchy relate to the financial contracts for natural gas futures. Prices are obtained from broker quotes and are based on actual market activity. The contracts are valued using NYMEX natural gas prices. 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 valuations adjusted for assumptions relating to exit price. Significant observable inputs for valuations of these contracts include energy and energy-related product prices in future years for which quoted prices in an active market exist. Fair value measurements categorized in Level 3 of the fair value hierarchy are prepared by individuals with expertise in valuation techniques, pricing of energy and energy-related products, and accounting requirements. The future power and capacity prices for periods that are not quoted in an active market or established at auction are based on available market data and are escalated based on estimates of inflation to address the full time period of the contract.
Valuations of derivative contracts using a 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 and NSTAR Electric'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:
63
66
per MWh
2018 - 2020
49
2018 - 2029
Capacity Prices:
3.13
13.00
per kW-Month
2016 - 2026
5.07
11.82
2017 - 2029
7.00
2018 - 2026
10.42
2017 - 2026
11.13
2016 - 2019
7.38
2017 - 2019
Forward Reserve:
NU, CL&P
3.30
9.50
2014 - 2024
REC Prices:
38
70
per REC
2014 - 2018
36
87
2014 - 2029
Exit price premiums of 8 percent through 25 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 energy 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.
27
Valuations using significant unobservable inputs: The following tables present changes 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.
Derivatives, Net:
Fair Value as of Beginning of Period
(564.3)
(833.1)
(635.2)
(878.6)
Net Realized/Unrealized Gains Included in:
1.3
7.1
111.8
22.7
161.3
48.9
Settlements
21.0
34.5
Fair Value as of End of Period
(430.9)
(788.1)
(557.0)
(7.3)
(819.6)
(13.6)
Net Realized/Unrealized Gains/(Losses)
Included in Regulatory Assets and Liabilities
112.2
(0.4)
20.2
1.4
(424.6)
(6.3)
(775.8)
(13.1)
(630.6)
(866.2)
(14.9)
Net Realized/Unrealized Gains/(Losses) Included in Regulatory Assets and Liabilities
164.5
46.3
41.5
1.5
44.1
5.
MARKETABLE SECURITIES
NU maintains trusts to fund certain non-qualified executive benefits and WMECO maintains a spent nuclear fuel trust to fund WMECO's prior period spent nuclear fuel liability. These trusts hold marketable securities. These trusts are not subject to regulatory oversight by state or federal agencies. In addition, CYAPC and YAEC maintain legally restricted trusts, each of which holds marketable securities, for settling the decommissioning obligations of their nuclear power plants.
In accordance with applicable accounting guidance, the Company elected to record mutual funds designated as available-for-sale at fair value and certain other equity investments as trading securities, with the changes in fair values recorded in Other Income, Net on the statements of income. As of June 30, 2014, the mutual funds and equity investments were classified as Level 1 in the fair value hierarchy and totaled $59.6 million and $24.9 million, respectively. As of December 31, 2013, the mutual funds were classified as Level 1, and totaled $57.2 million. Net gains on the mutual funds were $2.2 million and $0.1 million for the three months ended June 30, 2014 and 2013, respectively, and $2.4 million and $4.3 million for the six months ended June 30, 2014 and 2013, respectively. Net gains on the equity investments were $0.9 million and $1.4 million for the three and six months ended June 30, 2014, respectively. Dividend income is recorded in Other Income, Net on the statements of income when dividends are declared. All other marketable securities are accounted for as available-for-sale.
Available-for-Sale Securities: The following is a summary of NU's and WMECO's available-for-sale securities. 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
Losses
Fair Value
Debt Securities (1)
308.3
315.3
Equity Securities (1)
163.5
66.7
Debt Securities (2)
58.0
28
299.2
2.5
(2.1)
299.6
163.6
60.5
224.1
57.9
NU's amounts include CYAPC's and YAEC's marketable securities held in nuclear decommissioning trusts of $444.3 million and $424 million as of June 30, 2014 and December 31, 2013, respectively, which are legally restricted and can only be used for the decommissioning of the nuclear power plants owned by these companies. 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 statements of income. All of the equity securities accounted for as available-for-sale securities are held in the CYAPC and YAEC trusts.
(2)
Unrealized gains and losses on debt securities held by WMECO are recorded in Other Long-Term Assets on the balance sheets.
Unrealized Losses and Other-than-Temporary Impairment: There have been no significant unrealized losses, other-than-temporary impairments or credit losses for NU or WMECO. 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 NU's benefit trust, Other Long-Term Assets for WMECO, and offset in Other Long-Term Liabilities for CYAPC and YAEC. NU utilizes the specific identification basis method for the NU benefit trust and the average cost basis method for the WMECO trust and the CYAPC and YAEC nuclear decommissioning trusts to compute the realized gains and losses on the sale of available-for-sale securities.
Contractual Maturities: As of June 30, 2014, the contractual maturities of available-for-sale debt securities are as follows:
Less than one year (1)
75.9
75.8
19.2
One to five years
73.9
74.6
31.9
32.0
Six to ten years
56.1
57.7
2.7
Greater than ten years
102.4
4.2
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, 2013
Level 1:
Mutual Funds and Equities
314.7
281.3
Money Market Funds
42.3
32.9
2.0
10.9
Total Level 1
357.0
314.2
U.S. Government Issued Debt Securities
(Agency and Treasury)
40.6
61.4
6.8
Corporate Debt Securities
53.6
15.8
15.1
Asset-Backed Debt Securities
36.5
30.4
15.2
9.0
Municipal Bonds
105.5
11.7
11.2
Other Fixed Income Securities
24.6
13.3
4.9
Total Level 2
273.0
266.7
47.0
Total Marketable Securities
630.0
580.9
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.
29
6.
SHORT-TERM AND LONG-TERM DEBT
Credit Agreements and Commercial Paper Programs: Effective July 23, 2014, NU parent, CL&P, PSNH, WMECO, NSTAR Gas and Yankee Gas amended their joint $1.45 billion revolving credit facility to extend the expiration date an additional year to September 6, 2019. The revolving credit facility is to be used primarily to backstop NU parent's $1.45 billion commercial paper program. The commercial paper program allows NU parent to issue commercial paper as a form of short-term debt. As of June 30, 2014 and December 31, 2013, NU had $710.5 million and $1.01 billion, respectively, in short-term borrowings outstanding under the NU parent commercial paper program, leaving $739.5 million and $435.5 million of available borrowing capacity as of June 30, 2014 and December 31, 2013, respectively. The weighted-average interest rate on these borrowings as of June 30, 2014 and December 31, 2013 was 0.25 percent and 0.24 percent, respectively, which is generally based on A2/P2 rated commercial paper. As of June 30, 2014, there were intercompany loans from NU of $6.4 million to CL&P, $95 million to PSNH and $15.9 million to WMECO. As of December 31, 2013, there were intercompany loans from NU of $287.3 million to CL&P and $86.5 million to PSNH.
Effective July 23, 2014, NSTAR Electric amended its $450 million revolving credit facility to extend the expiration date an additional year to September 6, 2019. This facility serves to backstop NSTAR Electric's existing $450 million commercial paper program. As of June 30, 2014 and December 31, 2013, NSTAR Electric had $194.5 million and $103.5 million, respectively, in short-term borrowings outstanding under its commercial paper program, leaving $255.5 million and $346.5 million of available borrowing capacity as of June 30, 2014 and December 31, 2013, respectively. The weighted-average interest rate on these borrowings as of June 30, 2014 and December 31, 2013 was 0.16 percent and 0.13 percent, respectively, which is generally based on A2/P1 rated commercial paper.
Amounts outstanding under the commercial paper programs are generally 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 NU Parent and classified in current liabilities on the balance sheets. See the Long-Term Debt portion of this Note immediately below for further information on the Yankee Gas $100 million bond issuance and its impact on the NU balance sheet as of December 31, 2013.
Short-Term Borrowing Limits: The amount of short-term borrowings that may be incurred by NSTAR Electric is subject to periodic approval by the FERC. On June 11, 2014, the FERC granted authorization to allow NSTAR Electric to issue total short-term debt securities in an aggregate principal amount not to exceed $655 million outstanding at any one time, effective October 24, 2014 through October 23, 2016.
Long-Term Debt: On January 2, 2014, Yankee Gas issued $100 million of 4.82 percent Series L First Mortgage Bonds, due to mature in 2044. The proceeds, net of issuance costs, were used to repay the $75 million 4.80 percent Series G First Mortgage Bonds that matured on January 1, 2014 and to pay $25 million in short-term borrowings. In accordance with applicable accounting guidance, these amounts were classified as Long-Term Debt on NU's balance sheet as of December 31, 2013.
On March 7, 2014, NSTAR Electric issued $300 million of 4.40 percent debentures, due to mature in 2044. The proceeds, net of issuance costs, were used to repay the $300 million of 4.875 percent debentures that matured on April 15, 2014.
On April 24, 2014, CL&P issued $250 million of 4.30 percent 2014 Series A First Mortgage Bonds, due to mature in April 2044. The proceeds, net of issuance costs, were used to repay short-term borrowings.
On July 15, 2014, PSNH repaid at maturity the $50 million of 5.25 percent Series L First Mortgage Bonds using short-term debt.
Working Capital: Each of NU, CL&P, NSTAR Electric, PSNH and WMECO use its available capital resources to fund its 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 recover their electric and natural gas distribution construction expenditures as the related project costs are depreciated over the life of the assets. 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 $730 million, $220 million and $200 million at NU, CL&P and NSTAR Electric, respectively, as of June 30, 2014.
As of June 30, 2014, $366.7 million of NU's obligations classified as current liabilities relates to long-term debt that will be paid in the next 12 months, consisting of $312 million for CL&P, $4.7 million at NSTAR Electric and $50 million for PSNH. In addition, $28.9 million relates to the amortization of the purchase accounting fair value adjustment that will be amortized in the next twelve months. 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 or with the issuance of new long-term debt, determined considering capital requirements and maintenance of NU's credit rating and profile. Management expects the future operating cash flows of NU, CL&P, NSTAR Electric, PSNH and WMECO, along with the access to financial markets, will be sufficient to meet any future operating requirements and capital investment forecasted opportunities.
30
7.
PENSION BENEFITS AND POSTRETIREMENT BENEFITS OTHER THAN PENSIONS
The components of net periodic benefit expense for the Pension, SERP and PBOP Plans are detailed below. The net periodic benefit expense less the capitalized portion of pension and PBOP amounts is included in Operations and Maintenance on the statements of income. Capitalized pension and PBOP amounts relate to employees working on capital projects and are included in Property, Plant and Equipment, Net. Intercompany allocations are not included in the CL&P, NSTAR Electric, PSNH and WMECO net periodic benefit expense amounts.
Pension and SERP
Service Cost
19.1
51.1
Interest Cost
56.3
51.9
113.0
103.5
Expected Return on Plan Assets
(77.7)
(68.6)
(155.4)
(139.0)
Actuarial Loss
31.7
52.6
Prior Service Cost
1.1
2.1
Total Net Periodic Benefit Expense
30.5
61.5
65.9
123.2
Capitalized Pension Expense
8.7
3.2
3.7
8.5
12.1
24.7
23.6
(15.8)
(13.9)
(31.6)
(27.7)
3.0
6.0
13.0
Prior Service Credit
(1.4)
(1.1)
1.8
16.3
Capitalized PBOP Expense
5.0
For the Three Months Ended June 30, 2014
For the Three Months Ended June 30, 2013
Electric(1)
2.3
12.4
5.8
14.7
5.9
(18.7)
(15.7)
(9.3)
(4.4)
(18.4)
(20.2)
(9.2)
8.2
2.8
1.7
14.6
5.4
2.9
Prior Service Cost/(Credit)
0.1
3.5
14.4
Intercompany Allocations
7.5
11.3
2.6
4.4
0.6
7.0
6.5
For the Six Months Ended June 30, 2014
For the Six Months Ended June 30, 2013
10.2
7.6
5.1
16.5
2.4
25.7
12.3
5.2
24.2
29.0
11.9
(38.0)
(31.5)
(19.5)
(9.0)
(36.9)
(16.8)
(8.7)
17.3
28.0
10.8
0.9
16.1
28.6
32.3
12.7
4.8
14.3
3.8
22.1
14.0
11.8
31
(2.5)
(6.5)
(1.3)
(0.6)
Actuarial Loss/(Gain)
(0.2)
Total Net Periodic Benefit Expense/(Income)
(1.6)
0.0
Capitalized PBOP Expense/(Income)
9.7
(5.2)
(13.0)
(2.7)
(5.0)
(2.6)
(1.2)
(0.9)
(2.9)
4.3
2.2
3.6
(1.0)
NSTAR Electric's pension amounts for the three and six months ended June 30, 2013 do not include SERP expense.
For the three and six months ended June 30, 2013, the net periodic PBOP expense allocated to NSTAR Electric was a benefit of $2 million and an expense of $2.3 million, respectively.
As of December 31, 2013, the funded status of the NSTAR Pension Plan was recorded on NSTAR Electric's balance sheet while the total SERP obligation and PBOP Plan funded status were recorded on NSTAR Electric & Gas' balance sheet. As of December 31, 2013, all NSTAR employees were employed by NSTAR Electric & Gas. On January 1, 2014, NSTAR Electric & Gas was merged into NUSCO and, concurrently, all employees were transferred to the company they predominately provide services for: NUSCO, NSTAR Electric or NSTAR Gas. As a result of the employee transfers, the pension and PBOP assets and liabilities were attributed by participant and transferred to the respective company's balance sheets.
As of June 30, 2014, the liabilities associated with the Pension, SERP and PBOP plans for NSTAR Electric were $85.8 million for the Pension Plan, $3.6 million for the SERP Plans ($0.4 million of which is included in other current liabilities) and $61.2 million for the PBOP Plan. As of December 31, 2013, the liability associated with the NSTAR Pension Plan for NSTAR Electric was $118 million. This change had no impact on the income statement or net assets of NSTAR Electric or NU.
8.
COMMITMENTS AND CONTINGENCIES
Environmental Matters
General: NU, CL&P, NSTAR Electric, PSNH and WMECO are subject to environmental laws and regulations intended to mitigate or remove the effect of past operations and improve or maintain the quality of the environment. These laws and regulations require the removal or the remedy of the effect on the environment of the disposal or release of certain specified hazardous substances at current and former operating sites. NU, CL&P, NSTAR Electric, PSNH and WMECO have an active environmental auditing and training program and believe that they are substantially in compliance with all enacted laws and regulations.
