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UNITED STATES SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, D.C. 20549
FORM 10-Q
| QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE |
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| For the Quarterly Period Ended |
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| TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE |
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| For the transition period from ____________ to ____________ |
Commission | Registrant; State of Incorporation; | I.R.S. Employer |
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1-5324 |
| 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 |
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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 |
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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 wasregistrants were required to submit and post such files).
| Yes | No |
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Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, or a non-accelerated filer. See definition of "accelerated filerfiler" and large"large accelerated filer" in Rule 12b-2 of the Exchange Act. (Check one):
| Large |
| Accelerated |
| Non-accelerated |
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The Connecticut Light and Power Company |
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NSTAR Electric Company |
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Public Service Company of New Hampshire |
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Western Massachusetts Electric Company |
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Indicate by check mark whether the registrants are shell companies (as defined in Rule 12b-2 of the Exchange Act):
| Yes | No |
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The Connecticut Light and Power Company |
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NSTAR Electric Company |
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Public Service Company of New Hampshire |
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Western Massachusetts Electric Company |
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Indicate the number of shares outstanding of each of the issuers' classes of common stock, as of the latest practicable date:
Company - Class of Stock | Outstanding as of |
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The Connecticut Light and Power Company | 6,035,205 shares |
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NSTAR Electric Company | 100 shares |
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Public Service Company of New Hampshire | 301 shares |
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Western Massachusetts Electric Company | 434,653 shares |
Northeast UtilitiesEversource Energy 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.
Eversource Energy, The Connecticut Light and Power Company, NSTAR Electric Company, Public Service Company of New Hampshire, and Western Massachusetts Electric Company each separately file this combined Form 10-Q. Information contained herein relating to any individual registrant is filed by such registrant on its own behalf. Each registrant makes no representation as to information relating to the other registrants.
GLOSSARY OF TERMS
The following is a glossary of abbreviations or acronyms that are found in this report: | |
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Current or former Eversource Energy companies, segments or investments: | |
ES, Eversource or the Company | Eversource Energy and subsidiaries |
ES parent | Eversource Energy, a public utility holding company |
ES parent and other companies | ES parent and other companies is comprised of ES parent, Eversource Service and other subsidiaries, which primarily includes our unregulated businesses, HWP Company, The Rocky River Realty Company (a real estate subsidiary), and the consolidated operations of CYAPC and YAEC |
CL&P | The Connecticut Light and Power Company |
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WMECO | Western Massachusetts Electric Company |
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ESTV | Eversource Energy Transmission Ventures, Inc., the parent company of NPT and Renewable Properties, Inc. |
NPT | Northern Pass Transmission LLC |
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| Northeast Utilities Service Company (effective January 1, 2014 includes the operations of NSTAR Electric & Gas) |
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MYAPC | Maine Yankee Atomic Power Company |
YAEC | Yankee Atomic Electric Company |
Yankee Companies | CYAPC, YAEC and MYAPC |
Regulated companies |
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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 |
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AFUDC | Allowance For Funds Used During Construction |
AOCI | Accumulated Other Comprehensive Income/(Loss) |
ARO | Asset Retirement Obligation |
C&LM | Conservation and Load Management |
CfD | Contract for Differences |
Clean Air Project | The construction of a wet flue gas desulphurization system, known as "scrubber technology," |
CO2 | Carbon dioxide |
CPSL | Capital Projects Scheduling List |
CTA | Competitive Transition Assessment |
CWIP | Construction |
EPS | Earnings Per Share |
ERISA | Employee Retirement Income Security Act of 1974 |
ES 2014 Form 10-K |
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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 |
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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) |
LBR | Lost Base Revenue |
LNG | Liquefied natural gas |
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LRS | Supplier of last resort service |
MGP | Manufactured Gas Plant |
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MMBtu | One million British thermal units |
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MW | Megawatt |
MWh | Megawatt-Hours |
NEEWS | New England East-West Solution |
Northern Pass | The high voltage direct current transmission line project from Canada into New Hampshire |
NOx | Nitrogen |
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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 Plans and non-qualified defined benefit retirement plans |
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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 UTILITIESEVERSOURCE ENERGY 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
TABLE OF CONTENTS
| Page |
PART I - FINANCIAL INFORMATION |
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ITEM 1 - Unaudited Condensed Consolidated Financial Statements for the Following Companies: |
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The Connecticut Light and Power Company (Unaudited) |
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Condensed Statements of Income | 5 |
Condensed Statements of Comprehensive Income | 5 |
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NSTAR Electric Company and Subsidiary (Unaudited) |
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Condensed Consolidated Statements of Cash Flows |
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Public Service Company of New Hampshire and Subsidiary (Unaudited) |
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Western Massachusetts Electric Company (Unaudited) |
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Combined Notes to Condensed Consolidated Financial Statements (Unaudited) |
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ITEM 2– Management's Discussion and Analysis of Financial Condition and Results of Operations for the | |
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ITEM 3 – Quantitative and Qualitative Disclosures About Market Risk |
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PART II – OTHER INFORMATION |
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ITEM 2– Unregistered Sales of Equity Securities and Use of Proceeds |
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NORTHEAST UTILITIES AND SUBSIDIARIES |
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EVERSOURCE ENERGY AND SUBSIDIARIES | EVERSOURCE ENERGY AND SUBSIDIARIES |
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CONDENSED CONSOLIDATED BALANCE SHEETS | CONDENSED CONSOLIDATED BALANCE SHEETS |
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| CONDENSED CONSOLIDATED BALANCE SHEETS |
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(Unaudited) | (Unaudited) |
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| June 30, |
| December 31, |
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| March 31, |
| December 31, | ||||
(Thousands of Dollars) | (Thousands of Dollars) | 2014 |
| 2013 | (Thousands of Dollars) | 2015 |
| 2014 | |||||
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ASSETS | ASSETS |
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Current Assets: | Current Assets: |
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| Current Assets: |
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| Cash and Cash Equivalents | $ | 34,096 |
| $ | 43,364 |
| Cash and Cash Equivalents | $ | 71,027 |
| $ | 38,703 |
| Receivables, Net |
| 807,510 |
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| 765,391 |
| Receivables, Net |
| 1,131,434 |
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| 856,346 |
| Unbilled Revenues |
| 193,983 |
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| 224,982 |
| Unbilled Revenues |
| 229,760 |
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| 211,758 |
| Fuel, Materials and Supplies |
| 281,721 |
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| 303,233 |
| Taxes Receivable |
| 99,680 |
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| 337,307 |
| Regulatory Assets |
| 467,156 |
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| 535,791 |
| Fuel, Materials and Supplies |
| 281,492 |
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| 349,664 |
| Marketable Securities |
| 115,987 |
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| 92,427 |
| Regulatory Assets |
| 747,349 |
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| 672,493 |
| Prepayments and Other Current Assets |
| 168,022 |
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| 121,861 |
| Prepayments and Other Current Assets |
| 231,949 |
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| 226,194 |
Total Current Assets | Total Current Assets |
| 2,068,475 |
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| 2,087,049 | Total Current Assets |
| 2,792,691 |
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| 2,692,465 | |
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Property, Plant and Equipment, Net | Property, Plant and Equipment, Net |
| 17,978,692 |
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| 17,576,186 | Property, Plant and Equipment, Net |
| 18,810,708 |
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| 18,647,041 | |
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Deferred Debits and Other Assets: | Deferred Debits and Other Assets: |
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| Deferred Debits and Other Assets: |
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| Regulatory Assets |
| 3,339,457 |
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| 3,758,694 |
| Regulatory Assets |
| 3,981,507 |
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| 4,054,086 |
| Goodwill |
| 3,519,401 |
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| 3,519,401 |
| Goodwill |
| 3,519,401 |
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| 3,519,401 |
| Marketable Securities |
| 513,986 |
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| 488,515 |
| Marketable Securities |
| 518,065 |
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| 515,025 |
| Other Long-Term Assets |
| 370,434 |
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| 365,692 |
| Other Long-Term Assets |
| 329,393 |
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| 349,957 |
Total Deferred Debits and Other Assets | Total Deferred Debits and Other Assets |
| 7,743,278 |
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| 8,132,302 | Total Deferred Debits and Other Assets |
| 8,348,366 |
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| 8,438,469 | |
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Total Assets | Total Assets | $ | 29,951,765 |
| $ | 29,777,975 | |||||||
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LIABILITIES AND CAPITALIZATION | LIABILITIES AND CAPITALIZATION |
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Total Assets | $ | 27,790,445 |
| $ | 27,795,537 | ||||||||
Current Liabilities: | Current Liabilities: |
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| Notes Payable | $ | 1,003,500 |
| $ | 956,825 | |
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| Long-Term Debt - Current Portion |
| 245,583 |
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| 245,583 | |
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| Accounts Payable |
| 739,324 |
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| 868,231 | |
| Obligations to Third Party Suppliers |
| 157,143 |
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| 115,632 | |||||||
| Regulatory Liabilities |
| 201,180 |
| 235,022 | ||||||||
| Accumulated Deferred Income Taxes |
| 218,582 |
| 160,288 | ||||||||
| Other Current Liabilities |
| 546,470 |
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| 552,800 | |||||||
Total Current Liabilities | Total Current Liabilities |
| 3,111,782 |
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| 3,134,381 | |||||||
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Deferred Credits and Other Liabilities: | Deferred Credits and Other Liabilities: |
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| Accumulated Deferred Income Taxes |
| 4,574,630 |
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| 4,467,473 | |||||||
| Regulatory Liabilities |
| 524,940 |
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| 515,144 | |||||||
| Derivative Liabilities |
| 396,617 |
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| 409,632 | |||||||
| Accrued Pension, SERP and PBOP |
| 1,605,339 |
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| 1,638,558 | |||||||
| Other Long-Term Liabilities |
| 870,417 |
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| 874,387 | |||||||
Total Deferred Credits and Other Liabilities | Total Deferred Credits and Other Liabilities |
| 7,971,943 |
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| 7,905,194 | |||||||
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Capitalization: | Capitalization: |
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| Long-Term Debt |
| 8,602,067 |
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| 8,606,017 | |||||||
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| Noncontrolling Interest - Preferred Stock of Subsidiaries |
| 155,568 |
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| 155,568 | |||||||
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| Equity: |
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| Common Shareholders' Equity: |
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| Common Shares |
| 1,668,039 |
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| 1,666,796 | ||||||
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| Capital Surplus, Paid In |
| 6,241,417 |
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| 6,235,834 | ||||||
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| Retained Earnings |
| 2,569,482 |
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| 2,448,661 | ||||||
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| Accumulated Other Comprehensive Loss |
| (72,414) |
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| (74,009) | ||||||
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| Treasury Stock |
| (296,119) |
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| (300,467) | ||||||
| Common Shareholders' Equity |
| 10,110,405 |
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| 9,976,815 | |||||||
Total Capitalization | Total Capitalization |
| 18,868,040 |
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| 18,738,400 | |||||||
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Total Liabilities and Capitalization | Total Liabilities and Capitalization | $ | 29,951,765 |
| $ | 29,777,975 | |||||||
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The accompanying notes are an integral part of these unaudited condensed consolidated financial statements. | The accompanying notes are an integral part of these unaudited condensed consolidated financial statements. | The accompanying notes are an integral part of these unaudited condensed consolidated financial statements. |
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1
NORTHEAST UTILITIES AND SUBSIDIARIES |
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CONDENSED CONSOLIDATED BALANCE SHEETS |
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(Unaudited) |
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| June 30, |
| December 31, | ||
(Thousands of Dollars) | 2014 |
| 2013 | ||||
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LIABILITIES AND CAPITALIZATION |
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Current Liabilities: |
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| Notes Payable | $ | 905,000 |
| $ | 1,093,000 | |
| Long-Term Debt - Current Portion |
| 395,583 |
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| 533,346 | |
| Accounts Payable |
| 561,699 |
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| 742,251 | |
| Regulatory Liabilities |
| 359,921 |
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| 204,278 | |
| Other Current Liabilities |
| 580,605 |
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| 702,776 | |
Total Current Liabilities |
| 2,802,808 |
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| 3,275,651 | ||
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Deferred Credits and Other Liabilities: |
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| Accumulated Deferred Income Taxes |
| 4,270,050 |
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| 4,029,026 | |
| Regulatory Liabilities |
| 503,955 |
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| 502,984 | |
| Derivative Liabilities |
| 449,439 |
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| 624,050 | |
| Accrued Pension, SERP and PBOP |
| 825,001 |
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| 896,844 | |
| Other Long-Term Liabilities |
| 882,688 |
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| 923,053 | |
Total Deferred Credits and Other Liabilities |
| 6,931,133 |
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| 6,975,957 | ||
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Capitalization: |
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| Long-Term Debt |
| 8,147,129 |
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| 7,776,833 | |
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| Noncontrolling Interest - Preferred Stock of Subsidiaries |
| 155,568 |
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| 155,568 | |
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| Equity: |
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| Common Shareholders' Equity: |
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| Common Shares |
| 1,666,637 |
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| 1,665,351 |
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| Capital Surplus, Paid In |
| 6,201,555 |
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| 6,192,765 |
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| Retained Earnings |
| 2,241,025 |
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| 2,125,980 |
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| Accumulated Other Comprehensive Loss |
| (41,507) |
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| (46,031) |
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| Treasury Stock |
| (313,903) |
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| (326,537) |
| Common Shareholders' Equity |
| 9,753,807 |
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| 9,611,528 | |
Total Capitalization |
| 18,056,504 |
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| 17,543,929 | ||
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Total Liabilities and Capitalization | $ | 27,790,445 |
| $ | 27,795,537 | ||
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The accompanying notes are an integral part of these unaudited condensed consolidated financial statements. |
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EVERSOURCE ENERGY AND SUBSIDIARIES |
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CONDENSED CONSOLIDATED STATEMENTS OF INCOME |
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| For the Three Months Ended March 31, | ||||
(Thousands of Dollars, Except Share Information) | 2015 |
| 2014 | |||||
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Operating Revenues | $ | 2,513,431 |
| $ | 2,290,590 | |||
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Operating Expenses: |
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| Purchased Power, Fuel and Transmission |
| 1,162,049 |
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| 978,150 | ||
| Operations and Maintenance |
| 333,382 |
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| 351,688 | ||
| Depreciation |
| 163,837 |
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| 150,807 | ||
| Amortization of Regulatory Assets, Net |
| 60,604 |
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| 57,898 | ||
| Energy Efficiency Programs |
| 146,603 |
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| 138,825 | ||
| Taxes Other Than Income Taxes |
| 149,481 |
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| 145,533 | ||
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| Total Operating Expenses |
| 2,015,956 |
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| 1,822,901 |
Operating Income |
| 497,475 |
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| 467,689 | |||
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Interest Expense: |
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| Interest on Long-Term Debt |
| 87,714 |
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| 87,377 | ||
| Other Interest |
| 7,129 |
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| 2,598 | ||
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| Interest Expense |
| 94,843 |
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| 89,975 | |
Other Income, Net |
| 5,727 |
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| 1,667 | |||
Income Before Income Tax Expense |
| 408,359 |
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| 379,381 | |||
Income Tax Expense |
| 153,226 |
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| 141,545 | |||
Net Income |
| 255,133 |
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| 237,836 | |||
Net Income Attributable to Noncontrolling Interests |
| 1,879 |
|
| 1,879 | |||
Net Income Attributable to Controlling Interest | $ | 253,254 |
| $ | 235,957 | |||
|
|
|
|
|
|
|
|
|
Basic Earnings Per Common Share | $ | 0.80 |
| $ | 0.75 | |||
|
|
|
|
|
|
|
|
|
Diluted Earnings Per Common Share | $ | 0.80 |
| $ | 0.74 | |||
|
|
|
|
|
|
|
|
|
Dividends Declared Per Common Share | $ | 0.42 |
| $ | 0.39 | |||
|
|
|
|
|
|
|
|
|
Weighted Average Common Shares Outstanding: |
|
|
|
|
| |||
| Basic |
| 317,090,841 |
|
| 315,534,512 | ||
| Diluted |
| 318,491,188 |
|
| 316,892,119 | ||
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
The accompanying notes are an integral part of these unaudited condensed consolidated financial statements. | ||||||||
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME | ||||||||
(Unaudited) |
|
|
| |||||
|
|
|
|
|
|
|
|
|
Net Income | $ | 255,133 |
| $ | 237,836 | |||
Other Comprehensive Income, Net of Tax: |
|
|
|
|
| |||
| Qualified Cash Flow Hedging Instruments |
| 509 |
|
| 509 | ||
| Changes in Unrealized Gains on Other Securities |
| 132 |
|
| 240 | ||
| Changes in Funded Status of Pension, SERP and PBOP Benefit Plans |
| 954 |
|
| 961 | ||
Other Comprehensive Income, Net of Tax |
| 1,595 |
|
| 1,710 | |||
Comprehensive Income Attributable to Noncontrolling Interests |
| (1,879) |
|
| (1,879) | |||
Comprehensive Income Attributable to Controlling Interest | $ | 254,849 |
| $ | 237,667 | |||
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
The accompanying notes are an integral part of these unaudited condensed consolidated financial statements. |
2
EVERSOURCE ENERGY AND SUBSIDIARIES | |||||||
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS | |||||||
(Unaudited) |
|
|
|
|
| ||
| |||||||
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| For the Three Months Ended March 31, | ||||
(Thousands of Dollars) | 2015 |
| 2014 | ||||
|
|
|
|
|
|
|
|
Operating Activities: |
|
|
|
|
| ||
| Net Income | $ | 255,133 |
| $ | 237,836 | |
| Adjustments to Reconcile Net Income to Net Cash Flows Provided by Operating Activities: |
|
|
|
|
| |
|
| Depreciation |
| 163,837 |
|
| 150,807 |
|
| Deferred Income Taxes |
| 148,193 |
|
| 137,417 |
|
| Pension, SERP and PBOP Expense |
| 26,495 |
|
| 24,995 |
|
| Pension and PBOP Contributions |
| (26,659) |
|
| (6,622) |
|
| Regulatory Over/(Under) Recoveries, Net |
| (110,748) |
|
| 872 |
|
| Amortization of Regulatory Assets, Net |
| 60,604 |
|
| 57,898 |
|
| Proceeds from DOE Damages Claim, Net |
| - |
|
| 163,300 |
|
| Deferral of DOE Proceeds |
| - |
|
| (163,300) |
|
| Other |
| (21,617) |
|
| (7,574) |
| Changes in Current Assets and Liabilities: |
|
|
|
|
| |
|
| Receivables and Unbilled Revenues, Net |
| (328,299) |
|
| (182,221) |
|
| Fuel, Materials and Supplies |
| 68,172 |
|
| 75,041 |
|
| Taxes Receivable/Accrued, Net |
| 272,021 |
|
| (59,840) |
|
| Accounts Payable |
| (59,496) |
|
| 53,905 |
|
| Other Current Assets and Liabilities, Net |
| 34,179 |
|
| 11,282 |
Net Cash Flows Provided by Operating Activities |
| 481,815 |
|
| 493,796 | ||
|
|
|
|
|
|
|
|
Investing Activities: |
|
|
|
|
| ||
| Investments in Property, Plant and Equipment |
| (362,586) |
|
| (348,691) | |
| Proceeds from Sales of Marketable Securities |
| 114,730 |
|
| 128,505 | |
| Purchases of Marketable Securities |
| (116,735) |
|
| (132,605) | |
| Other Investing Activities |
| 66 |
|
| 1,637 | |
Net Cash Flows Used in Investing Activities |
| (364,525) |
|
| (351,154) | ||
|
|
|
|
|
|
|
|
Financing Activities: |
|
|
|
|
| ||
| Cash Dividends on Common Shares |
| (132,433) |
|
| (118,460) | |
| Cash Dividends on Preferred Stock |
| (1,879) |
|
| (1,879) | |
| Decrease in Notes Payable |
| (399,575) |
|
| (299,500) | |
| Issuance of Long-Term Debt |
| 450,000 |
|
| 400,000 | |
| Retirements of Long-Term Debt |
| - |
|
| (75,000) | |
| Other Financing Activities |
| (1,079) |
|
| (2,017) | |
Net Cash Flows Used in Financing Activities |
| (84,966) |
|
| (96,856) | ||
Net Increase in Cash and Cash Equivalents |
| 32,324 |
|
| 45,786 | ||
Cash and Cash Equivalents - Beginning of Period |
| 38,703 |
|
| 43,364 | ||
Cash and Cash Equivalents - End of Period | $ | 71,027 |
| $ | 89,150 | ||
|
|
|
|
|
|
|
|
The accompanying notes are an integral part of these unaudited condensed consolidated financial statements. | |||||||
|
|
|
|
|
|
|
|
3
NORTHEAST UTILITIES AND SUBSIDIARIES | |||||||
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS | |||||||
(Unaudited) |
|
|
|
|
| ||
| |||||||
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| For the Six Months Ended June 30, | ||||
(Thousands of Dollars) | 2014 |
| 2013 | ||||
|
|
|
|
|
|
|
|
Operating Activities: |
|
|
|
|
| ||
| Net Income | $ | 367,083 |
| $ | 403,032 | |
| Adjustments to Reconcile Net Income to Net Cash Flows Provided by Operating Activities: |
|
|
|
|
| |
|
| Depreciation |
| 303,014 |
|
| 314,530 |
|
| Deferred Income Taxes |
| 133,149 |
|
| 256,294 |
|
| Pension, SERP and PBOP Expense |
| 47,558 |
|
| 97,671 |
|
| Pension and PBOP Contributions |
| (40,640) |
|
| (122,826) |
|
| Regulatory Over/(Under) Recoveries, Net |
| 164,388 |
|
| (4,793) |
|
| Amortization of Regulatory Assets, Net |
| 54,356 |
|
| 108,623 |
|
| Amortization of Rate Reduction Bonds |
| - |
|
| 42,581 |
|
| Proceeds from DOE Damages Claim, Net |
| 125,658 |
|
| - |
|
| Other |
| (9,359) |
|
| 19,932 |
| Changes in Current Assets and Liabilities: |
|
|
|
|
| |
|
| Receivables and Unbilled Revenues, Net |
| (57,570) |
|
| (101,229) |
|
| Fuel, Materials and Supplies |
| 26,633 |
|
| 10,964 |
|
| Taxes Receivable/Accrued, Net |
| (62,900) |
|
| (58,350) |
|
| Accounts Payable |
| (112,954) |
|
| (127,379) |
|
| Other Current Assets and Liabilities, Net |
| (41,753) |
|
| (70,026) |
Net Cash Flows Provided by Operating Activities |
| 896,663 |
|
| 769,024 | ||
|
|
|
|
|
|
|
|
Investing Activities: |
|
|
|
|
| ||
| Investments in Property, Plant and Equipment |
| (724,043) |
|
| (700,252) | |
| Proceeds from Sales of Marketable Securities |
| 256,309 |
|
| 342,251 | |
| Purchases of Marketable Securities |
| (257,168) |
|
| (424,096) | |
| Decrease in Special Deposits |
| 2,894 |
|
| 65,121 | |
| Other Investing Activities |
| 579 |
|
| (843) | |
Net Cash Flows Used in Investing Activities |
| (721,429) |
|
| (717,819) | ||
|
|
|
|
|
|
|
|
Financing Activities: |
|
|
|
|
| ||
| Cash Dividends on Common Shares |
| (237,161) |
|
| (232,068) | |
| Cash Dividends on Preferred Stock |
| (3,759) |
|
| (3,922) | |
| Decrease in Short-Term Debt |
| (213,000) |
|
| (720,500) | |
| Issuance of Long-Term Debt |
| 650,000 |
|
| 1,350,000 | |
| Retirements of Long-Term Debt |
| (376,650) |
|
| (360,635) | |
| Retirements of Rate Reduction Bonds |
| - |
|
| (82,139) | |
| Other Financing Activities |
| (3,932) |
|
| (11,634) | |
Net Cash Flows Used in Financing Activities |
| (184,502) |
|
| (60,898) | ||
Net Decrease in Cash and Cash Equivalents |
| (9,268) |
|
| (9,693) | ||
Cash and Cash Equivalents - Beginning of Period |
| 43,364 |
|
| 45,748 | ||
Cash and Cash Equivalents - End of Period | $ | 34,096 |
| $ | 36,055 | ||
|
|
|
|
|
|
|
|
The accompanying notes are an integral part of these unaudited condensed consolidated financial statements. | |||||||
|
|
|
|
|
|
|
|
THE CONNECTICUT LIGHT AND POWER COMPANY |
|
|
|
|
| ||
CONDENSED BALANCE SHEETS |
|
|
|
|
| ||
(Unaudited) |
|
|
|
|
| ||
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| March 31, |
| December 31, | ||
(Thousands of Dollars) | 2015 |
| 2014 | ||||
|
|
|
|
|
|
|
|
ASSETS |
|
|
|
|
| ||
|
|
|
|
|
|
|
|
Current Assets: |
|
|
|
|
| ||
|
| Cash | $ | 16,818 |
| $ | 2,356 |
|
| Receivables, Net |
| 449,506 |
|
| 355,140 |
|
| Accounts Receivable from Affiliated Companies |
| 27,618 |
|
| 16,757 |
|
| Unbilled Revenues |
| 113,498 |
|
| 102,137 |
|
| Taxes Receivable |
| - |
|
| 116,148 |
|
| Regulatory Assets |
| 209,628 |
|
| 220,344 |
|
| Materials and Supplies |
| 48,135 |
|
| 46,664 |
|
| Prepayments and Other Current Assets |
| 51,074 |
|
| 37,822 |
Total Current Assets |
| 916,277 |
|
| 897,368 | ||
|
|
|
|
|
|
|
|
Property, Plant and Equipment, Net |
| 6,874,891 |
|
| 6,809,664 | ||
|
|
|
|
|
|
|
|
Deferred Debits and Other Assets: |
|
|
|
|
| ||
|
| Regulatory Assets |
| 1,454,150 |
|
| 1,475,508 |
|
| Other Long-Term Assets |
| 171,085 |
|
| 177,568 |
Total Deferred Debits and Other Assets |
| 1,625,235 |
|
| 1,653,076 | ||
|
|
|
|
|
|
|
|
Total Assets | $ | 9,416,403 |
| $ | 9,360,108 | ||
|
|
|
|
|
|
|
|
LIABILITIES AND CAPITALIZATION |
|
|
|
|
| ||
|
|
|
|
|
|
|
|
Current Liabilities: |
|
|
|
|
| ||
| Notes Payable to ES Parent | $ | 190,100 |
| $ | 133,400 | |
| Long-Term Debt - Current Portion |
| 162,000 |
|
| 162,000 | |
| Accounts Payable |
| 230,175 |
|
| 272,971 | |
| Accounts Payable to Affiliated Companies |
| 67,063 |
|
| 65,594 | |
| Obligations to Third Party Suppliers |
| 81,820 |
|
| 73,624 | |
| Regulatory Liabilities |
| 84,127 |
|
| 124,722 | |
| Derivative Liabilities |
| 88,218 |
|
| 88,459 | |
| Other Current Liabilities |
| 207,843 |
|
| 153,420 | |
Total Current Liabilities |
| 1,111,346 |
|
| 1,074,190 | ||
|
|
|
|
|
|
|
|
Deferred Credits and Other Liabilities: |
|
|
|
|
| ||
| Accumulated Deferred Income Taxes |
| 1,652,415 |
|
| 1,642,805 | |
| Regulatory Liabilities |
| 82,110 |
|
| 81,298 | |
| Derivative Liabilities |
| 395,038 |
|
| 406,199 | |
| Accrued Pension, SERP and PBOP |
| 272,292 |
|
| 273,854 | |
| Other Long-Term Liabilities |
| 150,396 |
|
| 148,844 | |
Total Deferred Credits and Other Liabilities |
| 2,552,251 |
|
| 2,553,000 | ||
|
|
|
|
|
|
|
|
Capitalization: |
|
|
|
|
| ||
| Long-Term Debt |
| 2,680,123 |
|
| 2,679,951 | |
|
|
|
|
|
|
|
|
| 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 |
| 1,805,626 |
|
| 1,804,869 |
|
| Retained Earnings |
| 1,091,321 |
|
| 1,072,477 |
|
| Accumulated Other Comprehensive Loss |
| (816) |
|
| (931) |
| Common Stockholder's Equity |
| 2,956,483 |
|
| 2,936,767 | |
Total Capitalization |
| 5,752,806 |
|
| 5,732,918 | ||
|
|
|
|
|
|
|
|
Total Liabilities and Capitalization | $ | 9,416,403 |
| $ | 9,360,108 | ||
|
|
|
|
|
|
|
|
The accompanying notes are an integral part of these unaudited condensed financial statements. |
|
|
|
4
THE CONNECTICUT LIGHT AND POWER COMPANY |
|
|
| ||||
CONDENSED STATEMENTS OF INCOME |
|
|
| ||||
(Unaudited) |
|
|
|
|
| ||
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| For the Three Months Ended March 31, | ||||
(Thousands of Dollars) | 2015 |
| 2014 | ||||
|
|
|
|
|
|
|
|
Operating Revenues | $ | 804,917 |
| $ | 734,614 | ||
|
|
|
|
|
|
|
|
Operating Expenses: |
|
|
|
|
| ||
| Purchased Power and Transmission |
| 333,619 |
|
| 281,381 | |
| Operations and Maintenance |
| 117,357 |
|
| 109,514 | |
| Depreciation |
| 52,902 |
|
| 46,130 | |
| Amortization of Regulatory Assets, Net |
| 48,306 |
|
| 29,931 | |
| Energy Efficiency Programs |
| 42,807 |
|
| 42,694 | |
| Taxes Other Than Income Taxes |
| 68,080 |
|
| 66,953 | |
|
| Total Operating Expenses |
| 663,071 |
|
| 576,603 |
Operating Income |
| 141,846 |
|
| 158,011 | ||
|
|
|
|
|
|
|
|
Interest Expense: |
|
|
|
|
| ||
| Interest on Long-Term Debt |
| 33,482 |
|
| 32,908 | |
| Other Interest |
| 3,142 |
|
| 1,335 | |
|
| Interest Expense |
| 36,624 |
|
| 34,243 |
Other Income, Net |
| 2,159 |
|
| 1,072 | ||
Income Before Income Tax Expense |
| 107,381 |
|
| 124,840 | ||
Income Tax Expense |
| 38,147 |
|
| 45,541 | ||
Net Income | $ | 69,234 |
| $ | 79,299 | ||
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
The accompanying notes are an integral part of these unaudited condensed financial statements. | |||||||
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
CONDENSED STATEMENTS OF COMPREHENSIVE INCOME |
|
|
| ||||
(Unaudited) |
|
|
| ||||
|
|
|
|
|
|
|
|
Net Income | $ | 69,234 |
| $ | 79,299 | ||
Other Comprehensive Income, Net of Tax: |
|
|
|
|
| ||
| Qualified Cash Flow Hedging Instruments |
| 111 |
|
| 111 | |
| Changes in Unrealized Gains on Other Securities |
| 4 |
|
| 8 | |
Other Comprehensive Income, Net of Tax |
| 115 |
|
| 119 | ||
Comprehensive Income | $ | 69,349 |
| $ | 79,418 | ||
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
The accompanying notes are an integral part of these unaudited condensed financial statements. |
5
THE CONNECTICUT LIGHT AND POWER COMPANY |
|
| |||||
CONDENSED BALANCE SHEETS |
|
|
|
|
| ||
(Unaudited) |
|
|
|
|
| ||
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| June 30, |
| December 31, | ||
(Thousands of Dollars) | 2014 |
| 2013 | ||||
|
|
|
|
|
|
|
|
LIABILITIES AND CAPITALIZATION |
|
|
|
|
| ||
|
|
|
|
|
|
|
|
Current Liabilities: |
|
|
|
|
| ||
| Notes Payable to NU Parent | $ | 6,400 |
| $ | 287,300 | |
| Long-Term Debt - Current Portion |
| 312,000 |
|
| 150,000 | |
| Accounts Payable |
| 189,171 |
|
| 201,047 | |
| Accounts Payable to Affiliated Companies |
| 44,031 |
|
| 56,531 | |
| Obligations to Third Party Suppliers |
| 59,312 |
|
| 73,914 | |
| Accrued Taxes |
| 52,900 |
|
| 37,186 | |
| Regulatory Liabilities |
| 143,457 |
|
| 93,961 | |
| Derivative Liabilities |
