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![[september302013form10qedg002.gif]](https://files.docoh.com/10-Q/0000072741-13-000064/september302013form10qedg002.gif)
UNITED STATES SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, D.C. 20549
FORM 10-Q
| QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE |
For the Quarterly Period Ended March 31, 2014
OR
o |
|
| |
| TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE |
|
For the transition period from to
Commission | Registrant; State of Incorporation; | I.R.S. Employer | ||
1-5324 | NORTHEAST UTILITIES (a Massachusetts voluntary association) |
|
04-2147929
| ||||
0-00404 | THE CONNECTICUT LIGHT AND POWER COMPANY |
|
06-0303850
| ||||
1-02301 | NSTAR ELECTRIC COMPANY |
|
04-1278810
| ||||
1-6392 | PUBLIC SERVICE COMPANY OF NEW HAMPSHIRE |
|
02-0181050
| ||||
0-7624 | WESTERN MASSACHUSETTS ELECTRIC COMPANY | 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 | ||
|
| x | ||
|
| o |
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).
| Yes | No | ||
|
| x | ||
|
| o |
Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, or a non-accelerated filer. See definition of "accelerated“accelerated filer and large accelerated filer"filer” in Rule 12b-2 of the Exchange Act. (Check one):
Large | Accelerated | Non-accelerated | ||||
Northeast Utilities |
| x |
| o |
| o |
The Connecticut Light and Power Company |
| o |
| o |
| x |
NSTAR Electric Company |
| o |
| o |
| x |
Public Service Company of New Hampshire |
| o |
| o |
| x |
Western Massachusetts Electric Company |
| o |
| o |
| x |
Indicate by check mark whether the registrants are shell companies (as defined in Rule 12b-2 of the Exchange Act):
Yes | No | |||
|
|
| ||
|
|
| ||
Northeast Utilities |
|
| x | |
The Connecticut Light and Power Company |
|
| x | |
NSTAR Electric Company |
|
| x | |
Public Service Company of New Hampshire |
|
| x | |
Western Massachusetts Electric Company |
|
| x |
Indicate the number of shares outstanding of each of the issuers'issuers’ classes of common stock, as of the latest practicable date:
Company - Class of Stock | Outstanding as of | |
Northeast Utilities |
| 315,985,270 shares |
|
| |
The Connecticut Light and Power Company | 6,035,205 shares | |
|
| |
NSTAR Electric Company | 100 shares | |
|
| |
Public Service Company of New Hampshire | 301 shares | |
|
| |
Western Massachusetts Electric Company | 434,653 shares |
Northeast Utilities directly or indirectly, holds all of the 6,035,205 shares, 100 shares, 301 shares, and 434,653 shares of the outstanding common stock of The Connecticut Light and Power Company, NSTAR Electric Company, Public Service Company of New Hampshire and Western Massachusetts Electric Company, respectively.
NSTAR Electric Company, Public Service Company of New Hampshire and Western Massachusetts Electric Company each meet the conditions set forth in General Instructions H(1)(a) and (b) of Form 10-Q, and each is therefore filing this Form 10-Q with the reduced disclosure format specified in General Instruction H(2) of Form 10-Q.
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 |
| |
| The Connecticut Light and Power Company | |
CYAPC | Connecticut Yankee Atomic Power Company | |
Hopkinton | Hopkinton LNG Corp., a wholly owned subsidiary of | |
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 Company | |
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, Inc., the parent company of NGS, Select Energy, | |
NU or the Company | Northeast Utilities and subsidiaries | |
NU parent and other companies | NU parent and other companies is comprised of NU parent, | |
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 | Public Service Company of New Hampshire | |
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 | Western Massachusetts Electric Company | |
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 | |
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 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 | |
|
| Nitrogen oxide |
NU |
| |
| The Northeast Utilities and Subsidiaries | |
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 & | |
SBC |
| Systems Benefits Charge |
SCRC | Stranded Cost Recovery Charge | |
SERP |
| Supplemental Executive Retirement |
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 SUBSIDIARIES
THE CONNECTICUT LIGHT AND POWER COMPANY
NSTAR ELECTRIC COMPANY AND SUBSIDIARY
PUBLIC SERVICE COMPANY OF NEW HAMPSHIRE AND SUBSIDIARY
WESTERN MASSACHUSETTS ELECTRIC COMPANY
iii
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Condensed Statements of Cash Flows — Three Months Ended March 31, 2014 and 2013 | 20 |
Combined Notes to Condensed Consolidated Financial Statements (Unaudited) | 21 |
Page | |
ITEM 2 | |
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49 | |
51 | |
53 | |
55 | |
ITEM 3 — Quantitative and Qualitative Disclosures About Market Risk | 57 |
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PART II |
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ITEM 2 |
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ITEM 6 — Exhibits |
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61 |
v
NORTHEAST UTILITIES AND SUBSIDIARIES
CONDENSED CONSOLIDATED BALANCE SHEETS
(Unaudited)
1
|
| March 31, |
| December 31, |
| ||
(Thousands of Dollars) |
| 2014 |
| 2013 |
| ||
|
|
|
|
|
| ||
ASSETS |
|
|
|
|
| ||
|
|
|
|
|
| ||
Current Assets: |
|
|
|
|
| ||
Cash and Cash Equivalents |
| $ | 89,150 |
| $ | 43,364 |
|
Receivables, Net |
| 980,033 |
| 765,391 |
| ||
Unbilled Revenues |
| 202,867 |
| 224,982 |
| ||
Fuel, Materials and Supplies |
| 228,192 |
| 303,233 |
| ||
Regulatory Assets |
| 573,028 |
| 535,791 |
| ||
Prepayments and Other Current Assets |
| 292,539 |
| 214,288 |
| ||
Total Current Assets |
| 2,365,809 |
| 2,087,049 |
| ||
|
|
|
|
|
| ||
Property, Plant and Equipment, Net |
| 17,713,027 |
| 17,576,186 |
| ||
|
|
|
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|
| ||
Deferred Debits and Other Assets: |
|
|
|
|
| ||
Regulatory Assets |
| 3,486,645 |
| 3,758,694 |
| ||
Goodwill |
| 3,519,401 |
| 3,519,401 |
| ||
Marketable Securities |
| 507,931 |
| 488,515 |
| ||
Other Long-Term Assets |
| 504,057 |
| 365,692 |
| ||
Total Deferred Debits and Other Assets |
| 8,018,034 |
| 8,132,302 |
| ||
|
|
|
|
|
| ||
Total Assets |
| $ | 28,096,870 |
| $ | 27,795,537 |
|
The accompanying notes are an integral part of these unaudited condensed consolidated financial statements.
NORTHEAST UTILITIES AND SUBSIDIARIES |
|
|
|
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| ||
CONDENSED CONSOLIDATED BALANCE SHEETS |
|
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(Unaudited) |
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| September 30, |
| December 31, | ||
(Thousands of Dollars) | 2013 |
| 2012 | ||||
|
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|
LIABILITIES AND CAPITALIZATION |
|
|
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| ||
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Current Liabilities: |
|
|
|
|
| ||
| Notes Payable | $ | 1,343,000 |
| $ | 1,120,196 | |
| Long-Term Debt - Current Portion |
| 608,346 |
|
| 763,338 | |
| Accounts Payable |
| 554,010 |
|
| 764,350 | |
| Regulatory Liabilities |
| 224,416 |
|
| 134,115 | |
| Other Current Liabilities |
| 648,658 |
|
| 861,691 | |
Total Current Liabilities |
| 3,378,430 |
|
| 3,643,690 | ||
|
|
|
|
|
|
|
|
Rate Reduction Bonds |
| - |
|
| 82,139 | ||
|
|
|
|
|
|
|
|
Deferred Credits and Other Liabilities: |
|
|
|
|
| ||
| Accumulated Deferred Income Taxes |
| 3,954,246 |
|
| 3,463,347 | |
| Regulatory Liabilities |
| 520,732 |
|
| 540,162 | |
| Derivative Liabilities |
| 766,804 |
|
| 882,654 | |
| Accrued Pension, SERP and PBOP |
| 1,808,896 |
|
| 2,130,497 | |
| Other Long-Term Liabilities |
| 897,997 |
|
| 967,561 | |
Total Deferred Credits and Other Liabilities |
| 7,948,675 |
|
| 7,984,221 | ||
|
|
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|
|
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|
Capitalization: |
|
|
|
|
| ||
| Long-Term Debt |
| 7,444,192 |
|
| 7,200,156 | |
|
|
|
|
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|
|
|
| Noncontrolling Interest - Preferred Stock of Subsidiaries |
| 155,568 |
|
| 155,568 | |
|
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| Equity: |
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| |
| Common Shareholders' Equity: |
|
|
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| |
|
| Common Shares |
| 1,665,098 |
|
| 1,662,547 |
|
| Capital Surplus, Paid In |
| 6,185,805 |
|
| 6,183,267 |
|
| Retained Earnings |
| 2,064,401 |
|
| 1,802,714 |
|
| Accumulated Other Comprehensive Loss |
| (67,387) |
|
| (72,854) |
|
| Treasury Stock |
| (330,464) |
|
| (338,624) |
| Common Shareholders' Equity |
| 9,517,453 |
|
| 9,237,050 | |
Total Capitalization |
| 17,117,213 |
|
| 16,592,774 | ||
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Total Liabilities and Capitalization | $ | 28,444,318 |
| $ | 28,302,824 | ||
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The accompanying notes are an integral part of these unaudited condensed consolidated financial statements. |
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3
4
5
THE CONNECTICUT LIGHT AND POWER COMPANY |
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CONDENSED BALANCE SHEETS |
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(Unaudited) |
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| September 30, |
| December 31, | ||
(Thousands of Dollars) | 2013 |
| 2012 | ||||
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LIABILITIES AND CAPITALIZATION |
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Current Liabilities: |
|
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|
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| Notes Payable to Affiliated Companies | $ | 342,900 |
| $ | 99,296 | |
| Long-Term Debt - Current Portion |
| 150,000 |
|
| 125,000 | |
| Accounts Payable |
| 170,683 |
|
| 262,857 | |
| Accounts Payable to Affiliated Companies |
| 46,401 |
|
| 52,326 | |
| Obligations to Third Party Suppliers |
| 65,580 |
|
| 67,344 | |
| Accrued Taxes |
| 60,643 |
|
| 60,109 | |
| Regulatory Liabilities |
| 81,988 |
|
| 32,119 | |
| Derivative Liabilities |
| 94,123 |
|
| 96,931 | |
| Other Current Liabilities |
| 78,520 |
|
| 125,662 | |
Total Current Liabilities |
| 1,090,838 |
|
| 921,644 | ||
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Deferred Credits and Other Liabilities: |
|
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| Accumulated Deferred Income Taxes |
| 1,471,547 |
|
| 1,336,105 | |
| Regulatory Liabilities |
| 107,964 |
|
| 124,319 | |
| Derivative Liabilities |
| 756,437 |
|
| 865,571 | |
| Accrued Pension, SERP and PBOP |
| 291,257 |
|
| 304,696 | |
| Other Long-Term Liabilities |
| 160,368 |
|
| 197,434 | |
Total Deferred Credits and Other Liabilities |
| 2,787,573 |
|
| 2,828,125 | ||
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Capitalization: |
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| Long-Term Debt |
| 2,591,012 |
|
| 2,737,790 | |
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| Preferred Stock Not Subject to Mandatory Redemption |
| 116,200 |
|
| 116,200 | |
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| Common Stockholder's Equity: |
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| Common Stock |
| 60,352 |
|
| 60,352 |
|
| Capital Surplus, Paid In |
| 1,641,487 |
|
| 1,640,149 |
|
| Retained Earnings |
| 940,647 |
|
| 839,628 |
|
| Accumulated Other Comprehensive Loss |
| (1,494) |
|
| (1,800) |
| Common Stockholder's Equity |
| 2,640,992 |
|
| 2,538,329 | |
Total Capitalization |
| 5,348,204 |
|
| 5,392,319 | ||
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Total Liabilities and Capitalization | $ | 9,226,615 |
| $ | 9,142,088 | ||
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The accompanying notes are an integral part of these unaudited condensed financial statements. |
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6
7
8
9
NSTAR ELECTRIC COMPANY AND SUBSIDIARY |
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CONDENSED CONSOLIDATED BALANCE SHEETS |
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(Unaudited) |
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| September 30, |
| December 31, | ||
(Thousands of Dollars) | 2013 |
| 2012 | ||||
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LIABILITIES AND CAPITALIZATION |
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Current Liabilities: |
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| Notes Payable | $ | 156,000 |
| $ | 276,000 | |
| Long-Term Debt - Current Portion |
| 301,650 |
|
| 1,650 | |
| Accounts Payable |
| 157,375 |
|
| 168,611 | |
| Accounts Payable to Affiliated Companies |
| 97,992 |
|
| 247,061 | |
| Accumulated Deferred Income Taxes |
| 32,049 |
|
| 104,668 | |
| Regulatory Liabilities |
| 82,521 |
|
| 47,539 | |
| Other Current Liabilities |
| 128,846 |
|
| 144,433 | |
Total Current Liabilities |
| 956,433 |
|
| 989,962 | ||
|
|
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|
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|
Rate Reduction Bonds |
| - |
|
| 43,493 | ||
|
|
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|
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Deferred Credits and Other Liabilities: |
|
|
|
|
| ||
| Accumulated Deferred Income Taxes |
| 1,463,285 |
|
| 1,321,026 | |
| Regulatory Liabilities |
| 251,005 |
|
| 244,224 | |
| Accrued Pension |
| 380,688 |
|
| 360,932 | |
| Payable to Affiliated Companies |
| 64,752 |
|
| 70,221 | |
| Other Long-Term Liabilities |
| 145,032 |
|
| 183,190 | |
Total Deferred Credits and Other Liabilities |
| 2,304,762 |
|
| 2,179,593 | ||
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Capitalization: |
|
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| Long-Term Debt |
| 1,499,378 |
|
| 1,600,911 | |
|
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| Preferred Stock Not Subject to Mandatory Redemption |
| 43,000 |
|
| 43,000 | |
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| Common Stockholder's Equity: |
|
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| |
|
| Common Stock |
| - |
|
| - |
|
| Capital Surplus, Paid In |
| 992,625 |
|
| 992,625 |
|
| Retained Earnings |
| 1,365,934 |
|
| 1,210,405 |
| Common Stockholder's Equity |
| 2,358,559 |
|
| 2,203,030 | |
Total Capitalization |
| 3,900,937 |
|
| 3,846,941 | ||
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Total Liabilities and Capitalization | $ | 7,162,132 |
| $ | 7,059,989 | ||
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The accompanying notes are an integral part of these unaudited condensed consolidated financial statements. |
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10
11
12
13
PUBLIC SERVICE COMPANY OF NEW HAMPSHIRE AND SUBSIDIARY |
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CONDENSED CONSOLIDATED BALANCE SHEETS |
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(Unaudited) |
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| September 30, |
| December 31, | ||
(Thousands of Dollars) | 2013 |
| 2012 | ||||
|
|
|
|
|
|
|
|
LIABILITIES AND CAPITALIZATION |
|
|
|
|
| ||
|
|
|
|
|
|
|
|
Current Liabilities: |
|
|
|
|
| ||
| Notes Payable to Affiliated Companies | $ | 228,500 |
| $ | 63,300 | |
| Long-Term Debt - Current Portion |
| 50,000 |
|
| - | |
| Accounts Payable |
| 60,814 |
|
| 62,864 | |
| Accounts Payable to Affiliated Companies |
| 18,279 |
|
| 21,337 | |
| Regulatory Liabilities |
| 23,394 |
|
| 23,002 | |
| Renewable Portfolio Standards Compliance Obligations |
| 6,701 |
|
| 17,383 | |
| Other Current Liabilities |
| 54,315 |
|
| 50,950 | |
Total Current Liabilities |
| 442,003 |
|
| 238,836 | ||
|
|
|
|
|
|
|
|
Rate Reduction Bonds |
| - |
|
| 29,294 | ||
|
|
|
|
|
|
|
|
Deferred Credits and Other Liabilities: |
|
|
|
|
| ||
| Accumulated Deferred Income Taxes |
| 490,863 |
|
| 441,577 | |
| Regulatory Liabilities |
| 52,867 |
|
| 52,418 | |
| Accrued Pension, SERP and PBOP |
| 104,557 |
|
| 220,129 | |
| Other Long-Term Liabilities |
| 43,866 |
|
| 47,896 | |
Total Deferred Credits and Other Liabilities |
| 692,153 |
|
| 762,020 | ||
|
|
|
|
|
|
|
|
Capitalization: |
|
|
|
|
| ||
| Long-Term Debt |
| 839,104 |
|
| 997,932 | |
|
|
|
|
|
|
|
|
| Common Stockholder's Equity: |
|
|
|
|
| |
|
| Common Stock |
| - |
|
| - |
|
| Capital Surplus, Paid In |
| 701,659 |
|
| 701,052 |
|
| Retained Earnings |
| 428,660 |
|
| 395,118 |
|
| Accumulated Other Comprehensive Loss |
| (8,833) |
|
| (9,655) |
| Common Stockholder's Equity |
| 1,121,486 |
|
| 1,086,515 | |
Total Capitalization |
| 1,960,590 |
|
| 2,084,447 | ||
|
|
|
|
|
|
|
|
Total Liabilities and Capitalization | $ | 3,094,746 |
| $ | 3,114,597 | ||
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
The accompanying notes are an integral part of these unaudited condensed consolidated financial statements. |
|
|
| ||||
14
15
16
17
WESTERN MASSACHUSETTS ELECTRIC COMPANY | |||||||
CONDENSED BALANCE SHEETS | |||||||
(Unaudited) | |||||||
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| September 30, |
| December 31, | ||
(Thousands of Dollars) | 2013 |
| 2012 | ||||
|
|
|
|
|
|
|
|
LIABILITIES AND CAPITALIZATION |
|
|
|
|
| ||
|
|
|
|
|
|
|
|
Current Liabilities: |
|
|
|
|
| ||
| Notes Payable to Affiliated Companies | $ | 79,800 |
| $ | 31,900 | |
| Long-Term Debt - Current Portion |
| - |
|
| 55,000 | |
| Accounts Payable |
| 40,432 |
|
| 68,141 | |
| Accounts Payable to Affiliated Companies |
| 7,521 |
|
| 7,103 | |
| Regulatory Liabilities |
| 22,400 |
|
| 21,037 | |
| Accumulated Deferred Income Taxes |
| 9,416 |
|
| 8,404 | |
| Other Current Liabilities |
| 18,718 |
|
| 24,809 | |
Total Current Liabilities |
| 178,287 |
|
| 216,394 | ||
|
|
|
|
|
|
|
|
Rate Reduction Bonds |
| - |
|
| 9,352 | ||
|
|
|
|
|
|
|
|
Deferred Credits and Other Liabilities: |
|
|
|
|
| ||
| Accumulated Deferred Income Taxes |
| 392,360 |
|
| 303,111 | |
| Regulatory Liabilities |
| 11,914 |
|
| 9,686 | |
| Accrued Pension, SERP and PBOP |
| 30,791 |
|
| 36,099 | |
| Other Long-Term Liabilities |
| 26,503 |
|
| 40,148 | |
Total Deferred Credits and Other Liabilities |
| 461,568 |
|
| 389,044 | ||
|
|
|
|
|
|
|
|
Capitalization: |
|
|
|
|
| ||
| Long-Term Debt |
| 549,617 |
|
| 550,270 | |
|
|
|
|
|
|
|
|
| Common Stockholder's Equity: |
|
|
|
|
| |
|
| Common Stock |
| 10,866 |
|
| 10,866 |
|
| Capital Surplus, Paid In |
| 390,645 |
|
| 390,412 |
|
| Retained Earnings |
| 180,618 |
|
| 160,577 |
|
| Accumulated Other Comprehensive Loss |
| (3,600) |
|
| (3,846) |
| Common Stockholder's Equity |
| 578,529 |
|
| 558,009 | |
Total Capitalization |
| 1,128,146 |
|
| 1,108,279 | ||
|
|
|
|
|
|
|
|
Total Liabilities and Capitalization | $ | 1,768,001 |
| $ | 1,723,069 | ||
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
The accompanying notes are an integral part of these unaudited condensed financial statements. |
|
|
| ||||
18
19
20
NORTHEAST UTILITIES AND SUBSIDIARIES
CONDENSED CONSOLIDATED BALANCE SHEETS
(Unaudited)
|
| March 31, |
| December 31, |
| ||
(Thousands of Dollars) |
| 2014 |
| 2013 |
| ||
|
|
|
|
|
| ||
LIABILITIES AND CAPITALIZATION |
|
|
|
|
| ||
|
|
|
|
|
| ||
Current Liabilities: |
|
|
|
|
| ||
Notes Payable |
| $ | 571,147 |
| $ | 1,093,000 |
|
Long-Term Debt - Current Portion |
| 530,533 |
| 533,346 |
| ||
Accounts Payable |
| 711,594 |
| 742,251 |
| ||
Regulatory Liabilities |
| 263,754 |
| 204,278 |
| ||
Other Current Liabilities |
| 713,116 |
| 702,776 |
| ||
Total Current Liabilities |
| 2,790,144 |
| 3,275,651 |
| ||
|
|
|
|
|
| ||
Deferred Credits and Other Liabilities: |
|
|
|
|
| ||
Accumulated Deferred Income Taxes |
| 4,209,969 |
| 4,029,026 |
| ||
Regulatory Liabilities |
| 591,468 |
| 502,984 |
| ||
Derivative Liabilities |
| 546,387 |
| 624,050 |
| ||
Accrued Pension, SERP and PBOP |
| 890,019 |
| 896,844 |
| ||
Other Long-Term Liabilities |
| 871,050 |
| 923,053 |
| ||
Total Deferred Credits and Other Liabilities |
| 7,108,893 |
| 6,975,957 |
| ||
|
|
|
|
|
| ||
Capitalization: |
|
|
|
|
| ||
Long-Term Debt |
| 8,318,332 |
| 7,776,833 |
| ||
|
|
|
|
|
| ||
Noncontrolling Interest - Preferred Stock of Subsidiaries |
| 155,568 |
| 155,568 |
| ||
|
|
|
|
|
| ||
Equity: |
|
|
|
|
| ||
Common Shareholders’ Equity: |
|
|
|
|
| ||
Common Shares |
| 1,666,580 |
| 1,665,351 |
| ||
Capital Surplus, Paid In |
| 6,185,027 |
| 6,192,765 |
| ||
Retained Earnings |
| 2,237,710 |
| 2,125,980 |
| ||
Accumulated Other Comprehensive Loss |
| (44,321 | ) | (46,031 | ) | ||
Treasury Stock |
| (321,063 | ) | (326,537 | ) | ||
Common Shareholders’ Equity |
| 9,723,933 |
| 9,611,528 |
| ||
Total Capitalization |
| 18,197,833 |
| 17,543,929 |
| ||
|
|
|
|
|
| ||
Total Liabilities and Capitalization |
| $ | 28,096,870 |
| $ | 27,795,537 |
|
The accompanying notes are an integral part of these unaudited condensed consolidated financial statements.
NORTHEAST UTILITIES AND SUBSIDIARIES
CONDENSED CONSOLIDATED STATEMENTS OF INCOME
(Unaudited)
|
| For the Three Months Ended March 31, |
| ||||
(Thousands of Dollars, Except Share Information) |
| 2014 |
| 2013 |
| ||
|
|
|
|
|
| ||
Operating Revenues |
| $ | 2,290,590 |
| $ | 1,995,023 |
|
|
|
|
|
|
| ||
Operating Expenses: |
|
|
|
|
| ||
Purchased Power, Fuel and Transmission |
| 978,150 |
| 747,809 |
| ||
Operations and Maintenance |
| 351,688 |
| 346,092 |
| ||
Depreciation |
| 150,807 |
| 154,977 |
| ||
Amortization of Regulatory Assets, Net |
| 57,898 |
| 54,049 |
| ||
Amortization of Rate Reduction Bonds |
| — |
| 34,499 |
| ||
Energy Efficiency Programs |
| 138,825 |
| 105,771 |
| ||
Taxes Other Than Income Taxes |
| 145,533 |
| 132,881 |
| ||
Total Operating Expenses |
| 1,822,901 |
| 1,576,078 |
| ||
Operating Income |
| 467,689 |
| 418,945 |
| ||
|
|
|
|
|
| ||
Interest Expense: |
|
|
|
|
| ||
Interest on Long-Term Debt |
| 87,377 |
| 85,906 |
| ||
Other Interest |
| 2,598 |
| (9,651 | ) | ||
Interest Expense |
| 89,975 |
| 76,255 |
| ||
Other Income, Net |
| 1,667 |
| 7,765 |
| ||
Income Before Income Tax Expense |
| 379,381 |
| 350,455 |
| ||
Income Tax Expense |
| 141,545 |
| 120,487 |
| ||
Net Income |
| 237,836 |
| 229,968 |
| ||
Net Income Attributable to Noncontrolling Interests |
| 1,879 |
| 1,879 |
| ||
Net Income Attributable to Controlling Interest |
| $ | 235,957 |
| $ | 228,089 |
|
|
|
|
|
|
| ||
Basic Earnings Per Common Share |
| $ | 0.75 |
| $ | 0.72 |
|
|
|
|
|
|
| ||
Diluted Earnings Per Common Share |
| $ | 0.74 |
| $ | 0.72 |
|
|
|
|
|
|
| ||
Dividends Declared Per Common Share |
| $ | 0.39 |
| $ | 0.37 |
|
|
|
|
|
|
| ||
Weighted Average Common Shares Outstanding: |
|
|
|
|
| ||
Basic |
| 315,534,512 |
| 315,129,782 |
| ||
Diluted |
| 316,892,119 |
| 316,002,538 |
| ||
The accompanying notes are an integral part of these unaudited condensed consolidated financial statements.
CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME
(Unaudited)
Net Income |
| $ | 237,836 |
| $ | 229,968 |
|
Other Comprehensive Income, Net of Tax: |
|
|
|
|
| ||
Qualified Cash Flow Hedging Instruments |
| 509 |
| 516 |
| ||
Changes in Unrealized Gains/(Losses) on Other Securities |
| 240 |
| (181 | ) | ||
Changes in Funded Status of Pension, SERP and PBOP Benefit Plans |
| 961 |
| 1,621 |
| ||
Other Comprehensive Income, Net of Tax |
| 1,710 |
| 1,956 |
| ||
Comprehensive Income Attributable to Noncontrolling Interests |
| (1,879 | ) | (1,879 | ) | ||
Comprehensive Income Attributable to Controlling Interest |
| $ | 237,667 |
| $ | 230,045 |
|
The accompanying notes are an integral part of these unaudited condensed consolidated financial statements.
NORTHEAST UTILITIES AND SUBSIDIARIES
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS
(Unaudited)
|
| For the Three Months Ended March 31, |
| ||||
(Thousands of Dollars) |
| 2014 |
| 2013 |
| ||
|
|
|
|
|
| ||
Operating Activities: |
|
|
|
|
| ||
Net Income |
| $ | 237,836 |
| $ | 229,968 |
|
Adjustments to Reconcile Net Income to Net Cash Flows Provided by Operating Activities: |
|
|
|
|
| ||
Depreciation |
| 150,807 |
| 154,977 |
| ||
Deferred Income Taxes |
| 137,417 |
| 168,938 |
| ||
Pension, SERP and PBOP Expense |
| 24,995 |
| 53,102 |
| ||
Pension and PBOP Contributions |
| (6,622 | ) | (47,048 | ) | ||
Regulatory Overrecoveries, Net |
| 872 |
| 39,218 |
| ||
Amortization of Regulatory Assets, Net |
| 57,898 |
| 54,049 |
| ||
Amortization of Rate Reduction Bonds |
| — |
| 34,499 |
| ||
Proceeds from DOE Damages Claim |
| 163,300 |
| 77,936 |
| ||
Deferred DOE Proceeds |
| (163,300 | ) | — |
| ||
Other |
| (7,574 | ) | (51,106 | ) | ||
Changes in Current Assets and Liabilities: |
|
|
|
|
| ||
Receivables and Unbilled Revenues, Net |
| (182,221 | ) | (129,431 | ) | ||
Fuel, Materials and Supplies |
| 75,041 |
| 28,487 |
| ||
Taxes Receivable/Accrued, Net |
| (59,840 | ) | (21,295 | ) | ||
Accounts Payable |
| 53,905 |
| (86,916 | ) | ||
Other Current Assets and Liabilities, Net |
| 11,282 |
| (32,235 | ) | ||
Net Cash Flows Provided by Operating Activities |
| 493,796 |
| 473,143 |
| ||
|
|
|
|
|
| ||
Investing Activities: |
|
|
|
|
| ||
Investments in Property, Plant and Equipment |
| (348,691 | ) | (388,950 | ) | ||
Proceeds from Sales of Marketable Securities |
| 128,505 |
| 98,070 |
| ||
Purchases of Marketable Securities |
| (132,605 | ) | (184,030 | ) | ||
Other Investing Activities |
| 1,637 |
| 27,997 |
| ||
Net Cash Flows Used in Investing Activities |
| (351,154 | ) | (446,913 | ) | ||
|
|
|
|
|
| ||
Financing Activities: |
|
|
|
|
| ||
Cash Dividends on Common Shares |
| (118,460 | ) | (116,431 | ) | ||
Cash Dividends on Preferred Stock |
| (1,879 | ) | (1,879 | ) | ||
Decrease in Short-Term Debt |
| (299,500 | ) | (228,000 | ) | ||
Issuance of Long-Term Debt |
| 400,000 |
| 400,000 |
| ||
Retirements of Long-Term Debt |
| (75,000 | ) | — |
| ||
Retirements of Rate Reduction Bonds |
| — |
| (62,529 | ) | ||
Other Financing Activities |
| (2,017 | ) | (2,322 | ) | ||
Net Cash Flows Used in Financing Activities |
| (96,856 | ) | (11,161 | ) | ||
Net Increase in Cash and Cash Equivalents |
| 45,786 |
| 15,069 |
| ||
Cash and Cash Equivalents - Beginning of Period |
| 43,364 |
| 45,748 |
| ||
Cash and Cash Equivalents - End of Period |
| $ | 89,150 |
| $ | 60,817 |
|
The accompanying notes are an integral part of these unaudited condensed consolidated financial statements.
THE CONNECTICUT LIGHT AND POWER COMPANY
(Unaudited)
|
| March 31, |
| December 31, |
| ||
(Thousands of Dollars) |
| 2014 |
| 2013 |
| ||
|
|
|
|
|
| ||
ASSETS |
|
|
|
|
| ||
|
|
|
|
|
| ||
Current Assets: |
|
|
|
|
| ||
Cash |
| $ | 15,675 |
| $ | 7,237 |
|
Receivables, Net |
| 386,876 |
| 319,670 |
| ||
Accounts Receivable from Affiliated Companies |
| 14,721 |
| 13,777 |
| ||
Unbilled Revenues |
| 98,095 |
| 92,401 |
| ||
Regulatory Assets |
| 175,926 |
| 150,943 |
| ||
Materials and Supplies |
| 51,376 |
| 54,606 |
| ||
Prepayments and Other Current Assets |
| 73,602 |
| 53,082 |
| ||
Total Current Assets |
| 816,271 |
| 691,716 |
| ||
|
|
|
|
|
| ||
Property, Plant and Equipment, Net |
| 6,506,245 |
| 6,451,259 |
| ||
|
|
|
|
|
| ||
Deferred Debits and Other Assets: |
|
|
|
|
| ||
Regulatory Assets |
| 1,580,609 |
| 1,663,147 |
| ||
Other Long-Term Assets |
| 170,814 |
| 174,380 |
| ||
Total Deferred Debits and Other Assets |
| 1,751,423 |
| 1,837,527 |
| ||
|
|
|
|
|
| ||
Total Assets |
| $ | 9,073,939 |
| $ | 8,980,502 |
|
The accompanying notes are an integral part of these unaudited condensed financial statements.
THE CONNECTICUT LIGHT AND POWER COMPANY
(Unaudited)
|
| March 31, |
| December 31, |
| ||
(Thousands of Dollars) |
| 2014 |
| 2013 |
| ||
|
|
|
|
|
| ||
LIABILITIES AND CAPITALIZATION |
|
|
|
|
| ||
|
|
|
|
|
| ||
Current Liabilities: |
|
|
|
|
| ||
Notes Payable to NU Parent |
| $ | 351,600 |
| $ | 287,300 |
|
Long-Term Debt - Current Portion |
| 150,000 |
| 150,000 |
| ||
Accounts Payable |
| 186,792 |
| 201,047 |
| ||
Accounts Payable to Affiliated Companies |
| 52,760 |
| 56,531 |
| ||
Obligations to Third Party Suppliers |
| 76,236 |
| 73,914 |
| ||
Regulatory Liabilities |
| 107,284 |
| 93,961 |
| ||
Derivative Liabilities |
| 92,040 |
| 92,233 |
| ||
Other Current Liabilities |
| 154,312 |
| 134,716 |
| ||
Total Current Liabilities |
| 1,171,024 |
| 1,089,702 |
| ||
|
|
|
|
|
| ||
Deferred Credits and Other Liabilities: |
|
|
|
|
| ||
Accumulated Deferred Income Taxes |
| 1,579,498 |
| 1,510,586 |
| ||
Regulatory Liabilities |
| 90,053 |
| 93,757 |
| ||
Derivative Liabilities |
| 539,444 |
| 617,072 |
| ||
Accrued Pension, SERP and PBOP |
| 94,820 |
| 95,895 |
| ||
Other Long-Term Liabilities |
| 152,920 |
| 163,588 |
| ||
Total Deferred Credits and Other Liabilities |
| 2,456,735 |
| 2,480,898 |
| ||
|
|
|
|
|
| ||
Capitalization: |
|
|
|
|
| ||
Long-Term Debt |
| 2,591,405 |
| 2,591,208 |
| ||
|
|
|
|
|
| ||
Preferred Stock Not Subject to Mandatory Redemption |
| 116,200 |
| 116,200 |
| ||
|
|
|
|
|
| ||
Common Stockholder’s Equity: |
|
|
|
|
| ||
Common Stock |
| 60,352 |
| 60,352 |
| ||
Capital Surplus, Paid In |
| 1,682,900 |
| 1,682,047 |
| ||
Retained Earnings |
| 996,591 |
| 961,482 |
| ||
Accumulated Other Comprehensive Loss |
| (1,268 | ) | (1,387 | ) | ||
Common Stockholder’s Equity |
| 2,738,575 |
| 2,702,494 |
| ||
Total Capitalization |
| 5,446,180 |
| 5,409,902 |
| ||
|
|
|
|
|
| ||
Total Liabilities and Capitalization |
| $ | 9,073,939 |
| $ | 8,980,502 |
|
The accompanying notes are an integral part of these unaudited condensed financial statements.
THE CONNECTICUT LIGHT AND POWER COMPANY
CONDENSED STATEMENTS OF INCOME
(Unaudited)
|
| For the Three Months Ended March 31, |
| ||||
(Thousands of Dollars) |
| 2014 |
| 2013 |
| ||
|
|
|
|
|
| ||
Operating Revenues |
| $ | 734,614 |
| $ | 624,097 |
|
|
|
|
|
|
| ||
Operating Expenses: |
|
|
|
|
| ||
Purchased Power and Transmission |
| 281,381 |
| 229,259 |
| ||
Operations and Maintenance |
| 109,514 |
| 108,895 |
| ||
Depreciation |
| 46,130 |
| 42,448 |
| ||
Amortization of Regulatory Assets, Net |
| 29,931 |
| 10,787 |
| ||
Energy Efficiency Programs |
| 42,694 |
| 22,813 |
| ||
Taxes Other Than Income Taxes |
| 66,953 |
| 60,192 |
| ||
Total Operating Expenses |
| 576,603 |
| 474,394 |
| ||
Operating Income |
| 158,011 |
| 149,703 |
| ||
|
|
|
|
|
| ||
Interest Expense: |
|
|
|
|
| ||
Interest on Long-Term Debt |
| 32,908 |
| 32,635 |
| ||
Other Interest |
| 1,335 |
| (2,941 | ) | ||
Interest Expense |
| 34,243 |
| 29,694 |
| ||
Other Income, Net |
| 1,072 |
| 4,187 |
| ||
Income Before Income Tax Expense |
| 124,840 |
| 124,196 |
| ||
Income Tax Expense |
| 45,541 |
| 39,188 |
| ||
Net Income |
| $ | 79,299 |
| $ | 85,008 |
|
The accompanying notes are an integral part of these unaudited condensed financial statements.
CONDENSED STATEMENTS OF COMPREHENSIVE INCOME
(Unaudited)
Net Income |
| $ | 79,299 |
| $ | 85,008 |
|
Other Comprehensive Income, Net of Tax: |
|
|
|
|
| ||
Qualified Cash Flow Hedging Instruments |
| 111 |
| 111 |
| ||
Changes in Unrealized Gains/(Losses) on Other Securities |
| 8 |
| (6 | ) | ||
Other Comprehensive Income, Net of Tax |
| 119 |
| 105 |
| ||
Comprehensive Income |
| $ | 79,418 |
| $ | 85,113 |
|
The accompanying notes are an integral part of these unaudited condensed financial statements.
THE CONNECTICUT LIGHT AND POWER COMPANY
CONDENSED STATEMENTS OF CASH FLOWS
(Unaudited)
|
| For the Three Months Ended March 31, |
| ||||
(Thousands of Dollars) |
| 2014 |
| 2013 |
| ||
|
|
|
|
|
| ||
Operating Activities: |
|
|
|
|
| ||
Net Income |
| $ | 79,299 |
| $ | 85,008 |
|
Adjustments to Reconcile Net Income to Net Cash Flows Provided by Operating Activities: |
|
|
|
|
| ||
Depreciation |
| 46,130 |
| 42,448 |
| ||
Deferred Income Taxes |
| 59,334 |
| 65,475 |
| ||
Pension, SERP and PBOP Expense, Net of PBOP Contributions |
| 4,086 |
| 8,183 |
| ||
Regulatory Underrecoveries, Net |
| (40,399 | ) | (15,835 | ) | ||
Amortization of Regulatory Assets, Net |
| 29,931 |
| 10,787 |
| ||
Other |
| 4,536 |
| 3,653 |
| ||
Changes in Current Assets and Liabilities: |
|
|
|
|
| ||
Receivables and Unbilled Revenues, Net |
| (82,833 | ) | (32,041 | ) | ||
Taxes Receivable/Accrued, Net |
| 7,015 |
| (12,777 | ) | ||
Accounts Payable |
| (2,872 | ) | (106,140 | ) | ||
Other Current Assets and Liabilities, Net |
| (8,730 | ) | (22,340 | ) | ||
Net Cash Flows Provided by Operating Activities |
| 95,497 |
| 26,421 |
| ||
|
|
|
|
|
| ||
Investing Activities: |
|
|
|
|
| ||
Investments in Property, Plant and Equipment |
| (107,993 | ) | (89,360 | ) | ||
Other Investing Activities |
| 1,027 |
| 447 |
| ||
Net Cash Flows Used in Investing Activities |
| (106,966 | ) | (88,913 | ) | ||
|
|
|
|
|
| ||
Financing Activities: |
|
|
|
|
| ||
Cash Dividends on Common Stock |
| (42,800 | ) | (38,000 | ) | ||
Cash Dividends on Preferred Stock |
| (1,390 | ) | (1,390 | ) | ||
Issuance of Long Term Debt |
| — |
| 400,000 |
| ||
Increase/(Decrease) in Notes Payable to NU Parent |
| 64,300 |
| (194,700 | ) | ||
Decrease in Short-Term Debt |
| — |
| (89,000 | ) | ||
Other Financing Activities |
| (203 | ) | (6,112 | ) | ||
Net Cash Flows Provided by Financing Activities |
| 19,907 |
| 70,798 |
| ||
Net Increase in Cash |
| 8,438 |
| 8,306 |
| ||
Cash - Beginning of Period |
| 7,237 |
| 1 |
| ||
Cash - End of Period |
| $ | 15,675 |
| $ | 8,307 |
|
The accompanying notes are an integral part of these unaudited condensed financial statements.
NSTAR ELECTRIC COMPANY AND SUBSIDIARY
CONDENSED CONSOLIDATED BALANCE SHEETS
(Unaudited)
|
| March 31, |
| December 31, |
| ||
(Thousands of Dollars) |
| 2014 |
| 2013 |
| ||
|
|
|
|
|
| ||
ASSETS |
|
|
|
|
| ||
|
|
|
|
|
| ||
Current Assets: |
|
|
|
|
| ||
Cash and Cash Equivalents |
| $ | 42,035 |
| $ | 8,021 |
|
Receivables, Net |
| 231,082 |
| 209,711 |
| ||
Accounts Receivable from Affiliated Companies |
| 123,953 |
| 27,264 |
| ||
Unbilled Revenues |
| 28,249 |
| 41,368 |
| ||
Materials and Supplies |
| 47,843 |
| 44,236 |
| ||
Regulatory Assets |
| 222,598 |
| 204,144 |
| ||
Prepayments and Other Current Assets |
| 5,686 |
| 36,710 |
| ||
Total Current Assets |
| 701,446 |
| 571,454 |
| ||
|
|
|
|
|
| ||
Property, Plant and Equipment, Net |
| 5,069,203 |
| 5,043,887 |
| ||
|
|
|
|
|
| ||
Deferred Debits and Other Assets: |
|
|
|
|
| ||
Regulatory Assets |
| 1,041,925 |
| 1,235,156 |
| ||
Other Long-Term Assets |
| 65,983 |
| 60,624 |
| ||
Total Deferred Debits and Other Assets |
| 1,107,908 |
| 1,295,780 |
| ||
|
|
|
|
|
| ||
Total Assets |
| $ | 6,878,557 |
| $ | 6,911,121 |
|
The accompanying notes are an integral part of these unaudited condensed consolidated financial statements.
NSTAR ELECTRIC COMPANY AND SUBSIDIARY
CONDENSED CONSOLIDATED BALANCE SHEETS
(Unaudited)
|
| March 31, |
| December 31, |
| ||
(Thousands of Dollars) |
| 2014 |
| 2013 |
| ||
|
|
|
|
|
| ||
LIABILITIES AND CAPITALIZATION |
|
|
|
|
| ||
|
|
|
|
|
| ||
Current Liabilities: |
|
|
|
|
| ||
Notes Payable |
| $ | — |
| $ | 103,500 |
|
Long-Term Debt - Current Portion |
| 301,650 |
| 301,650 |
| ||
Accounts Payable |
| 264,834 |
| 207,559 |
| ||
Accounts Payable to Affiliated Companies |
| 42,879 |
| 75,707 |
| ||
Accumulated Deferred Income Taxes |
| 55,763 |
| 50,128 |
| ||
Regulatory Liabilities |
| 73,596 |
| 53,958 |
| ||
Other Current Liabilities |
| 140,146 |
| 118,410 |
| ||
Total Current Liabilities |
| 878,868 |
| 910,912 |
| ||
|
|
|
|
|
| ||
Deferred Credits and Other Liabilities: |
|
|
|
|
| ||
Accumulated Deferred Income Taxes |
| 1,400,532 |
| 1,466,835 |
| ||
Regulatory Liabilities |
| 257,101 |
| 253,108 |
| ||
Accrued Pension, SERP and PBOP |
| 150,938 |
| 118,010 |
| ||
Payable to Affiliated Companies |
| — |
| 64,172 |
| ||
Other Long-Term Liabilities |
| 132,679 |
| 142,214 |
| ||
Total Deferred Credits and Other Liabilities |
| 1,941,250 |
| 2,044,339 |
| ||
|
|
|
|
|
| ||
Capitalization: |
|
|
|
|
| ||
Long-Term Debt |
| 1,797,389 |
| 1,499,417 |
| ||
|
|
|
|
|
| ||
Preferred Stock Not Subject to Mandatory Redemption |
| 43,000 |
| 43,000 |
| ||
|
|
|
|
|
| ||
Common Stockholder’s Equity: |
|
|
|
|
| ||
Common Stock |
| — |
| — |
| ||
Capital Surplus, Paid In |
| 992,625 |
| 992,625 |
| ||
Retained Earnings |
| 1,225,425 |
| 1,420,828 |
| ||
Common Stockholder’s Equity |
| 2,218,050 |
| 2,413,453 |
| ||
Total Capitalization |
| 4,058,439 |
| 3,955,870 |
| ||
|
|
|
|
|
| ||
Total Liabilities and Capitalization |
| $ | 6,878,557 |
| $ | 6,911,121 |
|
The accompanying notes are an integral part of these unaudited condensed consolidated financial statements.
NSTAR ELECTRIC COMPANY AND SUBSIDIARY
CONDENSED CONSOLIDATED STATEMENTS OF INCOME
(Unaudited)
|
| For the Three Months Ended March 31, |
| ||||
(Thousands of Dollars) |
| 2014 |
| 2013 |
| ||
|
|
|
|
|
| ||
Operating Revenues |
| $ | 666,188 |
| $ | 592,257 |
|
|
|
|
|
|
| ||
Operating Expenses: |
|
|
|
|
| ||
Purchased Power and Transmission |
| 319,082 |
| 214,053 |
| ||
Operations and Maintenance |
| 85,924 |
| 92,301 |
| ||
Depreciation |
| 46,626 |
| 45,441 |
| ||
Amortization of Regulatory Assets, Net |
| 15,664 |
| 46,994 |
| ||
Amortization of Rate Reduction Bonds |
| — |
| 15,054 |
| ||
Energy Efficiency Programs |
| 48,329 |
| 51,703 |
| ||
Taxes Other Than Income Taxes |
| 32,151 |
| 32,174 |
| ||
Total Operating Expenses |
| 547,776 |
| 497,720 |
| ||
Operating Income |
| 118,412 |
| 94,537 |
| ||
|
|
|
|
|
| ||
Interest Expense: |
|
|
|
|
| ||
Interest on Long-Term Debt |
| 20,756 |
| 19,991 |
| ||
Other Interest |
| 304 |
| (4,068 | ) | ||
Interest Expense |
| 21,060 |
| 15,923 |
| ||
Other Income/(Loss), Net |
| (31 | ) | 773 |
| ||
Income Before Income Tax Expense |
| 97,321 |
| 79,387 |
| ||
Income Tax Expense |
| 39,234 |
| 31,265 |
| ||
Net Income |
| $ | 58,087 |
| $ | 48,122 |
|
The accompanying notes are an integral part of these unaudited condensed consolidated financial statements.