The number of environmental sites and reserves related to these sites for which remediation or long-term monitoring, preliminary site work or site assessment are being performed are as follows:
Reserve
Number of Sites
(in millions)
68
35.4
5.3
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 $29.8 million and $31.4 million as of June 30, 2014 and December 31, 2013, respectively, and relates primarily to the natural gas business segment.
32
Long-Term Contractual Arrangements
The following is an update to the current status of long-term contractual arrangements set forth in Note 12B of the NU 2013 Form 10-K.
Renewable Energy: Renewable energy contracts include non-cancelable commitments under contracts of NSTAR Electric and WMECO for the purchase of energy and capacity from renewable energy facilities.
July - December
2015
2016
2017
2018
Thereafter
Total
Renewable Energy
43.6
86.3
93.7
89.8
53.3
302.8
669.5
28.9
36.1
Contractual Obligations – Yankee Companies
Spent Nuclear Fuel Litigation - DOE Phase II Damages - On November 15, 2013, the Court of Federal Claims issued an award to CYAPC for $126.3 million, YAEC for $73.3 million and MYAPC for $35.8 million for lawsuits against the DOE seeking recovery of actual damages incurred in the years following 2001 and 2002 (DOE Phase II Damages). On January 14, 2014, the Yankee Companies received a letter from the U.S. Department of Justice stating that the DOE will not appeal the court's final judgment.
On March 28, 2014, CYAPC, YAEC and MYAPC received payment of $90 million, $73.3 million and $35.8 million, respectively, of the DOE Phase II Damages proceeds. On April 24, 2014, CYAPC received payment of the remaining $36.3 million proceeds. On April 28, 2014, the Yankee Companies made the required informational filing with FERC in accordance with the process and methodology outlined in the 2013 FERC order. The Yankee Companies returned the DOE Phase II Damages proceeds to the member companies, including CL&P, NSTAR Electric, PSNH, and WMECO, for the benefit of their respective customers, on June 1, 2014.
As of June 30, 2014, CL&P's refund obligation to customers of $65.4 million was recorded as an offset to the deferred storm restoration costs regulatory asset, as directed by PURA. NSTAR Electric's, PSNH's and WMECO's refund obligation to customers of $29.1 million, $13.1 million and $18.1 million, respectively, was recorded as a regulatory liability in each company's respective regulatory tracker mechanisms. For further information, see Note 2, "Regulatory Accounting," to the financial statements.
DOE Phase III Damages - On August 15, 2013, the Yankee Companies each filed subsequent lawsuits against the DOE seeking recovery of actual damages incurred in the years 2009 through 2012. Responsive pleading from the U.S. Department of Justice was filed on November 18, 2013, and discovery has begun.
Guarantees and Indemnifications
NU parent 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 and the termination of an unregulated business, with maximum exposures either not specified or not material.
NU also issued a guaranty under which, beginning at the time the Northern Pass Transmission line goes into commercial operation, NU will guarantee the financial obligations of NPT under the TSA in an amount not to exceed $25 million. NU's obligations under the guaranty expire upon the full, final and indefeasible payment of the guaranteed obligations.
Management does not anticipate a material impact to Net Income as a result of these various guarantees and indemnifications.
The following table summarizes NU's guarantees of its subsidiaries, including CL&P, NSTAR Electric, PSNH and WMECO, as of June 30, 2014:
Maximum Exposure
Subsidiary
Description
Expiration Dates
Various
Surety Bonds
67.0
2014 - 2016 (1)
New England Hydro Companies' Long-Term Debt
Unspecified
NUSCO and RRR
Lease Payments for Vehicles and Real Estate
16.0
2019 and 2024
Surety bond expiration dates reflect termination dates, the majority of which will be renewed or extended.
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 are downgraded.
FERC Base ROE Complaints
On September 30, 2011, a complaint was filed jointly at FERC under Sections 206 and 306 of the Federal Power Act by several New England state attorneys general, state regulatory commissions, consumer advocates and other parties (the "Complainants"). The Complainants alleged that the base ROE of 11.14 percent that has been utilized since 2006 in the calculation of formula rates for transmission service under the ISO-NE Open Access Transmission Tariff by NETOs, including CL&P, NSTAR Electric, PSNH and WMECO, was unjust and unreasonable and asserted that the rate was excessive due to changes in the capital markets. Complainants sought an order to reduce the base ROE, effective October 1, 2011, and to require refunds. The FERC set the case for trial before a FERC ALJ after settlement negotiations were unsuccessful in August 2012.
33
On August 6, 2013, the FERC ALJ issued an initial decision finding that the base ROE in effect from October 1, 2011 through December 31, 2012 (refund period) was not reasonable, and recommended separate base ROEs for the refund period of 10.6 percent and for the period beginning when FERC issues its final decision (prospective period) of 9.7 percent, leaving policy considerations and additional adjustments to the FERC. In the third quarter of 2013, the Company recorded a series of reserves at its electric subsidiaries to recognize the potential financial impact from the FERC ALJ's initial decision for the refund period. The aggregate after-tax charge to third quarter 2013 earnings totaled $14.3 million at NU, which represented reserves of $7.7 million at CL&P, $3.4 million at NSTAR Electric, $1.4 million at PSNH and $1.8 million at WMECO.
On June 19, 2014, FERC issued an order partially affirming and partially reversing the ALJ's initial decision. FERC set a single tentative base ROE of 10.57 percent for the refund period and prospective period. FERC also modified its traditional methodology by adopting a two-step discounted cash flow analysis that it utilizes to determine the ROEs of both natural gas and oil pipeline projects. Using this methodology, FERC determined a new zone of reasonableness of 7.03 percent to 11.74 percent, and set the tentative base ROE at the 75th percentile of this new zone. FERC also stated that a utility's total ROE inclusive of transmission incentive ROE adders, should not exceed the top of the new zone of reasonableness produced by this methodology. FERC instituted a paper hearing on the long-term growth rate portion of the methodology, before it issues a final determination on the base ROE. On July 21, 2014, the NETOs and Complainants filed rehearing requests in this proceeding.
On December 27, 2012, a second complaint was filed jointly at FERC by several additional consumer groups and municipal parties, which challenged the NETOs' base ROE and sought refunds for the 15-month period beginning January 1, 2013. On June 19, 2014, the FERC issued a second order finding that the complaint raised issues of material fact, and set this complaint for trial, should settlement negotiations be unsuccessful. FERC stated that it could issue an order in this case by mid-2016. On July 21, 2014, the NETOs filed a rehearing request in this proceeding.
Though NU cannot predict the ultimate outcome of this proceeding, in the second quarter of 2014, the Company recorded a series of reserves at its electric subsidiaries to recognize the potential financial impact from the FERC’s two orders issued on June 19, 2014 for the two refund periods. The aggregate after-tax charge to second quarter 2014 earnings totaled $32.1 million at NU, which represented reserves of $18.5 million at CL&P, $6.1 million at NSTAR Electric, $2 million at PSNH and $5.5 million at WMECO.
As of June 30, 2014, the cumulative pre-tax reserves totaled $79.3 million at NU, $44.7 million at CL&P, $16.2 million at NSTAR Electric, $6.2 million at PSNH and $12.2 million at WMECO. As of December 31, 2013, the pre-tax reserves totaled $24.6 million at NU, $13.3 million at CL&P, $5.9 million at NSTAR Electric, $2.4 million at PSNH and $3 million at WMECO. The reserves were recorded in each electric subsidiary's respective transmission regulatory tracker mechanism and as a reduction of operating revenues. See Note 2, “Regulatory Accounting,” for further information.
On July 31, 2014, the Complainants filed an additional complaint with FERC. At this time, the Company cannot determine the outcome of this complaint.
Since 2006, NSTAR Electric has been recovering incremental costs related to the DPU-approved Safety and Reliability Programs. From 2006 through 2011, cumulative costs associated with the CPSL program resulted in an incremental revenue requirement to customers of approximately $83 million. These amounts included incremental operations and maintenance costs and the related revenue requirement for specific capital investments relative to the CPSL programs.
On May 28, 2010, the DPU issued an order on NSTAR Electric's 2006 CPSL cost recovery filing (the May 2010 Order). In October 2010, NSTAR Electric filed a reconciliation of the cumulative CPSL program activity for the periods 2006 through 2009 with the DPU in order to determine a proposed rate adjustment. The DPU allowed the proposed rates to go into effect January 1, 2011, subject to final reconciliation of CPSL program costs through a future DPU proceeding. In February 2013, NSTAR Electric updated the October 2010 filing with final activity through 2011. NSTAR Electric recorded its 2006 through 2011 revenues under the CPSL programs based on the May 2010 Order.
NSTAR Electric cannot predict the timing of a final DPU order related to its CPSL filings for the period 2006 through 2011. While management does not believe that any subsequent DPU order would result in revenues that are materially different than the amounts already recognized, it is reasonably possible that an order could have a material impact on NSTAR Electric's results of operations, financial position and cash flows.
Basic Service Bad Debt Adder
In accordance with a generic DPU order, electric utilities in Massachusetts recover the energy-related portion of bad debt costs in their Basic Service rates. In 2007, NSTAR Electric filed its 2006 Basic Service reconciliation with the DPU proposing an adjustment related to the increase of its Basic Service bad debt charge-offs. The DPU issued an order approving the implementation of a revised Basic Service rate but instructed NSTAR Electric to reduce distribution rates by an amount equal to the increase in its Basic Service bad debt charge-offs. This adjustment to NSTAR Electric's distribution rates would eliminate the fully reconciling nature of the Basic Service bad debt adder.
In 2010, NSTAR Electric filed an appeal of the DPU's order with the SJC. In 2012, the SJC vacated the DPU order and remanded the matter to the DPU for further review. The DPU has not taken any action on the remand.
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 the 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 2012. NSTAR Electric will continue to maintain the reserve until the proceeding has been concluded with the DPU.
34
9.
FAIR VALUE OF FINANCIAL INSTRUMENTS
The following methods and assumptions were used to estimate the fair value of each of the following financial instruments:
Preferred Stock and Long-Term Debt: 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 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
155.6
150.1
152.7
8,542.7
9,008.4
8,310.2
8,443.1
110.3
39.8
2,991.6
3,344.5
1,797.4
1,949.8
1,049.2
1,105.8
628.9
665.3
110.5
42.2
2,741.2
2,952.8
1,801.1
1,888.0
1,049.0
1,073.9
629.4
640.1
Derivative Instruments: Derivative instruments are carried at fair value. For further information, see Note 4, "Derivative Instruments," to the financial statements.
Other Financial Instruments: Investments in marketable securities are carried at fair value. For further information, see Note 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.
10.
ACCUMULATED OTHER COMPREHENSIVE INCOME/(LOSS)
The changes in accumulated other comprehensive income/(loss) by component, net of tax, is as follows:
Pension,
Qualified
Gains/(Losses)
SERP and
Cash Flow
on Available-
Hedging
for-Sale
Benefit
Instruments
Securities
Plans
AOCI as of Beginning of Period
(14.4)
(32.0)
(46.0)
(16.4)
(57.8)
(72.9)
OCI Before Reclassifications
Amounts Reclassified from AOCI
3.1
Net OCI
4.5
AOCI as of End of Period
(13.4)
(29.0)
(41.5)
(15.4)
(54.7)
(69.5)
NU's qualified cash flow hedging instruments represent interest rate swap agreements on debt issuances that were settled in prior years. The settlement amount was recorded in AOCI and is being amortized into Net Income over the term of the underlying debt instrument. CL&P, PSNH and WMECO continue to amortize interest rate swaps settled in prior years from AOCI into Interest Expense over the remaining life of the associated long-term debt, which are not material to their respective financial statements.
35
The following table sets forth the amounts reclassified from AOCI by component and the impacted line item on the statements of income:
Amounts Reclassified
Statements of Income
from AOCI
Line Item Impacted
(0.8)
(1.7)
Tax Benefit
Qualified Cash Flow Hedging Instruments, Net of Tax
Pension, SERP and PBOP Benefit Plan Costs:
Amortization of Actuarial Losses
(4.7)
Operations and Maintenance (1)
Amortization of Prior Service Cost
Total Pension, SERP and PBOP Benefit Plan Costs
(3.0)
Pension, SERP and PBOP Benefit Plan Costs, Net of Tax
(1.8)
(3.1)
Total Amounts Reclassified from AOCI, Net of Tax
(2.0)
(2.8)
These amounts are included in the computation of net periodic Pension, SERP and PBOP costs. See Note 7, "Pension Benefits and Postretirement Benefits Other Than Pensions," for further information.
11.
COMMON SHARES
The following table sets forth the NU common shares and the shares of common stock of CL&P, NSTAR Electric, PSNH and WMECO that were authorized and issued and the respective per share par values:
Shares
Authorized as of
Per Share
June 30, 2014 and
Issued as of
Par Value
380,000,000
333,327,485
333,113,492
24,500,000
6,035,205
100,000,000
100
301
1,072,471
434,653
As of June 30, 2014 and December 31, 2013, there were 17,108,131 and 17,796,672 NU common shares held as treasury shares, respectively. As of June 30, 2014 and December 31, 2013, NU common shares outstanding were 316,219,354 and 315,273,559, respectively.
12.
COMMON SHAREHOLDERS' EQUITY AND NONCONTROLLING INTERESTS
A summary of the changes in Common Shareholders' Equity and Noncontrolling Interests of NU is as follows:
Noncontrolling
Interest -
Common
Preferred
Shareholders'
Stock of
Equity
Subsidiaries
Balance as of Beginning of Period
9,723.9
9,345.2
129.2
173.1
Dividends on Common Shares
(124.1)
(115.6)
Dividends on Preferred Stock
(1.9)
Issuance of Common Shares
Other Transactions, Net
23.7
Other Comprehensive Income
Balance as of End of Period
9,753.8
9,406.6
9,611.5
9,237.1
367.1
403.0
(247.9)
(232.1)
(3.8)
(3.9)
8.8
(9.7)
13.
EARNINGS PER SHARE
Basic EPS is computed based upon the weighted average number of common shares outstanding during each period. Diluted EPS is computed on the basis of the weighted average number of common shares outstanding plus the potential dilutive effect of certain share-based compensation awards as if they were converted into common shares. There were no antidilutive share awards outstanding for the three and six months ended June 30, 2014 or for the three months ended June 30, 2013. For the six months ended June 30, 2013, there were 3,150 antidilutive share awards excluded from the computation.