| 85,611 |
|
| 92,233 | |
| Other Current Liabilities |
| 94,204 |
|
| 97,530 | |
Total Current Liabilities |
| 987,086 |
|
| 1,089,702 | ||
|
|
|
|
|
|
|
|
Deferred Credits and Other Liabilities: |
|
|
|
|
| ||
| Accumulated Deferred Income Taxes |
| 1,610,662 |
|
| 1,510,586 | |
| Regulatory Liabilities |
| 86,677 |
|
| 93,757 | |
| Derivative Liabilities |
| 445,342 |
|
| 617,072 | |
| Accrued Pension, SERP and PBOP |
| 66,543 |
|
| 95,895 | |
| Other Long-Term Liabilities |
| 154,001 |
|
| 163,588 | |
Total Deferred Credits and Other Liabilities |
| 2,363,225 |
|
| 2,480,898 | ||
|
|
|
|
|
|
|
|
Capitalization: |
|
|
|
|
| ||
| Long-Term Debt |
| 2,679,591 |
|
| 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 |
| 1,753,668 |
|
| 1,682,047 |
|
| Retained Earnings |
| 989,786 |
|
| 961,482 |
|
| Accumulated Other Comprehensive Loss |
| (1,150) |
|
| (1,387) |
| Common Stockholder's Equity |
| 2,802,656 |
|
| 2,702,494 | |
Total Capitalization |
| 5,598,447 |
|
| 5,409,902 | ||
|
|
|
|
|
|
|
|
Total Liabilities and Capitalization | $ | 8,948,758 |
| $ | 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 CASH FLOWS | |||||||
(Unaudited) | |||||||
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| For the Three Months Ended March 31, | ||||
(Thousands of Dollars) | 2015 |
| 2014 | ||||
|
|
|
|
|
|
|
|
Operating Activities: |
|
|
|
|
| ||
| Net Income | $ | 69,234 |
| $ | 79,299 | |
| Adjustments to Reconcile Net Income to Net Cash Flows Provided by Operating Activities: |
|
|
|
|
| |
|
| Depreciation |
| 52,902 |
|
| 46,130 |
|
| Deferred Income Taxes |
| 19,340 |
|
| 59,334 |
|
| Pension, SERP and PBOP Expense, Net of PBOP Contributions |
| 3,883 |
|
| 4,086 |
|
| Regulatory Underrecoveries, Net |
| (67,393) |
|
| (40,399) |
|
| Amortization of Regulatory Assets, Net |
| 48,306 |
|
| 29,931 |
|
| Other |
| 2,322 |
|
| 4,536 |
| Changes in Current Assets and Liabilities: |
|
|
|
|
| |
|
| Receivables and Unbilled Revenues, Net |
| (124,969) |
|
| (82,833) |
|
| Taxes Receivable/Accrued, Net |
| 158,163 |
|
| 7,015 |
|
| Accounts Payable |
| (20,194) |
|
| (2,872) |
|
| Other Current Assets and Liabilities, Net |
| (7,727) |
|
| (8,730) |
Net Cash Flows Provided by Operating Activities |
| 133,867 |
|
| 95,497 | ||
|
|
|
|
|
|
|
|
Investing Activities: |
|
|
|
|
| ||
| Investments in Property, Plant and Equipment |
| (127,631) |
|
| (107,993) | |
| Other Investing Activities |
| 1,981 |
|
| 1,027 | |
Net Cash Flows Used in Investing Activities |
| (125,650) |
|
| (106,966) | ||
|
|
|
|
|
|
|
|
Financing Activities: |
|
|
|
|
| ||
| Cash Dividends on Common Stock |
| (49,000) |
|
| (42,800) | |
| Cash Dividends on Preferred Stock |
| (1,390) |
|
| (1,390) | |
| Increase in Notes Payable to ES Parent |
| 56,700 |
|
| 64,300 | |
| Other Financing Activities |
| (65) |
|
| (203) | |
Net Cash Flows Provided by Financing Activities |
| 6,245 |
|
| 19,907 | ||
Net Increase in Cash |
| 14,462 |
|
| 8,438 | ||
Cash - Beginning of Period |
| 2,356 |
|
| 7,237 | ||
Cash - End of Period | $ | 16,818 |
| $ | 15,675 | ||
|
|
|
|
|
|
|
|
The accompanying notes are an integral part of these unaudited condensed financial statements. |
6
THE CONNECTICUT LIGHT AND POWER COMPANY |
|
|
|
|
|
|
|
|
| ||||
CONDENSED STATEMENTS OF INCOME |
|
|
|
|
|
|
|
|
| ||||
(Unaudited) |
|
|
|
|
|
|
|
|
|
|
| ||
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| For the Three Months Ended June 30, |
| For the Six Months Ended June 30, | ||||||||
(Thousands of Dollars) | 2014 |
| 2013 |
|
| 2014 |
|
| 2013 | ||||
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating Revenues | $ | 587,324 |
| $ | 569,329 |
| $ | 1,321,938 |
| $ | 1,193,425 | ||
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating Expenses: |
|
|
|
|
|
|
|
|
|
|
| ||
| Purchased Power and Transmission |
| 199,785 |
|
| 184,854 |
|
| 481,165 |
|
| 414,113 | |
| Operations and Maintenance |
| 131,762 |
|
| 123,760 |
|
| 241,276 |
|
| 232,655 | |
| Depreciation |
| 46,581 |
|
| 45,122 |
|
| 92,712 |
|
| 87,570 | |
| Amortization of Regulatory Assets, Net |
| 19,615 |
|
| 463 |
|
| 49,546 |
|
| 11,249 | |
| Energy Efficiency Programs |
| 35,296 |
|
| 20,854 |
|
| 77,991 |
|
| 43,668 | |
| Taxes Other Than Income Taxes |
| 62,159 |
|
| 57,506 |
|
| 129,111 |
|
| 117,697 | |
|
| Total Operating Expenses |
| 495,198 |
|
| 432,559 |
|
| 1,071,801 |
|
| 906,952 |
Operating Income |
| 92,126 |
|
| 136,770 |
|
| 250,137 |
|
| 286,473 | ||
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Interest Expense: |
|
|
|
|
|
|
|
|
|
|
| ||
| Interest on Long-Term Debt |
| 34,639 |
|
| 32,683 |
|
| 67,548 |
|
| 65,318 | |
| Other Interest |
| 2,831 |
|
| 1,301 |
|
| 4,165 |
|
| (1,640) | |
|
| Interest Expense |
| 37,470 |
|
| 33,984 |
|
| 71,713 |
|
| 63,678 |
Other Income, Net |
| 3,130 |
|
| 2,897 |
|
| 4,202 |
|
| 7,084 | ||
Income Before Income Tax Expense |
| 57,786 |
|
| 105,683 |
|
| 182,626 |
|
| 229,879 | ||
Income Tax Expense |
| 20,401 |
|
| 37,826 |
|
| 65,942 |
|
| 77,014 | ||
Net Income | $ | 37,385 |
| $ | 67,857 |
| $ | 116,684 |
| $ | 152,865 | ||
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
The accompanying notes are an integral part of these unaudited condensed financial statements. |
|
|
|
|
|
| |||||||
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
CONDENSED STATEMENTS OF COMPREHENSIVE INCOME |
|
|
|
|
|
|
|
|
| ||||
(Unaudited) |
|
|
|
|
|
|
|
|
| ||||
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net Income | $ | 37,385 |
| $ | 67,857 |
| $ | 116,684 |
| $ | 152,865 | ||
Other Comprehensive Income, Net of Tax: |
|
|
|
|
|
|
|
|
|
|
| ||
| Qualified Cash Flow Hedging Instruments |
| 111 |
|
| 111 |
|
| 222 |
|
| 222 | |
| Changes in Unrealized Gains/(Losses) on Other Securities |
| 7 |
|
| (20) |
|
| 15 |
|
| (26) | |
Other Comprehensive Income, Net of Tax |
| 118 |
|
| 91 |
|
| 237 |
|
| 196 | ||
Comprehensive Income | $ | 37,503 |
| $ | 67,948 |
| $ | 116,921 |
| $ | 153,061 | ||
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
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) | 2015 |
| 2014 | ||||
|
|
|
|
|
|
|
|
ASSETS |
|
|
|
|
| ||
|
|
|
|
|
|
|
|
Current Assets: |
|
|
|
|
| ||
|
| Cash and Cash Equivalents | $ | 17,897 |
| $ | 12,773 |
|
| Receivables, Net |
| 317,410 |
|
| 234,481 |
|
| Accounts Receivable from Affiliated Companies |
| 8,372 |
|
| 40,353 |
|
| Unbilled Revenues |
| 29,228 |
|
| 29,741 |
|
| Taxes Receivable |
| 63,652 |
|
| 144,601 |
|
| Materials and Supplies |
| 87,683 |
|
| 74,179 |
|
| Regulatory Assets |
| 309,547 |
|
| 198,710 |
|
| Prepayments and Other Current Assets |
| 7,885 |
|
| 10,815 |
Total Current Assets |
| 841,674 |
|
| 745,653 | ||
|
|
|
|
|
|
|
|
Property, Plant and Equipment, Net |
| 5,364,311 |
|
| 5,335,436 | ||
|
|
|
|
|
|
|
|
Deferred Debits and Other Assets: |
|
|
|
|
| ||
|
| Regulatory Assets |
| 1,178,738 |
|
| 1,179,100 |
|
| Other Long-Term Assets |
| 55,839 |
|
| 73,051 |
Total Deferred Debits and Other Assets |
| 1,234,577 |
|
| 1,252,151 | ||
|
|
|
|
|
|
|
|
Total Assets | $ | 7,440,562 |
| $ | 7,333,240 | ||
|
|
|
|
|
|
|
|
LIABILITIES AND CAPITALIZATION |
|
|
|
|
| ||
|
|
|
|
|
|
|
|
Current Liabilities: |
|
|
|
|
| ||
| Notes Payable | $ | 215,500 |
| $ | 302,000 | |
| Long-Term Debt - Current Portion |
| 4,700 |
|
| 4,700 | |
| Accounts Payable |
| 233,852 |
|
| 217,311 | |
| Accounts Payable to Affiliated Companies |
| 127,904 |
|
| 63,517 | |
| Obligations to Third Party Suppliers |
| 63,336 |
|
| 34,824 | |
| Renewable Portfolio Standards Compliance Obligations |
| 55,853 |
|
| 35,698 | |
| Accumulated Deferred Income Taxes |
| 111,288 |
|
| 55,136 | |
| Regulatory Liabilities |
| 24,605 |
|
| 49,611 | |
| Other Current Liabilities |
| 116,128 |
|
| 115,991 | |
Total Current Liabilities |
| 953,166 |
|
| 878,788 | ||
|
|
|
|
|
|
|
|
Deferred Credits and Other Liabilities: |
|
|
|
|
| ||
| Accumulated Deferred Income Taxes |
| 1,530,972 |
|
| 1,527,667 | |
| Regulatory Liabilities |
| 268,122 |
|
| 262,738 | |
| Accrued Pension, SERP and PBOP |
| 228,411 |
|
| 235,529 | |
| Other Long-Term Liabilities |
| 126,006 |
|
| 129,279 | |
Total Deferred Credits and Other Liabilities |
| 2,153,511 |
|
| 2,155,213 | ||
|
|
|
|
|
|
|
|
Capitalization: |
|
|
|
|
| ||
| Long-Term Debt |
| 1,792,717 |
|
| 1,792,712 | |
|
|
|
|
|
|
|
|
| Preferred Stock Not Subject to Mandatory Redemption |
| 43,000 |
|
| 43,000 | |
|
|
|
|
|
|
|
|
| Common Stockholder's Equity: |
|
|
|
|
| |
|
| Common Stock |
| - |
|
| - |
|
| Capital Surplus, Paid In |
| 995,378 |
|
| 994,130 |
|
| Retained Earnings |
| 1,502,528 |
|
| 1,468,955 |
|
| Accumulated Other Comprehensive Income |
| 262 |
|
| 442 |
| Common Stockholder's Equity |
| 2,498,168 |
|
| 2,463,527 | |
Total Capitalization |
| 4,333,885 |
|
| 4,299,239 | ||
|
|
|
|
|
|
|
|
Total Liabilities and Capitalization | $ | 7,440,562 |
| $ | 7,333,240 | ||
|
|
|
|
|
|
|
|
The accompanying notes are an integral part of these unaudited condensed consolidated financial statements. |
|
|
|
7
THE CONNECTICUT LIGHT AND POWER COMPANY | ||||||||||||||
CONDENSED STATEMENTS OF CASH FLOWS | ||||||||||||||
NSTAR ELECTRIC COMPANY AND SUBSIDIARY | NSTAR ELECTRIC COMPANY AND SUBSIDIARY |
|
|
|
| |||||||||
CONDENSED CONSOLIDATED STATEMENTS OF INCOME | CONDENSED CONSOLIDATED STATEMENTS OF INCOME |
|
| |||||||||||
(Unaudited) | (Unaudited) | (Unaudited) |
|
|
|
| ||||||||
|
|
|
|
|
|
|
|
|
|
|
|
| ||
|
|
|
|
|
|
|
|
|
|
|
|
| ||
|
|
| For the Six Months Ended June 30, |
|
| For the Three Months Ended March 31, | ||||||||
(Thousands of Dollars) | (Thousands of Dollars) | 2014 |
| 2013 | (Thousands of Dollars) | 2015 |
| 2014 | ||||||
|
|
|
|
|
|
|
|
|
|
|
|
| ||
Operating Revenues | Operating Revenues | $ | 766,808 |
| $ | 666,188 | ||||||||
|
|
|
|
|
|
|
| |||||||
Operating Expenses: | Operating Expenses: |
|
|
|
|
| ||||||||
| Purchased Power and Transmission |
| 401,867 |
|
| 319,082 | ||||||||
| Operations and Maintenance |
| 75,824 |
|
| 85,924 | ||||||||
| Depreciation |
| 48,768 |
|
| 46,626 | ||||||||
| Amortization of Regulatory Assets/(Liabilities), Net |
| (5,565) |
|
| 15,664 | ||||||||
| Energy Efficiency Programs |
| 55,417 |
|
| 48,329 | ||||||||
| Taxes Other Than Income Taxes |
| 30,962 |
|
| 32,151 | ||||||||
|
| Total Operating Expenses |
| 607,273 |
|
| 547,776 | |||||||
Operating Income | Operating Income |
| 159,535 |
|
| 118,412 | ||||||||
|
|
|
|
|
|
|
| |||||||
Interest Expense: | Interest Expense: |
|
|
|
|
| ||||||||
| Interest on Long-Term Debt |
| 18,645 |
|
| 20,756 | ||||||||
| Other Interest |
| 1,801 |
|
| 304 | ||||||||
|
| Interest Expense |
| 20,446 |
|
| 21,060 | |||||||
Other Income/(Loss), Net | Other Income/(Loss), Net |
| 602 |
|
| (31) | ||||||||
Income Before Income Tax Expense | Income Before Income Tax Expense |
| 139,691 |
|
| 97,321 | ||||||||
Income Tax Expense | Income Tax Expense |
| 56,130 |
|
| 39,234 | ||||||||
Net Income | Net Income | $ | 83,561 |
| $ | 58,087 | ||||||||
|
|
|
|
|
|
|
| |||||||
|
|
|
|
|
|
|
| |||||||
|
|
|
|
|
|
| ||||||||
The accompanying notes are an integral part of these unaudited condensed consolidated financial statements. | The accompanying notes are an integral part of these unaudited condensed consolidated financial statements. | |||||||||||||
|
|
|
|
|
|
|
| |||||||
|
|
|
|
|
|
|
| |||||||
|
|
|
|
|
|
|
| |||||||
|
|
|
|
|
|
|
| |||||||
|
|
|
|
|
|
|
| |||||||
CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME | CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME |
|
|
| ||||||||||
(Unaudited) | (Unaudited) |
|
| |||||||||||
|
|
|
|
|
|
|
| |||||||
Net Income | Net Income | $ | 83,561 |
| $ | 58,087 | ||||||||
Other Comprehensive Income/(Loss), Net of Tax: | Other Comprehensive Income/(Loss), Net of Tax: |
|
|
|
| |||||||||
| Changes in Funded Status of SERP Benefit Plan |
| (180) |
|
| - | ||||||||
Other Comprehensive Income/(Loss), Net of Tax | Other Comprehensive Income/(Loss), Net of Tax |
| (180) |
|
| - | ||||||||
Comprehensive Income | Comprehensive Income | $ | 83,381 |
| $ | 58,087 | ||||||||
|
|
|
|
|
|
| ||||||||
|
|
|
|
|
|
| ||||||||
|
|
|
|
|
|
| ||||||||
The accompanying notes are an integral part of these unaudited condensed consolidated financial statements. | The accompanying notes are an integral part of these unaudited condensed consolidated financial statements. |
Operating Activities: |
|
|
|
|
| ||
| Net Income | $ | 116,684 |
| $ | 152,865 | |
| Adjustments to Reconcile Net Income to Net Cash Flows Provided by Operating Activities: |
| 92,712 |
|
| 87,570 | |
|
| Depreciation |
|
|
|
|
|
|
| Deferred Income Taxes |
| 43,253 |
|
| 99,045 |
|
| Pension, SERP and PBOP Expense, Net of PBOP Contributions |
| 5,973 |
|
| 13,826 |
|
| Regulatory Over/(Under) Recoveries, Net |
| 18,156 |
|
| (36,902) |
|
| Amortization of Regulatory Assets, Net |
| 49,546 |
|
| 11,249 |
|
| Proceeds from DOE Damages Claim |
| 65,370 |
|
| - |
|
| Other |
| (3,428) |
|
| (13,476) |
| Changes in Current Assets and Liabilities: |
|
|
|
|
| |
|
| Receivables and Unbilled Revenues, Net |
| (129,209) |
|
| (33,976) |
|
| Taxes Receivable/Accrued, Net |
| 27,679 |
|
| (14,081) |
|
| Accounts Payable |
| (26,995) |
|
| (95,487) |
|
| Other Current Assets and Liabilities, Net |
| 15,705 |
|
| 7,548 |
Net Cash Flows Provided by Operating Activities |
| 275,446 |
|
| 178,181 | ||
|
|
|
|
|
|
|
|
Investing Activities: |
|
|
|
|
| ||
| Investments in Property, Plant and Equipment |
| (221,365) |
|
| (184,875) | |
| Other Investing Activities |
| 1,575 |
|
| 884 | |
Net Cash Flows Used in Investing Activities |
| (219,790) |
|
| (183,991) | ||
|
|
|
|
|
|
|
|
Financing Activities: |
|
|
|
|
| ||
| Cash Dividends on Common Stock |
| (85,600) |
|
| (76,000) | |
| Cash Dividends on Preferred Stock |
| (2,779) |
|
| (2,779) | |
| Issuance of Long Term Debt |
| 250,000 |
|
| 400,000 | |
| Decrease in Notes Payable to NU Parent |
| (280,900) |
|
| (215,800) | |
| Capital Contribution from NU Parent |
| 70,000 |
|
| - | |
| Decrease in Short-Term Debt |
| - |
|
| (89,000) | |
| Other Financing Activities |
| (3,128) |
|
| (6,345) | |
Net Cash Flows (Used in)/Provided by Financing Activities |
| (52,407) |
|
| 10,076 | ||
Net Increase in Cash |
| 3,249 |
|
| 4,266 | ||
Cash - Beginning of Period |
| 7,237 |
|
| 1 | ||
Cash - End of Period | $ | 10,486 |
| $ | 4,267 | ||
|
|
|
|
|
|
|
|
The accompanying notes are an integral part of these unaudited condensed financial statements. |
8
NSTAR ELECTRIC COMPANY AND SUBSIDIARY |
|
|
|
|
| |
CONDENSED CONSOLIDATED BALANCE SHEETS |
|
|
|
|
| |
(Unaudited) |
|
|
|
|
| |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| June 30, |
| December 31, | ||
(Thousands of Dollars) | 2014 |
| 2013 | |||
|
|
|
|
|
|
|
ASSETS |
|
|
|
|
| |
|
|
|
|
|
|
|
Current Assets: |
|
|
|
|
| |
| Cash and Cash Equivalents | $ | 12,975 |
| $ | 8,021 |
| Receivables, Net |
| 230,039 |
|
| 209,711 |
| Accounts Receivable from Affiliated Companies |
| - |
|
| 27,264 |
| Unbilled Revenues |
| 40,514 |
|
| 41,368 |
| Materials and Supplies |
| 51,635 |
|
| 44,236 |
| Regulatory Assets |
| 178,640 |
|
| 204,144 |
| Prepayments and Other Current Assets |
| 1,012 |
|
| 36,710 |
Total Current Assets |
| 514,815 |
|
| 571,454 | |
|
|
|
|
|
|
|
Property, Plant and Equipment, Net |
| 5,147,239 |
|
| 5,043,887 | |
|
|
|
|
|
|
|
Deferred Debits and Other Assets: |
|
|
|
|
| |
| Regulatory Assets |
| 1,020,990 |
|
| 1,235,156 |
| Other Long-Term Assets |
| 64,963 |
|
| 60,624 |
Total Deferred Debits and Other Assets |
| 1,085,953 |
|
| 1,295,780 | |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total Assets | $ | 6,748,007 |
| $ | 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 CASH FLOWS | |||||||
(Unaudited) | |||||||
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| For the Three Months Ended March 31, | ||||
(Thousands of Dollars) | 2015 |
| 2014 | ||||
|
|
|
|
|
|
|
|
Operating Activities: |
|
|
|
|
| ||
| Net Income | $ | 83,561 |
| $ | 58,087 | |
| Adjustments to Reconcile Net Income to Net Cash Flows Provided by Operating Activities: |
|
|
|
|
| |
|
| Depreciation |
| 48,768 |
|
| 46,626 |
|
| Deferred Income Taxes |
| 41,297 |
|
| 1,585 |
|
| Pension, SERP and PBOP Expense, Net of Contributions |
| 1,164 |
|
| (4,908) |
|
| Regulatory Over/(Under) Recoveries, Net |
| (103,142) |
|
| 6,423 |
|
| Amortization of Regulatory Assets/(Liabilities), Net |
| (5,565) |
|
| 15,664 |
|
| Bad Debt Expense |
| 8,049 |
|
| 6,096 |
|
| Other |
| (21,885) |
|
| (15,538) |
| Changes in Current Assets and Liabilities: |
|
|
|
|
| |
|
| Receivables and Unbilled Revenues, Net |
| (90,465) |
|
| (14,348) |
|
| Materials and Supplies |
| (13,504) |
|
| (3,606) |
|
| Taxes Receivable/Accrued, Net |
| 96,319 |
|
| 21,504 |
|
| Accounts Payable |
| 29,210 |
|
| 86,309 |
|
| Accounts Receivable from/Payable to Affiliates, Net |
| 96,368 |
|
| (43,654) |
|
| Other Current Assets and Liabilities, Net |
| 51,157 |
|
| 31,112 |
Net Cash Flows Provided by Operating Activities |
| 221,332 |
|
| 191,352 | ||
|
|
|
|
|
|
|
|
Investing Activities: |
|
|
|
|
| ||
| Investments in Property, Plant and Equipment |
| (79,776) |
|
| (94,957) | |
| Other Investing Activities |
| 53 |
|
| (489) | |
Net Cash Flows Used in Investing Activities |
| (79,723) |
|
| (95,446) | ||
|
|
|
|
|
|
|
|
Financing Activities: |
|
|
|
|
| ||
| Cash Dividends on Common Stock |
| (49,500) |
|
| (253,000) | |
| Cash Dividends on Preferred Stock |
| (490) |
|
| (490) | |
| Decrease in Notes Payable |
| (86,500) |
|
| (103,500) | |
| Issuance of Long-Term Debt |
| - |
|
| 300,000 | |
| Other Financing Activities |
| 5 |
|
| (4,902) | |
Net Cash Flows Used in Financing Activities |
| (136,485) |
|
| (61,892) | ||
Net Increase in Cash and Cash Equivalents |
| 5,124 |
|
| 34,014 | ||
Cash and Cash Equivalents - Beginning of Period |
| 12,773 |
|
| 8,021 | ||
Cash and Cash Equivalents - End of Period | $ | 17,897 |
| $ | 42,035 | ||
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
The accompanying notes are an integral part of these unaudited condensed consolidated financial statements. |
9
NSTAR ELECTRIC COMPANY AND SUBSIDIARY |
|
|
|
| ||||||||||
PUBLIC SERVICE COMPANY OF NEW HAMPSHIRE AND SUBSIDIARY | PUBLIC SERVICE COMPANY OF NEW HAMPSHIRE AND SUBSIDIARY |
|
|
|
| |||||||||
CONDENSED CONSOLIDATED BALANCE SHEETS | CONDENSED CONSOLIDATED BALANCE SHEETS |
|
|
|
| CONDENSED CONSOLIDATED BALANCE SHEETS |
|
|
|
| ||||
(Unaudited) | (Unaudited) |
|
|
|
| (Unaudited) |
|
|
|
| ||||
|
|
|
|
|
|
|
|
|
|
|
|
| ||
|
|
|
|
|
|
|
|
|
|
|
|
|
| |
|
|
| June 30, |
| December 31, |
|
| March 31, |
| December 31, | ||||
(Thousands of Dollars) | (Thousands of Dollars) | 2014 |
| 2013 | (Thousands of Dollars) | 2015 |
| 2014 | ||||||
|
|
|
|
|
|
|
| |||||||
ASSETS | ASSETS |
|
|
|
|
| ||||||||
|
|
|
|
|
|
|
| |||||||
Current Assets: | Current Assets: |
|
|
|
|
| ||||||||
|
| Cash | $ | 5,149 |
| $ | 489 | |||||||
|
| Receivables, Net |
| 99,748 |
| 80,151 | ||||||||
|
| Accounts Receivable from Affiliated Companies |
| 9,917 |
| 3,194 | ||||||||
|
| Unbilled Revenues |
| 43,359 |
| 40,181 | ||||||||
|
| Taxes Receivable |
| 31,147 |
| 14,571 | ||||||||
|
| Fuel, Materials and Supplies |
| 113,566 |
| 148,139 | ||||||||
|
| Regulatory Assets |
| 99,994 |
| 111,705 | ||||||||
|
| Prepayments and Other Current Assets |
| 13,520 |
|
| 27,821 | |||||||
Total Current Assets | Total Current Assets |
| 416,400 |
|
| 426,251 | ||||||||
|
|
|
|
|
|
| ||||||||
Property, Plant and Equipment, Net | Property, Plant and Equipment, Net |
| 2,666,312 |
|
| 2,635,844 | ||||||||
|
|
|
|
|
|
| ||||||||
Deferred Debits and Other Assets: | Deferred Debits and Other Assets: |
|
|
|
| |||||||||
|
| Regulatory Assets |
| 287,203 |
| 293,115 | ||||||||
|
| Other Long-Term Assets |
| 33,517 |
|
| 39,228 | |||||||
Total Deferred Debits and Other Assets | Total Deferred Debits and Other Assets |
| 320,720 |
|
| 332,343 | ||||||||
|
|
|
|
|
|
| ||||||||
Total Assets | Total Assets | $ | 3,403,432 |
| $ | 3,394,438 | ||||||||
|
|
|
|
|
|
|
|
|
|
|
|
| ||
LIABILITIES AND CAPITALIZATION | LIABILITIES AND CAPITALIZATION |
|
|
|
| LIABILITIES AND CAPITALIZATION |
|
|
|
|
| |||
|
|
|
|
|
|
|
|
|
|
|
|
|
| |
Current Liabilities: | Current Liabilities: |
|
|
|
| Current Liabilities: |
|
|
|
|
| |||
| Notes Payable | $ | 194,500 |
| $ | 103,500 | Notes Payable to ES Parent | $ | 82,000 |
| $ | 90,500 | ||
| Long-Term Debt - Current Portion |
| 4,700 |
| 301,650 | Accounts Payable |
| 62,513 |
| 93,349 | ||||
| Accounts Payable |
| 150,615 |
| 207,559 | Accounts Payable to Affiliated Companies |
| 42,670 |
| 33,734 | ||||
| Accounts Payable to Affiliated Companies |
| 69,949 |
| 75,707 | Regulatory Liabilities |
| 16,102 |
| 16,044 | ||||
| Accrued Taxes |
| 44,308 |
| 7,946 | Accumulated Deferred Income Taxes |
| 34,217 |
| 36,164 | ||||
| Accumulated Deferred Income Taxes |
| 54,434 |
| 50,128 | Other Current Liabilities |
| 39,777 |
|
| 38,969 | |||
| Regulatory Liabilities |
| 89,161 |
| 53,958 | |||||||||
| Other Current Liabilities |
| 109,048 |
|
| 110,464 | ||||||||
Total Current Liabilities | Total Current Liabilities |
| 716,715 |
|
| 910,912 | Total Current Liabilities |
| 277,279 |
|
| 308,760 | ||
|
|
|
|
|
|
|
|
|
|
|
|
| ||
Deferred Credits and Other Liabilities: | Deferred Credits and Other Liabilities: |
|
|
|
| Deferred Credits and Other Liabilities: |
|
|
|
| ||||
| Accumulated Deferred Income Taxes |
| 1,377,432 |
| 1,466,835 | |||||||||
| Regulatory Liabilities |
| 260,480 |
| 253,108 | Accumulated Deferred Income Taxes |
| 627,450 |
| 587,292 | ||||
| Accrued Pension, SERP and PBOP |
| 150,151 |
| 118,010 | Regulatory Liabilities |
| 51,897 |
| 51,372 | ||||
| Payable to Affiliated Companies |
| - |
| 64,172 | Accrued Pension, SERP and PBOP |
| 91,847 |
| 93,243 | ||||
| Other Long-Term Liabilities |
| 129,837 |
|
| 142,214 | Other Long-Term Liabilities |
| 45,088 |
|
| 50,155 | ||
Total Deferred Credits and Other Liabilities | Total Deferred Credits and Other Liabilities |
| 1,917,900 |
|
| 2,044,339 | Total Deferred Credits and Other Liabilities |
| 816,282 |
|
| 782,062 | ||
|
|
|
|
|
|
|
|
|
|
|
|
| ||
Capitalization: | Capitalization: |
|
|
|
| Capitalization: |
|
|
|
| ||||
| Long-Term Debt |
| 1,792,702 |
|
| 1,499,417 | Long-Term Debt |
| 1,076,303 |
|
| 1,076,286 | ||
|
|
|
|
|
|
|
|
|
|
|
|
| ||
| Preferred Stock Not Subject to Mandatory Redemption |
| 43,000 |
|
| 43,000 | Common Stockholder's Equity: |
|
|
|
| |||
|
|
|
|
|
|
|
| Common Stock |
| - |
| - | ||
| Common Stockholder's Equity: |
|
|
|
|
| Capital Surplus, Paid In |
| 748,634 |
| 748,240 | |||
|
| Common Stock |
| - |
| - |
| Retained Earnings |
| 492,004 |
| 486,459 | ||
|
| Capital Surplus, Paid In |
| 992,625 |
| 992,625 |
| Accumulated Other Comprehensive Loss |
| (7,070) |
|
| (7,369) | |
|
| Retained Earnings |
| 1,285,065 |
|
| 1,420,828 | Common Stockholder's Equity |
| 1,233,568 |
|
| 1,227,330 | |
| Common Stockholder's Equity |
| 2,277,690 |
|
| 2,413,453 | ||||||||
Total Capitalization | Total Capitalization |
| 4,113,392 |
|
| 3,955,870 | Total Capitalization |
| 2,309,871 |
|
| 2,303,616 | ||
|
|
|
|
|
|
|
|
|
|
|
|
| ||
Total Liabilities and Capitalization | Total Liabilities and Capitalization | $ | 6,748,007 |
| $ | 6,911,121 | Total Liabilities and Capitalization | $ | 3,403,432 |
| $ | 3,394,438 | ||
|
|
|
|
|
|
|
|
|
|
|
|
|
| |
The accompanying notes are an integral part of these unaudited condensed consolidated financial statements. | The accompanying notes are an integral part of these unaudited condensed consolidated financial statements. |
| ||||||||||||
|
|
|
|
|
|
|
|
|
|
|
|
|
| |
|
|
|
|
|
|
| ||||||||
The accompanying notes are an integral part of these unaudited condensed consolidated financial statements. |
|
|
10
NSTAR ELECTRIC COMPANY AND SUBSIDIARY |
|
|
|
|
|
|
|
|
| |||||||||||
PUBLIC SERVICE COMPANY OF NEW HAMPSHIRE AND SUBSIDIARY | PUBLIC SERVICE COMPANY OF NEW HAMPSHIRE AND SUBSIDIARY | |||||||||||||||||||
CONDENSED CONSOLIDATED STATEMENTS OF INCOME | CONDENSED CONSOLIDATED STATEMENTS OF INCOME |
|
|
|
|
|
|
| CONDENSED CONSOLIDATED STATEMENTS OF INCOME |
|
| |||||||||
(Unaudited) | (Unaudited) |
|
|
|
|
|
|
|
|
| (Unaudited) |
|
|
|
| |||||
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| |||
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| ||
|
|
| For the Three Months Ended June 30, |
| For the Six Months Ended June 30, |
|
| For the Three Months Ended March 31, | ||||||||||||
(Thousands of Dollars) | (Thousands of Dollars) | 2014 |
| 2013 |
|
| 2014 |
| 2013 | (Thousands of Dollars) | 2015 |
| 2014 | |||||||
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| ||
Operating Revenues | Operating Revenues | $ | 561,513 |
| $ | 570,420 |
| $ | 1,227,701 |
| $ | 1,162,677 | Operating Revenues | $ | 284,847 |
| $ | 299,833 | ||
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| ||
Operating Expenses: | Operating Expenses: |
|
|
|
|
|
|
|
|
|
| Operating Expenses: |
|
|
|
| ||||
| Purchased Power and Transmission |
| 242,907 |
|
| 189,843 |
|
| 561,989 |
| 403,896 | Purchased Power, Fuel and Transmission |
| 99,579 |
| 115,246 | ||||
| Operations and Maintenance |
| 78,981 |
|
| 87,891 |
|
| 164,905 |
| 180,192 | Operations and Maintenance |
| 58,428 |
| 62,212 | ||||
| Depreciation |
| 46,915 |
|
| 45,441 |
|
| 93,540 |
| 90,882 | Depreciation |
| 25,646 |
| 24,215 | ||||
| Amortization of Regulatory Assets/(Liabilities), Net |
| (1,517) |
|
| 53,554 |
|
| 14,147 |
| 100,548 | Amortization of Regulatory Assets, Net |
| 15,132 |
| 12,562 | ||||
| Amortization of Rate Reduction Bonds |
| - |
|
| - |
|
| - |
| 15,054 | Energy Efficiency Programs |
| 3,772 |
| 3,839 | ||||
| Energy Efficiency Programs |
| 40,255 |
|
| 50,679 |
|
| 88,584 |
| 102,382 | Taxes Other Than Income Taxes |
| 19,079 |
|
| 17,715 | |||
| Taxes Other Than Income Taxes |
| 32,458 |
|
| 30,491 |
|
| 64,610 |
|
| 62,665 |
| Total Operating Expenses |
| 221,636 |
|
| 235,789 | |
|
| Total Operating Expenses |
| 439,999 |
|
| 457,899 |
|
| 987,775 |
|
| 955,619 | |||||||
Operating Income | Operating Income |
| 121,514 |
|
| 112,521 |
|
| 239,926 |
| 207,058 | Operating Income |
| 63,211 |
| 64,044 | ||||
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| ||
Interest Expense: | Interest Expense: |
|
|
|
|
|
|
|
|
|
| Interest Expense: |
|
|
|
| ||||
| Interest on Long-Term Debt |
| 19,732 |
|
| 19,809 |
|
| 40,489 |
| 39,401 | Interest on Long-Term Debt |
| 11,399 |
| 11,526 | ||||
| Other Interest |
| 960 |
|
| (2,620) |
|
| 1,263 |
|
| (6,288) | Other Interest |
| (127) |
|
| 445 | ||
|
| Interest Expense |
| 20,692 |
|
| 17,189 |
|
| 41,752 |
| 33,113 |
| Interest Expense |
| 11,272 |
| 11,971 | ||
Other Income/(Loss), Net |
| (246) |
|
| 375 |
|
| (277) |
|
| 1,149 | |||||||||
Other Income, Net | Other Income, Net |
| 382 |
|
| 265 | ||||||||||||||
Income Before Income Tax Expense | Income Before Income Tax Expense |
| 100,576 |
|
| 95,707 |
|
| 197,897 |
| 175,094 | Income Before Income Tax Expense |
| 52,321 |
| 52,338 | ||||
Income Tax Expense | Income Tax Expense |
| 40,447 |
|
| 37,676 |
|
| 79,681 |
|
| 68,941 | Income Tax Expense |
| 20,276 |
|
| 19,700 | ||
Net Income | Net Income | $ | 60,129 |
| $ | 58,031 |
| $ | 118,216 |
| $ | 106,153 | Net Income | $ | 32,045 |
| $ | 32,638 | ||
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| ||
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| |||
The accompanying notes are an integral part of these unaudited condensed consolidated financial statements. | The accompanying notes are an integral part of these unaudited condensed consolidated financial statements. |
|
|
|
|
| The accompanying notes are an integral part of these unaudited condensed consolidated financial statements. | |||||||||||||
|
|
|
|
|
|
| ||||||||||||||
|
|
|
|
|
|
| ||||||||||||||
|
|
|
|
|
|
| ||||||||||||||
|
|
|
|
|
|
| ||||||||||||||
|
|
|
|
|
|
| ||||||||||||||
CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME | CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME | |||||||||||||||||||
(Unaudited) | (Unaudited) |
|
| |||||||||||||||||
|
|
|
|
|
|
| ||||||||||||||
Net Income | Net Income | $ | 32,045 |
| $ | 32,638 | ||||||||||||||
Other Comprehensive Income, Net of Tax: | Other Comprehensive Income, Net of Tax: |
|
|
|
|
| ||||||||||||||
| Qualified Cash Flow Hedging Instruments |
| 291 |
|
| 290 | ||||||||||||||
| Changes in Unrealized Gains on Other Securities |
| 8 |
|
| 14 | ||||||||||||||
Other Comprehensive Income, Net of Tax | Other Comprehensive Income, Net of Tax |
| 299 |
|
| 304 | ||||||||||||||
Comprehensive Income | Comprehensive Income | $ | 32,344 |
| $ | 32,942 | ||||||||||||||
|
|
|
|
|
|
|
| |||||||||||||
|
|
|
|
|
|
|
| |||||||||||||
|
|
|
|
|
|
|
| |||||||||||||
The accompanying notes are an integral part of these unaudited condensed consolidated financial statements. | The accompanying notes are an integral part of these unaudited condensed consolidated financial statements. |
11
NSTAR ELECTRIC COMPANY AND SUBSIDIARY | |||||||
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS | |||||||
(Unaudited) | |||||||
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| For the Six Months Ended June 30, | ||||
(Thousands of Dollars) | 2014 |
| 2013 | ||||
|
|
|
|
|
|
|
|
Operating Activities: |
|
|
|
| ||||||||||
PUBLIC SERVICE COMPANY OF NEW HAMPSHIRE AND SUBSIDIARY | PUBLIC SERVICE COMPANY OF NEW HAMPSHIRE AND SUBSIDIARY | |||||||||||||
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS | CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS | |||||||||||||
(Unaudited) | (Unaudited) | |||||||||||||
| Net Income | $ | 118,216 |
| $ | 106,153 |
|
|
|
|
|
| ||
| Adjustments to Reconcile Net Income to Net Cash Flows Provided by Operating Activities |
|
|
|
|
|
|
|
|
|
|
| ||
|
| Depreciation |
| 93,540 |
|
| 90,882 |
|
| For the Three Months Ended March 31, | ||||
(Thousands of Dollars) | (Thousands of Dollars) | 2015 |
| 2014 | ||||||||||
|
| Deferred Income Taxes |
| (21,724) |
|
| 28,750 |
|
|
|
|
|
| |
|
| Pension and PBOP Expense, Net of Contributions |
| (8,281) |
|
| (5,139) | |||||||
Operating Activities: | Operating Activities: |
|
|
|
| |||||||||
|
| Regulatory Over/(Under) Recoveries, Net |
| 63,955 |
|
| (33,901) | Net Income | $ | 32,045 |
| $ | 32,638 | |
|
| Amortization of Regulatory Assets, Net |
| 14,147 |
|
| 100,548 | Adjustments to Reconcile Net Income to Net Cash Flows Provided by Operating Activities: |
|
|
|
| ||
|
| Amortization of Rate Reduction Bonds |
| - |
|
| 15,054 |
| Depreciation |
| 25,646 |
| 24,215 | |
|
| Proceeds from DOE Damages Claim |
| 29,113 |
|
| - |
| Deferred Income Taxes |
| 38,767 |
| 33,667 | |
|
| Bad Debt Expense |
| 12,272 |
|
| 11,307 |
| Regulatory Over/(Under) Recoveries, Net |
| (288) |
| 6,827 | |
|
| Other |
| (29,142) |
|
| (47,574) |
| Amortization of Regulatory Assets, Net |
| 15,132 |
| 12,562 | |
| Changes in Current Assets and Liabilities: |
|
|
|
|
|
| Other |
| 2,999 |
| 4,660 | ||
|
| Receivables and Unbilled Revenues, Net |
| (31,746) |
|
| (60,174) | Changes in Current Assets and Liabilities: |
|
|
|
| ||
|
| Materials and Supplies |
| (7,399) |
|
| 3,294 |
| Receivables and Unbilled Revenues, Net |
| (31,556) |
| (14,268) | |
|
| Taxes Receivable/Accrued, Net |
| 65,692 |
|
| (39,813) |
| Fuel, Materials and Supplies |
| 34,572 |
| 34,326 | |
|
| Accounts Payable |
| (21,511) |
|
| (8,686) |
| Taxes Receivable/Accrued, Net |
| (16,576) |
| (30,254) | |
|
| Accounts Receivable from/Payable to Affiliates, Net |
| 107,363 |
|
| (57,369) |
| Accounts Payable |
| (4,285) |
| 3,403 | |
|
| Other Current Assets and Liabilities, Net |
| 3,158 |
|
| (11,702) |
| Other Current Assets and Liabilities, Net |
| 17,468 |
|
| 21,505 |
Net Cash Flows Provided by Operating Activities | Net Cash Flows Provided by Operating Activities |
| 387,653 |
|
| 91,630 | Net Cash Flows Provided by Operating Activities |
| 113,924 |
|
| 129,281 | ||
|
|
|
|
|
|
|
|
|
|
|
|
|
| |
Investing Activities: | Investing Activities: |
|
|
|
|
| Investing Activities: |
|
|
|
| |||
| Investments in Property, Plant and Equipment |
| (213,508) |
|
| (207,380) | Investments in Property, Plant and Equipment |
| (71,905) |
| (61,864) | |||
| Decrease in Special Deposits |
| 581 |
|
| 38,429 | Other Investing Activities |
| (2,277) |
|
| (76) | ||
| Other Investing Activities |
| (5) |
|
| 77 | ||||||||
Net Cash Flows Used in Investing Activities | Net Cash Flows Used in Investing Activities |
| (212,932) |
|
| (168,874) | Net Cash Flows Used in Investing Activities |
| (74,182) |
|
| (61,940) | ||
|
|
|
|
|
|
|
|
|
|
|
|
|
| |
Financing Activities: | Financing Activities: |
|
|
|
|
| Financing Activities: |
|
|
|
| |||
| Cash Dividends on Common Stock |
| (253,000) |
|
| (56,000) | Cash Dividends on Common Stock |
| (26,500) |
| (16,500) | |||
| Cash Dividends on Preferred Stock |
| (980) |
|
| (1,143) | Decrease in Notes Payable to ES Parent |
| (8,500) |
| (46,600) | |||
| Increase/(Decrease) in Notes Payable |
| 91,000 |
|
| (23,000) | Other Financing Activities |
| (82) |
|
| (87) | ||
| Issuance of Long-Term Debt |
| 300,000 |
|
| 200,000 | ||||||||
| Retirements of Long-Term Debt |
| (301,650) |
|
| (1,650) | ||||||||
| Retirements of Rate Reduction Bonds |
| - |
|
| (43,493) | ||||||||
| Other Financing Activities |
| (5,137) |
|
| - | ||||||||
Net Cash Flows (Used in)/Provided by Financing Activities |
| (169,767) |
|
| 74,714 | |||||||||
Net Increase/(Decrease) in Cash and Cash Equivalents |
| 4,954 |
|
| (2,530) | |||||||||
Cash and Cash Equivalents - Beginning of Period |
| 8,021 |
|
| 13,695 | |||||||||
Cash and Cash Equivalents - End of Period | $ | 12,975 |
| $ | 11,165 | |||||||||
Net Cash Flows Used in Financing Activities | Net Cash Flows Used in Financing Activities |
| (35,082) |
|
| (63,187) | ||||||||
Net Increase in Cash | Net Increase in Cash |
| 4,660 |
| 4,154 | |||||||||
Cash - Beginning of Period | Cash - Beginning of Period |
| 489 |
|
| 130 | ||||||||
Cash - End of Period | Cash - End of Period | $ | 5,149 |
| $ | 4,284 | ||||||||
|
|
|
|
|
|
|
|
|
|
|
|
| ||
|
|
|
|
|
|
|
|
|
|
|
|
| ||
|
|
|
|
|
|
|
|
|
|
|
|
| ||
The accompanying notes are an integral part of these unaudited condensed consolidated financial statements. | The accompanying notes are an integral part of these unaudited condensed consolidated financial statements. | The accompanying notes are an integral part of these unaudited condensed consolidated financial statements. |
12
PUBLIC SERVICE COMPANY OF NEW HAMPSHIRE AND SUBSIDIARY |
|
|
|
| |||||||||
CONDENSED CONSOLIDATED BALANCE SHEETS |
|
|
|
| |||||||||
WESTERN MASSACHUSETTS ELECTRIC COMPANY | WESTERN MASSACHUSETTS ELECTRIC COMPANY |
|
|
|
| ||||||||
CONDENSED BALANCE SHEETS | CONDENSED BALANCE SHEETS |
|
|
|
| ||||||||
(Unaudited) | (Unaudited) |
|
|
|
| (Unaudited) |
|
|
|
| |||
|
|
|
|
|
|
|
|
|
|
|
| ||
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| June 30, |
| December 31, |
|
| March 31, |
| December 31, | ||||
(Thousands of Dollars) | (Thousands of Dollars) | 2014 |
| 2013 | (Thousands of Dollars) | 2015 |
| 2014 | |||||
|
|
|
|
|
|
|
|
|
|
|
|
|
|
ASSETS | ASSETS |
|
|
|
|
| ASSETS |
|
|
|
|
| |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Current Assets: | Current Assets: |
|
|
|
|
| Current Assets: |
|
|
|
|
| |
| Cash | $ | 337 |
| $ | 130 |
| Cash | $ | 2,045 |
| $ | - |
| Receivables, Net |
| 69,646 |
| 76,331 |
| Receivables, Net |
| 72,366 |
| 51,066 | ||
| Accounts Receivable from Affiliated Companies |
| 54 |
| 90 |
| Accounts Receivable from Affiliated Companies |
| 8,726 |
| 7,851 | ||
| Unbilled Revenues |
| 36,971 |
| 38,344 |
| Unbilled Revenues |
| 18,186 |
| 15,146 | ||
| Taxes Receivable |
| 45,957 |
| 2,180 |
| Taxes Receivable |
| 18,062 |
| 18,126 | ||
| Fuel, Materials and Supplies |
| 120,723 |
| 128,736 |
| Regulatory Assets |
| 66,706 |
| 51,923 | ||
| Regulatory Assets |
| 95,270 |
| 92,194 |
| Marketable Securities |
| 33,183 |
| 28,658 | ||
| Prepayments and Other Current Assets |
| 21,770 |
|
| 21,920 |
| Prepayments and Other Current Assets |
| 6,431 |
|
| 7,607 |
Total Current Assets | Total Current Assets |
| 390,728 |
|
| 359,925 | Total Current Assets |
| 225,705 |
|
| 180,377 | |
|
|
|
|
|
|
|
|
|
|
|
|
| |
Property, Plant and Equipment, Net | Property, Plant and Equipment, Net |
| 2,519,921 |
|
| 2,467,556 | Property, Plant and Equipment, Net |
| 1,483,895 |
|
| 1,461,321 | |
|
|
|
|
|
|
|
|
|
|
|
|
| |