NSTAR ELECTRIC COMPANY AND SUBSIDIARY
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS
(Unaudited)
|
| For the Three Months Ended March 31, |
| ||||
(Thousands of Dollars) |
| 2014 |
| 2013 |
| ||
|
|
|
|
|
| ||
Operating Activities, SERP: |
|
|
|
|
| ||
Net Income |
| $ | 58,087 |
| $ | 48,122 |
|
Adjustments to Reconcile Net Income to Net Cash Flows Provided by Operating Activities: |
|
|
|
|
| ||
Depreciation |
| 46,626 |
| 45,441 |
| ||
Deferred Income Taxes |
| 1,585 |
| 26,571 |
| ||
Pension, SERP and PBOP Expense, Net of Contributions |
| (4,908 | ) | 6,420 |
| ||
Regulatory Underrecoveries, Net |
| 6,423 |
| (2,951 | ) | ||
Amortization of Regulatory Assets, Net |
| 15,664 |
| 46,994 |
| ||
Amortization of Rate Reduction Bonds |
| — |
| 15,054 |
| ||
Bad Debt Expense |
| 6,096 |
| 5,523 |
| ||
Other |
| (15,538 | ) | (23,969 | ) | ||
Changes in Current Assets and Liabilities: |
|
|
|
|
| ||
Receivables and Unbilled Revenues, Net |
| (14,348 | ) | (31,455 | ) | ||
Materials and Supplies |
| (3,606 | ) | (7,060 | ) | ||
Taxes Receivable/Accrued, Net |
| 21,504 |
| (22,501 | ) | ||
Accounts Payable |
| 86,309 |
| 1,867 |
| ||
Accounts Receivable from/Payable to Affiliates, Net |
| (43,654 | ) | (37,547 | ) | ||
Other Current Assets and Liabilities, Net |
| 31,112 |
| 18,916 |
| ||
Net Cash Flows Provided by Operating Activities |
| 191,352 |
| 89,425 |
| ||
|
|
|
|
|
| ||
Investing Activities: |
|
|
|
|
| ||
Investments in Property, Plant and Equipment |
| (94,957 | ) | (107,573 | ) | ||
(Increase)/Decrease in Special Deposits |
| (530 | ) | 33,631 |
| ||
Other Investing Activities |
| 41 |
| (86 | ) | ||
Net Cash Flows Used in Investing Activities |
| (95,446 | ) | (74,028 | ) | ||
|
|
|
|
|
| ||
Financing Activities: |
|
|
|
|
| ||
Cash Dividends on Common Stock |
| (253,000 | ) | — |
| ||
Cash Dividends on Preferred Stock |
| (490 | ) | (490 | ) | ||
(Decrease)/Increase in Notes Payable |
| (103,500 | ) | 32,000 |
| ||
Issuance of Long-Term Debt |
| 300,000 |
| — |
| ||
Retirements of Rate Reduction Bonds |
| — |
| (43,493 | ) | ||
Other Financing Activities |
| (4,902 | ) | — |
| ||
Net Cash Flows Used in Financing Activities |
| (61,892 | ) | (11,983 | ) | ||
Net Increase in Cash and Cash Equivalents |
| 34,014 |
| 3,414 |
| ||
Cash and Cash Equivalents - Beginning of Period |
| 8,021 |
| 13,695 |
| ||
Cash and Cash Equivalents - End of Period |
| $ | 42,035 |
| $ | 17,109 |
|
The accompanying notes are an integral part of these unaudited condensed consolidated financial statements.
PUBLIC SERVICE COMPANY OF NEW HAMPSHIRE AND SUBSIDIARY
CONDENSED CONSOLIDATED BALANCE SHEETS
(Unaudited)
|
| March 31, |
| December 31, |
| ||
(Thousands of Dollars) |
| 2014 |
| 2013 |
| ||
|
|
|
|
|
| ||
ASSETS |
|
|
|
|
| ||
|
|
|
|
|
| ||
Current Assets: |
|
|
|
|
| ||
Cash |
| $ | 4,284 |
| $ | 130 |
|
Receivables, Net |
| 88,143 |
| 76,331 |
| ||
Accounts Receivable from Affiliated Companies |
| 479 |
| 90 |
| ||
Unbilled Revenues |
| 38,327 |
| 38,344 |
| ||
Taxes Receivable |
| 20,968 |
| 2,180 |
| ||
Fuel, Materials and Supplies |
| 94,410 |
| 128,736 |
| ||
Regulatory Assets |
| 83,832 |
| 92,194 |
| ||
Prepayments and Other Current Assets |
| 7,270 |
| 21,920 |
| ||
Total Current Assets |
| 337,713 |
| 359,925 |
| ||
|
|
|
|
|
| ||
Property, Plant and Equipment, Net |
| 2,486,440 |
| 2,467,556 |
| ||
|
|
|
|
|
| ||
Deferred Debits and Other Assets: |
|
|
|
|
| ||
Regulatory Assets |
| 210,702 |
| 219,346 |
| ||
Other Long-Term Assets |
| 40,621 |
| 39,891 |
| ||
Total Deferred Debits and Other Assets |
| 251,323 |
| 259,237 |
| ||
|
|
|
|
|
| ||
Total Assets |
| $ | 3,075,476 |
| $ | 3,086,718 |
|
The accompanying notes are an integral part of these unaudited condensed consolidated financial statements.
PUBLIC SERVICE COMPANY OF NEW HAMPSHIRE AND SUBSIDIARY
CONDENSED CONSOLIDATED BALANCE SHEETS
(Unaudited)
|
| March 31, |
| December 31, |
| ||
(Thousands of Dollars) |
| 2014 |
| 2013 |
| ||
|
|
|
|
|
| ||
LIABILITIES AND CAPITALIZATION |
|
|
|
|
| ||
|
|
|
|
|
| ||
Current Liabilities: |
|
|
|
|
| ||
Notes Payable to NU Parent |
| $ | 39,900 |
| $ | 86,500 |
|
Long-Term Debt - Current Portion |
| 50,000 |
| 50,000 |
| ||
Accounts Payable |
| 59,847 |
| 82,920 |
| ||
Accounts Payable to Affiliated Companies |
| 28,009 |
| 22,040 |
| ||
Regulatory Liabilities |
| 27,333 |
| 20,643 |
| ||
Accumulated Deferred Income Taxes |
| 22,811 |
| 28,596 |
| ||
Other Current Liabilities |
| 46,880 |
| 51,729 |
| ||
Total Current Liabilities |
| 274,780 |
| 342,428 |
| ||
|
|
|
|
|
| ||
Deferred Credits and Other Liabilities: |
|
|
|
|
| ||
Accumulated Deferred Income Taxes |
| 539,255 |
| 500,166 |
| ||
Regulatory Liabilities |
| 51,769 |
| 51,723 |
| ||
Accrued SERP and PBOP |
| 15,321 |
| 15,272 |
| ||
Other Long-Term Liabilities |
| 46,559 |
| 46,247 |
| ||
Total Deferred Credits and Other Liabilities |
| 652,904 |
| 613,408 |
| ||
|
|
|
|
|
| ||
Capitalization: |
|
|
|
|
| ||
Long-Term Debt |
| 999,081 |
| 999,006 |
| ||
|
|
|
|
|
| ||
Common Stockholder’s Equity: |
|
|
|
|
| ||
Common Stock |
| — |
| — |
| ||
Capital Surplus, Paid In |
| 702,304 |
| 701,911 |
| ||
Retained Earnings |
| 454,653 |
| 438,515 |
| ||
Accumulated Other Comprehensive Loss |
| (8,246 | ) | (8,550 | ) | ||
Common Stockholder’s Equity |
| 1,148,711 |
| 1,131,876 |
| ||
Total Capitalization |
| 2,147,792 |
| 2,130,882 |
| ||
|
|
|
|
|
| ||
Total Liabilities and Capitalization |
| $ | 3,075,476 |
| $ | 3,086,718 |
|
The accompanying notes are an integral part of these unaudited condensed consolidated financial statements.
PUBLIC SERVICE COMPANY OF NEW HAMPSHIRE AND SUBSIDIARY
CONDENSED CONSOLIDATED STATEMENTS OF INCOME
(Unaudited)
|
| For the Three Months Ended March 31, |
| ||||
(Thousands of Dollars) |
| 2014 |
| 2013 |
| ||
|
|
|
|
|
| ||
Operating Revenues |
| $ | 299,833 |
| $ | 273,829 |
|
|
|
|
|
|
| ||
Operating Expenses: |
|
|
|
|
| ||
Purchased Power, Fuel and Transmission |
| 115,246 |
| 101,024 |
| ||
Operations and Maintenance |
| 62,212 |
| 59,729 |
| ||
Depreciation |
| 24,215 |
| 22,568 |
| ||
Amortization of Regulatory Assets/(Liabilities), Net |
| 12,562 |
| (3,051 | ) | ||
Amortization of Rate Reduction Bonds |
| — |
| 14,756 |
| ||
Energy Efficiency Programs |
| 3,839 |
| 3,669 |
| ||
Taxes Other Than Income Taxes |
| 17,715 |
| 17,016 |
| ||
Total Operating Expenses |
| 235,789 |
| 215,711 |
| ||
Operating Income |
| 64,044 |
| 58,118 |
| ||
|
|
|
|
|
| ||
Interest Expense: |
|
|
|
|
| ||
Interest on Long-Term Debt |
| 11,526 |
| 11,881 |
| ||
Other Interest |
| 445 |
| 287 |
| ||
Interest Expense |
| 11,971 |
| 12,168 |
| ||
Other Income, Net |
| 265 |
| 1,030 |
| ||
Income Before Income Tax Expense |
| 52,338 |
| 46,980 |
| ||
Income Tax Expense |
| 19,700 |
| 17,984 |
| ||
Net Income |
| $ | 32,638 |
| $ | 28,996 |
|
The accompanying notes are an integral part of these unaudited condensed consolidated financial statements.
CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME
(Unaudited)
Net Income |
| $ | 32,638 |
| $ | 28,996 |
|
Other Comprehensive Income, Net of Tax: |
|
|
|
|
| ||
Qualified Cash Flow Hedging Instruments |
| 290 |
| 291 |
| ||
Changes in Unrealized Gains/(Losses) on Other Securities |
| 14 |
| (11 | ) | ||
Changes in Funded Status of Pension, SERP and PBOP Benefit Plans |
| — |
| (3 | ) | ||
Other Comprehensive Income, Net of Tax |
| 304 |
| 277 |
| ||
Comprehensive Income |
| $ | 32,942 |
| $ | 29,273 |
|
The accompanying notes are an integral part of these unaudited condensed consolidated financial statements.
PUBLIC SERVICE COMPANY OF NEW HAMPSHIRE AND SUBSIDIARY
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS
(Unaudited)
|
| For the Three Months Ended March 31, |
| ||||
(Thousands of Dollars) |
| 2014 |
| 2013 |
| ||
|
|
|
|
|
| ||
Operating Activities: |
|
|
|
|
| ||
Net Income |
| $ | 32,638 |
| $ | 28,996 |
|
Adjustments to Reconcile Net Income to Net Cash Flows Provided by Operating Activities: |
|
|
|
|
| ||
Depreciation |
| 24,215 |
| 22,568 |
| ||
Deferred Income Taxes |
| 33,667 |
| 10,143 |
| ||
Pension, SERP and PBOP Expense |
| 1,961 |
| 8,022 |
| ||
Pension and PBOP Contributions |
| (30 | ) | (35,146 | ) | ||
Regulatory Over/(Under) Recoveries, Net |
| 6,827 |
| (799 | ) | ||
Amortization of Regulatory Assets/(Liabilities), Net |
| 12,562 |
| (3,051 | ) | ||
Amortization of Rate Reduction Bonds |
| — |
| 14,756 |
| ||
Other |
| 2,729 |
| (1,505 | ) | ||
Changes in Current Assets and Liabilities: |
|
|
|
|
| ||
Receivables and Unbilled Revenues, Net |
| (14,268 | ) | (13,889 | ) | ||
Fuel, Materials and Supplies |
| 34,326 |
| 562 |
| ||
Taxes Receivable/Accrued, Net |
| (30,254 | ) | 23,137 |
| ||
Accounts Payable |
| 3,403 |
| 31,257 |
| ||
Other Current Assets and Liabilities, Net |
| 21,505 |
| 22,152 |
| ||
Net Cash Flows Provided by Operating Activities |
| 129,281 |
| 107,203 |
| ||
|
|
|
|
|
| ||
Investing Activities: |
|
|
|
|
| ||
Investments in Property, Plant and Equipment |
| (61,864 | ) | (64,956 | ) | ||
Other Investing Activities |
| (76 | ) | (17 | ) | ||
Net Cash Flows Used in Investing Activities |
| (61,940 | ) | (64,973 | ) | ||
|
|
|
|
|
| ||
Financing Activities: |
|
|
|
|
| ||
Cash Dividends on Common Stock |
| (16,500 | ) | (17,000 | ) | ||
Decrease in Notes Payable to NU Parent |
| (46,600 | ) | (9,900 | ) | ||
Retirements of Rate Reduction Bonds |
| — |
| (14,320 | ) | ||
Other Financing Activities |
| (87 | ) | (127 | ) | ||
Net Cash Flows Used in Financing Activities |
| (63,187 | ) | (41,347 | ) | ||
Net Increase in Cash |
| 4,154 |
| 883 |
| ||
Cash - Beginning of Period |
| 130 |
| 2,493 |
| ||
Cash - End of Period |
| $ | 4,284 |
| $ | 3,376 |
|
The accompanying notes are an integral part of these unaudited condensed consolidated financial statements.
WESTERN MASSACHUSETTS ELECTRIC COMPANY
(Unaudited)
|
| March 31, |
| December 31, |
| ||
(Thousands of Dollars) |
| 2014 |
| 2013 |
| ||
|
|
|
|
|
| ||
ASSETS |
|
|
|
|
| ||
|
|
|
|
|
| ||
Current Assets: |
|
|
|
|
| ||
Cash |
| $ | 4,227 |
| $ | — |
|
Receivables, Net |
| 54,844 |
| 49,018 |
| ||
Accounts Receivable from Affiliated Companies |
| 5,996 |
| 47,607 |
| ||
Unbilled Revenues |
| 16,531 |
| 16,562 |
| ||
Taxes Receivable |
| 12,845 |
| 432 |
| ||
Regulatory Assets |
| 49,578 |
| 43,024 |
| ||
Marketable Securities |
| 19,194 |
| 26,628 |
| ||
Prepayments and Other Current Assets |
| 9,663 |
| 10,479 |
| ||
Total Current Assets |
| 172,878 |
| 193,750 |
| ||
|
|
|
|
|
| ||
Property, Plant and Equipment, Net |
| 1,398,810 |
| 1,381,060 |
| ||
|
|
|
|
|
| ||
Deferred Debits and Other Assets: |
|
|
|
|
| ||
Regulatory Assets |
| 132,181 |
| 146,088 |
| ||
Marketable Securities |
| 38,710 |
| 31,243 |
| ||
Other Long-Term Assets |
| 40,956 |
| 40,679 |
| ||
Total Deferred Debits and Other Assets |
| 211,847 |
| 218,010 |
| ||
|
|
|
|
|
| ||
Total Assets |
| $ | 1,783,535 |
| $ | 1,792,820 |
|
The accompanying notes are an integral part of these unaudited condensed financial statements.
WESTERN MASSACHUSETTS ELECTRIC COMPANY
CONDENSED BALANCE SHEETS
(Unaudited)
|
| March 31, |
| December 31, |
| ||
(Thousands of Dollars) |
| 2014 |
| 2013 |
| ||
|
|
|
|
|
| ||
LIABILITIES AND CAPITALIZATION |
|
|
|
|
| ||
|
|
|
|
|
| ||
Current Liabilities: |
|
|
|
|
| ||
Notes Payable to NU Parent |
| $ | 37,400 |
| $ | — |
|
Accounts Payable |
| 38,407 |
| 62,961 |
| ||
Accounts Payable to Affiliated Companies |
| 18,154 |
| 9,230 |
| ||
Accrued Interest |
| 2,837 |
| 7,525 |
| ||
Regulatory Liabilities |
| 21,816 |
| 19,858 |
| ||
Accumulated Deferred Income Taxes |
| 15,361 |
| 13,098 |
| ||
Counterparty Deposits |
| 3,188 |
| 7,688 |
| ||
Other Current Liabilities |
| 15,563 |
| 20,629 |
| ||
Total Current Liabilities |
| 152,726 |
| 140,989 |
| ||
|
|
|
|
|
| ||
Deferred Credits and Other Liabilities: |
|
|
|
|
| ||
Accumulated Deferred Income Taxes |
| 409,493 |
| 396,933 |
| ||
Regulatory Liabilities |
| 10,445 |
| 13,873 |
| ||
Accrued SERP and PBOP |
| 3,850 |
| 3,911 |
| ||
Other Long-Term Liabilities |
| 29,411 |
| 28,619 |
| ||
Total Deferred Credits and Other Liabilities |
| 453,199 |
| 443,336 |
| ||
|
|
|
|
|
| ||
Capitalization: |
|
|
|
|
| ||
Long-Term Debt |
| 629,162 |
| 629,389 |
| ||
|
|
|
|
|
| ||
Common Stockholder’s Equity: |
|
|
|
|
| ||
Common Stock |
| 10,866 |
| 10,866 |
| ||
Capital Surplus, Paid In |
| 390,895 |
| 390,743 |
| ||
Retained Earnings |
| 150,117 |
| 181,014 |
| ||
Accumulated Other Comprehensive Loss |
| (3,430 | ) | (3,517 | ) | ||
Common Stockholder’s Equity |
| 548,448 |
| 579,106 |
| ||
Total Capitalization |
| 1,177,610 |
| 1,208,495 |
| ||
|
|
|
|
|
| ||
Total Liabilities and Capitalization |
| $ | 1,783,535 |
| $ | 1,792,820 |
|
The accompanying notes are an integral part of these unaudited condensed financial statements.
WESTERN MASSACHUSETTS ELECTRIC COMPANY
CONDENSED STATEMENTS OF INCOME
(Unaudited)
|
| For the Three Months Ended March 31, |
| ||||
(Thousands of Dollars) |
| 2014 |
| 2013 |
| ||
|
|
|
|
|
| ||
Operating Revenues |
| $ | 137,409 |
| $ | 124,953 |
|
|
|
|
|
|
| ||
Operating Expenses: |
|
|
|
|
| ||
Purchased Power and Transmission |
| 49,431 |
| 40,044 |
| ||
Operations and Maintenance |
| 22,579 |
| 20,928 |
| ||
Depreciation |
| 10,321 |
| 8,970 |
| ||
Amortization of Regulatory Assets, Net |
| 399 |
| 129 |
| ||
Amortization of Rate Reduction Bonds |
| — |
| 4,689 |
| ||
Energy Efficiency Programs |
| 11,865 |
| 8,315 |
| ||
Taxes Other Than Income Taxes |
| 8,082 |
| 6,288 |
| ||
Total Operating Expenses |
| 102,677 |
| 89,363 |
| ||
Operating Income |
| 34,732 |
| 35,590 |
| ||
|
|
|
|
|
| ||
Interest Expense: |
|
|
|
|
| ||
Interest on Long-Term Debt |
| 6,062 |
| 6,082 |
| ||
Other Interest |
| (416 | ) | 211 |
| ||
Interest Expense |
| 5,646 |
| 6,293 |
| ||
Other Income, Net |
| 574 |
| 1,004 |
| ||
Income Before Income Tax Expense |
| 29,660 |
| 30,301 |
| ||
Income Tax Expense |
| 11,558 |
| 11,698 |
| ||
Net Income |
| $ | 18,102 |
| $ | 18,603 |
|
The accompanying notes are an integral part of these unaudited condensed financial statements.
CONDENSED STATEMENTS OF COMPREHENSIVE INCOME
(Unaudited)
Net Income |
| $ | 18,102 |
| $ | 18,603 |
|
Other Comprehensive Income, Net of Tax: |
|
|
|
|
| ||
Qualified Cash Flow Hedging Instruments |
| 85 |
| 85 |
| ||
Changes in Unrealized Gains/(Losses) on Other Securities |
| 2 |
| (2 | ) | ||
Other Comprehensive Income, Net of Tax |
| 87 |
| 83 |
| ||
Comprehensive Income |
| $ | 18,189 |
| $ | 18,686 |
|
The accompanying notes are an integral part of these unaudited condensed financial statements.
WESTERN MASSACHUSETTS ELECTRIC COMPANY
CONDENSED STATEMENTS OF CASH FLOWS
(Unaudited)
|
| For the Three Months Ended March 31, |
| ||||
(Thousands of Dollars) |
| 2014 |
| 2013 |
| ||
|
|
|
|
|
| ||
Operating Activities: |
|
|
|
|
| ||
Net Income |
| $ | 18,102 |
| $ | 18,603 |
|
Adjustments to Reconcile Net Income to Net Cash Flows Provided by Operating Activities: |
|
|
|
|
| ||
Depreciation |
| 10,321 |
| 8,970 |
| ||
Deferred Income Taxes |
| 14,688 |
| 16,828 |
| ||
Regulatory Over/(Under) Recoveries, Net |
| 5,780 |
| (2,357 | ) | ||
Amortization of Regulatory Assets, Net |
| 399 |
| 129 |
| ||
Amortization of Rate Reduction Bonds |
| — |
| 4,689 |
| ||
Other |
| (1,351 | ) | (1,299 | ) | ||
Changes in Current Assets and Liabilities: |
|
|
|
|
| ||
Receivables and Unbilled Revenues, Net |
| 34,905 |
| (4,907 | ) | ||
Taxes Receivable/Accrued, Net |
| (17,126 | ) | 21,600 |
| ||
Accounts Payable |
| (10,516 | ) | 17,667 |
| ||
Other Current Assets and Liabilities, Net |
| (8,869 | ) | (8,931 | ) | ||
Net Cash Flows Provided by Operating Activities |
| 46,333 |
| 70,992 |
| ||
|
|
|
|
|
| ||
Investing Activities: |
|
|
|
|
| ||
Investments in Property, Plant and Equipment |
| (30,347 | ) | (66,340 | ) | ||
Proceeds from Sales of Marketable Securities |
| 34,656 |
| 21,035 |
| ||
Purchases of Marketable Securities |
| (34,804 | ) | (21,191 | ) | ||
Other Investing Activities |
| — |
| 500 |
| ||
Net Cash Flows Used in Investing Activities |
| (30,495 | ) | (65,996 | ) | ||
|
|
|
|
|
| ||
Financing Activities: |
|
|
|
|
| ||
Cash Dividends on Common Stock |
| (49,000 | ) | (10,000 | ) | ||
Increase in Notes Payable to NU Parent |
| 37,400 |
| 11,500 |
| ||
Retirement of Rate Reduction Bonds |
| — |
| (4,716 | ) | ||
Other Financing Activities |
| (11 | ) | (13 | ) | ||
Net Cash Flows Used in Financing Activities |
| (11,611 | ) | (3,229 | ) | ||
Net Increase in Cash |
| 4,227 |
| 1,767 |
| ||
Cash - Beginning of Period |
| — |
| 1 |
| ||
Cash - End of Period |
| $ | 4,227 |
| $ | 1,768 |
|
The accompanying notes are an integral part of these unaudited condensed financial statements.
NORTHEAST UTILITIES AND SUBSIDIARIES
THE CONNECTICUT LIGHT AND POWER COMPANY
NSTAR ELECTRIC COMPANY AND SUBSIDIARY
PUBLIC SERVICE COMPANY OF NEW HAMPSHIRE AND SUBSIDIARY
WESTERN MASSACHUSETTS ELECTRIC COMPANY
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. On April 10, 2012, NU acquired 100 percent of the outstanding common shares of NSTAR and its subsidiaries. NU'sNU’s wholly owned regulated utility subsidiaries consist of CL&P, NSTAR Electric, PSNH, WMECO, Yankee Gas and NSTAR Gas. NU provides energy delivery service to approximately 3.6 million electric and natural gas customers through these six regulated utilities in Connecticut, Massachusetts and New Hampshire. NU's consolidated financial information does not include NSTAR and its subsidiaries' results of operations for the three months ended March 31, 2012. The information disclosed for NSTAR Electric represents its results of operations for the three and nine months ended September 30, 2013 and 2012, presented on a comparable basis.
The unaudited condensed consolidated financial statements of NU, NSTAR Electric and PSNH include the accounts of each of their respective subsidiaries. Intercompany transactions have been eliminated in consolidation. The accompanying unaudited condensed consolidated financial statements of NU, NSTAR Electric and PSNH and the unaudited condensed financial statements of CL&P and WMECO are herein collectively referred to as the "financial“financial statements."”
The combined notes to the financial statements have been prepared pursuant to the rules and regulations of the SEC. Certain information and footnote disclosures included in annual financial statements prepared in accordance with GAAP have been omitted pursuant to such rules and regulations. The accompanying financial statements should be read in conjunction with the entirety of this combined Quarterly Report on Form 10-Q the first and second quarter 2013 combined Quarterly Reports on Form 10-Q and the 20122013 combined Annual Report on Form 10-K of NU, CL&P, NSTAR Electric, PSNH and WMECO, which werewas 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,&P’s, NSTAR Electric’s, PSNH'sPSNH’s and WMECO'sWMECO’s financial position as of September 30, 2013March 31, 2014 and December 31, 2012,2013, and the results of operations, and comprehensive income for the three and nine months ended September 30, 2013 and 2012, and the cash flows for the ninethree months ended September 30, 2013March 31, 2014 and 2012.2013. The results of operations, and comprehensive income for the three and nine months ended September 30, 2013 and 2012, and the cash flows for the ninethree months ended September 30,March 31, 2014 and 2013 and 2012, are not necessarily indicative of the results expected for a full year. The demand for electricity and natural gas is affected by weather conditions, economic conditions, and consumer conservation (including company-sponsored energy efficiency programs). Electric energy sales and revenues are typically higher in the winter and summer months than in the spring and fall months. Natural gas sales and revenues are typically higher in the winter months than during other periods of the year.
NU consolidates CYAPC and YAEC as CL&P’s, NSTAR Electric’s, PSNH’s and WMECO’s combined ownership interest in each of these entities is greater than 50 percent. Intercompany transactions between CL&P, NSTAR Electric, PSNH and WMECO and the CYAPC and YAEC companies have been eliminated in consolidation.consolidation of the NU financial statements. For CL&P, NSTAR Electric, PSNH and WMECO, the investmentinvestments in CYAPC and YAEC continue to be accounted for under the equity method.
NU'sNU’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'sNU’s utility subsidiaries'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“Regulatory Accounting,"” for further information.
Certain reclassifications of prior period data were made in the accompanying balance sheets for NU, CL&P and PSNH, statements of income for NU, NSTAR Electric, PSNH and WMECO, and the statements of cash flows for all companies presented.CL&P, NSTAR Electric and WMECO. These reclassifications were made to conform to the current period’s presentation.
21
B.
Accounting Standards
Recently Adopted Accounting Standards: In the first quarter of 2013,Standards
On January 1, 2014, as required, NU prospectively adopted the following Financial Accounting Standards Board’s (FASB) final Accounting Standards Updates (ASU) relating to additional disclosure requirements:
Reporting of Amounts Reclassified Out of Accumulated Other Comprehensive Income:Requires entities to disclose additional information about items reclassified out of AOCI. The ASU does not change existing guidance on which items should be reclassified out of AOCI but requires disclosures about the components of AOCI and the amount of reclassification adjustments to be presented in one location. The ASU was effective beginning in the first quarter of 2013 and was applied prospectively. For further information, see Note 11, "Accumulated Other Comprehensive Income/(Loss)," to the financial statements. The ASU did not affect the calculation of net income, comprehensive income or EPS and did not have an impact on financial position, results of operations or cash flows.
Clarifying the Scope of Disclosures about Offsetting Assets and Liabilities:Clarifies the scope of the offsetting disclosure requirements under GAAP. The disclosure requirements apply to derivative instruments, do not change existing guidance on which items should be offset in the balance sheets and require disclosures about the items that are offset. The ASU was effective beginning in the first quarter of 2013 with retrospective application. For further information, see Note 4, "Derivative Instruments," to the financial statements. The ASU did not have an impact on financial position, results of operations or cash flows.
Accounting Standards Issued but not Yet Adopted: In July 2013, the FASB issued a final ASU that requiresrequired presentation of certain unrecognized tax benefits as reductions to deferred tax assets rather than as liabilities. Management is currently evaluatingassets. Implementation of this guidance had an immaterial impact on the balance sheetsheets and no impact of implementing this standard. The ASU does not impacton the results of operations or cash flows.flows of NU, CL&P, NSTAR Electric, PSNH and WMECO.
C.
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 amounts.accounts. This provision is determined based upon a variety of factors, including applyingthe application of an estimated uncollectible account percentage to each receivable aging category,category. The estimate is based upon historical collection and write-off experience and management'smanagement’s assessment of collectibility from individual customers. Management continuously assesses the collectibility of receivables, and if circumstances change,adjusts collectibility estimates are adjusted accordingly.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 September 30, 2013 |
| As of December 31, 2012 |
| As of March 31, 2014 |
| As of December 31, 2013 |
| ||||
NU |
| $ | 182.5 |
| $ | 165.5 |
| $ | 180.0 |
| $ | 171.3 |
|
CL&P |
|
| 85.8 |
|
| 77.6 |
| 83.4 |
| 82.0 |
| ||
NSTAR Electric |
|
| 45.9 |
|
| 44.1 |
| 43.1 |
| 41.7 |
| ||
PSNH |
|
| 7.7 |
|
| 6.8 |
| 7.8 |
| 7.4 |
| ||
WMECO |
|
| 10.4 |
|
| 8.5 |
| 10.6 |
| 10.0 |
| ||
D.
Fair Value Measurements
Fair value measurement guidance is applied to derivative contracts recorded at fair valuethat 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'sNU’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'sNU’s fair value measurements are described in Note 4, "Derivative“Derivative Instruments,"” Note 5, "Marketable“Marketable Securities,"” and Note 10, "Fair9, “Fair Value of Financial Instruments,"” to the financial statements.
22
E.
Other Income, Net
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'sElectric’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'sNU’s investment in two regional transmission companies.
F.Other Taxes
Gross receipts taxes levied by the state of Connecticut are collected by CL&P and Yankee Gas from their respective customers. These gross receipts taxes are shown on a gross basis with collections in Operating Revenues and payments in Taxes Other Than Income Taxes on the statements of income as follows:
| For the Three Months Ended |
| For the Nine Months Ended |
| For the Three Months Ended |
| ||||||||||||
(Millions of Dollars) | September 30, 2013 |
| September 30, 2012 |
| September 30, 2013 |
| September 30, 2012 |
| March 31, 2014 |
| March 31, 2013 |
| ||||||
NU | $ | 37.5 |
| $ | 36.4 |
| $ | 108.9 |
| $ | 102.0 |
| $ | 44.4 |
| $ | 38.4 |
|
CL&P |
| 35.5 |
| 34.4 |
| 97.3 |
| 91.5 |
| 35.6 |
| 32.0 |
| |||||
Certain sales taxes are also collected by NU'sNU’s companies that serve customers in Connecticut and Massachusetts as agents for state and local governments and are recorded on a net basis with no impact on the statements of income.
G.
Supplemental Cash Flow Information
Non-cash investing activities include plant additions included in Accounts Payable as follows: | |||||||||
|
|
|
|
|
|
|
|
|
|
(Millions of Dollars) | As of September 30, 2013 |
| As of September 30, 2012 |
| |||||
NU | $ | 122.9 |
| $ | 139.9 |
| |||
CL&P |
| 36.6 |
|
| 45.9 |
| |||
NSTAR Electric |
| 31.9 |
|
| 21.5 |
| |||
PSNH |
| 16.9 |
|
| 20.1 |
| |||
WMECO |
| 13.8 |
|
| 35.1 |
| |||
H.Non-cash investing activities include plant additions included in Accounts Payable as follows:
(Millions of Dollars) |
| As of March 31, 2014 |
| As of March 31, 2013 |
| ||
NU |
| $ | 108.5 |
| $ | 98.7 |
|
CL&P |
| 36.2 |
| 28.2 |
| ||
NSTAR Electric |
| 28.0 |
| 30.7 |
| ||
PSNH |
| 14.4 |
| 12.9 |
| ||
WMECO |
| 14.4 |
| 15.8 |
| ||
H.Severance Benefits
In the thirdfirst quarter of 2013,2014, NU recorded severance benefit expenses of $9.2$4.3 million in connectionassociated with the partial outsourcing of information technology functions made as part ofand ongoing post-merger integration. As of September 30,March 31, 2014 and December 31, 2013, the severance accrual totaled $14.2$17.7 million and $14.7 million, respectively, and was included in Other Current Liabilities on the accompanying balance sheet.sheets.
2.I.Restricted Cash
On March 28, 2014, CYAPC and YAEC received payment of $163.3 million of the DOE Phase II Damages proceeds. It is anticipated that in the second quarter of 2014, the Yankee Companies will complete the FERC review process and return these amounts to the member companies, including CL&P, NSTAR Electric, PSNH, and WMECO, for the benefit of their respective customers. As a result of the consolidation of CYAPC and YAEC, the cash received is included in Other Long-Term Assets on the NU consolidated balance sheet pending refund. For further information, see Note 8B, “Commitments and Contingencies - Contractual Obligations - Yankee Companies.”
2.REGULATORY ACCOUNTING
The rates charged to the customers of NU'sNU’s Regulated companies are designed to collect each company'scompany’s costs to provide service, including a return on investment. Therefore, the accounting policies of the Regulated companies reflectfollow 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'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:
| As of September 30, 2013 |
| As of December 31, 2012 |
| As of March 31, 2014 |
| As of December 31, 2013 |
| ||||
(Millions of Dollars) | NU |
| NU |
| NU |
| NU |
| ||||
Benefit Costs | $ | 2,256.0 |
| $ | 2,452.1 |
| $ | 1,205.4 |
| $ | 1,240.2 |
|
Regulatory Assets Offsetting Derivative Liabilities |
| 770.3 |
|
| 885.6 | |||||||
Derivative Liabilities |
| 564.9 |
| 638.0 |
| |||||||
Income Taxes, Net |
| 629.2 |
| 626.2 |
| |||||||
Storm Restoration Costs |
| 580.9 |
| 589.6 |
| |||||||
Goodwill |
| 531.1 |
|
| 537.6 |
| 520.8 |
| 525.9 |
| ||
Storm Restoration Costs |
| 621.0 |
|
| 547.7 | |||||||
Income Taxes, Net |
| 587.5 |
|
| 516.2 | |||||||
Securitized Assets |
| 37.4 |
|
| 232.6 | |||||||
Contractual Obligations |
| 170.9 |
|
| 217.6 | |||||||
Regulatory Tracker Mechanisms |
| 347.4 |
| 323.4 |
| |||||||
Buy Out Agreements for Power Contracts |
| 76.0 |
|
| 92.9 |
| 63.4 |
| 70.2 |
| ||
Regulatory Tracker Deferrals |
| 163.3 |
|
| 190.1 | |||||||
Asset Retirement Obligations |
| 93.0 |
|
| 88.8 | |||||||
Other Regulatory Assets |
| 50.1 |
|
| 76.2 |
| 147.6 |
| 281.0 |
| ||
Total Regulatory Assets |
| 5,356.6 |
|
| 5,837.4 |
| 4,059.6 |
| 4,294.5 |
| ||
Less: Current Portion |
| 474.2 |
|
| 705.0 |
| 573.0 |
| 535.8 |
| ||
Total Long-Term Regulatory Assets | $ | 4,882.4 |
| $ | 5,132.4 |
| $ | 3,486.6 |
| $ | 3,758.7 |
|
23
|
| As of March 31, 2014 |
| As of December 31, 2013 |
| ||||||||||||||||||||
|
|
|
| NSTAR |
|
|
|
|
|
|
| NSTAR |
|
|
|
|
| ||||||||
(Millions of Dollars) |
| CL&P |
| Electric |
| PSNH |
| WMECO |
| CL&P |
| Electric |
| PSNH |
| WMECO |
| ||||||||
Benefit Costs |
| $ | 287.1 |
| $ | 321.3 |
| $ | 96.7 |
| $ | 55.1 |
| $ | 297.7 |
| $ | 496.7 |
| $ | 100.6 |
| $ | 57.3 |
|
Derivative Liabilities |
| 557.0 |
| 7.9 |
| — |
| — |
| 630.4 |
| 7.7 |
| — |
| — |
| ||||||||
Income Taxes, Net |
| 419.7 |
| 82.5 |
| 39.4 |
| 43.5 |
| 415.5 |
| 84.0 |
| 40.3 |
| 43.7 |
| ||||||||
Storm Restoration Costs |
| 395.3 |
| 109.2 |
| 40.3 |
| 36.1 |
| 397.8 |
| 109.3 |
| 43.7 |
| 38.8 |
| ||||||||
Goodwill |
| — |
| 447.1 |
| — |
| — |
| — |
| 451.5 |
| — |
| — |
| ||||||||
Regulatory Tracker Mechanisms |
| 33.3 |
| 182.7 |
| 75.2 |
| 31.6 |
| 8.0 |
| 169.5 |
| 83.3 |
| 32.6 |
| ||||||||
Buy Out Agreements for Power Contracts |
| — |
| 58.3 |
| 5.1 |
| — |
| — |
| 64.7 |
| 5.5 |
| — |
| ||||||||
Other Regulatory Assets |
| 64.1 |
| 55.5 |
| 37.8 |
| 15.5 |
| 64.6 |
| 55.9 |
| 38.1 |
| 16.7 |
| ||||||||
Total Regulatory Assets |
| 1,756.5 |
| 1,264.5 |
| 294.5 |
| 181.8 |
| 1,814.0 |
| 1,439.3 |
| 311.5 |
| 189.1 |
| ||||||||
Less: Current Portion |
| 175.9 |
| 222.6 |
| 83.8 |
| 49.6 |
| 150.9 |
| 204.1 |
| 92.2 |
| 43.0 |
| ||||||||
Total Long-Term Regulatory Assets |
| $ | 1,580.6 |
| $ | 1,041.9 |
| $ | 210.7 |
| $ | 132.2 |
| $ | 1,663.1 |
| $ | 1,235.2 |
| $ | 219.3 |
| $ | 146.1 |
|
|
| As of September 30, 2013 |
| As of December 31, 2012 | ||||||||||||||||||||
|
|
|
|
| NSTAR |
|
|
|
|
|
|
|
|
|
| NSTAR |
|
|
|
|
|
| ||
(Millions of Dollars) | CL&P |
| Electric |
| PSNH |
| WMECO |
| CL&P |
| Electric |
| PSNH |
| WMECO | |||||||||
Benefit Costs | $ | 509.3 |
| $ | 824.3 |
| $ | 199.6 |
| $ | 103.8 |
| $ | 563.2 |
| $ | 781.2 |
| $ | 223.7 |
| $ | 116.0 | |
Regulatory Assets Offsetting |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| |
| Derivative Liabilities |
| 755.3 |
|
| 11.6 |
|
| 0.3 |
|
| - |
|
| 866.2 |
|
| 14.9 |
|
| - |
|
| 3.0 |
Goodwill |
| - |
|
| 455.9 |
|
| - |
|
| - |
|
| - |
|
| 461.5 |
|
| - |
|
| - | |
Storm Restoration Costs |
| 439.4 |
|
| 114.0 |
|
| 27.9 |
|
| 39.7 |
|
| 413.9 |
|
| 55.8 |
|
| 34.5 |
|
| 43.5 | |
Income Taxes, Net |
| 385.3 |
|
| 84.8 |
|
| 36.5 |
|
| 42.1 |
|
| 367.5 |
|
| 47.1 |
|
| 36.2 |
|
| 31.0 | |
Securitized Assets |
| - |
|
| 37.4 |
|
| - |
|
| - |
|
| - |
|
| 205.1 |
|
| 19.7 |
|
| 7.8 | |
Contractual Obligations |
| 20.0 |
|
| 6.4 |
|
| - |
|
| 4.6 |
|
| 64.0 |
|
| 22.8 |
|
| - |
|
| 14.9 | |
Buy Out Agreements for Power Contracts |
| - |
|
| 70.1 |
|
| 5.9 |
|
| - |
|
| - |
|
| 85.9 |
|
| 7.0 |
|
| - | |
Regulatory Tracker Deferrals |
| - |
|
| 83.6 |
|
| 52.5 |
|
| 21.5 |
|
| 12.2 |
|
| 71.4 |
|
| 49.3 |
|
| 31.9 | |
Asset Retirement Obligations |
| 31.1 |
|
| 30.7 |
|
| 14.7 |
|
| 3.7 |
|
| 29.4 |
|
| 29.4 |
|
| 14.2 |
|
| 3.5 | |
Other Regulatory Assets |
| 28.7 |
|
| 9.2 |
|
| 31.7 |
|
| 17.2 |
|
| 27.9 |
|
| 16.9 |
|
| 29.4 |
|
| 12.6 | |
Total Regulatory Assets |
| 2,169.1 |
|
| 1,728.0 |
|
| 369.1 |
|
| 232.6 |
|
| 2,344.3 |
|
| 1,792.0 |
|
| 414.0 |
|
| 264.2 | |
Less: Current Portion |
| 147.1 |
|
| 189.8 |
|
| 67.7 |
|
| 37.9 |
|
| 185.9 |
|
| 347.1 |
|
| 62.9 |
|
| 42.4 | |
Total Long-Term Regulatory Assets | $ | 2,022.0 |
| $ | 1,538.2 |
| $ | 301.4 |
| $ | 194.7 |
| $ | 2,158.4 |
| $ | 1,444.9 |
| $ | 351.1 |
| $ | 221.8 | |
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: The storm restoration cost deferrals relateFrom 2011 to costs incurred at2013, CL&P, NSTAR Electric, PSNH and WMECO thatexperienced several significant storm events. As a result of these storm events, each company expectssuffered extensive damage to collect from customers.its distribution and transmission systems resulting in customer outages. Each company incurred significant costs to repair damage and restore customer service. The storm restoration cost regulatory asset balance at CL&P, NSTAR Electric, PSNH and WMECO primarily reflects incremental costs incurred for Tropical Storm Irene, the October 2011 snowstorm, Storm Sandy and the February 2013 blizzard. For PSNH, costs incurred associated with these storms are recorded in Other Long-Term Assets. Themajor storm restoration cost regulatory asset balance at PSNH primarily reflects costs incurred for storms in 2008 and 2010, which are currently being recovered in rates.events. Management believes the storm restoration costs were prudent and meet the criteria for specific cost recovery in Connecticut, Massachusetts and New Hampshire and asthat recovery from customers is probable through the applicable regulatory recovery process.
On March 12, 2014, the PURA issued a result, are probable of recovery. Each operating company is seekingfinal decision on CL&P’s request to recover storm restoration costs associated with five major storms, which occurred in 2011 and 2012. The PURA approved recovery of these$365 million of deferred storm restoration costs and ordered CL&P to capitalize approximately $18 million of the deferred storm restoration costs as utility plant, which will be recovered through depreciation expense in future rate proceedings. CL&P will recover the $365 million with carrying charges in its applicable regulatory recovery process.distribution rates over a six-year period beginning December 1, 2014. The remaining costs were either disallowed or we believe will be recovered from other sources. These costs did not have a material impact on CL&P’s financial position, results of operations or cash flows.
Regulatory Costs in Other Long-Term Assets: The Regulated companies had $95.1$71.7 million ($3.412.4 million for CL&P, $31.3$33.7 million for NSTAR Electric, $37.3 million for PSNH, and $7.9$10.2 million for WMECO) and $69.9$65.1 million ($3.97.3 million for CL&P, $25.4$33.4 million for NSTAR Electric, $35.7 million for PSNH, and $1.4$10.1 million for WMECO) of additional regulatory costs as of September 30, 2013March 31, 2014 and December 31, 2012,2013, respectively, whichthat were included in Other Long-Term Assets on the balance sheets. These amounts represent incurred costs for which specific recovery has not yet been specifically approved by the applicable regulatory agency. ManagementHowever, 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.customers in rates.
Regulatory Liabilities: The components of regulatory liabilities are as follows:
| As of September 30, 2013 |
| As of December 31, 2012 |
| As of March 31, 2014 |
| As of December 31, 2013 |
| ||||
(Millions of Dollars) | NU |
| NU |
| NU |
| NU |
| ||||
Cost of Removal | $ | 434.3 |
| $ | 440.8 |
| $ | 437.3 |
| $ | 435.1 |
|
Regulatory Tracker Deferrals |
| 168.6 |
| 95.1 | ||||||||
Regulatory Tracker Mechanisms |
| 203.6 |
| 151.2 |
| |||||||
AFUDC - Transmission |
| 68.3 |
| 70.0 |
| 67.8 |
| 68.1 |
| |||
Contractual Obligations - Yankee Companies |
| 93.3 |
| — |
| |||||||
Other Regulatory Liabilities |
| 73.9 |
|
| 68.4 |
| 53.3 |
| 52.9 |
| ||
Total Regulatory Liabilities |
| 745.1 |
| 674.3 |
| 855.3 |
| 707.3 |
| |||
Less: Current Portion |
| 224.4 |
|
| 134.1 |
| 263.8 |
| 204.3 |
| ||
Total Long-Term Regulatory Liabilities | $ | 520.7 |
| $ | 540.2 |
| $ | 591.5 |
| $ | 503.0 |
|
|
| As of September 30, 2013 |
| As of December 31, 2012 |
| As of March 31, 2014 |
| As of December 31, 2013 |
| ||||||||||||||||||||||||||||||||||||||||
|
|
|
| NSTAR |
|
|
|
|
|
|
| NSTAR |
|
|
|
|
|
|
| NSTAR |
|
|
|
|
|
|
| NSTAR |
|
|
|
|
| ||||||||||||||||
(Millions of Dollars) | (Millions of Dollars) | CL&P |
| Electric |
| PSNH |
| WMECO |
| CL&P |
| Electric |
| PSNH |
| WMECO |
| CL&P |
| Electric |
| PSNH |
| WMECO |
| CL&P |
| Electric |
| PSNH |
| WMECO |
| ||||||||||||||||
Cost of Removal | Cost of Removal | $ | 31.2 |
| $ | 247.2 |
| $ | 49.8 |
| $ | - |
| $ | 44.2 |
| $ | 240.3 |
| $ | 51.2 |
| $ | - |
| $ | 27.5 |
| $ | 252.5 |
| $ | 49.7 |
| $ | — |
| $ | 29.1 |
| $ | 250.0 |
| $ | 49.7 |
| $ | — |
|
Regulatory Tracker Deferrals |
| 73.2 |
|
| 51.0 |
|
| 10.7 |
|
| 22.1 |
|
| 39.1 |
|
| 14.4 |
|
| 20.4 |
|
| 19.0 | ||||||||||||||||||||||||||
Regulatory Tracker Mechanisms |
| 105.6 |
| 43.8 |
| 27.5 |
| 22.4 |
| 95.6 |
| 21.9 |
| 21.6 |
| 21.1 |
| ||||||||||||||||||||||||||||||||
AFUDC - Transmission | AFUDC - Transmission |
| 55.0 |
|
| 4.0 |
|
| - |
|
| 9.3 |
|
| 56.6 |
|
| 4.1 |
|
| - |
|
| 9.3 |
| 54.5 |
| 4.0 |
| — |
| 9.3 |
| 54.7 |
| 4.1 |
| — |
| 9.3 |
| ||||||||
Other Regulatory Liabilities | Other Regulatory Liabilities |
| 30.6 |
|
| 31.3 |
|
| 15.8 |
|
| 2.9 |
|
| 16.5 |
|
| 32.9 |
|
| 3.8 |
|
| 2.4 |
| 9.8 |
| 30.4 |
| 1.9 |
| 0.5 |
| 8.4 |
| 31.1 |
| 1.0 |
| 3.4 |
| ||||||||
Total Regulatory Liabilities | Total Regulatory Liabilities |
| 190.0 |
|
| 333.5 |
|
| 76.3 |
|
| 34.3 |
|
| 156.4 |
|
| 291.7 |
|
| 75.4 |
|
| 30.7 |
| 197.4 |
| 330.7 |
| 79.1 |
| 32.2 |
| 187.8 |
| 307.1 |
| 72.3 |
| 33.8 |
| ||||||||
Less: Current Portion | Less: Current Portion |
| 82.0 |
|
| 82.5 |
|
| 23.4 |
|
| 22.4 |
|
| 32.1 |
|
| 47.5 |
|
| 23.0 |
|
| 21.0 |
| 107.3 |
| 73.6 |
| 27.3 |
| 21.8 |
| 94.0 |
| 54.0 |
| 20.6 |
| 19.9 |
| ||||||||
Total Long-Term Regulatory Liabilities | Total Long-Term Regulatory Liabilities | $ | 108.0 |
| $ | 251.0 |
| $ | 52.9 |
| $ | 11.9 |
| $ | 124.3 |
| $ | 244.2 |
| $ | 52.4 |
| $ | 9.7 |
| $ | 90.1 |
| $ | 257.1 |
| $ | 51.8 |
| $ | 10.4 |
| $ | 93.8 |
| $ | 253.1 |
| $ | 51.7 |
| $ | 13.9 |
|
For further information on matters related to the Yankee Companies, see Note 8B, “Commitments and Contingencies - Contractual Obligations - Yankee Companies,” to the financial statements.
24
3.