The following table sets forth the components of basic and diluted EPS:
(Millions of Dollars, except share information)
127.4
171.0
363.3
399.1
Dilutive Effect
1,162,291
808,489
1,259,950
840,622
Basic EPS
Diluted EPS
RSUs and performance shares are included in basic weighted average common shares outstanding as of the date that all necessary vesting conditions have been satisfied. The dilutive effect of unvested RSUs and performance shares is calculated using the treasury stock method. Assumed proceeds of these units under the treasury stock method consist of the remaining compensation cost to be recognized and a theoretical tax benefit. The theoretical tax benefit is calculated as the tax impact of the intrinsic value of the units (the difference between the market value of the average units outstanding for the period, using the average market price during the period, and the grant date market value).
The dilutive effect of stock options to purchase common shares is also calculated using the treasury stock method. Assumed proceeds for stock options consist of cash proceeds that would be received upon exercise, and a theoretical tax benefit. The theoretical tax benefit is calculated as the tax impact of the intrinsic value of the stock options (the difference between the market value of the average stock options outstanding for the period, using the average market price during the period, and the exercise price).
14.
SEGMENT INFORMATION
Presentation: NU is organized between the Electric Distribution, Electric Transmission and Natural Gas Distribution reportable segments and Other based on a combination of factors, including the characteristics of each segments' products and services, the sources of operating revenues and expenses and the regulatory environment in which each segment operates. These reportable segments represented substantially all of NU's total consolidated revenues for the three and six months ended June 30, 2014 and 2013. Revenues from the sale of electricity and natural gas primarily are derived from residential, commercial and industrial customers and are not dependent on any single customer. The Electric Distribution reportable segment includes the generation activities of PSNH and WMECO.
The remainder of NU's operations is presented as Other in the tables below and primarily consists of 1) the equity in earnings of NU parent from its subsidiaries and intercompany interest income, both of which are eliminated in consolidation, and interest expense related to the debt of NU parent, 2) the revenues and expenses of NU's service company, most of which are eliminated in consolidation, 3) the operations of CYAPC and YAEC, and 4) the results of other non-regulated subsidiaries, which are not part of its core business.
Cash flows used for investments in plant included in the segment information below are cash capital expenditures that do not include amounts incurred but not paid, cost of removal, AFUDC related to equity funds, and the capitalized portions of pension expense.
NU's reportable segments are determined based upon the level at which NU's chief operating decision maker assesses performance and makes decisions about the allocation of company resources. Each of NU's subsidiaries, including CL&P, NSTAR Electric, PSNH and WMECO, has one reportable segment. NU's operating segments and reporting units are consistent with its reportable business segments.
37
NU's segment information is as follows:
Natural Gas
Eliminations
1,261.8
195.5
206.9
184.7
(171.3)
1,677.6
Depreciation and Amortization
(89.3)
(16.9)
(37.0)
(7.7)
(148.6)
Other Operating Expenses
(991.5)
(166.5)
(71.0)
(174.9)
168.9
(1,235.0)
181.0
98.9
294.0
(47.2)
(28.8)
(9.1)
(92.5)
137.7
(137.8)
83.4
43.9
133.3
(135.2)
2,847.8
628.3
458.9
356.9
(323.7)
3,968.2
(238.2)
(34.6)
(74.0)
(14.7)
(357.4)
(2,202.4)
(487.9)
(137.3)
(340.3)
318.8
(2,849.1)
407.2
105.8
247.6
761.7
(94.6)
(17.1)
(54.3)
(182.5)
432.4
(433.8)
7.2
195.6
54.1
118.8
424.9
(430.1)
Cash Flows Used for Investments in Plant
335.6
68.6
289.3
724.0
1,221.6
154.1
247.9
220.7
(208.4)
1,635.9
(152.2)
(16.7)
(34.5)
(21.7)
(222.2)
(883.3)
(127.0)
(63.6)
(194.9)
205.7
(1,063.1)
186.1
10.4
149.8
350.6
(43.4)
(8.9)
(25.2)
(10.7)
(86.9)
232.2
(232.3)
91.2
76.8
232.8
(231.0)
2,595.8
515.9
487.4
437.8
(406.0)
3,630.9
(329.1)
(34.1)
(66.3)
(40.8)
4.6
(465.7)
(1,888.3)
(394.3)
(125.8)
(392.2)
404.9
(2,395.7)
378.4
87.5
295.3
769.5
(16.2)
(47.1)
(163.1)
554.0
(554.2)
190.6
44.5
156.7
555.5
(548.2)
70.9
297.4
700.3
The following table summarizes NU's segmented total assets:
16,942.5
2,753.8
6,934.1
11,566.6
(10,406.6)
27,790.4
17,260.0
2,759.7
6,745.8
11,842.4
(10,812.4)
27,795.5
Management's Discussion and Analysis of Financial Condition and Results of Operations
The following discussion and analysis should be read in conjunction with our unaudited condensed consolidated financial statements and related combined notes included in this combined Quarterly Report on Form 10-Q, the First Quarter 2014 Form 10-Q, and the 2013 Annual Report on Form 10-K. References in this Form 10-Q to "NU," the "Company," "we," "us," and "our" refer to Northeast Utilities and its consolidated subsidiaries. All per share amounts are reported on a diluted basis. The unaudited condensed consolidated financial statements of NU, NSTAR Electric and PSNH and the unaudited condensed financial statements of CL&P and WMECO are herein collectively referred to as the "financial statements."
Refer to the Glossary of Terms included in this combined Quarterly Report on Form 10-Q for abbreviations and acronyms used throughout this Management's Discussion and Analysis of Financial Condition and Results of Operations.
The only common equity securities that are publicly traded are common shares of NU. The earnings and EPS of each business discussed below do not represent a direct legal interest in the assets and liabilities allocated to such business but rather represent a direct interest in our assets and liabilities as a whole. EPS by business is a financial measure not recognized under GAAP that is calculated by dividing the Net Income Attributable to Controlling Interest of each business by the weighted average diluted NU common shares outstanding for the year. The discussion below also includes non-GAAP financial measures referencing our second quarter and first half of 2014 and 2013 earnings and EPS excluding certain integration costs related to NU's merger with NSTAR. We use these non-GAAP financial measures to evaluate and to provide details of earnings by business and to more fully compare and explain our second quarter and first half of 2014 and 2013 results without including the impact of these non-recurring items. Due to the nature and significance of these items on Net Income Attributable to Controlling Interest, we believe that the non-GAAP presentation is more representative of our financial performance and provides additional and useful information to readers of this report in analyzing historical and future performance by business. These non-GAAP financial measures should not be considered as an alternative to reported Net Income Attributable to Controlling Interest or EPS determined in accordance with GAAP as an indicator of operating performance.
Reconciliations of the above non-GAAP financial measures to the most directly comparable GAAP measures of consolidated diluted EPS and Net Income Attributable to Controlling Interest are included under "Financial Condition and Business Analysis – Overview – Consolidated" in Management's Discussion and Analysis, herein.
Forward-Looking Statements: From time to time we make statements concerning our expectations, beliefs, plans, objectives, goals, strategies, assumptions of future events, future financial performance or growth and other statements that are not historical facts. These statements are "forward-looking statements" within the meaning of the Private Securities Litigation Reform Act of 1995. You can generally identify our forward-looking statements through the use of words or phrases such as "estimate," "expect," "anticipate," "intend," "plan," "project," "believe," "forecast," "should," "could," and other similar expressions. Forward-looking statements are based on the current expectations, estimates, assumptions or projections of management and are not guarantees of future performance. These expectations, estimates, assumptions or projections may vary materially from actual results. Accordingly, any such statements are qualified in their entirety by reference to, and are accompanied by, the following important factors that could cause our actual results to differ materially from those contained in our forward-looking statements, including, but not limited to:
·
cyber breaches, acts of war or terrorism, or grid disturbances,
actions or inaction of local, state and federal regulatory and taxing bodies,
changes in business and economic conditions, including their impact on interest rates, bad debt expense, and demand for our products and services,
fluctuations in weather patterns,
changes in laws, regulations or regulatory policy,
changes in levels or timing of capital expenditures,
disruptions in the capital markets or other events that make our access to necessary capital more difficult or costly,
developments in legal or public policy doctrines,
technological developments,
changes in accounting standards and financial reporting regulations,
actions of rating agencies, and
other presently unknown or unforeseen factors.
Other risk factors are detailed in our reports filed with the SEC and updated as necessary, and we encourage you to consult such disclosures.
All such factors are difficult to predict, contain uncertainties that may materially affect our actual results and are beyond our control. You should not place undue reliance on the forward-looking statements, each speaks only as of the date on which such statement is made, and we undertake no obligation to update any forward-looking statement or statements to reflect events or circumstances after the date on which such statement is made or to reflect the occurrence of unanticipated events. New factors emerge from time to time and it is not possible for us to predict all of such factors, nor can we assess the impact of each such factor on the business or the extent to which any factor, or combination of factors, may cause actual results to differ materially from those contained in any forward-looking statements. For more information, see Item 1A, Risk Factors, included in this Quarterly Report on Form 10-Q and in NU's 2013 Annual Report on Form 10-K. This Quarterly Report on Form 10-Q and NU's 2013 Annual Report on Form 10-K also describe material contingencies and critical accounting policies in the accompanying Management's Discussion and Analysis of Financial Condition and Results of Operations and Combined Notes to Condensed Consolidated Financial Statements (Unaudited). We encourage you to review these items.
Financial Condition and Business Analysis
Executive Summary
The following items in this executive summary are explained in more detail in this combined Quarterly Report on Form 10-Q:
Results:
We earned $127.4 million, or $0.40 per share, in the second quarter of 2014, and $363.3 million, or $1.15 per share, in the first half of 2014, compared with $171 million, or $0.54 per share, in the second quarter of 2013 and $399.1 million, or $1.26 per share, in the first half of 2013. Excluding integration costs, we earned $131.9 million, or $0.42 per share, in the second quarter of 2014, and $373.7 million, or $1.18 per share, in the first half of 2014, compared with $172.8 million, or $0.55 per share, in the second quarter of 2013, and $402.6 million, or $1.27 per share, in the first half of 2013.
Our electric distribution segment, which includes generation, earned $83.4 million, or $0.26 per share, in the second quarter of 2014 and $195.6 million, or $0.62 per share, in the first half of 2014, compared with earnings of $91.2 million, or $0.29 per share, in the second quarter of 2013 and $190.6 million, or $0.60 per share, in the first half of 2013.
Our transmission segment earned $43.9 million, or $0.14 per share, in the second quarter of 2014 and $118.8 million, or $0.37 per share, in the first half of 2014, compared with $76.8 million, or $0.25 per share, in the second quarter of 2013 and $156.7 million, or $0.50 per share, in the first half of 2013. The decrease in the second quarter and first half of 2014 earnings, as compared to the same periods in 2013, was due primarily to the establishment of a $32.1 million after-tax reserve related to FERC ROE orders issued on June 19, 2014.
Our natural gas distribution segment earned $2 million, or $0.01 per share, in the second quarter of 2014 and $54.1 million, or $0.17 per share, in the first half of 2014, compared with $1.2 million in the second quarter of 2013 and $44.5 million, or $0.14 per share, in the first half of 2013.
NU parent and other companies had net losses of $1.9 million, or $0.01 per share, in the second quarter of 2014 and $5.2 million, or $0.01 per share, in the first half of 2014, compared with earnings of $1.8 million in the second quarter of 2013 and $7.3 million, or $0.02 per share, in the first half of 2013. Second quarter and first half 2014 results reflect $4.5 million and $10.4 million, respectively, of after-tax integration costs. Second quarter and first half 2013 results reflect $1.8 million and $3.5 million, respectively, of after-tax integration costs.
Legislative and Regulatory Items:
On June 9, 2014, CL&P filed an application with the PURA to amend customer rates, effective December 1, 2014. CL&P requested an increase in base distribution rates of $116.7 million. Based on the current schedule, we expect a final decision in December 2014.
On June 19, 2014, the FERC issued two orders in the pending base ROE complaint proceedings. The first order addressed the joint complaint filed at FERC in September 2011 by several New England parties alleging that the base ROE of 11.14 percent was unjust and unreasonable. The FERC set a single tentative base ROE of 10.57 percent for the refund period (October 1, 2011 through December 31, 2012) and the prospective period (beginning when FERC finalizes the base ROE). The second order addressed a second joint complaint filed at FERC in December 2012 by additional New England parties alleging that the base ROE was unjust and unreasonable. The complaint sought refunds for the 15-month period beginning January 1, 2013. The FERC found that the second complaint raised issues of material fact and set this complaint for settlement or trial if settlement negotiations should be unsuccessful. We recorded a series of reserves totaling $32.1 million after-tax at our electric subsidiaries to recognize the potential financial impact from the FERC's two orders for the two refund periods.
On July 7, 2014, Massachusetts enacted "An Act Relative to Natural Gas Leaks" (the Act). The Act establishes a uniform natural gas leak classification standard for all Massachusetts natural gas utilities and a program that accelerates the replacement of aging natural gas infrastructure. The Act also calls for the DPU to authorize natural gas utilities to design and offer programs to customers that will increase the availability, affordability and feasibility of natural gas service for new customers.
Liquidity:
Cash and cash equivalents totaled $34.1 million as of June 30, 2014, compared with $43.4 million as of December 31, 2013, while investments in property, plant and equipment totaled $724 million in the first half of 2014, compared with $700.3 million in the first half of 2013.
Cash flows provided by operating activities totaled $896.7 million in the first half of 2014, compared with $769 million in the first half of 2013. The improved operating cash flows were due primarily to approximately $126 million in DOE Phase II proceeds received by CL&P, NSTAR Electric, PSNH and WMECO on June 1, 2014 from the Yankee Companies associated with the spent nuclear fuel litigation, the absence of cash disbursements for major storm restoration costs and the decrease of $82.2 million in Pension and PBOP Plan cash contributions, partially offset by an increase in income taxes paid in the first half of 2014 ($158 million), as compared to the first half of 2013 ($16 million).
In the first half of 2014, we issued $650 million of new long-term debt consisting of $100 million by Yankee Gas on January 2, 2014, $300 million by NSTAR Electric on March 7, 2014, and $250 million by CL&P on April 24, 2014. These new issuances were used to repay approximately $375 million of existing long-term debt with the remainder used to pay short-term borrowings.