Deferred Debits and Other Assets: | Deferred Debits and Other Assets: |
|
|
|
| Deferred Debits and Other Assets: |
|
|
|
|
| ||
| Regulatory Assets |
| 187,592 |
| 219,346 |
| Regulatory Assets |
| 137,894 |
| 146,307 | ||
| Other Long-Term Assets |
| 53,779 |
|
| 39,891 |
| Marketable Securities |
| 25,027 |
| 29,452 | |
|
| Other Long-Term Assets |
| 22,726 |
|
| 22,018 | ||||||
Total Deferred Debits and Other Assets | Total Deferred Debits and Other Assets |
| 241,371 |
|
| 259,237 | Total Deferred Debits and Other Assets |
| 185,647 |
|
| 197,777 | |
|
|
|
|
|
|
|
| ||||||
Total Assets | Total Assets | $ | 1,895,247 |
| $ | 1,839,475 | |||||||
|
|
|
|
|
|
|
| ||||||
LIABILITIES AND CAPITALIZATION | LIABILITIES AND CAPITALIZATION |
|
|
|
|
| |||||||
|
|
|
|
|
|
|
| ||||||
Current Liabilities: | Current Liabilities: |
|
|
|
|
| |||||||
|
|
|
|
|
| Notes Payable to ES Parent | $ | 70,500 |
| $ | 21,400 | ||
|
|
|
|
|
| Long-Term Debt - Current Portion |
| 50,000 |
|
| 50,000 | ||
|
|
|
|
|
| Accounts Payable |
| 40,665 |
|
| 53,732 | ||
Total Assets | $ | 3,152,020 |
| $ | 3,086,718 | ||||||||
|
|
|
|
|
|
| Accounts Payable to Affiliated Companies |
| 21,634 |
|
| 14,328 | |
|
|
|
|
|
|
| Regulatory Liabilities |
| 22,289 |
| 22,486 | ||
|
|
|
|
|
|
| Accumulated Deferred Income Taxes |
| 24,607 |
| 18,089 | ||
The accompanying notes are an integral part of these unaudited condensed consolidated financial statements. |
| ||||||||||||
|
|
|
|
|
| Other Current Liabilities |
| 22,958 |
|
| 24,080 | ||
Total Current Liabilities | Total Current Liabilities |
| 252,653 |
|
| 204,115 | |||||||
|
|
|
|
|
|
|
| ||||||
Deferred Credits and Other Liabilities: | Deferred Credits and Other Liabilities: |
|
|
|
|
| |||||||
| Accumulated Deferred Income Taxes |
| 419,043 |
|
| 416,822 | |||||||
| Regulatory Liabilities |
| 12,673 |
|
| 10,835 | |||||||
| Accrued Pension, SERP and PBOP |
| 16,505 |
| 17,705 | ||||||||
| Other Long-Term Liabilities |
| 34,182 |
|
| 33,747 | |||||||
Total Deferred Credits and Other Liabilities | Total Deferred Credits and Other Liabilities |
| 482,403 |
|
| 479,109 | |||||||
|
|
|
|
|
|
|
| ||||||
Capitalization: | Capitalization: |
|
|
|
|
| |||||||
| Long-Term Debt |
| 578,239 |
|
| 578,471 | |||||||
|
|
|
|
|
|
|
| ||||||
| Common Stockholder's Equity: |
|
|
|
|
| |||||||
|
| Common Stock |
| 10,866 |
|
| 10,866 | ||||||
|
| Capital Surplus, Paid In |
| 391,398 |
|
| 391,256 | ||||||
|
| Retained Earnings |
| 182,778 |
|
| 178,834 | ||||||
|
| Accumulated Other Comprehensive Loss |
| (3,090) |
|
| (3,176) | ||||||
| Common Stockholder's Equity |
| 581,952 |
|
| 577,780 | |||||||
Total Capitalization | Total Capitalization |
| 1,160,191 |
|
| 1,156,251 | |||||||
|
|
|
|
|
|
|
| ||||||
Total Liabilities and Capitalization | Total Liabilities and Capitalization | $ | 1,895,247 |
| $ | 1,839,475 | |||||||
|
|
|
|
|
|
|
| ||||||
The accompanying notes are an integral part of these unaudited condensed financial statements. | The accompanying notes are an integral part of these unaudited condensed financial statements. |
|
| ||||||||||
|
|
13
PUBLIC SERVICE COMPANY OF NEW HAMPSHIRE AND SUBSIDIARY |
|
|
|
|
| ||
CONDENSED CONSOLIDATED BALANCE SHEETS |
|
|
|
|
| ||
(Unaudited) |
|
|
|
|
| ||
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| June 30, |
| December 31, | ||
(Thousands of Dollars) | 2014 |
| 2013 | ||||
|
|
|
|
|
|
|
|
LIABILITIES AND CAPITALIZATION |
|
|
|
|
| ||
|
|
|
|
|
|
|
|
Current Liabilities: |
|
|
|
|
| ||
| Notes Payable to NU Parent | $ | 95,000 |
| $ | 86,500 | |
| Long-Term Debt - Current Portion |
| 50,000 |
|
| 50,000 | |
| Accounts Payable |
| 58,910 |
|
| 82,920 | |
| Accounts Payable to Affiliated Companies |
| 18,760 |
|
| 22,040 | |
| Regulatory Liabilities |
| 36,627 |
|
| 20,643 | |
| Accumulated Deferred Income Taxes |
| 25,397 |
|
| 28,596 | |
| Other Current Liabilities |
| 35,440 |
|
| 51,729 | |
Total Current Liabilities |
| 320,134 |
|
| 342,428 | ||
|
|
|
|
|
|
|
|
Deferred Credits and Other Liabilities: |
|
|
|
|
| ||
| Accumulated Deferred Income Taxes |
| 563,291 |
|
| 500,166 | |
| Regulatory Liabilities |
| 50,843 |
|
| 51,723 | |
| Accrued SERP and PBOP |
| 15,055 |
|
| 15,272 | |
| Other Long-Term Liabilities |
| 46,598 |
|
| 46,247 | |
Total Deferred Credits and Other Liabilities |
| 675,787 |
|
| 613,408 | ||
|
|
|
|
|
|
|
|
Capitalization: |
|
|
|
|
| ||
| Long-Term Debt |
| 999,157 |
|
| 999,006 | |
|
|
|
|
|
|
|
|
| Common Stockholder's Equity: |
|
|
|
|
| |
|
| Common Stock |
| - |
|
| - |
|
| Capital Surplus, Paid In |
| 702,652 |
|
| 701,911 |
|
| Retained Earnings |
| 462,233 |
|
| 438,515 |
|
| Accumulated Other Comprehensive Loss |
| (7,943) |
|
| (8,550) |
| Common Stockholder's Equity |
| 1,156,942 |
|
| 1,131,876 | |
Total Capitalization |
| 2,156,099 |
|
| 2,130,882 | ||
|
|
|
|
|
|
|
|
Total Liabilities and Capitalization | $ | 3,152,020 |
| $ | 3,086,718 | ||
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
The accompanying notes are an integral part of these unaudited condensed consolidated financial statements. |
|
|
|
WESTERN MASSACHUSETTS ELECTRIC COMPANY |
|
|
| ||||
CONDENSED STATEMENTS OF INCOME |
|
|
|
|
| ||
(Unaudited) |
|
|
|
|
| ||
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| For the Three Months Ended March 31, | ||||
(Thousands of Dollars) | 2015 |
| 2014 | ||||
|
|
|
|
|
|
|
|
Operating Revenues | $ | 152,864 |
| $ | 137,409 | ||
|
|
|
|
|
|
|
|
Operating Expenses: |
|
|
|
|
| ||
| Purchased Power and Transmission |
| 69,661 |
|
| 49,431 | |
| Operations and Maintenance |
| 19,784 |
|
| 22,579 | |
| Depreciation |
| 10,375 |
|
| 10,321 | |
| Amortization of Regulatory Assets, Net |
| 3,927 |
|
| 399 | |
| Energy Efficiency Programs |
| 11,075 |
|
| 11,865 | |
| Taxes Other Than Income Taxes |
| 9,437 |
|
| 8,082 | |
|
| Total Operating Expenses |
| 124,259 |
|
| 102,677 |
Operating Income |
| 28,605 |
|
| 34,732 | ||
|
|
|
|
|
|
|
|
Interest Expense: |
|
|
|
|
| ||
| Interest on Long-Term Debt |
| 6,045 |
|
| 6,062 | |
| Other Interest |
| 778 |
|
| (416) | |
|
| Interest Expense |
| 6,823 |
|
| 5,646 |
Other Income, Net |
| 575 |
|
| 574 | ||
Income Before Income Tax Expense |
| 22,357 |
|
| 29,660 | ||
Income Tax Expense |
| 9,113 |
|
| 11,558 | ||
Net Income | $ | 13,244 |
| $ | 18,102 | ||
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
The accompanying notes are an integral part of these unaudited condensed financial statements. | |||||||
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
CONDENSED STATEMENTS OF COMPREHENSIVE INCOME |
|
|
| ||||
(Unaudited) |
|
|
|
|
| ||
|
|
|
|
|
|
|
|
Net Income | $ | 13,244 |
| $ | 18,102 | ||
Other Comprehensive Income, Net of Tax: |
|
|
|
|
| ||
| Qualified Cash Flow Hedging Instruments |
| 85 |
|
| 85 | |
| Changes in Unrealized Gains on Other Securities |
| 1 |
|
| 2 | |
Other Comprehensive Income, Net of Tax |
| 86 |
|
| 87 | ||
Comprehensive Income | $ | 13,330 |
| $ | 18,189 | ||
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
The accompanying notes are an integral part of these unaudited condensed financial statements. |
14
WESTERN MASSACHUSETTS ELECTRIC COMPANY | |||||||
CONDENSED STATEMENTS OF CASH FLOWS | |||||||
(Unaudited) | |||||||
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| For the Three Months Ended March 31, | ||||
(Thousands of Dollars) | 2015 |
| 2014 | ||||
|
|
|
|
|
|
|
|
Operating Activities: |
|
|
|
|
| ||
| Net Income | $ | 13,244 |
| $ | 18,102 | |
| Adjustments to Reconcile Net Income to Net Cash Flows Provided by/(Used in) Operating Activities: |
|
|
|
|
| |
|
| Depreciation |
| 10,375 |
|
| 10,321 |
|
| Deferred Income Taxes |
| 12,759 |
|
| 14,688 |
|
| Regulatory Over/(Under) Recoveries, Net |
| (14,442) |
|
| 5,780 |
|
| Amortization of Regulatory Assets, Net |
| 3,927 |
|
| 399 |
|
| Other |
| (1,197) |
|
| (1,351) |
| Changes in Current Assets and Liabilities: |
|
|
|
|
| |
|
| Receivables and Unbilled Revenues, Net |
| (26,298) |
|
| 34,905 |
|
| Taxes Receivable/Accrued, Net |
| 64 |
|
| (17,126) |
|
| Accounts Payable |
| 85 |
|
| (10,516) |
|
| Other Current Assets and Liabilities, Net |
| 65 |
|
| (8,869) |
Net Cash Flows Provided by/(Used in) Operating Activities |
| (1,418) |
|
| 46,333 | ||
|
|
|
|
|
|
|
|
Investing Activities: |
|
|
|
|
| ||
| Investments in Property, Plant and Equipment |
| (35,899) |
|
| (30,347) | |
| Proceeds from Sales of Marketable Securities |
| 23,249 |
|
| 34,656 | |
| Purchases of Marketable Securities |
| (23,442) |
|
| (34,804) | |
Net Cash Flows Used in Investing Activities |
| (36,092) |
|
| (30,495) | ||
|
|
|
|
|
|
|
|
Financing Activities: |
|
|
|
|
| ||
| Cash Dividends on Common Stock |
| (9,300) |
|
| (49,000) | |
| Increase in Notes Payable to ES Parent |
| 49,100 |
|
| 37,400 | |
| Other Financing Activities |
| (245) |
|
| (11) | |
Net Cash Flows Provided by/(Used in) Financing Activities |
| 39,555 |
|
| (11,611) | ||
Net Increase in Cash |
| 2,045 |
|
| 4,227 | ||
Cash - Beginning of Period |
| - |
|
| - | ||
Cash - End of Period | $ | 2,045 |
| $ | 4,227 | ||
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
The accompanying notes are an integral part of these unaudited condensed financial statements. |
15
PUBLIC SERVICE COMPANY OF NEW HAMPSHIRE AND SUBSIDIARY | |||||||
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS | |||||||
(Unaudited) | |||||||
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| For the Six Months Ended June 30, | ||||
(Thousands of Dollars) | 2014 |
| 2013 | ||||
|
|
|
|
|
|
|
|
Operating Activities: |
|
|
|
|
| ||
| Net Income | $ | 56,718 |
| $ | 56,189 | |
| Adjustments to Reconcile Net Income to Net Cash Flows Provided by Operating Activities: |
|
|
|
|
| |
|
| Depreciation |
| 48,679 |
|
| 45,515 |
|
| Deferred Income Taxes |
| 61,093 |
|
| 25,450 |
|
| Pension, SERP and PBOP Expense |
| 3,249 |
|
| 14,228 |
|
| Pension and PBOP Contributions |
| (833) |
|
| (45,721) |
|
| Regulatory Overrecoveries, Net |
| 18,849 |
|
| 4,844 |
|
| Amortization of Regulatory Liabilities, Net |
| (7,831) |
|
| (1,969) |
|
| Amortization of Rate Reduction Bonds |
| - |
|
| 19,748 |
|
| Proceeds from DOE Damages Claim |
| 13,103 |
|
| - |
|
| Other |
| 4,386 |
|
| 3,123 |
| Changes in Current Assets and Liabilities: |
|
|
|
|
| |
|
| Receivables and Unbilled Revenues, Net |
| 3,500 |
|
| 597 |
|
| Fuel, Materials and Supplies |
| 8,013 |
|
| (13,289) |
|
| Taxes Receivable/Accrued, Net |
| (55,243) |
|
| 21,584 |
|
| Accounts Payable |
| (7,146) |
|
| 26,159 |
|
| Other Current Assets and Liabilities, Net |
| (4,166) |
|
| (17,743) |
Net Cash Flows Provided by Operating Activities |
| 142,371 |
|
| 138,715 | ||
|
|
|
|
|
|
|
|
Investing Activities: |
|
|
|
|
| ||
| Investments in Property, Plant and Equipment |
| (117,387) |
|
| (109,565) | |
| (Increase)/Decrease in Special Deposits |
| (45) |
|
| 22,039 | |
| Other Investing Activities |
| (56) |
|
| (13) | |
Net Cash Flows Used in Investing Activities |
| (117,488) |
|
| (87,539) | ||
|
|
|
|
|
|
|
|
Financing Activities: |
|
|
|
|
| ||
| Cash Dividends on Common Stock |
| (33,000) |
|
| (34,000) | |
| Increase in Notes Payable to NU Parent |
| 8,500 |
|
| 118,900 | |
| Retirements of Long-Term Debt |
| - |
|
| (108,985) | |
| Retirements of Rate Reduction Bonds |
| - |
|
| (29,294) | |
| Other Financing Activities |
| (176) |
|
| (225) | |
Net Cash Flows Used in Financing Activities |
| (24,676) |
|
| (53,604) | ||
Net Increase/(Decrease) in Cash |
| 207 |
|
| (2,428) | ||
Cash - Beginning of Period |
| 130 |
|
| 2,493 | ||
Cash - End of Period | $ | 337 |
| $ | 65 | ||
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
The accompanying notes are an integral part of these unaudited condensed consolidated financial statements. |
16
WESTERN MASSACHUSETTS ELECTRIC COMPANY |
|
|
|
|
| |
CONDENSED BALANCE SHEETS |
|
|
|
|
| |
(Unaudited) |
|
|
|
|
| |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| June 30, |
| December 31, | ||
(Thousands of Dollars) | 2014 |
| 2013 | |||
|
|
|
|
|
|
|
ASSETS |
|
|
|
|
| |
|
|
|
|
|
|
|
Current Assets: |
|
|
|
|
| |
| Cash | $ | 1,709 |
| $ | - |
| Receivables, Net |
| 49,404 |
|
| 49,018 |
| Accounts Receivable from Affiliated Companies |
| 4,445 |
|
| 47,607 |
| Unbilled Revenues |
| 15,617 |
|
| 16,562 |
| Taxes Receivable |
| 15,228 |
|
| 432 |
| Regulatory Assets |
| 36,251 |
|
| 43,024 |
| Marketable Securities |
| 19,408 |
|
| 26,628 |
| Prepayments and Other Current Assets |
| 10,730 |
|
| 10,479 |
Total Current Assets |
| 152,792 |
|
| 193,750 | |
|
|
|
|
|
|
|
Property, Plant and Equipment, Net |
| 1,418,673 |
|
| 1,381,060 | |
|
|
|
|
|
|
|
Deferred Debits and Other Assets: |
|
|
|
|
| |
| Regulatory Assets |
| 120,303 |
|
| 146,088 |
| Marketable Securities |
| 38,640 |
|
| 31,243 |
| Other Long-Term Assets |
| 50,438 |
|
| 40,679 |
Total Deferred Debits and Other Assets |
| 209,381 |
|
| 218,010 | |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total Assets | $ | 1,780,846 |
| $ | 1,792,820 | |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
The accompanying notes are an integral part of these unaudited condensed financial statements. |
|
|
|
17
WESTERN MASSACHUSETTS ELECTRIC COMPANY | |||||||
CONDENSED BALANCE SHEETS | |||||||
(Unaudited) | |||||||
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| June 30, |
| December 31, | ||
(Thousands of Dollars) | 2014 |
| 2013 | ||||
|
|
|
|
|
|
|
|
LIABILITIES AND CAPITALIZATION |
|
|
|
|
| ||
|
|
|
|
|
|
|
|
Current Liabilities: |
|
|
|
|
| ||
| Notes Payable to NU Parent | $ | 15,900 |
| $ | - | |
| Accounts Payable |
| 28,502 |
|
| 62,961 | |
| Accounts Payable to Affiliated Companies |
| 7,533 |
|
| 9,230 | |
| Accrued Interest |
| 7,524 |
|
| 7,525 | |
| Regulatory Liabilities |
| 44,745 |
|
| 19,858 | |
| Accumulated Deferred Income Taxes |
| 57 |
|
| 13,098 | |
| Counterparty Deposits |
| 188 |
|
| 7,688 | |
| Other Current Liabilities |
| 16,518 |
|
| 20,629 | |
Total Current Liabilities |
| 120,967 |
|
| 140,989 | ||
|
|
|
|
|
|
|
|
Deferred Credits and Other Liabilities: |
|
|
|
|
| ||
| Accumulated Deferred Income Taxes |
| 423,013 |
|
| 396,933 | |
| Regulatory Liabilities |
| 10,317 |
|
| 13,873 | |
| Accrued SERP and PBOP |
| 2,805 |
|
| 3,911 | |
| Other Long-Term Liabilities |
| 39,121 |
|
| 28,619 | |
Total Deferred Credits and Other Liabilities |
| 475,256 |
|
| 443,336 | ||
|
|
|
|
|
|
|
|
Capitalization: |
|
|
|
|
| ||
| Long-Term Debt |
| 628,932 |
|
| 629,389 | |
|
|
|
|
|
|
|
|
| Common Stockholder's Equity: |
|
|
|
|
| |
|
| Common Stock |
| 10,866 |
|
| 10,866 |
|
| Capital Surplus, Paid In |
| 391,035 |
|
| 390,743 |
|
| Retained Earnings |
| 157,134 |
|
| 181,014 |
|
| Accumulated Other Comprehensive Loss |
| (3,344) |
|
| (3,517) |
| Common Stockholder's Equity |
| 555,691 |
|
| 579,106 | |
Total Capitalization |
| 1,184,623 |
|
| 1,208,495 | ||
|
|
|
|
|
|
|
|
Total Liabilities and Capitalization | $ | 1,780,846 |
| $ | 1,792,820 | ||
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
The accompanying notes are an integral part of these unaudited condensed financial statements. |
|
|
|
18
19
WESTERN MASSACHUSETTS ELECTRIC COMPANY | |||||||
CONDENSED STATEMENTS OF CASH FLOWS | |||||||
(Unaudited) | |||||||
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| For the Six Months Ended June 30, | ||||
(Thousands of Dollars) | 2014 |
| 2013 | ||||
|
|
|
|
|
|
|
|
Operating Activities: |
|
|
|
|
| ||
| Net Income | $ | 25,120 |
| $ | 35,016 | |
| Adjustments to Reconcile Net Income to Net Cash Flows Provided by Operating Activities: |
|
|
|
|
| |
|
| Depreciation |
| 20,638 |
|
| 18,280 |
|
| Deferred Income Taxes |
| 15,234 |
|
| 33,317 |
|
| Regulatory Over/(Under) Recoveries, Net |
| 28,115 |
|
| (5,094) |
|
| Amortization of Regulatory Assets, Net |
| 741 |
|
| 814 |
|
| Amortization of Rate Reduction Bonds |
| - |
|
| 7,780 |
|
| Proceeds from DOE Damages Claim |
| 18,073 |
|
| - |
|
| Other |
| 1,462 |
|
| 572 |
| Changes in Current Assets and Liabilities: |
|
|
|
|
| |
|
| Receivables and Unbilled Revenues, Net |
| 44,859 |
|
| (8,681) |
|
| Taxes Receivable/Accrued, Net |
| (19,555) |
|
| 21,081 |
|
| Accounts Payable |
| (26,494) |
|
| 21,389 |
|
| Other Current Assets and Liabilities, Net |
| (11,587) |
|
| (5,166) |
Net Cash Flows Provided by Operating Activities |
| 96,606 |
|
| 119,308 | ||
|
|
|
|
|
|
|
|
Investing Activities: |
|
|
|
|
| ||
| Investments in Property, Plant and Equipment |
| (61,470) |
|
| (96,051) | |
| Proceeds from Sales of Marketable Securities |
| 44,449 |
|
| 41,604 | |
| Purchases of Marketable Securities |
| (44,754) |
|
| (41,961) | |
| Other Investing Activities |
| - |
|
| 4,601 | |
Net Cash Flows Used in Investing Activities |
| (61,775) |
|
| (91,807) | ||
|
|
|
|
|
|
|
|
Financing Activities: |
|
|
|
|
| ||
| Cash Dividends on Common Stock |
| (49,000) |
|
| (20,000) | |
| Increase in Notes Payable to NU Parent |
| 15,900 |
|
| 3,300 | |
| Retirement of Rate Reduction Bonds |
| - |
|
| (9,352) | |
| Other Financing Activities |
| (22) |
|
| (31) | |
Net Cash Flows Used in Financing Activities |
| (33,122) |
|
| (26,083) | ||
Net Increase in Cash |
| 1,709 |
|
| 1,418 | ||
Cash - Beginning of Period |
| - |
|
| 1 | ||
Cash - End of Period | $ | 1,709 |
| $ | 1,419 | ||
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
The accompanying notes are an integral part of these unaudited condensed financial statements. |
20
NORTHEAST UTILITIESEVERSOURCE ENERGY 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
NUEversource Energy is a public utility holding company primarily engaged through its wholly owned regulated utility subsidiaries in the energy delivery business. NU'sEversource Energy's wholly owned regulated utility subsidiaries consist of CL&P, NSTAR Electric, PSNH, WMECO, Yankee Gas and NSTAR Gas. NUEversource 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.
On April 29, 2015, the Company's name was changed from Northeast Utilities to Eversource Energy. CL&P, NSTAR Electric, PSNH and WMECO operate under the brand Eversource Energy.
The unaudited condensed consolidated financial statements of NU,Eversource, 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,Eversource, NSTAR Electric and PSNH and the unaudited condensed financial statements of CL&P and WMECO are herein collectively referred to as the "financial statements."
The combined notes to the financial statements have been prepared pursuant to the rules and regulations of the SEC. Certain information and footnote disclosures included in annual financial statements prepared in accordance with GAAP have been omitted pursuant to such rules and regulations. The accompanying financial statements should be read in conjunction with the entirety of this combined Quarterly Report on Form 10-Q the first quarter 2014 combined Quarterly Report on Form 10-Q and the 20132014 combined Annual Report on Form 10-K of NU,Eversource, 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,Eversource's, CL&P's, NSTAR Electric's, PSNH's and WMECO's financial position as of June 30, 2014March 31, 2015 and December 31, 2013,2014, and the results of operations, and comprehensive income for the three and six months ended June 30, 2014 and 2013, and the cash flows for the sixthree months ended June 30, 2014March 31, 2015 and 2013.2014. The results of operations, and comprehensive income for the three and six months ended June 30, 2014 and 2013, and the cash flows for the sixthree months ended June 30,March 31, 2015 and 2014 and 2013 are not necessarily indicative of the results expected for a full year. The demand for electricity and natural gas is affected by weather conditions, economic conditions, and consumer conservation (including company-sponsored energy efficiency programs). Electric energy sales and revenues are typically higher in the winter and summer months than in the spring and fall months. Natural gas sales and revenues are typically higher in the winter months than during other periods of the year.
NUEversource consolidates CYAPC and YAEC asbecause CL&P's, NSTAR Electric's, PSNH's and WMECO's combined ownership interest in each of these entities is greater than 50 percent. Intercompany transactions between CL&P, NSTAR Electric, PSNH and WMECO and the CYAPC and YAEC companies have been eliminated in consolidation of the NUEversource financial statements. For CL&P, NSTAR Electric, PSNH and WMECO, the investments in CYAPC and YAEC continue to be accounted for under the equity method.
NU'sEversource's utility subsidiariessubsidiaries' distribution (including generation) and transmission businesses and NPT are subject to rate-regulation that is based on cost recovery and meets the criteria for application of accounting guidance for entities with rate-regulated operations, thatwhich considers the effect of regulation resulting fromon the differences in the timing of the recognition of certain revenues and expenses from those of other businesses and industries. NU's utility subsidiaries' energy delivery business is subject to rate-regulation that is based on cost recovery and meets the criteria for application of rate-regulated accounting. See Note 2, "Regulatory Accounting," for further information.
Certain reclassifications of prior period data were made in the accompanying balance sheets for NU, CL&P, NSTAR Electric and PSNH, and in thefinancial statements of income for NU, NSTAR Electric, PSNH and WMECO. These reclassifications were made to conform to the current period presentation.
B.
Accounting Standards
Recently Adopted Accounting Standards: On January 1, 2014, as required, NU prospectively adopted the Financial Accounting Standards Board's (FASB) final Accounting Standards Updates (ASU) that required presentation of certain unrecognized tax benefits as reductions to deferred tax assets. Implementation of this guidance had an immaterial impact on the balance sheets and no impact on the results of operations or cash flows of NU, CL&P, NSTAR Electric, PSNH and WMECO.
Accounting Standards Issued but not Yet Adopted: In May 2014, the FASBFinancial Accounting Standards Board (FASB) issued ASU 2014-09,Revenue from Contracts with Customers, effective January 1, 2017, which amends existing revenue recognition guidance and is required to be applied retrospectively (either to each reporting period presented or cumulatively at the date of initial application). In April 2015, the FASB decided to propose a one-year deferral of the effective date of the ASU. Management is reviewing the requirements of the newASU. The ASU however the ASU's impact is not expected to have a material impact on the financial statements of NU,Eversource, CL&P, NSTAR Electric, PSNH and WMECO.
21
C.
Provision for Uncollectible Accounts
NU,Eversource, including CL&P, NSTAR Electric, PSNH and WMECO, presents its receivables at estimated net realizable value by maintaining a provision for uncollectible accounts. This provision is determined based upon a variety of judgments and factors, including the application of an estimated uncollectible percentage to each receivable aging category. The estimate is based upon historical collection and write-off experience and management's assessment of collectibilitycollectability from individual customers. Management continuously assesses the collectibilitycollectability of receivables and adjusts collectibilitycollectability estimates based on actual experience. Receivable balances are written off against the provision for uncollectible accounts when the accounts are terminated and these balances are deemed to be uncollectible.
The PURA allows CL&P and Yankee Gas to accelerate the recovery of accounts receivable balances attributable to qualified customers under financial or medical duress (uncollectible hardship accounts receivable) outstanding for greater than 90 days. The DPU allows WMECO to also
16
recover in rates amounts associated with certain uncollectible hardship accounts receivable. Uncollectible customer account balances, which are expected to be recovered in rates, are included in Regulatory Assets or Other Long-Term Assets.
The total provision for uncollectible accounts and for uncollectible hardship accounts, which is included in the total provision, are included in Receivables, Net on the balance sheets, wasand were as follows:
|
| Total Provision for Uncollectible Accounts |
| Uncollectible Hardship | |||||||||||||||
(Millions of Dollars) |
| As of June 30, 2014 |
| As of December 31, 2013 | (Millions of Dollars) |
| As of March 31, 2015 |
| As of December 31, 2014 |
| As of March 31, 2015 |
| As of December 31, 2014 | ||||||
NU |
| $ | 197.4 |
| $ | 171.3 | |||||||||||||
ES | ES |
| $ | 187.4 |
| $ | 175.3 |
| $ | 92.3 |
| $ | 91.5 | ||||||
CL&P |
|
| 91.8 |
|
| 82.0 | CL&P |
|
| 86.6 |
| 84.3 |
|
| 74.5 |
|
| 74.0 | |
NSTAR Electric |
|
| 44.4 |
|
| 41.7 | NSTAR Electric |
|
| 43.8 |
| 40.7 |
|
| - |
|
| - | |
PSNH |
|
| 9.2 |
|
| 7.4 | PSNH |
|
| 8.1 |
| 7.7 |
|
| - |
|
| - | |
WMECO |
|
| 12.9 |
|
| 10.0 | WMECO |
|
| 10.7 |
| 9.9 |
|
| 6.5 |
|
| 6.2 |
D.
Fair Value Measurements
Fair value measurement guidance is applied to derivative contracts that are not elected or designated as "normal purchases or normal sales" (normal) and to the marketable securities held in trusts. Fair value measurement guidance is also applied to investment valuations of the investments used to calculate the funded status of pension and PBOP plans and nonrecurring fair value measurements of nonfinancial assets such as goodwill and AROs. AROs, and is also used to estimate the fair value of preferred stock and long-term debt.
Fair Value Hierarchy: In measuring fair value, NUEversource 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. NUEversource evaluates the classification of assets and liabilities measured at fair value on a quarterly basis, and NU'sEversource'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'sEversource's fair value measurements are described in Note 4, "Derivative Instruments," Note 5, "Marketable Securities," and Note 9, "Fair Value of Financial Instruments," to the financial statements.
E.
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's investment in two regional transmission companies, which are all accounted for on the equity method. On an NU consolidated basis, equity in earnings relate to the investment in MYAPC and NU's investment in two regional transmission companies.
F.
Other Taxes
Gross receipts taxes levied by the state of Connecticut are collected by CL&P and Yankee Gas from their respective customers. These gross receipts taxes are shown on a gross basis with collections in Operating Revenues and payments in Taxes Other Than Income Taxes on the statements of income as follows:
| For the Three Months Ended |
| For the Six Months Ended | For the Three Months Ended | ||||||||||||
(Millions of Dollars) | June 30, 2014 |
| June 30, 2013 |
| June 30, 2014 |
| June 30, 2013 | March 31, 2015 |
| March 31, 2014 | ||||||
NU | $ | 35.2 |
| $ | 33.0 |
| $ | 79.6 |
| $ | 71.4 | |||||
ES | $ | 41.9 |
| $ | 44.4 | |||||||||||
CL&P |
| 30.9 |
| 29.8 |
| 66.5 |
| 61.8 |
| 33.0 |
| 35.6 |
Certain sales taxes are also collected by NU'sEversource'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 March 31, 2015 |
| As of March 31, 2014 | |||||
ES | $ | 110.4 |
| $ | 108.5 | |||
CL&P |
| 42.3 |
|
| 36.2 | |||
NSTAR Electric |
| 21.9 |
|
| 28.0 | |||
PSNH |
| 21.7 |
|
| 14.4 | |||
WMECO |
| 8.3 |
|
| 14.4 |
2217
G. Supplemental Cash Flow Information |
| ||||||||
Non-cash investing activities include plant additions included in Accounts Payable as follows: | |||||||||
|
|
|
|
|
|
|
|
|
|
(Millions of Dollars) | As of June 30, 2014 |
| As of June 30, 2013 |
| |||||
NU | $ | 125.5 |
| $ | 109.5 |
| |||
CL&P |
| 54.0 |
|
| 28.3 |
| |||
NSTAR Electric |
| 21.6 |
|
| 33.4 |
| |||
PSNH |
| 14.8 |
|
| 15.5 |
| |||
WMECO |
| 9.9 |
|
| 17.0 |
|
In the first half of 2014, as a result of awards issued to the Yankee Companies for spent nuclear fuel lawsuits against the DOE described in Note 8C, "Commitments and Contingencies - Contractual Obligations - Yankee Companies," NU recognized total proceeds of $125.7 million, which were net of $80.6 million in proceeds CY and YAEC returned to non-affiliated member companies.
H.
Severance Benefits
NUFor the three months ended March 31, 2015 and 2014, Eversource recorded severance benefit expensesexpense of $1.4$0.4 million and $5.7$4.3 million, associatedrespectively, in connection with ongoing post-merger integration and, in 2014, the partial outsourcing of information technology functions and ongoing post-merger integration for the three and six months ended June 30, 2014, respectively.functions. As of June 30, 2014March 31, 2015 and December 31, 2013,2014, the severance accrual totaled $9.3$9 million and $14.7$10.4 million, respectively, and was included in Other Current Liabilities on the balance sheets.
2.
REGULATORY ACCOUNTING
Eversource's Regulated companies are subject to rate-regulation that is based on cost recovery and meets the criteria for application of accounting guidance for entities with rate-regulated operations and reflect the effects of the rate-making process. The rates charged to the customers of NU'sEversource's Regulated companies are designed to collect each company's costs to provide service, including a return on investment. Therefore, the accounting policies of the Regulated companies follow the application of accounting guidance for entities with rate-regulated operations and reflect the effects of the rate-making process.
Management believes it is probable that each of the Regulated companies will recover their respective investments in long-lived assets, including regulatory assets. If management were to determine that it could no longer apply the accounting guidance applicable to rate-regulated enterprises to any of the Regulated companies' operations, or that management could not conclude it is probable that costs would be recovered from customers in future rates, the costs would be charged to net income in the period in which the determination is made.
Regulatory Assets: The components of regulatory assets are as follows:
| As of June 30, 2014 |
| As of December 31, 2013 | As of March 31, 2015 |
| As of December 31, 2014 | ||||
(Millions of Dollars) | NU |
| NU | ES |
| ES | ||||
Benefit Costs | $ | 1,146.7 |
| $ | 1,240.2 | $ | 1,976.6 |
| $ | 2,016.0 |
Derivative Liabilities |
| 431.4 |
|
| 638.0 |
| 410.2 |
|
| 425.5 |
Income Taxes, Net |
| 631.8 |
|
| 626.2 |
| 632.1 |
|
| 635.3 |
Storm Restoration Costs |
| 503.9 |
|
| 589.6 |
| 504.8 |
|
| 502.8 |
Goodwill-related |
| 515.7 |
|
| 525.9 |
| 500.2 |
|
| 505.4 |
Regulatory Tracker Mechanisms |
| 275.1 |
|
| 323.4 |
| 434.5 |
|
| 350.5 |
Contractual Obligations - Yankee Companies |
| 128.4 |
|
| 154.2 |
| 119.0 |
|
| 123.8 |
Buy Out Agreements for Power Contracts |
| 56.7 |
|
| 70.2 | |||||
Other Regulatory Assets |
| 117.0 |
|
| 126.8 |
| 151.4 |
|
| 167.3 |
Total Regulatory Assets |
| 3,806.7 |
|
| 4,294.5 |
| 4,728.8 |
|
| 4,726.6 |
Less: Current Portion |
| 467.2 |
|
| 535.8 |
| 747.3 |
|
| 672.5 |
Total Long-Term Regulatory Assets | $ | 3,339.5 |
| $ | 3,758.7 | $ | 3,981.5 |
| $ | 4,054.1 |
|
| As of June 30, 2014 |
| As of December 31, 2013 |
| As of March 31, 2015 |
| As of December 31, 2014 | ||||||||||||||||||||||||||||||||||||||||
|
|
|
|
| NSTAR |
|
|
|
|
|
|
|
| NSTAR |
|
|
|
|
|
|
|
| NSTAR |
|
|
|
|
|
|
|
| NSTAR |
|
|
|
| ||||||||||||
(Millions of Dollars) | (Millions of Dollars) | CL&P |
| Electric |
| PSNH |
| WMECO |
| CL&P |
| Electric |
| PSNH |
| WMECO | (Millions of Dollars) | CL&P |
| Electric |
| PSNH |
| WMECO |
| CL&P |
| Electric |
| PSNH |
| WMECO | ||||||||||||||||
Benefit Costs | Benefit Costs | $ | 251.9 |
| $ | 323.4 |
| $ | 81.6 |
| $ | 46.2 |
| $ | 297.7 |
| $ | 496.7 |
| $ | 100.6 |
| $ | 57.3 | Benefit Costs | $ | 436.7 |
| $ | 505.6 |
| $ | 171.2 |
| $ | 83.3 |
| $ | 445.4 |
| $ | 515.9 |
| $ | 174.3 |
| $ | 85.0 |
Derivative Liabilities | Derivative Liabilities |
| 424.6 |
| 6.3 |
| - |
| - |
|
| 630.4 |
| 7.7 |
| - |
| - | Derivative Liabilities |
| 403.3 |
| 3.5 |
| - |
| - |
|
| 410.9 |
| 4.5 |
| - |
| - | ||||||||||||
Income Taxes, Net | Income Taxes, Net |
| 426.2 |
| 81.4 |
| 38.0 |
| 40.8 |
|
| 415.5 |
| 84.0 |
| 40.3 |
| 43.7 | Income Taxes, Net |
| 438.7 |
| 83.7 |
| 36.8 |
| 31.2 |
|
| 437.7 |
| 83.7 |
| 38.0 |
| 35.5 | ||||||||||||
Storm Restoration Costs | Storm Restoration Costs |
| 328.0 |
| 107.2 |
| 34.7 |
| 34.0 |
|
| 397.8 |
| 109.3 |
| 43.7 |
| 38.8 | Storm Restoration Costs |
| 308.5 |
| 119.7 |
| 46.9 |
| 29.7 |
|
| 319.6 |
| 103.7 |
| 47.7 |
| 31.8 | ||||||||||||
Goodwill-related | Goodwill-related |
| - |
| 442.8 |
| - |
| - |
|
| - |
| 451.5 |
| - |
| - | Goodwill-related |
| - |
| 429.5 |
| - |
| - |
|
| - |
| 433.9 |
| - |
| - | ||||||||||||
Regulatory Tracker Mechanisms | Regulatory Tracker Mechanisms |
| 8.1 |
| 131.8 |
| 87.9 |
| 20.7 |
|
| 8.0 |
| 169.5 |
| 83.3 |
| 32.6 | Regulatory Tracker Mechanisms |
| 10.1 |
| 261.2 |
| 93.4 |
| 47.6 |
|
| 16.1 |
| 141.4 |
| 103.5 |
| 33.0 | ||||||||||||
Buy Out Agreements for Power Contracts |
| - |
| 52.0 |
| 4.7 |
| - |
|
| - |
| 64.7 |
| 5.5 |
| - | |||||||||||||||||||||||||||||||
Other Regulatory Assets | Other Regulatory Assets |
| 63.7 |
|
| 54.7 |
|
| 36.0 |
|
| 14.9 |
|
| 64.6 |
|
| 55.9 |
|
| 38.1 |
|
| 16.7 | Other Regulatory Assets |
| 66.5 |
|
| 85.0 |
|
| 38.9 |
|
| 12.8 |
|
| 66.1 |
|
| 94.7 |
|
| 41.3 |
|
| 12.9 |
Total Regulatory Assets | Total Regulatory Assets |
| 1,502.5 |
| 1,199.6 |
| 282.9 |
| 156.6 |
|
| 1,814.0 |
| 1,439.3 |
| 311.5 |
| 189.1 | Total Regulatory Assets |
| 1,663.8 |
| 1,488.2 |
| 387.2 |
| 204.6 |
|
| 1,695.8 |
| 1,377.8 |
| 404.8 |
| 198.2 | ||||||||||||
Less: Current Portion | Less: Current Portion |
| 110.0 |
|
| 178.6 |
|
| 95.3 |
|
| 36.3 |
|
| 150.9 |
|
| 204.1 |
|
| 92.2 |
|
| 43.0 | Less: Current Portion |
| 209.6 |
|
| 309.5 |
|
| 100.0 |
|
| 66.7 |
|
| 220.3 |
|
| 198.7 |
|
| 111.7 |
|
| 51.9 |
Total Long-Term Regulatory Assets | Total Long-Term Regulatory Assets | $ | 1,392.5 |
| $ | 1,021.0 |
| $ | 187.6 |
| $ | 120.3 |
| $ | 1,663.1 |
| $ | 1,235.2 |
| $ | 219.3 |
| $ | 146.1 | Total Long-Term Regulatory Assets | $ | 1,454.2 |
| $ | 1,178.7 |
| $ | 287.2 |
| $ | 137.9 |
| $ | 1,475.5 |
| $ | 1,179.1 |
| $ | 293.1 |
| $ | 146.3 |
Benefit Costs: For information related to the Regulated companies' pension and other postretirement benefits, see Note 7, "Pension Benefits and Postretirement Benefits Other Than Pensions."
Storm Restoration Costs: On March 12, 2014, the PURA approved recovery of $365 million of deferred storm restoration costs associated with five major storms that occurred in 2011 and 2012. CL&P will recover the $365 million with carrying charges in its distribution rates over a six-year period beginning December 1, 2014. On June 17, 2014, the PURA ordered CL&P to use the DOE Phase II Damages proceeds of $65.4 million to offset the $365 million in 2011 and 2012 deferred storm restoration costs, which are reflected in the deferred storm restoration costs regulatory asset.
23
For further information on the DOE Phase II Damages proceeds received from the Yankee Companies, see Note 8C, "Commitments and Contingencies - Contractual Obligations - Yankee Companies," to the financial statements.
Regulatory Costs in Other Long-Term Assets: The Regulated companies had $64.5$49.3 million ($3.41.6 million for CL&P, $33.9$18.3 million for NSTAR Electric, $0.4 million for PSNH and $12$11.8 million for WMECO) and $65.1$60.5 million ($7.31.3 million for CL&P, $33.4$33.2 million for NSTAR Electric, $0.9 million for PSNH, and $10.1$11 million for WMECO) of additional regulatory costs as of June 30, 2014March 31, 2015 and December 31, 2013,2014, respectively, that were included in Other Long-Term Assets on the balance sheets. These amounts represent incurred costs for which recovery has not yet been specifically approved by the applicable regulatory agency. However, based on regulatory policies or past precedent on similar costs, management believes it is probable that these costs will ultimately be approved and recovered from customers in rates. The NSTAR Electric balance as of March 31, 2015 and December 31, 2014 primarily related to costs deferred in connection with the basic service bad debt adder. See Note 8E, "Commitments and Contingencies – Basic Service Bad Debt Adder," for further information.