PROPERTY, PLANT AND EQUIPMENT AND ACCUMULATED DEPRECIATION
The following tables summarize the NU, CL&P, NSTAR Electric, PSNH and WMECO investments in utility property, plant and equipment by asset category:
|
| As of September 30, 2013 |
| As of December 31, 2012 |
| As of March 31, 2014 |
| As of December 31, 2013 |
| ||||
(Millions of Dollars) | (Millions of Dollars) | NU |
| NU |
| NU |
| NU |
| ||||
Distribution - Electric | Distribution - Electric | $ | 11,735.4 |
| $ | 11,438.2 |
| $ | 12,039.7 |
| $ | 11,950.2 |
|
Distribution - Natural Gas | Distribution - Natural Gas |
| 2,352.4 |
| 2,274.2 |
| 2,447.9 |
| 2,425.9 |
| |||
Transmission | Transmission |
| 6,009.0 |
| 5,541.1 |
| 6,423.5 |
| 6,412.5 |
| |||
Generation | Generation |
| 1,142.1 |
|
| 1,146.6 |
| 1,154.7 |
| 1,152.3 |
| ||
Electric and Natural Gas Utility | Electric and Natural Gas Utility |
| 21,238.9 |
| 20,400.1 |
| 22,065.8 |
| 21,940.9 |
| |||
Other (1) | Other (1) |
| 505.2 |
|
| 429.3 |
| 510.2 |
| 508.7 |
| ||
Property, Plant and Equipment, Gross | Property, Plant and Equipment, Gross |
| 21,744.1 |
| 20,829.4 |
| 22,576.0 |
| 22,449.6 |
| |||
Less: Accumulated Depreciation |
|
|
|
| |||||||||
| Electric and Natural Gas Utility |
| (5,331.0) |
| (5,065.1) | ||||||||
| Other |
| (192.9) |
|
| (171.5) | |||||||
Less: Accumulated Depreciation Electric and Natural Gas Utility |
| (5,491.7 | ) | (5,387.0 | ) | ||||||||
Other |
| (204.7 | ) | (196.2 | ) | ||||||||
Total Accumulated Depreciation | Total Accumulated Depreciation |
| (5,523.9) |
|
| (5,236.6) |
| (5,696.4 | ) | (5,583.2 | ) | ||
Property, Plant and Equipment, Net | Property, Plant and Equipment, Net |
| 16,220.2 |
| 15,592.8 |
| 16,879.6 |
| 16,866.4 |
| |||
Construction Work in Progress | Construction Work in Progress |
| 967.7 |
|
| 1,012.2 |
| 833.4 |
| 709.8 |
| ||
Total Property, Plant and Equipment, Net | Total Property, Plant and Equipment, Net | $ | 17,187.9 |
| $ | 16,605.0 |
| $ | 17,713.0 |
| $ | 17,576.2 |
|
(1)
These assets represent unregulated property and are primarily comprised of building improvements, at RRR,computer software, hardware and equipment at NUSCO and telecommunications assets at NSTAR Communications, Inc.NU’s unregulated companies.
| As of September 30, 2013 |
| As of December 31, 2012 |
| As of March 31, 2014 |
| As of December 31, 2013 |
| ||||||||||||||||||||||||||||||||||||||||
|
|
|
| NSTAR |
|
|
|
|
|
|
|
| NSTAR |
|
|
|
|
|
|
| NSTAR |
|
|
|
|
|
|
| NSTAR |
|
|
|
|
| ||||||||||||||
(Millions of Dollars) | CL&P |
| Electric |
| PSNH |
| WMECO |
| CL&P |
| Electric |
| PSNH |
| WMECO |
| CL&P |
| Electric |
| PSNH |
| WMECO |
| CL&P |
| Electric |
| PSNH |
| WMECO |
| ||||||||||||||||
Distribution | $ | 4,836.1 |
| $ | 4,622.7 |
| $ | 1,569.7 |
| $ | 746.3 |
| $ | 4,691.3 |
| $ | 4,539.9 |
| $ | 1,520.1 |
| $ | 724.2 |
| $ | 4,979.8 |
| $ | 4,717.6 |
| $ | 1,620.3 |
| $ | 762.0 |
| $ | 4,930.7 |
| $ | 4,694.7 |
| $ | 1,608.2 |
| $ | 756.6 |
|
Transmission |
| 2,969.6 |
| 1,664.5 |
| 613.2 |
| 715.8 |
| 2,796.1 |
| 1,529.7 |
| 599.2 |
| 583.7 |
| 3,074.8 |
| 1,769.0 |
| 701.7 |
| 831.7 |
| 3,071.9 |
| 1,772.3 |
| 695.7 |
| 826.4 |
| |||||||||||||||
Generation |
| - |
|
| - |
|
| 1,121.0 |
|
| 21.1 |
|
| - |
|
| - |
|
| 1,125.5 |
|
| 21.1 |
| — |
| — |
| 1,133.6 |
| 21.1 |
| — |
| — |
| 1,131.2 |
| 21.1 |
| ||||||||
Property, Plant and |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| ||||||||||||||||||||||||||||||||
Equipment, Gross |
| 7,805.7 |
| 6,287.2 |
| 3,303.9 |
| 1,483.2 |
| 7,487.4 |
| 6,069.6 |
| 3,244.8 |
| 1,329.0 | ||||||||||||||||||||||||||||||||
Property, Plant and Equipment, Gross |
| 8,054.6 |
| 6,486.6 |
| 3,455.6 |
| 1,614.8 |
| 8,002.6 |
| 6,467.0 |
| 3,435.1 |
| 1,604.1 |
| |||||||||||||||||||||||||||||||
Less: Accumulated Depreciation |
| (1,778.7) |
|
| (1,634.5) |
|
| (1,001.7) |
|
| (265.7) |
|
| (1,698.1) |
|
| (1,540.1) |
|
| (954.0) |
|
| (252.1) |
| (1,838.5 | ) | (1,664.6 | ) | (1,040.6 | ) | (278.4 | ) | (1,804.1 | ) | (1,631.3 | ) | (1,021.8 | ) | (271.5 | ) | ||||||||
Property, Plant and Equipment, Net |
| 6,027.0 |
| 4,652.7 |
| 2,302.2 |
| 1,217.5 |
| 5,789.3 |
| 4,529.5 |
| 2,290.8 |
| 1,076.9 |
| 6,216.1 |
| 4,822.0 |
| 2,415.0 |
| 1,336.4 |
| 6,198.5 |
| 4,835.7 |
| 2,413.3 |
| 1,332.6 |
| |||||||||||||||
Construction Work in Progress |
| 299.2 |
|
| 270.7 |
|
| 106.8 |
|
| 135.2 |
|
| 363.7 |
|
| 205.8 |
|
| 61.7 |
|
| 213.6 |
| 290.1 |
| 247.2 |
| 71.4 |
| 62.4 |
| 252.8 |
| 208.2 |
| 54.3 |
| 48.5 |
| ||||||||
Total Property, Plant and |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| ||||||||||||||||||||||||||||||||
Equipment, Net | $ | 6,326.2 |
| $ | 4,923.4 |
| $ | 2,409.0 |
| $ | 1,352.7 |
| $ | 6,153.0 |
| $ | 4,735.3 |
| $ | 2,352.5 |
| $ | 1,290.5 | |||||||||||||||||||||||||
Total Property, Plant and Equipment, Net |
| $ | 6,506.2 |
| $ | 5,069.2 |
| $ | 2,486.4 |
| $ | 1,398.8 |
| $ | 6,451.3 |
| $ | 5,043.9 |
| $ | 2,467.6 |
| $ | 1,381.1 |
| |||||||||||||||||||||||
4.As discussed in Note 2, “Regulatory Accounting,” during the first quarter of 2014, as a result of a regulatory proceeding, CL&P reclassified approximately $18 million from Regulatory Assets to Property, Plant and Equipment, Net.
4.DERIVATIVE INSTRUMENTS
The Regulated companies purchase and procure energy and energy-related products for their customers, which are subject to price volatility. The costs associated with supplying energy to customers are recoverable through customer rates. The Regulated companies manage the risks associated with the price volatility of energy and energy-related products through the use of derivative and nonderivative contracts.
Many of the derivative contracts meet the definition of, and are designated as, "normal purchases or normal sales" (normal)and qualify for accrual accounting under the applicable accounting guidance.
Derivative contracts that are not designated as normal are recorded at fair value as current or long-term Derivative Assets or Derivative Liabilities on the balance sheets. For the Regulated companies, Regulatory Assets or Regulatory Liabilities are recorded for the fair values of derivatives, as costs are recovered from, or refunded to, customers in their respective energy supply rates. For NU's remaining unregulated wholesale marketing contracts, changes in fair values of derivatives are included in Net Income. The costs and benefits of derivative contracts that meet the definition of normal are recognized in Operating Expenses or Operating Revenues on the statements of income, as applicable, as electricity or natural gas is delivered.
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 amountsamount recorded as current or long-term derivative asset or liability:
|
| As of September 30, 2013 |
| As of March 31, 2014 |
| ||||||||||||||
|
| Commodity Supply and |
|
|
| Net Amount Recorded as |
| Commodity Supply and |
|
|
| Net Amount Recorded as |
| ||||||
(Millions of Dollars) | (Millions of Dollars) | Price Risk Management |
| Netting (1) |
| Derivative Asset/(Liability) |
| Price Risk Management |
| Netting (1) |
| Derivative Asset/(Liability) |
| ||||||
Current Derivative Assets: | Current Derivative Assets: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| |||
Level 2: |
|
|
|
|
|
|
| ||||||||||||
NU (1) |
| $ | 1.2 |
| $ | (0.1 | ) | $ | 1.1 |
| |||||||||
Level 3: | Level 3: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| |||
| CL&P (1) | $ | 17.3 |
| $ | (10.1) |
| $ | 7.2 | ||||||||||
| NSTAR Electric |
| 0.4 |
|
| - |
|
| 0.4 | ||||||||||
| Other |
| 1.3 |
|
| - |
|
| 1.3 | ||||||||||
Total Current Derivative Assets | $ | 19.0 |
| $ | (10.1) |
| $ | 8.9 | |||||||||||
NU (1) |
| 17.8 |
| (9.7 | ) | 8.1 |
| ||||||||||||
CL&P (1) |
| 17.0 |
| (9.7 | ) | 7.3 |
| ||||||||||||
NSTAR Electric |
| 0.8 |
| — |
| 0.8 |
| ||||||||||||
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| |||
Long-Term Derivative Assets: | Long-Term Derivative Assets: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| |||
Level 3: | Level 3: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| |||
| CL&P (1) | $ | 139.5 |
| $ | (51.5) |
| $ | 88.0 | ||||||||||
| WMECO |
| 0.9 |
|
| - |
|
| 0.9 | ||||||||||
Total Long-Term Derivative Assets | $ | 140.4 |
| $ | (51.5) |
| $ | 88.9 | |||||||||||
NU, CL&P (1) |
| $ | 98.8 |
| $ | (31.7 | ) | $ | 67.1 |
| |||||||||
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| |||
Current Derivative Liabilities: | Current Derivative Liabilities: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| |||
Level 2: |
|
|
|
|
|
|
|
| |||||||||||
| PSNH (1) | $ | (0.5) |
| $ | 0.2 |
| $ | (0.3) | ||||||||||
| Other (1) (2) |
| (7.4) |
|
| - |
|
| (7.4) | ||||||||||
Level 3: | Level 3: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| |||
| CL&P |
| (94.1) |
|
| - |
|
| (94.1) | ||||||||||
| NSTAR Electric |
| (1.6) |
|
| - |
|
| (1.6) | ||||||||||
| WMECO |
| (0.1) |
|
| - |
|
| (0.1) | ||||||||||
Total Current Derivative Liabilities | $ | (103.7) |
| $ | 0.2 |
| $ | (103.5) | |||||||||||
NU |
| $ | (93.3 | ) | $ | — |
| $ | (93.3 | ) | |||||||||
CL&P |
| (92.0 | ) | — |
| (92.0 | ) | ||||||||||||
NSTAR Electric |
| (1.3 | ) | — |
| (1.3 | ) | ||||||||||||
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| |||
Long-Term Derivative Liabilities: | Long-Term Derivative Liabilities: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| |||
Level 2: |
|
|
|
|
|
|
| ||||||||||||
NU |
| $ | (0.2 | ) | $ | — |
| $ | (0.2 | ) | |||||||||
Level 3: | Level 3: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| |||
| CL&P | $ | (756.4) |
| $ | - |
| $ | (756.4) | ||||||||||
| NSTAR Electric |
| (10.4) |
|
| - |
|
| (10.4) | ||||||||||
Total Long-Term Derivative Liabilities | $ | (766.8) |
| $ | - |
| $ | (766.8) | |||||||||||
NU |
| (546.2 | ) | — |
| (546.2 | ) | ||||||||||||
CL&P |
| (539.4 | ) | — |
| (539.4 | ) | ||||||||||||
NSTAR Electric |
| (6.8 | ) | — |
| (6.8 | ) | ||||||||||||
|
| As of December 31, 2012 |
| As of December 31, 2013 |
| ||||||||||||||
|
| Commodity Supply and |
|
|
| Net Amount Recorded as |
| Commodity Supply and |
|
|
| Net Amount Recorded as |
| ||||||
(Millions of Dollars) | (Millions of Dollars) | Price Risk Management |
| Netting (1) |
| Derivative Asset/(Liability) |
| Price Risk Management |
| Netting (1) |
| Derivative Asset/(Liability) |
| ||||||
Current Derivative Assets: | Current Derivative Assets: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| |||
Level 2: | Level 2: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| |||
| Other (1) | $ | 0.2 |
| $ | - |
| $ | 0.2 | ||||||||||
NU (1) |
| $ | 1.9 |
| $ | (0.3 | ) | $ | 1.6 |
| |||||||||
Level 3: | Level 3: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| |||
| CL&P (1) |
| 17.7 |
|
| (12.0) |
|
| 5.7 | ||||||||||
| Other |
| 5.5 |
|
| - |
|
| 5.5 | ||||||||||
Total Current Derivative Assets | $ | 23.4 |
| $ | (12.0) |
| $ | 11.4 | |||||||||||
NU (1) |
| 18.4 |
| (9.8 | ) | 8.6 |
| ||||||||||||
CL&P (1) |
| 17.1 |
| (9.8 | ) | 7.3 |
| ||||||||||||
NSTAR Electric |
| 1.2 |
| — |
| 1.2 |
| ||||||||||||
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| |||
Long-Term Derivative Assets: | Long-Term Derivative Assets: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| |||
Level 2: |
|
|
|
|
|
|
| ||||||||||||
NU |
| $ | 0.2 |
| $ | — |
| $ | 0.2 |
| |||||||||
Level 3: | Level 3: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| |||
| CL&P (1) | $ | 159.7 |
| $ | (69.1) |
| $ | 90.6 | ||||||||||
Total Long-Term Derivative Assets | $ | 159.7 |
| $ | (69.1) |
| $ | 90.6 | |||||||||||
NU (1) |
| 116.2 |
| (42.2 | ) | 74.0 |
| ||||||||||||
CL&P (1) |
| 113.6 |
| (42.2 | ) | 71.4 |
| ||||||||||||
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| |||
Current Derivative Liabilities: | Current Derivative Liabilities: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| |||
Level 2: |
|
|
|
|
|
|
|
| |||||||||||
| Other (1) (2) | $ | (19.9) |
| $ | 0.6 |
| $ | (19.3) | ||||||||||
Level 3: | Level 3: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| |||
| CL&P |
| (96.9) |
|
| - |
|
| (96.9) | ||||||||||
| NSTAR Electric |
| (1.0) |
|
| - |
|
| (1.0) | ||||||||||
Total Current Derivative Liabilities | $ | (117.8) |
| $ | 0.6 |
| $ | (117.2) | |||||||||||
NU |
| $ | (93.7 | ) | $ | — |
| $ | (93.7 | ) | |||||||||
CL&P |
| (92.2 | ) | — |
| (92.2 | ) | ||||||||||||
NSTAR Electric |
| (1.5 | ) | — |
| (1.5 | ) | ||||||||||||
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| |||
Long-Term Derivative Liabilities: | Long-Term Derivative Liabilities: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| |||
Level 2: |
|
|
|
|
|
|
|
| |||||||||||
| Other (1) | $ | (0.2) |
| $ | - |
| $ | (0.2) | ||||||||||
Level 3: | Level 3: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| |||
| CL&P |
| (865.6) |
|
| - |
|
| (865.6) | ||||||||||
| NSTAR Electric |
| (13.9) |
|
| - |
|
| (13.9) | ||||||||||
| WMECO |
| (3.0) |
|
| - |
|
| (3.0) | ||||||||||
Total Long-Term Derivative Liabilities | $ | (882.7) |
| $ | - |
| $ | (882.7) | |||||||||||
NU |
| $ | (624.1 | ) | $ | — |
| $ | (624.1 | ) | |||||||||
CL&P |
| (617.1 | ) | — |
| (617.1 | ) | ||||||||||||
NSTAR Electric |
| (7.0 | ) | — |
| (7.0 | ) | ||||||||||||
(1)
Amounts represent derivative assets and liabilities whichthat NU has elected to record net on the balance sheets. These amounts are subject to master netting agreements or similar agreements for which the right of offset exists.
26
(2)
As of September 30, 2013 and December 31, 2012, NU had $1 million and $4.1 million, respectively, of cash posted related to these contracts, which was not offset against the derivative liability and is recorded as Prepayments and Other Current Assets on the balance sheets.
For further information on the fair value of derivative contracts, see Note 1D, "Summary“Summary of Significant Accounting Policies - Fair Value Measurements,"” to the financial statements.
Derivatives Not Designated as Hedges
Commodity Supply and Price Risk Management: As required by regulation, CL&P has capacity-related contracts with generation facilities. These contracts and similar UI contracts have an expected capacity of 787 MW. CL&P has a sharing agreement with UI, with 80 percent of each contract allocated to CL&P and 20 percent allocated to UI. The capacity contracts extend through 2026 and obligate both CL&P and UI to make or receive payments on a monthly basis to or from the generation facilities based on the difference between a set capacity price and the forward capacity market price received in the ISO-NE capacity markets. In addition, CL&P has a contract to purchase 0.1 million MWh of energy per year through 2020.2020.
NSTAR Electric has a renewable energy contract to purchase 0.1 million MWh of energy per year through 2018.NSTAR Electric also has2018 and a capacity related contract forto purchase up to 35 MW per year that extends through 2019.
PSNH has electricity procurement contracts to purchase 0.2 million MWh of energy through November 2013.
WMECO has a renewable energy contract to purchase 0.1 million MWh of energy per year through 2029 with a facility that is expected to achieve commercial operation by June 2014.
As of September 30, 2013March 31, 2014 and December 31, 2012,2013, NU had NYMEX future contracts in order to reduce variability associated with the purchase price of approximately 10.27.4 million and 11.59.1 million MMBtu of natural gas, respectively.
As of September 30, 2013 and December 31, 2012, NU had approximately 5 thousand MWh and 24 thousand MWh, respectively, of supply volumes remaining in its unregulated wholesale portfolio when expected sales are compared with supply contracts.
The following table presents the current change in fair value, primarily recovered through rates from customers, associated with NU’s derivative contracts not designated as hedges:
| Amounts Recognized on Derivatives |
| ||||||||||||||||||||
Location of Amounts | Location of Amounts |
| Amounts Recognized on Derivatives |
| For the Three Months Ended March 31, |
| ||||||||||||||||
Recognized on Derivatives | Recognized on Derivatives |
| For the Three Months Ended September 30, |
| For the Nine Months Ended September 30, |
| 2014 |
| 2013 |
| ||||||||||||
(Millions of Dollars) | (Millions of Dollars) |
| 2013 |
| 2012 |
|
| 2013 |
| 2012 |
|
|
|
|
|
| ||||||
NU | NU |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| ||||
Balance Sheet: |
|
|
|
|
|
|
|
|
|
|
| |||||||||||
Balance Sheets: |
|
|
|
|
| |||||||||||||||||
Regulatory Assets and Liabilities |
| $ | 54.1 |
| $ | 28.0 |
| |||||||||||||||
Statements of Income: |
|
|
|
|
| |||||||||||||||||
Purchased Power, Fuel and Transmission |
| — |
| 0.3 |
| |||||||||||||||||
| Regulatory Assets |
| $ | 0.3 |
| $ | 11.7 |
| $ | 48.8 |
| $ | (25.0) |
| ||||||||
Statement of Income: |
|
|
|
|
|
|
|
|
|
|
| |||||||||||
| Purchased Power, Fuel and Transmission |
|
| 0.2 |
|
| 0.2 |
| 0.9 |
| (0.8) |
| ||||||||||
Credit Risk
Certain of NU’s derivative contracts contain credit risk contingent features. These features require NU to maintain investment grade credit ratings from the major rating agencies and to post collateral for contracts in a net liability position over specified credit limits. The following summarizes the fair valueAs of March 31, 2014 and December 31, 2013, there were no derivative contracts that were in a net liability position andthat were subject to credit risk contingent features and the additional collateral that would be required to be posted by NU if the unsecured debt credit ratings of NU parent were downgraded to below investment grade:features.
| As of September 30, 2013 |
| As of December 31, 2012 | ||||||||
|
|
|
| Additional Collateral |
|
|
|
| Additional Collateral | ||
| Fair Value Subject |
| Required if |
| Fair Value Subject |
| Required if | ||||
| to Credit Risk |
| Downgraded Below |
| to Credit Risk |
| Downgraded Below | ||||
(Millions of Dollars) | Contingent Features |
| Investment Grade |
| Contingent Features |
| Investment Grade | ||||
NU | $ | (6.7) |
| $ | 13.4 |
| $ | (15.3) |
| $ | 17.4 |
Fair Value MeasurementsValuation of Derivative Instruments
Valuation of Derivative Instruments:Derivative contracts classified as Level 2 in the fair value hierarchy relate to the financial contracts for natural gas futures, forward contracts to purchase energy at PSNH and the remaining unregulated wholesale marketing sourcing contracts.futures. Prices are obtained from broker quotes and are based on actual market activity. The contracts are valued using the mid-point of the bid-ask spread. Valuations of these contracts also incorporate discount rates using the yield curve approach.
The fair value of derivative contracts classified as Level 3 utilizes significant unobservable inputs. The fair value is modeled using income techniques, such as discounted cash flow approachesvaluations adjusted for assumptions relating to exit price. Significant observable inputs for valuations of these contracts include energy and energy-related product prices in future years for which quoted prices in an active market exist. Fair value measurements categorized in Level 3 of the fair value hierarchy are prepared by individuals with expertise in valuation techniques, pricing of energy and energy-related products, and accounting requirements. The future power and capacity prices for periods that are not quoted in an active market or established at auction are based on available market data and are escalated based on estimates of inflation to address the full time period of the contract.
27
Valuations of derivative contracts using 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'scounterparty’s credit rating for assets and the company'sCompany’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, and WMECO’s, Level 3 derivative contracts and the range of the significant unobservable inputs utilized in the valuations over the duration of the contracts:
As of March 31, 2014 | As of December 31, 2013 | ||||||||||
| Range | Period Covered | Range | Period Covered | |||||||
Energy Prices: |
|
| |||||||||
|
|
|
| ||||||||
|
|
|
|
|
|
|
| ||||
NU |
|
|
| $ |
| ||||||
|
|
| 2018 - 2020 |
| $ |
| |||||
|
|
| 2018 - 2029 |
| |||||||
CL&P | $ |
| 2018 - | $ 56 - 58 per MWh | 2018 - 2029 | ||||||
|
|
|
|
|
|
|
| ||||
Capacity Prices: |
|
|
|
|
|
|
| ||||
NU | $ | 2016 - 2026 | $ 5.07 - 11.82 per kW-Month |
| 2017 - 2029 |
| |||||
CL&P | $ |
|
| ||||||||
| $ |
| 2017 - 2026 |
| |||||||
NSTAR Electric | $ |
| 2016 - | ||||||||
| $ |
| 2017 - 2019 |
| |||||||
|
|
| |||||||||
|
|
|
|
| |||||||
|
|
|
|
|
|
|
| ||||
Forward Reserve: |
|
|
|
|
|
|
| ||||
NU, CL&P | $ |
|
|
| $ |
|
| ||||
|
|
|
|
|
|
|
| ||||
REC Prices: |
|
|
|
|
|
|
| ||||
NU | $ |
|
|
|
| ||||||
|
|
|
| $ |
| ||||||
|
|
| 2014 - 2029 |
| |||||||
NSTAR Electric | $ |
|
| $ 36 - 70 per REC | 2014 - 2018 | ||||||
Exit price premiums of 109 percent through 3226 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 powerenergy or capacity prices in isolation would decrease or increase, respectively, the fair value of the derivative liability. Any increases in the risk premiums would increase the fair value of the derivative liabilities. Changes in these fair values are recorded as a regulatory asset or liability and would not impact net income.
Valuations using significant unobservable inputs: The following tables present changes for the three and nine months ended September 30,March 31, 2014 and 2013 and 2012 in the Level 3 category of derivative assets and derivative liabilities measured at fair value on a recurring basis. The derivative assets and liabilities are presented on a net basis.
|
| For the Three Months Ended March 31, |
| ||||
|
| 2014 |
| 2013 |
| ||
(Millions of Dollars) |
| NU |
| NU |
| ||
Derivatives, Net: |
|
|
|
|
| ||
Fair Value as of Beginning of Period |
| $ | (635.2 | ) | $ | (878.6 | ) |
Net Realized/Unrealized Gains Included in: |
|
|
|
|
| ||
Net Income (1) |
| — |
| 5.7 |
| ||
Regulatory Assets and Liabilities |
| 49.2 |
| 26.2 |
| ||
Settlements |
| 21.7 |
| 13.6 |
| ||
Fair Value as of End of Period |
| $ | (564.3 | ) | $ | (833.1 | ) |
|
| For the Three Months Ended |
| ||||||||||
|
| March 31, 2014 |
| March 31, 2013 |
| ||||||||
(Millions of Dollars) |
| CL&P |
| NSTAR Electric |
| CL&P |
| NSTAR Electric |
| ||||
Derivatives, Net: |
|
|
|
|
|
|
|
|
| ||||
Fair Value as of Beginning of Period |
| $ | (630.6 | ) | $ | (7.3 | ) | $ | (866.2 | ) | $ | (14.9 | ) |
Net Realized/Unrealized Gains/(Losses) Included in Regulatory Assets and Liabilities |
| 52.0 |
| (0.1 | ) | 24.3 |
| 0.7 |
| ||||
Settlements |
| 21.6 |
| 0.1 |
| 22.3 |
| 0.6 |
| ||||
Fair Value as of End of Period |
| $ | (557.0 | ) | $ | (7.3 | ) | $ | (819.6 | ) | $ | (13.6 | ) |
(1)The fair value as of January 1, 2012 reflects a reclassification of remaining unregulated wholesale marketing sourcing contracts that had previously been presented as a portfolio along withNet Income impact for the three months ended March 31, 2013 related to the unregulated wholesale marketing sales contract that was offset by the gains/(losses) on the unregulated sourcing contracts classified as Level 3 under the highest and best use valuation premise. These contracts are now classified within Level 2 ofin the fair value hierarchy.hierarchy, resulting in a total net gain of $0.3 million as of March 31, 2013.
|
| For the Three Months Ended September 30, |
| For the Nine Months Ended September 30, | ||||||||
|
| 2013 |
| 2012 |
| 2013 |
| 2012 | ||||
(Millions of Dollars) | NU |
| NU |
| NU |
| NU | |||||
Derivatives, Net: |
|
|
|
|
|
|
|
|
|
|
| |
Fair Value as of Beginning of Period | $ | (788.1) |
| $ | (932.1) |
| $ | (878.6) |
| $ | (962.2) | |
Liabilities Assumed due to Merger with NSTAR |
| - |
|
| - |
|
| - |
|
| (5.4) | |
Transfer to Level 2 |
| - |
|
| - |
|
| - |
|
| 32.2 | |
Net Realized/Unrealized Gains/(Losses) Included in: |
|
|
|
|
|
|
|
|
|
|
| |
| Net Income |
| 1.2 |
|
| (0.2) |
|
| 8.3 |
|
| 7.2 |
| Regulatory Assets |
| 0.8 |
|
| 8.5 |
|
| 49.6 |
|
| (30.1) |
Settlements |
| 21.3 |
|
| 21.5 |
|
| 55.9 |
|
| 56.0 | |
Fair Value as of End of Period | $ | (764.8) |
| $ | (902.3) |
| $ | (764.8) |
| $ | (902.3) | |
28
|
| For the Three Months Ended | ||||||||||||||||
|
| September 30, 2013 |
| September 30, 2012 | ||||||||||||||
(Millions of Dollars) | CL&P |
| NSTAR Electric |
| WMECO |
| CL&P |
| NSTAR Electric(1) |
| WMECO | |||||||
Derivatives, Net: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| |
Fair Value as of Beginning of Period | $ | (775.8) |
| $ | (13.1) |
| $ | (0.7) |
| $ | (910.7) |
| $ | (15.8) |
| $ | (13.5) | |
Net Realized/Unrealized Gains/(Losses) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| |
| Included in Regulatory Assets |
| (1.2) |
|
| 0.5 |
|
| 1.5 |
|
| (2.8) |
|
| 1.4 |
|
| 9.8 |
Settlements |
| 21.7 |
|
| 1.0 |
|
| - |
|
| 22.6 |
|
| 0.6 |
|
| - | |
Fair Value as of End of Period | $ | (755.3) |
| $ | (11.6) |
| $ | 0.8 |
| $ | (890.9) |
| $ | (13.8) |
| $ | (3.7) | |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| For the Nine Months Ended | ||||||||||||||||
|
| September 30, 2013 |
| September 30, 2012 | ||||||||||||||
(Millions of Dollars) | CL&P |
| NSTAR Electric |
| WMECO |
| CL&P |
| NSTAR Electric(1) |
| WMECO | |||||||
Derivatives, Net: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| |
Fair Value as of Beginning of Period | $ | (866.2) |
| $ | (14.9) |
| $ | (3.0) |
| $ | (931.6) |
| $ | (3.4) |
| $ | (7.3) | |
Net Realized/Unrealized Gains/(Losses) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| |
| Included in Regulatory Assets |
| 45.1 |
|
| 0.6 |
|
| 3.8 |
|
| (23.8) |
|
| (13.2) |
|
| 3.6 |
Settlements |
| 65.8 |
|
| 2.7 |
|
| - |
|
| 64.5 |
|
| 2.8 |
|
| - | |
Fair Value as of End of Period | $ | (755.3) |
| $ | (11.6) |
| $ | 0.8 |
| $ | (890.9) |
| $ | (13.8) |
| $ | (3.7) | |
(1)
NSTAR Electric amounts are included in NU consolidated from the date of the merger, April 10, 2012, through September 30, 2012.
5.
MARKETABLE SECURITIES
NU maintains a supplemental benefit trusttrusts to fund certain non-qualified executive retirement benefit obligationsbenefits and WMECO maintains a spent nuclear fuel trust to fund WMECO’s prior period spent nuclear fuel liability, each of which hold marketable securities. These trusts are not subject to regulatory oversight by state or federal agencies. NU's marketable securities also includeIn addition, CYAPC and YAEC maintain legally restricted trusts, each of which holds marketable securities, for settling the decommissioning obligations of their nuclear power plants that are owned by CYAPC and YAEC.plants.
TheIn accordance with applicable accounting guidance, the Company electselected to record mutual funds purchased by the NU supplemental benefit trustdesignated as available-for-sale at fair value. As such, any changevalue and certain other equity investments as trading securities, with the changes in fair value of these mutual funds is reflected in Net Income. These mutual funds, classified as Level 1 in the fair value hierarchy, totaled $54.3 million and $47 million as of September 30, 2013 and December 31, 2012, respectively, and are included in current Marketable Securities. Net gains on these securities of $3 million and $7.3 million for the three and nine months ended September 30, 2013, respectively, werevalues recorded in Other Income, Net on the statements of income. These amountsAs of March 31, 2014, the mutual funds and equity investments were net gains of $1.9classified as Level 1 in the fair value hierarchy and totaled $57.4 million and $4.6$24 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 $0.2 million and $4.2 million for the three and nine months ended September 30, 2012, respectively.March 31, 2014 and 2013, respectively, and net gains on the equity investments were $0.5 million for the three months ended March 31, 2014. Dividend income is recorded when dividends are declared and is recorded in Other Income, Net on the statements of income.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'sNU’s and WMECO’s available-for-sale securities held in the NU supplemental benefit trust, WMECO's spent nuclear fuel trust and CYAPC's and YAEC's nuclear decommissioning trusts.securities. These securities are recorded at fair value and included in current and long-term Marketable Securities on the balance sheets.
|
| As of September 30, 2013 |
| As of March 31, 2014 |
| ||||||||||||||||||||
|
|
|
|
| Pre-Tax |
| Pre-Tax |
|
|
|
|
| Pre-Tax |
| Pre-Tax |
|
|
| |||||||
|
| Amortized |
| Unrealized |
| Unrealized |
|
|
| Amortized |
| Unrealized |
| Unrealized |
|
|
| ||||||||
(Millions of Dollars) | (Millions of Dollars) | Cost |
| Gains(1) |
| Losses(1) |
| Fair Value |
| Cost |
| Gains(1) |
| Losses(1) |
| Fair Value |
| ||||||||
NU | NU |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| |||||||
| Debt Securities (2) | $ | 306.1 |
| $ | 1.5 |
| $ | (3.8) |
| $ | 303.8 | |||||||||||||
| Equity Securities (2) |
| 164.0 |
| 40.9 |
| - |
| 204.9 | ||||||||||||||||
Debt Securities (2) |
| $ | 300.6 |
| $ | 4.8 |
| $ | (0.7 | ) | $ | 304.7 |
| ||||||||||||
Equity Securities (2) |
| 163.3 |
| 65.6 |
| — |
| 228.9 |
| ||||||||||||||||
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| |||||||
WMECO | WMECO |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| |||||||
Debt Securities |
| 58.0 |
| — |
| (0.1 | ) | 57.9 |
| ||||||||||||||||
| Debt Securities |
| 57.8 |
| - |
| - |
| 57.8 | ||||||||||||||||
|
|
|
|
|
|
|
|
|
| ||||||||||||||||
|
| As of December 31, 2012 | |||||||||||||||||||||||
|
|
|
|
| Pre-Tax |
| Pre-Tax |
|
| ||||||||||||||||
|
| Amortized |
| Unrealized |
| Unrealized |
|
| |||||||||||||||||
(Millions of Dollars) | Cost |
| Gains(1) |
| Losses(1) |
| Fair Value | ||||||||||||||||||
NU |
|
|
|
|
|
|
|
| |||||||||||||||||
| Debt Securities (2) | $ | 266.6 |
| $ | 13.3 |
| $ | (0.1) |
| $ | 279.8 | |||||||||||||
| Equity Securities (2) |
| 145.5 |
| 20.0 |
| - |
| 165.5 | ||||||||||||||||
|
|
|
|
|
|
|
|
|
| ||||||||||||||||
WMECO |
|
|
|
|
|
|
|
| |||||||||||||||||
| Debt Securities |
| 57.7 |
| 0.1 |
| (0.1) |
| 57.7 | ||||||||||||||||
|
| As of December 31, 2013 |
| ||||||||||
|
|
|
| Pre-Tax |
| Pre-Tax |
|
|
| ||||
|
| Amortized |
| Unrealized |
| Unrealized |
|
|
| ||||
(Millions of Dollars) |
| Cost |
| Gains(1) |
| Losses(1) |
| Fair Value |
| ||||
NU |
|
|
|
|
|
|
|
|
| ||||
Debt Securities (2) |
| $ | 299.2 |
| $ | 2.5 |
| $ | (2.1 | ) | $ | 299.6 |
|
Equity Securities (2) |
| 163.6 |
| 60.5 |
| — |
| 224.1 |
| ||||
|
|
|
|
|
|
|
|
|
| ||||
WMECO |
|
|
|
|
|
|
|
|
| ||||
Debt Securities |
| 57.9 |
| — |
| — |
| 57.9 |
| ||||
(1)Unrealized gains and losses on debt securities for the NU supplemental benefit trust andheld by WMECO spent nuclear fuel trust are recorded in AOCI and Other Long-Term Assets respectively, on the balance sheets.
(2)
NU'sNU’s amounts include CYAPC'sCYAPC’s and YAEC'sYAEC’s marketable securities held in nuclear decommissioning trusts of $403.1$435.9 million and $340.4$424 million as of September 30, 2013March 31, 2014 and December 31, 2012,2013, respectively, the majority of which are legally restricted and can only be used for the decommissioning of the nuclear power plants owned by these companies. In the first quarter of 2013, CYAPC
29
and YAEC received cash from the DOE related to the litigation of storage costs for spent nuclear fuel, which was invested in the nuclear decommissioning trusts. Unrealized gains and losses for the nuclear decommissioning trusts are offset in Other Long-Term Liabilities on the balance sheets, with no impact on the statementstatements of income. All of the equity securities accounted for as available-for-sale securities are held in these trusts.
Unrealized Losses and Other-than-Temporary Impairment: There have been no significant unrealized losses, other-than-temporary impairments or credit losses for the NU supplemental benefit trust, the WMECO spent nuclear fuel trust, and the trusts held by CYAPC and YAEC.Factorsor 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 the NU supplementalNU’s benefit trust, Other Long-Term Assets for the WMECO, spent nuclear fuel trust, and offset in Other Long-Term Liabilities for CYAPC and YAEC. NU utilizes the specific identification basis method for the NU supplemental benefit trust securities and the average cost basis method for the WMECO spent nuclear fuel trust and the CYAPC and YAEC nuclear decommissioning trusts to compute the realized gains and losses on the sale of available-for-sale securities.
Contractual Maturities: As of September 30, 2013,March 31, 2014, the contractual maturities of available-for-sale debt securities are as follows:
|
| NU |
| WMECO |
| NU |
| WMECO |
| ||||||||||||||||
|
| Amortized |
|
|
| Amortized |
|
|
| Amortized |
|
|
| Amortized |
|
|
| ||||||||
(Millions of Dollars) | (Millions of Dollars) | Cost |
| Fair Value |
| Cost |
| Fair Value |
| Cost |
| Fair Value |
| Cost |
| Fair Value |
| ||||||||
Less than one year (1) | Less than one year (1) | $ | 67.1 |
| $ | 65.3 |
| $ | 24.4 |
| $ | 24.6 |
| $ | 54.5 |
| $ | 54.4 |
| $ | 19.2 |
| $ | 19.2 |
|
One to five years | One to five years |
| 76.0 |
| 76.6 |
| 26.4 |
| 26.3 |
| 73.3 |
| 73.9 |
| 33.2 |
| 33.2 |
| |||||||
Six to ten years | Six to ten years |
| 58.4 |
| 57.3 |
| 2.5 |
| 2.5 |
| 68.1 |
| 69.4 |
| 1.6 |
| 1.6 |
| |||||||
Greater than ten years | Greater than ten years |
| 104.6 |
|
| 104.6 |
|
| 4.5 |
|
| 4.4 |
| 104.7 |
| 107.0 |
| 4.0 |
| 3.9 |
| ||||
Total Debt Securities | Total Debt Securities | $ | 306.1 |
| $ | 303.8 |
| $ | 57.8 |
| $ | 57.8 |
| $ | 300.6 |
| $ | 304.7 |
| $ | 58.0 |
| $ | 57.9 |
|
(1)
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:
|
|
| NU |
| WMECO |
| NU |
| WMECO |
| |||||||||||||||||
|
|
| As of |
| As of |
| As of |
| As of |
| |||||||||||||||||
(Millions of Dollars) | (Millions of Dollars) | September 30, 2013 |
| December 31, 2012 |
| September 30, 2013 |
| December 31, 2012 |
| March 31, 2014 |
| December 31, 2013 |
| March 31, 2014 |
| December 31, 2013 |
| ||||||||||
Level 1: | Level 1: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| |||||||||
| Mutual Funds and Equities | $ | 259.2 |
| $ | 212.5 |
| $ | - |
| $ | - | |||||||||||||||
| Money Market Funds |
| 40.0 |
|
| 40.2 |
|
| 2.8 |
|
| 5.2 | |||||||||||||||
Mutual Funds and Equities |
| $ | 310.3 |
| $ | 281.3 |
| $ | — |
| $ | — |
| ||||||||||||||
Money Market Funds |
| 22.5 |
| 32.9 |
| 4.3 |
| 10.9 |
| ||||||||||||||||||
Total Level 1 | Total Level 1 | $ | 299.2 |
| $ | 252.7 |
| $ | 2.8 |
| $ | 5.2 |
| $ | 332.8 |
| $ | 314.2 |
| $ | 4.3 |
| $ | 10.9 |
| ||
Level 2: | Level 2: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| |||||||||
| U.S. Government Issued Debt Securities |
|
|
|
|
|
|
|
| ||||||||||||||||||
|
| (Agency and Treasury) | $ | 74.9 |
| $ | 69.9 |
| $ | 16.6 |
| $ | 18.7 | ||||||||||||||
| Corporate Debt Securities |
| 48.9 |
| 33.0 |
| 15.1 |
| 7.0 | ||||||||||||||||||
| Asset-Backed Debt Securities |
| 30.4 |
| 28.5 |
| 9.6 |
| 10.9 | ||||||||||||||||||
| Municipal Bonds |
| 93.7 |
| 93.8 |
| 8.8 |
| 11.6 | ||||||||||||||||||
| Other Fixed Income Securities |
| 15.9 |
|
| 14.4 |
|
| 4.9 |
|
| 4.3 | |||||||||||||||
U.S. Government Issued Debt Securities (Agency and Treasury) |
| $ | 56.7 |
| $ | 61.4 |
| $ | — |
| $ | 6.8 |
| ||||||||||||||
Corporate Debt Securities |
| 56.3 |
| 53.6 |
| 14.1 |
| 15.1 |
| ||||||||||||||||||
Asset-Backed Debt Securities |
| 35.3 |
| 30.4 |
| 14.0 |
| 9.0 |
| ||||||||||||||||||
Municipal Bonds |
| 109.6 |
| 105.5 |
| 12.3 |
| 11.2 |
| ||||||||||||||||||
Other Fixed Income Securities |
| 24.3 |
| 15.8 |
| 13.2 |
| 4.9 |
| ||||||||||||||||||
Total Level 2 | Total Level 2 | $ | 263.8 |
| $ | 239.6 |
| $ | 55.0 |
| $ | 52.5 |
| $ | 282.2 |
| $ | 266.7 |
| $ | 53.6 |
| $ | 47.0 |
| ||
Total Marketable Securities | Total Marketable Securities | $ | 563.0 |
| $ | 492.3 |
| $ | 57.8 |
| $ | 57.7 |
| $ | 615.0 |
| $ | 580.9 |
| $ | 57.9 |
| $ | 57.9 |
| ||
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.
6.
SHORT-TERM AND LONG-TERM DEBT
Limits: The amount of short-term borrowings that may be incurred by CL&P and WMECO is subject to periodic approval by the FERC. On July 31, 2013, the FERC approved the short-term debt application of CL&P and WMECO for issuances in the amounts of $600 million and $300 million, respectively, effective January 1, 2014 through December 31, 2015.
Credit Agreements and Commercial Paper Programs: On September 6, 2013, NU parent, CL&P, NSTAR LLC,PSNH, WMECO, NSTAR Gas PSNH, WMECO and Yankee Gas amended their jointare parties to a five-year $1.15$1.45 billion revolving credit facility dated July 25, 2012, by increasing the aggregate principal amount available thereunder by $300 milliondue to $1.45 billion, extending the expiration date from July 25, 2017 toexpire on September 6, 2018, and increasing CL&P's borrowing sublimit from $300 million to $600 million. At the same time, effective September 6, 2013, the CL&P $300 million2018. The revolving credit facility was terminated.
On September 6, 2013, NSTAR Electric amended its five-year $450 million revolving credit facility dated July 25, 2012 by extendingis to be used primarily to backstop the expiration date from July 25, 2017 to September 6, 2018.
On September 6, 2013, the NU parent $1.15$1.45 billion commercial paper program was increased by $300 millionat NU. The commercial paper program allows NU parent to $1.45 billion.
issue commercial paper as a form of short-term debt. As of September 30, 2013March 31, 2014 and December 31, 2012,2013, NU had approximately $1.2 billion$818.5 million and $1.15$1.01 billion, respectively, in short-term borrowings outstanding under the NU parent commercial paper program, which provides $263leaving $631.5 million and $435.5 million of available borrowing capacity as of September 30, 2013.March 31, 2014 and December 31, 2013, respectively. The weighted-average interest rate on these borrowings as of September 30, 2013March 31, 2014 and December 31, 20122013 was 0.2680.23 percent and 0.460.24 percent, respectively, which is generally based on money market rates. As of September 30,March 31, 2014, there were intercompany loans from NU of $351.6 million to CL&P, $39.9 million to PSNH and $37.4 million to WMECO. As of December 31, 2013, there were intercompany loans from NU of $342.9$287.3 million to CL&P $228.5and $86.5 million to PSNH and $79.8PSNH.
NSTAR Electric has a five-year $450 million revolving credit facility due to WMECO.expire on September 6, 2018. This facility serves to backstop NSTAR Electric’s existing $450 million commercial paper program. As of March 31, 2014, NSTAR Electric had no borrowings outstanding under its commercial paper program. As of December 31, 2012, there were intercompany loans from NU of $405.1 million to CL&P, $63.3 million to PSNH, and $31.9 million to WMECO. As of September 30, 2013, and December 31, 2012, NSTAR Electric had $156$103.5 million and $276 million, respectively, in short-term borrowings outstanding under its commercial paper program, leaving $294$346.5 million and $174 million, respectively, of available borrowing capacity. The weighted-average interest rate on these borrowings as of September 30, 2013 and December 31, 20122013 was 0.1340.13 percent, and 0.31 percent, respectively, which is generally based on money market rates.
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 Affiliated CompaniesNU Parent and classified in current liabilities on the balance sheets.
See the Long-Term Debt:Debt On January 15, 2013, CL&P issued $400 millionportion of Series A First and Refunding Mortgage Bonds with a coupon rate of 2.5 percent and a maturity date of January 15, 2023. The proceeds, net of issuance costs, were used to pay short-term borrowings outstanding underthis Note for further information on the CL&P credit agreement$250 million bond issuance and the Yankee Gas $100 million bond issuance and their impacts on the NU parent commercial paper program. Therefore,balance sheet as of March 31, 2014 and December 31, 2012, CL&P's credit agreement borrowings of $89 million and intercompany loans related to the commercial paper program of $305.8 million were classified as 2013, respectively.
Long-Term Debt on the balance sheet.
Debt: On May 1, 2013, PSNH redeemed at par approximately $109January 2, 2014, Yankee Gas issued $100 million of the 20014.82 percent Series C PCRBs that wereL First Mortgage Bonds, due to mature in 2021 using short-term debt.
On May 13, 2013, NU parent issued $750 million of Senior Notes, consisting of $300 million of Series E Senior Notes at a coupon rate of 1.45 percent that will mature on May 1, 2018 and $450 million of Series F Senior Notes at a coupon rate of 2.80 percent that will mature on May 1, 2023. Part of the proceeds, net of issuance costs, was used to repay the NU parent $250 million Series C Senior Notes at a coupon rate of 5.65 percent that matured on June 1, 2013 and the NU parent $300 million floating rate Series D Senior Notes that matured on September 20, 2013. The remaining net proceeds were used to repay commercial paper borrowings and for other general corporate purposes.
On May 17, 2013, NSTAR Electric issued $200 million of three-year floating rate debentures due to mature on May 17, 2016.2044. The proceeds, net of issuance costs, were used to repay commercial paper borrowingsthe $75 million 4.80 percent Series G First Mortgage Bonds that matured on January 1, 2014 and for general corporate purposes. The debentures have a coupon rate reset quarterly basedto pay $25 million in short-term borrowings. In accordance with applicable accounting guidance, these amounts were classified as Long-Term Debt on 3-month LIBOR plus a credit spread of 0.24 percent. The interest rateNU’s balance sheet as of September 30, 2013 was 0.5032 percent.December 31, 2013.
On September 1, 2013, WMECO repaid at maturity, $55 million of 5.00 percent Series A Senior Notes using short-term debt.