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In the first half of 2014, we had cash dividends on common shares of $237.2 million, compared with $232 million in the first half of 2013. On May 1, 2014, our Board of Trustees approved a common dividend payment of $0.3925 per share, which was paid on June 30, 2014 to shareholders of record as of May 30, 2014.
Overview
Consolidated: A summary of our earnings by business, which also reconciles the non-GAAP financial measures of consolidated non-GAAP earnings and EPS, as well as EPS by business, to the most directly comparable GAAP measures of consolidated Net Income Attributable to Controlling Interest and diluted EPS, for the second quarter and first half of 2014 and 2013 is as follows:
(Millions of Dollars, Except
Per Share Amounts)
Net Income Attributable to Controlling Interest (GAAP)
Regulated Companies
129.3
0.41
169.2
368.5
1.16
391.8
1.24
NU Parent and Other Companies
0.01
0.02
0.03
Non-GAAP Earnings
131.9
0.42
172.8
0.55
373.7
1.18
402.6
Integration Costs (after-tax)
(4.5)
(0.02)
(0.01)
(10.4)
(0.03)
(3.5)
Excluding the impact of integration costs, our second quarter 2014 earnings decreased by $40.9 million, as compared to the second quarter of 2013. The decrease was due primarily to the establishment of an after-tax reserve of $32.1 million related to the June 2014 FERC ROE orders. For further information, see "FERC Regulatory Issues – FERC Base ROE Complaints" in this Management's Discussion and Analysis of Financial Condition and Results of Operations. In addition, earnings decreased as a result of higher depreciation expense and property taxes and lower retail electric sales, partially offset by lower general and administrative costs.
Excluding the impact of integration costs, our first half 2014 earnings decreased by $28.9 million, as compared to the first half of 2013, due primarily to the establishment of the $32.1 million after-tax reserve related to June 2014 FERC base ROE orders, the absence of a favorable impact from the resolution of a state income tax audit in the first quarter of 2013, and higher depreciation expense and property taxes. Earnings were favorably impacted by higher retail electric and firm natural gas sales as a result of the colder weather in the first quarter of 2014, as compared to the first quarter of 2013, and lower general and administrative costs.
Regulated Companies: Our Regulated companies consist of the electric distribution, transmission, and natural gas distribution segments. Generation activities of PSNH and WMECO are included in our electric distribution segment. A summary of our segment earnings for the second quarter and first half of 2014 and 2013 is as follows:
For the Three MonthsEnded June 30,
For the Six MonthsEnded June 30,
Electric Distribution
Natural Gas Distribution
Net Income - Regulated Companies
Our electric distribution segment earnings decreased $7.8 million in the second quarter of 2014, as compared to the second quarter of 2013, due primarily to a decrease of 2.9 percent in retail electric sales as a result of milder temperatures in late May and June, as compared to the same periods in 2013, the absence of regulatory interest income from stranded cost recoveries recognized in the second quarter of 2013, and higher depreciation and property tax expense, partially offset by lower general and administrative costs.
Our electric distribution segment earnings increased $5 million in the first half of 2014, as compared to the first half of 2013, due primarily to higher retail electric sales as a result of the colder weather in the first quarter of 2014, as compared to the first quarter of 2013, and a decrease in operations and maintenance costs that impact earnings. Partially offsetting these favorable impacts were the absence of regulatory interest income from stranded cost recoveries in 2013, and higher depreciation and property tax expense.
Our transmission segment earnings decreased $32.9 million in the second quarter of 2014, as compared to the second quarter of 2013, due primarily to the establishment of the $32.1 million after-tax reserve related to the June 2014 FERC ROE orders, the net unfavorable impact on transmission revenues as a result of a refund to our customers in June 2014, partially offset by a higher transmission rate base as a result of an increased investment in our transmission infrastructure.
Our transmission segment earnings decreased $37.9 million in the first half of 2014, as compared to the first half of 2013, due primarily to the $32.1 million after-tax reserve related to the June 2014 FERC ROE orders, the absence of the favorable impact from the resolution of the state income tax audit in the first quarter of 2013, the net unfavorable impact on transmission revenues as a result of a refund to our customers in June 2014, partially offset by a higher transmission rate base as a result of an increased investment in our transmission infrastructure.
Our natural gas distribution segment earnings increased $0.8 million in the second quarter of 2014, as compared to the second quarter of 2013, due primarily to higher firm natural gas sales and peak demand revenues as a result of the addition of new natural gas heating customers.
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Our natural gas distribution segment earnings increased $9.6 million in the first half of 2014, as compared to the first half of 2013, due primarily to higher firm natural gas sales and peak demand revenues as a result of colder weather in the first quarter of 2014, as well as the addition of new natural gas heating customers.
A summary of our retail electric GWh sales and percentage changes, as well as percentage changes in CL&P, NSTAR Electric, PSNH and WMECO retail electric GWh sales, is as follows:
For the Three Months EndedJune 30, 2014 Compared to 2013
For the Six Months EndedJune 30, 2014 Compared to 2013
Sales (GWh)
Percentage
NU – Electric
Decrease
Increase
Residential
4,510
4,720
(4.4)%
10,650
10,523
1.2%
Commercial (1)
6,591
6,754
(2.4)%
13,456
13,448
0.1%
Industrial
1,435
1,437
(0.1)%
2,778
2,736
1.5%
12,536
12,911
(2.9)%
26,884
26,707
0.7%
For the Three Months Ended June 30, 2014 Compared to 2013
For the Six Months Ended June 30, 2014 Compared to 2013
NSTARElectric
PercentageIncrease/(Decrease)
PercentageDecrease
PercentageIncrease
(5.3)%
(4.2)%
(1.8)%
(5.4)%
0.2 %
2.4%
0.9 %
(2.0)%
(3.0)%
(0.6)%
(4.5)%
(0.2)%
0.8%
(0.3)%
3.4 %
(6.9)%
1.7 %
(3.2)%
3.8%
(1.9)%
3.2%
(2.8)%
(3.6)%
(4.6)%
1.1%
1.9%
Commercial retail electric GWh sales include streetlighting and railroad retail sales.
A summary of our firm natural gas sales in million cubic feet and percentage changes, as well as percentage changes in Yankee Gas and NSTAR Gas, is as follows:
Sales (million cubic feet)
NU – Firm Natural Gas
5,169
4,970
4.0%
24,981
21,985
13.6%
Commercial
6,839
6,622
3.3%
26,467
23,393
13.1%
4,916
4,665
5.4%
12,393
11,494
7.8%
16,924
16,257
4.1%
63,841
56,872
12.3%
Total, Net of Special Contracts (1)
15,895
15,238
4.3%
61,445
54,660
12.4%
Firm Natural Gas
Increase/(Decrease)
(3.4)%
9.6 %
15.8%
12.2%
5.4 %
1.4 %
16.6%
10.2%
5.7 %
4.5%
8.4%
6.4%
3.3 %
5.0%
13.9%
10.6%
3.7 %
14.4%
Special contracts are unique to the customers who take service under such an arrangement and generally specify the amount of distribution revenue to be paid to Yankee Gas regardless of the customers' usage.
Weather, fluctuations in energy supply costs, conservation measures (including company-sponsored energy efficiency programs), and economic conditions affect customer energy usage. Industrial sales are less sensitive to temperature variations than residential and commercial sales. In our service territories, weather impacts electric sales during the summer and electric and natural gas sales during the winter (natural gas sales are more sensitive to temperature variations than electric sales). Customer heating or cooling usage may not directly correlate with historical levels or with the level of degree-days that occur. In addition, our electric and natural gas businesses are susceptible to damage from major storms and other natural events and disasters that could adversely affect our ability to provide energy.
For the second quarter of 2014, our consolidated retail electric sales, consisting of the retail electric sales of CL&P, NSTAR Electric, PSNH, and WMECO, were lower, as compared to the same period in 2013, due primarily to milder temperatures in late May and June, compared with the same periods in 2013. The second quarter of 2014 cooling degree days were 19 percent lower in Connecticut and western Massachusetts, 22 percent lower in the Boston metropolitan area, and 24 percent lower in New Hampshire, as compared to the second quarter of 2013. Weather-normalized retail
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electric sales (based on 30-year average temperatures) decreased 1.7 percent in the second quarter of 2014, as compared to the second quarter of 2013. We believe the decrease was due primarily to increased conservation efforts by our residential and commercial customer classes, which is driven by the energy efficiency programs sponsored by CL&P, NSTAR Electric and WMECO.
For the first half of 2014, our consolidated retail electric sales were higher, as compared to the same period in 2013, due primarily to colder weather in the first quarter of 2014. The first half 2014 heating degree days were 12 percent higher in Connecticut, New Hampshire and western Massachusetts and 9 percent higher in the Boston metropolitan area, as compared to the first half of 2013. Weather-normalized retail electric sales (based on 30-year average temperatures) decreased 0.1 percent in the first half of 2014, as compared to the first half of 2013. We believe the decrease was due primarily to an increase in customer conservation efforts as noted above.
For WMECO, fluctuations in retail electric sales do not impact earnings due to the DPU-approved revenue decoupling mechanism. Under this decoupling mechanism, WMECO has an overall fixed annual level of distribution delivery service revenues of $132.4 million, comprised of customer base rate revenues of $125.4 million and a baseline low income discount recovery of $7 million. These two mechanisms effectively break the relationship between sales volume and revenues recognized.
Our firm natural gas sales are subject to many of the same influences as our retail electric sales. In addition, they have benefitted from historically favorable natural gas prices and customer growth across both operating companies. In the second quarter and first half of 2014, consolidated firm natural gas sales, consisting of the firm natural gas sales of Yankee Gas and NSTAR Gas, were higher, as compared to the second quarter and first half of 2013, due primarily to colder weather in the first quarter of 2014, as compared to the same period in 2013, and customer growth in the first half of 2014, as compared to the same period in 2013. The second quarter and first half of 2014 weather-normalized NU consolidated total firm natural gas sales increased 5.3 percent and 4.1 percent, respectively, as compared to the same periods in 2013.
NU Parent and Other Companies: NU parent and other companies, which includes our competitive businesses, had net losses of $1.9 million and $5.2 million in the second quarter and first half of 2014, respectively, compared with earnings of $1.8 million and $7.3 million in the second quarter and first half of 2013, respectively. Excluding the impact of integration costs, NU parent and other companies earned $2.6 million and $5.2 million in the second quarter and first half of 2014, respectively, compared with $3.6 million and $10.8 million in the second quarter and first half of 2013, respectively. The decrease in first half of 2014 earnings was due to the absence of the favorable impact from the resolution of the state income tax audit, which provided a $5.8 million benefit to first half of 2013 earnings.
Liquidity
Consolidated: Cash and cash equivalents totaled $34.1 million as of June 30, 2014, compared with $43.4 million as of December 31, 2013.
On April 15, 2014, NSTAR Electric repaid at maturity the $300 million of 4.875 percent debentures using short-term debt.
Effective July 23, 2014, NU parent, CL&P, PSNH, WMECO, NSTAR Gas and Yankee Gas amended their joint $1.45 billion revolving credit facility to extend the expiration date an additional year to September 6, 2019. The revolving credit facility is to be used primarily to backstop NU parent's $1.45 billion commercial paper program. The commercial paper program allows NU parent to issue commercial paper as a form of short-term debt. As of June 30, 2014 and December 31, 2013, NU had $710.5 million and $1.01 billion, respectively, in short-term borrowings outstanding under the NU parent commercial paper program, leaving $739.5 million and $435.5 million of available borrowing capacity as of June 30, 2014 and December 31, 2013, respectively. The weighted-average interest rate on these borrowings as of June 30, 2014 and December 31, 2013 was 0.25 percent and 0.24 percent, respectively, which is generally based on A2/P2 rated commercial paper. As of June 30, 2014, there were intercompany loans from NU of $6.4 million to CL&P, $95 million to PSNH and $15.9 million to WMECO. As of December 31, 2013, there were intercompany loans from NU of $287.3 million to CL&P and $86.5 million to PSNH.
Effective July 23, 2014, NSTAR Electric amended its $450 million revolving credit facility to extend the expiration date an additional year to September 6, 2019. This facility serves to backstop NSTAR Electric's existing $450 million commercial paper program. As of June 30, 2014 and December 31, 2013, NSTAR Electric had $194.5 million and $103.5 million, respectively, in short-term borrowings outstanding under its commercial paper program, leaving $255.5 million and $346.5 million, respectively, of available borrowing capacity as of June 30, 2014 and December 31, 2013, respectively. The weighted-average interest rate on these borrowings as of June 30, 2014 and December 31, 2013 was 0.16 percent and 0.13 percent, respectively, which is generally based on A2/P1 rated commercial paper.
Cash flows provided by operating activities totaled $896.7 million in the first half of 2014, compared with $769 million in the first half of 2013. The improved operating cash flows were due primarily to approximately $126 million in DOE Phase II Damages proceeds received by CL&P, NSTAR Electric, PSNH and WMECO on June 1, 2014 from the Yankee Companies associated with the spent nuclear fuel litigation, the absence of cash disbursements for major storm restoration costs and the decrease of $82.2 million in Pension and PBOP Plan cash contributions, partially offset by an increase in income taxes paid in the first half of 2014 ($158 million), as compared to the first half of 2013 ($16 million). For further information on the spent nuclear fuel litigation, see Note 8C, "Commitments and Contingencies – Contractual Obligations – Yankee Companies," in this combined Quarterly Report on Form 10-Q.
On April 7, 2014, Fitch affirmed the corporate credit ratings and outlook of NU, CL&P, NSTAR Electric, PSNH, WMECO and NSTAR Gas. On April 25, 2014, S&P affirmed the corporate credit ratings and revised the outlooks to positive from stable of NU, CL&P, NSTAR Electric, PSNH, WMECO, Yankee Gas and NSTAR Gas.
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In the first half of 2014, CL&P, NSTAR Electric, PSNH, and WMECO paid $85.6 million, $253 million, $33 million, and $49 million, respectively, in common dividends to NU parent.
Investments in Property, Plant and Equipment on the accompanying statements of cash flows do not include amounts incurred on capital projects but not yet paid, cost of removal, AFUDC related to equity funds, and the capitalized portions of pension expense. In the first half of 2014, investments for NU, CL&P, NSTAR Electric, PSNH, and WMECO were $724 million, $221.4 million, $213.5 million, $117.4 million, and $61.5 million, respectively.