Regulatory Liabilities: The components of regulatory liabilities are as follows:
| As of June 30, 2014 |
| As of December 31, 2013 | ||
(Millions of Dollars) | NU |
| NU | ||
Cost of Removal | $ | 435.3 |
| $ | 435.1 |
Regulatory Tracker Mechanisms |
| 305.2 |
|
| 151.2 |
AFUDC - Transmission |
| 67.4 |
|
| 68.1 |
Other Regulatory Liabilities |
| 56.0 |
|
| 52.9 |
Total Regulatory Liabilities |
| 863.9 |
|
| 707.3 |
Less: Current Portion |
| 359.9 |
|
| 204.3 |
Total Long-Term Regulatory Liabilities | $ | 504.0 |
| $ | 503.0 |
|
| As of June 30, 2014 |
| As of December 31, 2013 | |||||||||||||||||||||||||
|
|
|
| NSTAR |
|
|
|
|
|
|
| NSTAR |
|
|
|
| As of March 31, 2015 |
| As of December 31, 2014 | ||||||||||
(Millions of Dollars) | (Millions of Dollars) | CL&P |
| Electric |
| PSNH |
| WMECO |
| CL&P |
| Electric |
| PSNH |
| WMECO | ES |
| ES | ||||||||||
Cost of Removal | Cost of Removal | $ | 22.8 |
| $ | 255.7 |
| $ | 48.7 |
| $ | - |
| $ | 29.1 |
| $ | 250.0 |
| $ | 49.7 |
| $ | - | $ | 452.8 |
| $ | 439.9 |
Regulatory Tracker Mechanisms | Regulatory Tracker Mechanisms |
| 143.2 |
|
| 60.2 |
|
| 34.8 |
|
| 45.1 |
|
| 95.6 |
|
| 21.9 |
|
| 21.6 |
|
| 21.1 |
| 183.3 |
| 192.3 | |
AFUDC - Transmission | AFUDC - Transmission |
| 54.2 |
|
| 4.0 |
|
| - |
|
| 9.2 |
|
| 54.7 |
|
| 4.1 |
|
| - |
|
| 9.3 |
| 67.1 |
| 67.1 | |
Other Regulatory Liabilities | Other Regulatory Liabilities |
| 10.0 |
|
| 29.8 |
|
| 3.9 |
|
| 0.7 |
|
| 8.4 |
|
| 31.1 |
|
| 1.0 |
|
| 3.4 |
| 22.9 |
|
| 50.8 |
Total Regulatory Liabilities | Total Regulatory Liabilities |
| 230.2 |
|
| 349.7 |
|
| 87.4 |
|
| 55.0 |
|
| 187.8 |
|
| 307.1 |
|
| 72.3 |
|
| 33.8 |
| 726.1 |
| 750.1 | |
Less: Current Portion | Less: Current Portion |
| 143.5 |
|
| 89.2 |
|
| 36.6 |
|
| 44.7 |
|
| 94.0 |
|
| 54.0 |
|
| 20.6 |
|
| 19.9 |
| 201.2 |
|
| 235.0 |
Total Long-Term Regulatory Liabilities | Total Long-Term Regulatory Liabilities | $ | 86.7 |
| $ | 260.5 |
| $ | 50.8 |
| $ | 10.3 |
| $ | 93.8 |
| $ | 253.1 |
| $ | 51.7 |
| $ | 13.9 | $ | 524.9 |
| $ | 515.1 |
18
|
| As of March 31, 2015 |
| As of December 31, 2014 | ||||||||||||||||||||
|
|
|
| NSTAR |
|
|
|
|
|
|
| NSTAR |
|
|
|
| ||||||||
(Millions of Dollars) | CL&P |
| Electric |
| PSNH |
| WMECO |
| CL&P |
| Electric |
| PSNH |
| WMECO | |||||||||
Cost of Removal | $ | 23.1 |
| $ | 263.4 |
| $ | 51.3 |
| $ | 2.8 |
| $ | 19.7 |
| $ | 258.3 |
| $ | 50.3 |
| $ | 1.1 | |
Regulatory Tracker Mechanisms |
| 77.5 |
|
| 22.5 |
|
| 13.9 |
|
| 22.2 |
|
| 122.6 |
|
| 20.7 |
|
| 14.2 |
|
| 22.3 | |
AFUDC - Transmission |
| 53.3 |
|
| 4.7 |
|
| - |
|
| 9.1 |
|
| 53.6 |
|
| 4.4 |
|
| - |
|
| 9.1 | |
Other Regulatory Liabilities |
| 12.3 |
|
| 2.1 |
|
| 2.8 |
|
| 0.9 |
|
| 10.1 |
|
| 28.9 |
|
| 2.9 |
|
| 0.8 | |
Total Regulatory Liabilities |
| 166.2 |
|
| 292.7 |
|
| 68.0 |
|
| 35.0 |
|
| 206.0 |
|
| 312.3 |
|
| 67.4 |
|
| 33.3 | |
Less: Current Portion |
| 84.1 |
|
| 24.6 |
|
| 16.1 |
|
| 22.3 |
|
| 124.7 |
|
| 49.6 |
|
| 16.0 |
|
| 22.5 | |
Total Long-Term Regulatory Liabilities | $ | 82.1 |
| $ | 268.1 |
| $ | 51.9 |
| $ | 12.7 |
| $ | 81.3 |
| $ | 262.7 |
| $ | 51.4 |
| $ | 10.8 |
2015 Regulatory Developments:As a result of twothe March 3, 2015 FERC orders issued on June 19, 2014order in the pending base ROE complaint proceedings described in Note 8E, "Commitments and Contingencies – FERC Base ROE Complaints," in the second quarter of 2014, the Company recorded a series of reserves at its electric subsidiaries to recognize the potential financial impact of these rulings. The aggregate pre-tax charge totaled $54.7 million at NU, which represented reserves of $31.4 million at CL&P, $10.3 million at NSTAR Electric, $3.8 million at PSNH and $9.2 million at WMECO. As of June 30, 2014, the cumulative reserves totaled $79.3 million at NU, $44.7 million at CL&P, $16.2 million at NSTAR Electric, $6.2 million at PSNH and $12.2 million at WMECO. As of December 31, 2013, as a result of the FERC ALJ initial decision in the third quarter of 2013, the Company had an aggregate pre-tax reserve of $24.6 million at NU, which represented reserves of $13.3 million at CL&P, $5.9 million at NSTAR Electric, $2.4 million at PSNH and $3 million at WMECO. These reserves were recorded in each electric subsidiary's respective transmission regulatory tracker mechanism and as a reduction of operating revenues.
As a result of awards issued to the Yankee Companies for spent nuclear fuel lawsuits against the DOE described in Note 8C, "Commitments and Contingencies - Contractual Obligations - Yankee Companies,– FERC ROE Complaints," in the Yankee Companies returned the DOE Phase II Damages proceedsfirst quarter of 2015, Eversource recognized a pre-tax charge to the member companies, including CL&P, NSTAR Electric, PSNH, and WMECO, for the benefitearnings (excluding interest) of their respective customers, effective June 1, 2014. CL&P's refund obligation to customers$20 million, of $65.4which $12.5 million was recorded as an offset to the deferred storm restoration costs regulatory asset, as directed by PURA.at CL&P, $2.4 million at NSTAR Electric's, PSNH'sElectric, $1 million at PSNH, and WMECO's refund obligation to customers of $29.1$4.1 million $13.1 million and $18.1 million, respectively,at WMECO. The pre-tax charge was recorded as a regulatory liability in each electric subsidiary's respective regulatory tracker mechanisms.and as a reduction of Operating Revenues.
24On March 2, 2015, the DPU approved the comprehensive settlement agreement between NSTAR Electric, NSTAR Gas and the Massachusetts Attorney General (the "Settlement") as filed with the DPU on December 31, 2014. The Settlement resolved the outstanding NSTAR Electric CPSL program filings for 2006 through 2011, the NSTAR Electric and NSTAR Gas PAM and energy efficiency-related customer billing adjustments reported in 2012, and the recovery of LBR related to NSTAR Electric's energy efficiency programs for 2008 through 2011 (11 dockets in total). As a result, NSTAR Electric and NSTAR Gas will refund a combined $44.7 million to customers. The refund was recorded as a regulatory liability as of March 31, 2015 and NSTAR Electric recognized a $21.7 million pre-tax benefit in the first quarter of 2015. For further information, see Note 8D, "Commitments and Contingencies – 2014 Comprehensive Settlement Agreement."
On January 7, 2015, the DPU issued an order concluding that NSTAR Electric had appropriately accounted for the removal of supply-related bad debt costs from base distribution rates effective January 1, 2006. The DPU ordered NSTAR Electric and the Massachusetts Attorney General to collaborate on the reconciliation of energy-related bad debt costs through 2014. During the second quarter of 2015, NSTAR Electric expects to file with the DPU to recover from customers approximately $43 million of supply-related bad debt costs. In the first quarter of 2015, as a result of the DPU order, NSTAR Electric increased its regulatory assets and reduced Operations and Maintenance expense by $24.2 million, resulting in an increase in after-tax earnings of $14.5 million. For further information, see Note 8E, "Commitments and Contingencies – Basic Service Bad Debt Adder."
3.
PROPERTY, PLANT AND EQUIPMENT AND ACCUMULATED DEPRECIATION
The following tables summarize the investments in utility property, plant and equipment by asset category:
|
| As of June 30, 2014 |
| As of December 31, 2013 |
| As of March 31, 2015 |
| As of December 31, 2014 | ||||
(Millions of Dollars) | (Millions of Dollars) | NU |
| NU | (Millions of Dollars) | ES |
| ES | ||||
Distribution - Electric | Distribution - Electric | $ | 12,145.0 |
| $ | 11,950.2 | Distribution - Electric | $ | 12,539.3 |
| $ | 12,495.2 |
Distribution - Natural Gas | Distribution - Natural Gas |
| 2,467.4 |
| 2,425.9 | Distribution - Natural Gas |
| 2,584.8 |
| 2,595.4 | ||
Transmission | Transmission |
| 6,508.0 |
| 6,412.5 | Transmission |
| 6,959.4 |
| 6,930.7 | ||
Generation | Generation |
| 1,167.9 |
|
| 1,152.3 | Generation |
| 1,172.2 |
|
| 1,170.9 |
Electric and Natural Gas Utility | Electric and Natural Gas Utility |
| 22,288.3 |
| 21,940.9 | Electric and Natural Gas Utility |
| 23,255.7 |
| 23,192.2 | ||
Other (1) | Other (1) |
| 506.5 |
|
| 508.7 | Other (1) |
| 547.9 |
|
| 551.3 |
Property, Plant and Equipment, Gross | Property, Plant and Equipment, Gross |
| 22,794.8 |
| 22,449.6 | Property, Plant and Equipment, Gross |
| 23,803.6 |
| 23,743.5 | ||
Less: Accumulated Depreciation | Less: Accumulated Depreciation |
|
|
|
| Less: Accumulated Depreciation |
|
|
|
| ||
| Electric and Natural Gas Utility |
| (5,575.8) |
| (5,387.0) | Electric and Natural Gas Utility |
| (5,842.6) |
| (5,777.8) | ||
| Other |
| (207.7) |
|
| (196.2) | Other |
| (232.3) |
|
| (231.8) |
Total Accumulated Depreciation | Total Accumulated Depreciation |
| (5,783.5) |
|
| (5,583.2) | Total Accumulated Depreciation |
| (6,074.9) |
|
| (6,009.6) |
Property, Plant and Equipment, Net | Property, Plant and Equipment, Net |
| 17,011.3 |
| 16,866.4 | Property, Plant and Equipment, Net |
| 17,728.7 |
| 17,733.9 | ||
Construction Work in Progress | Construction Work in Progress |
| 967.4 |
|
| 709.8 | Construction Work in Progress |
| 1,082.0 |
|
| 913.1 |
Total Property, Plant and Equipment, Net | Total Property, Plant and Equipment, Net | $ | 17,978.7 |
| $ | 17,576.2 | Total Property, Plant and Equipment, Net | $ | 18,810.7 |
| $ | 18,647.0 |
(1)
These assets represent unregulated property and are primarily comprised of building improvements, computer software, hardware and equipment and telecommunications assets at NU'sEversource Service and Eversource's unregulated companies.
| As of June 30, 2014 |
| As of December 31, 2013 | As of March 31, 2015 |
| As of December 31, 2014 | ||||||||||||||||||||||||||||||||||||||||
|
|
|
| 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 | $ | 5,035.2 |
| $ | 4,754.4 |
| $ | 1,629.1 |
| $ | 766.3 |
| $ | 4,930.7 |
| $ | 4,694.7 |
| $ | 1,608.2 |
| $ | 756.6 | $ | 5,180.0 |
| $ | 4,907.8 |
| $ | 1,704.1 |
| $ | 787.4 |
| $ | 5,158.8 |
| $ | 4,895.5 |
| $ | 1,696.7 |
| $ | 784.2 |
Transmission |
| 3,108.1 |
| 1,798.9 |
| 713.5 |
| 841.1 |
| 3,071.9 |
| 1,772.3 |
| 695.7 |
| 826.4 |
| 3,274.7 |
| 1,950.6 |
| 794.6 |
| 891.9 |
| 3,274.0 |
| 1,928.5 |
| 789.7 |
| 891.0 | ||||||||||||||
Generation |
| - |
|
| - |
|
| 1,134.0 |
|
| 33.9 |
|
| - |
|
| - |
|
| 1,131.2 |
|
| 21.1 |
| - |
|
| - |
|
| 1,137.8 |
|
| 34.4 |
|
| - |
|
| - |
|
| 1,136.5 |
|
| 34.4 |
Property, Plant and |
| 8,143.3 |
| 6,553.3 |
| 3,476.6 |
| 1,641.3 |
| 8,002.6 |
| 6,467.0 |
| 3,435.1 |
| 1,604.1 |
| 8,454.7 |
| 6,858.4 |
| 3,636.5 |
| 1,713.7 |
| 8,432.8 |
| 6,824.0 |
| 3,622.9 |
| 1,709.6 | ||||||||||||||
Less: Accumulated Depreciation |
| (1,867.9) |
|
| (1,700.6) |
|
| (1,045.3) |
|
| (283.7) |
|
| (1,804.1) |
|
| (1,631.3) |
|
| (1,021.8) |
|
| (271.5) |
| (1,950.7) |
|
| (1,783.6) |
|
| (1,105.7) |
|
| (303.3) |
|
| (1,928.0) |
|
| (1,761.4) |
|
| (1,090.0) |
|
| (297.4) |
Property, Plant and Equipment, Net |
| 6,275.4 |
| 4,852.7 |
| 2,431.3 |
| 1,357.6 |
| 6,198.5 |
| 4,835.7 |
| 2,413.3 |
| 1,332.6 |
| 6,504.0 |
| 5,074.8 |
| 2,530.8 |
| 1,410.4 |
| 6,504.8 |
| 5,062.6 |
| 2,532.9 |
| 1,412.2 | ||||||||||||||
Construction Work in Progress |
| 317.4 |
|
| 294.5 |
|
| 88.6 |
|
| 61.1 |
|
| 252.8 |
|
| 208.2 |
|
| 54.3 |
|
| 48.5 |
| 370.9 |
|
| 289.5 |
|
| 135.5 |
|
| 73.5 |
|
| 304.9 |
|
| 272.8 |
|
| 102.9 |
|
| 49.1 |
Total Property, Plant and | $ | 6,592.8 |
| $ | 5,147.2 |
| $ | 2,519.9 |
| $ | 1,418.7 |
| $ | 6,451.3 |
| $ | 5,043.9 |
| $ | 2,467.6 |
| $ | 1,381.1 | $ | 6,874.9 |
| $ | 5,364.3 |
| $ | 2,666.3 |
| $ | 1,483.9 |
| $ | 6,809.7 |
| $ | 5,335.4 |
| $ | 2,635.8 |
| $ | 1,461.3 |
19
As of March 31, 2015, PSNH had $1.1 billion in gross generation assets and Accumulated Depreciation of $497.1 million. These generation assets are the subject of a divestiture agreement in principle in a settlement Term Sheet entered into on March 11, 2015 between PSNH and key New Hampshire officials (Term Sheet) whereby, among other resolutions, PSNH has agreed to sell these assets. Upon completion of the sale, all remaining stranded costs will be recovered via bonds that will be secured by a non-bypassable charge to PSNH's customers. Consummation of the Term Sheet provisions is conditioned upon the enactment of New Hampshire legislation, completion of a final Settlement Agreement reflecting the provisions of the Term Sheet (Settlement Agreement), and NHPUC approval of the Settlement Agreement. See Note 8F, “Commitments and Contingencies – PSNH Generation Restructuring,” for further information.
4.
DERIVATIVE INSTRUMENTS
The Regulated companies purchase and procure energy and energy-related products, for their customers, which are subject to price volatility.volatility, for their customers. The costs associated with supplying energy to customers are recoverable through customer rates. The Regulated companies manage the risks associated with the price volatility of energy and energy-related products through the use of derivative and nonderivative contracts.
Many of the derivative contracts meet the definition of, and are designated as, normal and qualify for accrual accounting under the applicable accounting guidance. The costs and benefits of derivative contracts that meet the definition of normal are recognized in Operating Expenses or Operating Revenues on the statements of income, as applicable, as electricity or natural gas is delivered.
Derivative contracts that are not designated as normal are recorded at fair value as current or long-term Derivative Assets or Derivative Liabilities on the balance sheets. For the Regulated companies, regulatory assets or regulatory liabilities are recorded to offset the fair values of derivatives, as costscontract settlement amounts 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 presenttable presents the gross fair values of contracts categorized by risk type and the net amount recorded as current or long-term derivative asset or liability:
|
| As of June 30, 2014 | |||||||
|
| Commodity Supply and |
|
|
|
| Net Amount Recorded as | ||
(Millions of Dollars) | Price Risk Management |
| Netting(1) |
| Derivative Asset/(Liability) | ||||
Current Derivative Assets: |
|
|
|
|
|
|
|
| |
Level 2: |
|
|
|
|
|
|
|
| |
| NU (1) | $ | 0.4 |
| $ | (0.1) |
| $ | 0.3 |
Level 3: |
|
|
|
|
|
|
|
| |
| NU, CL&P (1) |
| 16.4 |
|
| (4.8) |
|
| 11.6 |
|
|
|
|
|
|
|
|
|
|
Long-Term Derivative Assets: |
|
|
|
|
|
|
|
| |
Level 3: |
|
|
|
|
|
|
|
| |
| NU, CL&P (1) | $ | 111.7 |
| $ | (17.0) |
| $ | 94.7 |
|
|
|
|
|
|
|
|
|
|
Current Derivative Liabilities: |
|
|
|
|
|
|
|
| |
Level 2: |
|
|
|
|
|
|
|
| |
| NU (1) | $ | (0.7) |
| $ | 0.2 |
| $ | (0.5) |
Level 3: |
|
|
|
|
|
|
|
| |
| NU |
| (87.8) |
|
| - |
|
| (87.8) |
| CL&P |
| (85.6) |
|
| - |
|
| (85.6) |
| NSTAR Electric |
| (2.2) |
|
| - |
|
| (2.2) |
|
|
|
|
|
|
|
|
|
|
Long-Term Derivative Liabilities: |
|
|
|
|
|
|
|
| |
Level 3: |
|
|
|
|
|
|
|
| |
| NU | $ | (449.4) |
| $ | - |
| $ | (449.4) |
| CL&P |
| (445.3) |
|
| - |
|
| (445.3) |
| NSTAR Electric |
| (4.1) |
|
| - |
|
| (4.1) |
|
| As of March 31, 2015 |
| As of December 31, 2014 | ||||||||||||||||||||||||
|
| As of December 31, 2013 |
|
| Commodity Supply |
|
|
| Net Amount |
| Commodity Supply |
|
|
| Net Amount | |||||||||||||
|
| Commodity Supply and |
|
|
|
| Net Amount Recorded as |
|
| and Price Risk |
|
|
|
| Recorded as |
| and Price Risk |
|
|
|
|
| Recorded as | |||||
(Millions of Dollars) | (Millions of Dollars) | Price Risk Management |
| Netting(1) |
| Derivative Asset/(Liability) | (Millions of Dollars) |
| Management |
| Netting(1) |
| a Derivative |
| Management |
| Netting(1) |
| a Derivative | |||||||||
Current Derivative Assets: | Current Derivative Assets: |
|
|
|
|
|
|
|
| Current Derivative Assets: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| |
Level 3: | Level 3: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| ||||||||||
| ES |
| $ | 16.0 |
| $ | (6.6) |
| $ | 9.4 |
| $ | 16.2 |
| $ | (6.6) |
| $ | 9.6 | |||||||||
| CL&P |
| 16.0 |
|
| (6.6) |
|
| 9.4 |
|
| 16.1 |
|
| (6.6) |
|
| 9.5 | ||||||||||
| NSTAR Electric |
| - |
|
| - |
|
| - |
|
| 0.1 |
|
| - |
|
| 0.1 | ||||||||||
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| ||||||||||
Long-Term Derivative Assets: | Long-Term Derivative Assets: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| ||||||||||
Level 3: | Level 3: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| ||||||||||
| ES, CL&P |
| $ | 88.3 |
| $ | (17.8) |
| $ | 70.5 |
| $ | 93.5 |
| $ | (19.2) |
| $ | 74.3 | |||||||||
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| ||||||||||
Current Derivative Liabilities: | Current Derivative Liabilities: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| ||||||||||
Level 2: | Level 2: |
|
|
|
|
|
|
|
| Level 2: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| |
| NU (1) | $ | 1.9 |
| $ | (0.3) |
| $ | 1.6 | ES |
| $ | (3.2) |
| $ | - |
| $ | (3.2) |
| $ | (9.8) |
| $ | - |
| $ | (9.8) |
Level 3: | Level 3: |
|
|
|
|
|
|
|
| Level 3: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| |
| NU (1) |
| 18.4 |
|
| (9.8) |
|
| 8.6 | ES |
| (90.3) |
|
| - |
|
| (90.3) |
|
| (90.0) |
|
| - |
|
| (90.0) | |
| CL&P (1) |
| 17.1 |
|
| (9.8) |
|
| 7.3 | CL&P |
| (88.2) |
|
| - |
|
| (88.2) |
|
| (88.5) |
|
| - |
|
| (88.5) | |
| NSTAR Electric |
| 1.2 |
|
| - |
|
| 1.2 | NSTAR Electric |
| (2.1) |
|
| - |
|
| (2.1) |
|
| (1.5) |
|
| - |
|
| (1.5) | |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| |
Long-Term Derivative Assets: |
|
|
|
|
|
|
|
| ||||||||||||||||||||
Long-Term Derivative Liabilities: | Long-Term Derivative Liabilities: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| ||||||||||
Level 2: | Level 2: |
|
|
|
|
|
|
|
| Level 2: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| |
| NU | $ | 0.2 |
| $ | - |
| $ | 0.2 | ES |
| $ | (0.2) |
| $ | - |
| $ | (0.2) |
| $ | (0.3) |
| $ | - |
| $ | (0.3) |
Level 3: | Level 3: |
|
|
|
|
|
|
|
| Level 3: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| |
| NU (1) |
| 116.2 |
|
| (42.2) |
|
| 74.0 | ES |
| (396.4) |
|
| - |
|
| (396.4) |
|
| (409.3) |
|
| - |
|
| (409.3) | |
| CL&P (1) |
| 113.6 |
|
| (42.2) |
|
| 71.4 | CL&P |
| (395.0) |
|
| - |
|
| (395.0) |
|
| (406.2) |
|
| - |
|
| (406.2) | |
|
|
|
|
|
|
|
|
|
| NSTAR Electric |
| (1.4) |
|
| - |
|
| (1.4) |
|
| (3.1) |
|
| - |
|
| (3.1) | |
Current Derivative Liabilities: |
|
|
|
|
|
|
|
| ||||||||||||||||||||
Level 3: |
|
|
|
|
|
|
|
| ||||||||||||||||||||
| NU | $ | (93.7) |
| $ | - |
| $ | (93.7) | |||||||||||||||||||
| CL&P |
| (92.2) |
|
| - |
|
| (92.2) | |||||||||||||||||||
| NSTAR Electric |
| (1.5) |
|
| - |
|
| (1.5) | |||||||||||||||||||
|
|
|
|
|
|
|
|
|
| |||||||||||||||||||
Long-Term Derivative Liabilities: |
|
|
|
|
|
|
|
| ||||||||||||||||||||
Level 3: |
|
|
|
|
|
|
|
| ||||||||||||||||||||
| NU | $ | (624.1) |
| $ | - |
| $ | (624.1) | |||||||||||||||||||
| CL&P |
| (617.1) |
|
| - |
|
| (617.1) | |||||||||||||||||||
| NSTAR Electric |
| (7.0) |
|
| - |
|
| (7.0) |
(1)
Amounts represent derivative assets and liabilities that NUEversource elected to record net on the balance sheets. These amounts are subject to master netting agreements or similar agreements for which the right of offset exists.
For further information on the fair value of derivative contracts, see Note 1D, "Summary of Significant Accounting Policies - Fair Value Measurements," to the financial statements.
Derivatives Not Designated as HedgesDerivative Contracts at Fair Value with Offsetting Regulatory Amounts
Commodity Supply and Price Risk Management: As required by regulation, CL&P, along with UI, has capacity-related contracts with generation facilities. CL&P has a sharing agreement with UI, with 80 percent of each contract allocated to CL&P and 20 percent allocated to UI. The combined capacity of these contracts is 787 MW. The capacity contracts extend through 2026 and obligate both CL&P and UI to make or receive payments on a monthly basis to or from the generation facilities based on the difference between a set capacity price and the forward capacity market price received in the ISO-NE capacity markets. In addition, CL&P has a contract to purchase 0.1 million MWh of energy per year through 2020.
26
NSTAR Electric has a renewable energy contract to purchase 0.1 million MWh of energy per year through 2018 and a capacity-related contract to purchase up to 35 MW per year through 2019.
20
As of June 30, 2014March 31, 2015 and December 31, 2013, NU2014, Eversource had NYMEX futurefinancial contracts for natural gas futures in order to reduce variability associated with the purchase price of approximately 6.65.3 million and 9.18.8 million MMBtu of natural gas, respectively.
The following table presentsFor the three months ended March 31, 2015 and 2014, there were losses of $16.6 million and gains of $54.1 million, respectively, recorded as regulatory assets and liabilities, which reflect the current change in fair value primarily recovered through rates from customers, associated with NU'sEversource's derivative contracts not designated as hedges:contracts.
|
| Amounts Recognized on Derivatives | |||||||||||||
|
| For the Three Months Ended June 30, |
| For the Six Months Ended June 30, | |||||||||||
(Millions of Dollars) |
| 2014 |
| 2013 |
| 2014 |
| 2013 | |||||||
NU |
|
|
|
|
|
|
|
|
|
|
|
|
|
| |
Balance Sheets: |
|
|
|
|
|
|
|
|
|
|
|
|
|
| |
| Regulatory Assets and Liabilities |
| $ | 111.6 |
| $ | 22.2 |
|
| $ | 166.0 |
| $ | 50.1 |
|
Statements of Income: |
|
|
|
|
|
|
|
|
|
|
|
|
|
| |
| Purchased Power, Fuel and Transmission |
|
| - |
|
| 0.5 |
|
|
| - |
|
| 0.8 |
|
Credit Risk
Certain of NU'sEversource's derivative contracts contain credit risk contingent features.provisions. These featuresprovisions require NUEversource to maintain investment grade credit ratings from the major rating agencies and to post collateral for contracts in a net liability position over specified credit limits. As of June 30, 2014, NSTAR GasMarch 31, 2015, Eversource had approximately $3 million of derivative contracts in a net liability position that were subject to credit risk contingent features. If NSTAR Gas' credit rating was downgraded below investment grade, NUprovisions and would have been required to post additional collateral of approximately $0.6$3 million in collateral.if ES parent's unsecured debt credit ratings had been downgraded to below investment grade. As of December 31, 2013, there were no2014, Eversource had approximately $10 million of derivative contracts in a net liability position that were subject to credit risk contingent features.provisions and would have been required to post additional collateral of approximately $10 million if ES parent's unsecured debt credit ratings had been downgraded to below investment grade.
ValuationFair Value Measurements of Derivative Instruments
Derivative contracts classified as Level 2 in the fair value hierarchy relate to the financial contracts for natural gas futures. Prices are obtained from broker quotes and are based on actual market activity. The contracts are valued using NYMEX natural gas prices. Valuations of these contracts also incorporate discount rates using the yield curve approach.
The fair value of derivative contracts classified as Level 3 utilizes significant unobservable inputs. The fair value is modeled using income techniques, such as discounted cash flow valuations adjusted for assumptions relating to exit price. Significant observable inputs for valuations of these contracts include energy and energy-related product prices in future years for which quoted prices in an active market exist. Fair value measurements categorized in Level 3 of the fair value hierarchy are prepared by individuals with expertise in valuation techniques, pricing of energy and energy-related products, and accounting requirements. The future power and capacity prices for periods that are not quoted in an active market or established at auction are based on available market data and are escalated based on estimates of inflation to address the full time period of the contract.
Valuations of derivative contracts using a discounted cash flow methodology include assumptions regarding the timing and likelihood of scheduled payments and also reflect non-performance risk, including credit, using the default probability approach based on the counterparty's credit rating for assets and the Company's credit rating for liabilities. Valuations incorporate estimates of premiums or discounts that would be required by a market participant to arrive at an exit price, using historical market transactions adjusted for the terms of the contract.
The following is a summary of NU's,Eversource's, including CL&P's and NSTAR Electric's, Level 3 derivative contracts and the range of the significant unobservable inputs utilized in the valuations over the duration of the contracts:
| As of June 30, 2014 |
| As of December 31, 2013 |
| As of March 31, 2015 |
| As of December 31, 2014 | ||||||||||||||||||||||||||||
|
| Range |
| Period Covered |
|
| Range |
| Period Covered |
|
| Range |
| Period Covered |
|
| Range |
| Period Covered | ||||||||||||||||
Energy Prices: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| Energy Prices: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
NU | $ | 63 | - | 66 | per MWh |
| 2018 - 2020 |
| $ | 49 | - | 77 | per MWh |
| 2018 - 2029 | ||||||||||||||||||||
CL&P | $ | 63 | - | 66 | per MWh |
| 2018 - 2020 |
| $ | 56 | - | 58 | per MWh |
| 2018 - 2029 | ||||||||||||||||||||
ES, CL&P | ES, CL&P | $ | 48 | per MWh |
| 2020 |
| $ | 52 | per MWh |
| 2020 | |||||||||||||||||||||||
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Capacity Prices: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| Capacity Prices: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
NU | $ | 3.13 | - | 13.00 | per kW-Month |
| 2016 - 2026 |
| $ | 5.07 | - | 11.82 | per kW-Month |
| 2017 - 2029 | ||||||||||||||||||||
ES | ES | $ | 8.80 | - | 12.98 | per kW-Month |
| 2016 – 2026 |
| $ | 5.30 | - | 12.98 | per kW-Month |
| 2016 - 2026 | |||||||||||||||||||
CL&P | $ | 7.00 | - | 13.00 | per kW-Month |
| 2018 - 2026 |
| $ | 5.07 | - | 10.42 | per kW-Month |
| 2017 - 2026 | CL&P | $ | 11.13 | - | 12.98 | per kW-Month |
| 2019 – 2026 |
| $ | 11.08 | - | 12.98 | per kW-Month |
| 2018 - 2026 | ||||
NSTAR Electric | $ | 3.13 | - | 11.13 | per kW-Month |
| 2016 - 2019 |
| $ | 5.07 | - | 7.38 | per kW-Month |
| 2017 - 2019 | NSTAR Electric | $ | 8.80 | - | 11.13 | per kW-Month |
| 2016 – 2019 |
| $ | 5.30 | - | 11.10 | per kW-Month |
| 2016 - 2019 | ||||
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Forward Reserve: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| Forward Reserve: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
NU, CL&P | $ | 3.30 | - | 9.50 | per kW-Month |
| 2014 - 2024 |
| $ | 3.30 | - | 3.30 | per kW-Month |
| 2014 - 2024 | ||||||||||||||||||||
ES, CL&P | ES, CL&P | $ | 5.80 | - | 9.50 | per kW-Month |
| 2015 – 2024 |
| $ | 5.80 | - | 9.50 | per kW-Month |
| 2015 - 2024 | |||||||||||||||||||
|
|
|
|
|
|
|
|
|
|
|
|
|
|
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REC Prices: |
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| REC Prices: |
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NU | $ | 38 | - | 70 | per REC |
| 2014 - 2018 |
| $ | 36 | - | 87 | per REC |
| 2014 - 2029 | ||||||||||||||||||||
NSTAR Electric | $ | 38 | - | 70 | per REC |
| 2014 - 2018 |
| $ | 36 | - | 70 | per REC |
| 2014 - 2018 | ||||||||||||||||||||
ES, NSTAR Electric | ES, NSTAR Electric | $ | 45 | - | 50 | per REC |
| 2015 – 2018 |
| $ | 38 | - | 56 | per REC |
| 2015 - 2018 |
Exit price premiums of 87 percent through 2524 percent are also applied on these contracts and reflect the most recent market activity available for similar type contracts.
Significant increases or decreases in future energy or capacity prices in isolation would decrease or increase, respectively, the fair value of the derivative liability. Any increases in the risk premiums would increase the fair value of the derivative liabilities. Changes in these fair values are recorded as a regulatory asset or liability and would not impact net income.
27
21
Valuations using significant unobservable inputs: The following tables presenttable presents changes in the Level 3 category of derivative assets and derivative liabilities measured at fair value on a recurring basis. The derivative assets and liabilities are presented on a net basis.
|
| For the Three Months Ended June 30, |
| For the Six Months Ended June 30, | ||||||||
|
| 2014 |
| 2013 |
| 2014 |
| 2013 | ||||
(Millions of Dollars) | NU |
| NU |
| NU |
| NU | |||||
Derivatives, Net: |
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| |
Fair Value as of Beginning of Period | $ | (564.3) |
| $ | (833.1) |
| $ | (635.2) |
| $ | (878.6) | |
Net Realized/Unrealized Gains Included in: |
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| |
| Net Income |
| - |
|
| 1.3 |
|
| - |
|
| 7.1 |
| Regulatory Assets and Liabilities |
| 111.8 |
|
| 22.7 |
|
| 161.3 |
|
| 48.9 |
Settlements |
| 21.6 |
|
| 21.0 |
|
| 43.0 |
|
| 34.5 | |
Fair Value as of End of Period | $ | (430.9) |
| $ | (788.1) |
| $ | (430.9) |
| $ | (788.1) |
|
| For the Three Months Ended June 30, | |||||||||||
|
| 2014 |
|
| 2013 | ||||||||
(Millions of Dollars) | CL&P |
| NSTAR Electric |
|
| CL&P |
| NSTAR Electric | |||||
Derivatives, Net: |
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| |
Fair Value as of Beginning of Period | $ | (557.0) |
| $ | (7.3) |
|
| $ | (819.6) |
| $ | (13.6) | |
Net Realized/Unrealized Gains/(Losses) Included in Regulatory Assets and Liabilities |
| 112.2 |
|
| (0.4) |
|
|
| 21.9 |
|
| (0.5) | |
Settlements |
| 20.2 |
|
| 1.4 |
|
|
| 21.9 |
|
| 1.0 | |
Fair Value as of End of Period | $ | (424.6) |
| $ | (6.3) |
|
| $ | (775.8) |
| $ | (13.1) | |
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| For the Three Months Ended March 31, | ||||||||||||||||||||||||||||||
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| For the Six Months Ended June 30, |
| 2015 |
| 2014 | |||||||||||||||||||||||||
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| 2014 |
| 2013 |
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| NSTAR |
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| NSTAR | |||||||||||||
(Millions of Dollars) | (Millions of Dollars) | CL&P |
| NSTAR Electric |
|
| CL&P |
| NSTAR Electric | (Millions of Dollars) | ES |
| CL&P |
| Electric |
| ES |
| CL&P |
| Electric | ||||||||||
Derivatives, Net: | Derivatives, Net: |
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| Derivatives, Net: |
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|
| |||||||
Fair Value as of Beginning of Period | Fair Value as of Beginning of Period | $ | (630.6) |
| $ | (7.3) |
| $ | (866.2) |
| $ | (14.9) | Fair Value as of Beginning of Period | $ | (415.4) |
| $ | (410.9) |
| $ | (4.5) |
| $ | (635.2) |
| $ | (630.6) |
| $ | (7.3) | |
Net Realized/Unrealized Gains/(Losses) | Net Realized/Unrealized Gains/(Losses) |
| 164.5 |
| (0.5) |
|
| 46.3 |
|
| 0.2 | Net Realized/Unrealized Gains/(Losses) Included in Regulatory Assets and Liabilities |
| (12.1) |
| (12.1) |
| - |
| 49.2 |
| 52.0 |
| (0.1) | |||||||
Settlements | Settlements |
| 41.5 |
|
| 1.5 |
|
| 44.1 |
|
| 1.6 | Settlements |
| 20.7 |
|
| 19.7 |
|
| 1.0 |
|
| 21.7 |
|
| 21.6 |
|
| 0.1 | |
Fair Value as of End of Period | Fair Value as of End of Period | $ | (424.6) |
| $ | (6.3) |
| $ | (775.8) |
| $ | (13.1) | Fair Value as of End of Period | $ | (406.8) |
| $ | (403.3) |
| $ | (3.5) |
| $ | (564.3) |
| $ | (557.0) |
| $ | (7.3) |
5.
MARKETABLE SECURITIES
NUEversource maintains trusts to fund certain non-qualified executive benefits and WMECO maintains a spent nuclear fuel trust to fund WMECO's prior period spent nuclear fuel liability. These trusts hold marketable securities. These trusts are not subject to regulatory oversight by state or federal agencies. In addition, CYAPC and YAEC maintain legally restricted trusts, each of which holds marketable securities, for settling the decommissioning obligations of their nuclear power plants.
In accordance with applicable accounting guidance, theThe Company elected to record mutual funds designated as available-for-sale at fair value and certain other equity investments as trading securities, with the changes in fair values recorded in Other Income, Net on the statements of income. As of June 30,March 31, 2015 and December 31, 2014, the mutual funds and equity investments were classified as Level 1 in the fair value hierarchy and totaled $59.6$86.7 million and $24.9$85.1 million, respectively. As of December 31, 2013, the mutual funds were classified as Level 1, and totaled $57.2 million. Net gains on the mutual funds were $2.2 million and $0.1 million forFor the three months ended June 30,March 31, 2015 and 2014, and 2013, respectively, and $2.4net gains on these securities of $1.6 million and $4.3$0.7 million, for the six months ended June 30, 2014 and 2013, respectively. Net gains on the equity investmentsrespectively, were $0.9 million and $1.4 million for the three and six months ended June 30, 2014, respectively. Dividend income is recorded in Other Income, Net on the statements of income. Dividend income is recorded in Other Income, Net 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'sEversource's and WMECO's available-for-sale securities. These securities are recorded at fair value and are included in current and long-term Marketable Securities on the balance sheets.
|
| As of June 30, 2014 | ||||||||||
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|
| Pre-Tax |
| Pre-Tax |
|
|
| ||
|
| Amortized |
| Unrealized |
| Unrealized |
|
|
| |||
(Millions of Dollars) | Cost |
| Gains |
| Losses |
| Fair Value | |||||
NU |
|
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| |
| Debt Securities (1) | $ | 308.3 |
| $ | 7.3 |
| $ | (0.3) |
| $ | 315.3 |
| Equity Securities (1) |
| 163.5 |
|
| 66.7 |
|
| - |
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| 230.2 |
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WMECO |
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| |
| Debt Securities (2) |
| 58.0 |
|
| - |
|
| - |
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| 58.0 |
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28
|
| As of December 31, 2013 |
| As of March 31, 2015 |
| As of December 31, 2014 | ||||||||||||||||||||||||||||||
|
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|
| Pre-Tax |
| Pre-Tax |
|
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|
| Pre-Tax |
| Pre-Tax |
|
|
|
|
|
| Pre-Tax |
| Pre-Tax |
|
| |||||||||
|
| Amortized |
| Unrealized |
| Unrealized |
|
|
| Amortized |
| Unrealized |
| Unrealized |
|
|
| Amortized |
| Unrealized |
| Unrealized |
|
| ||||||||||||
(Millions of Dollars) | (Millions of Dollars) | Cost |
| Gains |
| Losses |
| Fair Value | (Millions of Dollars) | Cost |
| Gains |
| Losses |
| Fair Value |
| Cost |
| Gains |
| Losses |
| Fair Value | ||||||||||||
NU |
|
|
|
|
|
|
|
| ||||||||||||||||||||||||||||
| Debt Securities (1) | $ | 299.2 |
| $ | 2.5 |
| $ | (2.1) |
| $ | 299.6 | ||||||||||||||||||||||||
ES | ES |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| ||||||||||||||||||
| Equity Securities (1) |
| 163.6 |
| 60.5 |
| - |
| 224.1 | Debt Securities (1) | $ | 318.2 |
| $ | 8.2 |
| $ | (0.1) |
| $ | 326.3 |
| $ | 313.0 |
| $ | 7.5 |
| $ | (0.3) |
| $ | 320.2 | |||
|
|
|
|
|
|
|
|
|
| Equity Securities (1) |
| 159.5 |
| 77.0 |
| - |
| 236.5 |
|
| 160.6 |
| 73.3 |
| - |
| 233.9 | |||||||||
WMECO | WMECO |
|
|
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|
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| WMECO |
|
|
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|
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|
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|
|
|
|
|
|
| |||||||||
| Debt Securities (2) |
| 57.9 |
| - |
| - |
| 57.9 | Debt Securities (2) |
| 58.2 |
| - |
| - |
| 58.2 |
|
| 58.2 |
| - |
| (0.1) |
| 58.1 |
(1)
NU'sEversource's amounts include CYAPC's and YAEC's marketable securities held in nuclear decommissioning trusts of $444.3$458.3 million and $424$450.8 million as of June 30, 2014March 31, 2015 and December 31, 2013,2014, respectively, which are legally restricted and can only be used for the costs of decommissioning of the nuclear power plants owned by these companies. Unrealized gains and losses for the nuclear decommissioning trusts are recorded in Marketable Securities with the corresponding offset into Other Long-Term Liabilities on the balance sheets, with no impact on the statements of income. All of the equity securities accounted for as available-for-sale securities are held in the CYAPC and YAEC trusts.