On September 3, 2013, CL&P redeemed at par $125 million of 1.25 percent Series B 2011 PCRBs that were subject to mandatory tender for purchase using short-term debt.
On September 20, 2013, NU parent repaid at maturity,March 7, 2014, NSTAR Electric issued $300 million of Floating Rate Series D Senior Notes with4.40 percent debentures, due to mature in 2044. The proceeds, from NU parent’snet of issuance on May 13, 2013 of $750costs, were used to repay the $300 million of Series E and Series F Senior Notes.4.875 percent debentures that matured on April 15, 2014.
On August 29, 2013, NSTAR Electric filed an applicationApril 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. In accordance with the DPU requesting authorization to issue up to $800applicable accounting guidance, Notes Payable of $247.4 million in long-term debt for the two-year period ending Decemberwere classified as Long-Term Debt on NU’s balance sheet as of March 31, 2015. 2014.
31
On September 26, 2013, the NHPUC issued an order, effective October 8, 2013, approving PSNH's request to issue up to $315 million in long-term debt through December 31, 2014, and to refinance $89.3 million 2001 Series B PCRBs through its existing maturity of May 2021.
Working Capital: Each of NU, CL&P, NSTAR Electric, PSNH and WMECO use theirits available capital resources to fund theirits respective construction expenditures, meet debt requirements, pay operating costs, including storm-related costs, pay dividends and fund other corporate obligations, such as pension contributions. The current growth in NU’s transmission construction expenditures utilizes a significant amount of cash for projects that have a long-term return on investment and recovery period. In addition, NU’s Regulated companies operate in an environment where recovery of itsrecover their electric and natural gas distribution construction expenditures takes placeas the related project costs are depreciated over an extended periodthe life of time.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 $1.4 billion, $392$424 million, $315 million, $114$355 million and $11$177 million at NU, CL&P and NSTAR Electric, PSNH and WMECO, respectively, as of September 30, 2013.March 31, 2014.
As of September 30, 2013, approximately $577March 31, 2014, $501.7 million of NU'sNU’s obligations classified as current liabilities relatedrelates to long-term debt that will be paid in the next 12 months, primarily consisting of $150 million for CL&P, $302$301.7 million for NSTAR Electric and $50 million for PSNH. In addition, $28.8 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 and/or with the issuance of new long-term debt, as deemed appropriate givendetermined considering capital requirements and maintenance of NU'sNU’s credit rating and profile. Management expects the future operating cash flows of NU, CL&P, NSTAR Electric, PSNH and WMECO, along with the access to financial markets, will be sufficient to meet any future operating requirements and forecasted capital investment forecasted opportunities.
7.PENSION BENEFITS AND POSTRETIREMENT BENEFITS OTHER THAN PENSIONS
The components of net periodic benefit expense for the Pension, Plans (including the SERP Plans) and PBOP Plans are detailed below. The net periodic benefit expense less the capitalized portion of pension and PBOP amounts capitalized relatedis included in Operations and Maintenance on the statements of income. Capitalized pension and PBOP amounts relate to employees working on capital projects and intercompanyare included in Property, Plant and Equipment, Net. Intercompany allocations are not included in the net periodic benefit expense are as follows:amounts.
|
| Pension and SERP |
| Pension and SERP |
| Pension and SERP |
| ||||||||||||
|
| For the Three Months Ended |
| For the Nine Months Ended |
| For the Three Months Ended |
| ||||||||||||
|
| September 30, 2013 |
| September 30, 2012 |
| September 30, 2013 |
| September 30, 2012 |
| March 31, 2014 |
| March 31, 2013 |
| ||||||
(Millions of Dollars) | (Millions of Dollars) | NU |
| NU |
| NU |
| NU |
| NU |
| NU |
| ||||||
Service Cost | Service Cost | $ | 25.6 |
| $ | 23.0 |
| $ | 76.7 |
| $ | 61.1 |
| $ | 22.3 |
| $ | 26.6 |
|
Interest Cost | Interest Cost |
| 51.7 |
| 53.3 |
|
| 155.0 |
| 144.7 |
| 56.6 |
| 51.4 |
| ||||
Expected Return on Plan Assets | Expected Return on Plan Assets |
| (69.5) |
| (59.5) |
|
| (208.5) |
| (161.3) |
| (77.7 | ) | (70.3 | ) | ||||
Actuarial Loss | Actuarial Loss |
| 52.4 |
| 47.4 |
|
| 158.1 |
| 125.0 |
| 33.0 |
| 52.9 |
| ||||
Prior Service Cost | Prior Service Cost |
| 1.1 |
|
| 2.0 |
|
| 3.0 |
|
| 6.1 |
| 1.1 |
| 1.1 |
| ||
Total Net Periodic Benefit Expense | Total Net Periodic Benefit Expense | $ | 61.3 |
| $ | 66.2 |
| $ | 184.3 |
| $ | 175.6 |
| $ | 35.3 |
| $ | 61.7 |
|
Capitalized Pension Expense | Capitalized Pension Expense | $ | 18.3 |
| $ | 19.2 |
| $ | 54.9 |
| $ | 49.5 |
| $ | 9.7 |
| $ | 16.7 |
|
|
|
|
|
|
|
|
|
|
|
| |||||||||
|
| PBOP |
| PBOP | |||||||||||||||
|
| For the Three Months Ended |
| For the Nine Months Ended | |||||||||||||||
|
| September 30, 2013 |
| September 30, 2012 |
| September 30, 2013 |
| September 30, 2012 | |||||||||||
(Millions of Dollars) | NU |
| NU |
| NU |
| NU | ||||||||||||
Service Cost | $ | 4.2 |
| $ | 4.4 |
| $ | 12.6 |
| $ | 11.3 | ||||||||
Interest Cost |
| 11.8 |
| 14.3 |
|
| 35.4 |
| 34.4 | ||||||||||
Expected Return on Plan Assets |
| (13.9) |
| (11.1) |
|
| (41.6) |
| (28.1) | ||||||||||
Actuarial Loss |
| 6.5 |
| 10.3 |
|
| 19.5 |
| 25.5 | ||||||||||
Prior Service Credit |
| (0.5) |
| (0.5) |
|
| (1.5) |
| (0.9) | ||||||||||
Net Transition Obligation Cost |
| - |
|
| 3.1 |
|
| - |
|
| 9.0 | ||||||||
Total Net Periodic Benefit Expense | $ | 8.1 |
| $ | 20.5 |
| $ | 24.4 |
| $ | 51.2 | ||||||||
Capitalized PBOP Expense | $ | 2.6 |
| $ | 5.1 |
| $ | 7.6 |
| $ | 14.9 | ||||||||
|
| Pension and SERP |
| PBOP |
| ||||||||||||||||||||||||||
|
| For the Three Months Ended September 30, 2013 |
| For the Three Months Ended September 30, 2012 |
| For the Three Months Ended |
| ||||||||||||||||||||||||
|
|
|
|
| NSTAR |
|
|
|
|
|
|
|
| NSTAR |
|
|
|
|
| March 31, 2014 |
| March 31, 2013 |
| ||||||||
(Millions of Dollars) | (Millions of Dollars) | CL&P |
| Electric(1) |
| PSNH |
| WMECO |
| CL&P |
| Electric(1) |
| PSNH |
| WMECO |
| NU |
| NU |
| ||||||||||
Service Cost | Service Cost | $ | 6.3 |
| $ | 8.3 |
| $ | 3.3 |
| $ | 1.2 |
| $ | 5.4 |
| $ | 7.6 |
| $ | 2.9 |
| $ | 1.0 |
| $ | 3.0 |
| $ | 4.8 |
|
Interest Cost | Interest Cost |
| 12.1 |
| 14.5 |
| 5.8 |
| 2.5 |
| 12.9 |
| 14.7 |
| 6.1 |
| 2.6 |
| 12.6 |
| 12.8 |
| |||||||||
Expected Return on Plan Assets | Expected Return on Plan Assets |
| (18.4) |
| (21.1) |
| (9.2) |
| (4.3) |
| (17.7) |
| (16.4) |
| (7.2) |
| (4.1) |
| (15.7 | ) | (13.8 | ) | |||||||||
Actuarial Loss | Actuarial Loss |
| 13.9 |
| 14.4 |
| 5.4 |
| 2.9 |
| 12.6 |
| 15.7 |
| 4.2 |
| 2.7 |
| 3.0 |
| 8.2 |
| |||||||||
Prior Service Cost/(Credit) |
| 0.4 |
|
| - |
|
| 0.1 |
|
| 0.1 |
|
| 0.9 |
|
| (0.1) |
|
| 0.4 |
|
| 0.2 | ||||||||
Prior Service Credit |
| (0.6 | ) | (0.6 | ) | ||||||||||||||||||||||||||
Total Net Periodic Benefit Expense | Total Net Periodic Benefit Expense | $ | 14.3 |
| $ | 16.1 |
| $ | 5.4 |
| $ | 2.4 |
| $ | 14.1 |
| $ | 21.5 |
| $ | 6.4 |
| $ | 2.4 |
| $ | 2.3 |
| $ | 11.4 |
|
Intercompany Allocations | $ | 11.4 |
| $ | (2.1) |
| $ | 2.6 |
| $ | 2.0 |
| $ | 10.7 |
| $ | (3.0) |
| $ | 2.4 |
| $ | 2.1 | ||||||||
Capitalized Pension Expense | $ | 7.0 |
| $ | 9.8 |
| $ | 1.7 |
| $ | 1.3 |
| $ | 6.8 |
| $ | 8.4 |
| $ | 1.9 |
| $ | 1.3 | ||||||||
| |||||||||||||||||||||||||||||||
Capitalized PBOP Expense |
| $ | 0.4 |
| $ | 3.5 |
| ||||||||||||||||||||||||
|
| Pension and SERP |
| ||||||||||||||||||||||
|
| For the Three Months Ended March 31, 2014 |
| For the Three Months Ended March 31, 2013 |
| ||||||||||||||||||||
|
|
|
| NSTAR |
|
|
|
|
|
|
| NSTAR |
|
|
|
|
| ||||||||
(Millions of Dollars) |
| CL&P |
| Electric |
| PSNH |
| WMECO |
| CL&P |
| Electric(1) |
| PSNH |
| WMECO |
| ||||||||
Service Cost |
| $ | 5.2 |
| $ | 4.6 |
| $ | 2.8 |
| $ | 1.0 |
| $ | 6.1 |
| $ | 9.3 |
| $ | 3.3 |
| $ | 1.2 |
|
Interest Cost |
| 13.3 |
| 10.2 |
| 6.5 |
| 2.7 |
| 12.1 |
| 14.2 |
| 6.0 |
| 2.5 |
| ||||||||
Expected Return on Plan Assets |
| (19.4 | ) | (15.8 | ) | (10.2 | ) | (4.6 | ) | (18.5 | ) | (22.0 | ) | (7.7 | ) | (4.3 | ) | ||||||||
Actuarial Loss |
| 9.1 |
| 5.8 |
| 3.3 |
| 1.9 |
| 14.1 |
| 14.5 |
| 5.5 |
| 3.0 |
| ||||||||
Prior Service Cost |
| 0.5 |
| — |
| 0.2 |
| 0.1 |
| 0.5 |
| — |
| 0.1 |
| 0.1 |
| ||||||||
Total Net Periodic Benefit Expense |
| $ | 8.7 |
| $ | 4.8 |
| $ | 2.6 |
| $ | 1.1 |
| $ | 14.3 |
| $ | 16.0 |
| $ | 7.2 |
| $ | 2.5 |
|
Intercompany Allocations |
| $ | 6.8 |
| $ | 2.4 |
| $ | 1.9 |
| $ | 1.3 |
| $ | 10.7 |
| $ | (2.0 | ) | $ | 2.6 |
| $ | 1.8 |
|
Capitalized Pension Expense |
| $ | 4.9 |
| $ | 1.9 |
| $ | 0.9 |
| $ | 0.8 |
| $ | 7.0 |
| $ | 5.3 |
| $ | 2.2 |
| $ | 1.3 |
|
|
| PBOP |
| |||||||||||||||||||
|
| For the Three Months Ended March 31, 2014 |
| For the Three Months Ended March 31, 2013 |
| |||||||||||||||||
(Millions of Dollars) |
| CL&P |
| NSTAR |
| PSNH |
| WMECO |
| CL&P |
| PSNH |
| WMECO |
| |||||||
Service Cost |
| $ | 0.6 |
| $ | 0.7 |
| $ | 0.4 |
| $ | 0.1 |
| $ | 0.9 |
| $ | 0.6 |
| $ | 0.2 |
|
Interest Cost |
| 2.1 |
| 4.9 |
| 1.1 |
| 0.5 |
| 2.0 |
| 1.0 |
| 0.4 |
| |||||||
Expected Return on Plan Assets |
| (2.7 | ) | (6.4 | ) | (1.4 | ) | (0.6 | ) | (2.5 | ) | (1.3 | ) | (0.6 | ) | |||||||
Actuarial Loss/(Gain) |
| 1.1 |
| (0.1 | ) | 0.5 |
| 0.1 |
| 1.7 |
| 0.9 |
| 0.3 |
| |||||||
Prior Service Credit |
| — |
| (0.5 | ) | — |
| — |
| — |
| — |
| — |
| |||||||
Total Net Periodic Benefit Expense/(Income) |
| $ | 1.1 |
| $ | (1.4 | ) | $ | 0.6 |
| $ | 0.1 |
| $ | 2.1 |
| $ | 1.2 |
| $ | 0.3 |
|
Intercompany Allocations |
| $ | 1.1 |
| $ | 0.1 |
| $ | 0.3 |
| $ | 0.2 |
| $ | 1.6 |
| $ | 0.4 |
| $ | 0.3 |
|
Capitalized PBOP Expense/(Income) |
| $ | 0.5 |
| $ | (0.5 | ) | $ | 0.2 |
| $ | 0.1 |
| $ | 1.2 |
| $ | 0.3 |
| $ | 0.2 |
|
32
|
| Pension and SERP | ||||||||||||||||||||||
|
| For the Nine Months Ended September 30, 2013 |
| For the Nine Months Ended September 30, 2012 | ||||||||||||||||||||
|
|
|
|
| NSTAR |
|
|
|
|
|
|
|
|
|
| NSTAR |
|
|
|
|
|
| ||
(Millions of Dollars) | CL&P |
| Electric(1) |
| PSNH |
| WMECO |
| CL&P |
| Electric(1) |
| PSNH |
| WMECO | |||||||||
Service Cost | $ | 18.7 |
| $ | 24.8 |
| $ | 9.8 |
| $ | 3.5 |
| $ | 16.3 |
| $ | 22.7 |
| $ | 8.8 |
| $ | 3.1 | |
Interest Cost |
| 36.3 |
|
| 43.5 |
|
| 17.8 |
|
| 7.5 |
|
| 38.5 |
|
| 44.2 |
|
| 18.3 |
|
| 7.9 | |
Expected Return on Plan Assets |
| (55.4) |
|
| (63.3) |
|
| (26.2) |
|
| (13.0) |
|
| (52.8) |
|
| (49.2) |
|
| (21.1) |
|
| (12.3) | |
Actuarial Loss |
| 42.0 |
|
| 43.6 |
|
| 16.2 |
|
| 8.9 |
|
| 37.0 |
|
| 47.3 |
|
| 12.1 |
|
| 8.0 | |
Prior Service Cost/(Credit) |
| 1.4 |
|
| (0.2) |
|
| 0.4 |
|
| 0.3 |
|
| 2.7 |
|
| (0.4) |
|
| 1.1 |
|
| 0.6 | |
Total Net Periodic Benefit Expense | $ | 43.0 |
| $ | 48.4 |
| $ | 18.0 |
| $ | 7.2 |
| $ | 41.7 |
| $ | 64.6 |
| $ | 19.2 |
| $ | 7.3 | |
Intercompany Allocations | $ | 33.6 |
| $ | (6.2) |
| $ | 7.8 |
| $ | 6.0 |
| $ | 32.0 |
| $ | (9.2) |
| $ | 7.5 |
| $ | 6.0 | |
Capitalized Pension Expense | $ | 21.0 |
| $ | 21.6 |
| $ | 5.6 |
| $ | 3.9 |
| $ | 20.2 |
| $ | 23.6 |
| $ | 5.8 |
| $ | 3.7 | |
|
| PBOP | ||||||||||||||||
|
| For the Three Months Ended September 30, 2013 |
| For the Three Months Ended September 30, 2012 | ||||||||||||||
(Millions of Dollars) | CL&P |
|
| PSNH |
|
| WMECO |
| CL&P |
| PSNH |
| WMECO | |||||
Service Cost | $ | 0.9 |
| $ | 0.6 |
| $ | 0.2 |
| $ | 0.8 |
| $ | 0.5 |
| $ | 0.1 | |
Interest Cost |
| 2.0 |
|
| 1.0 |
|
| 0.4 |
|
| 2.3 |
|
| 1.1 |
|
| 0.5 | |
Expected Return on Plan Assets |
| (2.5) |
|
| (1.3) |
|
| (0.6) |
|
| (2.3) |
|
| (1.1) |
|
| (0.5) | |
Actuarial Loss |
| 1.8 |
|
| 0.9 |
|
| 0.3 |
|
| 1.9 |
|
| 0.9 |
|
| 0.3 | |
Net Transition Obligation Cost |
| - |
|
| - |
|
| - |
|
| 1.5 |
|
| 0.6 |
|
| 0.3 | |
Total Net Periodic Benefit Expense | $ | 2.2 |
| $ | 1.2 |
| $ | 0.3 |
| $ | 4.2 |
| $ | 2.0 |
| $ | 0.7 | |
Intercompany Allocations | $ | 1.7 |
| $ | 0.4 |
| $ | 0.3 |
| $ | 2.0 |
| $ | 0.5 |
| $ | 0.4 | |
Capitalized PBOP Expense | $ | 1.3 |
| $ | 0.4 |
| $ | 0.3 |
| $ | 2.1 |
| $ | 0.6 |
| $ | 0.4 | |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| PBOP | ||||||||||||||||
|
| For the Nine Months Ended September 30, 2013 |
| For the Nine Months Ended September 30, 2012 | ||||||||||||||
(Millions of Dollars) | CL&P |
|
| PSNH |
|
| WMECO |
| CL&P |
| PSNH |
| WMECO | |||||
Service Cost | $ | 2.6 |
| $ | 1.7 |
| $ | 0.5 |
| $ | 2.2 |
| $ | 1.5 |
| $ | 0.4 | |
Interest Cost |
| 5.9 |
|
| 3.1 |
|
| 1.3 |
|
| 6.9 |
|
| 3.4 |
|
| 1.5 | |
Expected Return on Plan Assets |
| (7.6) |
|
| (3.9) |
|
| (1.7) |
|
| (6.8) |
|
| (3.4) |
|
| (1.6) | |
Actuarial Loss |
| 5.6 |
|
| 2.7 |
|
| 0.8 |
|
| 5.7 |
|
| 2.7 |
|
| 0.9 | |
Net Transition Obligation Cost |
| - |
|
| - |
|
| - |
|
| 4.6 |
|
| 1.9 |
|
| 1.1 | |
Total Net Periodic Benefit Expense | $ | 6.5 |
| $ | 3.6 |
| $ | 0.9 |
| $ | 12.6 |
| $ | 6.1 |
| $ | 2.3 | |
Intercompany Allocations | $ | 5.3 |
| $ | 1.2 |
| $ | 1.0 |
| $ | 5.9 |
| $ | 1.5 |
| $ | 1.1 | |
Capitalized PBOP Expense | $ | 3.7 |
| $ | 1.1 |
| $ | 0.7 |
| $ | 6.2 |
| $ | 1.7 |
| $ | 1.1 | |
(1)
NSTAR Electric'sElectric’s pension amounts for the three months ended March 31, 2013 do not include SERP expense. NSTAR Electric pension amounts are included in NU consolidated from
For the date ofthree months ended March 31, 2013, the merger, April 10, 2012, through September 30, 2012.
The net periodic postretirementPBOP expense allocated to NSTAR Electric was $1.2 million$4.3 million.
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 $8.5PBOP 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 March 31, 2014, the liabilities associated with the Pension, SERP and PBOP plans for NSTAR Electric were $74.8 million for the three months ended September 30, 2013 and 2012, respectively, andPension Plan, $3.5 million and $25.6 million for the nine months ended September 30, 2013 and 2012, respectively.
Contributions:For the nine months ended September 30, 2013, NU contributed $202.7 million to the NUSCO Pension Plan, $108.3SERP Plans ($0.4 million of which was contributed by PSNH,is included in other current liabilities) and NSTAR Electric contributed $82$73 million tofor the PBOP
Plan. As of December 31, 2013, the liability associated with the NSTAR Pension Plan. NU contributed $53.6 million to the PBOP PlansPlan for the nine months ended September 30, 2013.
8.
INCOME TAXES
2013 Massachusetts: On July 24, 2013, Massachusetts enacted a law that changesNSTAR Electric was $118 million. This change had no impact on the income tax rate applicable to utility companies effective January 1, 2014, from 6.5 percent to 8 percent. The tax law change required NU to remeasure its deferred taxes and resulted in NU increasing its deferred tax liability with an offsetting regulatory assetstatement or net assets of approximately $61 million at its utility companies ($46.4 million at NSTAR Electric and $9.8 million at WMECO). Electric.
2013 Federal: On September 13, 2013, the Internal Revenue Service issued final Tangible Property regulations. The final regulations are meant to simplify, clarify and make more administrable the previously issued temporary and proposed regulations. In the third quarter of 2013, CL&P recorded an after-tax valuation allowance of $10.5 million against its deferred tax assets as a result of these regulations. NU continues to evaluate the implications of these new regulations, including several new elections. Therefore, a change to the valuation allowance at CL&P could result once NU completes the review of the impact of the final regulations.
9.
8.COMMITMENTS AND CONTINGENCIES
A.
Environmental Matters
General: NU, CL&P, NSTAR Electric, PSNH and WMECO are subject to environmental laws and regulations intended to mitigate or remove the effect of past operations and improve or maintain the quality of the environment. These laws and regulations require the removal or the remedy of the effect on the environment of the disposal or release of certain specified hazardous substances at current and former operating sites. NU, CL&P, NSTAR Electric, PSNH and WMECO have an active environmental auditing and training program and believe that they are substantially in compliance with all enacted laws and regulations.
33
The number of environmental sites and reserves related to these sites for which remediation or long-term monitoring, preliminary site work or site assessment are being performed are as follows:
|
| As of September 30, 2013 |
| As of December 31, 2012 |
| As of March 31, 2014 |
| As of December 31, 2013 |
| ||||||||||||||||
|
|
|
|
| Reserve |
|
|
|
|
| Reserve |
|
|
|
| Reserve |
|
|
| Reserve |
| ||||
|
| Number of Sites |
| (in millions) |
|
| Number of Sites |
| (in millions) |
|
| Number of Sites |
| (in millions) |
| Number of Sites |
| (in millions) |
| ||||||
NU |
|
| 68 |
| $ | 36.5 |
| 77 |
| $ | 39.4 |
|
| 66 |
| $ | 35.4 |
| 68 |
| $ | 35.4 |
| ||
CL&P |
|
| 18 |
| 3.5 |
| 19 |
| 3.7 |
|
| 18 |
| 3.4 |
| 18 |
| 3.4 |
| ||||||
NSTAR Electric |
|
| 12 |
| 1.2 |
| 16 |
| 1.7 |
|
| 12 |
| 1.2 |
| 12 |
| 1.2 |
| ||||||
PSNH |
|
| 15 |
| 5.6 |
| 16 |
| 4.9 |
|
| 13 |
| 5.4 |
| 15 |
| 5.4 |
| ||||||
WMECO |
|
| 5 |
| 0.4 |
| 6 |
| 0.6 |
|
| 5 |
| 0.4 |
| 5 |
| 0.4 |
| ||||||
Included in the NU number of sites and reserve amounts above are former MGP sites that were operated several decades ago and manufactured gas from coal and other processes, which resulted in certain by-products remaining in the environment that may pose a potential risk to human health and the environment. The reserve balance related to these former MGP sites was $32.4$30.9 million and $34.5$31.4 million as of September 30, 2013March 31, 2014 and December 31, 2012,2013, respectively, and relates primarily to the natural gas business segment.
B.Contractual Obligations — Yankee Companies
Long-Term Contractual Arrangements
Yankee Billings: As a result of the change in forecasted life of spent nuclear fuel decommissioning obligations, as well as proceeds received from the DOE in January 2013 arising from the spent nuclear fuel litigation, estimated future annual costs of Yankee Billings as of September 30, 2013 are reflected in the table below.
Renewable Energy: Renewable energy contracts include non-cancelable commitments under contracts of CL&P for the purchase of energy and capacity from renewable energy facilities.
| October - December |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| |
(Millions of Dollars) | 2013 |
| 2014 |
| 2015 |
| 2016 |
| 2017 |
| Thereafter |
| Total | |||||||
Yankee Billings |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
CL&P | $ | 0.4 |
| $ | 1.5 |
| $ | 1.3 |
| $ | 0.8 |
| $ | 0.8 |
| $ | 13.1 |
| $ | 17.9 |
NSTAR Electric |
| 0.2 |
|
| 0.7 |
|
| 0.5 |
|
| 0.2 |
|
| 0.3 |
|
| 4.5 |
|
| 6.4 |
PSNH |
| 0.1 |
|
| 0.3 |
|
| 0.4 |
|
| 0.3 |
|
| 0.3 |
|
| 5.2 |
|
| 6.6 |
WMECO |
| 0.1 |
|
| 0.4 |
|
| 0.4 |
|
| 0.2 |
|
| 0.2 |
|
| 3.3 |
|
| 4.6 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Renewable Energy |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
CL&P |
| 1.2 |
|
| 49.9 |
|
| 50.9 |
|
| 51.4 |
|
| 52.0 |
|
| 626.0 |
|
| 831.4 |
Other Long-Term Renewable Energy Contracts: On September 20, 2013, NSTAR Electric and WMECO, along with two other Massachusetts utilities, signed a long-term commitment, as required by state regulation, to purchase wind power from six wind farms in Maine and New Hampshire for a combined estimated generating capacity of approximately 550 MW. Over the life of the 15- to 20-year contracts, the utilities will pay an average price of less than $0.08 per kWh. On September 19, 2013, CL&P, along with another Connecticut utility, signed long-term commitments, as required by state regulation, to purchase approximately 250 MW of wind power from a Maine wind farm and 20 MW of solar power from sites in Connecticut, at a combined average price of less than $0.08 per kWh. The table above does not include these commitments for the purchase of renewable energy, as such commitments are contingent on the future construction of the respective energy facilities.
C.
Deferred Contractual Obligations
Spent Nuclear Fuel Litigation - DOE Phase III Damages - On May 1,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 filed applications with the FERC to reduce rates in their wholesale power contracts through the applicationreceived payment of $90 million, $73.3 million and $35.8 million, respectively, of the DOE proceeds forPhase II Damages proceeds. On April 28, 2014, the benefit of customers. In its June 27, 2013 order,Yankee Companies made the required informational filing with FERC granted the proposed rate reductions, and changes to the terms of the wholesale power contracts to become effective on July 1, 2013. Inin accordance with the process and methodology outlined in the 2013 FERC order,order. It is anticipated that the Yankee Companies will receive FERC approval and return the DOE Phase II Damages proceeds to the member companies, including CL&P, NSTAR Electric, PSNH, and WMECO, began receivingfor the benefit of their respective customers, effective June 1, 2014.
As of March 31, 2014, the CYAPC and YAEC proceeds received have been reflected as restricted cash in Other Long-Term Assets and the refund obligation to the member companies was reflected as Regulatory Liabilities on the NU consolidated balance sheet.
DOE Phase III Damages - On August 15, 2013, the Yankee Companies each filed subsequent lawsuits against the DOE proceeds,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 the benefits have been or will be passed on to customers. discovery has begun.
D.
C.Guarantees and Indemnifications
NU parent or NSTAR LLC, as applicable, provides credit assurances on behalf of its subsidiaries, including CL&P, NSTAR Electric, PSNH and WMECO, in the form of guarantees in the normal course of business.
NU provided guarantees and various indemnifications on behalf of external parties as a result of the sales of former subsidiaries of NU Enterprises 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'sNU’s obligations under the guaranty expire upon the full, final and indefeasible payment of the guaranteed obligations.
Management does not anticipate a material impact to net income or cash flows from operationsNet Income as a result of these various guarantees and indemnifications.
34
The following table summarizes NU'sNU’s guarantees of its subsidiaries, including CL&P, NSTAR Electric, PSNH and WMECO, as of September 30, 2013: March 31, 2014:
| |||||||||
|
|
|
| ||||||
|
|
|
|
| |||||
|
|
|
|
| |||||
|
|
|
|
| |||||
|
|
|
|
|
| ||||
|
|
|
| Maximum Exposure |
|
|
| |
Subsidiary |
| Description |
| (in millions) |
| Expiration Dates |
| |
|
|
|
|
|
|
|
| |
Various |
| Surety Bonds |
| $ | 66.7 |
| 2014 - 2016 (1) |
|
|
|
|
|
|
|
|
| |
Various |
| New England Hydro Companies’ Long-Term Debt |
| $ | 3.0 |
| Unspecified |
|
|
|
|
|
|
|
|
| |
NUSCO and RRR |
| Lease Payments for Vehicles and Real Estate |
| $ | 16.8 |
| 2019 and 2024 |
|
(1)
Surety bond expiration dates reflect termination dates, the majority of which will be renewed or extended.
(2)
The maximum exposure includes $3.8 million related to performance guarantees on wholesale purchase contracts, which expire December 31, 2013. Also included in the maximum exposure is $57.5 million relating to surety bonds covering ongoing projects, which expire upon project completion. The remaining $1 million is related to an insurance bond with no expiration date that is billed annually.
Many of the underlying contracts that NU parent guarantees, as well as certainCertain surety bonds contain credit ratings triggers that would require NU parent to post collateral in the event that the unsecured debt credit ratings of NU or NSTAR LLC, as applicable, are downgraded.
E.
D.FERC Base ROE Complaint
On September 30, 2011, several New England state attorneys general, state regulatory commissions, consumer advocates and other parties filed a joint complaint with the FERC under Sections 206 and 306 of the Federal Power Act alleging that the base ROE used in calculating formula rates for transmission service under the ISO-NE Open Access Transmission Tariff by NETOs, including CL&P, NSTAR Electric, PSNH and WMECO, is unjust and unreasonable. The complainants asserted that the current 11.14 percent rate, which became effective in 2006, is excessive due to changes in the capital markets and are seeking an order to reduce the rate, which would be effective October 1, 2011. In response, the NETOs filed testimony and analysis based on standard FERC methodology and precedent demonstrating that the base ROE of 11.14 percent remained just and reasonable. The FERC set the case for trial before a FERC ALJ after settlement negotiations were unsuccessful in August 2012.
Hearings before the FERC ALJ were held in May 2013, followed by the filing of briefs by the complainants, the Massachusetts municipal electric utilities (late interveners to the case), the FERC trial staff and the NETOs. The NETOs recommended that the current base ROE of 11.14 percent should remain in effect for the refund period (October 1, 2011 through December 31, 2012) and the prospective period (beginning when FERC issues its final decision). The complainants, the Massachusetts municipal electric utilities, and the FERC trial staff each recommended a base ROE of 9 percent or below.
On August 6, 2013, the FERC ALJ issued an initial decision, finding that the current base ROE isin effect from October 2011 through December 2012 was not reasonable under the standard application of FERC methodology, but leaving policy considerations and additional adjustments to the FERC. Using the established FERC methodology, the FERC ALJ determined that a separate base ROEROEs should be set for the refund period and the prospective period. The FERC ALJ found those base ROEs to be 10.6 percent and 9.7 percent, respectively. The FERC may adjust the prospective period base ROE in its final decision to reflect movement in 10-year Treasury bond rates from whenthe date that the case was filed (April 2013) to the date of the final decision. The parties filed briefs on this decision towith the FERC, and a decision from the FERC is expected in 2014. Though NU cannot predict the ultimate outcome of this proceeding, during the third quarter ofin 2013 the Company recorded a series of reserves at its electric subsidiaries to recognize the potential financial impact from the FERC ALJ'sALJ’s initial decision for the refund period. As a result, theThe aggregate after-tax charge to earnings totaled $14.3 million at NU. ThisNU, which represents reserves of $7.7 million at CL&P, $3.4 million at NSTAR Electric, $1.4 million at PSNH and $1.8 million at WMECO.
On December 27, 2012, several additional parties filed a separate complaint concerning the NETOs'NETOs’ base ROE with the FERC. This complaint seeks to reduce the NETOs’ base ROE effective January 1, 2013, effectively extending the refund period for an additional 15 months, and to consolidate this complaint with the joint complaint filed on September 30, 2011. The NETOs have asked the FERC to reject this complaint. The FERC has not yet acted on this complaint, and management is unable to predict the ultimate outcome or estimate the estimated impacts of this complaint on the financial position, results of operations or cash flows, of this complaint.flows.
Management expects the CL&P, NSTAR Electric, PSNH, and WMECO aggregate shareholder equity invested in their transmission facilities towill be approximately $2.4 billion at the end of 2013.2014. As a result, each 10 basis point change in the prospective period authorized base ROE would change annual consolidated earnings by an approximate $2.4 million.
F.E.CPSL
DPU Safety and Reliability Programs - CPSL
Since 2006, NSTAR Electric has been recovering incremental costs related to the DPU-approved Safety and Reliability Programs. From 2006 through 2011, cumulative costs associated with the CPSL program resulted in an incremental revenue requirement to customers of approximately $83 million. These amounts included incremental operations and maintenance costs and the related revenue requirement for specific capital investments relative to the CPSL programs.
35
On May 28, 2010, the DPU issued an order on NSTAR Electric’s 2006 CPSL cost recovery filing (the May 2010 Order). In October 2010, NSTAR Electric filed a reconciliation of the cumulative CPSL program activity for the periods 2006 through 2009 with the DPU in order to determine a proposed rate adjustment. The DPU allowed the proposed rates to go into effect January 1, 2011, subject to final reconciliation of CPSL program costs through a future DPU proceeding. In February 2013, NSTAR Electric updated the October 2010 filing with final activity through 2011. NSTAR Electric recorded its 2006 through 2011 revenues under the CPSL programs based on the May 2010 Order.
NSTAR Electric cannot predict the timing of a final DPU order related to its CPSL filings for the period 2006 through 2011. While management does not believe that any subsequent DPU order would result in revenues that are materially different than the amounts
already recognized, it is reasonably possible that an order could have a material impact on NSTAR Electric’s results of operations, financial position and cash flows.
G.
F.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“more likely than not,"” it could no longer be deemed "probable."“probable.” As a result, NSTAR Electric recognized a reserve related to the regulatory asset in the first quarter of 2012. NSTAR Electric will continue to maintain the reserve until the ultimate outcome of the proceeding has been concluded with the DPU.
10.
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 and Rate Reduction Bonds:Debt: The fair value of CL&P's&P’s and NSTAR Electric’s preferred stock is based upon pricing models that incorporate interest rates and other market factors, valuations or trades of similar securities and cash flow projections. The fair value of fixed-rate long-term debt securities and RRBs is based upon pricing models that incorporate quoted market prices for those issues or similar issues adjusted for market conditions, credit ratings of the respective companies and treasury benchmark yields. Adjustable rate long-term debt securities are assumed to have a fair value equal to their carrying value. The fair values provided in the tables below are classified as Level 2 within the fair value hierarchy. Carrying amounts and estimated fair values are as follows:
|
| As of September 30, 2013 |
| As of December 31, 2012 |
| As of March 31, 2014 |
| As of December 31, 2013 |
| ||||||||||||||||
|
| NU |
| NU |
| NU |
| NU |
| ||||||||||||||||
|
| Carrying |
| Fair |
| Carrying |
| Fair |
| Carrying |
| Fair |
| Carrying |
| Fair |
| ||||||||
(Millions of Dollars) | (Millions of Dollars) | Amount |
| Value |
| Amount |
| Value |
| Amount |
| Value |
| Amount |
| Value |
| ||||||||
Preferred Stock Not | Preferred Stock Not |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| |||||||
Subject to Mandatory Redemption |
| $ | 155.6 |
| $ | 152.0 |
| $ | 155.6 |
| $ | 152.7 |
| ||||||||||||
Long-Term Debt |
| 8,848.9 |
| 9,177.7 |
| 8,310.2 |
| 8,443.1 |
| ||||||||||||||||
| Subject to Mandatory Redemption | $ | 155.6 |
| $ | 152.2 |
| $ | 155.6 |
| $ | 152.2 | |||||||||||||
Long-Term Debt |
| 8,052.5 |
| 8,267.2 |
| 7,963.5 |
| 8,640.7 | |||||||||||||||||
Rate Reduction Bonds |
| - |
| - |
| 82.1 |
| 83.0 | |||||||||||||||||
|
| As of September 30, 2013 |
| As of March 31, 2014 |
| ||||||||||||||||||||||||||||||||||||||||||||
|
| CL&P |
| NSTAR Electric |
| PSNH |
| WMECO |
| CL&P |
| NSTAR Electric |
| PSNH |
| WMECO |
| ||||||||||||||||||||||||||||||||
|
| Carrying |
| Fair |
| Carrying |
| Fair |
| Carrying |
| Fair |
| Carrying |
| Fair |
| Carrying |
| Fair |
| Carrying |
| Fair |
| Carrying |
| Fair |
| Carrying |
| Fair |
| ||||||||||||||||
(Millions of Dollars) | (Millions of Dollars) | Amount |
| Value |
| Amount |
| Value |
| Amount |
| Value |
| Amount |
| Value |
| Amount |
| Value |
| Amount |
| Value |
| Amount |
| Value |
| Amount |
| Value |
| ||||||||||||||||
Preferred Stock Not | Preferred Stock Not |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| |||||||||||||||
| Subject to Mandatory Redemption | $ | 116.2 |
| $ | 110.3 |
| $ | 43.0 |
| $ | 41.9 |
| $ | - |
| $ | - |
| $ | - |
| $ | - | |||||||||||||||||||||||||
Subject to Mandatory Redemption |
| $ | 116.2 |
| $ | 110.9 |
| $ | 43.0 |
| $ | 41.1 |
| $ | — |
| $ | — |
| $ | — |
| $ | — |
| ||||||||||||||||||||||||
Long-Term Debt | Long-Term Debt |
| 2,741.0 |
| 2,992.0 |
| 1,801.0 |
| 1,881.9 |
| 889.1 |
| 934.7 |
| 549.6 |
| 562.1 |
| 2,741.4 |
| 3,033.1 |
| 2,099.0 |
| 2,224.0 |
| 1,049.1 |
| 1,096.5 |
| 629.2 |
| 661.0 |
| |||||||||||||||
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| ||||||||||||||||||||||||||||||||
|
| As of December 31, 2012 | |||||||||||||||||||||||||||||||||||||||||||||||
|
| CL&P |
| NSTAR Electric |
| PSNH |
| WMECO | |||||||||||||||||||||||||||||||||||||||||
|
| Carrying |
| Fair |
| Carrying |
| Fair |
| Carrying |
| Fair |
| Carrying |
| Fair | |||||||||||||||||||||||||||||||||
(Millions of Dollars) | Amount |
| Value |
| Amount |
| Value |
| Amount |
| Value |
| Amount |
| Value | ||||||||||||||||||||||||||||||||||
Preferred Stock Not |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| |||||||||||||||||||||||||||||||||
| Subject to Mandatory Redemption | $ | 116.2 |
| $ | 110.0 |
| $ | 43.0 |
| $ | 42.2 |
| $ | - |
| $ | - |
| $ | - |
| $ | - | |||||||||||||||||||||||||
Long-Term Debt |
| 2,862.8 |
| 3,295.4 |
| 1,602.6 |
| 1,818.8 |
| 997.9 |
| 1,088.0 |
| 605.3 |
| 660.4 | |||||||||||||||||||||||||||||||||
Rate Reduction Bonds |
| - |
| - |
| 43.5 |
| 43.9 |
| 29.3 |
| 29.6 |
| 9.4 |
| 9.5 | |||||||||||||||||||||||||||||||||
|
| As of December 31, 2013 |
| ||||||||||||||||||||||
|
| CL&P |
| NSTAR Electric |
| PSNH |
| WMECO |
| ||||||||||||||||
|
| Carrying |
| Fair |
| Carrying |
| Fair |
| Carrying |
| Fair |
| Carrying |
| Fair |
| ||||||||
(Millions of Dollars) |
| Amount |
| Value |
| Amount |
| Value |
| Amount |
| Value |
| Amount |
| Value |
| ||||||||
Preferred Stock Not |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| ||||||||
Subject to Mandatory Redemption |
| $ | 116.2 |
| $ | 110.5 |
| $ | 43.0 |
| $ | 42.2 |
| $ | — |
| $ | — |
| $ | — |
| $ | — |
|
Long-Term Debt |
| 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“Derivative Instruments,"” to the financial statements.
36
Other Financial Instruments: Investments in marketable securities are carried at fair value. For further information, see Note 1D, "Summary“Summary of Significant Accounting Policies - Fair Value Measurements,"” and Note 5, "Marketable“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:
|
| For the Nine Months Ended September 30, 2013 | ||||||||||
(Millions of Dollars) | Qualified Cash Flow Hedging Instruments |
| Unrealized Gains/(Losses) on Available-for-Sale Securities |
| Pension, SERP and PBOP |
| Total | |||||
AOCI as of January 1, 2013 | $ | (16.4) |
| $ | 1.3 |
| $ | (57.8) |
| $ | (72.9) | |
|
|
|
|
|
|
|
|
|
|
|
|
|
Other Comprehensive Income Before Reclassifications |
| - |
|
| (0.8) |
|
| - |
|
| (0.8) | |
Amounts Reclassified from AOCI |
| 1.5 |
|
| - |
|
| 4.8 |
|
| 6.3 | |
Net Other Comprehensive Income |
| 1.5 |
|
| (0.8) |
|
| 4.8 |
|
| 5.5 | |
AOCI as of September 30, 2013 | $ | (14.9) |
| $ | 0.5 |
| $ | (53.0) |
| $ | (67.4) | |
|
| For the Three Months Ended March 31, 2014 |
| For the Three Months Ended March 31, 2013 |
| ||||||||||||||||||||
|
|
|
| Unrealized |
| Pension, |
|
|
|
|
| Unrealized |
| Pension, |
|
|
| ||||||||
|
| Qualified |
| Gains/(Losses) |
| SERP and |
|
|
| Qualified |
| Gains/(Losses) |
| SERP and |
|
|
| ||||||||
|
| Cash Flow |
| on Available- |
| PBOP |
|
|
| Cash Flow |
| on Available- |
| PBOP |
|
|
| ||||||||
|
| Hedging |
| for-Sale |
| Benefit |
|
|
| Hedging |
| for-Sale |
| Benefit |
|
|
| ||||||||
(Millions of Dollars) |
| Instruments |
| Securities |
| Plans |
| Total |
| Instruments |
| Securities |
| Plans |
| Total |
| ||||||||
AOCI as of Beginning of Period |
| $ | (14.4 | ) | $ | 0.4 |
| $ | (32.0 | ) | $ | (46.0 | ) | $ | (16.4 | ) | $ | 1.3 |
| $ | (57.8 | ) | $ | (72.9 | ) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| ||||||||
OCI Before Reclassifications |
| — |
| 0.2 |
| — |
| 0.2 |
| — |
| (0.1 | ) | — |
| (0.1 | ) | ||||||||
Amounts Reclassified from AOCI |
| 0.5 |
| — |
| 1.0 |
| 1.5 |
| 0.5 |
| — |
| 1.6 |
| 2.1 |
| ||||||||
Net OCI |
| 0.5 |
| 0.2 |
| 1.0 |
| 1.7 |
| 0.5 |
| (0.1 | ) | 1.6 |
| 2.0 |
| ||||||||
AOCI as of End of Period |
| $ | (13.9 | ) | $ | 0.6 |
| $ | (31.0 | ) | $ | (44.3 | ) | $ | (15.9 | ) | $ | 1.2 |
| $ | (56.2 | ) | $ | (70.9 | ) |
NU'sNU’s qualified cash flow hedging instruments represent interest rate swap agreements on debt issuances that were settled in prior years. The settlement amount was recorded in AOCI and is being amortized into Net Income over the term of the underlying debt instrument. CL&P, PSNH and WMECO continue to amortize interest rate swaps settled in prior years from AOCI into Interest Expense over the remaining life of the associated long-term debt, which are not material to their respective financial statements.
The following table sets forth the amounts reclassified from AOCI by component and the affectedimpacted line item on the statements of income:
| For the Three Months Ended |
| For the Nine Months Ended |
|
| |||||||||||
| September 30, 2013 |
| September 30, 2013 |
|
|
| For the Three Months Ended March 31, |
| ||||||||
| Amount Reclassified |
| Amount Reclassified |
| Statements of Income |
| Amounts Reclassified from AOCI |
| Statements of Income Line Item |
| ||||||
(Millions of Dollars) | from AOCI |
| from AOCI |
| Line Item Impacted |
| 2014 |
| 2013 |
|
|
| ||||
Qualified Cash Flow Hedging Instruments | $ | (0.8) |
| $ | (2.5) |
| Interest Expense |
| $ | (0.8 | ) | $ | (0.8 | ) | Interest Expense |
|
Tax Benefit |
| 0.3 |
|
| 1.0 |
| Income Tax Expense |
| 0.3 |
| 0.3 |
| Income Tax Expense |
| ||
Qualified Cash Flow Hedging Instruments, Net of Tax | $ | (0.5) |
| $ | (1.5) |
|
|
| $ | (0.5 | ) | $ | (0.5 | ) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| ||
Pension, SERP and PBOP Benefit Plan Costs: |
|
|
|
|
|
|
|
|
|
|
|
|
|
| ||
Amortization of Actuarial Losses | $ | (2.5) |
| $ | (7.3) |
| (1) |
| $ | (1.7 | ) | $ | (2.6 | ) | Operations and Maintenance (1) |
|
Amortization of Prior Service Cost |
| - |
|
| (0.1) |
| (1) | |||||||||
Total Pension, SERP and PBOP Benefit Plan Costs |
| (2.5) |
|
| (7.4) |
| (1) | |||||||||
Tax Benefit |
| 0.9 |
|
| 2.6 |
| Income Tax Expense |
| 0.7 |
| 1.0 |
| Income Tax Expense |
| ||
Pension, SERP and PBOP Benefit Plan Costs, Net of Tax | $ | (1.6) |
| $ | (4.8) |
|
|
| $ | (1.0 | ) | $ | (1.6 | ) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| ||
Total Amount Reclassified from AOCI, Net of Tax | $ | (2.1) |
| $ | (6.3) |
|
|
| $ | (1.5 | ) | $ | (2.1 | ) |
|
|
(1)
These AOCI amounts are included in the computation of net periodic Pension, SERP and PBOP costs. See Note 7, "Pension“Pension Benefits and Postretirement Benefits Other Than Pensions,"” for further information.
12.
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 common stockthat were authorized and issued and the respective per share par values:
| Shares |
| Shares |
| |||||||||||||||||
| Authorized |
| Issued |
|
|
| Authorized as of |
|
|
|
|
| |||||||||
| Per Share |
| As of |
| As of |
| Per Share |
| March 31, 2014 and |
| Issued as of |
| |||||||||
| Par Value |
| September 30, 2013 |
| December 31, 2012 |
| September 30, 2013 |
| December 31, 2012 |
| Par Value |
| December 31, 2013 |
| March 31, 2014 |
| December 31, 2013 |
| |||
NU | $ | 5 |
| 380,000,000 |
| 380,000,000 |
| 333,019,517 |
|
| 332,509,383 |
| $ | 5 |
| 380,000,000 |
| 333,316,045 |
| 333,113,492 |
|
CL&P | $ | 10 |
| 24,500,000 |
| 24,500,000 |
| 6,035,205 |
|
| 6,035,205 |
| $ | 10 |
| 24,500,000 |
| 6,035,205 |
| 6,035,205 |
|
NSTAR Electric | $ | 1 |
| 100,000,000 |
| 100,000,000 |
| 100 |
|
| 100 |
| $ | 1 |
| 100,000,000 |
| 100 |
| 100 |
|
PSNH | $ | 1 |
| 100,000,000 |
| 100,000,000 |
| 301 |
|
| 301 |
| $ | 1 |
| 100,000,000 |
| 301 |
| 301 |
|
WMECO | $ | 25 |
| 1,072,471 |
| 1,072,471 |
| 434,653 |
|
| 434,653 |
| $ | 25 |
| 1,072,471 |
| 434,653 |
| 434,653 |
|
As of September 30, 2013March 31, 2014 and December 31, 2012, 18,137,0172013, there were 17,498,327 and 18,455,74917,796,672 NU common shares were held as treasury shares, respectively. As of March 31, 2014 and December 31, 2013, NU common shares outstanding were 315,817,718 and 315,273,559, respectively.