Business Development and Capital Expenditures
Consolidated: Our consolidated capital expenditures, including amounts incurred but not paid, cost of removal, AFUDC, and the capitalized portions of pension expense (all of which are non-cash factors), totaled $706.2 million in the first half of 2014, compared with $644 million in the first half of 2013. These amounts included $25.5 million and $6.7 million in the first half of 2014 and 2013, respectively, related to our corporate service companies, NUSCO and RRR.
Transmission Business: Overall, transmission business capital expenditures increased by $9.6 million in the first half of 2014, as compared to the first half of 2013. A summary of transmission capital expenditures by company for the first half of 2014 and 2013 is as follows:
84.1
79.3
44.3
35.0
33.1
Total Transmission Segment
271.6
262.0
NEEWS: GSRP, the first, largest and most complicated project within the NEEWS family of projects was fully energized on November 20, 2013. As of June 30, 2014, CL&P and WMECO have placed $638.1 million in service with minimal remaining close-out activities continuing throughout the remainder of 2014.
The Interstate Reliability Project, which includes CL&P's construction of an approximately 40-mile, 345 kV overhead line from Lebanon, Connecticut to the Connecticut-Rhode Island border in Thompson, Connecticut where it will connect to transmission enhancements being constructed by National Grid in Rhode Island and Massachusetts, is the second major NEEWS project. As of May 2014, all three states have issued siting approvals. Completing all the project permit requirements, the Army Corps of Engineers issued its permit on the project in the first quarter of 2014. Project construction is underway in all three states. NU's portion of the cost is estimated to be $218 million and construction on its portion of the project is approximately 40 percent complete as of June 30, 2014. The project is expected to be placed in service by the end of 2015.
The Greater Hartford Central Connecticut Study (GHCC), which includes the reassessment of the Central Connecticut Reliability Project, continues to make progress. The final need results showed existing and worsening severe regional and local thermal overloads and voltage violations within each of the areas studied and across the interfaces of those areas. These results were presented to the ISO-NE Planning Advisory Committee in November 2013. On July 15, 2014, ISO-NE presented the preferred transmission solutions to its Planning Advisory Committee. These solutions are comprised of many 115 kV upgrades and are expected to cost approximately $350 million and be placed in service in late 2017.
Included as part of NEEWS are associated reliability related projects, $93.1 million of which have been placed in service. As of June 30, 2014, all construction on the associated reliability related projects has been completed.
Through June 30, 2014, CL&P and WMECO capitalized $292 million and $573.4 million, respectively, in costs associated with NEEWS, of which $39.2 million and $6.4 million, respectively, were capitalized in the first half of 2014.
Northern Pass: Northern Pass is NU's planned HVDC transmission line from the Québec-New Hampshire border to Franklin, New Hampshire and an associated alternating current radial transmission line between Franklin and Deerfield, New Hampshire. Northern Pass will interconnect at the Québec-New Hampshire border with a planned HQ HVDC transmission line. NPT received ISO-NE approval under Section I.3.9 of the ISO tariff in 2013. By approving the project's Section I.3.9 application, ISO-NE determined that Northern Pass can reliably interconnect with the New England grid with no significant adverse effect on the reliability or operating characteristics of the regional energy grid and its participants. The $1.4 billion project is subject to comprehensive federal and state public permitting processes and is expected to be operational in the second half of 2017. The DOE continues to work on the draft Environmental Impact Statement (EIS) for Northern Pass. This includes a review of both the recommended route and various alternative routes. We expect the DOE to issue the draft EIS in late 2014. Once it is published, the DOE will commence a process of receiving written and verbal comments on the draft EIS and we expect the issuance of a final EIS in the second half of 2015. We expect to file the state permit application in January 2015 after receipt of the draft EIS.
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Greater Boston Reliability and Boston Network Improvements: As a result of continued analysis of the transmission needs to enhance system reliability and improve capacity in eastern Massachusetts, NSTAR Electric and PSNH expect to implement a series of new transmission initiatives over the next five years. We expect ISO-NE to select preferred solutions in the second half of 2014, and project costs to be approximately $495 million for these new initiatives.
Distribution Business: A summary of distribution capital expenditures by company for the first half of 2014 and 2013 is as follows:
CL&P:
Basic Business
24.3
27.8
Aging Infrastructure
74.7
71.3
Load Growth
31.8
Total CL&P
133.7
130.9
NSTAR Electric:
50.2
48.3
53.1
51.3
13.4
Total NSTAR Electric
118.0
PSNH:
14.1
26.5
20.0
13.1
10.1
Total PSNH
53.7
38.6
WMECO:
3.3
Total WMECO
15.4
17.8
Total - Electric Distribution (excluding Generation)
320.8
300.3
PSNH Generation
WMECO Generation
Total - Natural Gas
75.7
70.3
Total Electric and Natural Gas Distribution Segment
409.1
375.2
For the electric distribution business, basic business includes the purchase of meters, tools, vehicles, information technology, transformer replacements, equipment facilities, and the relocation of plant. Aging infrastructure relates to reliability and the replacement of overhead lines, distribution substations, underground cable replacement, and equipment failures. Load growth includes requests for new business and capacity additions on distribution lines and substation additions and expansions.
FERC Regulatory Issues
FERC Base ROE Complaints: On September 30, 2011, a complaint was filed jointly at FERC under Sections 206 and 306 of the Federal Power Act by several New England state attorneys general, state regulatory commissions, consumer advocates and other parties (the "Complainants"). The Complainants alleged that the base ROE of 11.14 percent that has been utilized since 2006 in the calculation of formula rates for transmission service under the ISO-NE Open Access Transmission Tariff by NETOs, including CL&P, NSTAR Electric, PSNH and WMECO, was unjust and unreasonable and asserted that the rate was excessive due to changes in the capital markets. Complainants sought an order to reduce the base ROE, effective October 1, 2011, and to require refunds. The FERC set the case for trial before a FERC ALJ after settlement negotiations were unsuccessful in August 2012.
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Though NU cannot predict the ultimate outcome of this proceeding, in the second quarter of 2014, the Company recorded a series of reserves at its electric subsidiaries to recognize the potential financial impact from the FERC's two orders issued on June 19, 2014 for the two refund periods. The aggregate after-tax charge to second quarter 2014 earnings totaled $32.1 million at NU, which represented reserves of $18.5 million at CL&P, $6.1 million at NSTAR Electric, $2 million at PSNH and $5.5 million at WMECO.
Regulatory Developments and Rate Matters
The Regulated companies' distribution rates are set by their respective state regulatory commissions, and their tariffs include mechanisms for periodically adjusting their rates for the recovery of specific incurred costs. Other than as described below, for the first half of 2014, changes made to the Regulated companies' rates did not have a material impact on their earnings, financial position, or cash flows. For further information, see "Financial Condition and Business Analysis – Regulatory Developments and Rate Matters" included in Item 7, "Management's Discussion and Analysis of Financial Condition and Results of Operations," of the NU 2013 Annual Report on Form 10-K.
Connecticut:
Distribution Rates: On June 9, 2014, CL&P filed an application with the PURA to amend customer rates, effective December 1, 2014. CL&P requested an increase in total distribution rates of $231.5 million. The increase includes a base distribution rate increase of $116.7 million, an increase for the annual recovery of $89.5 million of previously approved 2011 and 2012 deferred storm restoration costs totaling $365 million, and an increase of $25.3 million for previously approved electric system resiliency costs. Currently, hearings are scheduled to occur in late August through September, and a final decision is expected in December 2014.
On June 17, 2014, PURA ordered CL&P to use the DOE Phase II Damages proceeds of $65.4 million received on June 1, 2014 to offset the $365 million in 2011 and 2012 deferred storm restoration costs that were approved for recovery by the PURA on March 12, 2014. For further information on the spent nuclear fuel litigation awards, see Note 8C, "Commitments and Contingencies – Contractual Obligations – Yankee Companies." As a result, CL&P will now recover approximately $300 million in storm costs from customers, which will be reflected in final rates approved by PURA at the conclusion of the current CL&P distribution rate case.
New Hampshire:
Generation: In 2013, the NHPUC opened a docket to investigate market conditions affecting PSNH's ES rate, how PSNH will maintain just and reasonable rates in light of those conditions, and any impact of PSNH's generation ownership on the New Hampshire competitive electric market. In a 2013 NHPUC staff report accepted by the NHPUC, the NHPUC staff recommended that the NHPUC examine whether default service rates remain sustainable on a going forward basis, define "just and reasonable" with respect to default service in the context of competitive retail markets, analyze the current and expected value of PSNH's generating units, and identify means to mitigate and address stranded cost recovery. In October 2013, the New Hampshire Legislative Oversight Committee on Electric Utility Restructuring (Oversight Committee) requested that the NHPUC conduct an analysis to determine whether it is now in the economic interest of PSNH's retail customers for PSNH to divest its interest in generation plants. On November 1, 2013, the Oversight Committee asked for a preliminary report by April 1, 2014 that would include a third party valuation of PSNH's generating assets and a report from NHPUC staff members concerning customers' economic interests in those generating assets.
On April 1, 2014, the NHPUC staff issued a "Preliminary Status Report Addressing the Economic Interest of PSNH's Retail Customers as it Relates to the Potential Divestiture of PSNH's Generating Plants," which included a consultant's analysis of the fair market value of PSNH generating assets and long-term power purchase contracts. The consultant's analysis estimated the fair market value of PSNH's generation assets to be $225 million as of December 31, 2013 and compared that amount to a stated net book value of $660 million, implying potential "stranded costs" in excess of $400 million. NHPUC staff made three recommendations: (1) that any further actions relating to PSNH's generating assets await a final decision in the Clean Air Project (scrubber) prudence proceeding; (2) that existing laws regarding divestiture, energy service, and cost recovery be harmonized; and (3) that ISO-NE provide input on the economic and reliability consequences of retirement of PSNH's coal- and oil-fired electric generating plants.
During its 2014 session, in response to the NHPUC staff report, the House and Senate passed a bill, which enacted changes to the laws governing divestiture of PSNH's generating assets. That bill requires the NHPUC to initiate a proceeding before January 1, 2015, to determine whether all or some of PSNH's generation assets should be divested. A progress report from the NHPUC must be made by March 31, 2015. The bill also changes the law to give the NHPUC express authority to order the divestiture of all or some of PSNH's generation assets if the NHPUC finds it is in the economic interest of customers to do so. The bill also clarifies the definition of "stranded costs" to include costs approved for recovery by the NHPUC in connection with the divestiture or retirement of PSNH's generation assets.
In the event of generation asset divestiture or retirement, present law, the PSNH Restructuring Settlement Agreement approved in 2000, and the Bill all require that the NHPUC provide recovery of any stranded costs by PSNH. We continue to believe all costs and generation investments are probable of recovery.
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Legislative and Policy Matters
Massachusetts:
Gas Replacement and Expansion: On July 7, 2014, Massachusetts enacted "An Act Relative to Natural Gas Leaks" (the Act). The Act establishes a uniform natural gas leak classification standard for all Massachusetts natural gas utilities and a program that accelerates the replacement of aging natural gas infrastructure. The program will enable companies, including NSTAR Gas, to better manage the scheduling and costs of replacement. The Act also calls for the DPU to authorize natural gas utilities to design and offer programs to customers that will increase the availability, affordability and feasibility of natural gas service for new customers.
Critical Accounting Policies
The preparation of financial statements in conformity with GAAP requires management to make estimates, assumptions and, at times, difficult, subjective or complex judgments. Changes in these estimates, assumptions and judgments, in and of themselves, could materially impact our financial position, results of operations or cash flows. Our management communicates to and discusses with the Audit Committee of our Board of Trustees significant matters relating to critical accounting policies. Our critical accounting policies that we believed were the most critical in nature were reported in the NU 2013 Form 10-K. There have been no material changes with regard to these critical accounting policies.
Other Matters
Accounting Standards Recently Adopted: For information regarding new accounting standards, see Note 1B, "Summary of Significant Accounting Policies –Accounting Standards," to the financial statements.
Contractual Obligations and Commercial Commitments: Refer to Note 8B, "Commitments and Contingencies – Long-Term Contractual Arrangements," for discussion of material changes to contractual obligations.
Web Site: Additional financial information is available through our web site at www.nu.com. Information contained on the Company's website or that can be accessed through the website is not incorporated into and does not constitute a part of this Quarterly Report on Form 10-Q.
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RESULTS OF OPERATIONS – NORTHEAST UTILITIES AND SUBSIDIARIES
The following provides the amounts and variances in operating revenues and expense line items for the condensed consolidated statements of income for NU included in this Quarterly Report on Form 10-Q for the three and six months ended June 30, 2014 and 2013:
Operating Revenues and Expenses
Increase/
(Decrease)
Percent
%
337.3
624.2
488.3
135.9
1,602.4
1,236.1
366.3
29.6
373.2
357.2
724.9
703.3
152.2
159.5
(4.6)
303.0
314.5
(11.5)
(3.7)
54.6
(58.1)
(a)
54.4
108.6
(54.2)
(49.9)
(8.1)
(100.0)
42.6
(42.6)
102.7
94.1
9.1
241.5
199.9
41.6
20.8
134.8
123.5
280.3
256.4
23.9
1,383.6
1,285.3
98.3
3,206.5
2,861.4
345.1
(56.6)
(16.1)
(7.8)
Percent greater than 100 percent not shown as it is not meaningful.
40.2
252.0
41.4
26.9
112.4
21.8
Total Distribution
1,457.3
1,375.7
3,476.1
3,111.7
364.4
(41.0)
(16.5)
(28.5)
(5.8)
Total Regulated Companies
1,664.2
1,623.6
3,935.0
3,599.1
335.9
Other and Eliminations
8.9
33.2
Total Operating Revenues
A summary of our retail electric sales and firm natural gas sales were as follows:
Retail Electric Sales in GWh
(375)
177
Firm Natural Gas Sales in Million Cubic Feet
667
6,969
Operating Revenues increased in the second quarter of 2014, as compared to the second quarter of 2013. The increase primarily reflects higher costs associated with purchasing electricity and natural gas on behalf of our customers. Fluctuations in these energy supply costs are recovered from customers in rates and therefore have no impact on earnings. Retail electric sales volumes decreased 2.9 percent from the second quarter of 2013 as a result of milder temperatures in late May and June of 2014, as well as the impact of utility-sponsored energy efficiency programs. Firm natural gas sales volume increased 4.1 percent from the second quarter of 2013 as customer growth and economic conditions in our service territory have shown steady improvement over the past year.