(2)
Unrealized gains and losses on debt securities held by WMECO are recorded in Marketable Securities with the corresponding offset to Other Long-Term Assets on the balance sheets.
Unrealized Losses and Other-than-Temporary Impairment: There have been no significant unrealized losses, other-than-temporary impairments or credit losses for NUEversource or WMECO. Factors considered in determining whether a credit loss exists include the duration and severity of the impairment, adverse conditions specifically affecting the issuer, and the payment history, ratings and rating changes of the security. For asset-backed debt securities, underlying collateral and expected future cash flows are also evaluated.
Realized Gains and Losses: Realized gains and losses on available-for-sale securities are recorded in Other Income, Net for NU'sEversource's benefit trust, Other Long-Term Assets for WMECO, and are offset in Other Long-Term Liabilities for CYAPC and YAEC. NUEversource utilizes the specific identification basis method for the NUEversource benefit trust, and the average cost basis method for the WMECO trust and the CYAPC and YAEC nuclear decommissioning trusts to compute the realized gains and losses on the sale of available-for-sale securities.
Contractual Maturities: As of June 30, 2014,March 31, 2015, the contractual maturities of available-for-sale debt securities arewere as follows:
|
| NU |
| WMECO |
| ES |
| WMECO | ||||||||||||||||
|
| Amortized |
|
|
| Amortized |
|
|
| Amortized |
|
|
| Amortized |
|
| ||||||||
(Millions of Dollars) | (Millions of Dollars) | Cost |
| Fair Value |
| Cost |
| Fair Value | (Millions of Dollars) | Cost |
| Fair Value |
| Cost |
| Fair Value | ||||||||
Less than one year (1) | Less than one year (1) | $ | 75.9 |
| $ | 75.8 |
| $ | 19.2 |
| $ | 19.2 | Less than one year (1) | $ | 59.9 |
| $ | 59.9 |
| $ | 33.2 |
| $ | 33.2 |
One to five years | One to five years |
| 73.9 |
| 74.6 |
| 31.9 |
| 32.0 | One to five years |
| 83.3 |
| 83.8 |
| 21.3 |
| 21.3 | ||||||
Six to ten years | Six to ten years |
| 56.1 |
| 57.7 |
| 2.7 |
| 2.7 | Six to ten years |
| 61.6 |
| 63.5 |
| 0.6 |
| 0.6 | ||||||
Greater than ten years | Greater than ten years |
| 102.4 |
|
| 107.2 |
|
| 4.2 |
|
| 4.1 | Greater than ten years |
| 113.4 |
|
| 119.1 |
|
| 3.1 |
|
| 3.1 |
Total Debt Securities | Total Debt Securities | $ | 308.3 |
| $ | 315.3 |
| $ | 58.0 |
| $ | 58.0 | Total Debt Securities | $ | 318.2 |
| $ | 326.3 |
| $ | 58.2 |
| $ | 58.2 |
22
(1)
Amounts in the Less than one year NUEversource 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 | |||||||||||||||||||||||
|
|
| As of |
| As of |
|
| ES |
| WMECO | ||||||||||||||||||
(Millions of Dollars) | (Millions of Dollars) | June 30, 2014 |
| December 31, 2013 |
| June 30, 2014 |
| December 31, 2013 | (Millions of Dollars) | As of March 31, 2015 |
| As of December 31, 2014 |
| As of March 31, 2015 |
| As of December 31, 2014 | ||||||||||||
Level 1: | Level 1: |
|
|
|
|
|
|
|
| Level 1: |
|
|
|
|
|
|
|
| ||||||||||
| Mutual Funds and Equities | $ | 314.7 |
| $ | 281.3 |
| $ | - |
| $ | - | Mutual Funds and Equities | $ | 323.2 |
| $ | 319.0 |
| $ | - |
| $ | - | ||||
| Money Market Funds |
| 42.3 |
|
| 32.9 |
|
| 2.0 |
|
| 10.9 | Money Market Funds |
| 32.9 |
|
| 24.9 |
|
| 10.5 |
|
| 4.3 | ||||
Total Level 1 | Total Level 1 | $ | 357.0 |
| $ | 314.2 |
| $ | 2.0 |
| $ | 10.9 | Total Level 1 | $ | 356.1 |
| $ | 343.9 |
| $ | 10.5 |
| $ | 4.3 | ||||
Level 2: | Level 2: |
|
|
|
|
|
|
|
| Level 2: |
|
|
|
|
|
|
|
| ||||||||||
| U.S. Government Issued Debt Securities (Agency and Treasury) | $ | 40.6 |
| $ | 61.4 |
| $ | - |
| $ | 6.8 | U.S. Government Issued Debt Securities (Agency and Treasury) | $ | 46.0 |
| $ | 51.3 |
| $ | - |
| $ | - | ||||
| Corporate Debt Securities |
| 61.8 |
| 53.6 |
| 15.8 |
| 15.1 | Corporate Debt Securities |
| 157.3 |
| 49.1 |
| 14.4 |
| 14.7 | ||||||||||
| Asset-Backed Debt Securities |
| 36.5 |
| 30.4 |
| 15.2 |
| 9.0 | Asset-Backed Debt Securities |
| 36.5 |
| 54.1 |
| 12.1 |
| 14.5 | ||||||||||
| Municipal Bonds |
| 109.5 |
| 105.5 |
| 11.7 |
| 11.2 | Municipal Bonds |
| 31.9 |
| 116.3 |
| 12.9 |
| 13.0 | ||||||||||
| Other Fixed Income Securities |
| 24.6 |
|
| 15.8 |
|
| 13.3 |
|
| 4.9 | Other Fixed Income Securities |
| 21.7 |
|
| 24.5 |
|
| 8.3 |
|
| 11.6 | ||||
Total Level 2 | Total Level 2 | $ | 273.0 |
| $ | 266.7 |
| $ | 56.0 |
| $ | 47.0 | Total Level 2 | $ | 293.4 |
| $ | 295.3 |
| $ | 47.7 |
| $ | 53.8 | ||||
Total Marketable Securities | Total Marketable Securities | $ | 630.0 |
| $ | 580.9 |
| $ | 58.0 |
| $ | 57.9 | Total Marketable Securities | $ | 649.5 |
| $ | 639.2 |
| $ | 58.2 |
| $ | 58.1 |
U.S. government issued debt securities are valued using market approaches that incorporate transactions for the same or similar bonds and adjustments for yields and maturity dates. Corporate debt securities are valued using a market approach, utilizing recent trades of the same or similar instrument and also incorporating yield curves, credit spreads and specific bond terms and conditions. Asset-backed debt securities include collateralized mortgage obligations, commercial mortgage backed securities, and securities collateralized by auto loans, credit card loans or receivables. Asset-backed debt securities are valued using recent trades of similar instruments, prepayment assumptions, yield curves, issuance and maturity dates, and tranche information. Municipal bonds are valued using a market approach that incorporates reported trades and benchmark yields. Other fixed income securities are valued using pricing models, quoted prices of securities with similar characteristics, and discounted cash flows.
29
6.
SHORT-TERM AND LONG-TERM DEBT
Credit Agreements and Commercial Paper Programs: Effective July 23, 2014, NUES parent, CL&P, PSNH, WMECO, NSTAR Gas and Yankee Gas amended their jointare parties to a five-year $1.45 billion revolving credit facility to extend the expiration date an additional year tothat expires September 6, 2019. The revolving credit facility is to be used primarily to backstop NUES parent's $1.45 billion commercial paper program. The commercial paper program allows NUES parent to issue commercial paper as a form of short-term debt. As of June 30, 2014March 31, 2015 and December 31, 2013, NU2014, ES parent had $710.5$788 million and $1.01approximately $1.1 billion, respectively, in short-term borrowings outstanding under the NUES parent commercial paper program, leaving $739.5$662 million and $435.5$348.9 million of available borrowing capacity as of June 30, 2014March 31, 2015 and December 31, 2013,2014, respectively. The weighted-average interest rate on these borrowings as of June 30, 2014March 31, 2015 and December 31, 20132014 was 0.250.53 percent and 0.240.43 percent, respectively, which is generally based on A2/P2 rated commercial paper. As of June 30, 2014,March 31, 2015, there were intercompany loans from NUES parent of $6.4$190.1 million to CL&P, $95$82 million to PSNH and $15.9$70.5 million to WMECO. As of December 31, 2013,2014, there were intercompany loans from NUES parent of $287.3$133.4 million to CL&P, and $86.5$90.5 million to PSNH. PSNH and $21.4 million to WMECO.
Effective July 23, 2014, NSTAR Electric amended itshas a five-year $450 million revolving credit facility to extend the expiration date an additional year tothat expires September 6, 2019. This facility serves to backstop NSTAR Electric's existing $450 million commercial paper program. As of June 30, 2014March 31, 2015 and December 31, 2013,2014, NSTAR Electric had $194.5$215.5 million and $103.5$302 million, respectively, in short-term borrowings outstanding under its commercial paper program, leaving $255.5$234.5 million and $346.5$148 million of available borrowing capacity as of June 30, 2014March 31, 2015 and December 31, 2013,2014, respectively. The weighted-average interest rate on these borrowings as of June 30, 2014March 31, 2015 and December 31, 20132014 was 0.160.35 percent and 0.130.27 percent, respectively, which is generally based on A2/P1 rated commercial paper.
AmountsExcept as described below, amounts outstanding under the commercial paper programs are generally included in Notes Payable for NUEversource 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 NUES parent to CL&P, PSNH and WMECO are included in Notes Payable to NUES Parent and classified in current liabilities on the balance sheets. See theLong-Term Debtportion of this Note immediately below for further information on the Yankee Gas $100 million bond issuanceIntercompany loans from ES parent to CL&P, PSNH and its impact on the NUWMECO are eliminated in consolidation in Eversource's balance sheet as of December 31, 2013.
Short-Term Borrowing Limits: The amount of short-term borrowings that may be incurred by NSTAR Electric is subject to periodic approval by the FERC. On June 11, 2014, the FERC granted authorization to allow NSTAR Electric to issue total short-term debt securities in an aggregate principal amount not to exceed $655 million outstanding at any one time, effective October 24, 2014 through October 23, 2016.sheets.
Long-Term Debt: On January 2, 2014, Yankee Gas15, 2015, ES parent issued $100$150 million of 4.821.60 percent Series L First Mortgage Bonds,G Senior Notes, due to mature in 2044. The proceeds, net of issuance costs, were used to repay the $75 million 4.80 percent Series G First Mortgage Bonds that matured on January 1, 20142018 and to pay $25 million in short-term borrowings. In accordance with applicable accounting guidance, these amounts were classified as Long-Term Debt on NU's balance sheet as of December 31, 2013.
On March 7, 2014, NSTAR Electric issued $300 million of 4.403.15 percent debentures,Series H Senior Notes, due to mature in 2044. The proceeds, net of issuance costs, were used to repay the $300 million of 4.875 percent debentures that matured on April 15, 2014.
On April 24, 2014, CL&P issued $250 million of 4.30 percent 2014 Series A First Mortgage Bonds, due to mature in April 2044.2025. The proceeds, net of issuance costs, were used to repay short-term borrowings.borrowings outstanding under the ES parent commercial paper program. As the debt issuances refinanced short-term debt, the short-term debt was classified as Long-Term Debt as of December 31, 2014.
On July 15, 2014, PSNHApril 1, 2015, CL&P repaid at maturity the $50$100 million of 5.255.00 percent 2005 Series LA First and Refunding Mortgage Bonds using short-term debt.
Working Capital: Each of NU,borrowings. On April 1, 2015, CL&P NSTAR Electric, PSNH and WMECO use its available capital resourcesalso redeemed the $62 million 1996A Series 1.55 percent PCRBs that were subject to fund its respective construction expenditures, meet debt requirements, pay operating costs, including storm-related costs, pay dividends and fund other corporate obligations, such as pension contributions. The current growth in NU's transmission construction expenditures utilizes a significant amount of cash for projects that have a long-term return on investment and recovery period. In addition, NU's Regulated companies recover their electric and natural gas distribution construction expenditures as the related project costs are depreciated over the life of the assets. This impacts the timing of the revenue stream designed to fully recover the total investment plus a return on the equity portion of the cost and related financing costs. These factors have resulted in current liabilities exceeding current assets by approximately $730 million, $220 million and $200 million at NU, CL&P and NSTAR Electric, respectively, as of June 30, 2014.mandatory tender, using short term borrowings.
As of June 30, 2014, $366.7Long-Term Debt Issuance Authorization: On April 3, 2015, the DPU authorized NSTAR Gas to issue up to $100 million of NU's obligations classified as current liabilities relates toin long-term debt that will be paid infor the next 12 months, consisting of $312 million for CL&P, $4.7 million at NSTAR Electric and $50 million for PSNH. In addition, $28.9 million relates to the amortization of the purchase accounting fair value adjustment that will be amortized in the next twelve months. NU, with its strong credit ratings, has several options available in the financial markets to repay or refinance these maturities with the issuance of new long-term debt. NU, CL&P, NSTAR Electric, PSNH and WMECO will reduce their short-term borrowings with cash received from operating cash flows or with the issuance of new long-term debt, determined considering capital requirements and maintenance of NU's credit rating and profile. Management expects the future operating cash flows of NU, CL&P, NSTAR Electric, PSNH and WMECO, along with the access to financial markets, will be sufficient to meet any future operating requirements and capital investment forecasted opportunities.period through December 31, 2015.
3023
7.
PENSION BENEFITS AND POSTRETIREMENT BENEFITS OTHER THAN PENSIONS
As of December 31, 2014, Eversource Service sponsored two defined benefit retirement plans that covered eligible employees, including employees of CL&P, NSTAR Electric, PSNH and WMECO. Effective January 1, 2015, the two pension plans were merged into one plan, sponsored by Eversource Service. As of December 31, 2014, Eversource Service also sponsored defined benefit postretirement plans that provide certain retiree benefits, primarily medical, dental and life insurance, to retiring employees that meet certain age and service eligibility requirements, including employees of CL&P, NSTAR Electric, PSNH and WMECO. Effective January 1, 2015, the postretirement plans were merged into one plan, sponsored by Eversource Service.
The components of net periodic benefit expense for the Pension, SERP and PBOP Plans are detailedshown below. The net periodic benefit expense and the intercompany allocations less the capitalized portion of pension, SERP and PBOP amounts is included in Operations and Maintenance on the statements of income. Capitalized pension and PBOP amounts relate to employees working on capital projects and are included in Property, Plant and Equipment, Net. Intercompany allocations are not included in the CL&P, NSTAR Electric, PSNH and WMECO net periodic benefit expense amounts. Pension, SERP and PBOP expense reflected in the statements of cash flows for CL&P, NSTAR Electric, PSNH and WMECO does not include the intercompany allocations and the corresponding capitalized portion, as these amounts are cash settled on a short-term basis.
|
| Pension and SERP |
| Pension and SERP |
| Pension and SERP | ||||||||||||
|
| For the Three Months Ended |
| For the Six Months Ended |
| For the Three Months Ended | ||||||||||||
|
| June 30, 2014 |
| June 30, 2013 |
| June 30, 2014 |
| June 30, 2013 |
| March 31, 2015 |
| March 31, 2014 | ||||||
(Millions of Dollars) | (Millions of Dollars) | NU |
| NU |
| NU |
| NU | (Millions of Dollars) | ES(1) |
| ES | ||||||
Service Cost | Service Cost | $ | 19.1 |
| $ | 24.6 |
| $ | 41.5 |
| $ | 51.1 | Service Cost | $ | 23.2 |
| $ | 22.3 |
Interest Cost | Interest Cost |
| 56.3 |
| 51.9 |
|
| 113.0 |
| 103.5 | Interest Cost |
| 56.6 |
| 56.6 | |||
Expected Return on Plan Assets | Expected Return on Plan Assets |
| (77.7) |
| (68.6) |
|
| (155.4) |
| (139.0) | Expected Return on Plan Assets |
| (84.3) |
| (77.7) | |||
Actuarial Loss | Actuarial Loss |
| 31.7 |
| 52.6 |
|
| 64.7 |
| 105.5 | Actuarial Loss |
| 38.9 |
| 33.0 | |||
Prior Service Cost | Prior Service Cost |
| 1.1 |
|
| 1.0 |
|
| 2.1 |
|
| 2.1 | Prior Service Cost |
| 0.9 |
|
| 1.1 |
Total Net Periodic Benefit Expense | Total Net Periodic Benefit Expense | $ | 30.5 |
| $ | 61.5 |
| $ | 65.9 |
| $ | 123.2 | Total Net Periodic Benefit Expense | $ | 35.3 |
| $ | 35.3 |
Capitalized Pension Expense | Capitalized Pension Expense | $ | 8.7 |
| $ | 19.9 |
| $ | 18.4 |
| $ | 36.6 | Capitalized Pension Expense | $ | 9.6 |
| $ | 9.7 |
|
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| |||
|
| PBOP |
| PBOP |
| PBOP | ||||||||||||
|
| For the Three Months Ended |
| For the Six Months Ended |
| For the Three Months Ended | ||||||||||||
|
| June 30, 2014 |
| June 30, 2013 |
| June 30, 2014 |
| June 30, 2013 |
| March 31, 2015 |
| March 31, 2014 | ||||||
(Millions of Dollars) | (Millions of Dollars) | NU |
| NU |
| NU |
| NU | (Millions of Dollars) | ES(1) |
| ES | ||||||
Service Cost | Service Cost | $ | 3.2 |
| $ | 3.7 |
| $ | 6.3 |
| $ | 8.5 | Service Cost | $ | 4.2 |
| $ | 3.0 |
Interest Cost | Interest Cost |
| 12.1 |
| 10.9 |
|
| 24.7 |
| 23.6 | Interest Cost |
| 11.9 |
| 12.6 | |||
Expected Return on Plan Assets | Expected Return on Plan Assets |
| (15.8) |
| (13.9) |
|
| (31.6) |
| (27.7) | Expected Return on Plan Assets |
| (16.8) |
| (15.7) | |||
Actuarial Loss | Actuarial Loss |
| 3.0 |
| 4.7 |
|
| 6.0 |
| 13.0 | Actuarial Loss |
| 1.8 |
| 3.0 | |||
Prior Service Credit | Prior Service Credit |
| (0.7) |
|
| (0.5) |
|
| (1.4) |
|
| (1.1) | Prior Service Credit |
| (0.1) |
|
| (0.6) |
Total Net Periodic Benefit Expense | Total Net Periodic Benefit Expense | $ | 1.8 |
| $ | 4.9 |
| $ | 4.0 |
| $ | 16.3 | Total Net Periodic Benefit Expense | $ | 1.0 |
| $ | 2.3 |
Capitalized PBOP Expense | Capitalized PBOP Expense | $ | 0.4 |
| $ | 1.5 |
| $ | 0.8 |
| $ | 5.0 | Capitalized PBOP Expense | $ | 0.2 |
| $ | 0.4 |
|
| Pension and SERP |
| Pension and SERP | ||||||||||||||||||||||||||||||||||||||||||||
|
| For the Three Months Ended June 30, 2014 |
| For the Three Months Ended June 30, 2013 |
| For the Three Months Ended March 31, 2015 |
| For the Three Months Ended March 31, 2014 | ||||||||||||||||||||||||||||||||||||||||
|
|
|
|
| NSTAR |
|
|
|
|
|
|
|
| NSTAR |
|
|
|
|
|
|
|
| NSTAR |
|
|
|
|
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|
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| NSTAR |
|
|
|
| ||||||||||||
(Millions of Dollars) | (Millions of Dollars) | CL&P |
| Electric |
| PSNH |
| WMECO |
| CL&P |
| Electric(1) |
| PSNH |
| WMECO | (Millions of Dollars) | CL&P |
| Electric |
| PSNH(1) |
| WMECO |
| CL&P |
| Electric |
| PSNH |
| WMECO | ||||||||||||||||
Service Cost | Service Cost | $ | 5.0 |
| $ | 3.0 |
| $ | 2.3 |
| $ | 0.8 |
| $ | 6.3 |
| $ | 7.3 |
| $ | 3.2 |
| $ | 1.2 | Service Cost | $ | 6.0 |
| $ | 3.8 |
| $ | 2.9 |
| $ | 1.1 |
| $ | 5.2 |
| $ | 4.6 |
| $ | 2.8 |
| $ | 1.0 |
Interest Cost | Interest Cost |
| 12.4 |
| 10.3 |
| 5.8 |
| 2.5 |
| 12.1 |
| 14.7 |
| 5.9 |
| 2.5 | Interest Cost |
| 12.7 |
| 10.2 |
| 5.9 |
| 2.5 |
|
| 13.3 |
| 10.2 |
| 6.5 |
| 2.7 | |||||||||||||
Expected Return on Plan Assets | Expected Return on Plan Assets |
| (18.7) |
| (15.7) |
| (9.3) |
| (4.4) |
| (18.4) |
| (20.2) |
| (9.2) |
| (4.4) | Expected Return on Plan Assets |
| (19.7) |
| (17.6) |
| (10.0) |
| (4.7) |
|
| (19.4) |
| (15.8) |
| (10.2) |
| (4.6) | |||||||||||||
Actuarial Loss | Actuarial Loss |
| 8.2 |
| 5.9 |
| 2.8 |
| 1.7 |
| 13.9 |
| 14.6 |
| 5.4 |
| 2.9 | Actuarial Loss |
| 8.2 |
| 9.6 |
| 3.0 |
| 1.6 |
|
| 9.1 |
| 5.8 |
| 3.3 |
| 1.9 | |||||||||||||
Prior Service Cost/(Credit) |
| 0.5 |
|
| - |
|
| 0.1 |
|
| 0.1 |
|
| 0.5 |
|
| (0.1) |
|
| 0.1 |
|
| 0.1 | |||||||||||||||||||||||||
Prior Service Cost | Prior Service Cost |
| 0.4 |
|
| - |
|
| 0.1 |
|
| 0.1 |
|
| 0.5 |
|
| - |
|
| 0.2 |
|
| 0.1 | ||||||||||||||||||||||||
Total Net Periodic Benefit Expense | Total Net Periodic Benefit Expense | $ | 7.4 |
| $ | 3.5 |
| $ | 1.7 |
| $ | 0.7 |
| $ | 14.4 |
| $ | 16.3 |
| $ | 5.4 |
| $ | 2.3 | Total Net Periodic Benefit Expense | $ | 7.6 |
| $ | 6.0 |
| $ | 1.9 |
| $ | 0.6 |
| $ | 8.7 |
| $ | 4.8 |
| $ | 2.6 |
| $ | 1.1 |
Intercompany Allocations | Intercompany Allocations | $ | 7.5 |
| $ | 1.4 |
| $ | 2.1 |
| $ | 1.4 |
| $ | 11.3 |
| $ | (2.2) |
| $ | 2.6 |
| $ | 2.0 | Intercompany Allocations | $ | 6.4 |
| $ | 3.6 |
| $ | 1.7 |
| $ | 1.2 |
| $ | 6.8 |
| $ | 2.4 |
| $ | 1.9 |
| $ | 1.3 |
Capitalized Pension Expense | Capitalized Pension Expense | $ | 4.4 |
| $ | 1.0 |
| $ | 0.8 |
| $ | 0.6 |
| $ | 7.0 |
| $ | 6.5 |
| $ | 1.7 |
| $ | 1.3 | Capitalized Pension Expense | $ | 4.3 |
| $ | 2.8 |
| $ | 0.8 |
| $ | 0.5 |
| $ | 4.9 |
| $ | 1.9 |
| $ | 0.9 |
| $ | 0.8 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| |||||||||||||||||||||||||||||||
|
| Pension and SERP | ||||||||||||||||||||||||||||||||||||||||||||||
|
| For the Six Months Ended June 30, 2014 |
| For the Six Months Ended June 30, 2013 | ||||||||||||||||||||||||||||||||||||||||||||
|
|
|
|
| NSTAR |
|
|
|
|
|
|
|
| NSTAR |
|
|
|
| ||||||||||||||||||||||||||||||
(Millions of Dollars) | CL&P |
| Electric |
| PSNH |
| WMECO |
| CL&P |
| Electric(1) |
| PSNH |
| WMECO | |||||||||||||||||||||||||||||||||
Service Cost | $ | 10.2 |
| $ | 7.6 |
| $ | 5.1 |
| $ | 1.9 |
| $ | 12.4 |
| $ | 16.5 |
| $ | 6.5 |
| $ | 2.4 | |||||||||||||||||||||||||
Interest Cost |
| 25.7 |
| 20.6 |
| 12.3 |
| 5.2 |
| 24.2 |
| 29.0 |
| 11.9 |
| 5.0 | ||||||||||||||||||||||||||||||||
Expected Return on Plan Assets |
| (38.0) |
| (31.5) |
| (19.5) |
| (9.0) |
| (36.9) |
| (42.2) |
| (16.8) |
| (8.7) | ||||||||||||||||||||||||||||||||
Actuarial Loss |
| 17.3 |
| 11.7 |
| 6.0 |
| 3.5 |
| 28.0 |
| 29.1 |
| 10.8 |
| 5.9 | ||||||||||||||||||||||||||||||||
Prior Service Cost/(Credit) |
| 0.9 |
|
| - |
|
| 0.3 |
|
| 0.2 |
|
| 0.9 |
|
| (0.1) |
|
| 0.3 |
|
| 0.2 | |||||||||||||||||||||||||
Total Net Periodic Benefit Expense | $ | 16.1 |
| $ | 8.4 |
| $ | 4.2 |
| $ | 1.8 |
| $ | 28.6 |
| $ | 32.3 |
| $ | 12.7 |
| $ | 4.8 | |||||||||||||||||||||||||
Intercompany Allocations | $ | 14.3 |
| $ | 3.8 |
| $ | 4.2 |
| $ | 2.7 |
| $ | 22.1 |
| $ | (4.1) |
| $ | 5.2 |
| $ | 4.0 | |||||||||||||||||||||||||
Capitalized Pension Expense | $ | 9.3 |
| $ | 2.9 |
| $ | 1.7 |
| $ | 1.4 |
| $ | 14.0 |
| $ | 11.8 |
| $ | 3.9 |
| $ | 2.6 |
|
| PBOP | ||||||||||||||||||||||
|
| For the Three Months Ended March 31, 2015 |
| For the Three Months Ended March 31, 2014 | ||||||||||||||||||||
|
|
|
|
| NSTAR |
|
|
|
|
|
|
|
|
|
| NSTAR |
|
|
|
|
|
| ||
(Millions of Dollars) | CL&P |
| Electric |
|
| PSNH(1) |
|
| WMECO |
| CL&P |
| Electric |
| PSNH |
| WMECO | |||||||
Service Cost | $ | 0.6 |
| $ | 1.3 |
| $ | 0.4 |
| $ | 0.1 |
| $ | 0.6 |
| $ | 0.7 |
| $ | 0.4 |
| $ | 0.1 | |
Interest Cost |
| 1.8 |
|
| 4.8 |
|
| 1.0 |
|
| 0.4 |
|
| 2.1 |
|
| 4.9 |
|
| 1.1 |
|
| 0.5 | |
Expected Return on Plan Assets |
| (2.8) |
|
| (6.8) |
|
| (1.5) |
|
| (0.6) |
|
| (2.7) |
|
| (6.4) |
|
| (1.4) |
|
| (0.6) | |
Actuarial Loss/(Gain) |
| 0.2 |
|
| 0.8 |
|
| 0.1 |
|
| - |
|
| 1.1 |
|
| (0.1) |
|
| 0.5 |
|
| 0.1 | |
Prior Service Credit |
| - |
|
| (0.1) |
|
| - |
|
| - |
|
| - |
|
| (0.5) |
|
| - |
|
| - | |
Total Net Periodic Benefit Expense/(Income) | $ | (0.2) |
| $ | - |
| $ | - |
| $ | (0.1) |
| $ | 1.1 |
| $ | (1.4) |
| $ | 0.6 |
| $ | 0.1 | |
Intercompany Allocations | $ | 0.5 |
| $ | 0.3 |
| $ | 0.1 |
| $ | 0.1 |
| $ | 1.1 |
| $ | 0.1 |
| $ | 0.3 |
| $ | 0.2 | |
Capitalized PBOP Expense/(Income) | $ | - |
| $ | 0.1 |
| $ | - |
| $ | - |
| $ | 0.5 |
| $ | (0.5) |
| $ | 0.2 |
| $ | 0.1 | |
|
|
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|
|
|
|
|
|
|
|
|
|
|
|
(1) Amounts exclude approximately $1 million that represented deferred regulatory assets. |
3124
|
| PBOP | |||||||||||||||||||
|
| For the Three Months Ended June 30, 2014 |
| For the Three Months Ended June 30, 2013 | |||||||||||||||||
(Millions of Dollars) | CL&P |
|
| NSTAR Electric |
|
| PSNH |
|
| WMECO |
| CL&P |
| PSNH |
| WMECO | |||||
Service Cost | $ | 0.5 |
| $ | 0.8 |
| $ | 0.3 |
| $ | 0.1 |
| $ | 0.9 |
| $ | 0.6 |
| $ | 0.2 | |
Interest Cost |
| 1.9 |
|
| 4.8 |
|
| 1.0 |
|
| 0.4 |
|
| 2.0 |
|
| 1.0 |
|
| 0.4 | |
Expected Return on Plan Assets |
| (2.5) |
|
| (6.5) |
|
| (1.3) |
|
| (0.6) |
|
| (2.5) |
|
| (1.3) |
|
| (0.6) | |
Actuarial Loss/(Gain) |
| 1.0 |
|
| (0.2) |
|
| 0.6 |
|
| 0.1 |
|
| 1.9 |
|
| 0.9 |
|
| 0.3 | |
Prior Service Credit |
| - |
|
| (0.5) |
|
| - |
|
| - |
|
| - |
|
| - |
|
| - | |
Total Net Periodic Benefit Expense/(Income) | $ | 0.9 |
| $ | (1.6) |
| $ | 0.6 |
| $ | 0.0 |
| $ | 2.3 |
| $ | 1.2 |
| $ | 0.3 | |
Intercompany Allocations | $ | 1.1 |
| $ | - |
| $ | 0.3 |
| $ | 0.2 |
| $ | 1.9 |
| $ | 0.4 |
| $ | 0.3 | |
Capitalized PBOP Expense/(Income) | $ | 0.5 |
| $ | (0.5) |
| $ | 0.2 |
| $ | - |
| $ | 1.2 |
| $ | 0.4 |
| $ | 0.2 | |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| PBOP | |||||||||||||||||||
|
| For the Six Months Ended June 30, 2014 |
| For the Six Months Ended June 30, 2013 | |||||||||||||||||
(Millions of Dollars) | CL&P |
|
| NSTAR Electric |
|
| PSNH |
|
| WMECO |
| CL&P |
| PSNH |
| WMECO | |||||
Service Cost | $ | 1.1 |
| $ | 1.6 |
| $ | 0.7 |
| $ | 0.2 |
| $ | 1.7 |
| $ | 1.1 |
| $ | 0.4 | |
Interest Cost |
| 4.0 |
|
| 9.7 |
|
| 2.1 |
|
| 0.8 |
|
| 3.9 |
|
| 2.0 |
|
| 0.8 | |
Expected Return on Plan Assets |
| (5.2) |
|
| (13.0) |
|
| (2.7) |
|
| (1.1) |
|
| (5.0) |
|
| (2.6) |
|
| (1.2) | |
Actuarial Loss/(Gain) |
| 2.1 |
|
| (0.3) |
|
| 1.1 |
|
| 0.2 |
|
| 3.7 |
|
| 1.8 |
|
| 0.6 | |
Prior Service Credit |
| - |
|
| (0.9) |
|
| - |
|
| - |
|
| - |
|
| - |
|
| - | |
Total Net Periodic Benefit Expense/(Income) | $ | 2.0 |
| $ | (2.9) |
| $ | 1.2 |
| $ | 0.1 |
| $ | 4.3 |
| $ | 2.3 |
| $ | 0.6 | |
Intercompany Allocations | $ | 2.2 |
| $ | 0.1 |
| $ | 0.6 |
| $ | 0.4 |
| $ | 3.6 |
| $ | 0.8 |
| $ | 0.6 | |
Capitalized PBOP Expense/(Income) | $ | 1.0 |
| $ | (1.0) |
| $ | 0.4 |
| $ | 0.1 |
| $ | 2.4 |
| $ | 0.7 |
| $ | 0.4 |
(1)
NSTAR Electric's pension amounts for the three and six months ended June 30, 2013 do not include SERP expense.
For the three and six months ended June 30, 2013, the net periodic PBOP expense allocated to NSTAR Electric was a benefit of $2 million and an expense of $2.3 million, respectively.
As of December 31, 2013, the funded status of the NSTAR Pension Plan was recorded on NSTAR Electric's balance sheet while the total SERP obligation and PBOP Plan funded status were recorded on NSTAR Electric & Gas' balance sheet. As of December 31, 2013, all NSTAR employees were employed by NSTAR Electric & Gas. On January 1, 2014, NSTAR Electric & Gas was merged into NUSCO and, concurrently, all employees were transferred to the company they predominately provide services for: NUSCO, NSTAR Electric or NSTAR Gas. As a result of the employee transfers, the pension and PBOP assets and liabilities were attributed by participant and transferred to the respective company's balance sheets.
As of June 30, 2014, the liabilities associated with the Pension, SERP and PBOP plans for NSTAR Electric were $85.8 million for the Pension Plan, $3.6 million for the SERP Plans ($0.4 million of which is included in other current liabilities) and $61.2 million for the PBOP Plan. As of December 31, 2013, the liability associated with the NSTAR Pension Plan for NSTAR Electric was $118 million. This change had no impact on the income statement or net assets of NSTAR Electric or NU.
8.
COMMITMENTS AND CONTINGENCIES
A.
Environmental Matters
General: NU,Eversource, 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,Eversource, CL&P, NSTAR Electric, PSNH and WMECO have an active environmental auditing and training program and believe that they are substantially in compliance with all enacted laws and regulations.
The number of environmental sites and reserves related to these sites for which remediation or long-term monitoring, preliminary site work or site assessment are being performed are as follows:
| As of June 30, 2014 |
|
| As of December 31, 2013 | As of March 31, 2015 |
|
| As of December 31, 2014 | ||||||||||||||||
|
|
|
| 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 |
| 66 |
| $ | 34.5 |
| 68 |
| $ | 35.4 | ||||||||||||||
ES |
| 65 |
| $ | 43.6 |
| 65 |
| $ | 43.3 | ||||||||||||||
CL&P |
| 17 |
| 4.2 |
| 18 |
| 3.4 |
| 16 |
| 5.0 |
| 16 |
| 3.8 | ||||||||
NSTAR Electric |
| 14 |
| 1.2 |
|
| 12 |
| 1.2 |
| 14 |
| 1.7 |
|
| 13 |
| 1.1 | ||||||
PSNH |
| 13 |
| 5.3 |
| 15 |
| 5.4 |
| 12 |
| 3.4 |
| 13 |
| 5.2 | ||||||||
WMECO |
| 5 |
| 0.6 |
| 5 |
| 0.4 |
| 4 |
| 0.6 |
| 4 |
| 0.5 |
Included in the NUEversource number of sites and reserve amounts above are former MGP sites that were operated several decades ago and manufactured gas from coal and other processes, which resulted in certain by-products remaining in the environment that may pose a potential risk to human health and the environment. The reserve balance related to these former MGP sites was $29.8$35.4 million and $31.4$38.8 million as of June 30, 2014March 31, 2015 and December 31, 2013,2014, respectively, and relates primarily to the natural gas business segment.
32
B.
Long-Term Contractual Arrangements
The following is an update to the current status of long-term contractual arrangements set forth in Note 12B of the NU 2013 Form 10-K.
Renewable Energy: Renewable energy contracts include non-cancelable commitments under contracts of NSTAR Electric and WMECO for the purchase of energy and capacity from renewable energy facilities.
| July - December |
|
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|
|
|
|
|
|
|
| |
(Millions of Dollars) | 2014 |
| 2015 |
| 2016 |
| 2017 |
| 2018 |
| Thereafter |
| Total | |||||||
Renewable Energy |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
NSTAR Electric | $ | 43.6 |
| $ | 86.3 |
| $ | 93.7 |
| $ | 89.8 |
| $ | 53.3 |
| $ | 302.8 |
| $ | 669.5 |
WMECO |
| - |
|
| - |
|
| 2.4 |
|
| 2.4 |
|
| 2.4 |
|
| 28.9 |
|
| 36.1 |
C.
Contractual Obligations – Yankee Companies
Spent Nuclear Fuel Litigation - DOE Phase II Damages - On November 15, 2013, the Court of Federal Claims issued an award to CYAPC for $126.3 million, YAEC for $73.3 million and MYAPC for $35.8 million for lawsuits against the DOE seeking recovery of actual damages incurred in the years following 2001 and 2002 (DOE Phase II Damages). On January 14, 2014, the Yankee Companies received a letter from the U.S. Department of Justice stating that the DOE will not appeal the court's final judgment.
On March 28, 2014, CYAPC, YAEC and MYAPC received payment of $90 million, $73.3 million and $35.8 million, respectively, of the DOE Phase II Damages proceeds. On April 24, 2014, CYAPC received payment of the remaining $36.3 million proceeds. On April 28, 2014, the Yankee Companies made the required informational filing with FERC in accordance with the process and methodology outlined in the 2013 FERC order. The Yankee Companies returned the DOE Phase II Damages proceeds to the member companies, including CL&P, NSTAR Electric, PSNH, and WMECO, for the benefit of their respective customers, on June 1, 2014.
As of June 30, 2014, CL&P's refund obligation to customers of $65.4 million was recorded as an offset to the deferred storm restoration costs regulatory asset, as directed by PURA. NSTAR Electric's, PSNH's and WMECO's refund obligation to customers of $29.1 million, $13.1 million and $18.1 million, respectively, was recorded as a regulatory liability in each company's respective regulatory tracker mechanisms. For further information, see Note 2, "Regulatory Accounting," to the financial statements.
DOE Phase III Damages - On August 15, 2013, the Yankee Companies each filed subsequent lawsuits against the DOE seeking recovery of actual damages incurred in the years 2009 through 2012. Responsive pleading from the U.S. Department of Justice was filed on November 18, 2013, and discovery has begun.
D.
Guarantees and Indemnifications
NUES parent provides credit assurances on behalf of its subsidiaries, including CL&P, NSTAR Electric, PSNH and WMECO, in the form of guarantees in the normal course of business.
NU provided guarantees and various indemnifications on behalf of external parties as a result of the sales of former subsidiaries of NU Enterprises and the termination of an unregulated business, with maximum exposures either not specified or not material.
NUES parent also issued a guaranty under which, beginning at the time the Northern Pass Transmission line goes into commercial operation, NUES parent will guarantee the financial obligations of NPT under the TSA in an amount not to exceed $25 million. NU'sES parent's obligations under the guaranty expire upon the full, final and indefeasible payment of the guaranteed obligations.
ES parent has also guaranteed certain indemnification and other obligations as a result of the sales of former unregulated subsidiaries and the termination of an unregulated business, with maximum exposures either not specified or not material.
Management does not anticipate a material impact to Net Income as a result of these various guarantees and indemnifications.
The following table summarizes NU'sES parent's guarantees of its subsidiaries, including CL&P, NSTAR Electric, PSNH and WMECO, as of June 30, 2014:March 31, 2015:
|
|
|
| Maximum Exposure |
|
|
| |||
|
| Description |
| (in millions) |
| Expiration Dates | ||||
Various |
| Surety Bonds |
|
|
| |||||
| $ | |||||||||
|
|
|
|
|
| |||||
|
|
|
|
|
|
|
|
| ||
|
| Lease Payments for Vehicles and Real Estate |
| $ |
| 13.8 |
| 2019 and 2024 |
(1)
Surety bond expiration dates reflect termination dates, the majority of which will be renewed or extended.
Certain surety bonds contain credit ratings triggers that would require NUES parent to post collateral in the event that the unsecured debt credit ratings of NUEversource are downgraded.
E.C.
FERC Base ROE Complaints
On September 30,Beginning in 2011, a complaint wasthree separate complaints were filed jointly at FERC under Sections 206 and 306by combinations of the Federal Power Act by several New England state attorneys general, state regulatory commissions, consumer advocates, consumer groups, municipal parties and other parties (the "Complainants"). TheIn the first complaint, filed in 2011, the Complainants alleged that the NETOs' base ROE of 11.14 percent that has beenwas utilized since 2006 in the calculation of formula rates for transmission service under the ISO-NE Open Access Transmission Tariff by NETOs, including CL&P, NSTAR Electric, PSNH and WMECO, was unjust and unreasonable, and asserted that the rate was excessive due to changes in the capital markets. Complainantsmarkets, and sought an order to reduce it prospectively from the base ROE, effectivedate of the final FERC order and for the 15-month period beginning October 1, 2011 to December 31, 2012 (the "first complaint refund period"). In the second and to require refunds. The FERC setthird complaints, filed in 2012 and 2014, the caseComplainants challenged the NETOs' base ROE and sought refunds for trial before a FERC ALJ after settlement negotiations were unsuccessful in August 2012.
33the 15-month periods beginning December 27, 2012 and July 31, 2014.