37
12.COMMON SHAREHOLDERS’ EQUITY AND NONCONTROLLING INTERESTS
13. COMMON SHAREHOLDERS' EQUITY AND NONCONTROLLING INTERESTS | ||||||||||||||||||||
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
A summary of the changes in Common Shareholders' Equity and Noncontrolling Interests of NU is as follows: | ||||||||||||||||||||
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| For the Three Months Ended | ||||||||||||||||
|
|
|
| September 30, 2013 |
| September 30, 2012 | ||||||||||||||
|
|
|
|
|
|
| Noncontrolling |
|
|
|
|
|
|
|
|
|
| Noncontrolling | ||
|
|
|
|
|
| Interest - |
|
|
|
|
|
|
|
|
|
| Interest - | |||
|
|
|
| Common |
| Preferred |
| Common |
| Non- |
|
|
| Preferred | ||||||
|
|
|
| Shareholders' |
| Stock of |
| Shareholders' |
| Controlling |
| Total |
| Stock of | ||||||
(Millions of Dollars) | Equity |
| Subsidiaries |
| Equity |
| Interest |
| Equity |
| Subsidiaries | |||||||||
Balance - Beginning of Period | $ | 9,406.6 |
| $ | 155.6 |
| $ | 9,067.6 |
| $ | - |
| $ | 9,067.6 |
| $ | 155.6 | |||
Net Income |
| 211.4 |
|
| - |
|
| 209.5 |
|
| - |
|
| 209.5 |
|
| - | |||
Dividends on Common Shares |
| (114.9) |
|
| - |
|
| (107.6) |
|
| - |
|
| (107.6) |
|
| - | |||
Dividends on Preferred Stock |
| (1.9) |
|
| (1.9) |
|
| (1.9) |
|
| - |
|
| (1.9) |
|
| (1.9) | |||
Issuance of Common Shares |
| 1.4 |
|
| - |
|
| 0.8 |
|
| - |
|
| 0.8 |
|
| - | |||
Other Transactions, Net |
| 12.8 |
|
| - |
|
| 6.3 |
|
| - |
|
| 6.3 |
|
| - | |||
Net Income Attributable to |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| |||
| Noncontrolling Interests |
| - |
|
| 1.9 |
|
| - |
|
| - |
|
| - |
|
| 1.9 | ||
Other Comprehensive Income |
| 2.1 |
|
| - |
|
| 2.2 |
|
| - |
|
| 2.2 |
|
| - | |||
Balance - End of Period | $ | 9,517.5 |
| $ | 155.6 |
| $ | 9,176.9 |
| $ | - |
| $ | 9,176.9 |
| $ | 155.6 | |||
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| For the Nine Months Ended | ||||||||||||||||
|
|
|
| September 30, 2013 |
| September 30, 2012 | ||||||||||||||
|
|
|
|
|
|
| Noncontrolling |
|
|
|
|
|
|
|
|
|
| Noncontrolling | ||
|
|
|
|
|
| Interest - |
|
|
|
|
|
|
|
|
|
| Interest - | |||
|
|
|
| Common |
| Preferred |
| Common |
| Non- |
|
|
| Preferred | ||||||
|
|
|
| Shareholders' |
| Stock of |
| Shareholders' |
| Controlling |
| Total |
| Stock of | ||||||
(Millions of Dollars) | Equity |
| Subsidiaries |
| Equity |
| Interest |
| Equity |
| Subsidiaries | |||||||||
Balance - Beginning of Period | $ | 9,237.1 |
| $ | 155.6 |
| $ | 4,012.7 |
| $ | 3.0 |
| $ | 4,015.7 |
| $ | 116.2 | |||
Net Income |
| 614.4 |
|
| - |
|
| 356.5 |
|
| - |
|
| 356.5 |
|
| - | |||
Purchase Price of NSTAR |
| - |
|
| - |
|
| 5,038.3 |
|
| - |
|
| 5,038.3 |
|
| - | |||
Other Equity Impacts of |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| |||
| Merger with NSTAR |
| - |
|
| - |
|
| 3.4 |
|
| (3.4) |
|
| - |
|
| 39.4 | ||
Dividends on Common Shares |
| (346.9) |
|
| - |
|
| (267.8) |
|
| - |
|
| (267.8) |
|
| - | |||
Dividends on Preferred Stock |
| (5.8) |
|
| (5.8) |
|
| (5.1) |
|
| - |
|
| (5.1) |
|
| (5.1) | |||
Issuance of Common Shares |
| 10.2 |
|
| - |
|
| 12.2 |
|
| - |
|
| 12.2 |
|
| - | |||
Contributions to NPT |
| - |
|
| - |
|
| - |
|
| 0.3 |
|
| 0.3 |
|
| - | |||
Other Transactions, Net |
| 3.0 |
|
| - |
|
| 20.3 |
|
| - |
|
| 20.3 |
|
| - | |||
Net Income Attributable to |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| |||
| Noncontrolling Interests |
| - |
|
| 5.8 |
|
| (0.1) |
|
| 0.1 |
|
| - |
|
| 5.1 | ||
Other Comprehensive Income |
| 5.5 |
|
| - |
|
| 6.5 |
|
| - |
|
| 6.5 |
|
| - | |||
Balance - End of Period | $ | 9,517.5 |
| $ | 155.6 |
| $ | 9,176.9 |
| $ | - |
| $ | 9,176.9 |
| $ | 155.6 | |||
A summary of the changes in Common Shareholders’ Equity and Noncontrolling Interests of NU is as follows:
14.
|
| For the Three Months Ended |
| ||||||||||
|
| March 31, 2014 |
| March 31, 2013 |
| ||||||||
|
|
|
| Noncontrolling |
|
|
| Noncontrolling |
| ||||
|
|
|
| Interest - |
|
|
| Interest - |
| ||||
|
| Common |
| Preferred |
| Common |
| Preferred |
| ||||
|
| Shareholders’ |
| Stock of |
| Shareholders’ |
| Stock of |
| ||||
(Millions of Dollars) |
| Equity |
| Subsidiaries |
| Equity |
| Subsidiaries |
| ||||
Balance as of Beginning of Period |
| $ | 9,611.5 |
| $ | 155.6 |
| $ | 9,237.1 |
| $ | 155.6 |
|
Net Income |
| 237.8 |
| — |
| 230.0 |
| — |
| ||||
Dividends on Common Shares |
| (123.9 | ) | — |
| (116.4 | ) | — |
| ||||
Dividends on Preferred Stock |
| (1.9 | ) | (1.9 | ) | (1.9 | ) | (1.9 | ) | ||||
Issuance of Common Shares |
| 5.2 |
| — |
| 8.4 |
| — |
| ||||
Other Transactions, Net |
| (6.5 | ) | — |
| (14.0 | ) | — |
| ||||
Net Income Attributable to Noncontrolling Interests |
| — |
| 1.9 |
| — |
| 1.9 |
| ||||
Other Comprehensive Income |
| 1.7 |
| — |
| 2.0 |
| — |
| ||||
Balance as of End of Period |
| $ | 9,723.9 |
| $ | 155.6 |
| $ | 9,345.2 |
| $ | 155.6 |
|
13.EARNINGS PER SHARE
Basic EPS is computed based upon the weighted average number of common shares outstanding during each period. Diluted EPS is computed on the basis of the weighted average number of common shares outstanding plus the potential dilutive effect ifof certain share-based compensation awards areas if they were converted into common shares. There were no antidilutive share awards outstanding for the three months ended September 30, 2013 and 2012.March 31, 2014. For the ninethree months ended September 30,March 31, 2013, and 2012, there were 2,100 and 5,688, respectively,6,299 antidilutive share awards excluded from the computation.
The following table sets forth the components of basic and diluted EPS:
|
| For the Three Months Ended |
| For the Nine Months Ended |
|
| For the Three Months Ended |
| ||||||||||||
(Millions of Dollars, except share information) | (Millions of Dollars, except share information) | September 30, 2013 |
| September 30, 2012 |
| September 30, 2013 |
| September 30, 2012 |
|
| March 31, 2014 |
| March 31, 2013 |
| ||||||
Net Income Attributable to Controlling Interest | Net Income Attributable to Controlling Interest | $ | 209.5 |
| $ | 207.6 |
| $ | 608.6 |
| $ | 351.2 |
|
| $ | 236.0 |
| $ | 228.1 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| |||||
Weighted Average Common Shares Outstanding: | Weighted Average Common Shares Outstanding: |
|
|
|
|
|
|
|
|
|
|
|
|
|
| |||||
| Basic |
| 315,291,346 |
| 314,806,441 |
| 315,191,752 |
| 264,636,636 |
| ||||||||||
| Dilutive Effect |
| 926,893 |
|
| 999,355 |
|
| 869,379 |
|
| 716,741 |
| |||||||
| Diluted |
| 316,218,239 |
|
| 315,805,796 |
|
| 316,061,131 |
|
| 265,353,377 |
| |||||||
Basic |
| 315,534,512 |
| 315,129,782 |
| |||||||||||||||
Dilutive Effect |
| 1,357,607 |
| 872,756 |
| |||||||||||||||
Diluted |
| 316,892,119 |
| 316,002,538 |
| |||||||||||||||
Basic EPS | Basic EPS | $ | 0.66 |
| $ | 0.66 |
| $ | 1.93 |
| $ | 1.33 |
|
| $ | 0.75 |
| $ | 0.72 |
|
Diluted EPS | Diluted EPS | $ | 0.66 |
| $ | 0.66 |
| $ | 1.93 |
| $ | 1.32 |
|
| $ | 0.74 |
| $ | 0.72 |
|
On April 10, 2012, NU issued approximately 136 million common shares as a result of the merger with NSTAR, which are reflected in weighted average common shares outstanding for all periods presented.
RSUs and performance shares are included in basic weighted average common shares outstanding as of the date that all necessary vesting conditions have been satisfied. The dilutive effect of unvested RSUs and performance shares is calculated using the treasury
38
stock method. Assumed proceeds of these units under the treasury stock method consist of the remaining compensation cost to be recognized and a theoretical tax benefit. The theoretical tax benefit is calculated as the tax impact of the intrinsic value of the units (the difference between the market value of the average units outstanding for the period, using the average market price during the period, and the grant date market value).
The dilutive effect of stock options to purchase common shares is also calculated using the treasury stock method. Assumed proceeds for stock options consist of cash proceeds that would be received upon exercise, and a theoretical tax benefit. The theoretical tax benefit is calculated as the tax impact of the intrinsic value of the stock options (the difference between the market value of the average stock options outstanding for the period, using the average market price during the period, and the exercise price).
15.
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'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'sNU’s total consolidated revenues for the three and nine months ended September 30, 2013March 31, 2014 and 2012.2013. 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 operations 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 income and expense related to the cash and debt of NU parent, and NSTAR LLC, respectively, 2) the revenues and expenses of NU'sNU’s service companies,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 comprisednot part of NU Enterprises, NSTAR Communications, Inc., RRR (a real estate subsidiary), the non-energy-related subsidiariesits core business.
Table of Yankee and the remaining operations of HWP.Contents
Cash flows used for investments in plant included in the segment information below are cash capital expenditures that do not include amounts incurred but not paid, cost of removal, AFUDC related to equity funds, and the capitalized portions of pension expense.
NU’s reportable segments are the combined Electric Distribution, Electric Transmission and Natural Gas Distribution segments,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. Therefore, separate Transmission and Distribution information is not disclosed for CL&P, NSTAR Electric, PSNH or WMECO. NU’s operating segments and reporting units are consistent with its reportable business segments.
NSTAR amounts are included in NU consolidated as of April 10, 2012.
NU'sNU’s segment information for the three and nine months ended September 30,March 31, 2014 and 2013 and 2012 is as follows:
|
| For the Three Months Ended September 30, 2013 |
| For the Three Months Ended March 31, 2014 |
| ||||||||||||||||||||||||||||||||
|
| Electric |
| Natural Gas |
|
|
|
|
|
|
|
|
| Electric |
| Natural Gas |
|
|
|
|
|
|
|
|
| ||||||||||||
(Millions of Dollars) | (Millions of Dollars) | Distribution |
| Distribution |
| Transmission |
| Other |
| Eliminations |
| Total |
| Distribution |
| Distribution |
| Transmission |
| Other |
| Eliminations |
| Total |
| ||||||||||||
Operating Revenues | Operating Revenues | $ | 1,508.6 |
| $ | 97.1 |
| $ | 234.1 |
| $ | 212.5 |
| $ | (159.7) |
| $ | 1,892.6 |
| $ | 1,585.9 |
| $ | 432.8 |
| $ | 252.1 |
| $ | 172.2 |
| $ | (152.4 | ) | $ | 2,290.6 |
|
Depreciation and Amortization | Depreciation and Amortization |
| (159.6) |
| (16.4) |
| (34.5) |
| (11.2) |
| 2.6 |
| (219.1) |
| (148.8 | ) | (17.7 | ) | (37.0 | ) | (7.0 | ) | 1.8 |
| (208.7 | ) | |||||||||||
Other Operating Expenses | Other Operating Expenses |
| (1,064.1) |
|
| (89.4) |
|
| (73.4) |
|
| (206.8) |
|
| 159.5 |
|
| (1,274.2) |
| (1,210.9 | ) | (321.4 | ) | (66.4 | ) | (165.4 | ) | 149.9 |
| (1,614.2 | ) | ||||||
Operating Income/(Loss) | Operating Income/(Loss) |
| 284.9 |
| (8.7) |
| 126.2 |
| (5.5) |
| 2.4 |
| 399.3 |
| 226.2 |
| 93.7 |
| 148.7 |
| (0.2 | ) | (0.7 | ) | 467.7 |
| |||||||||||
Net Income/(Loss) Attributable |
|
|
|
|
|
|
|
|
|
|
|
| |||||||||||||||||||||||||
| to Controlling Interest |
| 156.9 |
| (10.4) |
| 58.6 |
| 313.1 |
| (308.7) |
| 209.5 | ||||||||||||||||||||||||
|
|
|
|
|
|
|
|
|
|
|
|
|
| ||||||||||||||||||||||||
Interest Expense |
| (47.4 | ) | (8.5 | ) | (25.5 | ) | (9.6 | ) | 1.0 |
| (90.0 | ) | ||||||||||||||||||||||||
Other Income, Net |
| 1.4 |
| 0.1 |
| 1.5 |
| 294.8 |
| (296.1 | ) | 1.7 |
| ||||||||||||||||||||||||
Net Income Attributable to Controlling Interest |
| $ | 112.2 |
| $ | 52.1 |
| $ | 74.9 |
| $ | 291.7 |
| $ | (294.9 | ) | $ | 236.0 |
| ||||||||||||||||||
Cash Flows Used for Investments in Plant |
| $ | 189.4 |
| $ | 28.9 |
| $ | 112.2 |
| $ | 18.2 |
| $ | — |
| $ | 348.7 |
| ||||||||||||||||||
|
| For the Nine Months Ended September 30, 2013 |
| For the Three Months Ended March 31, 2013 |
| ||||||||||||||||||||||||||||||||
|
| Electric |
| Natural Gas |
|
|
|
|
|
|
|
|
| Electric |
| Natural Gas |
|
|
|
|
|
|
|
|
| ||||||||||||
(Millions of Dollars) | (Millions of Dollars) | Distribution |
| Distribution |
| Transmission |
| Other |
| Eliminations |
| Total |
| Distribution |
| Distribution |
| Transmission |
| Other |
| Eliminations |
| Total |
| ||||||||||||
Operating Revenues | Operating Revenues | $ | 4,104.4 |
| $ | 613.0 |
| $ | 721.5 |
| $ | 650.4 |
| $ | (565.8) |
| $ | 5,523.5 |
| $ | 1,374.2 |
| $ | 361.8 |
| $ | 239.5 |
| $ | 217.2 |
| $ | (197.7 | ) | $ | 1,995.0 |
|
Depreciation and Amortization | Depreciation and Amortization |
| (488.7) |
| (50.5) |
| (100.9) |
| (52.0) |
| 7.2 |
| (684.9) |
| (177.0 | ) | (17.4 | ) | (31.8 | ) | (19.0 | ) | 1.7 |
| (243.5 | ) | |||||||||||
Other Operating Expenses | Other Operating Expenses |
| (2,952.4) |
|
| (483.6) |
|
| (199.1) |
|
| (599.0) |
|
| 564.3 |
|
| (3,669.8) |
| (1,004.9 | ) | (267.2 | ) | (62.2 | ) | (197.4 | ) | 199.2 |
| (1,332.5 | ) | ||||||
Operating Income/(Loss) |
| 663.3 |
| 78.9 |
| 421.5 |
| (0.6) |
| 5.7 |
| 1,168.8 | |||||||||||||||||||||||||
Net Income Attributable |
|
|
|
|
|
|
|
|
|
|
|
| |||||||||||||||||||||||||
| to Controlling Interest |
| 347.5 |
| 34.1 |
| 215.4 |
| 868.7 |
| (857.1) |
| 608.6 | ||||||||||||||||||||||||
Cash Flows Used for |
|
|
|
|
|
|
|
|
|
|
|
| |||||||||||||||||||||||||
| Investments in Plant |
| 501.9 |
| 91.2 |
| 458.2 |
| 22.5 |
| - |
| 1,073.8 | ||||||||||||||||||||||||
Operating Income |
| 192.3 |
| 77.2 |
| 145.5 |
| 0.8 |
| 3.2 |
| 419.0 |
| ||||||||||||||||||||||||
Interest Expense |
| (42.1 | ) | (7.4 | ) | (21.9 | ) | (6.4 | ) | 1.5 |
| (76.3 | ) | ||||||||||||||||||||||||
Other Income, Net |
| 4.8 |
| 0.2 |
| 2.8 |
| 321.9 |
| (321.9 | ) | 7.8 |
| ||||||||||||||||||||||||
Net Income Attributable to Controlling Interest |
| $ | 99.5 |
| $ | 43.3 |
| $ | 79.9 |
| $ | 322.8 |
| $ | (317.4 | ) | $ | 228.1 |
| ||||||||||||||||||
Cash Flows Used for Investments in Plant |
| $ | 157.8 |
| $ | 31.2 |
| $ | 185.4 |
| $ | 14.6 |
| $ | — |
| $ | 389.0 |
| ||||||||||||||||||
The following table summarizes NU’s segmented total assets:
39
|
| Electric |
| Natural Gas |
|
|
|
|
|
|
|
|
| ||||||
(Millions of Dollars) |
| Distribution |
| Distribution |
| Transmission |
| Other |
| Eliminations |
| Total |
| ||||||
As of March 31, 2014 |
| $ | 18,882.9 |
| $ | 2,846.7 |
| $ | 5,165.6 |
| $ | 11,913.6 |
| $ | (10,711.9 | ) | $ | 28,096.9 |
|
As of December 31, 2013 |
| 17,260.0 |
| 2,759.7 |
| 6,745.8 |
| 11,842.4 |
| (10,812.4 | ) | 27,795.5 |
| ||||||
15.SUBSEQUENT EVENT
See Note 6, “Short-Term and Long-Term Debt,” for information regarding the April 2014 CL&P long-term debt issuance.
|
| For the Three Months Ended September 30, 2012 | ||||||||||||||||
|
| Electric |
| Natural Gas |
|
|
|
|
|
|
|
|
|
|
|
| ||
(Millions of Dollars) | Distribution |
| Distribution |
| Transmission |
| Other |
| Eliminations |
| Total | |||||||
Operating Revenues | $ | 1,483.7 |
| $ | 91.3 |
| $ | 235.6 |
| $ | 219.5 |
| $ | (168.6) |
| $ | 1,861.5 | |
Depreciation and Amortization |
| (172.6) |
|
| (12.6) |
|
| (29.7) |
|
| (17.5) |
|
| 1.1 |
|
| (231.3) | |
Other Operating Expenses |
| (1,027.4) |
|
| (77.2) |
|
| (66.3) |
|
| (216.8) |
|
| 170.4 |
|
| (1,217.3) | |
Operating Income/(Loss) |
| 283.7 |
|
| 1.5 |
|
| 139.6 |
|
| (14.8) |
|
| 2.9 |
|
| 412.9 | |
Net Income/(Loss) Attributable |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| |
| to Controlling Interest |
| 150.5 |
|
| (4.4) |
|
| 71.1 |
|
| 313.9 |
|
| (323.5) |
|
| 207.6 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
40
NORTHEAST UTILITIES AND SUBSIDIAIRIESSUBSIDIARIES
Management'sManagement’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 and Second Quarter 2013 Quarterly Reports on Form 10-Q, and the 20122013 Annual Report on Form 10-K. References in this Form 10-Q to "NU,"“NU,” the "Company," "we," "us"“Company,” “we,” “us,” and "our"“our” refer to Northeast Utilities and its consolidated subsidiaries, including NSTAR LLC and its subsidiaries for the periods after April 10, 2012.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“financial statements."”
Refer to the Glossary of Terms included in this combined Quarterly Report on Form 10-Q for abbreviations and acronyms used throughout thisManagement'sManagement’s Discussion and Analysis of Financial Condition and Results of Operations.
The only common equity securities that are publicly traded are common shares of NU. The earnings and EPS of each business discussed below do not represent a direct legal interest in the assets and liabilities allocated to such business but rather represent a direct interest in our assets and liabilities as a whole. EPS by business is a financial measure not recognized under GAAP that is calculated by dividing the Net Income Attributable to Controlling Interest of each business by the weighted average diluted NU common shares outstanding for the period.year. The discussion below also includes non-GAAP financial measures referencing our thirdfirst quarter 2014 and first nine months of 2013 and 2012 earnings and EPS excluding certain integration and merger costs related to NU'sNU’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 thirdfirst quarter 2014 and first nine months of 2013 and 2012 results without including the impact of these non-recurring items. Due to the nature and significance of these items on Net Income Attributable to Controlling Interest, we believe that the non-GAAP presentation is more representative of our financial performance and provides additional and useful information to readers of this report in analyzing historical and future performance by business. These non-GAAP financial measures should not be considered as an alternative to reported Net Income Attributable to Controlling Interest or EPS determined in accordance with GAAP as an indicator of operating performance.
Reconciliations of the above non-GAAP financial measures to the most directly comparable GAAP measures of consolidated diluted EPS and Net Income Attributable to Controlling Interest are included under "Financial“Financial Condition and Business Analysis –— Overview – Consolidated"— Consolidated” inManagement'sManagement’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"“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,"“estimate,” “expect,” “anticipate,” “intend,” “plan,” “project,” “believe,” “forecast,” “should,” “could,” and other similar expressions. Forward-looking statements are based on the current expectations, estimates, assumptions or projections of management and are not guarantees of future performance. These expectations, estimates, assumptions or projections may vary materially from actual results. Accordingly, any such statements are qualified in their entirety by reference to, and are accompanied by, the following important factors that could cause our actual results to differ materially from those contained in our forward-looking statements, including, but not limited to:
·
the possibility that expected merger synergies will not be realized or will not be realized within the expected time period,
·
cyber breaches, acts of war or terrorism, or grid disturbances,
·
actions or inaction byof local, state and federal regulatory and taxing bodies,
·
changes in business and economic conditions, including their impact on interest rates, collectability of receivables,bad debt expense, and demand for our products and services,
·
fluctuations in weather patterns,
·
changes in laws, regulations or regulatory policy,
·
changes in levels andor 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
41
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 20122013 Annual Report on Form 10-K. This Quarterly Report on Form 10-Q and NU’s 20122013 Annual Report on Form 10-K also
describe material contingencies and critical accounting policies in the accompanyingManagement’s Discussion and Analysis of Financial Condition and Results of Operations andCombined Notes to Condensed Consolidated Financial Statements (Unaudited). We encourage you to review these items.
Financial Condition and Business Analysis
Merger with NSTAR:
On April 10, 2012, we completed our merger with NSTAR. Unless otherwise noted, the results of NSTAR LLC and its subsidiaries, hereinafter referred to as "NSTAR," are included in NU’s financial position, results of operations and cash flows as of September 30, 2013 and December 31, 2012, for the three months ended September 30, 2013 and 2012, and for the nine months ended September 30, 2013, throughout thisManagement's Discussion and Analysis of Financial Condition and Results of Operations.
Executive Summary
The followingfollowing items in this executive summary are explained in more detail in this combined Quarterly Report on Form 10-Q:
Results:
·The earnings discussion below compares the three months ended March 31, 2014 with the same period in 2013:
·We earned $209.5$236 million, or $0.66$0.74 per share, in the third quarter of 2013, and $608.6compared with $228.1 million, or $1.93$0.72 per share. Excluding integration costs, we earned $241.8 million, or $0.76 per share, compared with $229.9 million, or $0.73 per share. Improved earnings results were due primarily to higher retail electric and firm natural gas sales as a result of colder weather, partially offset by the absence of a favorable impact from the resolution of a state income tax audit in the first nine monthsquarter of 2013, compared with $207.62013.
·The resolution of the state income tax audit provided a $13.6 million, or $0.66$0.04 per share, in the third quarter of 2012 and $351.2 million, or $1.32 per share, in the first nine months of 2012. Excluding integration and merger-related costs, we earned $216.5 million, or $0.69 per share, in the third quarter of 2013, and $619.2 million, or $1.96 per share, in the first nine months of 2013, compared with $220.5 million, or $0.70 per share, in the third quarter of 2012, and $456.7 million, or $1.72 per share, in the first nine months of 2012.
·
The addition of NSTAR provided an earnings contribution of $225.6 million for the first nine months of 2013, comparedbenefit to $141 million for the first nine months of 2012. Because the merger closed on April 10, 2012, NSTAR’sour first quarter 2012 results are not reflected in NU’s results for the first nine months2013 earnings, consisting of 2012.a $6.7 million benefit to NU parent, a $5.7 million benefit to our transmission segment, and a $1.2 million benefit to our electric distribution segment.
·
Our electric distribution segment, which includes generation, earned $156.9$112.2 million, or $0.50$0.35 per share, in the third quarter of 2013 and $347.5compared with $99.5 million, or $1.10$0.32 per share, in the first nine months of 2013, compared with earnings of $150.5 million, or $0.48 per share, in the third quarter of 2012 and $212.1 million, or $0.80 per share, in the first nine months of 2012. The results for the third quarter and first nine months of 2012 reflect $0.2 million and $51 million, respectively, of after-tax merger-related costs.share.
·
Our transmission segment earned $58.6$74.9 million, or $0.18$0.24 per share, in the third quarter of 2013 and $215.4compared with $79.9 million, or $0.68$0.25 per share, inshare. The decrease was due to the first nine monthsabsence of 2013, compared with $71.1the $5.7 million or $0.23 per share, infavorable impact from the third quarter of 2012 and $181.1 million, or $0.68 per share, in the first nine months of 2012. The results for the third quarter and first nine months of 2013 reflect an after-tax reserve of $14.3 million. For further information, see theLegislative, Regulatory, Policy and Other Itemssection in this Executive Summary. resolution described above.
·
Our natural gas distribution segment had a net loss of $10.4earned $52.1 million, or $0.03$0.16 per share, in the third quartercompared with $43.3 million, or $0.14 per share.
·NU parent and other companies had net losses of 2013 and$3.2 million, or $0.01 per share, compared with earnings of $34.1 million, or $0.11 per share, in the first nine months of 2013, compared with a net loss of $4.4$5.4 million, or $0.02 per share, in the third quarter of 2012 and earnings of $8.3 million, or $0.03 per share, in the first nine months of 2012. The results for the first nine months of 2012 reflect $2.1 million of after-tax merger-related costs.
·
share. Excluding integration costs, NU parent and other companies earned $4.4$2.6 million, or $0.01 per share, in the third quarter of 2013 and $11.6compared with $7.2 million, or $0.04$0.02 per share, in the first nine months of 2013, compared with net expenses of $9.6 million, or $0.03 per share, in the third quarter of 2012 and $50.3 million, or $0.19 per share, in the first nine months of 2012.share. The results for the third quarter and first nine months of 2013 reflect $7 million and $10.6 million, respectively, of after-tax integration costs. The results for the third quarter and first nine months of 2012 reflect $12.7 million and $52.4 million, respectively, of after-tax merger-related costs.
Legislative, Regulatory, Policy and Other Items:
·
On July 1, 2013, NPT filed the DOE Presidential Permit Application Amendment. The DOE has completed its public scoping meeting process and is currently performing field work and data collection. The $1.4 billion project is expected to be operational by mid-2017.
·
On August 6, 2013, a FERC ALJ issued an initial decision regarding the September 2011 joint complaint filed at FERC by various New England parties concerning the base ROE earned by New England transmission owners (NETOs). The initial decision found that the current base ROE is not reasonable, but leaves policy considerations and additional adjustmentsdecrease was due to the FERC, and determined that a separate base ROEabsence of 10.6 percent and 9.7 percent should be set for the refund period (October 1, 2011 through December 31, 2012) and the prospective period (beginning when FERC issues its final decision), respectively. The FERC may adjust the prospective period base ROE in its final decision, expected in 2014, to reflect movement in the capital markets from
42
when the case was filed in April 2013. As a result, in the third quarter of 2013, we recorded a reserve and recognized an after-tax charge of $14.3$6.7 million for the potential financialfavorable impact from the FERC ALJ's initial decision.resolution described above.
Liquidity:Regulatory Items:
·On March 12, 2014, the PURA issued a final decision that approved recovery of CL&P’s $365 million in storm restoration costs and ordered CL&P to capitalize approximately $18 million of the deferred storm restoration costs as utility plant. PURA will allow recovery of the $365 million with carrying charges in CL&P’s distribution rates over a six-year period beginning December 1, 2014.
·Pursuant to an October 2013 request from the New Hampshire Legislative Oversight Committee on Electric Utility Restructuring, staff of the NHPUC issued a report on April 1, 2014 that 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, compared to their net book value of $660 million, implying potential “stranded costs” in excess of $400 million. The NHPUC staff recommended that any further actions relating to PSNH’s generating assets await a final decision in the Clean Air Project prudence proceeding, that existing laws regarding divestiture, energy service, and cost recovery be harmonized, and that ISO-NE provide input on the economic and reliability consequences of retirement of PSNH’s fossil generating plants. In the event of generation asset divestiture or retirement, both present law and the PSNH Restructuring Settlement Agreement approved in 2000 require that the NHPUC provide stranded cost recovery to PSNH.
Liquidity:
·Cash and cash equivalents totaled $57.9$89.2 million as of September 30, 2013,March 31, 2014, compared with $45.7$43.4 million as of December 31, 2012,2013, while investments in property, plant and equipment totaled $1.1 billion$348.7 million in the first nine monthsquarter of 2013 and 2012.2014, compared with $389 million in the first quarter of 2013.
·
Cash flows provided by operating activities totaled $1.1 billion in the first nine months of 2013, compared with $700.8$493.8 million in the first nine monthsquarter of 2012 (amounts are net2014, compared with $473.1 million in the first quarter of RRB payments).2013. The improved operating cash flows were due primarily to the additionabsence of NSTAR, a decrease incash disbursements for major storm restoration costs and the absencea decrease in 2013 of customer bill creditsPension and merger-related costs paid in the first nine months of 2012,PBOP Plan cash contributions, partially offset by an increase in Pension Plan cash contributions.income taxes paid in the first quarter of 2014, as compared to the first quarter of 2013, and the absence of costs recovered in rates related to the RRBs that were fully amortized in the first half of 2013.
On September 1, 2013, WMECO repaid at maturity $55
·In the first quarter of 2014, we issued $400 million of 5.00 percent Senior Notes using short-term debt. On September 3, 2013, CL&P redeemed at par $125new long-term debt consisting of $100 million by Yankee Gas on January 2, 2014 and $300 million by NSTAR Electric on March 7, 2014. These new issuances were used primarily to repay approximately $375 million of 1.25 percent 2011 PCRBs that were subjectexisting long-term debt.
·On February 4, 2014, our Board of Trustees approved a common dividend payment of $0.3925 per share, payable on March 31, 2014 to mandatory tender for purchase using short-term debt.shareholders of record as of March 3, 2014. On September 20, 2013, NU parent repaid at maturity $300 millionMay 1, 2014, our Board of Floating Rate Senior Notes with proceeds from NU parent’s issuance onTrustees approved a common dividend payment of $0.3925 per share, payable June 30, 2014 to shareholders of record as of May 13, 2013 of $750 million of Senior Notes.30, 2014.
·
The following transactions became effective on September 6, 2013: (1) NU parent and certain of its subsidiaries amended their joint five-year $1.15 billion revolving credit facility dated July 25, 2012 by increasing the aggregate principal amount available thereunder by $300 million to $1.45 billion, extending the expiration date from July 25, 2017 to September 6, 2018, and increasing CL&P's borrowing sublimit from $300 million to $600 million; (2) CL&P’s $300 million revolving credit facility was terminated; (3) NSTAR Electric amended its five-year $450 million revolving credit facility dated July 25, 2012 by extending the expiration date from July 25, 2017 to September 6, 2018; and (4) NU parent’s $1.15 billion commercial paper program was increased by $300 million to $1.45 billion.
Overview
Consolidated: A summary of our earnings by business, which also reconciles the non-GAAP financial measures of consolidated non-GAAP earnings and EPS, as well as EPS by business, to the most directly comparable GAAP measures of consolidated Net Income Attributable to Controlling Interest and diluted EPS, for the third quarterfirst quarters of 2014 and first nine months of 2013 and 2012 is as follows:
|
| For the Three Months Ended September 30, |
| For the Nine Months Ended September 30, | ||||||||||||||||||||
(Millions of Dollars, Except |
| 2013 |
| 2012 |
| 2013 |
| 2012(1) | ||||||||||||||||
Per Share Amounts) |
| Amount |
| Per Share |
| Amount |
| Per Share |
| Amount |
| Per Share |
| Amount |
| Per Share | ||||||||
Net Income Attributable to |
| $ | 209.5 |
| $ | 0.66 |
| $ | 207.6 |
| $ | 0.66 |
| $ | 608.6 |
| $ | 1.93 |
| $ | 351.2 |
| $ | 1.32 |
|
| $ | 205.1 |
| $ | 0.65 |
| $ | 217.4 |
| $ | 0.69 |
| $ | 597.0 |
| $ | 1.89 |
| $ | 454.6 |
| $ | 1.71 |
NU Parent and Other Companies |
|
| 11.4 |
|
| 0.04 |
|
| 3.1 |
|
| 0.01 |
|
| 22.2 |
|
| 0.07 |
|
| 2.1 |
|
| 0.01 |
Non-GAAP Earnings |
|
| 216.5 |
|
| 0.69 |
|
| 220.5 |
|
| 0.70 |
|
| 619.2 |
|
| 1.96 |
|
| 456.7 |
|
| 1.72 |
Integration and Merger-Related |
|
| (7.0) |
|
| (0.03) |
|
| (12.9) |
|
| (0.04) |
|
| (10.6) |
|
| (0.03) |
|
| (105.5) |
|
| (0.40) |
Net Income Attributable to |
| $ | 209.5 |
| $ | 0.66 |
| $ | 207.6 |
| $ | 0.66 |
| $ | 608.6 |
| $ | 1.93 |
| $ | 351.2 |
| $ | 1.32 |
|
| For the Three Months Ended March 31, |
| ||||||||||
|
| 2014 |
| 2013 |
| ||||||||
(Millions of Dollars, Except Per Share Amounts) |
| Amount |
| Per Share |
| Amount |
| Per Share |
| ||||
Net Income Attributable to Controlling Interest (GAAP) |
| $ | 236.0 |
| $ | 0.74 |
| $ | 228.1 |
| $ | 0.72 |
|
|
|
|
|
|
|
|
|
|
| ||||
Regulated Companies |
| $ | 239.2 |
| $ | 0.75 |
| $ | 222.7 |
| $ | 0.71 |
|
NU Parent and Other Companies |
| 2.6 |
| 0.01 |
| 7.2 |
| 0.02 |
| ||||
Non-GAAP Earnings |
| 241.8 |
| 0.76 |
| 229.9 |
| 0.73 |
| ||||
Integration Costs (after-tax) |
| (5.8 | ) | (0.02 | ) | (1.8 | ) | (0.01 | ) | ||||
Net Income Attributable to Controlling Interest (GAAP) |
| $ | 236.0 |
| $ | 0.74 |
| $ | 228.1 |
| $ | 0.72 |
|
(1)
Results include the operations of NSTAR from the date of the merger, April 10, 2012, through September 30, 2012.
(2)
The third quarter and first nine months of 2013 costs related to integration costs incurred at NU parent for employee severance accruals, consulting and compensation expenses. The first nine months of 2012 after-tax merger-related costs consisted of Regulated companies’ charges of $53.1 million (for further information, see theRegulated Companiesportion of this Overview section), costs of $33.2 million at NU parent related to investment advisory fees, attorney fees, and consulting costs, a $10.3 million charge related to change in control costs and other compensation costs at NU parent and NSTAR LLC, and an $8.9 million charge at NU parent for the establishment of a fund to advance Connecticut energy goals related to the Connecticut settlement agreement.
In the third quarter of 2013, we recorded an after-tax charge for severance benefit expenses of $5.5 million at NU parent in connection with the partial outsourcing of information technology functions made as part of ongoing post-merger integration. Excluding the impact of these integration costs as well as other integration and merger-related costs, our third quarter 2013 earnings decreased by $4 million, as compared to the third quarter of 2012. The decrease was due primarily to the establishment of an after-tax reserve of $14.3 million related to an August 2013 initial decision from a FERC ALJ that lowers the base ROE earned by NETOs for the 15-month period ended December 31, 2012. For further information, see “FERC Regulatory Issues - FERC Base ROE Complaint” in thisManagement's Discussion and Analysis of Financial Condition and Results of Operations. Partially offsetting that reserve was higher transmission segment earnings as a result of increased investments in the transmission infrastructure and higher retail electric distribution revenues as a result of an increase in third quarter 2013 demand charges, as compared to third quarter 2012, and the favorable impact related to an increase in PSNH rates effective July 1, 2013 as a result of the PSNH 2010 distribution rate case settlement.
Excluding the impacts of integration and merger-related costs, our first nine months of 2013quarter 2014 earnings increased by $162.5$11.9 million, as compared to the first nine monthsquarter of 2012,2013, due primarily to the inclusion of NSTAR effective April 10, 2012 (NSTAR provided an earnings contribution of $225.6 million for the first nine months of 2013, compared to $141 million for the first nine months of 2012), lower overall operations and maintenance costs, higher retail electric and firm natural gas sales higher transmission segment earnings
43
as a result of increased investments incolder weather, partially offset by the transmission infrastructure, and theabsence of a favorable impact from the resolution of a state income tax audit in the first quarter of 2013. Partially offsetting these favorable earnings impacts were higher depreciation and property tax expense and the establishmentThe resolution of the $14.3state income tax audit provided a $13.6 million, after-tax reserve relatedor $0.04 per share, benefit to the Augustour first quarter 2013 FERC ALJ initial decision.earnings.
Regulated Companies: Our Regulated companies consist of the electric distribution, transmission, and natural gas distribution segments. Generation activities of PSNH and WMECO are included in our electric distribution segment. A summary of our segment earnings for the third quarterfirst quarters of 2014 and first nine months of 2013 and 2012 is as follows:
| For the Three Months |
| For the Nine Months |
| For the Three Months |
| ||||||||||||
(Millions of Dollars) | 2013 |
| 2012 |
| 2013 |
| 2012(1) |
| 2014 |
| 2013 |
| ||||||
Electric Distribution | $ | 156.9 |
| $ | 150.7 |
| $ | 347.5 |
| $ | 263.1 |
| $ | 112.2 |
| $ | 99.5 |
|
Transmission |
| 58.6 |
|
| 71.1 |
|
| 215.4 |
|
| 181.1 |
| 74.9 |
| 79.9 |
| ||
Natural Gas Distribution |
| (10.4) |
|
| (4.4) |
|
| 34.1 |
|
| 10.4 |
| 52.1 |
| 43.3 |
| ||
Total - Regulated Companies | $ | 205.1 |
| $ | 217.4 |
| $ | 597.0 |
| $ | 454.6 | |||||||
Merger-Related Costs (after-tax)(2) |
| - |
|
| (0.2) |
|
| - |
|
| (53.1) | |||||||
Net Income - Regulated Companies | $ | 205.1 |
| $ | 217.2 |
| $ | 597.0 |
| $ | 401.5 |
| $ | 239.2 |
| $ | 222.7 |
|
(1)
Results include the operations of NSTAR from the date of the merger, April 10, 2012, through September 30, 2012.
(2)
The first nine months of 2012 after-tax merger-related costs consisted of $27.6 million in charges ($46 million pre-tax) at CL&P, NSTAR Electric, NSTAR Gas and WMECO for customer bill credits related to the Connecticut and Massachusetts settlement agreements, a $23.6 million charge ($40 million pre-tax) related to the Connecticut settlement agreement, whereby CL&P agreed to forego recovery of previously deferred storm restoration costs associated with Tropical Storm Irene and the October 2011 snowstorm, and a $1.9 million charge related to change in control costs and other compensation costs.
The third quarter 2013Our electric distribution segment earnings increased $12.7 million in the first quarter of 2014, as compared to the thirdfirst quarter of 2012,2013, due primarily to higher retail electric distribution revenues as a result of an increase in third quarter 2013 demand charges, as compared to third quarter 2012, and the favorable impact related to an increase in PSNH rates effective July 1, 2013 as a result of the PSNH 2010 distribution rate case settlement. Partially offsetting these favorable earnings impacts were higher depreciation and property tax expense as well as lower retail electric sales as a result of cooler summer weather in the third quarter of 2013, as compared to the same period in 2012.
Excluding $51 million of 2012 after-tax merger-related costs, the first nine months of 2013 electric distribution segment earnings increased, as compared to the first nine months of 2012, due primarily to the inclusion of NSTAR Electric distribution business’ earnings, lower overall operations and maintenance costs and higher retail electric sales due primarily to colder weather in the first quarter of 2013, as compared to the first quarter of 2012.weather. The first nine months of 20132014 results were also favorably impacted by a PSNH rate increasesincrease effective July 1, 2012 and July 1, 2013 as a result of the 2010 distribution rate case settlement. Partially offsetting these favorable earnings impacts were higher depreciation and property tax expense.
The third quarter 2013Our transmission segment earnings decreased as compared toin the thirdfirst quarter of 2012, due primarily to the establishment of the $14.3 million after-tax reserve related to the August 2013 FERC ALJ initial decision. Partially offsetting that reserve was increased investments in the transmission infrastructure, including GSRP, which was 98 percent complete as of September 30, 2013.
The first nine months of 2013 transmission segment earnings increased,2014, as compared to the first nine monthsquarter of 2012,2013, due primarily to the inclusionabsence of NSTAR Electric transmission business’ earnings, increased investments in the transmission infrastructure, including GSRP, and the favorable impact from the resolution of athe state income tax audit in the first quarter of 2013, which provided a $5.7 million benefit to our first quarter 2013 transmission segment earnings, partially offset by the $14.3 million after-tax reserve related to the August 2013 FERC ALJ initial decision.a higher transmission rate base as a result of an increased investment in our transmission infrastructure.
The third quarter 2013 natural gas distribution segment earnings decreased, as compared to the third quarter of 2012, due primarily to the recognition of higher depreciation and property tax expense at NSTAR Gas and higher overall operations and maintenance costs.
Excluding $2.1 million of 2012 after-tax merger-related costs, the first nine months of 2013Our natural gas distribution segment earnings increased as compared to the first nine months of 2012, due primarily to the inclusion of NSTAR Gas’ earnings, higher firm natural gas sales due primarily to colder weather in the first quarter of 2013,2014, as compared to the first quarter of 2012, the favorable impact related2013, due primarily to an increase in Yankee Gas rates effective July 1, 2012higher firm natural gas sales as a result of colder weather, as well as the Yankee Gas 2011 rate case decision, and lower interest expense, partially offset by the recognitionaddition of higher depreciation and property tax expense at NSTAR Gas. new natural gas heating customers.
A summary of our retail electric GWh sales and percentage changes, assuming NSTAR Electric had been part of the NU electric distribution system for all periods, as well as percentage changes in CL&P, NSTAR Electric, PSNH and WMECO retail electric GWh sales, is as follows:
|
| For the Three Months Ended |
| ||||
|
| Sales (GWh) |
| Percentage |
| ||
NU – Electric |
| 2014 |
| 2013 |
| Increase |
|
Residential |
| 6,139 |
| 5,803 |
| 5.8 | % |
Commercial (1) |
| 6,866 |
| 6,695 |
| 2.6 | % |
Industrial |
| 1,343 |
| 1,298 |
| 3.4 | % |
Total |
| 14,348 |
| 13,796 |
| 4.0 | % |
|
| For the Three Months Ended |
| ||||||
|
| CL&P |
| NSTAR |
| PSNH |
| WMECO |
|
Electric |
| Percentage |
| Percentage |
| Percentage |
| Percentage |
|
Residential |
| 6.9 | % | 4.1 | % | 5.8 | % | 5.7 | % |
Commercial (1) |
| 2.3 | % | 2.6 | % | 2.3 | % | 4.2 | % |
Industrial |
| 4.2 | % | 3.5 | % | 4.8 | % | (2.4 | )% |
Total |
| 4.7 | % | 3.2 | % | 4.2 | % | 3.8 | % |
(1)Commercial retail electric GWh sales include streetlighting and railroad retail sales.
A summary of our firm natural gas sales in million cubic feet and percentage changes, assuming NSTAR Gas had been part of the NU natural gas distribution system for all periods, as well as percentage changes in Yankee Gas and NSTAR Gas, for the third quarter and first nine months of 2013, as compared to the same periods in 2012, is as follows:
|
| For the Three Months Ended |
| ||||
|
| Sales (million cubic feet) |
| Percentage |
| ||
NU - Firm Natural Gas |
| 2014 |
| 2013 |
| Increase |
|
Residential |
| 19,812 |
| 17,015 |
| 16.4 | % |
Commercial |
| 19,627 |
| 16,771 |
| 17.0 | % |
Industrial |
| 7,478 |
| 6,829 |
| 9.5 | % |
Total |
| 46,917 |
| 40,615 |
| 15.5 | % |
Total, Net of Special Contracts (1) |
| 45,550 |
| 39,422 |
| 15.5 | % |
44
|
| For the Three Months Ended |
| ||
|
| Sales (million cubic feet) |
| ||
|
| Yankee Gas |
| NSTAR Gas |
|
|
| Percentage |
| Percentage |
|
Firm Natural Gas |
| Increase |
| Increase |
|
Residential |
| 21.8 | % | 12.9 | % |
Commercial |
| 21.0 | % | 13.6 | % |
Industrial |
| 10.2 | % | 7.7 | % |
Total |
| 18.6 | % | 12.7 | % |
Total, Net of Special Contracts (1) |
| 18.9 | % |
|
|
| For the Three Months Ended |
| For the Nine Months Ended | ||||||||
| Sales (GWh) |
|
|
| Sales (GWh) |
| Percentage | ||||
NU – Electric | 2013 |
| 2012 |
| Percentage Decrease |
| 2013 |
| 2012(1) |
| Increase/ |
Residential | 6,102 |
| 6,217 |
| (1.8)% |
| 16,625 |
| 16,296 |
| 2.0 % |
Commercial(2) | 7,616 |
| 7,721 |
| (1.4)% |
| 21,064 |
| 21,008 |
| 0.3 % |
Industrial | 1,529 |
| 1,563 |
| (2.2)% |
| 4,265 |
| 4,393 |
| (2.9)% |
Total | 15,247 |
| 15,501 |
| (1.6)% |
| 41,954 |
| 41,697 |
| 0.6 % |
| For the Three Months Ended September 30, 2013 Compared to 2012 |
| For the Nine Months Ended September 30, 2013 Compared to 2012 | ||||||||||||
| CL&P |
| NSTAR |
| PSNH |
| WMECO |
| CL&P |
| NSTAR |
| PSNH |
| WMECO |
Electric | Percentage |
| Percentage |
| Percentage |
| Percentage |
| Percentage |
| Percentage |
| Percentage |
| Percentage |
Residential | (1.8)% |
| (2.7)% |
| 0.3 % |
| (2.5)% |
| 2.9 % |
| 0.8 % |
| 2.1% |
| 1.3 % |
Commercial(2) | (1.1)% |
| (1.9)% |
| (0.3)% |
| (1.7)% |
| 0.4 % |
| 0.1 % |
| 0.7% |
| (0.7)% |
Industrial | (5.2)% |
| (1.2)% |
| 2.0 % |
| (1.1)% |
| (5.4)% |
| (3.3)% |
| 1.5% |
| (1.9)% |
Total | (1.9)% |
| (2.1)% |
| 0.3 % |
| (1.9)% |
| 0.9 % |
| 0.1 % |
| 1.4% |
| (0.1)% |
(1)
Results include retail electric sales of NSTAR Electric from January 1, 2012 through September 30, 2012 for comparative purposes only.