As noted above, our respective utility-sponsored energy efficiency programs have the impact of reducing both retail electric and firm natural gas sales. Certain utility operating companies are permitted to bill customers for lost base revenues related to reductions in sales volume as a result of their energy efficiency. In the second quarter of 2014, base electric and natural gas distribution revenues decreased $3 million, compared to the second quarter of 2013 (including the impact from the recognition of lost base revenues).
Transmission revenues decreased in the second quarter of 2014, as compared to the second quarter of 2013, due primarily to the impact of the reserves recorded during the second quarter of 2014 as a result of the FERC ROE orders issued in the FERC base ROE complaints. For further information, see "FERC Regulatory Issues - FERC Base ROE Complaints" in this Management's Discussion and Analysis.
Operating Revenues increased in the first half of 2014, as compared to the first half of 2013. The increase reflects higher retail electric and firm natural gas sales volumes primarily as a result of the significantly colder weather in the first quarter of 2014, as compared to the same period in 2013, and the overall impact of higher costs associated with the procurement of energy supply. Our energy supply costs were impacted by higher natural gas transportation costs which, in addition to its impact on the cost of natural gas purchased on behalf of our retail natural gas customers, had an adverse impact on the cost of purchased electric energy for our retail electric customers. Fluctuations in energy supply costs are recovered from customers in rates and therefore have no impact on earnings.
As noted above, the increase in distribution revenues reflects an increase of approximately 0.7 percent in retail electric sales and 12.3 percent in firm natural gas sales. The increase in sales volumes was driven primarily by the cold winter weather experienced throughout our service territories in the first quarter of 2014. The winter was significantly colder than both normal and the same period last year throughout New England. Weather-normalized retail electric sales (based on 30-year average temperatures) decreased 0.1 percent in the first half of 2014, as compared to the same
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period in 2013, reflecting the impact of our utility-sponsored energy efficiency programs. Weather-normalized total firm natural gas sales increased 4.1 percent in the first half of 2014, as compared to the same period in 2013, due primarily to residential and commercial customer growth.
Certain utility operating companies are permitted to bill customers for lost base revenues related to reductions in sales volume as a result of their energy efficiency. In the first half of 2014, base electric and natural gas distribution revenues increased $38 million, compared to the first half of 2013 (including the impact from the recognition of lost base revenues).
Transmission revenues decreased in the first half of 2014, as compared to the first half of 2013, due primarily to the impact of the reserve recorded during the second quarter of 2014 as a result of the FERC ROE orders issued in the FERC base ROE complaints.
Purchased Power, Fuel and Transmission increased for the three and six months ended June 30, 2014, as compared to the same periods in 2013, due primarily to the following:
Three Months Ended
Six Months Ended
Electric distribution segment fuel and energy supply costs
139.6
334.7
Firm natural gas sales related costs
35.3
69.2
Transmission segment costs
(3.2)
All other (including eliminations)
15.7
Partially offset by:
Electric distribution segment purchased power and deferred fuel costs
(41.9)
(50.1)
Operations and Maintenance expense includes costs that are recovered in rates through cost tracking mechanisms, which have no earnings impact (tracked costs), and costs that are recovered through base electric and natural gas distribution rates (and therefore impact earnings). Operations and Maintenance increased for the three and six months ended June 30, 2014, as compared to the same periods in 2013, due primarily to the following:
Base Electric Distribution:
Bad debt expense
Implementation of a new outage restoration program at CL&P
Employee costs, including pension and benefit related costs
(30.9)
Storm costs
Other operations and maintenance
Total Base Electric Distribution
(6.9)
(17.6)
Total Natural Gas Distribution
Total Tracked costs (Transmission and Electric Distribution)
23.5
Total Distribution and Transmission
6.4
Other and eliminations:
Integration and severance costs
11.5
Total Operations and Maintenance
The Operations and Maintenance expenses that are recovered through base electric distribution rates (and therefore impact earnings) decreased $6.9 million and $17.6 million, respectively, for the three and six months ended June 30, 2014, as compared to the same periods in 2013. The Operations and Maintenance expenses that are recovered through cost tracking mechanisms (and therefore have no earnings impact) increased $14.4 million and $23.5 million, respectively, for the three and six months ended June 30, 2014, as compared to the same periods in 2013. These increases were primarily driven by an increase in bad debt expense ($4.2 million and $8.2 million, respectively) and higher operation and maintenance costs at the PSNH generation business due to the timing of planned outages ($4.2 million and $5.1 million, respectively) for the three and six months ended June 30, 2014, as compared to the same periods in 2013.
Depreciation decreased for the three and six months ended June 30, 2014, as compared to the same periods in 2013, due primarily to a decrease in CYAPC and YAEC decommissioning costs ($12.5 million and $25 million, respectively), partially offset by an increase related to higher utility plant balances resulting from completed construction projects placed into service ($5 million and $10.6 million, respectively).
Amortization of Regulatory Assets/(Liabilities), Net decreased for the three and six months ended June 30, 2014, as compared to the same periods in 2013, due primarily to the following:
Recovery of stranded costs at NSTAR Electric
(55.1)
(86.4)
Increases in the SCRC, ES and other amortizations at PSNH
(21.5)
Amortization of previously deferred congestion costs at CL&P
38.3
Amortization of Rate Reduction Bonds decreased for the three and six months ended June 30, 2014, as compared to the same periods in 2013, due to the maturity in 2013 of RRBs of NSTAR Electric, PSNH, and WMECO.
Energy Efficiency Programs increased for the three and six months ended June 30, 2014, as compared to the same periods in 2013, due primarily to an increase in energy efficiency costs in accordance with the three-year program guidelines established by the DPU at NSTAR Electric and WMECO and expanded energy conservation programs at CL&P in 2014, partially offset by a decrease in the amortization of previously deferred costs at NSTAR Electric. All costs are fully recovered through approved tracking mechanisms and therefore do not impact earnings.
Taxes Other Than Income Taxes increased for the three and six months ended June 30, 2014, as compared to the same periods in 2013, due primarily to an increase in property taxes ($9.1 million and $16.6 million, respectively) as a result of both an increase in utility plant balances and property tax rates, and an increase in the Connecticut gross earnings tax ($2.2 million and $8.2 million, respectively) attributable to an increase in retail revenues.
Interest Expense increased $5.6 million and $19.4 million for the three and six months ended June 30, 2014, as compared to the same periods in 2013, respectively, due primarily to the absence in 2014 of the favorable impact from the resolution of a Connecticut state income tax audit in the first quarter of 2013 ($8.8 million for the six months), lower interest income on deferred transition costs ($3.5 million and $8 million, respectively), and an increase in interest on long-term debt ($1.5 million and $3.6 million, respectively) as a result of new debt issuances in the second quarter and first half of 2014.
Other Income, Net decreased $5.5 million in the first half of 2014, as compared to the first half of 2013, due primarily to lower unrealized gains on the assets supporting the deferred compensation plans ($5.3 million).
77.8
(17.8)
(18.6)
216.1
Income Tax Expense decreased for the three months ended June 30, 2014, as compared to the same period in 2013, due primarily to lower pre-tax earnings ($2.5 million) and the tax benefit impact from the reserve recorded in the second quarter of 2014 as a result of the FERC ROE orders issued in the FERC base ROE complaints ($22.1 million), partially offset by higher state taxes ($4.6 million) and various other tax impacts ($2.2 million).
Income Tax Expense increased for the six months ended June 30, 2014, as compared to the same period in 2013, due primarily to higher pre-tax earnings ($10.6 million), higher state taxes ($8.6 million), the absence of the favorable impact from the resolution of a state income tax audit in the first quarter of 2013 ($4.8 million), and various other tax impacts ($1.3 million), partially offset by the tax benefit impact from the reserve recorded as a result of the FERC ROE orders issued in the FERC base ROE complaints ($22.1 million).
50
RESULTS OF OPERATIONS – THE CONNECTICUT LIGHT AND POWER COMPANY
The following provides the amounts and variances in operating revenues and expense line items for the condensed statements of income for CL&P included in this Quarterly Report on Form 10-Q for the three and six months ended June 30, 2014 and 2013:
587.3
569.3
18.0
1,321.9
1,193.4
128.5
199.8
184.8
15.0
481.2
414.1
67.1
16.2
123.8
241.3
232.6
46.6
92.7
87.6
19.6
49.5
14.5
69.7
78.0
34.3
78.5
62.1
57.5
129.1
117.7
11.4
495.2
432.5
62.7
1,071.8
906.9
164.9
18.2
92.1
136.8
(44.7)
(32.7)
250.1
286.5
(36.4)
(12.7)
(a) Percent greater than 100 percent not shown as it is not meaningful.
CL&P's retail sales were as follows:
Retail Sales in GWh
5,050
5,194
(144)
10,875
124
CL&P's Operating Revenues increased in the second quarter of 2014, as compared to the same period of 2013. The increase primarily reflects higher costs associated with purchasing electricity on behalf of our customers. Fluctuations in these energy supply costs are recovered from customers in rates and therefore have no impact on earnings. Partially offsetting this increase was the impact of the reserve recorded during the second quarter of 2014 as a result of the FERC ROE orders issued in the FERC base ROE complaints. For further information, see "FERC Regulatory Issues - FERC Base ROE Complaints" in this Management's Discussion and Analysis. In addition, retail sales volumes decreased 2.8 percent in the second quarter of 2014, as compared to the same period in 2013, as a result of milder temperatures in late May and June of 2014.
CL&P's Operating Revenues increased in the first half of 2014, as compared to the first half of 2013. The increase reflects higher retail sales volumes of 1.1 percent as a result of significantly colder weather in the first quarter of 2014, as compared to the same period in 2013, and the overall impact of higher costs associated with the procurement of energy supply. The energy supply costs were impacted by higher natural gas transportation costs, which had an adverse impact on the cost of purchased electric energy for our retail customers. Fluctuations in energy supply costs are recovered from customers in rates and therefore have no impact on earnings. Partially offsetting this increase was the impact of the reserve recorded during the second quarter of 2014 as a result of the FERC ROE orders issued in the FERC base ROE complaints.
Purchased Power and Transmission increased for the three and six months ended June 30, 2014, as compared to the same periods in 2013, due primarily to the following:
GSC Supply Costs
104.4
Transmission Costs
Deferred Fuel Costs
26.8
Purchased Power Costs
(15.6)
(15.2)
(4.9)
The increase in GSC supply costs was due primarily to higher average supply prices and an increase in GSC loads as a result of an increase in retail sales and customers returning to standard offer from third party suppliers. On July 1, 2013, CL&P began to procure approximately 30 percent of GSC load. Costs associated with the remaining 70 percent of the GSC load are the contractual amounts CL&P must pay to various energy suppliers that have been awarded the right to supply standard service and supplier of last resort service load through a competitive solicitation process. The increase in transmission costs was the result of an increase in the retail transmission deferral, which reflects the actual costs of transmission service compared to estimated billed amounts. The decrease in deferred fuel costs for the six months ended June 30, 2014 was due primarily to higher average electric supply prices, as compared to the prices projected when standard service rates were set. Purchased Power and Transmission costs are included in PURA-approved tracking mechanisms and do not impact earnings.
Operations and Maintenance expense includes costs that are recovered in rates through cost tracking mechanisms, which have no earnings impact (tracked costs), and costs that are recovered through base electric distribution rates (and therefore impact earnings). Operations and Maintenance increased in the second quarter of 2014, as compared to the same period in 2013, driven by a $5.2 million increase in tracked costs that have no earnings impact, which was primarily attributable to higher bad debt expense of $3.6 million. There was also an increase in costs that impact earnings of $2.8 million, which was primarily attributable to the implementation of a new outage restoration program of $3.7 million, higher routine vegetation management costs of $3.7 million and higher bad debt expense of $1.3 million, partially offset by lower employee costs (including pension and benefit related costs) of $8.4 million.
Operations and Maintenance increased in the first half of 2014, as compared to the same period in 2013, driven by a $9.6 million increase in costs that have no earnings impact, primarily attributable to higher bad debt expense of $7.2 million. Partially offsetting this increase was a decrease in costs that impact earnings of $0.9 million, primarily attributable to lower employee costs (including pension and benefit related costs) of $13.1 million, partially offset by the implementation of a new outage restoration program of $3.8 million, higher bad debt expense of $2.9 million and higher routine vegetation management costs of $3.4 million.
Depreciation increased for the three and six months ended June 30, 2014, as compared to the same periods in 2013, due primarily to higher utility plant balances resulting from completed construction projects placed into service.
Amortization of Regulatory Assets, Net increased for the three and six months ended June 30, 2014, as compared to the same periods in 2013, due primarily to an increase in amortization expense related to previously deferred congestion charges.
Energy Efficiency Programs increased for the three and six months ended June 30, 2014, as compared to the same periods in 2013, due primarily to expanded energy conservation programs in 2014. All costs are fully recovered through PURA-approved tracking mechanisms and therefore do not impact earnings.
Taxes Other Than Income Taxes increased for the three and six months ended June 30, 2014, as compared to the same periods in 2013, due primarily to an increase in property taxes as a result of both an increase in utility plant balances and property tax rates ($3.9 million and $7.8 million, respectively). In addition, there was an increase in the Connecticut gross earnings tax attributable to an increase in retail revenues ($1.1 million and $4.7 million, respectively).
Interest Expense increased $3.5 million and $8 million for the three and six months ended June 30, 2014, as compared to the same periods in 2013, respectively, due primarily to the absence in 2014 of the favorable impact from the resolution of a state income tax audit in the first quarter of 2013 ($6 million for the six months), an increase in other interest ($1 million and $2.2 million, respectively) and an increase in interest on long-term debt ($2 million and $2.2 million, respectively).
Other Income, Net decreased $2.9 million in the first six months of 2014, as compared to the same period in 2013, due primarily to lower unrealized gains on the assets supporting the deferred compensation plans ($1.4 million) and lower AFUDC-Equity ($1.2 million).
20.4
37.8
(17.4)
77.0
(11.1)
Income Tax Expense decreased for the three and six months ended June 30, 2014, as compared to the same periods in 2013, due primarily to lower pre-tax earnings ($5.8 million and $4.2 million, respectively) and the tax benefit impact from the FERC ROE orders issued in the second quarter of 2014 ($12.8 million for the three and six months), partially offset by the absence in 2014 of the state audit closure benefit impact ($2.9 million for the six months) and various other tax impacts ($1.2 million and $3.0 million, respectively).