On August 6, 2013,In 2014, the FERC ALJ issued an initial decision findingdetermined that the base ROE in effect from October 1, 2011 through December 31, 2012 (refund period) was not reasonable, and recommended separate base ROEs for the refund period of 10.6 percent and for the period beginning when FERC issues its final decision (prospective period) of 9.7 percent, leaving policy considerations and additional adjustments to the FERC. In the third quarter of 2013, the Company recorded a series of reservesshould be set at its electric subsidiaries to recognize the potential financial impact from the FERC ALJ's initial decision for the refund period. The aggregate after-tax charge to third quarter 2013 earnings totaled $14.3 million at NU, which represented reserves of $7.7 million at CL&P, $3.4 million at NSTAR Electric, $1.4 million at PSNH and $1.8 million at WMECO.
On June 19, 2014, FERC issued an order partially affirming and partially reversing the ALJ's initial decision. FERC set a single tentative base ROE of 10.57 percent for the first complaint refund period and prospective period. FERC also modified its traditional methodology by adopting a two-step discounted cash flow analysis that it utilizes to determine the ROEs of both natural gas and oil pipeline projects. Using this methodology, FERC determined a new zone of reasonableness of 7.03 percent to 11.74 percent, and set the tentative base ROE at the 75th percentile of this new zone. FERC also stated that a utility's total or maximum ROE inclusive of transmission incentive ROE adders, should not exceed the top of the new zone of reasonableness, producedwhich was set at 11.74 percent. The FERC ordered the NETOs to provide refunds to customers for the first complaint refund period and set the new base ROE of 10.57 percent prospectively from October 16, 2014. The NETOs and the Complainants sought rehearing from FERC. In late 2014, the NETOs made a compliance filing, which was challenged by this methodology.the Complainants, and the Company began refunding amounts from the first complaint period.
On March 3, 2015, FERC instituted a paper hearingissued an order denying all issues raised on the long-term growth rate portion of the methodology, before it issues a final determination on the base ROE. On July 21, 2014,rehearing by the NETOs and Complainants filed rehearing requests in this proceeding. the first base ROE complaint. The FERC order upheld the base ROE of 10.57 percent for the first complaint refund period and prospectively from October 16, 2014, and upheld that the utility's total ROE (the base ROEplus anyincentive adders) for the transmission assets to which the adder applies is capped at the top of the zone of reasonableness, which is currently set at 11.74 percent. As a result ofclarifying information related to how the ROE cap is applied, which is
25
On December 27, 2012, a second complaint was filed jointly at FERC by several additional consumer groups and municipal parties, which challenged the NETOs' base ROE and sought refunds for the 15-month period beginning January 1, 2013. On June 19, 2014, the FERC issued a second order finding that the complaint raised issues of material fact, and set this complaint for trial, should settlement negotiations be unsuccessful. FERC stated that it could issue an order in this case by mid-2016. On July 21, 2014, the NETOs filed a rehearing request in this proceeding.
Though NU cannot predict the ultimate outcome of this proceeding,contained in the secondorder, Eversource adjusted its reservein the first quarter of 2014, the Company recorded2015 and recognized a series of reserves at its electric subsidiaries to recognize the potential financial impact from the FERC’s two orders issued on June 19, 2014 for the two refund periods. The aggregate after-taxpre-tax charge to second quarter 2014 earnings totaled $32.1(excluding interest) of $20 million, at NU,of which represented reserves of $18.5$12.5 million was recorded at CL&P, $6.1$2.4 million at NSTAR Electric, $2$1 million at PSNH, and $5.5 million at WMECO.
As of June 30, 2014, the cumulative pre-tax reserves totaled $79.3 million at NU, $44.7 million at CL&P, $16.2 million at NSTAR Electric, $6.2 million at PSNH and $12.2 million at WMECO. As of December 31, 2013, the pre-tax reserves totaled $24.6 million at NU, $13.3 million at CL&P, $5.9 million at NSTAR Electric, $2.4 million at PSNH and $3$4.1 million at WMECO. The reserves werepre-tax charge was recorded in each electric subsidiary's respective transmissionas a regulatory tracker mechanismliability and as a reduction of operating revenues. See Note 2, “Regulatory Accounting,” for further information.Operating Revenues.
On July 31, 2014, the Complainants filed an additional complaint with FERC. At this time, the Company cannot determine the outcome of this complaint.
F.D.
CPSL2014 Comprehensive Settlement Agreement
Since 2006,On March 2, 2015, the DPU approved the comprehensive settlement agreement between NSTAR Electric, has been recovering incremental costs related toNSTAR Gas and the DPU-approved Safety and Reliability Programs. FromMassachusetts Attorney General (the "Settlement") as filed with the DPU on December 31, 2014. The Settlement resolved the outstanding NSTAR Electric CPSL program filings for 2006 through 2011, cumulative costs associated with the CPSL program resultedNSTAR Electric and NSTAR Gas PAM and energy efficiency-related customer billing adjustments reported in an incremental revenue requirement to customers of approximately $83 million. These amounts included incremental operations and maintenance costs2012, and the recovery of LBR related revenue requirementto NSTAR Electric's energy efficiency programs for specific capital investments relative2008 through 2011 (11 dockets in total). As a result, NSTAR Electric and NSTAR Gas will refund $42.5 million and $2.2 million, respectively, to customers. The refund was recorded as a regulatory liability as of March 31, 2015 and NSTAR Electric recognized a $21.7 million pre-tax benefit in the CPSL programs.first quarter of 2015.
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. E.
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.
Basic Service Bad Debt Adder
In accordance with a generic 2005 DPU order, electric utilities in Massachusetts recover the energy-related portion of bad debt costs in their Basic Service rates. In February 2007, NSTAR Electric filed its 2005 through 2006 Basic Service reconciliation with the DPU proposing an adjustment related to the increase of its Basic Service bad debt charge-offs. TheIn June 2007, the DPU issued an order approvingapproved NSTAR Electric's proposed adjustment to the implementation of a revised Basic Service rateAdder but instructed NSTAR Electric to reduce distribution rates by an amount equal to the increase in its Basic Service bad debt charge-offs.and offsetting amount. This adjustment to NSTAR Electric's distribution rates would eliminatehave eliminated 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. NSTAR Electric took the position that it had fully removed the collection of energy-related bad debt costs from its base distribution rates effective January 1, 2006; therefore, no further adjustment to distribution rates was warranted. 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.
On January 7, 2015, the DPU issued an order concluding that NSTAR Electric deferred approximately $34 millionhad appropriately accounted for the removal of supply-related bad debt costs associated withfrom base distribution rates effective January 1, 2006. The DPU ordered NSTAR Electric and the Massachusetts Attorney General to collaborate on the reconciliation of energy-related bad debt costs through 2014. During the second quarter of 2015, NSTAR Electric expects to file with the DPU to recover from customers approximately $43 million of supply-related bad debt costs. In the first quarter of 2015, as a regulatory asset through 2011 asresult of the DPU order, NSTAR Electric had concluded that it was probable that these costs would ultimately be recovered from customers. Due to the delaysincreased its regulatory assets and the durationreduced Operations and Maintenance expense by $24.2 million, resulting in an increase in after-tax earnings of the proceedings, NSTAR Electric concluded that while an ultimate outcome on the matter in its favor remained "more likely than not," it could no longer be deemed "probable." As a result, NSTAR Electric recognized a reserve related to the regulatory asset in 2012. NSTAR Electric will continue to maintain the reserve until the proceeding has been concluded with the DPU.$14.5 million.
F.
34PSNH Generation Restructuring
On March 11, 2015, PSNH and key New Hampshire officials entered into an agreement in principle in a settlement Term Sheet. Under the Term Sheet, PSNH has agreed to pursue the divestiture of its generation assets upon NHPUC approval of a final Settlement Agreement reflecting the provisions of the Term Sheet, and PSNH will not seek a general distribution rate increase that would become effective before July 1, 2017. PSNH will contribute $5 million to create a clean energy fund, which will not be recoverable from its customers, and will record this liability and related charge upon completion of the Settlement Agreement.
9.
FAIR VALUE OF FINANCIAL INSTRUMENTS
The following methods and assumptions were used to estimate the fair value of each of the following financial instruments:
Preferred Stock and Long-Term Debt: The fair value of CL&P's and NSTAR Electric's preferred stock is based upon pricing models that incorporate interest rates and other market factors, valuations or trades of similar securities and cash flow projections. The fair value of fixed-rate long-term debt securities is based upon pricing models that incorporate quoted market prices for those issues or similar issues adjusted for market conditions, credit ratings of the respective companies and treasury benchmark yields. Adjustable rate long-term debt securities are assumed to have a fair value equal to their carrying value. The fair values provided in the tables below are classified as Level 2 within the fair value hierarchy. Carrying amounts and estimated fair values are as follows:
|
| As of June 30, 2014 |
| As of December 31, 2013 |
| As of March, 31, 2015 |
| As of December 31, 2014 | ||||||||||||||||
|
| NU |
| NU |
| ES |
| ES | ||||||||||||||||
|
| Carrying |
| Fair |
| Carrying |
| Fair |
| Carrying |
| Fair |
| Carrying |
| Fair | ||||||||
(Millions of Dollars) | (Millions of Dollars) | Amount |
| Value |
| Amount |
| Value | (Millions of Dollars) | Amount |
| Value |
| Amount |
| Value | ||||||||
Preferred Stock Not | Preferred Stock Not | $ | 155.6 |
| $ | 150.1 |
| $ | 155.6 |
| $ | 152.7 | Preferred Stock Not | $ | 155.6 |
| $ | 155.1 |
| $ | 155.6 |
| $ | 153.6 |
Long-Term Debt | Long-Term Debt |
| 8,542.7 |
| 9,008.4 |
| 8,310.2 |
| 8,443.1 | Long-Term Debt |
| 8,847.7 |
| 9,553.1 |
| 8,851.6 |
| 9,451.2 |
|
| As of June 30, 2014 |
| As of March 31, 2015 | ||||||||||||||||||||||||||||||||||||||||||||
|
| 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 | (Millions of Dollars) | Amount |
| Value |
| Amount |
| Value |
| Amount |
| Value |
| Amount |
| Value | ||||||||||||||||
Preferred Stock Not | Preferred Stock Not | $ | 116.2 |
| $ | 110.3 |
| $ | 43.0 |
| $ | 39.8 |
| $ | - |
| $ | - |
| $ | - |
| $ | - | Preferred Stock Not | $ | 116.2 |
| $ | 113.0 |
| $ | 43.0 |
| $ | 42.1 |
| $ | - |
| $ | - |
| $ | - |
| $ | - |
Long-Term Debt | Long-Term Debt |
| 2,991.6 |
| 3,344.5 |
| 1,797.4 |
| 1,949.8 |
| 1,049.2 |
| 1,105.8 |
| 628.9 |
| 665.3 | Long-Term Debt |
| 2,842.1 |
| 3,260.4 |
| 1,797.4 |
| 2,022.1 |
| 1,076.3 |
| 1,156.4 |
| 628.2 |
| 674.4 | ||||||||||||||
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| |||||||||||||||||||||||||||||||
|
| 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 | $ | 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 |
26
|
| As of December 31, 2014 | ||||||||||||||||||||||
|
| 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 | $ | 116.2 |
| $ | 112.0 |
| $ | 43.0 |
| $ | 41.6 |
| $ | - |
| $ | - |
| $ | - |
| $ | - | |
Long-Term Debt |
| 2,842.0 |
|
| 3,214.5 |
|
| 1,797.4 |
|
| 1,993.5 |
|
| 1,076.3 |
|
| 1,137.9 |
|
| 628.5 |
|
| 689.4 |
Derivative Instruments: Derivative instruments are carried at fair value. For further information, see Note 4, "Derivative Instruments," to the financial statements.
Other Financial Instruments: Investments in marketable securities are carried at fair value. For further information, see Note 1D, "Summary of Significant Accounting Policies - Fair Value Measurements," and Note 5, "Marketable Securities," to the financial statements. The carrying value of other financial instruments included in current assets and current liabilities, including cash and cash equivalents and special deposits, approximates their fair value due to the short-term nature of these instruments.
See Note 1D, "Summary of Significant Accounting Policies - Fair Value Measurements," for the fair value measurement policy and the fair value hierarchy.
10.
ACCUMULATED OTHER COMPREHENSIVE INCOME/(LOSS)
The changes in accumulated other comprehensive income/(loss) by component, net of tax, is as follows:
|
| For the Six Months Ended June 30, 2014 |
| For the Six Months Ended June 30, 2013 | ||||||||||||||||||||||||||||||||||||||||||||
|
|
|
| Unrealized |
| Pension, |
|
|
|
|
| Unrealized |
| Pension, |
|
|
| For the Three Months Ended March 31, 2015 |
| For the Three Months Ended March 31, 2014 | ||||||||||||||||||||||||||||
|
| Qualified |
| Gains/(Losses) |
| SERP and |
|
|
| Qualified |
| Gains/(Losses) |
| SERP and |
|
|
| Qualified |
| Unrealized |
|
|
|
|
| Qualified |
| Unrealized |
|
|
|
| ||||||||||||||||
|
| Cash Flow |
| on Available- |
| PBOP |
|
|
| Cash Flow |
| on Available- |
| PBOP |
|
|
| Cash Flow |
| Gains on |
| Defined |
|
|
| Cash Flow |
| Gains on |
| Defined |
|
| ||||||||||||||||
|
| Hedging |
| for-Sale |
| Benefit |
|
|
| Hedging |
| for-Sale |
| Benefit |
|
|
| Hedging |
| Marketable |
| Benefit |
|
|
| Hedging |
| Marketable |
| Benefit |
|
| ||||||||||||||||
(Millions of Dollars) | (Millions of Dollars) | Instruments |
| Securities |
| Plans |
| Total |
| Instruments |
| Securities |
| Plans |
| Total | (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) | |||||||||||||||||||||||||
Balance as of Beginning of Period | Balance as of Beginning of Period | $ | (12.4) |
| $ | 0.7 |
| $ | (62.3) |
| $ | (74.0) |
| $ | (14.4) |
| $ | 0.4 |
| $ | (32.0) |
| $ | (46.0) | ||||||||||||||||||||||||
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| ||||||||
OCI Before Reclassifications | OCI Before Reclassifications |
| - |
| 0.5 |
| 1.2 |
|
| 1.7 |
|
| - |
| (0.7) |
| - |
|
| (0.7) | OCI Before Reclassifications |
| - |
| 0.1 |
| - |
|
| 0.1 |
|
| - |
| 0.2 |
| - |
|
| 0.2 | ||||||||
Amounts Reclassified from AOCI | Amounts Reclassified from AOCI |
| 1.0 |
|
| - |
|
| 1.8 |
|
| 2.8 |
|
| 1.0 |
|
| - |
|
| 3.1 |
|
| 4.1 | Amounts Reclassified from AOCI |
| 0.5 |
|
| - |
|
| 1.0 |
|
| 1.5 |
|
| 0.5 |
|
| - |
|
| 1.0 |
|
| 1.5 |
Net OCI | Net OCI |
| 1.0 |
|
| 0.5 |
|
| 3.0 |
|
| 4.5 |
|
| 1.0 |
|
| (0.7) |
|
| 3.1 |
|
| 3.4 | Net OCI |
| 0.5 |
|
| 0.1 |
|
| 1.0 |
|
| 1.6 |
|
| 0.5 |
|
| 0.2 |
|
| 1.0 |
|
| 1.7 |
AOCI as of End of Period | $ | (13.4) |
| $ | 0.9 |
| $ | (29.0) |
| $ | (41.5) |
| $ | (15.4) |
| $ | 0.6 |
| $ | (54.7) |
| $ | (69.5) | |||||||||||||||||||||||||
Balance as of End of Period | Balance as of End of Period | $ | (11.9) |
| $ | 0.8 |
| $ | (61.3) |
| $ | (72.4) |
| $ | (13.9) |
| $ | 0.6 |
| $ | (31.0) |
| $ | (44.3) |
NU'sEversource's qualified cash flow hedging instruments represent interest rate swap agreements on debt issuances that were settled in prior years. The settlement amount was recorded in AOCI and is being amortized into Net Income over the term of the underlying debt instrument. CL&P, PSNH and WMECO continue to amortize interest rate swaps settled in prior years from AOCI into Interest Expense over the remaining life of the associated long-term debt, which are not material to their respective financial statements.
35
The following table sets forthamortization expense of actuarial gains and losses on the defined benefit plans is amortized from AOCI into Operations and Maintenance over the average future employee service period, and are reflected in amounts reclassified from AOCI by componentAOCI. The related tax effects of the reclassification adjustments are not material to the financial statements for the three months ended March 31, 2015 and the impacted line item on the statements of income:
| For the Three Months Ended |
| For the Six Months Ended |
|
| ||||||||
| June 30, |
| June 30, |
|
| ||||||||
| Amounts Reclassified |
| Amounts Reclassified |
| Statements of Income | ||||||||
| from AOCI |
| from AOCI |
| Line Item Impacted | ||||||||
(Millions of Dollars) | 2014 |
| 2013 |
| 2014 |
| 2013 |
|
| ||||
Qualified Cash Flow Hedging Instruments | $ | (0.8) |
| $ | (0.8) |
| $ | (1.7) |
| $ | (1.7) |
| Interest Expense |
Tax Benefit |
| 0.3 |
|
| 0.3 |
|
| 0.7 |
|
| 0.7 |
| Income Tax Expense |
Qualified Cash Flow Hedging Instruments, Net of Tax | $ | (0.5) |
| $ | (0.5) |
| $ | (1.0) |
| $ | (1.0) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Pension, SERP and PBOP Benefit Plan Costs: |
|
|
|
|
|
|
|
|
|
|
|
|
|
Amortization of Actuarial Losses | $ | (1.2) |
| $ | (2.2) |
| $ | (2.9) |
| $ | (4.7) |
| Operations and Maintenance (1) |
Amortization of Prior Service Cost |
| - |
|
| - |
|
| (0.1) |
|
| (0.1) |
| Operations and Maintenance (1) |
Total Pension, SERP and PBOP Benefit Plan Costs |
| (1.2) |
|
| (2.2) |
|
| (3.0) |
|
| (4.8) |
|
|
Tax Benefit |
| 0.5 |
|
| 0.7 |
|
| 1.2 |
|
| 1.7 |
| Income Tax Expense |
Pension, SERP and PBOP Benefit Plan Costs, Net of Tax | $ | (0.7) |
| $ | (1.5) |
| $ | (1.8) |
| $ | (3.1) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total Amounts Reclassified from AOCI, Net of Tax | $ | (1.2) |
| $ | (2.0) |
| $ | (2.8) |
| $ | (4.1) |
|
|
(1)
These amounts are included in the computation of net periodic Pension, SERP and PBOP costs. See Note 7, "Pension Benefits and Postretirement Benefits Other Than Pensions," for further information.2014.
11.
COMMON SHARES
The following table sets forth the NUES parent common shares and the shares of common stock of CL&P, NSTAR Electric, PSNH and WMECO that were authorized and issued and the respective per share par values:
| Shares | Shares | ||||||||||||||
|
|
|
| Authorized as of |
|
|
|
|
|
|
| Authorized as of |
|
|
|
|
| Per Share |
| June 30, 2014 and |
| Issued as of | Per Share |
| March 31, 2015 and |
| Issued as of | ||||||
| Par Value |
| December 31, 2013 |
| June 30, 2014 |
| December 31, 2013 | Par Value |
| December 31, 2014 |
| March 31, 2015 |
| December 31, 2014 | ||
NU | $ | 5 |
| 380,000,000 |
| 333,327,485 |
| 333,113,492 | ||||||||
ES | $ | 5 |
| 380,000,000 |
| 333,607,844 |
| 333,359,172 | ||||||||
CL&P | $ | 10 |
| 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 |
| 100 | $ | 1 |
| 100,000,000 |
| 100 |
| 100 |
PSNH | $ | 1 |
| 100,000,000 |
| 301 |
| 301 | $ | 1 |
| 100,000,000 |
| 301 |
| 301 |
WMECO | $ | 25 |
| 1,072,471 |
| 434,653 |
| 434,653 | $ | 25 |
| 1,072,471 |
| 434,653 |
| 434,653 |
As of June 30, 2014March 31, 2015 and December 31, 2013,2014, there were 17,108,13116,138,845 and 17,796,672 NU16,375,835 Eversource common shares held as treasury shares, respectively. As of June 30, 2014March 31, 2015 and December 31, 2013, NU2014, Eversource common shares outstanding were 316,219,354317,468,999 and 315,273,559,316,983,337, respectively.
12. COMMON SHAREHOLDERS' EQUITY AND NONCONTROLLING INTERESTS |
| ||||||||||||||
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
A summary of the changes in Common Shareholders' Equity and Noncontrolling Interests of NU is as follows: | |||||||||||||||
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| For the Three Months Ended |
| ||||||||||
|
|
|
| June 30, 2014 |
| June 30, 2013 |
| ||||||||
|
|
|
|
|
|
| Noncontrolling |
|
|
|
| Noncontrolling |
| ||
|
|
|
|
|
| Interest - |
|
|
|
| Interest - |
| |||
|
|
|
| Common |
| Preferred |
| Common |
| Preferred |
| ||||
|
|
|
| Shareholders' |
| Stock of |
| Shareholders' |
| Stock of |
| ||||
(Millions of Dollars) | Equity |
| Subsidiaries |
| Equity |
| Subsidiaries |
| |||||||
Balance as of Beginning of Period | $ | 9,723.9 |
| $ | 155.6 |
| $ | 9,345.2 |
| $ | 155.6 |
| |||
Net Income |
| 129.2 |
|
| - |
|
| 173.1 |
|
| - |
| |||
Dividends on Common Shares |
| (124.1) |
|
| - |
|
| (115.6) |
|
| - |
| |||
Dividends on Preferred Stock |
| (1.9) |
|
| (1.9) |
|
| (2.0) |
|
| (2.0) |
| |||
Issuance of Common Shares |
| 0.2 |
|
| - |
|
| 0.3 |
|
| - |
| |||
Other Transactions, Net |
| 23.7 |
|
| - |
|
| 4.2 |
|
| - |
| |||
Net Income Attributable to Noncontrolling Interests |
| - |
|
| 1.9 |
|
| - |
|
| 2.0 |
| |||
Other Comprehensive Income |
| 2.8 |
|
| - |
|
| 1.4 |
|
| - |
| |||
Balance as of End of Period | $ | 9,753.8 |
| $ | 155.6 |
| $ | 9,406.6 |
| $ | 155.6 |
| |||
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
12.
COMMON SHAREHOLDERS' EQUITY AND NONCONTROLLING INTERESTS
For the three months ended March 31, 2015 and 2014, there were dividends on the preferred stock of CL&P and NSTAR Electric of $1.9 million, which were presented as Net Income Attributable to Noncontrolling Interests on the Eversource statements of income. Common Shareholders' Equity was fully attributable to the parent and Noncontrolling Interest – Preferred Stock of Subsidiaries was fully attributable to the noncontrolling interest on the Eversource balance sheets.
3627
|
|
|
| For the Six Months Ended |
| ||||||||||
|
|
|
| June 30, 2014 |
| June 30, 2013 |
| ||||||||
|
|
|
|
|
|
| Noncontrolling |
|
|
|
| Noncontrolling |
| ||
|
|
|
|
|
| Interest - |
|
|
|
| Interest - |
| |||
|
|
|
| Common |
| Preferred |
| Common |
| Preferred |
| ||||
|
|
|
| Shareholders' |
| Stock of |
| Shareholders' |
| Stock of |
| ||||
(Millions of Dollars) | Equity |
| Subsidiaries |
| Equity |
| Subsidiaries |
| |||||||
Balance as of Beginning of Period | $ | 9,611.5 |
| $ | 155.6 |
| $ | 9,237.1 |
| $ | 155.6 |
| |||
Net Income |
| 367.1 |
|
| - |
|
| 403.0 |
|
| - |
| |||
Dividends on Common Shares |
| (247.9) |
|
| - |
|
| (232.1) |
|
| - |
| |||
Dividends on Preferred Stock |
| (3.8) |
|
| (3.8) |
|
| (3.9) |
|
| (3.9) |
| |||
Issuance of Common Shares |
| 5.4 |
|
| - |
|
| 8.8 |
|
| - |
| |||
Other Transactions, Net |
| 17.0 |
|
| - |
|
| (9.7) |
|
| - |
| |||
Net Income Attributable to Noncontrolling Interests |
| - |
|
| 3.8 |
|
| - |
|
| 3.9 |
| |||
Other Comprehensive Income |
| 4.5 |
|
| - |
|
| 3.4 |
|
| - |
| |||
Balance as of End of Period | $ | 9,753.8 |
| $ | 155.6 |
| $ | 9,406.6 |
| $ | 155.6 |
|
13.
EARNINGS PER SHARE
Basic EPS is computed based upon the weighted average number of common shares outstanding during each period. Diluted EPS is computed on the basis of the weighted average number of common shares outstanding plus the potential dilutive effect of certain share-based compensation awards as if they were converted into common shares. There were no antidilutive share awards outstanding for the three and six months ended June 30, 2014 or forFor the three months ended June 30, 2013. For the six months ended June 30, 2013,March 31, 2015 and 2014, there were 3,150no antidilutive share awards excluded from the computation.
The following table sets forth the components of basic and diluted EPS:
|
| For the Three Months Ended |
| For the Six Months Ended |
| For the Three Months Ended | ||||||||||||
(Millions of Dollars, except share information) | (Millions of Dollars, except share information) | June 30, 2014 |
| June 30, 2013 |
| June 30, 2014 |
| June 30, 2013 | (Millions of Dollars, except share information) | March 31, 2015 |
| March 31, 2014 | ||||||
Net Income Attributable to Controlling Interest | Net Income Attributable to Controlling Interest | $ | 127.4 |
| $ | 171.0 |
| $ | 363.3 |
| $ | 399.1 | Net Income Attributable to Controlling Interest | $ | 253.3 |
| $ | 236.0 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| ||||
Weighted Average Common Shares Outstanding: | Weighted Average Common Shares Outstanding: |
|
|
|
|
|
|
|
| Weighted Average Common Shares Outstanding: |
|
|
|
| ||||
| Basic |
| 315,950,510 |
| 315,154,130 |
| 315,742,511 |
| 315,141,956 | Basic |
| 317,090,841 |
| 315,534,512 | ||||
| Dilutive Effect |
| 1,162,291 |
|
| 808,489 |
|
| 1,259,950 |
|
| 840,622 | Dilutive Effect |
| 1,400,347 |
|
| 1,357,607 |
| Diluted |
| 317,112,801 |
|
| 315,962,619 |
|
| 317,002,461 |
|
| 315,982,578 | Diluted |
| 318,491,188 |
|
| 316,892,119 |
Basic EPS | Basic EPS | $ | 0.40 |
| $ | 0.54 |
| $ | 1.15 |
| $ | 1.27 | Basic EPS | $ | 0.80 |
| $ | 0.75 |
Diluted EPS | Diluted EPS | $ | 0.40 |
| $ | 0.54 |
| $ | 1.15 |
| $ | 1.26 | Diluted EPS | $ | 0.80 |
| $ | 0.74 |
RSUs and performance shares are included in basic weighted average common shares outstanding as of the date that all necessary vesting conditions have been satisfied. The dilutive effect of unvested RSUs and performance shares is calculated using the treasury stock method. Assumed proceeds of these units under the treasury stock method consist of the remaining compensation cost to be recognized and a theoretical tax benefit. The theoretical tax benefit is calculated as the tax impact of the intrinsic value of the units (the difference between the market value of the average units outstanding for the period, using the average market price during the period, and the grant date market value).
The dilutive effect of stock options to purchase common shares is also calculated using the treasury stock method. Assumed proceeds for stock options consist of cash proceeds that would be received upon exercise, and a theoretical tax benefit. The theoretical tax benefit is calculated as the tax impact of the intrinsic value of the stock options (the difference between the market value of the average stock options outstanding for the period, using the average market price during the period, and the exercise price).
14.
SEGMENT INFORMATION
Presentation: NUEversource is organized between the Electric Distribution, Electric Transmission and Natural Gas Distribution reportable segments and Other based on a combination of factors, including the characteristics of each segments' products and services, the sources of operating revenues and expenses and the regulatory environment in which each segment operates. These reportable segments represented substantially all of NU'sEversource's total consolidated revenues for the three and six months ended June 30, 2014March 31, 2015 and 2013.2014. 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'sEversource's operations is presented as Other in the tables below and primarily consists of 1) the equity in earnings of NUES parent from its subsidiaries and intercompany interest income, both of which are eliminated in consolidation, and interest expense related to the debt of NUES parent, 2) the revenues and expenses of NU's service company,Eversource Service, most of which are eliminated in consolidation, 3) the operations of CYAPC and YAEC, and 4) the results of other non-regulatedunregulated subsidiaries, which are not part of its core business.
Cash flows used for investments in plant included in the segment information below are cash capital expenditures that do not include amounts incurred but not paid, cost of removal, AFUDC related to equity funds, and the capitalized portions of pension expense.
NU'sEversource's reportable segments are determined based upon the level at which NU'sEversource's chief operating decision maker assesses performance and makes decisions about the allocation of company resources. Each of NU'sEversource's subsidiaries, including CL&P, NSTAR Electric, PSNH and WMECO, has one reportable segment. NU'sEversource's operating segments and reporting units are consistent with its reportable business segments.
37
NU'sEversource's segment information is as follows:
|
| For the Three Months Ended June 30, 2014 | ||||||||||||||||
|
| Electric |
| Natural Gas |
|
|
|
|
|
|
|
|
|
|
|
| ||
(Millions of Dollars) | Distribution |
| Distribution |
| Transmission |
| Other |
| Eliminations |
| Total | |||||||
Operating Revenues | $ | 1,261.8 |
| $ | 195.5 |
| $ | 206.9 |
| $ | 184.7 |
| $ | (171.3) |
| $ | 1,677.6 | |
Depreciation and Amortization |
| (89.3) |
|
| (16.9) |
|
| (37.0) |
|
| (7.7) |
|
| 2.3 |
|
| (148.6) | |
Other Operating Expenses |
| (991.5) |
|
| (166.5) |
|
| (71.0) |
|
| (174.9) |
|
| 168.9 |
|
| (1,235.0) | |
Operating Income |
| 181.0 |
|
| 12.1 |
|
| 98.9 |
|
| 2.1 |
|
| (0.1) |
|
| 294.0 | |
Interest Expense |
| (47.2) |
|
| (8.7) |
|
| (28.8) |
|
| (9.1) |
|
| 1.3 |
|
| (92.5) | |
Other Income, Net |
| 2.9 |
|
| - |
|
| 2.7 |
|
| 137.7 |
|
| (137.8) |
|
| 5.5 | |
Net Income Attributable to Controlling Interest | $ | 83.4 |
| $ | 2.0 |
| $ | 43.9 |
| $ | 133.3 |
| $ | (135.2) |
| $ | 127.4 | |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| For the Six Months Ended June 30, 2014 | ||||||||||||||||
|
| Electric |
| Natural Gas |
|
|
|
|
|
|
|
|
|
|
|
| ||
(Millions of Dollars) | Distribution |
| Distribution |
| Transmission |
| Other |
| Eliminations |
| Total | |||||||
Operating Revenues | $ | 2,847.8 |
| $ | 628.3 |
| $ | 458.9 |
| $ | 356.9 |
| $ | (323.7) |
| $ | 3,968.2 | |
Depreciation and Amortization |
| (238.2) |
|
| (34.6) |
|
| (74.0) |
|
| (14.7) |
|
| 4.1 |
|
| (357.4) | |
Other Operating Expenses |
| (2,202.4) |
|
| (487.9) |
|
| (137.3) |
|
| (340.3) |
|
| 318.8 |
|
| (2,849.1) | |
Operating Income |
| 407.2 |
|
| 105.8 |
|
| 247.6 |
|
| 1.9 |
|
| (0.8) |
|
| 761.7 | |
Interest Expense |
| (94.6) |
|
| (17.1) |
|
| (54.3) |
|
| (18.7) |
|
| 2.2 |
|
| (182.5) | |
Other Income, Net |
| 4.3 |
|
| 0.1 |
|
| 4.2 |
|
| 432.4 |
|
| (433.8) |
|
| 7.2 | |
Net Income Attributable to Controlling Interest | $ | 195.6 |
| $ | 54.1 |
| $ | 118.8 |
| $ | 424.9 |
| $ | (430.1) |
| $ | 363.3 | |
Cash Flows Used for Investments in Plant | $ | 335.6 |
| $ | 68.6 |
| $ | 289.3 |
| $ | 30.5 |
| $ | - |
| $ | 724.0 |
|
| For the Three Months Ended June 30, 2013 | ||||||||||||||||
|
| Electric |
| Natural Gas |
|
|
|
|
|
|
|
|
|
|
|
| ||
(Millions of Dollars) | Distribution |
| Distribution |
| Transmission |
| Other |
| Eliminations |
| Total | |||||||
Operating Revenues | $ | 1,221.6 |
| $ | 154.1 |
| $ | 247.9 |
| $ | 220.7 |
| $ | (208.4) |
| $ | 1,635.9 | |
Depreciation and Amortization |
| (152.2) |
|
| (16.7) |
|
| (34.5) |
|
| (21.7) |
|
| 2.9 |
|
| (222.2) | |
Other Operating Expenses |
| (883.3) |
|
| (127.0) |
|
| (63.6) |
|
| (194.9) |
|
| 205.7 |
|
| (1,063.1) | |
Operating Income |
| 186.1 |
|
| 10.4 |
|
| 149.8 |
|
| 4.1 |
|
| 0.2 |
|
| 350.6 | |
Interest Expense |
| (43.4) |
|
| (8.9) |
|
| (25.2) |
|
| (10.7) |
|
| 1.3 |
|
| (86.9) | |
Other Income, Net |
| 2.2 |
|
| 0.1 |
|
| 2.8 |
|
| 232.2 |
|
| (232.3) |
|
| 5.0 | |
Net Income Attributable to Controlling Interest | $ | 91.2 |
| $ | 1.2 |
| $ | 76.8 |
| $ | 232.8 |
| $ | (231.0) |
| $ | 171.0 |
|
| For the Six Months Ended June 30, 2013 | ||||||||||||||||
|
| Electric |
| Natural Gas |
|
|
|
|
|
|
|
|
|
|
|
| ||
(Millions of Dollars) | Distribution |
| Distribution |
| Transmission |
| Other |
| Eliminations |
| Total | |||||||
Operating Revenues | $ | 2,595.8 |
| $ | 515.9 |
| $ | 487.4 |
| $ | 437.8 |
| $ | (406.0) |
| $ | 3,630.9 | |
Depreciation and Amortization |
| (329.1) |
|
| (34.1) |
|
| (66.3) |
|
| (40.8) |
|
| 4.6 |
|
| (465.7) | |
Other Operating Expenses |
| (1,888.3) |
|
| (394.3) |
|
| (125.8) |
|
| (392.2) |
|
| 404.9 |
|
| (2,395.7) | |
Operating Income |
| 378.4 |
|
| 87.5 |
|
| 295.3 |
|
| 4.8 |
|
| 3.5 |
|
| 769.5 | |
Interest Expense |
| (85.6) |
|
| (16.2) |
|
| (47.1) |
|
| (17.1) |
|
| 2.9 |
|
| (163.1) | |
Other Income, Net |
| 7.1 |
|
| 0.3 |
|
| 5.5 |
|
| 554.0 |
|
| (554.2) |
|
| 12.7 | |
Net Income Attributable to Controlling Interest | $ | 190.6 |
| $ | 44.5 |
| $ | 156.7 |
| $ | 555.5 |
| $ | (548.2) |
| $ | 399.1 | |
Cash Flows Used for Investments in Plant | $ | 315.3 |
| $ | 70.9 |
| $ | 297.4 |
| $ | 16.7 |
| $ | - |
| $ | 700.3 |
The following table summarizes NU's segmented total assets: | ||||||||||||||||||
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| Electric |
| Natural Gas |
|
|
|
|
|
|
|
|
|
|
|
| ||
(Millions of Dollars) | Distribution |
| Distribution |
| Transmission |
| Other |
| Eliminations |
| Total | |||||||
As of June 30, 2014 | $ | 16,942.5 |
| $ | 2,753.8 |
| $ | 6,934.1 |
| $ | 11,566.6 |
| $ | (10,406.6) |
| $ | 27,790.4 | |
As of December 31, 2013 |
| 17,260.0 |
|
| 2,759.7 |
|
| 6,745.8 |
|
| 11,842.4 |
|
| (10,812.4) |
|
| 27,795.5 |
|
| For the Three Months Ended March 31, 2015 | ||||||||||||||||
|
| Electric |
| Natural Gas |
|
|
|
|
|
|
|
|
|
|
|
| ||
(Millions of Dollars) | Distribution |
| Distribution |
| Transmission |
| Other |
| Eliminations |
| Total | |||||||
Operating Revenues | $ | 1,760.1 |
| $ | 507.4 |
| $ | 249.0 |
| $ | 240.0 |
| $ | (243.1) |
| $ | 2,513.4 | |
Depreciation and Amortization |
| (159.1) |
|
| (18.2) |
|
| (40.4) |
|
| (7.2) |
|
| 0.5 |
|
| (224.4) | |
Other Operating Expenses |
| (1,342.8) |
|
| (388.5) |
|
| (74.1) |
|
| (229.2) |
|
| 243.1 |
|
| (1,791.5) | |
Operating Income |
| 258.2 |
|
| 100.7 |
|
| 134.5 |
|
| 3.6 |
|
| 0.5 |
|
| 497.5 | |
Interest Expense |
| (47.6) |
|
| (9.0) |
|
| (27.6) |
|
| (11.8) |
|
| 1.2 |
|
| (94.8) | |
Other Income/(Loss), Net |
| 2.2 |
|
| (0.2) |
|
| 2.9 |
|
| 314.9 |
|
| (314.1) |
|
| 5.7 | |
Net Income Attributable to Controlling Interest | $ | 130.6 |
| $ | 55.6 |
| $ | 66.6 |
| $ | 312.9 |
| $ | (312.4) |
| $ | 253.3 | |
Cash Flows Used for Investments in Plant | $ | 172.5 |
| $ | 30.0 |
| $ | 150.0 |
| $ | 10.1 |
| $ | - |
| $ | 362.6 |
3828
NORTHEAST UTILITIES
29
EVERSOURCE ENERGY AND SUBSIDIARIES
Management's Discussion and Analysis of Financial Condition and Results of Operations
The following discussion and analysis should be read in conjunction with our unaudited condensed consolidated financial statements and related combined notes included in this combined Quarterly Report on Form 10-Q the First Quarter 2014 Form 10-Q, and the 20132014 Annual Report on Form 10-K. References in this Form 10-Q to "NU,"Eversource," the "Company," "we," "us," and "our" refer to Northeast UtilitiesEversource and its consolidated subsidiaries. All per share amounts are reported on a diluted basis. The unaudited condensed consolidated financial statements of NU,Eversource, NSTAR Electric and PSNH and the unaudited condensed financial statements of CL&P and WMECO are herein collectively referred to as the "financial statements."
Refer to the Glossary of Terms included in this combined Quarterly Report on Form 10-Q for abbreviations and acronyms used throughout thisManagement'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.Eversource. The earnings and EPS of each business discussed below do not represent a direct legal interest in the assets and liabilities allocated toof 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 NUEversource common shares outstanding for the year.period. The discussion below also includes non-GAAP financial measures referencing our secondfirst quarter 2015 and first half of 2014 and 2013 earnings and EPS excluding certain integration costs related to NU'sour 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 secondfirst quarter 2015 and first half of 2014 and 2013 results without including the impact of these non-recurring items. Due to the nature and significance of these items on Net Income Attributable to Controlling Interest, we believe that the non-GAAP presentation is more representative of our financial performance and provides additional and useful information to readers of this report in analyzing historical and future performance by business. These non-GAAP financial measures should not be considered as an alternative to reported Net Income Attributable to Controlling Interest or EPS determined in accordance with GAAP as an indicator of operating performance.
Reconciliations of the above non-GAAP financial measures to the most directly comparable GAAP measures of consolidated diluted EPS and Net Income Attributable to Controlling Interest are included under "Financial Condition and Business Analysis – Overview – Consolidated" and "Financial Condition and Business Analysis – Overview – Regulated Companies" inManagement's Discussion and Analysis of Financial Condition and Results of Operations, herein.
Forward-Looking Statements:From time to time we make statements concerning our expectations, beliefs, plans, objectives, goals, strategies, assumptions of future events, future financial performance or growth and other statements that are not historical facts. These statements are "forward-looking statements" within the meaning of the Private Securities Litigation Reform Act of 1995. You can generally identify our forward-looking statements through the use of words or phrases such as "estimate," "expect," "anticipate," "intend," "plan," "project," "believe," "forecast," "should," "could," and other similar expressions. Forward-looking statements are based on the current expectations, estimates, assumptions or projections of management and are not guarantees of future performance. These expectations, estimates, assumptions or projections may vary materially from actual results. Accordingly, any such statements are qualified in their entirety by reference to, and are accompanied by, the following important factors that could cause our actual results to differ materially from those contained in our forward-looking statements, including, but not limited to:
·
cyber breaches, acts of war or terrorism, or grid disturbances,
·
actions or inaction of local, state and federal regulatory, public policy and taxing bodies,
·
changes in business and economic conditions, including their impact on interest rates, bad debt expense, and demand for our products and services, which could include disruptive technology related to our current or future business model,
·
fluctuations in weather patterns,
·
changes in laws, regulations or regulatory policy,
·
changes in levels or timing of capital expenditures,
·
disruptions in the capital markets or other events that make our access to necessary capital more difficult or costly,
·
developments in legal or public policy doctrines,
·
technological developments,
·
changes in accounting standards and financial reporting regulations,
·
actions of rating agencies, and
·
other presently unknown or unforeseen factors.