(2)
Commercial retail electric GWh sales include streetlighting and railroad retail sales.
| For the Three Months Ended |
| For the Nine Months Ended | ||||||||
| Sales (million cubic feet) |
| Percentage |
| Sales (million cubic feet) |
|
| ||||
NU – Firm Natural Gas | 2013 |
| 2012 |
| Increase/ |
| 2013 |
| 2012(1) |
| Percentage Increase |
Residential | 2,407 |
| 2,413 |
| (0.3)% |
| 24,392 |
| 20,124 |
| 21.2% |
Commercial | 4,673 |
| 4,230 |
| 10.5 % |
| 28,066 |
| 24,524 |
| 14.4% |
Industrial | 4,093 |
| 4,053 |
| 1.0 % |
| 15,588 |
| 15,387 |
| 1.3% |
Total | 11,173 |
| 10,696 |
| 4.5 % |
| 68,046 |
| 60,035 |
| 13.3% |
Total, Net of Special Contracts(2) | 10,155 |
| 9,462 |
| 7.3 % |
| 64,815 |
| 55,341 |
| 17.1% |
| For the Three Months Ended |
| For the Nine Months Ended | ||||
| Sales (million cubic feet) |
| Sales (million cubic feet) | ||||
| Yankee Gas |
| NSTAR Gas |
| Yankee Gas |
| NSTAR Gas(3) |
| Percentage |
| Percentage |
| Percentage |
| Percentage |
NU – Firm Natural Gas | Increase/(Decrease) |
| Increase/(Decrease) |
| Increase/(Decrease) |
| Increase |
Residential | 9.0 % |
| (6.4)% |
| 23.0 % |
| 20.0% |
Commercial | 6.5 % |
| 14.6 % |
| 15.4 % |
| 13.6% |
Industrial | (1.7)% |
| 11.1 % |
| (2.8)% |
| 14.4% |
Total | 2.7 % |
| 7.0 % |
| 10.5 % |
| 16.4% |
Total, Net of Special Contracts(2) | 7.6 % |
|
|
| 17.9 % |
|
|
(1)
Results include firm natural gas sales of NSTAR Gas from January 1, 2012 through September 30, 2012 for comparative purposes only.
(2)
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.
(3)
NSTAR Gas’ sales data from January 1, 2012 through September 30, 2012 has been provided for comparative purposes only.
Weather, fluctuations in energy supply costs, conservation measures (including company-sponsored energy efficiency programs), and economic conditions affect customer energy usage. Industrial sales are less sensitive to temperature variations than residential and commercial sales. WeatherIn our service territories, weather impacts electric sales primarily during the summer and electric and natural gas sales during the winter in our service territories (natural gas sales are more sensitive to temperature variations than electric sales). Customer heating or cooling usage may not directly correlate with historical levels or with the level of degree-days that occur. In addition, our electric and natural gas businesses are impacted by variations in weather and are susceptible to damage from major storms and other natural events and disasters that could adversely affect our ability to provide energy.
For the thirdOur first quarter of 2013, our2014 consolidated retail electric sales, were lower, as compared toconsisting of the same period in 2012, due primarily to a decrease in residential sales as a result of cooler summer weather in the third quarter of 2013, as compared to the same period in 2012. For the first nine months of 2013, our consolidated retail electric sales of CL&P, NSTAR Electric, PSNH, and WMECO, were higher, as compared to the same period in 2012, due primarily to the colder weather in the first quarter of 2013, as compared to the first quarter of 2012.
45
For the third quarter of 2013, actual retail electric sales for CL&P, NSTAR Electric and WMECO decreased while actual retail electric sales for PSNH reflected a slight increase, as compared to the same period in 2012. Cooling degree days were eight percent lower than last year in Connecticut and western Massachusetts, two percent lower than last year in the Boston metropolitan area, and 11 percent lower than last year in New Hampshire. On a weather-normalized basis (based on 30-year average temperatures), retail electric sales for CL&P, NSTAR Electric and WMECO decreased, while retail electric sales for PSNH increased, for the third quarter of 2013, as compared to the same period in 2012, with the NU combined consolidated total retail electric sales decreasing by 0.3 percent. We believe the decrease was due primarily to increased conservation efforts among all our customer classes, primarily at NSTAR Electric as a result of company sponsored energy efficiency programs.
For the first nine months of 2013, actual retail electric sales for CL&P, NSTAR Electric and PSNH increased while actual retail electric sales for WMECO remained relatively unchanged, as compared to the same period in 2012. Actual retail electric sales increased due primarily to the colder weather in the firstweather. First quarter of 2013, as compared to the first quarter of 2012. For the first nine months of 2013,2014 heating degree days were 2216 percent higher in Connecticut and western Massachusetts, 21 percenthigher12 percent higher in the Boston metropolitan area, and 15 percent higher in New Hampshire, as compared to the same period in 2012. On a weather-normalized basis,first quarter of 2013. Weather-normalized retail electric sales for CL&P and PSNH(based on 30-year average temperatures) increased while retail electric sales for NSTAR Electric and WMECO decreased, for1.3 percent in the first nine monthsquarter of 2013,2014, as compared to the same periodfirst quarter of 2013, reflecting a steady improvement in 2012, with the NU combined consolidated total retail electric sales remaining relatively unchanged, assuming NSTAR Electric had been parteconomic conditions across our service territory.
Table of the NU electric distribution system for all periods. Contents
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 $125.4 million and a baseline low income discount recovery of $7 million. These two mechanisms effectively break the relationship between sales volume and revenues recognized.
Our consolidated firm natural gas sales are subject to many of the same influences as our retail electric sales, butsales. In addition, they have benefitted from historically favorable natural gas prices and customer growth across all three customer classes. In the thirdboth operating companies. Our first quarter and first nine months of 2013, actual and weather-normalized2014 consolidated firm natural gas sales, increased, as compared toconsisting of the same periods in 2012. Third quarter actual and weather-normalized firm natural gas sales of Yankee Gas and NSTAR Gas, were higher, due primarilyas compared to residential customer growth, incremental natural gas conversions, the migration of interruptible customers switching to firm service rates, and the addition of gas-fired distributed generation, all of which was primarily in the Yankee Gas service territory. The first nine months of 2013 actual firm natural gas sales were higher due primarily to colder weather in the first quarter of 2013, as compareddue primarily to the same period in 2012, assuming NSTAR Gas had been part of thecolder weather. The first quarter 2014 weather-normalized NU combined natural gas distribution system for all periods. On a weather-normalized basis, the NU combined consolidated total firm natural gas sales increased 3.6 percent, in the first nine months of 2013, as compared to the same period in 2012,2013, due primarily to residential and commercial customer growth, incremental natural gas conversions, the migration of interruptible customers switching to firm service rates, and the addition of gas-fired distributed generation, all of which was primarily in the Yankee Gas service territory.growth.
NU Parent and Other Companies: NU parent and other companies, (whichwhich includes NSTAR LLC from the date of the merger, April 10, 2012, and our competitive businesses, held by NU Enterprises) earned $4.4 million and $11.6had net losses of $3.2 million in the thirdfirst quarter and first nine months of 2013, respectively,2014, compared with net expensesearnings of $9.6 million and $50.3$5.4 million in the thirdfirst quarter and first nine months of 2012, respectively.2013. Excluding the impact of integration and merger-related costs, NU parent and other companies earned $11.4 million and $22.2$2.6 million in the thirdfirst quarter and first nine months of 2013, respectively,2014, compared with earnings of $3.1 million and $2.1$7.2 million in the thirdfirst quarter and first nine months of 2012, respectively. Improved results were2013. The decrease in earnings was due primarily to a lower effectivethe absence of the favorable impact from the resolution of the state income tax rate and, foraudit in the first nine monthsquarter of 2013, the inclusion of NSTAR Communications.which provided a $6.7 million benefit to first quarter 2013 NU parent earnings.
Liquidity
Consolidated: Cash and cash equivalents totaled $57.9$89.2 million as of September 30, 2013,March 31, 2014, compared with $45.7$43.4 million as of December 31, 2012.2013.
On July 31, 2013,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 FERC approved CL&P’s and WMECO’s short-term debt application requesting authorization to issue total short-term borrowings up to a maximum of $600$75 million and $300 million, respectively. The authorization is effective4.80 percent Series G First Mortgage Bonds that matured on January 1, 2014 through December 31, 2015.and to repay $25 million in short-term borrowings.
On August 29, 2013,March 7, 2014, NSTAR Electric filed an application with the DPU requesting authorization to issue up to $800 million in long-term debt for the two-year period ending December 31, 2015.
On September 1, 2013, WMECO repaid at maturity $55 million of 5.00 percent Series A Senior Notes using short-term debt.
On September 3, 2013, CL&P redeemed at par $125 million of 1.25 percent Series B 2011 PCRBs that were subject to mandatory tender for purchase using short-term debt.
On September 20, 2013, NU parent repaid at maturityissued $300 million of Floating Rate Series D Senior Notes with4.40 percent debentures, due to mature in 2044. The proceeds, from NU parent’snet of issuance on May 13, 2013 of $750costs, were used to repay the $300 million of Series E and Series F Senior Notes.4.875 percent debentures that matured on April 15, 2014.
On September 6, 2013, 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.
NU parent, CL&P, NSTAR LLC,PSNH, WMECO, NSTAR Gas PSNH, WMECO and Yankee Gas amended theirare parties to a joint five-year $1.15$1.45 billion revolving credit facility dated July 25, 2012 by increasing the aggregate principal amount available thereunder by $300 milliondue to $1.45 billion, extending the expiration date from July 25, 2017 toexpire on September 6, 2018, and increasing CL&P's borrowing
46
sublimit from $300 million to $600 million. At the same time, effective September 6, 2013, the CL&P $300 million2018. The revolving credit facility is to be used primarily to backstop the $1.45 billion commercial paper program at NU. The commercial paper program allows NU parent to issue commercial paper as a form of short-term debt. As of March 31, 2014 and December 31, 2013, NU had approximately $818.5 million and $1.01 billion, respectively, in short-term borrowings outstanding under the NU parent commercial paper program, leaving $631.5 million and $435.5 million of available borrowing capacity as of March 31, 2014 and December 31, 2013, respectively. The weighted-average interest rate on these borrowings as of March 31, 2014 and December 31, 2013 was terminated.0.23 percent and 0.24 percent, respectively, which is generally based on money market rates. As of March 31, 2014, there were intercompany loans from NU of $351.6 million to CL&P, $39.9 million to PSNH and $37.4 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.
On September 6, 2013, NSTAR Electric amended itshas a five-year $450 million revolving credit facility dated July 25, 2012 by extending the expiration date from July 25, 2017due to expire on September 6, 2018.
On September 6,This facility serves to backstop NSTAR Electric’s existing $450 million commercial paper program. As of March 31, 2014, NSTAR Electric had no borrowings outstanding under its commercial paper program. As of December 31, 2013, the NU parent $1.15 billionNSTAR Electric had $103.5 million in short-term borrowings outstanding under its commercial paper program, was increased by $300leaving $346.5 million to $1.45 billion.
On September 26, 2013, the NHPUC issued an order, effective October 8, 2013, approving PSNH's request to issue up to $315 million in long-term debt throughof available borrowing capacity. The weighted-average interest rate on these borrowings as of December 31, 2014, and to refinance $89.3 million 2001 Series B PCRBs through its existing maturity of May 2021.2013 was 0.13 percent, which is generally based on money market rates.
Cash flows provided by operating activities totaled $1.1 billion$493.8 million in the first nine monthsquarter of 2013,2014, compared with $700.8$473.1 million in the same periodfirst quarter of 2012 (all amounts are net of RRB payments, which are included in financing activities on the accompanying statements of cash flows).2013. The improved operating cash flows were due primarily to the additionabsence of NSTAR, which contributed $138.1cash disbursements for major storm restoration costs and the decrease of $40.3 million of operatingin Pension and PBOP Plan cash flows (net of RRB payments)contributions, partially offset by an increase in income taxes paid in the first quarter of 2014 ($82.6 million), as compared to the first quarter of 2013 a decrease($22.2 million), and the absence of approximately $93 millionin cash disbursements for storm restoration costs recovered in rates related to the RRBs that were fully amortized in the first nine monthshalf of 2013 associated primarily with2013.
On March 28, 2014, CYAPC and YAEC received payment of $163.3 million of the February blizzard, as compared to cash disbursements for storm restoration costsDOE Phase II Damages proceeds. It is anticipated that in the first nine monthssecond quarter of 2012 associated primarily with Tropical Storm Irene2014, the Yankee Companies will complete the FERC review process and return these amounts to the October 2011 snowstorm, the absence in 2013 of $73 million in cash disbursements in the first nine months of 2012 atmember companies, including CL&P, NSTAR Electric, PSNH, and WMECO, for the benefit of their respective customers. As a result of the consolidation of CYAPC and YAEC, the cash received was included in Other Long-Term Assets on the NU consolidated balance sheet pending refund as of March 31, 2014 and in Proceeds from DOE Damages Claim with an offset in Deferred DOE Proceeds on the NU consolidated statement of cash flows for the three months ended March 31, 2014. These proceeds had no impact on NU’s earnings or net cash flows provided by operating activities for the three months ended March 31, 2014.
On January 31, 2014, Moody’s upgraded corporate credit and securities ratings of NU, CL&P and PSNH by one level and WMECO by two-levels. 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 WMECO related to customer bill credits and the absence in 2013NSTAR Gas.
Table of $34 million ofmerger-related costs inContents
In the first nine monthsquarter of 2012. Partially offsetting these favorable2014, we had cash flow impacts were a $97.4dividends on common shares of $118.5 million, increase in Pension Plan cash contributions, an increase in coal and fuel inventories, and changes in traditional working capital amounts principally due to the changes in timing of accounts receivable and accounts payable.
We paid common dividends of $341.7compared with $116.4 million in the first nine monthsquarter of 2013, compared with $267.4 million in the same period of 2012. 2013. On SeptemberFebruary 4, 2013,2014, our Board of Trustees approved a common dividend payment of $0.3675$0.3925 per share, which was paidpayable on September 30, 2013March 31, 2014 to shareholders of record as of September 16,March 3, 2014. The dividend represented an increase of 6.8 percent over the dividend paid in December 2013. On May 1, 2014, our Board of Trustees approved a common dividend payment of $0.3925 per share, payable June 30, 2014 to shareholders of record as of May 30, 2014.
In the first nine monthsquarter of 2013,2014, CL&P, NSTAR Electric, PSNH, and WMECO paid $114$42.8 million, $56$253 million, $51$16.5 million, and $30$49 million, respectively, in common dividends to their respective parent company. 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 nine monthsquarter of 2013,2014, investments for NU, CL&P, NSTAR Electric, PSNH, and WMECO were $1.1 billion, $294.6$348.7 million, $330.6$108 million, $155.7$95 million, $61.9 million, and $127.4$30.3 million, respectively.
Business Development and Capital Expenditures
Consolidated: Our consolidated capital expenditures, including amounts incurred but not paid, cost of removal, AFUDC, and the capitalized portions of pension expense (all of which are non-cash factors), totaled $1.1 billion in the first nine months of 2013, compared with $1.1 billion in the same period of 2012. These amounts included $14.7 million and $30.9$277.9 million in the first nine monthsquarter of 20132014, compared with $299.8 million in the first quarter of 2013. These amounts included $5.9 million and 2012,$5.4 million in the first quarters of 2014 and 2013, respectively, related to our corporate service companies, NUSCO and RRR.
Transmission Business:Overall, transmission business capital expenditures decreased by $47.7$53.3 million in the first nine monthsquarter of 2013,2014, as compared to the same periodfirst quarter of 2012, due primarily to the WMECO portion of GSRP nearing completion, partially offset by the addition of NSTAR Electric's capital expenditures.2013. A summary of transmission capital expenditures by company for the first ninethree months ofended March 31, 2014 and 2013 and 2012 is as follows:
|
| For the Nine Months Ended September 30, |
| For the Three Months Ended March 31, |
| ||||||||
(Millions of Dollars) |
| 2013 |
| 2012(1) |
| 2014 |
| 2013 |
| ||||
CL&P |
| $ | 133.5 |
| $ | 148.2 |
| $ | 36.2 |
| $ | 44.0 |
|
NSTAR Electric |
|
| 140.0 |
|
| 79.4 |
| 12.4 |
| 49.3 |
| ||
PSNH |
|
| 58.0 |
|
| 44.5 |
| 16.7 |
| 14.6 |
| ||
WMECO |
|
| 62.0 |
|
| 179.3 |
| 16.3 |
| 17.2 |
| ||
NPT |
|
| 32.0 |
|
| 21.8 |
| 6.7 |
| 16.5 |
| ||
Total Transmission Segment |
| $ | 425.5 |
| $ | 473.2 |
| $ | 88.3 |
| $ | 141.6 |
|
(1)
Results include transmission capital expenditures of NSTAR Electric from the date of the merger, April 10, 2012, through September 30, 2012.
NEEWS: GSRP, a project that involves the construction of 115 kV and 345 kV overhead lines by CL&P and WMECO from Ludlow, Massachusetts to Bloomfield, Connecticut, is the first, largest and most complicated project within the NEEWS family of projects. The $718 million project is currently completing its last major construction phase and, with the new 345 kV circuit in service, is already providing reliability and economic benefits to customers. We expect the project to beprojects was fully placed in service in late 2013 with a total cost approximately six percent lower than budget.energized on November 20, 2013. As of September 30, 2013, the project was approximately 98 percent complete andMarch 31, 2014, CL&P and WMECO hadhave placed $534$631.5 million in service. service with minimal remaining close-out activities continuing throughout the first half of 2014.
47
The Interstate Reliability Project, which includes CL&P’s construction of an approximately 40-mile, 345 kV overhead line from Lebanon, Connecticut to the Connecticut-Rhode Island border in Thompson, Connecticut where it will connect to transmission enhancements being constructed by National Grid, is ourthe second major NEEWS project. All siting applications have been filed by CL&P and National Grid. The Connecticut and Rhode Island portions of the project have been approved. We now have all state environmental approvals and expectapproved by their respective siting boards. On January 30, 2014, the Massachusetts EFSB voted unanimously to draft a tentative opinion approving the MA component of the project; a siting approval decision in Massachusetts is expected in the second quarter of 2014. OurIn the first quarter of 2014, the Army Corps of Engineers issued its permit on the project, which enabled construction on the Connecticut portion of the project to begin. NU’s portion of the cost is expectedestimated to be $218 million and the project is expected to be placed in service in late 2015.
The Greater Hartford Central Connecticut Study (GHCC): GHCC,, which includes the reassessment of the Central Connecticut Reliability Project, continues to make progress. In August 2012, ISO-NEThe final need results, which were presented its preliminary reliability needs assessment for GHCC to the ISO-NE Planning Advisory Committee. The resultsCommittee in November 2013, showed existing and worsening severe regional and local thermal overloads and voltage violations within and across each of the four study areas. ISO-NE is expected to confirm the preferred transmission solutions in the first halfsummer of 2014, which are likely to include many 115 kV upgrades. We continue to expect that the specific future projects being identified to address these reliability concerns will cost approximately $300 million.million and that the project will be placed in service in 2017.
Included as part of NEEWS are associated reliability related projects, approximately $82$90.5 million of which have been placed in service and approximately $12service. As of March 31, 2014, the remaining construction on the associated reliability related projects totaled $2.9 million, of which are in various phases of construction and will continueis scheduled to go into service through 2013. be completed by mid-2014.
Through September 30, 2013,March 31, 2014, CL&P and WMECO had capitalized $242$259 million and $556$571.1 million, respectively, in costs associated with NEEWS, of which $30.1$6.2 million and $37.6$4.1 million, respectively, were capitalized duringin the first nine monthsquarter of 2013. 2014.
Cape Cod Reliability Projects: Transmission projects serving Cape Cod in the Southeastern Massachusetts (SEMA) reliability region consist of an expansion and upgrade of NSTAR Electric's existing transmission infrastructure including construction of a new 345 kV transmission line that crosses the Cape Cod Canal and associated 115 kV upgrades in the center of Cape Cod (Lower SEMA Transmission Project) and related 115 kV projects (Mid-Cape Project). All regulatory licensing and permitting is complete for the Lower SEMA Transmission Project and construction commenced in September 2012. The new 345 kV line was placed into service on June 25, 2013. Additional 115 kV line upgrades are expected to be completed in late 2013. The Mid-Cape Project is scheduled to be completed in 2017. The aggregate estimated construction costs for the Cape Cod projects are expected to be approximately $150 million. Through September 30, 2013, NSTAR Electric had capitalized $91.3 million in costs associated with the Cape Cod projects, of which $55.4 million was capitalized during the first nine months of 2013.
Northern Pass: Northern Pass is NPT'sNU’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 by mid-2017. On July 1, 2013, NPT filedin 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 Presidential Permit Application Amendment. Theto issue the draft EIS in late 2014. Once it is published, DOE has completed its public scoping meetingwill commence a process of receiving written and verbal comments on the draft EIS and we expect the DOE to issue a final EIS in the second half of 2015. We expect to file the state permit application in January 2015 after the DOE’s draft EIS is currently performing field workreceived.
Greater Boston Reliability and data collection.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 first half of 2014. We expect projected costs to be approximately $480 million for these new initiatives.
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Distribution Business: A summary of distribution capital expenditures by company for the first nine monthsquarters of 20132014 and 20122013 is as follows:
| For the Nine Months Ended September 30, |
| For the Three Months Ended March 31, |
| ||||||||
(Millions of Dollars) | 2013 |
| 2012(1) |
| 2014 |
| 2013 |
| ||||
CL&P: |
|
|
|
|
|
|
|
|
|
| ||
Basic Business | $ | 42.7 |
| $ | 55.5 |
| $ | 10.7 |
| $ | 13.2 |
|
Aging Infrastructure |
| 116.6 |
|
| 133.2 |
| 34.3 |
| 29.0 |
| ||
Load Growth |
| 56.9 |
|
| 57.8 |
| 17.3 |
| 17.0 |
| ||
Total CL&P |
| 216.2 |
|
| 246.5 |
| 62.3 |
| 59.2 |
| ||
NSTAR Electric: |
|
|
|
|
|
|
|
|
|
| ||
Basic Business |
| 84.6 |
|
| 31.9 |
| 29.6 |
| 15.6 |
| ||
Aging Infrastructure |
| 75.0 |
|
| 76.6 |
| 22.9 |
| 27.3 |
| ||
Load Growth |
| 22.5 |
|
| 7.3 |
| 6.5 |
| 1.9 |
| ||
Total NSTAR Electric |
| 182.1 |
|
| 115.8 |
| 59.0 |
| 44.8 |
| ||
PSNH: |
|
|
|
|
|
|
|
|
|
| ||
Basic Business |
| 13.7 |
|
| 16.1 |
| 5.8 |
| 3.8 |
| ||
Aging Infrastructure |
| 32.2 |
|
| 33.3 |
| 12.5 |
| 7.8 |
| ||
Load Growth |
| 18.3 |
|
| 14.0 |
| 6.1 |
| 4.6 |
| ||
Total PSNH |
| 64.2 |
|
| 63.4 |
| 24.4 |
| 16.2 |
| ||
WMECO: |
|
|
|
|
|
|
|
|
|
| ||
Basic Business |
| 5.3 |
|
| 10.4 |
| 1.5 |
| 0.5 |
| ||
Aging Infrastructure |
| 16.7 |
|
| 13.8 |
| 3.3 |
| 4.3 |
| ||
Load Growth |
| 5.7 |
|
| 4.9 |
| 1.4 |
| 1.5 |
| ||
Total WMECO |
| 27.7 |
|
| 29.1 |
| 6.2 |
| 6.3 |
| ||
Total - Electric Distribution (excluding Generation) |
| 490.2 |
|
| 454.8 |
| 151.9 |
| 126.5 |
| ||
PSNH Generation |
| 2.5 |
| 0.7 |
| |||||||
WMECO Generation |
| 4.1 |
| 0.1 |
| |||||||
Total - Natural Gas |
| 126.3 |
|
| 111.9 |
| 25.2 |
| 25.5 |
| ||
Other Distribution |
| 0.4 |
|
| 0.2 | |||||||
Total Electric and Natural Gas |
| 616.9 |
|
| 566.9 | |||||||
PSNH Generation: |
|
|
|
|
| |||||||
Clean Air Project |
| - |
|
| 22.2 | |||||||
Other |
| 5.5 |
|
| 6.8 | |||||||
Total PSNH Generation |
| 5.5 |
|
| 29.0 | |||||||
WMECO Generation |
| 0.9 |
|
| 0.5 | |||||||
Total Distribution Segment | $ | 623.3 |
| $ | 596.4 | |||||||
Total Electric and Natural Gas Distribution Segment |
| $ | 183.7 |
| $ | 152.8 |
| |||||
(1)
Results include the electric and natural gas distribution capital expenditures of NSTAR from the date of the merger, April 10, 2012, through September 30, 2012.
For the electric distribution business, basic business includes the purchase of meters, tools, vehicles, information technology, transformer replacements, equipment facilities, and the relocation of plant. Aging infrastructure relates to reliability and the replacement of overhead lines, plantdistribution substations, underground cable replacement, and equipment failures. Load growth includes requests for new business and capacity additions on distribution lines and substation additions and expansions.
WMECO Solar Project: On September 4, 2013, the DPU approved WMECO's proposal to build a third solar generation facility and expand its solar energy portfolio from 6 MW to 8 MW. On October 22, 2013, WMECO announced it would install a 3.9 MW solar generation facility on a site in East Springfield, Massachusetts. The facility is expected to be completed in mid-2014 with an estimated cost of approximately $15 million. WMECO currently has two solar generation facilities in operation. The 1.8 MW solar facility in Pittsfield, Massachusetts has been operating since October 2010 and the 2.3 MW solar facility in Springfield, Massachusetts has been generating electricity since November 2011.
FERC Regulatory Issues
FERC Base ROE Complaint: On September 30, 2011, several New England state attorneys general, state regulatory commissions, consumer advocates and other parties filed a joint complaint with the FERC under Sections 206 and 306 of the Federal Power Act alleging that the base ROE used in calculating formula rates for transmission service under the ISO-NE Open Access Transmission Tariff by NETOs, including CL&P, NSTAR Electric, PSNH and WMECO, is unjust and unreasonable. The complainants asserted that the current 11.14 percent rate, which became effective in 2006, is excessive due to changes in the capital markets and are seeking an order to reduce the rate, which would be effective October 1, 2011. In response, the NETOs filed testimony and analysis based on standard FERC methodology and precedent, demonstrating that the base ROE of 11.14 percent remained just and reasonable. The FERC set the case for trial before a FERC ALJ after settlement negotiations were unsuccessful in August 2012.
49
Hearings before the FERC ALJ were held in May 2013, followed by the filing of briefs by the complainants, the Massachusetts municipal electric utilities (late interveners to the case), the FERC trial staff and the NETOs. The NETOs recommended that the current base ROE of 11.14 percent should remain in effect for the refund period (October 1, 2011 through December 31, 2012) and the prospective period (beginning when FERC issues its final decision). The complainants, the Massachusetts municipal electric utilities, and the FERC trial staff each recommended a base ROE of 9 percent or below.
On August 6, 2013, the FERC ALJ issued an initial decision, finding that the current base ROE is not reasonable under the standard application of FERC methodology, but leaving policy considerations and additional adjustments to the FERC. Using the established FERC methodology, the FERC ALJ determined that a separate base ROE should be set for the refund period and the prospective period. The FERC ALJ found those base ROEs to be 10.6 percent and 9.7 percent, respectively. The FERC may adjust the prospective period base ROE in its final decision to reflect movement in 10-year Treasury bond rates from when the case was filed (April 2013) to the date of the final decision. The parties filed briefs on this decision to the FERC, and a decision from the FERC is expected in 2014. Though NU cannot predict the ultimate outcome of this proceeding, during the third quarter of 2013, the Company recorded a series of reserves at its electric subsidiaries to recognize the potential financial impact from the FERC ALJ's initial decision for the refund period. As a result, the aggregate after-tax charge to earnings totaled $14.3 million at NU. This represents reserves of $7.7 million at CL&P, $3.4 million at NSTAR Electric, $1.4 million at PSNH and $1.8 million at WMECO.
We expect the CL&P, NSTAR Electric, PSNH, and WMECO aggregate shareholder equity invested in their transmission facilities to be approximately $2.4 billion at the end of 2013. As a result, each 10 basis point change in the prospective period authorized base ROE would change annual consolidated earnings by an approximate $2.4 million.
Regulatory Developments and Rate Matters
The Regulated companies'companies’ distribution rates are set by their respective state regulatory commissions, and their tariffs include mechanisms for periodically adjusting their rates. Other than as described below, for the first nine monthsquarter of 2013,2014, 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“Financial Condition and Business Analysis –— Regulatory Developments and Rate Matters"Matters” included in Item 7, "“Management'sManagement’s Discussion and Analysis of Financial Condition and Results of Operations,"” of the NU 20122013 Annual Report on Form 10-K.
Major Storms:Connecticut:
2013, 2012 and 2011 Major Storms: In 2013, 2012 and 2011, CL&P NSTAR Electric, PSNH and WMECO each experienced significant storms that impacted their service territories, including Tropical2014 Storm Irene, the October 2011 snowstorm, Storm Sandy, and the February 2013 blizzard. As of September 30, 2013, the estimated storm restoration costs deferred for future recovery for major storms that occurred during these time periods at CL&P, NSTAR Electric, PSNH, and WMECO were as follows:
(Millions of Dollars) |
| 2012 |
| 2013 |
| Total |
CL&P |
| $ 462.0 |
| $ 28.7 |
| $ 490.7 |
NSTAR Electric |
| 64.9 |
| 63.6 |
| 128.5 |
PSNH |
| 33.5 |
| 2.3 |
| 35.8 |
WMECO |
| 35.4 |
| - |
| 35.4 |
Total |
| $ 595.8 |
| $ 94.6 |
| $ 690.4 |
The magnitude of these storm restoration costs met the criteria for cost deferral in Connecticut, Massachusetts, and New Hampshire, and as a result, the storms had no material impact on the results of operations of CL&P, NSTAR Electric, PSNH and WMECO. We believe our response to all of these storms was prudent and therefore we believe it is probable that CL&P, NSTAR Electric, PSNH and WMECO will be allowed to recover the deferred storm restoration costs. Each operating company is seeking recovery of its estimated deferred storm restoration costs through its applicable regulatory recovery process.
Connecticut 2013 Storm Filing: Order: In March 2013, CL&P filed a request with PURA for approval to recover storm restoration costs associated with five major storms, all of which occurred in 2011 and 2012. CL&P's&P’s deferred storm restoration costs associated with these major storms totaled $462 million. Of that amount, approximately $414 million is subject to recovery in rates after giving effect to CL&P’s agreement to forego the recovery of $40 million of previously deferred storm restoration costs as well as an existing storm reserve fund balance of approximately $8 million. During the second half of 2013, the PURA proceeded with the storm recovery review issuing discovery requests, holding hearings and ultimately on March 12, 2014, issuing a final decision on the level of storm costs recovery.
In its final decision, the PURA approved recovery of $365 million of deferred storm restoration costs and ordered CL&P is seeking to recovercapitalize approximately $18 million of the $414deferred storm restoration costs as utility plant, which will be recovered through depreciation expense in future rate proceedings. PURA will allow recovery of the $365 million pluswith carrying costs,charges in itsCL&P’s distribution rates over a six-year period beginning on December 1, 2014, in accordance with the PURA-approved Connecticut settlement agreement. In September 2013, PURA completed hearings to review the March 2013 filing. Currently2014. The remaining costs were either disallowed or we believe will be recovered from other sources. These costs did not have a material impact on CL&P is in the briefing stage&P’s financial position, results of the PURA review process with the proposed schedule providing a final PURA decision regarding the recoveryoperations or cash flows.
Table of these storm restoration costs in late-January 2014. Contents
WMECO SRRCA Mechanism: New Hampshire:In February 2011, at the time of the last base distribution rate case, WMECO established a Storm Reserve Recovery Cost Adjustment (SRRCA) mechanism to recover the restoration costs associated with seven major storms, which occurred between June 2008 and May 2010, and to allow WMECO to request approval to recover qualified incremental major storm restoration costs over a five-year period. WMECO began recovering the restoration costs of these seven major storms effective February 1, 2011, subject to further review and reconciliation. On October 31, 2011, WMECO requested approval to recover the restoration costs of four additional major storms, all of which occurred in 2011 and included Tropical Storm Irene. WMECO began recovering the restoration costs of these four major storms effective January 1, 2012, subject to further review and reconciliation. The
50
DPU consolidated its review of the restoration costs for these eleven major storms into a single proceeding. Hearings were conducted in early April 2013, followed by the submission of initial and reply briefs in May and June 2013. Collectively, WMECO is requesting that the DPU approve the recovery of storm restoration costs totaling $24 million for these eleven storms.
Massachusetts 2013 Storm Filings: In March 2013, NSTAR Electric filed a request with the DPU for approval to recover approximately $35 million in storm restoration costs, plus carrying costs, related to Tropical Storm Irene and the October 2011 snowstorm. NSTAR Electric is seeking to recover these costs in its distribution rates over a five-year period beginning on January 1, 2014 in accordance with the DPU-approved Massachusetts comprehensive merger settlement agreement. Hearings were conducted in early August 2013, followed by the submission of simultaneous initial briefs on August 28, 2013 and simultaneous reply briefs on September 6, 2013.
On August 30, 2013, WMECO filed its annual SRRCA filing for restoration costs incurred for the October 2011 snowstorm ($23 million) and Storm Sandy ($4 million) for a total of $27 million. WMECO is seeking to recover these costs in its distribution rates over a five-year period beginning on January 1, 2014.
DPU Storm Penalties:In December 2012, in separate orders issued by the DPU, NSTAR Electric and WMECO received penalties related to the investigation into the electric utilities’ responses to Tropical Storm Irene and the October 2011 snowstorm. The DPU ordered penalties of $4.1 million and $2 million for NSTAR Electric and WMECO, respectively, which have been refunded to their customers. In December 2012, NSTAR Electric and WMECO each filed appeals with the SJC arguing the DPU penalties should be vacated. A briefing schedule has been established, with NSTAR Electric and WMECO’s initial briefs due to be submitted on November 5, 2013 and the Massachusetts Attorney General's response brief due 30 days later. Oral arguments are scheduled for March 2014.
Long-Term Wind ContractsGeneration: NSTAR Electric and WMECO, along with two other Massachusetts utilities, signed a long-term commitment, as required by regulation, to purchase wind power from six wind farms in Maine and New Hampshire for a combined estimated generating capacity of approximately 550 MW. These contracts were filed jointly with the DPU on September 20, 2013. Over the life of the 15- to 20-year contracts, the utilities will pay an average price of less than $0.08 per kWh. The projects are in various stages of permitting or development and are expected to begin operation between 2014 and 2016.
On September 19, 2013, CL&P, along with another Connecticut utility, signed long-term commitments, as required by regulation, to purchase approximately 250 MW of wind power from a Maine wind farm and 20 MW of solar power from sites in Connecticut, at a combined average price of less than $0.08 per kWh. On October 23, 2013, PURA issued a final decision accepting the contracts. The two projects are expected to be operational by the end of 2016. For further information, see "Legislative and Policy Matters – 2013 Connecticut Legislation" in thisManagement’s Discussion and Analysis.
Connecticut:
Yankee Gas: On June 14, 2013, Yankee Gas and other Connecticut natural gas distribution companies filed a comprehensive joint natural gas infrastructure expansion plan (expansion plan) with DEEP and PURA in response to Connecticut Governor Malloy’s Comprehensive Energy Strategy (CES) and the recently enacted Connecticut Public Act 13-298, "An Act Concerning Implementation of Connecticut’s Comprehensive Energy Strategy and Various Revisions to the Energy Statutes." The expansion plan describes how the natural gas distribution companies expect to add approximately 280,000 new natural gas heating customers over the next 10 years, 82,000 of those for Yankee Gas. The expansion plan outlines a set of comprehensive recommendations, several of which are already incorporated into Public Act 13-298. Key recommendations include providing more flexibility in the process of adding new customers, establishing new regulatory tools to help fund conversion costs over time, providing for mechanisms for timely recovery of capital investments made by natural gas distribution companies and allowing utilities to secure additional pipeline capacity into Connecticut. On July 16, 2013, DEEP issued a determination letter finding the expansion plan was consistent with the CES and requesting certain modifications to be made. On July 26, 2013, the natural gas distribution companies submitted their responses to DEEP and PURA. PURA has conducted hearings on the expansion plan, has concluded briefing, and intends to issue a final decision approving or modifying the expansion plan on November 21, 2013. For further information on the Connecticut legislation, see "Legislative and Policy Matters – 2013 Connecticut Legislation" in thisManagement’s Discussion and Analysis.
New Hampshire:
PSNH Generation: On July 15,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 fromby the NHPUC, Staff a "Report on Investigation into Market Conditions, Default Service Rate, Generation Ownership and Impact on the Competitive Electricity Market." The reportNHPUC staff recommended that the NHPUC open a proceeding to examine whether default service rates remain sustainable on a going forward basis, define "just“just and reasonable"reasonable” with respect to default service in the context of competitive retail markets, analyze the current and expected value of PSNH’s generating units, and identify means to mitigate and address stranded cost recovery. On September 18,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 Request for Proposal“Preliminary Status Report Addressing the Economic Interest of PSNH’s Retail Customers as it Relates to hirethe Potential Divestiture of PSNH’s Generating Plants”, which included a valuation expert to determineconsultant’s analysis of the fair market value of PSNH'sPSNH 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 entitlements. The expert will be announcedcompared that amount to a stated net book value of $660 million, implying potential “stranded costs” in early November 2013withexcess of $400 million. NHPUC staff made three recommendations: (1) that any further actions relating to PSNH’s generating assets await a final valuation report due no later than 180 days afterdecision in the dateClean 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 expert is hired. No further schedule has been announced. At this time, we cannot predicteconomic and reliability consequences of retirement of PSNH’s fossil generating plants. In the outcomeevent of this review.generation asset divestiture or retirement, both present law and the PSNH Restructuring Settlement Agreement approved in 2000 require that the NHPUC provide stranded cost recovery to PSNH. We continue to believe all costs and generation investments are probable of recovery. Our current PSNH generation rate base is approximately $750 million.
51
Clean Air Project Prudence Proceeding: In November 2011, the NHPUC opened a docket to review the Clean Air Project including the establishment of temporary rates for near-term recovery of Clean Air Project costs, a prudence review of PSNH's overall construction program, and establishment of permanent rates for recovery of prudently incurred Clean Air Project costs. In April 2012, the NHPUC issued an order authorizing temporary rates to recover a significant portion of the Clean Air Project costs. The docket will remain open to conduct a comprehensive prudence review of the Clean Air Project and the establishment of a permanent rate. The temporary rates will remain in effect until a permanent rate allowing full recovery of all prudently incurred costs is approved. At that time, the NHPUC will reconcile recoveries collected under the temporary rates with approved permanent rates.
The NHPUC has issued a series of orders ruling on the scope of its inquiry and discovery issues. In September 2013, PSNH filed an appeal with the New Hampshire Supreme Court regarding the scope of the docket and is awaiting a Supreme Court decision on whether it will accept the case for review at this time. The NHPUC has suspended its docket pending action by the Supreme Court. We continue to believe that we were prudent in the undertaking and completion of the Clean Air Project. However, we cannot predict with certainty the outcome of the Clean Air Project prudence review, but believe all costs were incurred appropriately and are probable of recovery.
Legislative and Policy Matters
2013 Connecticut Legislation: Connecticut Governor Malloy signed into law two significant energy bills that were enacted by the legislature during the 2013 session. The first law, Public Act 13-298, implemented a number of the recommendations proposed in the CES. Public Act 13-298 authorized the filing of a plan to expand natural gas service to Connecticut residents that currently do not have access to natural gas. For further information on Yankee Gas’ filing, see “Regulatory Developments and Rate Matters – Connecticut – Yankee Gas” in thisManagement's Discussion and Analysis of Financial Condition and Results of Operations. The law also required PURA to implement decoupling for each of Connecticut’s electric and natural gas utilities in their next respective rate cases. PURA is required to implement decoupling for electric utilities that reconciles actual revenues to allowed revenues. For natural gas distribution companies, the decoupling mechanism is required to be a mechanism that does not remove the incentive to support the expansion of natural gas use pursuant to the CES (such as a mechanism that decouples distribution revenue based on a use-per-customer basis). Finally, the law allows electric distribution companies to recover their costs as well as lost revenues from various state energy policy initiatives, including expanded energy efficiency programs.
The second law, Public Act 13-303, "An Act Concerning Connecticut’s Clean Energy Goals," allows DEEP to conduct a process to procure from renewable energy generators, under long-term contracts with the electric distribution companies, additional renewable generation to help Connecticut meet its Renewable Portfolio Standard (RPS). Large scale hydropower facilities located in the New England Power Pool Generation Information System (NEPOOL GIS) geographic eligibility area or an area abutting the northern boundary of the NEPOOL GIS geographic eligibility area are eligible to bid into DEEP's process. If Connecticut experiences a material shortfall in reaching its RPS goals, such hydropower, under certain conditions, can be used to alleviate such shortfall, up to five percent of RPS requirements in 2020.
The law also requires DEEP to develop a schedule to assign a gradually reducing renewable energy credit value for all Class I biomass or landfill generation facilities. Such reduced credit values will not apply to biogas or anaerobic digestion facilities, or to facilities that have a long-term contract in place. The commissioner of DEEP may adjust such changes to the values of renewable energy credits, if such adjustment is appropriate given the availability of other Class I renewable energy sources.
On September 26, 2013, DEEP issued a final determination that authorized the state’s electric distribution companies to enter into long term power purchase agreements for a total of 270 MW of Class I renewable generation from two projects. On October 23, 2013, PURA issued a final decision accepting the contracts presented by the electric distribution companies. On October 21, 2013, DEEP issued a Request for Proposal seeking proposals for energy and RECs from private developers for up to 4 percent of the state’s electric distribution companies’ load (estimated to be between 100 MW to 150 MW) of Class I renewable energy resources for biomass, landfill gas and run off river hydropower projects from new or existing facilities. Proposals are due to DEEP on November 18, 2013.
2013 Massachusetts: On July 24, 2013, Massachusetts enacted a law that changes the income tax rate applicable to utility companies effective January 1, 2014, from 6.5 percent to 8 percent. The tax law change required NU to remeasure its deferred taxes and resulted in NU increasing its deferred tax liability with an offsetting regulatory asset of approximately $61 million at its utility companies ($46.4 million at NSTAR Electric and $9.8 million at WMECO).
2013 Federal: On September 13, 2013, the Internal Revenue Service issued final Tangible Property regulations. The final regulations are meant to simplify, clarify and make more administrable the previously issued temporary and proposed regulations. In the third quarter of 2013, CL&P recorded an after-tax valuation allowance of $10.5 million against its deferred tax assets as a result of these regulations. NU continues to evaluate the implications of these new regulations, including several new elections. Therefore, a change to the valuation allowance at CL&P could result once NU completes the review of the impact of the final regulations.
Critical Accounting Policies
The preparation of financial statements in conformity with GAAP requires management to make estimates, assumptions and, at times, difficult, subjective or complex judgments. Changes in these estimates, assumptions and judgments, in and of themselves, could materially impact our financial position, results of operations or cash flows. Our management communicates to and discusses with the Audit Committee of our Board of Trustees significant matters relating to critical accounting policies. Our critical accounting policies that
52
we believed were the most critical in nature were reported in NU’s 2012the NU 2013 Form 10-K. There have been no material changes with regard to these critical accounting policies.
Other Matters
Accounting Standards: Standards Recently Adopted: For information regarding new accounting standards, see Note 1B, "Summary“Summary of Significant Accounting Policies –— Recently Adopted Accounting Standards." Standards,” to the financial statements.
Contractual Obligations and Commercial Commitments: Refer There have been no material changes with regard to Note 9B, "Commitmentsthe contractual obligations and Contingencies – Long-Term Contractual Arrangements," for discussion of material contractual obligations.commercial commitments disclosed in the NU 2013 Form 10-K.
Web Site: Additional financial information is available through our web site atwww.nu.com.