EARNINGS SUMMARY
37.4
67.9
(30.5)
(44.9)
116.7
152.9
(36.2)
(23.7)
CL&P's second quarter 2014 earnings were lower than the same period in 2013 due primarily to the establishment of an $18.5 million after-tax reserve related to the June 2014 FERC ROE orders, lower retail sales as a result of milder temperatures in late May and June of 2014, as compared to the same period in 2013, higher property tax expense, increased interest expense relating to an April 2014 financing, and higher depreciation expense. Partially offsetting these unfavorable earnings impacts were increased investments in the transmission infrastructure.
For the six months ended June 30, 2014, CL&P's earnings decreased, as compared to the same period in 2013, due primarily to the establishment of the after-tax reserve related to the June 2014 FERC ROE orders, higher property tax expense and increased interest expense relating to an April 2014 financing. Partially offsetting these unfavorable earnings impacts were higher retail electric sales as a result of colder weather in the first quarter of 2014 and increased investments in the transmission infrastructure.
52
LIQUIDITY
CL&P had cash flows provided by operating activities of $275.4 million in the first half of 2014, compared with $178.2 million in the first half of 2013. The improved cash flows were due primarily to $65.4 million in DOE Phase II Damages proceeds received on June 1, 2014 from the Yankee Companies associated with the spent nuclear fuel litigation, the absence of cash disbursements for major storm restoration costs and an increase in regulatory overrecoveries, partially offset by income tax payments of $3.8 million in the first half of 2014, as compared to income tax refunds of $6 million in the first half of 2013, and an unfavorable cash flow impact relating to the timing of accounts receivable payments made to affiliated companies in the second quarter of 2014.
Investments in Property, Plant and Equipment on the accompanying statements of cash flows do not include amounts incurred on capital projects but not yet paid, cost of removal, AFUDC related to equity funds, and the capitalized portions of pension expense. In the first half of 2014, investments for CL&P were $221.4 million.
Effective July 23, 2014, NU parent and certain of its subsidiaries, including CL&P, amended their joint $1.45 billion revolving credit facility to extend the expiration date an additional year to September 6, 2019. The revolving credit facility is to be used primarily to backstop NU parent's $1.45 billion commercial paper program. The commercial paper program allows NU parent to issue commercial paper as a form of short-term debt to its subsidiaries, including CL&P. As of June 30, 2014 and December 31, 2013, there were intercompany loans from NU parent of $6.4 million and $287.3 million, respectively, to CL&P.
Additional financing activities in the first half of 2014 included $85.6 million in common stock dividends paid to NU parent.
On April 7, 2014, Fitch affirmed the corporate credit rating and outlook of CL&P. On April 25, 2014, S&P affirmed the corporate credit rating and revised the outlook to positive from stable of CL&P.
53
RESULTS OF OPERATIONS – NSTAR ELECTRIC COMPANY AND SUBSIDIARY
The following provides the amounts and variances in operating revenues and expense line items for the condensed consolidated statements of income for NSTAR Electric included in this Quarterly Report on Form 10-Q for the six months ended June 30, 2014 and 2013:
1,227.7
1,162.7
65.0
5.6
562.0
403.9
158.1
39.1
180.2
(15.3)
(8.5)
93.6
90.9
100.5
(86.0)
(15.0)
(13.8)
(13.5)
987.8
955.6
32.2
239.9
207.1
32.8
NSTAR Electric's retail sales were as follows:
10,183
10,198
(15)
NSTAR Electric's Operating Revenues increased in the first half of 2014, as compared to the first half of 2013. The increase primarily reflects the overall impact of higher costs associated with the procurement of energy supply. Our energy supply costs were impacted by higher natural gas transportation costs, which had an adverse impact on the cost of purchased electric energy for our retail customers. Fluctuations in energy supply costs are recovered from customers in rates and therefore have no impact on earnings. Partially offsetting this increase was the impact of the reserve recorded during the second quarter of 2014 as a result of the FERC ROE orders issued in the FERC base ROE complaints. For further information, see "FERC Regulatory Issues - FERC Base ROE Complaints" in this Management's Discussion and Analysis. Additionally, stranded cost recovery revenues decreased during the period, reflecting the full collection in 2013 of previously deferred costs, as well as the full amortization of RRBs. Base distribution revenues were relatively flat in the first half of 2014, as compared to the same period in 2013, reflecting comparable sales, which was due primarily to colder weather in the first quarter of 2014 offset by milder temperatures in late May and June of 2014 and customer savings due to the impact of its energy efficiency programs. NSTAR Electric is permitted to bill customers for lost base revenues related to reductions in sales volume as a result of their energy efficiency. In the first half of 2014, base distribution revenues increased $5.4 million, compared to the first half of 2013 (including the impact from the recognition of lost base revenues).
Purchased Power and Transmission increased in the first half of 2014, as compared to the first half of 2013, due primarily to the following:
Six Months EndedIncrease/(Decrease)
Basic Service Costs
115.4
26.4
20.1
The increase in Basic Service costs was primarily related to higher average supply prices. The increase in transmission costs was due primarily to higher RNS expense, and the increase in purchased power costs was due primarily to higher congestion charges. The decrease in deferred fuel costs was due primarily to higher average electricity supply prices, as compared to the prices projected when Basic Service rates were set. Purchased Power and Transmission costs are included in DPU-approved tracking mechanisms and do not impact earnings.
Operations and Maintenance expense includes costs that are recovered in rates through cost tracking mechanisms, which have no earnings impact (tracked costs), and costs that are recovered through base electric distribution rates (and therefore impact earnings). Operations and Maintenance decreased in the first half of 2014, as compared to the first half of 2013, driven by a $21.5 million reduction in costs that impact earnings (primarily attributable to lower employee costs and benefit costs of $15.7 million and lower storm costs of $3 million. Partially offsetting this decrease was an increase in costs that have no earnings impact of $6.2 million (primarily attributable to higher storm costs of $3 million).
Depreciation increased in the first half of 2014, as compared to the first half of 2013, due primarily to higher utility plant balances resulting from completed construction projects placed into service.
Amortization of Regulatory Assets, Net decreased in the first half of 2014, as compared to the first half of 2013, due primarily to a decrease in the recovery of previously deferred stranded costs.
Amortization of Rate Reduction Bonds decreased in the first half of 2014, as compared to the first half of 2013, due to the maturity of the RRBs in March 2013.
Energy Efficiency Programs decreased in the first half of 2014, as compared to the first half of 2013, due primarily to a decrease in the amortization of previously deferred costs. All costs are fully recovered through DPU-approved tracking mechanisms and therefore do not impact earnings.
Taxes Other Than Income Taxes increased in the first half of 2014, as compared to the first half of 2013, due to an increase in property taxes as a result of an increase in utility plant balances, partially offset by lower average municipal property tax rates.
Interest Expense increased $8.6 million in the first half of 2014, as compared to the first half of 2013, due primarily to lower interest income on deferred transition costs ($8 million), as well as an increase in interest on long-term debt.
Other Income/(Loss), Net decreased $1.4 million in the first half of 2014, as compared to the first half of 2013, due primarily to lower unrealized gains on the assets supporting the deferred compensation plans.
79.7
68.9
Income Tax Expense increased in the first half of 2014, as compared to the same period in 2013, due primarily to higher pre-tax earnings ($11.6 million) and higher state taxes ($3.5 million), partially offset by the tax benefit impact from the FERC ROE orders issued in the second quarter of 2014 ($4.1 million).
118.2
106.2
12.0
In the first half of 2014, NSTAR Electric's earnings increased, as compared to the same period in 2013, due primarily to lower operations and maintenance expenses attributed to lower employee costs, benefit costs and lower storm costs. Partially offsetting these favorable earnings impacts were the establishment of a $6.1 million after-tax reserve related to the June 2014 FERC ROE orders and higher depreciation and property tax expenses.
NSTAR Electric had cash flows provided by operating activities of $387.7 million in the first half of 2014, compared with $91.6 million in the first half of 2013. The increase in operating cash flows was due primarily to the absence of cash disbursements for major storm restoration costs associated with the February 2013 blizzard, the timing of collections of accounts receivables from affiliated companies, $29.1 million in DOE Phase II Damages proceeds received on June 1, 2014 from the Yankee Companies associated with the spent nuclear fuel litigation, a decrease in income tax payments in the first half of 2014, as compared to the first half of 2013, and the absence of Pension Plan cash contributions in the first half of 2014, as compared to the first half of 2013. These favorable cash flow impacts were partially offset by the absence of costs recovered in rates related to the RRBs that were fully amortized in the first quarter of 2013.
Effective July 23, 2014, NSTAR Electric amended its $450 million revolving credit facility to extend the expiration date an additional year to September 6, 2019. This facility serves to backstop NSTAR Electric's existing $450 million commercial paper program. As of June 30, 2014 and December 31, 2013, NSTAR Electric had $194.5 million and $103.5 million, respectively, in short-term borrowings outstanding under its commercial paper program, leaving $255.5 million and $346.5 million, respectively, of available borrowing capacity. The weighted-average interest rate on these borrowings as of June 30, 2014 and December 31, 2013 was 0.16 percent and 0.13 percent, respectively, which is generally based on A2/P1 rated commercial paper.
RESULTS OF OPERATIONS – PUBLIC SERVICE COMPANY OF NEW HAMPSHIRE AND SUBSIDIARY
The following provides the amounts and variances in operating revenues and expense line items for the condensed consolidated statements of income for PSNH included in this Quarterly Report on Form 10-Q for the six months ended June 30, 2014 and 2013:
511.5
489.9
183.6
151.1
32.5
21.5
132.5
122.1
45.5
19.8
(19.8)
398.4
377.5
20.9
113.1
PSNH's retail sales were as follows:
3,909
3,837
72
PSNH's Operating Revenues increased in the first half of 2014, as compared to the first half of 2013, due primarily to an increase of 1.9 percent in retail sales as a result of the colder weather in the first quarter of 2014, as compared to the same period in 2013. The average daily temperature in New Hampshire in the first quarter of 2014 was over five degrees lower than the first quarter of 2013. In addition, revenues increased due to the overall impact of higher costs associated with the procurement of energy supply. The energy supply costs were impacted by higher natural gas transportation costs, which had an adverse impact on the cost of purchased electric energy for our retail customers. Fluctuations in energy supply costs are recovered from customers in rates and therefore have no impact on earnings. Also reflected in the revenue increase were increases of $6.4 million related to NHPUC-approved distribution rate increases effective July 1, 2013 and increases in transmission revenues as a result of the recovery of higher transmission expenses including ongoing investments in our transmission infrastructure, partially offset by the impact of the reserve recorded during the second quarter of 2014 as a result of the FERC ROE orders issued in the FERC base ROE complaints. For further information, see "FERC Regulatory Issues - FERC Base ROE Complaints" in this Management's Discussion and Analysis.
Purchased Power, Fuel and Transmission increased in the first half of 2014, as compared to the first half of 2013, due primarily to the following:
Generation Fuel Costs
Renewable Energy Costs
(19.2)
The increase in generation fuel costs was due primarily to an increase in the amount of electricity generated by PSNH facilities. The increase in renewable energy costs was a result of lower regional greenhouse gas initiative auction proceeds, partially offset by lower renewable energy requirements set by the NHPUC. The increase in transmission costs was as a result of an increase in the retail transmission cost deferral, which reflects the actual costs of transmission service compared to estimated amounts billed to customers. The decrease in purchased power costs was a result of additional customer migration to third party suppliers. Purchased Power, Fuel and Transmission costs are included in NHPUC-approved tracking mechanisms and do not impact earnings.
Operations and Maintenance expense includes costs that are recovered in rates through cost tracking mechanisms, which have no earnings impact (tracked costs), and costs that are recovered through base electric distribution rates (and therefore impact earnings). Operations and Maintenance increased in the first half of 2014, as compared to the first half of 2013, driven by an $8 million increase in costs that have no earnings impact (primarily attributable to higher operations and maintenance costs at the generation business of $5.1 million due to the timing of planned outages and higher bad debt expense of $1 million, partially offset by lower employee costs, including pension and benefit related costs, of $2.4 million). Additionally, there was an increase in costs that impact earnings of $2.4 million.
Amortization of Regulatory Assets/(Liabilities), Net increased in the first half of 2014, as compared to the first half of 2013, due primarily to increases in the stranded cost recovery charge, default energy service, and other amortizations of $1.7 million, $0.2 million, and $3.9 million, respectively.
Amortization of Rate Reduction Bonds decreased in the first half of 2014, as compared to the first half of 2013, due to the maturity of the RRBs in May 2013.
Change
34.6
Income Tax Expense was relatively flat in the first half of 2014, as compared to the first half of 2013, due primarily to higher pre-tax earnings ($1.5 million), offset by the tax benefit impact from the FERC ROE orders issued in the second quarter of 2014 ($1.5 million).
56.2
In the first half of 2014, PSNH's earnings increased, as compared to the same period in 2013, due primarily to higher distribution retail revenues, which were favorably impacted by the PSNH annualized distribution rate increases effective July 1, 2013, and higher retail electric sales. Partially offsetting these favorable earnings impacts were the establishment of a $2 million after-tax reserve related to the June 2014 FERC ROE orders, and higher depreciation expense.
PSNH had cash flows provided by operating activities of $142.4 million in the first half of 2014, compared with $138.7 million in the first half of 2013. The improved cash flows were due to $13.1 million in DOE Phase II Damages proceeds received on June 1, 2014 from the Yankee Companies associated with the spent nuclear fuel litigation, the absence of approximately $45 million in NUSCO Pension Plan cash contributions in the first half of 2014, and the favorable impact of the 2010 rate case settlement related to the additional increase to annualized rates that was effective July 1, 2013. These favorable cash flow impacts were partially offset by income tax payments of $28.8 million in the first half of 2014, compared with income tax refunds of $12.1 million in the first half of 2013, and the absence of costs recovered in rates related to the RRBs that were fully amortized in the second quarter of 2013.