Other risk factors are detailed in our reports filed with the SEC and updated as necessary, and we encourage you to consult such disclosures.
All such factors are difficult to predict, contain uncertainties that may materially affect our actual results and are beyond our control. You should not place undue reliance on the forward-looking statements, each speaks only as of the date on which such statement is made, and we undertake no obligation to update any forward-looking statement or statements to reflect events or circumstances after the date on which such statement is made or to reflect the occurrence of unanticipated events. New factors emerge from time to time and it is not possible for us to predict all of such factors, nor can we assess the impact of each such factor on the business or the extent to which any factor, or combination of factors, may cause actual results to differ materially from those contained in any forward-looking statements. For more information, see Item 1A, Risk Factors, included in this Quarterly Report on Form 10-Q and in NU's 2013Eversource's 2014 combined Annual Report on Form 10-K. This Quarterly Report on Form 10-Q and NU's 2013Eversource's 2014 combined Annual Report on Form 10-K also describedescribes material contingencies and critical accounting policies in the accompanyingManagement's Discussion and Analysis of Financial Condition and Results of OperationsandCombined Notes to Condensed Consolidated Financial Statements (Unaudited). We encourage you to review these items.
3930
Financial Condition and Business Analysis
Executive Summary
The following items in this executive summary are explained in more detail in this combined Quarterly Report on Form 10-Q:
Results:
The earnings discussion below compares the first quarter of 2015 with the first quarter of 2014:
·
We earned $127.4$253.3 million, or $0.40$0.80 per share, in the second quarter of 2014, and $363.3compared with $236 million, or $1.15$0.74 per share, in the first half of 2014, compared with $171 million, or $0.54 per share, in the second quarter of 2013 and $399.1 million, or $1.26 per share, in the first half of 2013.share. Excluding integration costs, we earned $131.9$257.3 million, or $0.42$0.81 per share, in the second quarter of 2014, and $373.7compared with $241.8 million, or $1.18$0.76 per share, in the first half of 2014, compared with $172.8 million, or $0.55 per share, in the second quarter of 2013, and $402.6 million, or $1.27 per share, in the first half of 2013.share.
·
Our electric distribution segment, which includes generation, earned $83.4$130.6 million, or $0.26$0.41 per share, in the second quarter of 2014 and $195.6compared with $112.2 million, or $0.62$0.35 per share, in the first half of 2014, compared with earnings of $91.2 million, or $0.29 per share, in the second quarter of 2013 and $190.6 million, or $0.60 per share, in the first half of 2013.
·
share. Our transmission segment earned $43.9$66.6 million, or $0.14$0.21 per share, in the second quarter of 2014 and $118.8compared with $74.9 million, or $0.37$0.24 per share, in the first half of 2014, compared with $76.8 million, or $0.25 per share, in the second quarter of 2013 and $156.7 million, or $0.50 per share, in the first half of 2013. The decrease in the second quarter and first half of 2014 earnings, as compared to the same periods in 2013, was due primarily to the establishment of a $32.1 million after-tax reserve related to FERC ROE orders issued on June 19, 2014.
·
share. Our natural gas distribution segment earned $2$55.6 million, or $0.01$0.18 per share, in the second quarter of 2014 and $54.1compared with $52.1 million, or $0.17$0.16 per share, in the first half of 2014, compared with $1.2 million in the second quarter of 2013 and $44.5 million, or $0.14 per share, in the first half of 2013.share.
·
NUES parent and other companies had net earnings of $0.5 million, compared with net losses of $1.9$3.2 million, or $0.01 per share. The 2015 and 2014 results reflect $4 million, or $0.01 per share, in the second quarter of 2014 and $5.2 million, or $0.01 per share, in the first half of 2014, compared with earnings of $1.8 million in the second quarter of 2013 and $7.3$5.8 million, or $0.02 per share, in the first half of 2013. Second quarter and first half 2014 results reflect $4.5 million and $10.4 million, respectively, of after-tax integration costs. Second quarter and first half 2013 results reflect $1.8 million and $3.5 million, respectively, of after-tax integration costs.
Legislative, Regulatory, Policy and RegulatoryOther Items:
·
On June 9, 2014, CL&P filedJanuary 7, 2015, the DPU issued an applicationorder concluding that NSTAR Electric had appropriately accounted for the removal of supply-related bad debt costs from base distribution rates effective January 1, 2006. The DPU ordered NSTAR Electric and the Massachusetts Attorney General to collaborate on the reconciliation of energy-related bad debt costs through 2014. During the second quarter of 2015, NSTAR Electric expects to file with the PURADPU to amend customer rates, effective December 1, 2014. CL&P requestedrecover from customers approximately $43 million of supply-related bad debt costs. In the first quarter of 2015, as a result of the January 7th DPU order, NSTAR Electric increased its regulatory assets by $24.2 million, resulting in an increase in base distribution ratesafter-tax earnings of $116.7$14.5 million. Based on the current schedule, we expect a final decision in December 2014.
·
On June 19, 2014,March 2, 2015, the DPU approved a comprehensive settlement agreement between NSTAR Electric, NSTAR Gas and the Massachusetts Attorney General (the "Settlement") as filed with the DPU on December 31, 2014. The Settlement resolved the outstanding NSTAR Electric CPSL program filings, the NSTAR Electric and NSTAR Gas PAM and energy efficiency-related customer billing adjustments, and the recovery of LBR related to NSTAR Electric’s energy efficiency programs (11 dockets in total). As a result, NSTAR Electric and NSTAR Gas will refund a combined $44.7 million to customers, which was recorded as a regulatory liability as of March 31, 2015, and recognized a $13 million after-tax benefit in the first quarter of 2015.
·
On March 3, 2015, FERC issued two ordersan order denying all issues raised on rehearing by the NETOs and Complainants in the pendingfirst base ROE complaint proceedings. The first order addressed the joint complaint filed at FERC in September 2011 by several New England parties alleging that the base ROE of 11.14 percent was unjust and unreasonable.complaint. The FERC set a single tentativeorder upheld our base ROE of 10.57 percent for the refund period (October 1, 2011 through December 31, 2012) and the prospective period (beginning when FERC finalizes the base ROE). The second order addressed a second joint complaint filed at FERC in December 2012 by additional New England parties allegingupheld that the baseutilities total ROE was unjust and unreasonable. The complaint sought refunds foris capped at the 15-month period beginning January 1, 2013. The FERC found thattop of the second complaint raised issueszone of material fact andreasonableness, which is currently set this complaint for settlement or trial if settlement negotiations should be unsuccessful. We recordedat 11.74 percent. As a seriesresult of reserves totaling $32.1 millionclarifying information related to how the ROE cap is applied, which is contained in the order, we recognized an after-tax at our electric subsidiariescharge to recognize the potential financial impact from the FERC's two orders for the two refund periods.earnings of $12.4 million.
·
On July 7, 2014, Massachusetts enacted "An Act RelativeMarch 11, 2015, PSNH and key New Hampshire officials entered into an agreement in principle in a settlement Term Sheet (Term Sheet) designed to Natural Gas Leaks" (the Act)provide a resolution of issues pertaining to PSNH’s generation assets in pending regulatory proceedings. PSNH has agreed to pursue the divestiture of its generation assets upon NHPUC approval of a final Settlement Agreement reflecting the provisions of the Term Sheet (Settlement Agreement). The Act establishesAs part of the planned Settlement Agreement, PSNH has agreed to forego recovery of $25 million of the deferred equity return related to the Clean Air Project. Upon completion of the divestiture process, all costs not recovered from sales proceeds (stranded costs), will be recovered via bonds that will be secured by a uniform natural gas leak classification standard for all Massachusetts natural gas utilitiesnon-bypassable charge to PSNH's customers. Consummation of the Term Sheet provisions is conditioned upon the enactment of New Hampshire legislation, completion of the Settlement Agreement, and NHPUC approval of the Settlement Agreement. We expect legislation to be finalized in the third quarter of 2015 and a program that accelerates the replacement of aging natural gas infrastructure. The Act also calls for the DPUNHPUC decision to authorize natural gas utilities to design and offer programs to customers that will increase the availability, affordability and feasibility of natural gas service for new customers.be issued in late 2015.
Liquidity:
·
Cash and cash equivalents totaled $34.1 million as of June 30, 2014, compared with $43.4 million as of December 31, 2013, while investments in property, plant and equipment totaled $724 million in the first half of 2014, compared with $700.3 million in the first half of 2013.
·
Cash flows provided by operating activities totaled $896.7$481.8 million in the first halfquarter of 2014,2015, compared with $769$493.8 million in the first halfquarter of 2013. The improved operating cash flows were due primarily to approximately $1262014. Investments in property, plant and equipment totaled $362.6 million in DOE Phase II proceeds received by CL&P, NSTAR Electric, PSNH and WMECO on June 1, 2014 from the Yankee Companies associated with the spent nuclear fuel litigation, the absence of cash disbursements for major storm restoration costs and the decrease of $82.2 million in Pension and PBOP Plan cash contributions, partially offset by an increase in income taxes paid in the first halfquarter of 2014 ($158 million), as2015, compared towith $348.7 million in the first halfquarter of 2013 ($16 million).2014. Cash and cash equivalents totaled $71 million as of March 31, 2015, compared with $38.7 million as of December 31, 2014.
·
In the first half of 2014, weOn January 15, 2015, ES parent issued $650$150 million of new long-term debt consisting of $100 million by Yankee Gas on January 2, 2014,1.60 percent Series G Senior Notes, due to mature in 2018 and $300 million by NSTAR Electric on March 7, 2014, and $250 million by CL&P on April 24, 2014. These new issuancesof 3.15 percent Series H Senior Notes, due to mature in 2025. Proceeds were used to repay approximately $375 million of existing long-term debt withshort-term borrowings outstanding under the remainder used to pay short-term borrowings. ES parent commercial paper program.
40
·
In the first half of 2014, we had cash dividends on common shares of $237.2 million, compared with $232 million in the first half of 2013. On May 1, 2014,April 29, 2015, our Board of Trustees approved a common share dividend payment of $0.3925$0.4175 per share, which was paidpayable on June 30, 20142015 to shareholders of record as of May 30, 2014. 29, 2015.
31
Overview
Consolidated: A summary of our earnings by business, which also reconciles the non-GAAP financial measures of consolidated non-GAAP earnings and EPS, as well as EPS by business, to the most directly comparable GAAP measures of consolidated Net Income Attributable to Controlling Interest and diluted EPS, for the second quarterfirst quarters of 2015 and first half of 2014 and 2013 is as follows:
|
| For the Three Months Ended June 30, |
| For the Six Months Ended June 30, | ||||||||||||||||||||
(Millions of Dollars, Except |
| 2014 |
| 2013 |
| 2014 |
| 2013 | ||||||||||||||||
Per Share Amounts) |
| Amount |
| Per Share |
| Amount |
| Per Share |
| Amount |
| Per Share |
| Amount |
| Per Share | ||||||||
Net Income Attributable to |
| $ | 127.4 |
| $ | 0.40 |
| $ | 171.0 |
| $ | 0.54 |
| $ | 363.3 |
| $ | 1.15 |
| $ | 399.1 |
| $ | 1.26 |
|
| $ | 129.3 |
| $ | 0.41 |
| $ | 169.2 |
| $ | 0.54 |
| $ | 368.5 |
| $ | 1.16 |
| $ | 391.8 |
| $ | 1.24 |
NU Parent and Other Companies |
|
| 2.6 |
|
| 0.01 |
|
| 3.6 |
|
| 0.01 |
|
| 5.2 |
|
| 0.02 |
|
| 10.8 |
|
| 0.03 |
Non-GAAP Earnings |
|
| 131.9 |
|
| 0.42 |
|
| 172.8 |
|
| 0.55 |
|
| 373.7 |
|
| 1.18 |
|
| 402.6 |
|
| 1.27 |
Integration Costs (after-tax) |
|
| (4.5) |
|
| (0.02) |
|
| (1.8) |
|
| (0.01) |
|
| (10.4) |
|
| (0.03) |
|
| (3.5) |
|
| (0.01) |
Net Income Attributable to |
| $ | 127.4 |
| $ | 0.40 |
| $ | 171.0 |
| $ | 0.54 |
| $ | 363.3 |
| $ | 1.15 |
| $ | 399.1 |
| $ | 1.26 |
Excluding the impact of integration costs, our second quarter 2014 earnings decreased by $40.9 million, as compared to the second quarter of 2013. The decrease was due primarily to the establishment of an after-tax reserve of $32.1 million related to the June 2014 FERC ROE orders. For further information, see "FERC Regulatory Issues – FERC Base ROE Complaints" in thisManagement's Discussion and Analysis of Financial Condition and Results of Operations. In addition, earnings decreased as a result of higher depreciation expense and property taxes and lower retail electric sales, partially offset by lower general and administrative costs.
|
| For the Three Months Ended March 31, | |||||||||||
|
| 2015 |
| 2014 | |||||||||
(Millions of Dollars, Except Per Share Amounts) |
| Amount |
| Per Share |
| Amount |
| Per Share | |||||
Net Income Attributable to Controlling Interest (GAAP) |
| $ | 253.3 |
| $ | 0.80 |
| $ | 236.0 |
| $ | 0.74 | |
|
| $ | 252.8 |
| $ | 0.80 |
| $ | 239.2 |
| $ | 0.75 | |
ES Parent and Other Companies |
|
| 4.5 |
|
| 0.01 |
|
| 2.6 |
|
| 0.01 | |
Non-GAAP Earnings |
|
| 257.3 |
|
| 0.81 |
|
| 241.8 |
|
| 0.76 | |
Integration Costs (after-tax) |
|
| (4.0) |
|
| (0.01) |
|
| (5.8) |
|
| (0.02) | |
Net Income Attributable to Controlling Interest (GAAP) |
| $ | 253.3 |
| $ | 0.80 |
| $ | 236.0 |
| $ | 0.74 |
Excluding the impact of integration costs, our first half 2014quarter 2015 earnings decreasedincreased by $28.9$15.5 million, as compared to the first half of 2013, due primarily to the establishment of the $32.1 million after-tax reserve related to June 2014 FERC base ROE orders, the absence of a favorable impact from the resolution of a state income tax audit in the first quarter of 2013, and higher depreciation expense and property taxes. Earnings were favorably impacted by higher retail electric and firm natural gas sales as a result of the colder weather in the first quarter of 2014, as compared to the first quarter of 2013,2014. The increase was due primarily to the $27.5 million favorable earnings impact related to the resolution of NSTAR Electric’s basic service bad debt adder, the CPSL program filings, and lower generalthe recovery of LBR related to energy efficiency programs, and administrative costs. the impact of the December 1, 2014 CL&P base distribution rate increase. Partially offsetting these favorable earnings impacts were the $12.4 million after-tax reserve related to the March 2015 FERC ROE order, an increase in operations and maintenance costs primarily attributable to an increase in labor and employee benefits expense, as a result of the impact from winter weather and storms, as compared to the first quarter of 2014, higher depreciation expense and higher property taxes.
The first quarter 2015 and 2014 integration costs included costs incurred for employee severance in connection with ongoing integration. In addition, the first quarter 2015 integration costs also included costs associated with our branding efforts.
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 and EPS for the second quarterfirst quarters of 2015 and first half of 2014 and 2013 is as follows:
| For the Three Months |
| For the Six Months |
| For the Three Months Ended March 31, | |||||||||||||||||||
(Millions of Dollars) | 2014 |
| 2013 |
| 2014 |
| 2013 | |||||||||||||||||
|
| 2015 |
| 2014 | ||||||||||||||||||||
(Millions of Dollars, Except Per Share Amounts) |
| Amount |
| Per Share |
| Amount |
| Per Share | ||||||||||||||||
Electric Distribution | $ | 83.4 |
| $ | 91.2 |
| $ | 195.6 |
| $ | 190.6 |
| $ | 130.6 |
| $ | 0.41 |
| $ | 112.2 |
| $ | 0.35 | |
Transmission |
| 43.9 |
|
| 76.8 |
|
| 118.8 |
|
| 156.7 |
|
| 66.6 |
| 0.21 |
| 74.9 |
|
| 0.24 | |||
Natural Gas Distribution |
| 2.0 |
|
| 1.2 |
|
| 54.1 |
|
| 44.5 |
|
| 55.6 |
|
| 0.18 |
|
| 52.1 |
|
| 0.16 | |
Net Income - Regulated Companies | $ | 129.3 |
| $ | 169.2 |
| $ | 368.5 |
| $ | 391.8 |
| $ | 252.8 |
| $ | 0.80 |
| $ | 239.2 |
| $ | 0.75 |
Our electric distribution segment earnings decreased $7.8 million in the second quarter of 2014, as compared to the second quarter of 2013, due primarily to a decrease of 2.9 percent in retail electric sales as a result of milder temperatures in late May and June, as compared to the same periods in 2013, the absence of regulatory interest income from stranded cost recoveries recognized in the second quarter of 2013, and higher depreciation and property tax expense, partially offset by lower general and administrative costs.
Our electricOurelectric distribution segment earnings increased $5$18.4 million in the first half of 2014, as compared to the first half of 2013, due primarily to higher retail electric sales as a result of the colder weather in the first quarter of 2014,2015, as compared to the first quarter of 2013,2014, due primarily to the $27.5 million favorable earnings impact related to the resolution of NSTAR Electric’s basic service bad debt adder, the CPSL program filings, and a decreasethe recovery of LBR related to energy efficiency programs, and the impact of the December 1, 2014 CL&P base distribution rate increase. Partially offsetting these favorable earnings impacts were an increase in operations and maintenance costs thatprimarily attributable to an increase in labor and employee benefits expense, as a result of the impact earnings. Partially offsetting these favorable impacts werefrom winter weather and storms, as compared to the absencefirst quarter of regulatory interest income from stranded cost recoveries in 2013,2014, higher depreciation expense and higher depreciation and property tax expense.taxes.
Our transmission segment earnings decreased $32.9$8.3 million in the secondfirst quarter of 2014,2015, as compared to the secondfirst quarter of 2013,2014, due primarily to the establishment of the $32.1$12.4 million after-tax reserve related to the June 2014March 2015 FERC ROE orders,order and the net unfavorablenegative earnings impact on transmission revenues as a result of a refund to our customers in June 2014, partially offset by a higher transmission rate base as a result of an increased investment in our transmission infrastructure.
Our transmission segment earnings decreased $37.9 millionresulting from the lower allowed ROE in the first halfquarter of 2014,2015, as compared to the first half of 2013, due primarily to the $32.1 million after-tax reserve related to the June 2014 FERC ROE orders, the absence of the favorable impact from the resolution of the state income tax audit in the first quarter of 2013, the net unfavorable impact on transmission revenues as a result of a refund to our customers in June 2014, partially offset by a higher transmission rate base as a result of an increased investment in our transmission infrastructure.
Our natural gas distribution segment earnings increased $0.8$3.5 million in the secondfirst quarter of 2014,2015, as compared to the secondfirst quarter of 2013,2014, due primarily to higher firm natural gas sales volumes and peak demand revenues as a result of the addition of new natural gas heating customers.
41
Our natural gas distribution segment earnings increased $9.6 million in the first half of 2014, as compared to the first half of 2013, due primarily to higher firm natural gas sales and peak demand revenues as a result ofresulting from colder weather in the first quarter of 2015, as compared to the first quarter of 2014, as well as the addition of newand additional natural gas heating customers.customers, partially offset by higher property taxes, higher depreciation expense and bad debt expense.
A summary of our retail electric GWh sales volumes and percentage changes, as well as percentage changes in CL&P, NSTAR Electric, PSNH and WMECO retail electric GWh sales volumes, is as follows:
| For the Three Months Ended |
| For the Six Months Ended | ||||||||
| Sales (GWh) |
| Percentage |
| Sales (GWh) |
| Percentage | ||||
NU – Electric | 2014 |
| 2013 |
| Decrease |
| 2014 |
| 2013 |
| Increase |
Residential | 4,510 |
| 4,720 |
| (4.4)% |
| 10,650 |
| 10,523 |
| 1.2% |
Commercial (1) | 6,591 |
| 6,754 |
| (2.4)% |
| 13,456 |
| 13,448 |
| 0.1% |
Industrial | 1,435 |
| 1,437 |
| (0.1)% |
| 2,778 |
| 2,736 |
| 1.5% |
Total | 12,536 |
| 12,911 |
| (2.9)% |
| 26,884 |
| 26,707 |
| 0.7% |
| For the Three Months Ended March 31, 2015 Compared to 2014 | |||||||||||||||||||||||||||
ES |
| CL&P |
| NSTAR Electric |
| PSNH |
| WMECO | ||||||||||||||||||||
| For the Three Months Ended June 30, 2014 Compared to 2013 |
| For the Six Months Ended June 30, 2014 Compared to 2013 |
|
| Percentage |
| Percentage |
| Percentage |
| Percentage |
|
| ||||||||||||||
| CL&P |
| NSTAR |
| PSNH |
| WMECO |
| CL&P |
| NSTAR |
| PSNH |
| WMECO | Sales Volumes (GWh) |
| Increase/ |
| Increase/ |
| Increase/ |
| Increase/ |
| Percentage | ||
Electric | Percentage |
| Percentage |
| Percentage |
| Percentage |
| Percentage |
| Percentage |
| Percentage |
| Percentage | 2015 |
| 2014 |
| (Decrease) |
| (Decrease) |
| (Decrease) |
| (Decrease) |
| Decrease |
Residential | (5.3)% |
| (4.2)% |
| (1.8)% |
| (5.4)% |
| 1.5% |
| 0.2 % |
| 2.4% |
| 0.9 % | 6,217 |
| 6,139 |
| 1.3 % |
| 1.2 % |
| 1.6 % |
| 1.6 % |
| (0.6)% |
Commercial (1) | (2.0)% |
| (3.0)% |
| (0.6)% |
| (4.5)% |
| 0.1% |
| (0.2)% |
| 0.8% |
| (0.3)% | |||||||||||||
Commercial | 6,930 |
| 6,866 |
| 0.9 % |
| 0.5 % |
| 1.9 % |
| (1.0)% |
| (0.1)% | |||||||||||||||
Industrial | 3.4 % |
| (6.9)% |
| 1.7 % |
| (3.2)% |
| 3.8% |
| (1.9)% |
| 3.2% |
| (2.8)% | 1,301 |
| 1,343 |
| (3.1)% |
| (0.9)% |
| (4.5)% |
| (4.9)% |
| (4.7)% |
Total | (2.8)% |
| (3.6)% |
| (0.6)% |
| (4.6)% |
| 1.1% |
| (0.1)% |
| 1.9% |
| (0.2)% | 14,448 |
| 14,348 |
| 0.7 % |
| 0.8 % |
| 1.4 % |
| (0.5)% |
| (1.1)% |
(1)
Commercial retail electric GWh sales include streetlighting and railroad retail sales.32
A summary of our firm natural gas sales volumes in million cubic feet and percentage changes as well as percentage changes in Yankee Gas and NSTAR Gas, is as follows:
| For the Three Months Ended |
| For the Six Months Ended | ||||||||
| Sales (million cubic feet) |
| Percentage |
| Sales (million cubic feet) |
| Percentage | ||||
NU – Firm Natural Gas | 2014 |
| 2013 |
| Increase |
| 2014 |
| 2013 |
| Increase |
Residential | 5,169 |
| 4,970 |
| 4.0% |
| 24,981 |
| 21,985 |
| 13.6% |
Commercial | 6,839 |
| 6,622 |
| 3.3% |
| 26,467 |
| 23,393 |
| 13.1% |
Industrial | 4,916 |
| 4,665 |
| 5.4% |
| 12,393 |
| 11,494 |
| 7.8% |
Total | 16,924 |
| 16,257 |
| 4.1% |
| 63,841 |
| 56,872 |
| 12.3% |
Total, Net of Special Contracts(1) | 15,895 |
| 15,238 |
| 4.3% |
| 61,445 |
| 54,660 |
| 12.4% |
| For the Three Months Ended |
| For the Six Months Ended | |||||||||
| Sales (million cubic feet) |
| Sales (million cubic feet) | For the Three Months Ended March 31, 2015 Compared to 2014 | ||||||||
| Yankee Gas |
| NSTAR Gas |
| Yankee Gas |
| NSTAR Gas | ES | ||||
| Percentage |
| Percentage |
| Percentage |
| Percentage | Sales Volumes (million cubic feet) |
| Percentage | ||
Firm Natural Gas | Increase/(Decrease) |
| Increase |
| Increase/(Decrease) |
| Increase | 2015 |
| 2014 |
| Increase |
Residential | (3.4)% |
| 9.6 % |
| 15.8% |
| 12.2% | 21,455 |
| 19,812 |
| 8.3% |
Commercial | 5.4 % |
| 1.4 % |
| 16.6% |
| 10.2% | 21,450 |
| 19,627 |
| 9.3% |
Industrial | 5.7 % |
| 4.5% |
| 8.4% |
| 6.4% | 7,667 |
| 7,478 |
| 2.5% |
Total | 3.3 % |
| 5.0% |
| 13.9% |
| 10.6% | 50,572 |
| 46,917 |
| 7.8% |
Total, Net of Special Contracts(1) | 3.7 % |
|
|
| 14.4% |
|
| 49,381 |
| 45,550 |
| 8.4% |
(1)
Special contracts are unique to the customers who take service under such an arrangement and generally specify the amount of distribution revenue to be paid to Yankee Gas regardless of the customers' usage.
Weather, fluctuations in energy supply costs, conservation measures (including company-sponsoredutility-sponsored energy efficiency programs), and economic conditions affect customer energy usage. Industrial sales are less sensitive to temperature variations than residential and commercial sales. In our service territories, weather impacts electric sales during the summer and electric and natural gas sales during the winter (natural gas sales are more sensitive to temperature variations than electric sales). Customer heating or cooling usage may not directly correlate with historical levels or with the level of degree-days that occur. In addition, our electric and natural gas businesses are susceptible to damage from major storms and other natural events and disasters that could adversely affect our ability to provide energy.
For the secondOur first quarter of 2014, our2015 total consolidated retail electric sales consisting of the retail electric sales of CL&P, NSTAR Electric, PSNH, and WMECO,volumes were lower,higher, as compared to the same period in 2013,first quarter of 2014, due primarily to milder temperatures in late May and June, compared with the same periods in 2013. The secondcolder weather. First quarter of 2014 cooling2015 heating degree days were 195 percent lowerhigher in Connecticut and western Massachusetts, 22 percentlower10 percent higher in the Boston metropolitan area, and 244 percent lowerhigher in New Hampshire, as compared to the secondfirst quarter of 2013.2014. Weather-normalized retail
42
electric sales (based on 30-year average temperatures) decreased 1.7 percent in the second quarter of 2014, as compared to the second quarter of 2013. We believe the decrease was due primarily to increased conservation efforts by our residential and commercial customer classes, which is driven by the energy efficiency programs sponsored by CL&P, NSTAR Electric and WMECO.
For the first half of 2014, ourEversource consolidated retail electric sales were higher, as compared to the same period in 2013, due primarily to colder weathervolumes remained relatively unchanged in the first quarter of 2014. The first half 2014 heating degree days were 12 percent higher in Connecticut, New Hampshire and western Massachusetts and 9 percenthigher in the Boston metropolitan area,2015, as compared to the first halfquarter of 2013. Weather-normalized retail electric sales (based on 30-year average temperatures) decreased 0.1 percent in the first half of 2014, as compared to the first half of 2013. We believe the decrease was due primarily to an increase in customer conservation efforts as noted above.2014.
For CL&P (effective December 1, 2014) and WMECO, fluctuations in retail electric sales volumes do not impact earnings due to the DPU-approvedregulatory commission approved revenue decoupling mechanism. Under this decoupling mechanism,mechanisms. Distribution revenues are decoupled from their customer sales volumes. CL&P and WMECO has an overall fixedreconcile their annual base distribution rate recovery to pre-established levels of baseline distribution delivery service revenues. Any difference between the allowed level of distribution delivery service revenues of $132.4 million, comprised of customer base rate revenues of $125.4 millionrevenue and the actual amount incurred during a baseline low income discount recovery of $7 million. These two mechanisms12-month period is adjusted through rates in the following period. The decoupling mechanism effectively breakbreaks the relationship between sales volumevolumes and revenues recognized. Prior to December 1, 2014, CL&P recognized LBR related to reductions in sales volume as a result of successful energy efficiency programs. LBR was recovered from retail customers through the FMCC. Effective December 1, 2014, CL&P no longer recognizes LBR due to its revenue decoupling mechanism. NSTAR Electric continues to recognize LBR through December 31, 2015 in accordance with the 2012 DPU-approved comprehensive merger settlement agreement with the Massachusetts Attorney General. For the first quarter of 2015 and 2014, NSTAR Electric recognized LBR of $12.5 million and $8.7 million, respectively.
Our firm natural gas sales are subject to many of the same influences as our retail electric sales. In addition, they have benefittedbenefited from historically favorable natural gas prices and customer growth across both operating companies. In the secondOur first quarter and first half of 2014,2015 consolidated firm natural gas sales volumes, consisting of the firm natural gas sales volumes of Yankee Gas and NSTAR Gas, were higher, as compared to the secondfirst quarter and first half of 2013,2014, due primarily to colder weather in the first quarter of 2014,2015, as compared to the first quarter of 2014. The first quarter 2015 weather-normalized Eversource consolidated firm natural gas sales volumes increased 3.2 percent, as compared to the same period in 2013,2014, due primarily to residential and commercial customer growth in the first half of 2014, as compared to the same period in 2013. The second quarter and first half of 2014 weather-normalized NU consolidated total firm natural gas sales increased 5.3 percent and 4.1 percent, respectively, as compared to the same periods in 2013.growth.
NUES Parent and Other Companies: NUES parent and other companies, which includesinclude our competitiveunregulated businesses, had net lossesearnings of $1.9 million and $5.2$0.5 million in the secondfirst quarter and first half of 2014, respectively,2015, compared with earningsnet losses of $1.8 million and $7.3$3.2 million in the secondfirst quarter and first half of 2013, respectively.2014. Excluding the impact of integration costs, NUES parent and other companies earned $2.6 million and $5.2$4.5 million in the secondfirst quarter and first half of 2014, respectively,2015, compared with $3.6 million and $10.8$2.6 million in the secondfirst quarter and first half of 2013, respectively.2014. The decreaseearnings increase in first half of 2014 earnings2015 was due primarily to the absence of the favorable impact from the resolution of the state income tax audit, which provided a $5.8 millionbenefit to first half of 2013 earnings. $2.5 million contribution made in March 2014.
Liquidity
Consolidated: Cash and cash equivalents totaled $34.1$71 million as of June 30, 2014,March 31, 2015, compared with $43.4$38.7 million as of December 31, 2013.2014.
On April 24, 2014, CL&P3, 2015, the DPU authorized NSTAR Gas to issue up to $100 million in long-term debt for the period through December 31, 2015.
On January 15, 2015, ES parent issued $250$150 million of 4.301.60 percent 2014 Series A First Mortgage Bonds,G Senior Notes, due to mature in April 2044.2018 and $300 million of 3.15 percent Series H Senior Notes, due to mature in 2025. The proceeds, net of issuance costs, were used to repay short-term borrowings.borrowings outstanding under the ES parent commercial paper program.
On April 15, 2014, NSTAR Electric1, 2015, CL&P repaid at maturity the $300$100 million of 4.8755.00 percent debentures using short-term debt.
On July 15, 2014, PSNH repaid at maturity the $50 million of 5.25 percent2005 Series LA First and Refunding Mortgage Bonds using short-term debt.borrowings. On April 1, 2015, CL&P also redeemed the $62 million 1996A Series 1.55 percent PCRBs that were subject to mandatory tender, using short term borrowings.
Effective July 23, 2014, NUES parent, CL&P, PSNH, WMECO, NSTAR Gas and Yankee Gas amended their jointare parties to a five-year $1.45 billion revolving credit facility to extend the expiration date an additional year tothat expires September 6, 2019. The revolving credit facility is to be used primarily to backstop NUES parent's $1.45 billion commercial paper program. The commercial paper program allows NUES parent to issue commercial paper as a form of short-term debt. As of June 30, 2014March 31, 2015 and December 31, 2013, NU2014, ES parent had $710.5$788 million and $1.01approximately $1.1 billion, respectively, in short-term borrowings outstanding under the NUES parent commercial paper program, leaving $739.5$662 million and $435.5$348.9 million of available borrowing capacity as of June 30, 2014March 31, 2015 and December 31, 2013,2014, respectively. The weighted-average interest rate on these borrowings as of June 30, 2014March 31, 2015 and December 31, 20132014 was 0.250.53 percent and 0.240.43 percent, respectively, which is
33
generally based on A2/P2 rated commercial paper. As of June 30, 2014,March 31, 2015, there were intercompany loans from NUES parent of $6.4$190.1 million to CL&P, $95$82 million to PSNH and $15.9$70.5 million to WMECO. As of December 31, 2013,2014, there were intercompany loans from NUES parent of $287.3$133.4 million to CL&P, and $86.5$90.5 million to PSNH. PSNH and $21.4 million to WMECO.
Effective July 23, 2014, NSTAR Electric amended itshas a five-year $450 million revolving credit facility to extend the expiration date an additional year tothat expires September 6, 2019. This facility serves to backstop NSTAR Electric's existing $450 million commercial paper program. As of June 30, 2014March 31, 2015 and December 31, 2013,2014, NSTAR Electric had $194.5$215.5 million and $103.5$302 million, respectively, in short-term borrowings outstanding under its commercial paper program, leaving $255.5$234.5 million and $346.5$148 million respectively, of available borrowing capacity as of June 30, 2014March 31, 2015 and December 31, 2013,2014, respectively. The weighted-average interest rate on these borrowings as of June 30, 2014March 31, 2015 and December 31, 20132014 was 0.160.35 percent and 0.130.27 percent, respectively, which is generally based on A2/P1 rated commercial paper.
Cash flows provided by operating activities totaled $896.7$481.8 million in the first halfquarter of 2014,2015, compared with $769$493.8 million in the first halfquarter of 2013.2014. The improveddecrease in operating cash flows werewas due primarily to approximately $126 millionthe timing of regulatory recoveries, resulting from both the increase in DOE Phase II Damages proceeds received bypurchased power and congestion costs at NSTAR Electric, WMECO and CL&P, NSTAR Electric, PSNH and WMECO on June 1, 2014 from the Yankee Companies associatedalong with the spent nuclear fuel litigation,timing of collections and payments related to our working capital items, including accounts receivable and accounts payable. Accounts receivable increased due primarily to higher sales volumes in the absencefirst quarter of cash disbursements for major storm restoration costs2015 as a result of colder weather, increases in both CL&P’s and NSTAR Electric’s basic service rates effective January 1, 2015, and the decreaseincrease in CL&P's base distribution rates effective December 1, 2014. In addition, there was an increase of $82.2approximately $20 million inof Pension and PBOP Plan cash contributions partially offset by an increase in income taxes paid in the first halfquarter of 2015, compared to the same period in 2014. Partially offsetting these unfavorable cash flow impacts was an income tax refund received in the first quarter of 2015 primarily related to the extension of the accelerated deduction of depreciation in 2014, ($158 million),which resulted in cash receipts of approximately $250 million in 2015, as compared to income tax payments in the first halfquarter of 2013 ($16 million). For further information on the spent nuclear fuel litigation, see Note 8C, "Commitments and Contingencies – Contractual Obligations – Yankee Companies," in this combined Quarterly Report on Form 10-Q. 2014.
On April 7, 2014, Fitch affirmed23, 2015, S&P upgraded the corporate credit ratings by one level 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 stable from positive from stable of NU,ES parent, CL&P, NSTAR Electric, PSNH, WMECO, Yankee Gas and NSTAR Gas.
43 A summary of our corporate credit ratings and outlooks by Moody's, S&P and Fitch is as follows:
Moody's | S&P | Fitch | ||||||||||
Current | Outlook | Current | Outlook | Current | Outlook | |||||||
ES Parent | Baa1 | Stable | A | Stable | BBB+ | Stable | ||||||
CL&P | Baa1 | Stable | A | Stable | BBB+ | Stable | ||||||
NSTAR Electric | A2 | Stable | A | Stable | A | Stable | ||||||
PSNH | Baa1 | Stable | A | Stable | BBB+ | Stable | ||||||
WMECO | A3 | Stable | A | Stable | BBB+ | Stable |
In the first halfquarter of 2014,2015, we had cash dividends on common shares of $237.2$132.5 million, compared with $232$118.5 million in the first halfquarter of 2013.2014. On May 1, 2014,February 3, 2015, our Board of Trustees approved a common share dividend payment of $0.3925$0.4175 per share, which waspayable on March 31, 2015 to shareholders of record as of March 2, 2015. The dividend represented an increase of 6.4 percent over the dividend paid in December 2014. On April 29, 2015, our Board of Trustees approved a common share dividend payment of $0.4175 per share, payable on June 30, 20142015 to shareholders of record as of May 30, 2014.29, 2015.
In the first halfquarter of 2014,2015, CL&P, NSTAR Electric, PSNH, and WMECO paid $85.6$49 million, $253$49.5 million, $33$26.5 million, and $49$9.3 million, respectively, in common stock dividends to NUES 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 halfquarter of 2014,2015, investments for NU,Eversource, CL&P, NSTAR Electric, PSNH, and WMECO were $724$362.6 million, $221.4$127.6 million, $213.5$79.8 million, $117.4$71.9 million, and $61.5$35.9 million, respectively.
Business Development and Capital Expenditures
Consolidated: Our consolidated capital expenditures, including amounts incurred but not paid, cost of removal, AFUDC, and the capitalized portions of pension expense (all of which are non-cash factors), totaled $706.2$310.5 million in the first halfquarter of 2014,2015, compared with $644$277.9 million in the first halfquarter of 2013.2014. These amounts included $25.5$8.4 million and $6.7$5.9 million in the first halfquarter of 20142015 and 2013,2014, respectively, related to our corporate serviceinformation technology and facilities upgrades and enhancements, primarily at Eversource Service and The Rocky River Realty Company.
Access Northeast: In September 2014, Eversource and Spectra Energy Corp announced Access Northeast, a natural gas pipeline expansion project. Access Northeast will enhance the Algonquin and Maritimes pipeline systems using existing routes and is expected to be capable of delivering approximately one billion cubic feet of natural gas per day to New England. Eversource and Spectra Energy Corp will have equal ownership interest in the project with the option of additional investors in the future. On February 18, 2015, National Grid was added as a co-developer in the project for a total ownership interest of 20 percent, with Eversource and Spectra Energy Corp each owning 40 percent. The total project cost, subject to FERC approval, is expected to be approximately $3 billion and has an anticipated in-service date of November 2018.
In December 2014, Eversource and Spectra Energy Corp announced an alliance with Iroquois Gas Transmission for the Access Northeast project. This alliance will provide New England natural gas distribution companies NUSCO and RRR.generators with additional access to natural gas supplies from multiple, diverse receipt points along the Algonquin pipeline system, including the Iroquois pipeline system.
34
Transmission Business: Overall, transmission business capital expenditures increased by $9.6$37.9 million in the first halfquarter of 2014,2015, as compared to the first halfquarter of 2013.2014. A summary of transmission capital expenditures by company for the first half of 2014 and 2013 is as follows:
|
| For the Six Months Ended June 30, |
| For the Three Months Ended March 31, | ||||||||
(Millions of Dollars) |
| 2014 |
| 2013 |
| 2015 |
| 2014 | ||||
CL&P |
| $ | 111.6 |
| $ | 84.1 |
| $ | 42.4 |
| $ | 36.2 |
NSTAR Electric |
|
| 70.2 |
|
| 79.3 |
|
| 21.4 |
|
| 12.4 |
PSNH |
|
| 44.3 |
|
| 35.0 |
|
| 28.9 |
|
| 16.7 |
WMECO |
|
| 33.1 |
|
| 41.5 |
|
| 23.8 |
|
| 16.3 |
NPT |
|
| 12.4 |
|
| 22.1 |
|
| 9.7 |
|
| 6.7 |
Total Transmission Segment |
| $ | 271.6 |
| $ | 262.0 |
| $ | 126.2 |
| $ | 88.3 |
NEEWS: GSRP, the first, largest and most complicated project within the NEEWS family of projects was fully energized on November 20, 2013. As of June 30, 2014, CL&P and WMECO have placed $638.1 million in service with minimal remaining close-out activities continuing throughout the remainder of 2014.
The Interstate Reliability Project which(IRP) includes CL&P's construction of an approximately 40-mile, 345 kV345-kV overhead line from Lebanon, Connecticut to the Connecticut-Rhode Island border in Thompson, Connecticut where it will connect to transmission enhancements being constructed by National Grid in Rhode Island and Massachusetts, is the second major NEEWS project. As of May 2014, all three states have issued siting approvals. Completing all the project permit requirements, the Army Corps of Engineers issued its permit on the project in the first quarter of 2014. Project construction isMassachusetts. Construction has been underway in all three states. NU'sstates since March 2014. Eversource's portion of the cost is estimated to be $218 million, and construction on its portion of the project is approximately 40 percentwe expect to complete as of June 30, 2014. The project is expected to be placed in serviceIRP by the end of 2015. As of March 31, 2015, IRP was approximately 90 percent complete, and CL&P had placed $34 million in service.
The Greater Hartford Central Connecticut Study (GHCC), which includes the reassessment of the Central Connecticut Reliability Project, continues to make progress. The final need results showed existing and worsening severe regional and local thermal overloads and voltage violations within each of the areas studied and across the interfaces of those areas. These results were presented to the ISO-NE Planning Advisory Committee in November 2013. On July 15, 2014, ISO-NE presented the preferred transmission solutions to its Planning Advisory Committee. These solutions are comprised of many 115 kV115-kV upgrades and are expected to cost approximately $350 million and be placed in service from 2016 through 2018. ISO New England posted the final Solutions Study for GHCC in late 2017.