53
RESULTS OF OPERATIONS –— NORTHEAST UTILITIES AND SUBSIDIARIES
The following table provides the amounts and variances in operating revenues and expense line items for the condensed consolidated statements of income for NU included in this Quarterly Report on Form 10-Q for the three and nine months ended September 30, 2013March 31, 2014 and 2012: 2013:
|
|
| Operating Revenues and Expenses |
|
| Operating Revenues and Expenses |
|
| Operating Revenues and Expenses |
| |||||||||||||||||||||||||||
| For the Three Months Ended September 30, |
|
| For the Nine Months Ended September 30, |
|
| For the Three Months Ended March 31, |
| |||||||||||||||||||||||||||||
|
|
|
|
|
|
|
|
| Increase/ |
|
|
|
|
|
|
|
|
|
| Increase/ |
|
|
|
|
|
|
|
| Increase/ |
|
|
| |||||
(Millions of Dollars) | (Millions of Dollars) | 2013 |
| 2012 |
| (Decrease) |
| Percent |
|
| 2013 |
| 2012(a) |
| (Decrease) |
| Percent |
|
| 2014 |
| 2013 |
| (Decrease) |
| Percent |
| ||||||||||
Operating Revenues | Operating Revenues | $ | 1,892.6 |
| $ | 1,861.5 |
| $ | 31.1 |
| 1.7 | % |
| $ | 5,523.5 |
| $ | 4,589.8 |
| $ | 933.7 |
| 20.3 | % |
| $ | 2,290.6 |
| $ | 1,995.0 |
| $ | 295.6 |
| 14.8 | % | |
Operating Expenses: | Operating Expenses: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| ||||
| Purchased Power, Fuel and Transmission |
| 645.9 |
|
| 602.8 |
|
| 43.1 |
| 7.1 |
|
|
| 1,882.0 |
|
| 1,540.1 |
|
| 341.9 |
| 22.2 |
| |||||||||||||
| Operations and Maintenance |
| 386.7 |
|
| 395.5 |
|
| (8.8) |
| (2.2) |
|
|
| 1,090.0 |
|
| 1,187.4 |
|
| (97.4) |
| (8.2) |
| |||||||||||||
| Depreciation |
| 149.1 |
|
| 144.5 |
|
| 4.6 |
| 3.2 |
|
|
| 463.6 |
|
| 369.8 |
|
| 93.8 |
| 25.4 |
| |||||||||||||
| Amortization of Regulatory Assets, Net |
| 70.0 |
|
| 43.8 |
|
| 26.2 |
| 59.8 |
|
|
| 178.7 |
|
| 74.9 |
|
| 103.8 |
| (b) |
| |||||||||||||
| Amortization of Rate Reduction Bonds |
| - |
|
| 43.0 |
|
| (43.0) |
| (100.0) |
|
|
| 42.6 |
|
| 102.1 |
|
| (59.5) |
| (58.3) |
| |||||||||||||
| Energy Efficiency Programs |
| 106.1 |
|
| 98.3 |
|
| 7.8 |
| 7.9 |
|
|
| 306.0 |
|
| 209.1 |
|
| 96.9 |
| 46.3 |
| |||||||||||||
| Taxes Other Than Income Taxes |
| 135.5 |
|
| 120.7 |
|
| 14.8 |
| 12.3 |
|
|
| 391.8 |
|
| 319.6 |
|
| 72.2 |
| 22.6 |
| |||||||||||||
|
| Total Operating Expenses |
| 1,493.3 |
|
| 1,448.6 |
|
| 44.7 |
| 3.1 |
|
|
| 4,354.7 |
|
| 3,803.0 |
|
| 551.7 |
| 14.5 |
| ||||||||||||
Purchased Power, Fuel and Transmission |
| 978.2 |
| 747.8 |
| 230.4 |
| 30.8 |
| ||||||||||||||||||||||||||||
Operations and Maintenance |
| 351.7 |
| 346.1 |
| 5.6 |
| 1.6 |
| ||||||||||||||||||||||||||||
Depreciation |
| 150.8 |
| 155.0 |
| (4.2 | ) | (2.7 | ) | ||||||||||||||||||||||||||||
Amortization of Regulatory Assets, Net |
| 57.9 |
| 54.0 |
| 3.9 |
| 7.2 |
| ||||||||||||||||||||||||||||
Amortization of Rate Reduction Bonds |
| — |
| 34.5 |
| (34.5 | ) | (100.0 | ) | ||||||||||||||||||||||||||||
Energy Efficiency Programs |
| 138.8 |
| 105.8 |
| 33.0 |
| 31.2 |
| ||||||||||||||||||||||||||||
Taxes Other Than Income Taxes |
| 145.5 |
| 132.9 |
| 12.6 |
| 9.5 |
| ||||||||||||||||||||||||||||
Total Operating Expenses |
| 1,822.9 |
| 1,576.1 |
| 246.8 |
| 15.7 |
| ||||||||||||||||||||||||||||
Operating Income | Operating Income | $ | 399.3 |
| $ | 412.9 |
| $ | (13.6) |
| (3.3) | % |
| $ | 1,168.8 |
| $ | 786.8 |
| $ | 382.0 |
| 48.6 | % |
| $ | 467.7 |
| $ | 418.9 |
| $ | 48.8 |
| 11.6 | % | |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| ||||||||||||
(a) The 2012 results include the operations of NSTAR from the date of the merger, April 10, 2012, through September 30, 2012. | |||||||||||||||||||||||||||||||||||||
(b) Percent greater than 100 percent not shown as it is not meaningful. | |||||||||||||||||||||||||||||||||||||
Operating Revenues |
|
|
|
|
|
|
|
|
|
|
|
|
| |||||||||||
|
| For the Three Months Ended September 30, |
|
| For the Nine Months Ended September 30, |
| ||||||||||||||||||
(Millions of Dollars) | 2013 |
| 2012 |
| Increase/ (Decrease) |
| Percent |
|
| 2013 |
| 2012(a) |
| Increase/ (Decrease) |
| Percent |
| |||||||
Electric Distribution | $ | 1,508.6 |
| $ | 1,483.7 |
| $ | 24.9 |
| 1.7 | % |
| $ | 4,104.4 |
| $ | 3,499.7 |
| $ | 604.7 |
| 17.3 | % | |
Natural Gas Distribution |
| 97.1 |
|
| 91.3 |
|
| 5.8 |
| 6.4 |
|
|
| 613.0 |
|
| 361.5 |
|
| 251.5 |
| 69.6 |
| |
| Total Distribution |
| 1,605.7 |
|
| 1,575.0 |
|
| 30.7 |
| 1.9 |
|
|
| 4,717.4 |
|
| 3,861.2 |
|
| 856.2 |
| 22.2 |
|
Transmission |
| 234.1 |
|
| 235.6 |
|
| (1.5) |
| (0.6) |
|
|
| 721.5 |
|
| 627.2 |
|
| 94.3 |
| 15.0 |
| |
| Total Regulated Companies |
| 1,839.8 |
|
| 1,810.6 |
|
| 29.2 |
| 1.6 |
|
|
| 5,438.9 |
|
| 4,488.4 |
|
| 950.5 |
| 21.2 |
|
Other and Eliminations |
| 52.8 |
|
| 50.9 |
|
| 1.9 |
| 3.7 |
|
|
| 84.6 |
|
| 101.4 |
|
| (16.8) |
| (16.6) |
| |
Total Operating Revenues | $ | 1,892.6 |
| $ | 1,861.5 |
| $ | 31.1 |
| 1.7 | % |
| $ | 5,523.5 |
| $ | 4,589.8 |
| $ | 933.7 |
| 20.3 | % | |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(a) The 2012 results include the operations of NSTAR from the date of the merger, April 10, 2012, through September 30, 2012. | ||||||||||||||||||||||||
A summary of our retail electric sales and firm natural gas sales were as follows: | ||||||||||||||||||
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| For the Three Months Ended September 30, |
|
| For the Nine Months Ended September 30, |
| ||||||||||||
|
|
|
|
|
| Increase/ |
|
|
|
|
|
|
|
|
|
|
|
|
|
| 2013 |
| 2012 |
| (Decrease) |
| Percent |
|
| 2013 |
| 2012(a) |
| Increase |
| Percent |
|
Retail Electric Sales in GWh | 15,247 |
| 15,501 |
| (254) |
| (1.6) | % |
| 41,954 |
| 41,697 |
| 257 |
| 0.6 | % | |
Firm Natural Gas Sales in Million Cubic Feet | 11,173 |
| 10,696 |
| 477 |
| 4.5 |
|
| 68,046 |
| 60,035 |
| 8,011 |
| 13.3 |
| |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(a) Results include the retail electric sales of NSTAR Electric and the firm natural gas sales of NSTAR Gas from January 1, 2012 |
| |||||||||||||||||
| through September 30, 2012 for comparative purposes only. |
|
|
|
|
| ||||||||||||
Our Operating Revenues
|
| For the Three Months Ended March 31, |
| |||||||||
(Millions of Dollars) |
| 2014 |
| 2013 |
| Increase |
| Percent |
| |||
Electric Distribution |
| $ | 1,585.9 |
| $ | 1,374.2 |
| $ | 211.7 |
| 15.4 | % |
Natural Gas Distribution |
| 432.8 |
| 361.8 |
| 71.0 |
| 19.6 |
| |||
Total Distribution |
| 2,018.7 |
| 1,736.0 |
| 282.7 |
| 16.3 |
| |||
Transmission |
| 252.1 |
| 239.5 |
| 12.6 |
| 5.3 |
| |||
Total Regulated Companies |
| 2,270.8 |
| 1,975.5 |
| 295.3 |
| 14.9 |
| |||
Other and Eliminations |
| 19.8 |
| 19.5 |
| 0.3 |
| 1.5 |
| |||
Total Operating Revenues |
| $ | 2,290.6 |
| $ | 1,995.0 |
| $ | 295.6 |
| 14.8 | % |
A summary of our retail electric sales and firm natural gas sales were as follows:
|
| For the Three Months Ended March 31, |
| ||||||
|
| 2014 |
| 2013 |
| Increase |
| Percent |
|
Retail Electric Sales in GWh |
| 14,348 |
| 13,796 |
| 552 |
| 4.0 | % |
Firm Natural Gas Sales in Million Cubic Feet |
| 46,917 |
| 40,615 |
| 6,302 |
| 15.5 |
|
Operating revenues increased $31.1$295.6 million in the third quarter of 2013, as compared to the thirdfirst quarter of 2012, due primarily to:
·
A $3.6 million increase in base electric distribution revenues, net of applicable eliminations, despite a 1.6 percent decrease in retail electric sales.2013. The increase in revenue was primarily driven by an NHPUC-approved distribution rate increase at PSNH effective July 1, 2013reflects higher retail electric and firm natural gas sales volumes as a result of the 2010significantly colder than normal winter temperatures and the overall impact of higher wholesale energy costs in New England. The wholesale energy markets 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 on wholesale energy costs are recovered from customers in rates and therefore have no impact on earnings.
As noted above, the increase in distribution rate case settlement and higher demand revenue. The decreaserevenues reflect an increase of approximately 4 percent in retail electric sales was primarily driven by slightly cooler summer weather experiencedand 15.5 percent in the third quarter of 2013, as compared to the same period in 2012, and the impact of company-sponsored energy efficiency programs.
·
A $24.8 million increase in transmission revenues, net of applicable eliminations, as a result of the recovery of higher transmission expenses and continuing investments in our transmission infrastructure. The increase was partially offset by the establishment of a reserve related to an August 2013 initial decision from a FERC ALJ that lowers the base ROE earned by New England transmission owners for the 15-month period ended December 31, 2012. For further information, see “FERC Regulatory Issues - FERC Base ROE Complaint” in thisManagement's Discussion and Analysis of Financial Condition and Results of Operations.
·
The remaining increase was due primarily to higher revenues from the Company’s reconciling costs recovery mechanisms. Revenues related to cost recovery mechanisms vary from period to period based on the timing of collections of the costs incurred. These revenues had no material impact on earnings.
Our Operating Revenues increased $933.7 million for the nine months ended September 30, 2013, as compared to the same period in 2012. The primary driver of the increase was the absence of NSTAR in the first quarter of 2012. During the first quarter of 2013, the
54
former operating subsidiaries of NSTAR contributed approximately $800 million of operating revenues. In the absence of NSTAR, our Operating Revenues increased approximately $134 million due primarily to:
·
A $24.1 million increase in base electric distribution revenues, net of applicable eliminations, reflecting a 0.6 percent increase in retail electricfirm natural gas sales. The increase in sales volumes was driven primarily by the coldercold winter weather experienced throughout our service territories in early 2013,the first quarter of 2014. The winter was significantly colder than both normal and last year throughout New England. Weather-normalized retail electric sales (based on 30-year average temperatures) increased 1.3 percent in the first quarter of 2014, as compared to the same period in 2012. In addition,2013, reflecting a steady improvement in economic conditions across our service territory. Weather-normalized total firm natural gas sales increased 3.6 percent in the increasefirst quarter of 2014, as compared to the same period in 2013, due primarily to residential and commercial customer growth.
The positive impacts on sales volume were partially offset by customer savings due to the impact of our respective utility-sponsored energy efficiency programs. Certain utility operating companies are permitted to bill customers for lost base revenues resulted from the NHPUC-approved distribution rate increases at PSNH effective July 1, 2012 and July 1, 2013related to reductions in sales volume as a result of their energy efficiency. In the 2010 distribution rate case settlement. These positive impacts on revenue were partially offset byfirst quarter of 2014, the impactrecognition of our company-sponsored energy efficiency programs.lost base revenues increased $4.8 million compared to the first quarter of 2013.
·
A $31.5 millionThe increase in transmission revenues, net of applicable eliminations, as a result ofreflects the recovery of higher transmission expenses and continuingincluding ongoing investments in our transmission infrastructure. The increase was partially offset by the establishment
Table of a reserve related to the FERC ALJ initial decisionContents
Purchased Power, Fuel and Transmission increased in the thirdfirst quarter of 2013.
·
A $20 million increase in firm natural gas revenues. This increase was driven by the colder winter weather in early 2013,2014, as compared to the same period in 2012.
·
The remaining increase wasfirst quarter of 2013, due primarily to higher revenues from the Company’s reconciling costs recovery mechanisms. Revenues related to cost recovery mechanisms vary from period to period based on the timing of collections of the costs incurred. These revenues had no material impact on earnings. following:
(Millions of Dollars) |
| Increase/(Decrease) |
| |
Electric distribution segment fuel and energy supply costs |
| $ | 238.8 |
|
Firm natural gas sales related costs |
| 33.9 |
| |
Transmission segment costs |
| 35.2 |
| |
Other and eliminations |
| 11.1 |
| |
Partially offset by: |
|
|
| |
Electric distribution segment deferred fuel costs |
| (88.6 | ) | |
|
| $ | 230.4 |
|
Purchased Power, FuelOperations and TransmissionMaintenance increased forin the three and nine months ended September 30, 2013,first quarter of 2014, as compared to the same periods in 2012,first quarter of 2013, due primarily to the following:
(Millions of Dollars) | Three Months Ended |
| Nine Months Ended | ||
The addition of NSTAR's operations | $ | n/a |
| $ | 321.4 |
Transmission segment costs |
| 39.1 |
|
| 50.3 |
Electric distribution segment deferred fuel costs |
| 27.5 |
|
| 29.9 |
Firm natural gas sales related costs |
| 1.3 |
|
| 24.2 |
Partially offset by: |
|
|
|
|
|
Electric distribution segment fuel and energy supply costs |
| (3.1) |
|
| (46.7) |
RECs and emission allowances |
| (18.7) |
|
| (28.2) |
Other and eliminations |
| (3.0) |
|
| (9.0) |
| $ | 43.1 |
| $ | 341.9 |
(Millions of Dollars) |
| Increase/(Decrease) |
| |
Electric Distribution: |
|
|
| |
Bad debt expense |
| $ | 6.9 |
|
General and administrative |
| 7.4 |
| |
Pension and employee benefit costs |
| (15.3 | ) | |
Storm costs |
| (5.3 | ) | |
Total Electric Distribution |
| (6.3 | ) | |
Total Natural Gas Distribution |
| 4.1 |
| |
Total Distribution |
| (2.2 | ) | |
Total Transmission maintenance costs |
| 2.4 |
| |
Other and eliminations: |
|
|
| |
Integration and severance costs |
| 6.9 |
| |
Other |
| (1.5 | ) | |
Total Operations and Maintenance |
| $ | 5.6 |
|
The Operations and Maintenance expense increase of $5.6 million includes costs that are recovered through cost tracking mechanisms, which have no earnings impact. The Operations and Maintenance expenses that are recovered through base distribution rates (and therefore impact earnings) decreased for$3.7 million in the three and nine months ended September 30, 2013,first quarter of 2014, as compared to the same periods in 2012,first quarter of 2013, due primarily to the following:a decrease in pension and employee benefit costs.
| Three Months Ended |
| Nine Months Ended | ||
(Millions of Dollars) | Increase/(Decrease) |
| Increase/(Decrease) | ||
The addition of NSTAR’s operations | $ | n/a |
| $ | 123.6 |
Partially offset by: |
|
|
|
|
|
Absence of merger and settlement agreement costs |
| - |
|
| (148.2) |
Electric distribution segment costs |
| 3.6 |
|
| (39.5) |
NU’s unregulated contracting business costs |
| (7.5) |
|
| (13.8) |
Transmission segment costs |
| 2.0 |
|
| (7.8) |
General and administrative costs |
| 2.2 |
|
| (6.6) |
Customer EIA incentives |
| (6.1) |
|
| (5.8) |
Natural gas segment costs |
| 4.7 |
|
| 1.9 |
Other and eliminations |
| (7.7) |
|
| (1.2) |
| $ | (8.8) |
| $ | (97.4) |
Depreciationincreased fordecreased in the three and nine months ended September 30, 2013,first quarter of 2014, as compared to the same periods in 2012,first quarter of 2013, due primarily to the addition of NSTAR ($54.2 million for the nine months) and an increase as a result of the consolidation ofdecrease in CYAPC and YAEC decommissioning collections ($13.7 million for the nine months). Excluding the impact of NSTAR and the consolidation of CYAPC and YAEC, depreciation increased due primarily12.5 million), partially offset by an increase related to higher utility plant balances resulting from completed construction projects placed into service.service ($8.3 million).
Amortization of Regulatory Assets, Net increased forin the three and nine months ended September 30, 2013,first quarter of 2014, as compared to the same periods in 2012,first quarter of 2013, due primarily to the following:
| Three Months Ended |
| Nine Months Ended | ||||||
(Millions of Dollars) | Increase/(Decrease) |
| Increase/(Decrease) |
| Increase/(Decrease) |
| |||
The addition of NSTAR’s operations | $ | n/a |
| $ | 45.8 | ||||
Recovery of transition costs at NSTAR Electric |
| 31.5 |
| 77.1 |
| $ | (31.2 | ) | |
Amortization related to CL&P’s SBC and CTA |
| (9.9) |
| (14.0) | |||||
Increases in the SCRC, ES and TCAM amortizations at PSNH |
| 15.7 |
| ||||||
Amortization related to deferred energy efficiency program costs at CL&P |
| 14.3 |
| ||||||
Other |
| 4.6 |
|
| (5.1) |
| 5.1 |
| |
| $ | 26.2 |
| $ | 103.8 |
| $ | 3.9 |
|
55
Amortization of Rate Reduction Bonds decreased forin the three and nine months ended September 30, 2013,first quarter of 2014, as compared to the same periods in 2012,first quarter of 2013, due primarily to the maturity in 2013 of RRBs of NSTAR Electric's, PSNH's,Electric, PSNH, and WMECO's RRBs in 2013, partially offset by the addition of NSTAR Electric’s amortization ($15.1 million for the nine months).WMECO.
Energy Efficiency Programs increased forin the three and nine months ended September 30, 2013,first quarter of 2014, as compared to the same periods in 2012,first quarter of 2013, due primarily to the addition of NSTAR's operations ($68.6 million for the nine months), as well as an increase in energy efficiency costs in accordance with the three-year program guidelines established by the DPU at NSTAR Electric and WMECO.WMECO and expanded energy conservation programs at CL&P in 2014. All costs are fully recovered through DPU-approvedapproved tracking mechanisms and therefore do not impact earnings.
Taxes Other Than Income Taxes increased forin the three and nine months ended September 30, 2013,first quarter of 2014, as compared to the same periods in 2012,first quarter of 2013, due primarily to the addition of NSTAR's operations ($37.8 million for the nine months). In addition, there was an increase in property taxes ($7.5 million) as a result of both an increase in Property, Plantutility plant balances and Equipment related to our regulated capital programs and an increase in the property tax rates, and an increase in the Connecticut gross earnings tax ($6 million) attributable to an increase in gross earnings.retail revenues.
Interest Expenseincreased for$13.7 million in the nine months ended September 30, 2013,first quarter of 2014, as compared to the same period in 2012,first quarter of 2013, due primarily to the additionabsence of NSTAR’s operations ($22 million), partially offset by a decrease in Other Interest due primarily to athe favorable impact from the resolution of a state income tax audit in the first quarter of 2013 ($8.8 million) and lower Interestinterest income on RRBs and lower Interest on Long-Term Debt.deferred transition costs ($4.5 million).
Other Income, Net increased fordecreased $6.1 million in the three and nine months ended September 30, 2013,first quarter of 2014, as compared to the same period in 2012, due primarily to higher gains on the NU supplemental benefit trust and an increase related to officer insurance policies.
Income Tax Expense
|
| For the Three Months Ended September 30, |
|
| For the Nine Months Ended September 30, |
| ||||||||||||||||||
(Millions of Dollars) | 2013 |
| 2012 |
| Decrease |
| Percent |
|
| 2013 |
| 2012 |
| Increase |
| Percent |
| |||||||
Income Tax Expense | $ | 109.4 |
| $ | 117.4 |
| $ | (8.0) |
| (6.8) | % |
| $ | 325.4 |
| $ | 199.4 |
| $ | 126.0 |
| 63.2 | % | |
Income Tax Expense decreased for the three months ended September 30,first quarter of 2013, as compared to the same period in 2012, due primarily to lower pre-tax earnings ($9.4 million), lower state taxes and various other impacts ($5.4 million), state audit impacts ($1.1 million), partially offset by prior year merger impacts ($8.3 million). mark-to-market gains associated with marketable securities held in trust.
Income Tax Expense
|
| For the Three Months Ended March 31, |
| |||||||||
(Millions of Dollars) |
| 2014 |
| 2013 |
| Increase |
| Percent |
| |||
Income Tax Expense |
| $ | 141.5 |
| $ | 120.5 |
| $ | 21.0 |
| 17.4 | % |
Income Tax Expense increased forin the nine months ended September 30, 2013,first quarter of 2014, as compared to the same period in 2012,first quarter of 2013, due primarily to higher pre-tax earnings ($7313.1 million), prior year Connecticut and Massachusetts settlement agreement impacts ($41 million), prior year merger impacts ($22.8 million), partially offset by various other impactsthe absence of the favorable impact from the resolution of a state income tax audit in the first quarter of 2013 ($4.8 million), and higher state taxes ($3.7 million).
56
RESULTS OF OPERATIONS –— THE CONNECTICUT LIGHT AND POWER COMPANY
The following table provides the amounts and variances in operating revenues and expense line items for the condensed statements of income for CL&P included in this Quarterly Report on Form 10-Q for the three and nine months ended September 30, 2013March 31, 2014 and 2012: 2013:
|
|
| Operating Revenues and Expenses |
|
| Operating Revenues and Expenses |
| ||||||||||||||||||||||||||||||
|
|
| For the Three Months Ended September 30, |
|
| For the Nine Months Ended September 30, |
|
| Operating Revenues and Expenses |
| |||||||||||||||||||||||||||
|
|
|
|
|
|
|
|
| Increase/ |
|
|
|
|
|
|
|
|
|
| Increase/ |
|
|
|
| For the Three Months Ended March 31, |
| |||||||||||
(Millions of Dollars) | (Millions of Dollars) | 2013 |
| 2012 |
| (Decrease) |
| Percent |
|
| 2013 |
| 2012 |
| (Decrease) |
| Percent |
|
| 2014 |
| 2013 |
| Increase |
| Percent |
| ||||||||||
Operating Revenues | Operating Revenues | $ | 648.4 |
| $ | 658.1 |
| $ | (9.7) |
| (1.5) | % |
| $ | 1,841.8 |
| $ | 1,812.2 |
| $ | 29.6 |
| 1.6 | % |
| $ | 734.6 |
| $ | 624.1 |
| $ | 110.5 |
| 17.7 | % | |
Operating Expenses: | Operating Expenses: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| ||||
| Purchased Power and Transmission |
| 253.1 |
|
| 241.0 |
|
| 12.1 |
| 5.0 |
|
|
| 667.3 |
|
| 658.7 |
|
| 8.6 |
| 1.3 |
| |||||||||||||
| Operations and Maintenance |
| 127.1 |
|
| 141.9 |
|
| (14.8) |
| (10.4) |
|
|
| 359.7 |
|
| 480.3 |
|
| (120.6) |
| (25.1) |
| |||||||||||||
| Depreciation |
| 44.8 |
|
| 41.9 |
|
| 2.9 |
| 6.9 |
|
|
| 132.3 |
|
| 124.5 |
|
| 7.8 |
| 6.3 |
| |||||||||||||
| Amortization of Regulatory Assets, Net |
| - |
|
| 8.7 |
|
| (8.7) |
| (100.0) |
|
|
| 11.2 |
|
| 19.9 |
|
| (8.7) |
| (43.7) |
| |||||||||||||
| Energy Efficiency Programs |
| 24.5 |
|
| 25.2 |
|
| (0.7) |
| (2.8) |
|
|
| 68.2 |
|
| 68.2 |
|
| - |
| - |
| |||||||||||||
| Taxes Other Than Income Taxes |
| 65.0 |
|
| 59.7 |
|
| 5.3 |
| 8.9 |
|
|
| 182.7 |
|
| 168.6 |
|
| 14.1 |
| 8.4 |
| |||||||||||||
|
| Total Operating Expenses |
| 514.5 |
|
| 518.4 |
|
| (3.9) |
| (0.8) |
|
|
| 1,421.4 |
|
| 1,520.2 |
|
| (98.8) |
| (6.5) |
| ||||||||||||
Purchased Power and Transmission |
| 281.4 |
| 229.3 |
| 52.1 |
| 22.7 |
| ||||||||||||||||||||||||||||
Operations and Maintenance |
| 109.5 |
| 108.9 |
| 0.6 |
| 0.6 |
| ||||||||||||||||||||||||||||
Depreciation |
| 46.1 |
| 42.4 |
| 3.7 |
| 8.7 |
| ||||||||||||||||||||||||||||
Amortization of Regulatory Assets, Net |
| 29.9 |
| 10.8 |
| 19.1 |
| (a) |
| ||||||||||||||||||||||||||||
Energy Efficiency Programs |
| 42.7 |
| 22.8 |
| 19.9 |
| 87.3 |
| ||||||||||||||||||||||||||||
Taxes Other Than Income Taxes |
| 67.0 |
| 60.2 |
| 6.8 |
| 11.3 |
| ||||||||||||||||||||||||||||
Total Operating Expenses |
| 576.6 |
| 474.4 |
| 102.2 |
| 21.5 |
| ||||||||||||||||||||||||||||
Operating Income | Operating Income | $ | 133.9 |
| $ | 139.7 |
| $ | (5.8) |
| (4.2) | % |
| $ | 420.4 |
| $ | 292.0 |
| $ | 128.4 |
| 44.0 | % |
| $ | 158.0 |
| $ | 149.7 |
| $ | 8.3 |
| 5.5 | % | |
Operating Revenues |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| |
CL&P's retail sales were as follows: |
|
|
|
|
|
|
|
|
| |||||||||
|
| For the Three Months Ended September 30, |
|
| For the Nine Months Ended September 30, |
| ||||||||||||
|
| 2013 |
| 2012 |
| Decrease |
| Percent |
|
| 2013 |
| 2012 |
| Increase |
| Percent |
|
Retail Sales in GWh | 6,119 |
| 6,235 |
| (116) |
| (1.9) | % |
| 16,993 |
| 16,843 |
| 150 |
| 0.9 | % | |
(a) Percent greater than 100 percent not shown as it is not meaningful.
Operating Revenues
CL&P's&P’s retail sales were as follows:
|
| For the Three Months Ended March 31, |
| ||||||
|
| 2014 |
| 2013 |
| Increase |
| Percent |
|
Retail Sales in GWh |
| 5,949 |
| 5,681 |
| 268 |
| 4.7 | % |
CL&P’s Operating Revenues decreased $9.7revenues increased $110.5 million for the three months ended September 30, 2013, as compared to the same period in 2012, due primarily to:
·
A $2.1 million decrease in base distribution revenues reflecting a 1.9 percent decrease in retail sales. This decrease was due primarily to slightly cooler summer weather in 2013, as compared to the summer weather in 2012.
·
A $7.8 million decrease in transmission revenues reflecting the establishment of a reserve related to the FERC ALJ initial decision in the thirdfirst quarter of 2013. The decrease was partially offset by recoveryincrease in revenue reflects higher retail sales volumes as a result of the significantly colder than normal winter temperatures and the overall impact of higher transmission expenseswholesale energy costs in New England. The wholesale energy markets 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 on wholesale energy costs are recovered from customers in rates and continuing transmission infrastructure investments.therefore have no impact on earnings.
CL&P’s Operating Revenues increased $29.6 million forAs noted above, the nine months ended September 30, 2013, as compared to the same period in 2012, due primarily to:
·
A $9.4 million increase in base distribution revenues reflecting a 0.9reflects an increase of 4.7 percent increase in retail sales. This increase was due primarily to the colder winter weather experienced in early 2013, as compared tothe first quarter of 2014, when the average daily temperature was 5 degrees lower than the same period in 2012.2013.
·
An $8.7 millionThe increase in transmission revenues reflectingreflects recovery of higher transmission expenses and continuingincluding ongoing investments in our transmission infrastructure investments. The increase was partially offset by the establishment of a reserve related to the FERC ALJ initial decision in the third quarter of 2013.infrastructure.
·
The remaining increase was due primarily to higher collections of costs through reconciling cost mechanisms. These revenues are fully reconciled to the related costs. Therefore this increase in revenues had no impact on earnings.
Purchased Power and Transmission increased forin the three and nine months ended September 30, 2013,first quarter of 2014, as compared to the same periods in 2012,first quarter of 2013, due primarily to the following:
| Three Months Ended |
| Nine Months Ended |
| Three Months Ended |
| |||
(Millions of Dollars) | Increase/(Decrease) |
| Increase/(Decrease) |
| Increase/(Decrease) |
| |||
GSC Supply Costs |
| $ | 101.1 |
| |||||
Transmission Costs | $ | 20.5 |
| $ | 32.5 |
| 6.5 |
| |
Deferred Fuel Costs |
| 20.4 |
| 29.6 |
| (55.8 | ) | ||
CfD Costs |
| (6.3) |
| 0.9 | |||||
GSC Supply Costs |
| (20.0) |
| (45.0) | |||||
Purchased Power Contracts |
| (4.5) |
| (10.7) | |||||
Other |
| 2.0 |
|
| 1.3 |
| 0.3 |
| |
| $ | 12.1 |
| $ | 8.6 |
| $ | 52.1 |
|
The decreaseincrease in GSC supply costs was due primarily to lowerhigher average supply prices partially offset byand an increase in GSC sales.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 thirty30 percent of GSC load. Costs associated with the remaining seventy70 percent of the GSC load are the contractual amounts CL&P must pay to various suppliers that have been awarded the right to supply SS and LRS load through a competitive solicitation process. All GSCThe 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 was due primarily to higher average supply prices, as compared to prices projected when standard service rates were set. Purchased Power and Transmission costs are included in PURA approvedregulatory-approved tracking mechanisms and do not impact earnings.
57
Operations and Maintenancedecreased forincreased in the three and nine months ended September 30, 2013,first quarter of 2014, as compared to the same periods in 2012, due primarily to the absence in 2013 of costs recognized in the secondfirst quarter of 2012 as a result of the Connecticut settlement agreement (established a $40 million storm fund reserve and provided a $25 million bill credit2013, due to customers). In addition, there were lowerhigher bad debt expense ($5.5 million), higher distribution general and administrative expensescosts ($1.8 million2.3 million), higher routine maintenance costs ($1.5 million), and $6.8 million, respectively)other operating costs ($1 million). Offsetting these increases was a decrease in pension and lower distributionPBOP costs related to customer EIA incentives ($6.1 million and $5.8 million, respectively)9.7 million). Also contributing to the decrease was the absence in 2013 of the amortization of a regulatory deferral allowed
Depreciation increased in the 2010 rate case decision ($4 million for the nine months), lower routine vegetation management costs ($3.5 million for the nine months), the absencefirst quarter of amortization of the PBOP transition obligation ($1.5 million and $4.6 million, respectively), and lower routine distribution maintenance costs ($0.7 million for the nine months). Partially offsetting the third quarter 2013 decrease was higher routine vegetation management costs ($1.8 million for the third quarter) and higher routine distribution maintenance costs ($1.8 million for the third quarter).
Depreciation increased for the three and nine months ended September 30, 2013,2014, as compared to the same periods in 2012,first quarter of 2013, due primarily to higher utility plant balances resulting from completed construction projects placed into service related to CL&P's capital programs.service.
Amortization of Regulatory Assets, Netdecreased forincreased in the three and nine months ended September 30, 2013,first quarter of 2014, as compared to the same periods in 2012,first quarter of 2013, due primarily to lower retail SBC revenues ($7.4 million and $18.7 million, respectively), lower SBC transition costs ($0.3 million and $5.4 million, respectively), lower CTA revenues ($3.8 million and $9.8 million, respectively) and lower CTA transition costs ($5.9 million and $11.8 million, respectively). Partially offsetting these decreases was an increase in amortization expense related to a DOE refund ($11.9 million forpreviously deferred congestion charges.
Energy Efficiency Programs increased in the third quarter).first quarter of 2014, as compared to the first quarter of 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 forin the three and nine months ended September 30, 2013,first quarter of 2014, as compared to the same periods in 2012,first quarter 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 ($3.9 million). In addition, there was an increase in the Connecticut gross earnings tax attributable to an increase in gross earningsretail revenues ($1.1 million and $5.8 million, respectively), and an increase in property taxes as a result of an increase in Property, Plant and Equipment related to CL&P’s capital program and an increase in the property tax rates ($3.9 million and $7.3 million, respectively)3.6 million).
Interest Expenseincreased for the three months ended September 30, 2013,$4.5 million in first quarter of 2014, as compared to the same period in 2012,first quarter of 2013, due primarily to higher interest on long-term debt. Interest Expensedecreased for the nine months ended September 30, 2013,absence in 2014 of the favorable impact from the resolution of a state income tax audit in the first quarter of 2013.
Other Income, Net decreased $3.1 million in the first quarter of 2014, as compared to the same period in 2012,first quarter of 2013, due primarily to a decreaselower mark-to-market gains associated with marketable securities held in other interesttrust.
Income Tax Expense
|
| For the Three Months Ended March 31, |
| |||||||||
(Millions of Dollars) |
| 2014 |
| 2013 |
| Increase |
| Percent |
| |||
Income Tax Expense |
| $ | 45.5 |
| $ | 39.2 |
| $ | 6.3 |
| 16.1 | % |
Income Tax Expense increased in the first quarter of 2014, as a resultcompared to the first quarter of 2013, 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 ($2.9 million), higher pre-tax earnings ($1.6 million), and higher state taxes ($0.9 million).
EARNINGS SUMMARY
|
| For the Three Months Ended March 31, |
| ||||
(Millions of Dollars) |
| 2014 |
| 2013 |
| ||
Net Income |
| $ | 79.3 |
| $ | 85.0 |
|
CL&P’s earnings decreased $5.7 million in the first quarter of 2014, as compared to the first quarter of 2013, 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 and lower interest on short term loans, partially offset by higher interest on long-term debt.
Other Incomeincreased for the three and nine months ended September 30, 2013, as compared to the same periods in 2012, due primarily to higher gains on the NU supplemental benefit trust.
Income Tax Expense
|
| For the Three Months Ended September 30, |
|
| For the Nine Months Ended September 30, |
| ||||||||||||||||||
(Millions of Dollars) | 2013 |
| 2012 |
| Increase |
| Percent |
|
| 2013 |
| 2012 |
| Increase |
| Percent |
| |||||||
Income Tax Expense | $ | 36.1 |
| $ | 34.1 |
| $ | 2.0 |
| 5.9 | % |
| $ | 113.1 |
| $ | 63.9 |
| $ | 49.2 |
| 77.0 | % | |
Income Tax Expense increased for the nine months ended September 30, 2013, as compared to the same period in 2012, due primarily to higher pre-tax earnings ($22.6 million), the absence in 2013 of the impact of costs recognized as a result of the Connecticut settlement agreement ($26.6 million), and higher state taxes ($3.4 million), partially offset by state audit impacts ($2.9 million).
EARNINGS SUMMARY
| For the Three Months |
| For the Nine Months | ||||||||
(Millions of Dollars) | 2013 |
| 2012 |
| 2013 |
| 2012 | ||||
Income Before Merger-Related Costs | $ | 66.3 |
| $ | 74.9 |
| $ | 219.2 |
| $ | 174.2 |
Merger-Related Costs (after-tax)(1) |
| - |
|
| - |
|
| - |
|
| (38.4) |
Net Income | $ | 66.3 |
| $ | 74.9 |
| $ | 219.2 |
| $ | 135.8 |
(1)
The first nine months of 2012 after-tax merger-related costs consisted of charges related to the Connecticut settlement agreement, including $14.8 million ($25 million pre-tax) for customer bill credits and $23.6 million ($40 million pre-tax) whereby CL&P agreed to forego recovery of deferred storm costs associated with Tropical Storm Irene and the October 2011 snowstorm.
CL&P’s third quarter 2013 earnings were lower than the same period in 2012 due primarily to the establishment of a $7.7 million after-tax reserve related to the August 2013 FERC ALJ initial decision, higher depreciation and property tax expense and lower retail electric sales as a result of slightly cooler summer weather in 2013, as compared to the summer weather in 2012.depreciation. Partially offsetting these unfavorable earnings impacts were increased investments in the transmission infrastructure.
Excluding merger-related costs, CL&P’s first nine months of 2013 earnings were $45 million higher than the same period in 2012 due primarily to increased investments in the transmission infrastructure, lower overall operations and maintenance costs and higher retail electric sales due primarily to colder weather in the first quarter of 2013,2014, as compared to the first quarter of 2012. Partially offsetting these favorable earnings impacts were higher depreciation and property tax expense.2013.
LIQUIDITY
58
LIQUIDITY
CL&P had cash flows provided by operating activities of $308.6$95.5 million in the first nine monthsquarter of 2013,2014, compared with $148.2$26.4 million in the first nine monthsquarter of 2012.2013. The improved cash flows were due primarily to the absence of cash disbursements for major storm restoration costs in the first nine monthsquarter of 2014, as compared to the first quarter of 2013, of $164.3 million in cash disbursements for storm costs associated with Tropical Storm Irene and the October 2011 snowstorm in the first nine months of 2012, the absence of approximately $27 million in 2012 CL&P customer bill credits associated with the October 2011 snowstorm and the absence of approximately $25 million in 2012 CL&P customer bill credits associated with the Connecticut settlement agreement. Partially offsetting improved cash flows were income tax paymentsrefunds of $41.2$11.7 million in the first nine monthsquarter of 2013,2014, as compared with income tax refunds of $39to $1.6 million in the first nine monthsquarter of 2012, and the change in2013, partially offset by an unfavorable cash flow impact relating to traditional working capital amounts primarilyprincipally due to the changes in timing of accounts receivable collections.receivables.
Investments in Property, Plant and Equipment on the accompanying statements of cash flows do not include amounts incurred on capital projects but not yet paid, cost of removal, AFUDC related to equity funds, and the capitalized portions of pension expense. CL&P’s investments totaled $294.6 million inIn the first nine monthsquarter of 2013, compared with $332.3 million in the first nine months of 2012.2014, investments for CL&P were $108 million.
On January 15, 2013,April 24, 2014, CL&P issued $400$250 million of 2.54.30 percent first mortgage bonds that will2014 Series A First Mortgage Bonds, due to mature on January 15, 2023.in April 2044. The proceeds, net of issuance costs, were used to repay CL&P’s December 31, 2012 revolving credit facility borrowings of $89 million and intercompany loans related to NU's commercial paper program borrowings of $305.8 million.
On July 31, 2013, the FERC approved CL&P’s short-term debt application requesting the authorization to issue total short-term borrowings up to a maximum of $600 million. The authorization is effective January 1, 2014 through December 31, 2015.from NU parent.
On September 3, 2013, CL&P redeemed at par $125 million of the 1.25 percent Series B 2011 PCRBs that were subject to mandatory tender for purchase using short-term debt.
On September 6, 2013, NU parent and certain of its subsidiaries, amended theirincluding CL&P, are parties to a joint five-year $1.15$1.45 billion revolving credit facility dated July 25, 2012 by increasing the aggregate principal amount available thereunder by $300 milliondue to $1.45 billion, extending the expiration date from July 25, 2017 toexpire on September 6, 2018, and increasing CL&P's borrowing sublimit from $300 million to $600 million. At the same time, effective September 6, 2013, the CL&P $300 million2018. The revolving credit facility was terminated.is to be used primarily to backstop the $1.45 billion commercial paper program at NU parent. 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 March 31, 2014 and December 31, 2013, there were intercompany loans from NU parent of $351.6 million and $287.3 million, respectively, to CL&P.
OtherAdditional financing activities in the first nine monthsquarter of 20132014 included $114$42.8 million in common stock dividends paid to NU parent.
On January 31, 2014, Moody’s upgraded corporate credit and securities ratings of CL&P by one level. On April 7, 2014, Fitch affirmed the corporate credit rating and outlook of CL&P.
59
RESULTS OF OPERATIONS –— NSTAR ELECTRIC COMPANY AND SUBSIDIARY
The following table provides the amounts and variances in operating revenues and expense line items for the condensed consolidated statements of income for NSTAR Electric included in this Quarterly Report on Form 10-Q for the ninethree months ended September 30, 2013March 31, 2014 and 2012: 2013:
| Operating Revenues and Expenses |
| |||||||||||||||||||||||
|
|
| Operating Revenues and Expenses |
| |||||||||||||||||||||
| For the Nine Months Ended September 30, |
| |||||||||||||||||||||||
(Millions of Dollars) | 2013 |
| 2012 |
| Increase/ |
| Percent |
| |||||||||||||||||
(Decrease) |
|
| 2014 |
| 2013 |
| Increase/ |
| Percent |
| |||||||||||||||
Operating Revenues | Operating Revenues | $ | 1,916.6 |
| $ | 1,784.8 |
| $ | 131.8 |
| 7.4 | % |
| $ | 666.2 |
| $ | 592.3 |
| $ | 73.9 |
| 12.5 | % | |
Operating Expenses: | Operating Expenses: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| ||||
| Purchased Power and Transmission |
| 659.1 |
|
| 622.3 |
|
| 36.8 |
| 5.9 |
| |||||||||||||
| Operations and Maintenance |
| 277.3 |
|
| 340.6 |
|
| (63.3) |
| (18.6) |
| |||||||||||||
| Depreciation |
| 136.3 |
|
| 127.7 |
|
| 8.6 |
| 6.7 |
| |||||||||||||
| Amortization of Regulatory Assets, Net |
| 173.3 |
|
| 87.9 |
|
| 85.4 |
| 97.2 |
| |||||||||||||
| Amortization of Rate Reduction Bonds |
| 15.1 |
|
| 67.7 |
|
| (52.6) |
| (77.7) |
| |||||||||||||
| Energy Efficiency Programs |
| 161.2 |
|
| 138.4 |
|
| 22.8 |
| 16.5 |
| |||||||||||||
| Taxes Other Than Income Taxes |
| 95.3 |
|
| 89.7 |
|
| 5.6 |
| 6.2 |
| |||||||||||||
| Total Operating Expenses |
| 1,517.6 |
|
| 1,474.3 |
|
| 43.3 |
| 2.9 |
| |||||||||||||
Purchased Power and Transmission |
| 319.1 |
| 214.1 |
| 105.0 |
| 49.0 |
| ||||||||||||||||
Operations and Maintenance |
| 85.9 |
| 92.3 |
| (6.4 | ) | (6.9 | ) | ||||||||||||||||
Depreciation |
| 46.6 |
| 45.4 |
| 1.2 |
| 2.6 |
| ||||||||||||||||
Amortization of Regulatory Assets, Net |
| 15.7 |
| 47.0 |
| (31.3 | ) | (66.6 | ) | ||||||||||||||||
Amortization of Rate Reduction Bonds |
| — |
| 15.1 |
| (15.1 | ) | (100.0 | ) | ||||||||||||||||
Energy Efficiency Programs |
| 48.3 |
| 51.7 |
| (3.4 | ) | (6.6 | ) | ||||||||||||||||
Taxes Other Than Income Taxes |
| 32.2 |
| 32.2 |
| — |
| — |
| ||||||||||||||||
Total Operating Expenses |
| 547.8 |
| 497.8 |
| 50.0 |
| 10.0 |
| ||||||||||||||||
Operating Income | Operating Income | $ | 399.0 |
| $ | 310.5 |
| $ | 88.5 |
| 28.5 | % |
| $ | 118.4 |
| $ | 94.5 |
| $ | 23.9 |
| 25.3 | % | |
Operating Revenues |
|
|
|
|
|
|
|
|
| |
NSTAR Electric's retail sales were as follows: |
|
|
| |||||||
|
|
|
|
|
|
|
|
|
|
|
|
|
| For the Nine Months Ended September 30, |
| ||||||
|
|
| 2013 |
| 2012 |
| Increase |
| Percent |
|
Retail Sales in GWh |
| 16,204 |
| 16,189 |
| 15 |
| 0.1 | % | |
Operating Revenues
NSTAR Electric’s retail sales were as follows:
|
| For the Three Months Ended March 31, |
| ||||||
|
| 2014 |
| 2013 |
| Increase |
| Percent |
|
Retail Sales in GWh |
| 5,358 |
| 5,194 |
| 164 |
| 3.2 | % |
NSTAR Electric’s Operating Revenuesrevenues increased $131.8$73.9 million for the nine months ended September 30, 2013, as compared to the same periodfirst quarter of 2013. The increase in 2012, due primarily to:revenue reflects higher retail sales volumes as a result of the significantly colder than normal winter temperatures and the overall impact of higher wholesale energy costs in New England. The wholesale energy markets 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 on wholesale energy costs are recovered from customers in rates and therefore have no impact on earnings.
·
A $6.5 millionAs noted above, the increase in base distribution revenues reflectingreflects a 0.13.2 percent increase in retail sales. The increase in sales volume was due primarily to colder winter weather in the first quarter of 2014. The average daily temperature in Boston was over 3 degrees lower than the first quarter of 2013.
The positive impacts on sales volume were partially offset by customer savings due to the impact of our energy efficiency programs. NSTAR Electric is permitted to bill customers for lost base revenues related to reductions in sales volume as a greater numberresult of cooling degree days duringits energy efficiency. In the summerfirst quarter of 20132014, the recognition of lost base revenues increased $4.8 million compared to the first quarter of 2013.
The increase in transmission revenues reflects recovery of higher transmission expenses including continuing transmission infrastructure investments.
Purchased Power and heating degree daysTransmission increased in early 2013,the first quarter of 2014, as compared to the same periodsfirst quarter of 2013, due primarily to the following:
(Millions of Dollars) |
| Three Months Ended |
| |
Basic Service Costs |
| $ | 106.8 |
|
Transmission Costs |
| 18.8 |
| |
Purchased Power Contracts |
| 12.2 |
| |
Deferred Fuel Costs |
| (32.8 | ) | |
|
| $ | 105.0 |
|
The increase in 2012. This favorableBasic Service costs was primarily related to higher average supply prices. The increase in transmission costs was due primarily to higher RNS expense. The increase in purchased power contracts was due primarily to higher congestion charges. The decrease in deferred fuel costs was due primarily to higher average supply prices, as compared to the prices projected when Basic Service rates were set. Purchased Power and Transmission costs are included in regulatory-approved tracking mechanisms and do not impact wasearnings.
Operations and Maintenance decreased in the first quarter of 2014, as compared to the first quarter of 2013, due primarily to lower employee benefit costs ($6 million) and lower storm-related costs ($2 million), partially offset by reductionshigher bad debt expense ($0.6 million), and other operating expenses ($1 million).
Depreciation increased in the first quarter of 2014, as compared to the first quarter 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 quarter of 2014, as compared to the first quarter of 2013, due primarily to a decrease in the recovery of previously deferred transition costs.
Amortization of Rate Reduction Bonds decreased in the first quarter of 2014, as compared to the first quarter of 2013, due to the maturity of the RRBs in March 2013.
Energy Efficiency Programs decreased in the first quarter of 2014, as compared to the first quarter of 2013, due primarily to a decrease in the amortization of previously deferred costs ($8 million), partially offset by an increase in energy efficiency costs incurred in accordance with the three-year program guidelines established by the DPU ($4.6 million). All costs are fully recovered through DPU-approved tracking mechanisms and therefore do not impact earnings.
Taxes Other Than Income Taxes remained unchanged in the first quarter of 2014, as compared to the first quarter of 2013, due to lower average municipal property tax rates, offset by an increase in property taxes as a result of an increase in utility plant balances.
Interest Expense increased $5.1 million in the first quarter of 2014, as compared to the first quarter of 2013, due primarily to lower regulatory interest income primarily from deferred transition costs ($4.7 million), as well as higher average long-term debt outstanding.
Other Income/(Loss), Net decreased $0.8 million in the first quarter of 2014, as compared to the first quarter of 2013, due primarily to lower gains on the deferred compensation plans.
Income Tax Expense
|
| For the Three Months Ended March 31, |
| |||||||||
(Millions of Dollars) |
| 2014 |
| 2013 |
| Increase |
| Percent |
| |||
Income Tax Expense |
| $ | 39.2 |
| $ | 31.3 |
| $ | 7.9 |
| 25.2 | % |
Income Tax Expense increased in the first quarter of 2014, as compared to the first quarter of 2013, due primarily to higher pre-tax earnings ($6.3 million) and higher state taxes ($1.6 million).