RESULTS OF OPERATIONS – WESTERN MASSACHUSETTS ELECTRIC COMPANY
The following provides the amounts and variances in operating revenues and expense line items for the condensed statements of income for WMECO included in this Quarterly Report on Form 10-Q for the six months ended June 30, 2014 and 2013:
245.7
240.0
5.7
87.1
20.5
18.3
12.6
(12.5)
7.8
36.4
12.5
193.3
172.0
21.3
52.4
68.0
(22.9)
WMECO's retail sales were as follows:
1,793
1,798
WMECO's Operating Revenues increased in the first half of 2014, as compared to the first half of 2013, due primarily to a $3.9 million increase in revenues that impacts earnings due to the reversal of a previously established wholesale billing adjustment. The remaining increase primarily reflects a higher level of recovery related to WMECO's energy supply and energy efficiency programs. These revenues are fully reconciled to the related costs. Therefore this increase in revenues had no material impact on earnings. Partially offsetting this increase was the impact of the reserve recorded during the second quarter of 2014 as a result of the FERC ROE orders issued in the FERC base ROE complaints. For further information, see "FERC Regulatory Issues - FERC Base ROE Complaints" in this Management's Discussion and Analysis. Base distribution revenues were relatively flat in the first half of 2014, as compared to the same period in 2013. Fluctuations in WMECO's kWh sales have no impact on earnings, as its revenues are decoupled from sales volumes and changes in revenues are primarily related to changes in its cost tracking mechanisms.
Purchased Power and Transmission increased in the first half of 2014, as compared to the first half of 2013, due primarily to an increase in supplier contract prices and an increase in customers returning to default service from third party suppliers ($13.9 million) and an increase in transmission costs ($5.7 million) as a result of an increase in the retail transmission cost deferral, which reflects the actual costs of transmission service compared to estimated amounts billed to customers. Partially offsetting this increase was the impact of the change in deferred fuel costs ($2.4 million) due primarily to higher average electric supply prices, as compared to the prices projected when basic service rates were set. Purchased Power and Transmission costs are included in DPU-approved tracking mechanisms and do not impact earnings.
Operations and Maintenance expense includes costs that are recovered in rates through cost tracking mechanisms, which have no earnings impact (tracked costs), and costs that are recovered through base electric distribution rates (and therefore impact earnings). Operations and Maintenance increased in the first half of 2014, as compared to the first half of 2013, driven by a $2.5 million increase in costs that impact earnings (primarily attributable to an increase in workers' compensation claims of $1.9 million and higher bad debt expense of $0.8 million). Partially offsetting this increase was a decrease in costs that have no earnings impact of $0.3 million.
Amortization of Rate Reduction Bonds decreased in the first half of 2014, as compared to the first half of 2013, due to the maturity of the RRBs in June 2013.
Energy Efficiency Programs increased in the first half of 2014, as compared to the first half of 2013, due primarily to an increase in energy efficiency costs in accordance with the three-year program guidelines established by the DPU. All costs are fully recovered through DPU-approved tracking mechanisms and therefore do not impact earnings.
Taxes Other Than Income Taxes increased in the first half of 2014, as compared to the first half of 2013, due primarily to an increase in property taxes as a result of both an increase in utility plant balances and property tax rates.
(5.7)
(26.1)
Income Tax Expense decreased in the first half of 2014, as compared to the first half of 2013, due primarily to the tax benefit impact from the FERC ROE orders issued in the second quarter of 2014 ($3.6 million) and lower pre-tax earnings ($2.3 million).
25.1
(9.9)
(28.3)
In the first half of 2014, WMECO's earnings decreased, as compared to the same period in 2013, due primarily to the establishment of a $5.5 million after-tax reserve related to the June 2014 FERC ROE orders, an increase in workers' compensation claims, and higher depreciation and property tax expense. Partially offsetting these unfavorable earnings impacts were an increase in generation earnings and a decrease in other interest expense.
WMECO had cash flows provided by operating activities of $96.6 million in the first half of 2014, compared with $119.3 million in the first half of 2013. The decrease in operating cash flows was due primarily to income tax payments of $16.9 million in the first half of 2014, compared with income tax refunds of $32.4 million in the first half of 2013 and the absence of costs recovered in rates related to the RRBs that were fully amortized in the second quarter of 2013, partially offset by the receipt of $18.1 million in DOE Phase II Damages proceeds received on June 1, 2014 from the Yankee Companies associated with the spent nuclear fuel litigation and an increase in regulatory overrecoveries.
59
ITEM 3.
QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
Market Risk Information
Commodity Price Risk Management: Our Regulated companies enter into energy contracts to serve our customers and the economic impacts of those contracts are passed on to our customers. Accordingly, the Regulated companies have no exposure to loss of future earnings or fair values due to these market risk-sensitive instruments. NU's Energy Supply Risk Committee, comprised of senior officers, reviews and approves all large scale energy related transactions entered into by its Regulated companies.
Other Risk Management Activities
Interest Rate Risk Management: We manage our interest rate risk exposure in accordance with our written policies and procedures by maintaining a mix of fixed and variable rate long-term debt.
Credit Risk Management: Credit risk relates to the risk of loss that we would incur as a result of non-performance by counterparties pursuant to the terms of our contractual obligations. We serve a wide variety of customers and transact with suppliers that include IPPs, industrial companies, gas and electric utilities, oil and gas producers, financial institutions, and other energy marketers. Margin accounts exist within this diverse group, and we realize interest receipts and payments related to balances outstanding in these margin accounts. This wide customer and supplier mix generates a need for a variety of contractual structures, products and terms that, in turn, require us to manage the portfolio of market risk inherent in those transactions in a manner consistent with the parameters established by our risk management process.
If the respective unsecured debt ratings of NU or its subsidiaries were reduced to below investment grade by either Moody's or S&P, certain of NU's contracts would require additional collateral in the form of cash to be provided to counterparties and independent system operators. NU would have been and remains able to provide that collateral.
For further information on cash collateral deposited and posted with counterparties as well as any cash collateral netted against the fair value of the related derivative contracts, see Note 4, "Derivative Instruments," to the financial statements.
We have provided additional disclosures regarding interest rate risk management and credit risk management in Part II, Item 7A, "Quantitative and Qualitative Disclosures about Market Risk," in NU's 2013 Form 10-K, which is incorporated herein by reference. There have been no additional risks identified and no material changes with regard to the items previously disclosed in the NU 2013 Form 10-K.
ITEM 4.
CONTROLS AND PROCEDURES
Management, on behalf of NU, CL&P, NSTAR Electric, PSNH and WMECO, evaluated the design and operation of the disclosure controls and procedures as of June 30, 2014 to determine whether they are effective in ensuring that the disclosure of required information is made timely and in accordance with the Securities Exchange Act of 1934 and the rules and regulations of the SEC. This evaluation was made under management's supervision and with management's participation, including the principal executive officers and principal financial officer as of the end of the period covered by this Quarterly Report on Form 10-Q. There are inherent limitations of disclosure controls and procedures, including the possibility of human error and the circumventing or overriding of the controls and procedures. Accordingly, even effective disclosure controls and procedures can only provide reasonable assurance of achieving their control objectives. The principal executive officers and principal financial officer have concluded, based on their review, that the disclosure controls and procedures of NU, CL&P, NSTAR Electric, PSNH and WMECO are effective to ensure that information required to be disclosed by us in reports filed under the Securities Exchange Act of 1934 (i) is recorded, processed, summarized, and reported within the time periods specified in SEC rules and regulations and (ii) is accumulated and communicated to management, including the principal executive officers and principal financial officer, as appropriate to allow timely decisions regarding required disclosures.
There have been no changes in internal controls over financial reporting for NU, CL&P, NSTAR Electric, PSNH and WMECO during the quarter ended June 30, 2014 that have materially affected, or are reasonably likely to materially affect, internal controls over financial reporting.
PART II. OTHER INFORMATION
ITEM 1.
LEGAL PROCEEDINGS
We are parties to various legal proceedings. We have identified these legal proceedings in Part I, Item 3, "Legal Proceedings," and elsewhere in our 2013 Form 10-K, which disclosures are incorporated herein by reference. There have been no additional material legal proceedings identified and no material changes with regard to the legal proceedings previously disclosed in our 2013 Form 10-K.
ITEM 1A.
RISK FACTORS
We are subject to a variety of significant risks in addition to the matters set forth under "Forward-Looking Statements," in Item 2, "Management's Discussion and Analysis of Financial Condition and Results of Operations," of this Quarterly Report on Form 10-Q. We have identified a number of these risk factors in Part I, Item 1A, "Risk Factors," in our 2013 Form 10-K, which risk factors are incorporated herein by reference. These risk factors should be considered carefully in evaluating our risk profile. There have been no additional risk factors identified and no material changes with regard to the risk factors previously disclosed in our 2013 Form 10-K.
ITEM 2.
UNREGISTERED SALES OF EQUITY SECURITIES AND USE OF PROCEEDS
The following table discloses purchases of our common shares made by us or on our behalf for the periods shown below. The common shares purchased consist of open market purchases made by the Company or an independent agent. These share transactions related to the Company's Long-Term Incentive Plans.
Period
Total Numberof SharesPurchased
AveragePricePaid perShare
Total Number ofShares Purchasedas Part of PubliclyAnnounced Plans orPrograms
Approximate DollarValue of Shares thatMay Yet Be PurchasedUnder the Plans andPrograms (at month end)
April 1 – April 30, 2014
May 1 – May 31, 2014
June 1 – June 30, 2014
208,608
46.93
ITEM 6.
EXHIBITS
Each document described below is filed herewith, unless designated with an asterisk (*), which exhibits are incorporated by reference by the registrant under whose name the exhibit appears.
Exhibit No.
Listing of Exhibits (NU)
Ratio of Earnings to Fixed Charges
Certification of Thomas J. May, Chairman, President and Chief Executive Officer of NU, required by Rule 13a - 14(a)/15d - 14(a) of the Securities Exchange Act of 1934, as amended, as adopted pursuant to Section 302 of the Sarbanes-Oxley Act of 2002, dated August 1, 2014
Certification of James J. Judge, Executive Vice President and Chief Financial Officer of NU, required by Rule 13a - 14(a)/15d - 14(a) of the Securities Exchange Act of 1934, as amended, as adopted pursuant to Section 302 of the Sarbanes-Oxley Act of 2002, dated August 1, 2014
Certification of Thomas J. May, Chairman, President and Chief Executive Officer of NU, and James J. Judge, Executive Vice President and Chief Financial Officer of NU, pursuant to 18 U.S.C. Section 1350 as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, dated August 1, 2014
Listing of Exhibits (CL&P)
*4.1
Supplemental Indenture (2014 Series A Bond) between CL&P and Deutsche Bank Trust Company Americas, as Trustee dated as of April 1, 2014 (Exhibit 4.1, CL&P Current Report on Form 8-K filed April 29, 2014, File No. 000-00404)
Certification of Leon J. Olivier, Chief Executive Officer of CL&P, required by Rule 13a - 14(a)/15d - 14(a) of the Securities Exchange Act of 1934, as amended, as adopted pursuant to Section 302 of the Sarbanes-Oxley Act of 2002, dated August 1, 2014
Certification of James J. Judge, Executive Vice President and Chief Financial Officer of CL&P, required by Rule 13a - 14(a)/15d - 14(a) of the Securities Exchange Act of 1934, as amended, as adopted pursuant to Section 302 of the Sarbanes-Oxley Act of 2002, dated August 1, 2014
Certification of Leon J. Olivier, Chief Executive Officer of CL&P, and James J. Judge, Executive Vice President and Chief Financial Officer of CL&P, pursuant to 18 U.S.C. Section 1350 as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, dated August 1, 2014
Listing of Exhibits (NSTAR Electric)
Certification of Leon J. Olivier, Chief Executive Officer of NSTAR Electric, required by Rule 13a - 14(a)/15d - 14(a) of the Securities Exchange Act of 1934, as amended, as adopted pursuant to Section 302 of the Sarbanes-Oxley Act of 2002, dated August 1, 2014
Certification of James J. Judge, Executive Vice President and Chief Financial Officer of NSTAR Electric, required by Rule 13a - 14(a)/15d - 14(a) of the Securities Exchange Act of 1934, as amended, as adopted pursuant to Section 302 of the Sarbanes-Oxley Act of 2002, dated August 1, 2014
Certification of Leon J. Olivier, Chief Executive Officer of NSTAR Electric, and James J. Judge, Executive Vice President and Chief Financial Officer of NSTAR Electric, pursuant to 18 U.S.C. Section 1350 as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, dated August 1, 2014
Listing of Exhibits (PSNH)
Certification of Leon J. Olivier, Chief Executive Officer of PSNH, required by Rule 13a - 14(a)/15d - 14(a) of the Securities Exchange Act of 1934, as amended, as adopted pursuant to Section 302 of the Sarbanes-Oxley Act of 2002, dated August 1, 2014
Certification of James J. Judge, Executive Vice President and Chief Financial Officer of PSNH, required by Rule 13a - 14(a)/15d - 14(a) of the Securities Exchange Act of 1934, as amended, as adopted pursuant to Section 302 of the Sarbanes-Oxley Act of 2002, dated August 1, 2014
Certification of Leon J. Olivier, Chief Executive Officer of PSNH, and James J. Judge, Executive Vice President and Chief Financial Officer of PSNH, pursuant to 18 U.S.C. Section 1350 as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, dated August 1, 2014
Listing of Exhibits (WMECO)
Certification of Leon J. Olivier, Chief Executive Officer of WMECO, required by Rule 13a - 14(a)/15d - 14(a) of the Securities Exchange Act of 1934, as amended, as adopted pursuant to Section 302 of the Sarbanes-Oxley Act of 2002, dated August 1, 2014
Certification of James J. Judge, Executive Vice President and Chief Financial Officer of WMECO, required by Rule 13a - 14(a)/15d - 14(a) of the Securities Exchange Act of 1934, as amended, as adopted pursuant to Section 302 of the Sarbanes-Oxley Act of 2002, dated August 1, 2014
Certification of Leon J. Olivier, Chief Executive Officer of WMECO, and James J. Judge, Executive Vice President and Chief Financial Officer of WMECO, pursuant to 18 U.S.C. Section 1350 as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, dated August 1, 2014
Listing of Exhibits (NU, CL&P, NSTAR Electric, PSNH, WMECO)
101.INS
XBRL Instance Document
101.SCH
XBRL Taxonomy Extension Schema
101.CAL
XBRL Taxonomy Extension Calculation
101.DEF
XBRL Taxonomy Extension Definition
101.LAB
XBRL Taxonomy Extension Labels
101.PRE
XBRL Taxonomy Extension Presentation
SIGNATURE
Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the Registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.
NORTHEAST UTILITIES
August 1, 2014
By:
/s/
Jay S. Buth
Vice President, Controller and Chief Accounting Officer
NSTAR ELECTRIC COMPANY
PUBLIC SERVICE COMPANY OF NEW HAMPSHIRE