EARNINGS SUMMARY
|
| For the Three Months Ended March 31, |
| ||||
(Millions of Dollars) |
| 2014 |
| 2013 |
| ||
Net Income |
| $ | 58.1 |
| $ | 48.1 |
|
NSTAR Electric’s earnings increased $10 million in the first quarter of 2014, as compared to the first quarter of 2013, due primarily to higher transmission margin, higher distribution revenues related to higher retail electric sales due primarily to colder weather in the first quarter in 2014, as compared to the first quarter of 2013, higher lost base revenues, and lower non-tracked operations and maintenance costs. Partially offsetting these favorable earnings impacts was higher interest cost, primarily on deferred transition costs.
LIQUIDITY
NSTAR Electric had cash flows provided by operating activities of $191.4 million in the first quarter of 2014, compared with $89.4 million in the first quarter 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, a decrease in income tax payments in the first quarter of 2014, as compared to the first quarter of 2013, the absence of costs recovered in rates related to the RRBs that were fully amortized in the first quarter of 2013, and the absence of pension contributions in the first quarter of 2014, as compared to the first quarter of 2013.
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 three months ended March 31, 2014 and 2013:
|
| Operating Revenues and Expenses |
| |||||||||
|
| For the Three Months Ended March 31, |
| |||||||||
|
|
|
|
|
| Increase/ |
|
|
| |||
(Millions of Dollars) |
| 2014 |
| 2013 |
| (Decrease) |
| Percent |
| |||
Operating Revenues |
| $ | 299.8 |
| $ | 273.8 |
| $ | 26.0 |
| 9.5 | % |
Operating Expenses: |
|
|
|
|
|
|
|
|
| |||
Purchased Power, Fuel and Transmission |
| 115.3 |
| 101.0 |
| 14.3 |
| 14.2 |
| |||
Operations and Maintenance |
| 62.2 |
| 59.7 |
| 2.5 |
| 4.2 |
| |||
Depreciation |
| 24.2 |
| 22.6 |
| 1.6 |
| 7.1 |
| |||
Amortization of Regulatory Assets/(Liabilities), Net |
| 12.6 |
| (3.1 | ) | 15.7 |
| (a) |
| |||
Amortization of Rate Reduction Bonds |
| — |
| 14.8 |
| (14.8 | ) | (100.0 | ) | |||
Energy Efficiency Programs |
| 3.8 |
| 3.7 |
| 0.1 |
| 2.7 |
| |||
Taxes Other Than Income Taxes |
| 17.7 |
| 17.0 |
| 0.7 |
| 4.1 |
| |||
Total Operating Expenses |
| 235.8 |
| 215.7 |
| 20.1 |
| 9.3 |
| |||
Operating Income |
| $ | 64.0 |
| $ | 58.1 |
| $ | 5.9 |
| 10.2 | % |
(a) Percent greater than 100 percent not shown as it is not meaningful.
Operating Revenues
PSNH’s retail sales were as follows:
|
| For the Three Months Ended March 31, |
| ||||||
|
| 2014 |
| 2013 |
| Increase |
| Percent |
|
Retail Sales in GWh |
| 2,076 |
| 1,992 |
| 84 |
| 4.2 | % |
PSNH’s Operating revenues increased $26 million compared to the first quarter of 2013. The increase in revenue reflects higher retail sales volumes as a result of the significantly colder than normal winter temperatures and the overall impact of higher wholesale energy costs in New England. The wholesale energy markets 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 on wholesale energy costs are recovered from customers in rates and therefore have no impact on earnings.
As noted above, the increase in base distribution revenues reflects an increase of 4.2 percent in retail sales. PSNH experienced strong sales in 2014 due to colder winter weather than what was experienced in 2013. The average daily temperature in New Hampshire was over 5 degrees lower than the first quarter of 2013. Also reflected in this revenue increase was an increase of $3.3 million related to NHPUC-approved distribution rate increases effective July 1, 2013 as a result of a 2010 distribution rate case settlement.
The increase in transmission revenues reflects recovery of higher transmission expenses including ongoing investments in our transmission infrastructure.
Purchased Power, Fuel and Transmission increased in the first quarter of 2014, as compared to the first quarter of 2013, due primarily to an increase in generation fuel costs, partially offset by lower purchased power costs due to customer fundedmigration, lower renewable energy efficiency programs.requirements set by the NHPUC, and lower regional greenhouse gas initiative auction proceeds. Purchased Power, Fuel and Transmission costs are included in regulatory-approved tracking mechanisms and do not impact earnings.
·Operations and Maintenance increased in the first quarter of 2014, as compared to the first quarter of 2013, due primarily to an increase in routine maintenance costs at the generation business ($1.2 million), an increase in routine transmission maintenance costs ($0.9 million) and higher bad debt expense ($0.6 million), partially offset by other operating costs ($0.2 million).
Transmission
Depreciation increased in the first quarter of 2014, as compared to the first quarter of 2013, due primarily to higher utility plant balances resulting from completed construction projects placed into service.
Amortization of Regulatory Assets/(Liabilities), Net increased in the first quarter of 2014, as compared to the first quarter of 2013, due primarily to increases in the SCRC, ES and TCAM amortizations ($7.3 million, $4.8 million, and $6.2 million, respectively).
Amortization of Rate Reduction Bonds decreased in the first quarter of 2014, as compared to the first quarter of 2013, due to the maturity of the RRBs in May 2013.
Income Tax Expense
|
| For the Three Months Ended March 31, |
| |||||||||
(Millions of Dollars) |
| 2014 |
| 2013 |
| Increase |
| Percent |
| |||
Income Tax Expense |
| $ | 19.7 |
| $ | 18.0 |
| $ | 1.7 |
| 9.4 | % |
Income Tax Expense increased in the first quarter of 2014, as compared to the first quarter of 2013, due primarily to higher pre-tax earnings ($1.9 million).
EARNINGS SUMMARY
|
| For the Three Months Ended March 31, |
| |||||||
(Millions of Dollars) |
| 2014 |
| 2013 |
| Increase |
| |||
Net Income |
| $ | 32.6 |
| $ | 29.0 |
| $ | 3.6 |
|
PSNH’s earnings increased due primarily to higher generation earnings and distribution retail revenues. The first quarter 2014 distribution retail revenues remained comparablewere favorably impacted by the PSNH rate increases effective July 1, 2013 as a result of the 2010 distribution rate case settlement and a 4.2 percent increase in retail sales. PSNH experienced strong sales in the first quarter of 2014 due to 2012colder winter weather than what was experienced in 2013. Partially offsetting these favorable earnings impacts were higher operations and maintenance, depreciation and property tax expense.
LIQUIDITY
PSNH had cash flows provided by operating activities of $129.3 million in the first quarter of 2014, compared with $107.2 million in the first quarter of 2013. The improved cash flows were due primarily to the absence of a $35.1 million NUSCO Pension and PBOP Plan contribution in the first quarter of 2014, as compared to the first quarter of 2013, the favorable impact of the 2010 rate case decision related to the additional increase to annualized rates that was effective July 1, 2013, and the favorable cash flow impacts relating to changes in traditional working capital amounts. These favorable cash flow impacts were partially offset by income tax payments of $16.1 million in the first quarter of 2014, compared with income tax refunds of $15.3 million in the first quarter 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 three months ended March 31, 2014 and 2013:
|
| Operating Revenues and Expenses |
| |||||||||
(Millions of Dollars) |
| 2014 |
| 2013 |
| Increase/ |
| Percent |
| |||
Operating Revenues |
| $ | 137.4 |
| $ | 125.0 |
| $ | 12.4 |
| 9.9 | % |
Operating Expenses: |
|
|
|
|
|
|
|
|
| |||
Purchased Power and Transmission |
| 49.4 |
| 40.1 |
| 9.3 |
| 23.2 |
| |||
Operations and Maintenance |
| 22.6 |
| 20.9 |
| 1.7 |
| 8.1 |
| |||
Depreciation |
| 10.3 |
| 9.0 |
| 1.3 |
| 14.4 |
| |||
Amortization of Regulatory (Liabilities)/Assets, Net |
| 0.4 |
| 0.1 |
| 0.3 |
| (a) |
| |||
Amortization of Rate Reduction Bonds |
| — |
| 4.7 |
| (4.7 | ) | (100.0 | ) | |||
Energy Efficiency Programs |
| 11.9 |
| 8.3 |
| 3.6 |
| 43.4 |
| |||
Taxes Other Than Income Taxes |
| 8.1 |
| 6.3 |
| 1.8 |
| 28.6 |
| |||
Total Operating Expenses |
| 102.7 |
| 89.4 |
| 13.3 |
| 14.9 |
| |||
Operating Income |
| $ | 34.7 |
| $ | 35.6 |
| $ | (0.9 | ) | (2.5 | )% |
(a) Percent greater than 100 percent not shown as it is not meaningful.
Operating Revenues
WMECO’s retail sales were as follows:
|
| For the Three Months Ended March 31, |
| ||||||
|
| 2014 |
| 2013 |
| Increase |
| Percent |
|
Retail Sales in GWh |
| 965 |
| 929 |
| 36 |
| 3.8 | % |
WMECO’s Operating Revenues increased $12.4 million in the first quarter of 2014, as compared to the first quarter 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.
·Base distribution revenues are consistent with 2013. WMECO’s kWh sales have no impact on earnings, as its revenues are decoupled from sales volumes.
·A $0.8 million increase in transmission revenues reflecting recovery of higher transmission expenses and continuingincluding investments in our transmission infrastructure, investments, offset by the establishment of a reserveprimarily related to the FERC ALJ initial decision in the third quarter of 2013.NEEWS project.
·
The remaining increase primarily reflects a higher level of collectionsrecovery related to NSTAR Electric'sWMECO’s energy supply and company-sponsored energy efficiency programs. These revenues are fully reconciled to the related costs. Therefore this increase in revenues had no material impact on earnings.
Purchased Power and Transmissionincreased forin the nine months ended September 30, 2013,first quarter of 2014, as compared to the same period in 2012,first quarter of 2013, due primarily to the following:
|
| |
|
|
|
|
| |
|
| |
|
| |
|
| |
Thean increase in transmission costs was due primarily to a higher regional rate leading to higher regional network service costs, as well as higher forward capacity market reliability charges. Thesupplier contract prices and an increase in deferred fuel costs was due primarilycustomers returning to lower average supply prices, as compared to the prices projected when Basic Service customer rates were set. The decrease in Basic Service costs was due primarily to lower average supply prices. Thesedefault service from third party suppliers. Purchased Power and Transmission costs are included in DPU-approvedregulatory-approved tracking mechanisms and do not impact earnings.
Operations and Maintenance decreased for increased in the nine months ended September 30, 2013,first quarter of 2014, as compared to the same period in 2012,first quarter of 2013, due primarily to the absence of the cumulative adjustment recordedan increase in 2012 to establish a reserve against the regulatory assetcustomer related to Basic Service bad debtexpenses ($0.8 million), an increase in routine maintenance costs ($280.6 million), and an increase in distribution vegetation management costs ($0.3 million). In addition,
Depreciation increased in the first quarter 2012 adjustments were recognized for changes in accounting estimates related primarily to the allowance for doubtful accounts, workers’ compensation, employee medical benefits, and general liability claims ($18.7 million). In addition, a bill credit to customers ($15 million) was recorded in the second quarter of 2012 as a result of the Massachusetts settlement agreement. Also contributing to the decrease in costs was a March 2012 substation fire in the Back Bay/Prudential area of Boston ($10.1 million).
60
Depreciationincreased for the nine months ended September 30, 2013,2014, as compared to the same period in 2012,first quarter of 2013, due primarily to higher utility plant balances resulting from completed construction projects placed into service related to NSTAR Electric’s capital programs.service.
Amortization of Regulatory Assets, NetRate Reduction Bonds increased fordecreased in the nine months ended September 30, 2013,first quarter of 2014, as compared to the same period in 2012, due primarily to an increase in the recoveryfirst quarter of transition costs.
Amortization of Rate Reduction Bondsdecreased for the nine months ended September 30, 2013, as compared to the same period in 2012, due to the maturity of the RRBs in MarchJune 2013.
Energy Efficiency Programsincreased forin the nine months ended September 30, 2013,first quarter of 2014, as compared to the same period in 2012,first quarter 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 forin the nine months ended September 30, 2013,first quarter of 2014, as compared to the same period in 2012, due to higher municipal property taxes as a result of an increase in Property, Plant and Equipment related to the company’s regulated capital programs.
Interest Expense decreased for the nine months ended September 30, 2013, as compared to the same period in 2012, due primarily to lower average long-term bond rates, partially offset by a higher level of average debt outstanding. Lower regulatory interest income was primarily from deferred transition costs.
Income Tax Expense
|
| For the Nine Months Ended September 30, |
| |||||||||
(Millions of Dollars) | 2013 |
| 2012 |
| Increase |
| Percent |
| ||||
Income Tax Expense | $ | 137.5 |
| $ | 102.2 |
| $ | 35.3 |
| 34.5 | % | |
Income Tax Expense increased for the nine months ended September 30, 2013, as compared to the same period in 2012, due primarily to higher pre-tax earnings ($30.2 million) and the absence in 2013 of the impact of costs recognized as a result of the Massachusetts settlement agreement ($5.9 million), partially offset by other impacts ($0.9 million).
EARNINGS SUMMARY
| For the Nine Months | ||||
(Millions of Dollars) |
| 2013 |
|
| 2012 |
Income Before Merger-Related Costs | $ | 213.2 |
| $ | 167.0 |
Merger-Related Costs (after-tax) (1) |
| - |
|
| (10.8) |
Net Income | $ | 213.2 |
| $ | 156.2 |
(1)
The 2012 after-tax merger-related costs consisted of a $15 million pre-tax charge for customer bill credits related to the Massachusetts settlement agreement and a $2.7 million pre-tax charge related to compensation costs.
Excluding merger-related costs, NSTAR Electric’s 2013 earnings were $46.2 million higher than the same period in 2012 due primarily to the absence of 2012 adjustments recorded to establish a reserve against the regulatory asset related to Basic Service bad debt costs ($17 million), and for changes in accounting estimates related primarily to the allowance for doubtful accounts, workers’ compensation, employee medical benefits, and general liability claims ($11.4 million). Also contributing to the increase was a March 2012 substation fire in theBack Bay/Prudential area of Boston ($7.2 million), a reserve recorded relating to lost base revenues based on 2012 developments during hearings in the merger proceeding ($3.7 million), and the establishment of a reserve in the thirdfirst quarter of 2013, related to the August 2013 FERC ALJ initial decision ($3.4 million).
61
CAPITAL EXPENDITURES
A summary of capital expenditures, including amounts incurred but not paid, cost of removal, AFUDC, and the capitalized portions of pension expense, is as follows:
| For the Nine Months | ||||
(Millions of Dollars) |
| 2013 |
|
| 2012 |
Transmission | $ | 140.0 |
| $ | 110.7 |
Distribution: |
|
|
|
|
|
Basic Business |
| 84.6 |
|
| 40.8 |
Aging Infrastructure |
| 75.0 |
|
| 119.1 |
Load Growth |
| 22.5 |
|
| 11.1 |
Total Distribution |
| 182.1 |
|
| 171.0 |
Total | $ | 322.1 |
| $ | 281.7 |
LIQUIDITY
NSTAR Electric had cash flows provided by operating activities of $274.1 million for the first nine months of 2013, compared with $348.2 million for the first nine months of 2012 (amounts are net of RRB payments, which are included in financing activities). The decrease in operating cash flows was due primarily to an increase in cash disbursements for storm costs for the first nine months of 2013 associated with the February 2013 blizzard, as compared to cash disbursements for storm costs for the first nine months of 2012, associated with Tropical Storm Irene and the October 2011 snowstorm, and a $57 million increase in pension contributions for the first nine months of 2013, as compared to the same period of 2012. The change in traditional working capital amounts, principally due to the changes in timing of accounts receivable collections, also contributed to the decrease in operating cash flows. Partially offsetting the negative cash flow impacts was the absence in 2013 of $15 million in bill credits provided to customers in the second quarter of 2012 in connection with the Massachusetts settlement agreement.
62
RESULTS OF OPERATIONS – PUBLIC SERVICE COMPANY OF NEW HAMPSHIRE AND SUBSIDIARY
The following table provides the amounts and variances in operating revenues and expense line items for the condensed consolidated statements of income for PSNH included in this Quarterly Report on Form 10-Q for the nine months ended September 30, 2013 and 2012:
|
|
| Operating Revenues and Expenses |
| |||||||||
|
|
| For the Nine Months Ended September 30, |
| |||||||||
|
|
|
|
|
|
|
|
| Increase/ |
|
|
| |
(Millions of Dollars) | 2013 |
| 2012 |
| (Decrease) |
| Percent |
| |||||
Operating Revenues | $ | 708.6 |
| $ | 755.0 |
| $ | (46.4) |
| (6.1) | % | ||
Operating Expenses: |
|
|
|
|
|
|
|
|
|
|
| ||
| Purchased Power, Fuel and Transmission |
| 197.8 |
|
| 239.1 |
|
| (41.3) |
| (17.3) |
| |
| Operations and Maintenance |
| 191.6 |
|
| 201.0 |
|
| (9.4) |
| (4.7) |
| |
| Depreciation |
| 68.4 |
|
| 65.3 |
|
| 3.1 |
| 4.7 |
| |
| Amortization of Regulatory Liabilities, Net |
| (1.7) |
|
| (6.2) |
|
| 4.5 |
| 72.6 |
| |
| Amortization of Rate Reduction Bonds |
| 19.7 |
|
| 43.9 |
|
| (24.2) |
| (55.1) |
| |
| Energy Efficiency Programs |
| 11.0 |
|
| 10.8 |
|
| 0.2 |
| 1.9 |
| |
| Taxes Other Than Income Taxes |
| 52.7 |
|
| 47.4 |
|
| 5.3 |
| 11.2 |
| |
|
| Total Operating Expenses |
| 539.5 |
|
| 601.3 |
|
| (61.8) |
| (10.3) |
|
Operating Income | $ | 169.1 |
| $ | 153.7 |
| $ | 15.4 |
| 10.0 | % | ||
Operating Revenues |
|
|
|
|
|
|
|
| |
PSNH's retail sales were as follows: |
|
|
|
|
|
|
|
| |
|
| For the Nine Months Ended September 30, |
| ||||||
|
| 2013 |
| 2012 |
| Increase |
| Percent |
|
Retail Sales in GWh | 5,971 |
| 5,888 |
| 83 |
| 1.4 | % | |
PSNH's Operating Revenues decreased $46.4 million for the nine months ended September 30, 2013, as compared to the same period in 2012, due primarily to:
·
A $12.5 million increase in base distribution revenues reflecting a 1.4 percent increase in retail sales. PSNH experienced strong sales in early 2013 due to colder winter weather than what was experienced in early 2012. In addition, revenue was positively impacted by an increase of $8.6 million related to NHPUC-approved distribution rate increases effective July 1, 2012 and July 1, 2013 as a result of the 2010 distribution rate case settlement.
·
A $2 million increase in transmission revenues reflecting recovery of higher transmission expenses and continuing transmission infrastructure investments. The increase was mostly offset by the establishment of a reserve related to the FERC ALJ initial decision in the third quarter of 2013.
·
These increases were more than offset by a decrease of approximately $61 million related to PSNH's cost recovery mechanisms. The primary reason for this decrease was the reduction of recoveries related to PSNH’s RRBs, which were fully collected during the first half of 2013. This reduction had no impact on earnings.
Purchased Power, Fuel and Transmission decreased for the nine months ended September 30, 2013, as compared to the same period in 2012, due primarily to a decrease in costs related to RECs and a decrease in fuel costs resulting from an increase in customer migration to third party suppliers, which resulted in a decrease in load obligation and an increase in RGGI auction proceeds, which offset the cost of fuel. These decreases were partially offset by an increase in transmission costs resulting from an increase in regional transmission rates leading to higher RNS costs.
Operations and Maintenance decreased for the nine months ended September 30, 2013, as compared to the same period in 2012, due primarily to a decrease in RRB charges that are included in NHPUC-approved tracking mechanisms ($2.8 million), a decrease in vegetation management costs ($2.0 million), the absence in 2013 of PBOP transition obligation amortization ($1.9 million), lower general and administrative costs ($1.8 million) and lower routine generation and transmission maintenance costs ($1.3 million and $1.2 million, respectively). These decreases were partially offset by an increase in routine distribution overhead line maintenance costs ($4.4 million).
Amortization of Regulatory Liabilities, Netincreased expenses for the nine months ended September 30, 2013, as compared to the same period in 2012, due primarily to an increase in the ES and TCAM amortization ($13.4 million and $3.2 million, respectively), partially offset by a decrease in the SCRC amortization ($11.3 million).
Amortization of Rate Reduction Bonds decreased for the nine months ended September 30, 2013, as compared to the same period in 2012, due to the maturity of the RRBs in May 2013.
Taxes Other Than Income Taxes increased for the nine months ended September 30, 2013, as compared to the same period in 2012, due primarily to an increase in property taxes as a result of both an increase in Property, Plantutility plant balances and Equipment related to PSNH’s capital program and an increaseproperty tax rates.
Interest Expense decreased $0.6 million in the property tax rates.
63
Interest Expensedecreased $4 million for the nine months ended September 30, 2013,first quarter of 2014, as compared to the same periodfirst quarter of 2013, due primarily to the reversal of interest expense related to a previously recognized wholesale billing adjustment.
Other Income, Net decreased $0.4 million in 2012,the first quarter of 2014, as compared to the first quarter of 2013, due primarily to lower Interest on Rate Reduction Bonds as a resultmark-to-market gains associated with marketable securities held in trust.
EARNINGS SUMMARY
|
| For the Three Months Ended March 31, |
| ||||
(Millions of Dollars) |
| 2014 |
| 2013 |
| ||
Net Income |
| $ | 18.1 |
| $ | 18.6 |
|
WMECO’s earnings decreased $0.5 million in the first quarter of the maturity of the RRBs in May 2013.
Income Tax Expense
|
|
|
| For the Nine Months Ended September 30, |
| |||||||||
(Millions of Dollars) |
|
| 2013 |
| 2012 |
| Increase |
| Percent |
| ||||
Income Tax Expense |
|
| $ | 52.8 |
| $ | 48.0 |
| $ | 4.8 |
| 10.0 | % | |
Income Tax Expense increased for the nine months ended September 30, 2013,2014, as compared to the same period in 2012,first quarter of 2013, due primarily to lower mark-to-market gains associated with marketable securities held in trust, higher pre-tax earnings ($6.9 million), partially offset by lower state taxesoperations and other impacts ($2.1 million).
EARNINGS SUMMARY
For the nine months ended September 30, 2013, PSNH’s earnings were $14.8 million higher than the same period in 2012 due primarily to higher distribution retail revenuesmaintenance and higher generation earnings. The nine months of 2013 distribution retail revenues were favorably impacted by the PSNH rate increases effective July 1, 2012 and July 1, 2013 as a result of the 2010 distribution rate case settlement, and higher weather-normalized retail electric sales (1.8 percent).depreciation expense. Partially offsetting these favorableunfavorable earnings impacts were higher depreciation and property tax expense.
LIQUIDITY
PSNH had cash flows provided by operating activities of $131.1 million for the nine months ended September 30, 2013, compared with $136.5 million for the same period in 2012 (amounts are net of RRB payments, which are included in financing activities). The decrease in cash flows was due primarily to an increase in NUSCO Pension Plan contributions of $20.6 million for the nine months ended September 30, 2013, as compared to the same period in 2012, and an increase in coal and fuel inventories for the nine months ended September 30, 2013 creating a negative cash flow impact of $30.9 million, as compared to a reduction in coal and fuel inventories for the nine months ended September 30, 2012 creating a positive cash flow impact of $23.1 million. Partially offsetting these decreases were income tax refunds of $8.7 million for the nine months ended September 30, 2013, compared to income tax payments of $9.3 million for the same period in 2012, the absence of $8.7 million of 2012 cash disbursements for storm costs associated with Tropical Storm Irene and the October 2011 snowstorm, the favorable impacts related to the distribution rate increases effective July 1, 2012 and July 1, 2013 as a result of the 2010 distribution rate case settlement, and the change in traditional working capital amounts principally due to the changes in timing of accounts payable payments.
64
RESULTS OF OPERATIONS – WESTERN MASSACHUSETTS ELECTRIC COMPANY
The following table provides the amounts and variances in operating revenues and expense line items for the condensed statements of income for WMECO included in this Quarterly Report on Form 10-Q for the nine months ended September 30, 2013 and 2012:
|
|
| Operating Revenues and Expenses |
|
| |||||||||
| For the Nine Months Ended September 30, |
| ||||||||||||
(Millions of Dollars) | 2013 |
| 2012 |
| Increase/ |
| Percent |
|
| |||||
(Decrease) |
| |||||||||||||
Operating Revenues | $ | 361.8 |
| $ | 333.3 |
| $ | 28.5 |
| 8.6 | % |
| ||
Operating Expenses: |
|
|
|
|
|
|
|
|
|
|
|
| ||
| Purchased Power and Transmission |
| 111.1 |
|
| 105.3 |
|
| 5.8 |
| 5.5 |
|
| |
| Operations and Maintenance |
| 70.2 |
|
| 75.2 |
|
| (5.0) |
| (6.6) |
|
| |
| Depreciation |
| 27.7 |
|
| 22.1 |
|
| 5.6 |
| 25.3 |
|
| |
| Amortization of Regulatory (Liabilities)/ |
|
|
|
|
|
|
|
|
|
|
|
| |
|
| Assets, Net |
| (0.6) |
|
| 0.6 |
|
| (1.2) |
| (a) |
|
|
| Amortization of Rate Reduction Bonds |
| 7.8 |
|
| 13.1 |
|
| (5.3) |
| (40.5) |
|
| |
| Energy Efficiency Programs |
| 28.5 |
|
| 19.7 |
|
| 8.8 |
| 44.7 |
|
| |
| Taxes Other Than Income Taxes |
| 20.2 |
|
| 15.4 |
|
| 4.8 |
| 31.2 |
|
| |
|
| Total Operating Expenses |
| 264.9 |
|
| 251.4 |
|
| 13.5 |
| 5.4 |
|
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Operating Income | $ | 96.9 |
| $ | 81.9 |
| $ | 15.0 |
| 18.3 | % |
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(a) Percent greater than 100 percent not shown as it is not meaningful. |
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Operating Revenues |
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WMECO's retail sales were as follows: |
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| For the Nine Months Ended September 30, |
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|
|
| 2013 |
| 2012 |
| Decrease |
| Percent |
|
Retail Sales in GWh |
| 2,786 |
| 2,788 |
| (2) |
| (0.1) | % | |
WMECO’s Operating Revenues increased $28.5 million for the nine months ended September 30, 2013, as compared to the same period in 2012, due primarily to:
·
WMECO’s base distribution revenues are decoupled from its sales volumes. Therefore, its 2013 distribution revenues are consistent with 2012.
·
A $19.8 million increase in transmission revenues reflecting recovery of higher transmission expenses and continuing transmission infrastructure investments, primarily related to the NEEWS project. The increase was partially offset by the establishment of a reserve related to the FERC ALJ initial decision in the third quarter of 2013.
·
The remaining increase primarily reflects a higher level of collections related to WMECO’s energy supply and company-sponsored energy efficiency programs. These revenues are fully reconciled to the related costs. Therefore this increase in revenues had no material impact on earnings.
Purchased Power and Transmissionincreased for the nine months ended September 30, 2013, as compared to the same period in 2012, due primarily to an increase in supplier contract prices.
Operations and Maintenance decreased for the nine months ended September 30, 2013, as compared to the same period in 2012, due primarily to the absence in 2013 of bill credits to customers ($3 million) made in the second quarter of 2012 as a result of the Massachusetts settlement agreement. In addition, there were lower general and administrative expenses ($2.2 million), lower customer uncollectible expenses ($1.8 million) and lower routine distribution maintenance expenses ($1.1 million). Partially offsetting these decreases was an increase in pension costs ($3.3 million), which was recovered through DPU-approved tracking mechanisms and had no earnings impact.
Depreciation increased for the nine months ended September 30, 2013, as compared to the same period in 2012, due primarily to higher utility plant balances resulting from completed construction projects placed into service related to WMECO's capital programs.
Amortization of Rate Reduction Bondsdecreased for the nine months ended September 30, 2013, as compared to the same period in 2012, due to the maturity of the RRBs in June 2013.
Energy Efficiency Programsincreased for the nine months ended September 30, 2013, as compared to the same period in 2012, due primarily to an increase in expenses attributable to an increase in spending in accordance with the three-year program guidelines established by the DPU. All costs are fully recovered through DPU-approved tracking mechanisms and therefore do not impact earnings.
Taxes Other Than Income Taxes increased for the nine months ended September 30, 2013, as compared to the same period in 2012, due primarily to an increase in property taxes as a result of an increase in Property, Plant and Equipment related to WMECO’s capital program and an increase in the property tax rates.
65
Income Tax Expense
|
|
| For the Nine Months Ended September 30, |
| |||||||||
(Millions of Dollars) |
| 2013 |
| 2012 |
| Increase |
| Percent |
| ||||
Income Tax Expense |
| $ | 30.4 |
| $ | 24.4 |
| $ | 6.0 |
| 24.6 | % | |
Income Tax Expense increased for the nine months ended September 30, 2013, as compared to the same period in 2012, due primarily to higher pre-tax earnings ($4.8 million) and the absence in 2013 of the impact of costs recognized as a result of the Massachusetts settlement agreement ($1.2 million).
EARNINGS SUMMARY
For the nine months ended September 30, 2013, excluding $1.8 million in 2012 of after-tax merger-related costs, WMECO’s earnings were $8.8 million higher, as compared to the same period in 2012, due primarily to higher transmission earnings as a result of an increased level of investment in transmission infrastructure, primarily related to the NEEWS project, and lower overall operations and maintenance costs. Partially offsetting these favorable earnings impacts were higher depreciation and property tax expense.reversal of a previously established wholesale billing adjustment.
LIQUIDITY
WMECO had cash flows provided by operating activities of $160.7$46.3 million forin the nine months ended September 30, 2013,first quarter of 2014, compared with $44.9$71 million forin the same periodfirst quarter of 2013. The decrease in 2012 (amounts are net of RRB payments, which are included in financing activities). The improvedoperating cash flows werewas due primarily to income tax refundspayments of $64.4$14.1 million forin the nine months ended September 30, 2013,first quarter of 2014, compared with income tax refunds of $12.9 million for the same period in 2012, the absence for the nine months ended September 30, 2013 of $14.7$26.6 million in cash disbursements made for storm costs in 2012,the first quarter of 2013 and the absence of $3 millioncosts recovered in bill credits providedrates related to customersthe RRBs that were fully amortized in the second quarter of 2012 associated with2013, partially offset by the Massachusetts settlement agreement, andfavorable cash flow impacts relating to changes in traditional working capital amounts principally due to the changes in timing of accounts payable payments.and accounts receivables.
66
ITEM 3.
QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
Market Risk Information
Commodity Price Risk Management: Our Regulated companies enter into energy contracts to serve our customers and the economic impacts of those contracts are passed on to our customers. Accordingly, the Regulated companies have no exposure to loss of future earnings or fair values due to these market risk-sensitive instruments. The remaining unregulated wholesale portfolio held by SelectNU’s Energy includes contracts that are market risk-sensitive, including a wholesale energy sales contract through December 2013 with an agencySupply Risk Committee, comprised of municipalities. As Select Energy's contract volumes are winding down,senior officers, reviews and as the wholesaleapproves all large scale energy sales contract is substantially hedged against price risks, we have limited exposure to commodity price risks. We have notrelated transactions entered into any energy contracts for trading purposes. 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 independent power producers,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 ourthe respective unsecured debt ratings of NU or its subsidiaries were reduced to below investment grade by either Moody’s or S&P, certain of ourNU’s contracts would require additional collateral in the form of cash to be provided to counterparties and independent system operators. If such an event occurred as of September 30, 2013, we would have been required to provide additional collateral. WeNU would have been and remainremains 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“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“Quantitative and Qualitative Disclosures about Market Risk,"” in NU's 2012NU’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 20122013 Form 10-K.
ITEM 4.
Management, on behalf of NU, CL&P, NSTAR Electric, PSNH and WMECO, evaluated the design and operation of the disclosure controls and procedures as of September 30, 2013March 31, 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'smanagement’s supervision and with management'smanagement’s participation, including the principal executive officers and principal financial officer as of the end of the period covered by this Quarterly Report on Form 10-Q. There are inherent limitations of disclosure controls and procedures, including the possibility of human error and the circumventing or overriding of the controls and procedures. Accordingly, even effective disclosure controls and procedures can only provide reasonable assurance of achieving their control objectives. The principal executive officers and principal financial officer have concluded, based on their review, that the disclosure controls and procedures of NU, CL&P, NSTAR Electric, PSNH and WMECO are effective to ensure that information required to be disclosed by us in reports filed under the Securities Exchange Act of 1934 (i) is recorded, processed, summarized, and reported within the time periods specified in SEC rules and regulations and (ii) is accumulated and communicated to management, including the principal executive officers and principal financial officer, as appropriate to allow timely decisions regarding required disclosures.
There have been no changes in internal controls over financial reporting for NU, CL&P, NSTAR Electric, PSNH and WMECO during the quarter ended September 30, 2013, other than changes resulting from the April 10, 2012 merger with NSTAR,March 31, 2014 that have materially affected, or are reasonably likely to materially affect, internal controls over financial reporting.
ITEM 1.
We are parties to various legal proceedings. We have identified these legal proceedings in Part I, Item 3, "Legal“Legal Proceedings,"” and elsewhere in our 20122013 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 20122013 Form 10-K.
ITEM 1A.
We are subject to a variety of significant risks in addition to the matters set forth under "Forward-Looking“Forward-Looking Statements,"” in Item 2, "Management's“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“Risk Factors,"” in our 20122013 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 20122013 Form 10-K.
ITEM 2.
UNREGISTERED SALES OF EQUITY SECURITIES AND USE OF PROCEEDS
The following table discloses purchases of shares of our common stockshares 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 and its Employee Savings Plan.
| Period |
| Total Number |
|
| Average | Total Number of | Approximate Dollar |
| July 1 – July 31, 2013 |
| - |
| $ | - | - | - |
| August 1 – August 31, 2013 |
| - |
|
| - | - | - |
| September 1 – September 30, 2013 |
| 101,000 |
|
| 41.19 | - | - |
| Total |
| 101,000 |
| $ | 41.19 | - | - |
Period |
| Total Number |
| Average |
| Total Number of |
| Approximate Dollar |
| |
January 1 – January 31, 2014 |
| 503,821 |
| $ | 43.30 |
| — |
| — |
|
February 1 – February 28, 2014 |
| 37,241 |
| 43.42 |
| — |
| — |
| |
March 1 – March 31, 2014 |
| 138,094 |
| 44.52 |
| — |
| — |
| |
Total |
| 679,156 |
| $ | 43.55 |
| — |
| — |
|
68
EXHIBITS
Each documentexhibit described below is filed herewith, unless designated with an asterisk (*), which exhibits are incorporated by reference by the registrant(s) listed toregistrant under whose name the files identified, unless designated with a (*), which exhibits are filed herewith.exhibit appears.
Exhibit No. | Description | |
Listing of Exhibits (NU) | ||
* 10.1 | Composite Amended and Restated Indenture, effective January 2, 2014, between Yankee Gas Services Company and The Bank of New York Mellon Trust Company, N.A., successor as Trustee to The Bank of New York, as successor to Fleet National Bank (formerly known as The Connecticut National Bank, as Trustee, dated July 1, 1989 (Composite including all amendments) (incorporated by reference to Exhibit B to the Eleventh Supplemental Indenture, filed as Exhibit 10.2 hereto) | |
10.2 | Eleventh Supplemental Indenture of Mortgage and Deed of Trust, dated as of January 1, 2014, between Yankee Gas Services Company and The Bank of New York Mellon Trust Company, N.A., successor as Trustee to The Bank of New York, as successor to Fleet National Bank (formerly known as The Connecticut National Bank) | |
12 | Ratio of Earnings to Fixed Charges | |
31 | Certification of Thomas J. May, Chairman, President and Chief Executive Officer of NU, required by Rule 13a - 14(a)/15d - 14(a) of the Securities Exchange Act of 1934, as amended, as adopted pursuant to Section 302 of the Sarbanes-Oxley Act of 2002, dated May 2, 2014 | |
31.1 | Certification of James J. Judge, Executive Vice President and Chief Financial Officer of NU, required by Rule 13a - 14(a)/15d - 14(a) of the Securities Exchange Act of 1934, as amended, as adopted pursuant to Section 302 of the Sarbanes-Oxley Act of 2002, dated May 2, 2014 | |
32 | Certification of Thomas J. May, Chairman, President and Chief Executive Officer of NU, and James J. Judge, Executive Vice President and Chief Financial Officer of NU, pursuant to 18 U.S.C. Section 1350 as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, dated May 2, 2014 | |
Listing of Exhibits (CL&P) | ||
12 | Ratio of Earnings to Fixed Charges | |
31 | Certification of Leon J. Olivier, Chief Executive Officer of CL&P, required by Rule 13a - 14(a)/15d - 14(a) of the Securities Exchange Act of 1934, as amended, as adopted pursuant to Section 302 of the Sarbanes-Oxley Act of 2002, dated May 2, 2014 | |
31.1 | Certification of James J. Judge, Executive Vice President and Chief Financial Officer of CL&P, required by Rule 13a - 14(a)/15d - 14(a) of the Securities Exchange Act of 1934, as amended, as adopted pursuant to Section 302 of the Sarbanes-Oxley Act of 2002, dated May 2, 2014 | |
32 | Certification of Leon J. Olivier, Chief Executive Officer of CL&P, and James J. Judge, Executive Vice President and Chief Financial Officer of CL&P, pursuant to 18 U.S.C. Section 1350 as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, dated May 2, 2014 | |
Listing of Exhibits (NSTAR Electric) | ||
* 4.1 | A Form of 4.40% Debenture Due March 1, 2044. (Incorporated by reference to Exhibit 4 of the NSTAR Electric Company Current Report on Form 8-K, filed March 13, 2014, File No. 001-02301) | |
12 | Ratio of Earnings to Fixed Charges | |
31 | Certification of Leon J. Olivier, Chief Executive Officer of NSTAR Electric, required by Rule 13a - 14(a)/15d - 14(a) of the Securities Exchange Act of 1934, as amended, as adopted pursuant to Section 302 of the Sarbanes-Oxley Act of 2002, dated May 2, 2014 | |
31.1 | Certification of James J. Judge, Executive Vice President and Chief Financial Officer of NSTAR Electric, required by Rule 13a - 14(a)/15d - 14(a) of the Securities Exchange Act of 1934, as amended, as adopted pursuant to Section 302 of the Sarbanes-Oxley Act of 2002, dated May 2, 2014 | |
32 | Certification of Leon J. Olivier, Chief Executive Officer of NSTAR Electric, and James J. Judge, Executive Vice President and Chief Financial Officer of NSTAR Electric, pursuant to 18 U.S.C. Section 1350 as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, dated May 2, 2014 | |
Description
Listing of Exhibits (PSNH) | ||
12 | Ratio of Earnings to Fixed Charges | |
31 | Certification of Leon J. Olivier, Chief Executive Officer of PSNH, required by Rule 13a - 14(a)/15d - 14(a) of the Securities Exchange Act of 1934, as amended, as adopted pursuant to Section 302 of the Sarbanes-Oxley Act of 2002, dated May 2, 2014 | |
31.1 | Certification of James J. Judge, Executive Vice President and Chief Financial Officer of PSNH, required by Rule 13a - 14(a)/15d - 14(a) of the Securities Exchange Act of 1934, as amended, as adopted pursuant to Section 302 of the Sarbanes-Oxley Act of 2002, dated May 2, 2014 | |
32 | Certification of Leon J. Olivier, Chief Executive Officer of PSNH, and James J. Judge, Executive Vice President and Chief Financial Officer of PSNH, pursuant to 18 U.S.C. Section 1350 as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, dated May 2, 2014 | |
Listing of Exhibits (WMECO) | ||
12 | Ratio of Earnings to Fixed Charges | |
31 | Certification of Leon J. Olivier, Chief Executive Officer of WMECO, required by Rule 13a - 14(a)/15d - 14(a) of the Securities Exchange Act of 1934, as amended, as adopted pursuant to Section 302 of the Sarbanes-Oxley Act of 2002, dated May 2, 2014 | |
31.1 | Certification of James J. Judge, Executive Vice President and Chief Financial Officer of WMECO, required by Rule 13a - 14(a)/15d - 14(a) of the Securities Exchange Act of 1934, as amended, as adopted pursuant to Section 302 of the Sarbanes-Oxley Act of 2002, dated May 2, 2014 | |
32 | Certification of Leon J. Olivier, Chief Executive Officer of WMECO, and James J. Judge, Executive Vice President and Chief Financial Officer of WMECO, pursuant to 18 U.S.C. Section 1350 as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, dated May 2, 2014 | |
Listing of Exhibits (NU)
*12
Ratio of Earnings to Fixed Charges
*31
Certification of Thomas J. May, Chairman, President and Chief Executive Officer of Northeast Utilities, required by Rule 13a-14(a)/15d-14(a) of the Securities Exchange Act of 1934, as amended, as adopted pursuant to Section 302 of the Sarbanes-Oxley Act of 2002, dated November 4, 2013
*31.1
Certification of James J. Judge, Executive Vice President and Chief Financial Officer of Northeast Utilities, required by Rule 13a-14(a)/15d-14(a) of the Securities Exchange Act of 1934, as amended, as adopted pursuant to Section 302 of the Sarbanes-Oxley Act of 2002, dated November 4, 2013
*32
Certification of Thomas J. May, Chairman, President and Chief Executive Officer of Northeast Utilities and James J. Judge, Executive Vice President and Chief Financial Officer of Northeast Utilities, pursuant to 18 U.S.C. Section 1350 as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, dated November 4, 2013
Listing of Exhibits (CL&P)
*12
Ratio of Earnings to Fixed Charges
*31
Certification of Leon J. Olivier, Chief Executive Officer of The Connecticut Light and Power Company, required by Rule 13a-14(a)/15d-14(a) of the Securities Exchange Act of 1934, as amended, as adopted pursuant to Section 302 of the Sarbanes- Oxley Act of 2002, dated November 4, 2013
*31.1
Certification of James J. Judge, Executive Vice President and Chief Financial Officer of The Connecticut Light and Power Company, required by Rule 13a-14(a)/15d-14(a) of the Securities Exchange Act of 1934, as amended, as adopted pursuant to Section 302 of the Sarbanes-Oxley Act of 2002, dated November 4, 2013
*32
Certification of Leon J. Olivier, Chief Executive Officer of The Connecticut Light and Power Company and James J. Judge, Executive Vice President and Chief Financial Officer of The Connecticut Light and Power Company, pursuant to 18 U.S.C. Section 1350 as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, dated November 4, 2013
Listing of Exhibits (NSTAR Electric)
4.1
First Amendment to Credit Agreement, dated September 6, 2013, by and among NSTAR Electric Company and Barclays Bank PLC, as Administrative Agent, and other lenders named therein. (Exhibit 4.2 to NSTAR Electric Company Current Report on Form 8-K filed on September 12, 2013, File No. 001-02301.)
*12
Ratio of Earnings to Fixed Charges
*31
Certification of Leon J. Olivier, Chief Executive Officer of NSTAR Electric Company, required by Rule 13a-14(a)/15d-14(a) of the Securities Exchange Act of 1934, as amended, as adopted pursuant to Section 302 of the Sarbanes-Oxley Act of 2002, dated November 4, 2013
*31.1
Certification of James J. Judge, Executive Vice President and Chief Financial Officer of NSTAR Electric Company, required by Rule 13a-14(a)/15d-14(a) of the Securities Exchange Act of 1934, as amended, as adopted pursuant to Section 302 of the Sarbanes-Oxley Act of 2002, dated November 4, 2013
*32
Certification of Leon J. Olivier, Chief Executive Officer of NSTAR Electric Company and James J. Judge, Executive Vice President and Chief Financial Officer of NSTAR Electric Company, pursuant to 18 U.S.C. Section 1350 as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, dated November 4, 2013
69
Listing of Exhibits (PSNH)
*12
Ratio of Earnings to Fixed Charges
*31
Certification of Leon J. Olivier, Chief Executive Officer of Public Service Company of New Hampshire, required by Rule 13a-14(a)/15d-14(a) of the Securities Exchange Act of 1934, as amended, as adopted pursuant to Section 302 of the Sarbanes- Oxley Act of 2002, dated November 4, 2013
*31.1
Certification of James J. Judge, Executive Vice President and Chief Financial Officer of Public Service Company of New Hampshire, required by Rule 13a-14(a)/15d-14(a) of the Securities Exchange Act of 1934, as amended, as adopted pursuant to Section 302 of the Sarbanes-Oxley Act of 2002, dated November 4, 2013
*32
Certification of Leon J. Olivier, Chief Executive Officer of Public Service Company of New Hampshire and James J. Judge, Executive Vice President and Chief Financial Officer of Public Service Company of New Hampshire, pursuant to 18 U.S.C. Section 1350 as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, dated November 4, 2013
Listing of Exhibits (WMECO)
*12
Ratio of Earnings to Fixed Charges
*31
Certification of Leon J. Olivier, Chief Executive Officer of Western Massachusetts Electric Company, required by Rule 13a-14(a)/15d-14(a) of the Securities Exchange Act of 1934, as amended, as adopted pursuant to Section 302 of the Sarbanes- Oxley Act of 2002, dated November 4, 2013
*31.1
Certification of James J. Judge, Executive Vice President and Chief Financial Officer of Western Massachusetts Electric Company, required by Rule 13a-14(a)/15d-14(a) of the Securities Exchange Act of 1934, as amended, as adopted pursuant to Section 302 of the Sarbanes-Oxley Act of 2002, dated November 4, 2013
*32
Certification of Leon J. Olivier, Chief Executive Officer of Western Massachusetts Electric Company and James J. Judge, Executive Vice President and Chief Financial Officer of Western Massachusetts Electric Company, pursuant to 18 U.S.C. Section 1350 as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, dated November 4, 2013
Listing of Exhibits (NU, CL&P, PSNH, WMECO)
4.1
First Amendment to Credit Agreement, dated September 6, 2013, by and among Northeast Utilities and its subsidiaries, The Connecticut Light and Power Company, NSTAR Gas Company, NSTAR LLC, Public Service Company of New Hampshire, Western Massachusetts Electric Company and Yankee Gas Services Company, and Bank of America, N.A., as Administrative Agent, and other lenders named therein (Exhibit 4.1 to NU Current Report on Form 8-K filed on September 12, 2013, File No. 001-05324.)
Listing of Exhibits (NU, CL&P, NSTAR Electric, PSNH, WMECO)
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.
|
| |
May 2, 2014 | By: | /s/ Jay S. Buth |
Jay S. Buth | ||
Vice President, Controller and Chief Accounting Officer | ||
SIGNATURE
Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the Registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.
THE CONNECTICUT LIGHT AND POWER COMPANY | ||
May 2, 2014 | By: | /s/ Jay S. Buth |
Jay S. Buth | ||
Vice President, Controller and Chief Accounting Officer | ||
SIGNATURE
Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the Registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.
NSTAR ELECTRIC COMPANY | ||
May 2, 2014 | By: | /s/ Jay S. Buth |
Jay S. Buth | ||
Vice President, Controller and Chief Accounting Officer | ||
SIGNATURE
Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the Registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.
PUBLIC SERVICE COMPANY OF NEW HAMPSHIRE | ||
May 2, 2014 | By: | /s/ Jay S. Buth |
Jay S. Buth | ||
Vice President, Controller and Chief Accounting Officer | ||
SIGNATURE
Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the Registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.
WESTERN MASSACHUSETTS ELECTRIC COMPANY | ||
May 2, 2014 | By: | /s/ Jay S. Buth |
Jay S. Buth | ||
Vice President, Controller and Chief Accounting Officer | ||