Included as partFebruary 2015. The Reliability Committee recommended approval of NEEWSour Proposed Plan Applications to ISO New England at its March 17, 2015 meeting. The first siting filing for these projects was made to the Connecticut Siting Council on February 27, 2015. Additional siting filings are associated reliability relatedexpected to be made throughout 2015 and 2016. We expect to begin work on these projects $93.1 million of which have been placed in service. As of June 30, 2014, all construction on the associated reliability related projects has been completed. mid-2015 and complete GHCC-related work in 2018.
Through June 30, 2014,March 31, 2015, CL&P and WMECO capitalized $292$371.4 million and $573.4$573.7 million, respectively, in costs associated with NEEWS. Included in the NEEWS amounts are costs for IRP, of which $39.2CL&P capitalized $183.8 million in costs through March 31, 2015, and $6.4$15 million respectively, were capitalized in the first halfquarter of 2014. 2015.
Northern Pass: Northern Pass is NU'sEversource's planned HVDC transmission line from the Québec-New Hampshire border to Franklin, New Hampshire and an associated alternating current radial transmission line between Franklin and Deerfield, New Hampshire. Northern Pass will interconnect at the Québec-New Hampshire border with a planned HQ HVDC transmission line. NPT received ISO-NE approval under Section I.3.9 of the ISO tariff in 2013. By approving the project's Section I.3.9 application, ISO-NE determined that Northern Pass can reliably interconnect with the New England grid with no significant adverse effect on the reliability or operating characteristics of the regional energy grid and its participants. The $1.4 billion project is subject to comprehensive federal and state public permitting processes and is expected to be operational in the second half of 2017. The DOE continues to work on the draft Environmental Impact Statement (EIS)(draft EIS) for Northern Pass. This includes a reviewThe issuance of both the recommended route and various alternative routes. We expect the DOE to issue the draft EIS for public comment is anticipated in late 2014. Once it is published, the DOE will commence a process of receiving written and verbal comments on the draft EIS and we expect the issuance of a final EIS in the second half ofJune 2015. We expectNPT expects to file the state permitNew Hampshire Site Evaluation Committee application in January 2015the third quarter after receipt of the draft EIS.
44The $1.4 billion project is subject to federal and state public permitting processes and is now expected to be operational in the first half of 2019.
Greater Boston Reliability and Boston Network Improvements:Solutions: 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 initiativesprojects over the next five years.years to enhance the region's system reliability. On February 12, 2015, ISO-NE selected Eversource's and National Grid's proposed Greater Boston and New Hampshire Solution (Solution) as its preferred option because it is significantly less expensive than an alternate proposal and has superior performance criteria. The Solution consists of important electric transmission upgrades encompassing the Merrimack Valley area of southern New Hampshire and the metropolitan Boston area. We expect ISO-NE to select preferred solutionsestimate our investment in the second half of 2014,Solution will be $489 million, and project costs to be approximately $495 million for these new initiatives.we are pursuing the necessary regulatory approvals.
35
Distribution Business: A summary of distribution capital expenditures by company for the first half of 2014 and 2013 is as follows:
| For the Six Months Ended June 30, | For the Three Months Ended March 31, | ||||||||
(Millions of Dollars) | 2014 |
| 2013 | 2015 |
| 2014 | ||||
CL&P: |
|
|
|
|
|
|
|
|
|
|
Basic Business | $ | 24.3 |
| $ | 27.8 | $ | 27.2 |
| $ | 10.7 |
Aging Infrastructure |
| 74.7 |
|
| 71.3 |
| 34.2 |
|
| 34.3 |
Load Growth |
| 34.7 |
|
| 31.8 |
| 11.5 |
|
| 17.3 |
Total CL&P |
| 133.7 |
|
| 130.9 |
| 72.9 |
|
| 62.3 |
NSTAR Electric: |
|
|
|
|
|
|
|
|
|
|
Basic Business |
| 50.2 |
|
| 48.3 |
| 22.2 |
|
| 29.6 |
Aging Infrastructure |
| 53.1 |
|
| 51.3 |
| 13.5 |
|
| 22.9 |
Load Growth |
| 14.7 |
|
| 13.4 |
| 3.9 |
|
| 6.5 |
Total NSTAR Electric |
| 118.0 |
|
| 113.0 |
| 39.6 |
|
| 59.0 |
PSNH: |
|
|
|
|
|
|
|
|
|
|
Basic Business |
| 14.1 |
|
| 8.5 |
| 12.3 |
|
| 5.8 |
Aging Infrastructure |
| 26.5 |
|
| 20.0 |
| 9.2 |
|
| 12.5 |
Load Growth |
| 13.1 |
|
| 10.1 |
| 6.7 |
|
| 6.1 |
Total PSNH |
| 53.7 |
|
| 38.6 |
| 28.2 |
|
| 24.4 |
WMECO: |
|
|
|
|
|
|
|
|
|
|
Basic Business |
| 4.5 |
|
| 3.7 |
| 3.1 |
|
| 1.5 |
Aging Infrastructure |
| 8.1 |
|
| 10.8 |
| 4.5 |
|
| 3.3 |
Load Growth |
| 2.8 |
|
| 3.3 |
| 1.8 |
|
| 1.4 |
Total WMECO |
| 15.4 |
|
| 17.8 |
| 9.4 |
|
| 6.2 |
Total - Electric Distribution (excluding Generation) |
| 320.8 |
|
| 300.3 |
| 150.1 |
|
| 151.9 |
PSNH Generation |
| 5.2 |
|
| 4.3 |
| 2.6 |
|
| 2.5 |
WMECO Generation |
| 7.4 |
|
| 0.3 |
| - |
|
| 4.1 |
Total - Natural Gas |
| 75.7 |
|
| 70.3 |
| 23.2 |
|
| 25.2 |
Total Electric and Natural Gas Distribution Segment | $ | 409.1 |
| $ | 375.2 | |||||
Total Distribution Segment | $ | 175.9 |
| $ | 183.7 |
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, distributionplant 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.
NSTAR Electric's capital spending program decreased by $19.4 million in the first quarter of 2015, as compared to the first quarter of 2014, as a result of the impact from the winter weather and storms in the greater Boston metropolitan area.
Natural Gas Business Expansion and Enhancement: In 2013, in accordance with Connecticut law and regulations, PURA approved a comprehensive joint natural gas infrastructure expansion plan (expansion plan) filed by Yankee Gas and other Connecticut natural gas distribution companies. The expansion plan described how Yankee Gas expects to add approximately 82,000 new natural gas heating customers over a 10-year period. Yankee Gas estimates that its portion of the plan will cost approximately $700 million over 10 years. In January 2015, PURA approved a joint settlement agreement proposed by Yankee Gas and other Connecticut natural gas distribution companies and regulatory agencies that clarified the procedures and oversight criteria applicable to the expansion plan.
In October 2014, pursuant to new legislation, NSTAR Gas filed the Gas System Enhancement Program (GSEP) with the DPU. NSTAR Gas' program accelerates the replacement of certain natural gas distribution facilities in the system within 25 years. The GSEP includes a new tariff that provides NSTAR Gas an opportunity to collect the costs for the program on an annual basis through a newly designed reconciling factor. On April 30, 2015, the DPU approved the GSEP. We have projected capital expenditures of approximately $200 million for the period 2015 through 2018 for the GSEP, which are consistent with our request in the NSTAR Gas rate case application currently before the DPU.
FERC Regulatory Issues
FERC Base ROE Complaints: On September 30,Beginning in 2011, a complaint wasthree separate complaints were filed jointly at FERC under Sections 206 and 306by combinations of the Federal Power Act by several New England state attorneys general, state regulatory commissions, consumer advocates, consumer groups, municipal parties and other parties (the "Complainants"). TheIn these three separate complaints, the Complainants alleged thatchallenged the NETOs' base ROE of 11.14 percent that has beenwas utilized since 2006 in the calculation of formula rates for transmission service under the ISO-NE Open Access Transmission Tariff by NETOs, including CL&P, NSTAR Electric, PSNH and WMECO, was unjust and unreasonable and asserted that the rate was excessive due to changes in the capital markets. Complainants sought an order to reduce it prospectively from the date of the final FERC order and for the 15-month complaint refund periods stipulated in the separate complaints. In 2014, the FERC ordered the base ROE effective October 1, 2011, and to require refunds. The FERCbe set the case for trial before a FERC ALJ after settlement negotiations were unsuccessful in August 2012.
On August 6, 2013, the FERC ALJ issued an initial decision finding that the base ROE in effect from October 1, 2011 through December 31, 2012 (refund period) was not reasonable, and recommended separate base ROEs for the refund period of 10.6 percent and for the period beginning when FERC issues its final decision (prospective period) of 9.7 percent, leaving policy considerations and additional adjustments to the FERC. In the third quarter of 2013, the Company recorded a series of reserves at its electric subsidiaries to recognize the potential financial impact from the FERC ALJ's initial decision for the refund period. The aggregate after-tax charge to third quarter 2013 earnings totaled $14.3 million at NU, which represented reserves of $7.7 million at CL&P, $3.4 million at NSTAR Electric, $1.4 million at PSNH and $1.8 million at WMECO.
On June 19, 2014, FERC issued an order partially affirming and partially reversing the ALJ's initial decision. FERC set a single tentative base ROE of 10.57 percent for the first complaint refund period and prospective period. FERC also modified its traditional methodology by adopting a two-step discounted cash flow analysis that it utilizes to determine the ROEs of both natural gasprospectively from October 16, 2014 and oil pipeline projects. Using this methodology, FERC determined a new zone of reasonableness of 7.03 percent to 11.74 percent, and set the tentative base ROE at the 75th percentile of this new zone. FERC also stated that a utility's total or maximum ROE inclusive of transmission incentive ROE adders, shouldshall not exceed the top of the new zone of reasonableness, producedwhich was set at 11.74 percent. The NETOs and the Complainants sought rehearing from FERC. In late 2014, the NETOs made a compliance filing, which was challenged by this methodology.the Complainants, and in accordance with FERC instituted a paper hearingorders, began issuing refunds to customers from the first complaint period.
On March 3, 2015, FERC issued an order denying all issues raised on the long-term growth rate portion of the methodology, before it issues a final determination on the base ROE. On July 21, 2014,rehearing by the NETOs and Complainants filed rehearing requests in this proceeding.
the first base ROE complaint. The FERC order upheld the base ROE of 10.57 percent for the first complaint refund period and prospectively from October 16, 2014, and upheld that the utility's total ROE (the base ROEplus anyincentive adders) for the transmission assets to which the adder applies is capped at the top of the zone of reasonableness, which is currently set at 11.74 percent. As a result ofclarifying information related to how the ROE cap is applied, which is contained in the order, Eversource adjusted its reservein the first quarter of 2015 and recognized an after-tax charge to earnings (excluding interest)
4536
On December 27, 2012, a second complaintof $12.4 million, of which $7.9 million was filed jointly at FERC by several additional consumer groups and municipal parties, which challenged the NETOs' base ROE and sought refunds for the 15-month period beginning January 1, 2013. On June 19, 2014, the FERC issued a second order finding that the complaint raised issues of material fact, and set this complaint for trial, should settlement negotiations be unsuccessful. FERC stated that it could issue an order in this case by mid-2016. On July 21, 2014, the NETOs filed a rehearing request in this proceeding.
Though NU cannot predict the ultimate outcome of this proceeding, in the second quarter of 2014, the Company recorded a series of reserves at its electric subsidiaries to recognize the potential financial impact from the FERC's two orders issued on June 19, 2014 for the two refund periods. The aggregate after-tax charge to second quarter 2014 earnings totaled $32.1 million at NU, which represented reserves of $18.5 million at CL&P, $6.1$1.4 million at NSTAR Electric, $2$0.6 million at PSNH, and $5.5$2.5 million at WMECO. The charge was recorded as a regulatory liability.
FERC Order No. 1000: On July 31, 2014,March 19, 2015, FERC acted on all rehearing requests filed by the Complainants filed anNETOs, including CL&P, NSTAR Electric, PSNH and WMECO, and other parties and accepted the November 2013 compliance filing made by ISO-NE and the NETOs, subject to further compliance. FERC accepted our proposal that the new competitive transmission planning process will not apply to certain projects, which have been declared as the preferred solution by ISO-NE, unless ISO-NE later decides the solution must be re-evaluated. FERC determined on rehearing that we can restore provisions that recognize the NETOs’ rights to retain use and control of their existing rights of ways (ROWs).
FERC affirmed that it can eliminate our right of first refusal to build transmission in New England even though FERC previously approved and granted special protections to these rights. We are currently evaluating this and other parts of the FERC decision with the NETOs and ISO-NE. Implementation of FERC's goals in New England, including within our service territories, may expose us to competition for construction of transmission projects, additional complaintregulatory considerations, and potential delay with FERC. At this time,respect to future transmission projects. While the Company cannot determine the outcomeFERC Orders may bring new challenges, we believe there are also opportunities for us to compete for transmission reliability projects outside of this complaint.our service territories.
Regulatory Developments and Rate Matters
The Regulated companies' distribution rates are set by their respective state regulatory commissions, and their tariffs include mechanisms for periodically adjusting their rates for the recovery of specific incurred costs. Other than as described below, for the first halfquarter of 2014,2015, changes made to the Regulated companies' rates did not have a material impact on their earnings, financial position, or cash flows. For further information, see "Financial Condition and Business Analysis – Regulatory Developments and Rate Matters" included in Item 7, "Management's Discussion and Analysis of Financial Condition and Results of Operations," of the NU 2013Eversource 2014 Annual Report on Form 10-K.
Connecticut:
Distribution RatesYankee Gas - Settlement Agreement: On June 9, 2014, CL&P filedApril 29, 2015, the PURA approved a settlement agreement entered into among Yankee Gas, the Connecticut Office of Consumer Counsel, and the PURA Staff, which eliminates the requirement to file a rate case in 2015. Under the terms of the settlement agreement, Yankee Gas will provide a $1.5 million rate credit to firm customers beginning in December 2015, will establish an applicationearnings sharing mechanism whereby Yankee Gas and its customers will share equally any earnings exceeding a 9.5 percent ROE in a twelve month period commencing with the PURAperiod from April 1, 2015 through March 31, 2016, and Yankee Gas shall forgo its right to amend customer rates, effective December 1, 2014. CL&P requestedfile a rate case for an increase in totalits base distribution rates prior to January 1, 2017. This does not impact the rates charged under the CES program. In addition, the settlement agreement resolves two pending regulatory proceedings before PURA pertaining to a review of $231.5 million.Yankee Gas’ overearnings. In the first quarter of 2015, Yankee Gas recorded the $1.5 million expected refund to customers as a reduction to operating revenues.
Massachusetts:
2014 Comprehensive Settlement Agreement: On March 2, 2015, the DPU approved the comprehensive settlement agreement between NSTAR Electric, NSTAR Gas and the Massachusetts Attorney General (the "Settlement") as filed with the DPU on December 31, 2014. The Settlement resolved the outstanding NSTAR Electric CPSL program filings for 2006 through 2011, the NSTAR Electric and NSTAR Gas PAM and energy efficiency-related customer billing adjustments reported in 2012, and the recovery of LBR related to NSTAR Electric's energy efficiency programs for 2008 through 2011 (11 dockets in total). As a result, NSTAR Electric and NSTAR Gas will refund a combined $44.7 million to customers. The refund was recorded as a regulatory liability as of March 31, 2015 and NSTAR Electric recognized a $13 million after-tax benefit in the first quarter of 2015.
Basic Service Bad Debt Adder: In accordance with a generic 2005 DPU order, electric utilities in Massachusetts recover the energy-related portion of bad debt costs in their Basic Service rates. In February 2007, NSTAR Electric filed its 2005 through 2006 Basic Service reconciliation with the DPU proposing an adjustment related to the increase includes aof its Basic Service bad debt charge-offs. In June 2007, the DPU approved NSTAR Electric's proposed adjustment to the Basic Service Adder but instructed NSTAR Electric to reduce distribution rates by an equal and offsetting amount. This adjustment to NSTAR Electric's distribution rates would have eliminated 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. NSTAR Electric took the position that it had fully removed the collection of energy-related bad debt costs from its base distribution rate increase of $116.7 million, an increaserates effective January 1, 2006; therefore, no further adjustment to distribution rates was warranted. In 2012, the SJC vacated the DPU order and remanded the matter to the DPU for the annual recovery of $89.5 million of previously approved 2011 and 2012 deferred storm restoration costs totaling $365 million, and an increase of $25.3 million for previously approved electric system resiliency costs. Currently, hearings are scheduled to occur in late August through September, and a final decision is expected in December 2014.further review.
On June 17, 2014, PURAJanuary 7, 2015, the DPU issued an order concluding that NSTAR Electric had appropriately accounted for the removal of supply-related bad debt costs from base distribution rates effective January 1, 2006. The DPU ordered CL&PNSTAR Electric and the Massachusetts Attorney General to use the DOE Phase II Damages proceeds of $65.4 million received on June 1, 2014 to offset the $365 million in 2011 and 2012 deferred storm restoration costs that were approved for recovery by the PURA on March 12, 2014. For further informationcollaborate on the spent nuclear fuel litigation awards, see Note 8C, "Commitments and Contingencies – Contractual Obligations – Yankee Companies." Asreconciliation of energy-related bad debt costs through 2014. During the second quarter of 2015, NSTAR Electric expects to file with the DPU to recover from customers approximately $43 million of supply-related bad debt costs. In the first quarter of 2015, as a result CL&P will now recover approximately $300 million in storm costs from customers, which will be reflected in final rates approved by PURA at the conclusion of the current CL&P distribution rate case.DPU order, NSTAR Electric increased its regulatory assets by $24.2 million, resulting in an increase in after-tax earnings of $14.5 million.
New Hampshire:
PSNH Generation Agreement::In 2013, the NHPUC opened On March 11, 2015, PSNH entered into an agreement in principle in 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 onsettlement Term Sheet with the New Hampshire competitive electric market. In a 2013 NHPUC staff report accepted byOffice of Energy and Planning, certain members of the Staff of the NHPUC, the NHPUC staff recommended that the NHPUC examine whether default service rates remain sustainable on a going forward basis, define "just and reasonable" with respect to default service in the context of competitive retail markets, analyze the current and expected value of PSNH's generating units, and identify means to mitigate and address stranded cost recovery. In October 2013, the New Hampshire Legislative Oversight Committee on Electric Utility Restructuring (Oversight Committee) requested that the NHPUC conduct an analysis to determine whether it is now in the economic interest of PSNH's retail customers for PSNH to divest its interest in generation plants. On November 1, 2013, the Oversight Committee asked for a preliminary report by April 1, 2014 that would include a third party valuation of PSNH's generating assets and a report from NHPUC staff members concerning customers' economic interests in those generating assets.
On April 1, 2014, the NHPUC staff issued a "Preliminary Status Report Addressing the Economic Interest of PSNH's Retail Customers as it Relates to the Potential Divestiture of PSNH's Generating Plants," which included a consultant's analysisOffice of the fair market valueConsumer Advocate, and two State Senators. The Term Sheet is designed to provide a resolution of PSNH generating assets and long-term power purchase contracts. The consultant's analysis estimated the fair market value ofissues pertaining to PSNH's generation assets to be $225 million asin pending regulatory proceedings before the NHPUC. Under the terms of December 31, 2013 and compared that amount to a stated net book value of $660 million, implying potential "stranded costs" in excess of $400 million. NHPUC staff made three recommendations: (1) that any further actions relating to PSNH's generating assets await a final decision inthe Term Sheet, the Clean Air Project (scrubber) prudence proceeding; (2) that existing laws regarding divestiture, energy service,proceeding will be resolved and cost recoveryall remaining Clean Air Project costs will be harmonized; and (3) that ISO-NE provide input on the economic and reliability consequences of retirement of PSNH's coal- and oil-fired electric generating plants.
During its 2014 session,included in response to the NHPUC staff report, the House and Senate passed a bill, which enacted changes to the laws governing divestiture of PSNH's generating assets. That bill requires the NHPUC to initiate a proceeding beforerates effective January 1, 2015,2016. PSNH has agreed to determine whether all or some of PSNH's generation assets should be divested. A progress report from the NHPUC must be made by March 31, 2015. The bill also changes the law to give the NHPUC express authority to orderpursue the divestiture of all or some of PSNH'sits generation assets if theupon NHPUC finds it is in the economic interest of customers to do so. The bill also clarifies the definition of "stranded costs" to include costs approved for recovery by the NHPUC in connection with the divestiture or retirement of PSNH's generation assets.
In the event of generation asset divestiture or retirement, present law, the PSNH Restructuring Settlement Agreement approved in 2000, and the Bill all require that the NHPUC provide recovery of any stranded costs by PSNH. We continue to believe all costs and generation investments are probable of recovery.
4637
Legislativeapproval of a final Settlement Agreement reflecting the provisions of the Term Sheet. As part of the planned Settlement Agreement, PSNH has agreed to forego recovery of $25 million of the deferred equity return related to the Clean Air Project. Upon completion of the divestiture process, all remaining stranded costs, including any remaining deferred equity return in excess of the $25 million that PSNH has agreed to forego, will be recovered via bonds that will be secured by a non-bypassable charge to PSNH's customers. In addition, PSNH will not seek a general distribution rate increase that would become effective before July 1, 2017 and Policy Matterswill contribute $5 million to create a clean energy fund, which will not be recoverable from its customers.
Massachusetts:
Gas ReplacementConsummation of the Term Sheet provisions is conditioned upon the enactment of authorizing securitization legislation in New Hampshire, completion of the Settlement Agreement, and Expansion:NHPUC approval of the Settlement Agreement. On July 7, 2014, Massachusetts enacted "An Act RelativeMarch 26, 2015, the New Hampshire Senate passed the legislation, which is currently pending in the New Hampshire House. We expect legislation to Natural Gas Leaks" (the Act). The Act establishes a uniform natural gas leak classification standard for all Massachusetts natural gas utilitiesbe finalized in the third quarter of 2015 and a program that accelerates the replacement of aging natural gas infrastructure. The program will enable companies, including NSTAR Gas,NHPUC decision to better manage the scheduling and costs of replacement. The Act also calls for the DPU to authorize natural gas utilities to design and offer programs to customers that will increase the availability, affordability and feasibility of natural gas service for new customers. be issued in late 2015.
Critical Accounting Policies
The preparation of financial statements in conformity with GAAP requires management to make estimates, assumptions and, at times, difficult, subjective or complex judgments. Changes in these estimates, assumptions and judgments, in and of themselves, could materially impact our financial position, results of operations or cash flows. Our management communicates to and discusses with the Audit Committee of our Board of Trustees significant matters relating to critical accounting policies. Our critical accounting policies that we believed were the most critical in nature were reported in the NU 2013Eversource 2014 Form 10-K. There have been no material changes with regard to these critical accounting policies.
Other Matters
Accounting Standards Recently Adopted:Standards: For information regarding new accounting standards, see Note 1B, "Summary of Significant Accounting Policies –Accounting Standards," to the financial statements.
Contractual Obligations and Commercial Commitments: Refer to Note 8B, "CommitmentsThere have been no material contractual obligations identified and Contingencies – Long-Term Contractual Arrangements," for discussion ofno material changes with regard to the contractual obligations.obligations and commercial commitments previously disclosed in the Eversource 2014 Form 10-K.
Web Site: Additional financial information is available through our webwebsite atwww.eversource.com. We make available through our website a link to the SEC's EDGAR website (http://www.sec.gov/edgar/searchedgar/companysearch.html), at which site atwww.nu.com.Eversource's, CL&P's, NSTAR Electric's, PSNH's and WMECO's Annual Reports on Form 10-K, Quarterly Reports on Form 10-Q, Current Reports on Form 8-K and any amendments to those reports may be reviewed. Information contained on the Company's website or that can be accessed through the website is not incorporated into and does not constitute a part of this Quarterly Report on Form 10-Q.
4738
RESULTS OF OPERATIONS – NORTHEAST UTILITIESEVERSOURCE ENERGY AND SUBSIDIARIES
The following provides the amounts and variances in operating revenues and expense line items forin the condensed consolidated statements of income for NUEversource for the three months ended March 31, 2015 and 2014 included in this Quarterly Report on Form 10-Q for the three and six months ended June 30, 2014 and 2013:10-Q:
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| Operating Revenues and Expenses |
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| Operating Revenues and Expenses |
| ||||||||||||||||||
| For the Three Months Ended June 30, |
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| For the Six Months Ended June 30, |
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| Increase/ |
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| Increase/ |
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(Millions of Dollars) | 2014 |
| 2013 |
| (Decrease) |
| Percent |
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| 2014 |
| 2013 |
| (Decrease) |
| Percent |
| ||||||||
Operating Revenues | $ | 1,677.6 |
| $ | 1,635.9 |
| $ | 41.7 |
| 2.5 | % |
| $ | 3,968.2 |
| $ | 3,630.9 |
| $ | 337.3 |
| 9.3 | % | ||
Operating Expenses: |
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| Purchased Power, Fuel and Transmission |
| 624.2 |
|
| 488.3 |
|
| 135.9 |
| 27.8 |
|
|
| 1,602.4 |
|
| 1,236.1 |
|
| 366.3 |
| 29.6 |
| |
| Operations and Maintenance |
| 373.2 |
|
| 357.2 |
|
| 16.0 |
| 4.5 |
|
|
| 724.9 |
|
| 703.3 |
|
| 21.6 |
| 3.1 |
| |
| Depreciation |
| 152.2 |
|
| 159.5 |
|
| (7.3) |
| (4.6) |
|
|
| 303.0 |
|
| 314.5 |
|
| (11.5) |
| (3.7) |
| |
| Amortization of Regulatory |
| (3.5) |
|
| 54.6 |
|
| (58.1) |
| (a) |
|
|
| 54.4 |
|
| 108.6 |
|
| (54.2) |
| (49.9) |
| |
| Amortization of Rate Reduction Bonds |
| - |
|
| 8.1 |
|
| (8.1) |
| (100.0) |
|
|
| - |
|
| 42.6 |
|
| (42.6) |
| (100.0) |
| |
| Energy Efficiency Programs |
| 102.7 |
|
| 94.1 |
|
| 8.6 |
| 9.1 |
|
|
| 241.5 |
|
| 199.9 |
|
| 41.6 |
| 20.8 |
| |
| Taxes Other Than Income Taxes |
| 134.8 |
|
| 123.5 |
|
| 11.3 |
| 9.1 |
|
|
| 280.3 |
|
| 256.4 |
|
| 23.9 |
| 9.3 |
| |
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| Total Operating Expenses |
| 1,383.6 |
|
| 1,285.3 |
|
| 98.3 |
| 7.6 |
|
|
| 3,206.5 |
|
| 2,861.4 |
|
| 345.1 |
| 12.1 |
|
Operating Income | $ | 294.0 |
| $ | 350.6 |
| $ | (56.6) |
| (16.1) | % |
| $ | 761.7 |
| $ | 769.5 |
| $ | (7.8) |
| (1.0) | % | ||
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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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| For the Three Months Ended June 30, |
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| For the Six Months Ended June 30, |
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(Millions of Dollars) | 2014 |
| 2013 |
| Increase/ |
| Percent |
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| 2014 |
| 2013 |
| Increase/ (Decrease) |
| Percent |
| |||||||
Electric Distribution | $ | 1,261.8 |
| $ | 1,221.6 |
| $ | 40.2 |
| 3.3 | % |
| $ | 2,847.8 |
| $ | 2,595.8 |
| $ | 252.0 |
| 9.7 | % | |
Natural Gas Distribution |
| 195.5 |
|
| 154.1 |
|
| 41.4 |
| 26.9 |
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|
| 628.3 |
|
| 515.9 |
|
| 112.4 |
| 21.8 |
| |
| Total Distribution |
| 1,457.3 |
|
| 1,375.7 |
|
| 81.6 |
| 5.9 |
|
|
| 3,476.1 |
|
| 3,111.7 |
|
| 364.4 |
| 11.7 |
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Transmission |
| 206.9 |
|
| 247.9 |
|
| (41.0) |
| (16.5) |
|
|
| 458.9 |
|
| 487.4 |
|
| (28.5) |
| (5.8) |
| |
| Total Regulated Companies |
| 1,664.2 |
|
| 1,623.6 |
|
| 40.6 |
| 2.5 |
|
|
| 3,935.0 |
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| 3,599.1 |
|
| 335.9 |
| 9.3 |
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Other and Eliminations |
| 13.4 |
|
| 12.3 |
|
| 1.1 |
| 8.9 |
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|
| 33.2 |
|
| 31.8 |
|
| 1.4 |
| 4.4 |
| |
Total Operating Revenues | $ | 1,677.6 |
| $ | 1,635.9 |
| $ | 41.7 |
| 2.5 | % |
| $ | 3,968.2 |
| $ | 3,630.9 |
| $ | 337.3 |
| 9.3 | % |
A summary of our retail electric sales and firm natural gas sales were as follows: | ||||||||||||||||||
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| For the Three Months Ended June 30, |
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| For the Six Months Ended June 30, |
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| Increase/ |
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| 2014 |
| 2013 |
| (Decrease) |
| Percent |
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| 2014 |
| 2013 |
| Increase |
| Percent |
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Retail Electric Sales in GWh | 12,536 |
| 12,911 |
| (375) |
| (2.9) | % |
| 26,884 |
| 26,707 |
| 177 |
| 0.7 | % | |
Firm Natural Gas Sales in Million Cubic Feet | 16,924 |
| 16,257 |
| 667 |
| 4.1 |
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| 63,841 |
| 56,872 |
| 6,969 |
| 12.3 |
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| Operating Revenues and Expenses |
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| For the Three Months Ended March 31, |
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| Increase/ |
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(Millions of Dollars) | 2015 |
| 2014 |
| (Decrease) |
| Percent |
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| |||||
Operating Revenues | $ | 2,513.4 |
| $ | 2,290.6 |
| $ | 222.8 |
| 9.7 | % |
| ||
Operating Expenses: |
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|
|
|
|
|
|
|
|
|
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| Purchased Power, Fuel and Transmission |
| 1,162.1 |
|
| 978.2 |
|
| 183.9 |
| 18.8 |
|
| |
| Operations and Maintenance |
| 333.4 |
|
| 351.7 |
|
| (18.3) |
| (5.2) |
|
| |
| Depreciation |
| 163.8 |
|
| 150.8 |
|
| 13.0 |
| 8.6 |
|
| |
| Amortization of Regulatory Assets, Net |
| 60.6 |
|
| 57.9 |
|
| 2.7 |
| 4.7 |
|
| |
| Energy Efficiency Programs |
| 146.6 |
|
| 138.8 |
|
| 7.8 |
| 5.6 |
|
| |
| Taxes Other Than Income Taxes |
| 149.4 |
|
| 145.5 |
|
| 3.9 |
| 2.7 |
|
| |
|
| Total Operating Expenses |
| 2,015.9 |
|
| 1,822.9 |
|
| 193.0 |
| 10.6 |
|
|
Operating Income |
| 497.5 |
|
| 467.7 |
|
| 29.8 |
| 6.4 |
|
| ||
Interest Expense |
| 94.8 |
|
| 90.0 |
|
| 4.8 |
| 5.3 |
|
| ||
Other Income, Net |
| 5.7 |
|
| 1.7 |
|
| 4.0 |
| (a) |
|
| ||
Income Before Income Tax Expense |
| 408.4 |
|
| 379.4 |
|
| 29.0 |
| 7.6 |
|
| ||
Income Tax Expense |
| 153.2 |
|
| 141.5 |
|
| 11.7 |
| 8.3 |
|
| ||
Net Income |
| 255.2 |
|
| 237.9 |
|
| 17.3 |
| 7.3 |
|
| ||
Net Income Attributable to Noncontrolling Interests |
| 1.9 |
|
| 1.9 |
|
| - |
| - |
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| ||
Net Income Attributable to Controlling Interest | $ | 253.3 |
| $ | 236.0 |
| $ | 17.3 |
| 7.3 | % |
| ||
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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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| ||||||||||||
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| For the Three Months Ended March 31, |
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| |||||||||
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| Increase/ |
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(Millions of Dollars) | 2015 |
| 2014 |
| (Decrease) |
| Percent |
|
| |||||
Electric Distribution | $ | 1,760.1 |
| $ | 1,585.9 |
| $ | 174.2 |
| 11.0 | % |
| ||
Natural Gas Distribution |
| 507.4 |
|
| 432.8 |
|
| 74.6 |
| 17.2 |
|
| ||
| Total Distribution |
| 2,267.5 |
|
| 2,018.7 |
|
| 248.8 |
| 12.3 |
|
| |
Transmission |
| 249.0 |
|
| 252.1 |
|
| (3.1) |
| (1.2) |
|
| ||
| Total Regulated Companies |
| 2,516.5 |
|
| 2,270.8 |
|
| 245.7 |
| 10.8 |
|
| |
Other and Eliminations |
| (3.1) |
|
| 19.8 |
|
| (22.9) |
| (a) |
|
| ||
Total Operating Revenues | $ | 2,513.4 |
| $ | 2,290.6 |
| $ | 222.8 |
| 9.7 | % |
| ||
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(a) Percent greater than 100 percent not shown as it is not meaningful. |
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A summary of our retail electric sales volumes and firm natural gas sales volumes were as follows: | ||||||||||||||
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|
| For the Three Months Ended March 31, |
|
| |||||||||
|
|
| 2015 |
| 2014 |
| Increase |
| Percent |
|
| |||
Retail Electric Sales Volumes in GWh |
| 14,448 |
|
| 14,348 |
|
| 100 |
| 0.7 | % |
| ||
Firm Natural Gas Sales Volumes in Million Cubic Feet |
| 50,572 |
|
| 46,917 |
|
| 3,655 |
| 7.8 |
|
|
Operating Revenues increased by $222.8 million in the secondfirst quarter of 2014,2015, as compared to the secondsame period in 2014.
Electric distribution segment revenues increased by $174.2 million as a result of the impact of both weather and increased rates on our base distribution revenues ($35 million), the 2014 Comprehensive Settlement Agreement at NSTAR Electric ($11 million), and the aggregate impact on revenues of corresponding costs that are recovered through our cost tracking mechanisms, which were the result of increases in energy supply costs ($211 million), offset by decreased costs associated with federally mandated congestion charges and transition costs ($46.6 million).
Energy supply costs were impacted by the overall New England wholesale energy supply market in which natural gas delivery costs are adversely impacting the cost of electric energy purchased for our retail electric customers. Energy supply costs are recovered from customers in rates through cost tracking mechanisms and therefore have no impact on earnings. Electric distribution segment revenues were favorably impacted by an increase in base distribution revenues, which reflected a 0.7 percent increase in retail electric sales volumes driven primarily by the colder winter weather experienced throughout our service territories in the first quarter of 2013. 2015, and the impact of CL&P's base distribution rate case effective December 1, 2014. Additionally, in connection with the 2014 Comprehensive Settlement Agreement, NSTAR Electric recognized an $11 million benefit to distribution revenues in the first quarter of 2015. These increases were partially offset by decreases in rates related to the recovery of costs associated with federally mandated congestion charges and transition cost recovery revenues, which are also recovered through cost tracking mechanisms.
Effective December 1, 2014, CL&P’s distribution revenues were decoupled from its sales volumes and CL&P no longer recognized LBR. This is similar to WMECO's revenue decoupling mechanism in that it provides CL&P a base amount of distribution revenues ($1.041 billion on an annual basis) and effectively breaks the relationship between revenues and customer electricity usage. Revenue decoupling mechanisms ensure the recovery of our approved base distribution revenue requirements. Therefore, changes in sales volumes have no impact on the level of base distribution revenue realized. In the first quarter of 2014, which was colder than normal, CL&P’s rates were not decoupled.
39
The natural gas distribution segment revenues increased by $74.6 million due primarily to an increase in rates related to the recovery of costs associated with the procurement of natural gas supply ($56.1 million). Natural gas supply costs were impacted by the overall New England wholesale energy supply market in which natural gas delivery costs are adversely impacting the cost of natural gas purchased on behalf of our retail natural gas customers. Natural gas supply costs are recovered from customers in rates through cost tracking mechanisms and therefore have no impact on earnings. In addition, revenues increased due to the firm natural gas base distribution revenues increase ($12.4 million) due primarily reflectsto a 7.8 percent increase in firm natural gas sales volumes, which was driven primarily by the colder winter. The weather conditions experienced were significantly colder than both normal and the same period last year throughout our natural gas service territories in Connecticut and Massachusetts. Weather-normalized firm natural gas sales volumes (based on 30-year average temperatures) increased 3.2 percent in 2015, as compared to 2014, due primarily to residential and commercial customer growth.
The transmission segment revenues decreased by $3.1 million due primarily to the impact of the $20 million reserve related to the March 2015 FERC ROE order, partially offset by the recovery of higher revenue requirements associated with ongoing investments in our transmission infrastructure.
Purchased Power, Fuel and Transmission expense includes costs associated with purchasing electricity and natural gas on behalf of our customers. Fluctuations in theseThese energy supply costs are recovered from customers in rates and thereforethrough cost tracking mechanisms, which have no impact on earnings. Retail electric sales volumes decreased 2.9 percent from the second quarter of 2013 as a result of milder temperatures in late Mayearnings (tracked costs). Purchased Power, Fuel and June of 2014, as well as the impact of utility-sponsored energy efficiency programs. Firm natural gas sales volumeTransmission increased 4.1 percent from the second quarter of 2013 as customer growth and economic conditions in our service territory have shown steady improvement over the past year.
As noted above, our respective utility-sponsored energy efficiency programs have the impact of reducing both retail electric and firm natural gas sales. Certain utility operating companies are permitted to bill customers for lost base revenues related to reductions in sales volume as a result of their energy efficiency. In the second quarter of 2014, base electric and natural gas distribution revenues decreased $3 million, compared to the second quarter of 2013 (including the impact from the recognition of lost base revenues).
Transmission revenues decreased in the second quarter of 2014, as compared to the second quarter of 2013, due primarily to the impact of the reserves recorded during the second quarter of 2014 as a result of the FERC ROE orders issued in the FERC base ROE complaints. For further information, see "FERC Regulatory Issues - FERC Base ROE Complaints"in thisManagement's Discussion and Analysis.
Operating Revenues increased in the first half of 2014, as compared to the first half of 2013. The increase reflects higher retail electric and firm natural gas sales volumes primarily as a result of the significantly colder weather in the first quarter of 2014,2015, as compared to the same period in 2013,2014, due primarily to the following:
(Millions of Dollars) | Increase/(Decrease) | |
Electric Distribution | $ | 138.6 |
Natural Gas Distribution | 62.3 | |
Transmission | 0.9 | |
Other and Eliminations | (17.9) | |
Total Purchased Power, Fuel and Transmission | $ | 183.9 |
The increase in purchased power at the electric and natural gas distribution businesses were driven by the overall impact of higher costs associated with the procurement of energy supply. Our energy supply costs were impacted by higher natural gas transportationdelivery 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 purchased for our retail electric customers. Fluctuations in energy supply costs are recovered from customers in rates and therefore have no impact on earnings.
As noted above, the increase in distribution revenues reflects an increase of approximately 0.7 percent in retail electric sales and 12.3 percent in firm natural gas sales. The increase in sales volumes was driven primarily by the cold winter weather experienced throughout our service territories in the first quarter of 2014. The winter was significantly colder than both normal and the same period last year throughout New England. Weather-normalized retail electric sales (based on 30-year average temperatures) decreased 0.1 percent in the first half of 2014, as compared to the same
48
period in 2013, reflecting the impact of our utility-sponsored energy efficiency programs. Weather-normalized total firm natural gas sales increased 4.1 percent in the first half of 2014, as compared to the same period in 2013, due primarily to residential and commercial customer growth.
Certain utility operating companies are permitted to bill customers for lost base revenues related to reductions in sales volume as a result of their energy efficiency. In the first half of 2014, base electric and natural gas distribution revenues increased $38 million, compared to the first half of 2013 (including the impact from the recognition of lost base revenues).
Transmission revenues decreased in the first half of 2014, as compared to the first half of 2013, due primarily to the impact of the reserve recorded during the second quarter of 2014 as a result of the FERC ROE orders issued in the FERC base ROE complaints.
Purchased Power, Fuel and Transmission increased for the three and six months ended June 30, 2014, as compared to the same periods in 2013, due primarily to the following:
| Three Months Ended |
| Six Months Ended | ||
(Millions of Dollars) | Increase/(Decrease) |
| Increase/(Decrease) | ||
Electric distribution segment fuel and energy supply costs | $ | 139.6 |
| $ | 334.7 |
Firm natural gas sales related costs |
| 35.3 |
|
| 69.2 |
Transmission segment costs |
| (0.7) |
|
| (3.2) |
All other (including eliminations) |
| 3.6 |
|
| 15.7 |
Partially offset by: |
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|
|
Electric distribution segment purchased power and deferred fuel costs |
| (41.9) |
|
| (50.1) |
| $ | 135.9 |
| $ | 366.3 |
Operations and Maintenanceexpense includes tracked costs that are recovered in rates through cost tracking mechanisms, which have no earnings impact (tracked costs), and costs that are recovered through base electric and natural gas distribution rates (andrates; therefore variances impact earnings)earnings (non-tracked costs). Operations and Maintenance increased fordecreased in the three and six months ended June 30, 2014,first quarter of 2015, as compared to the same periodsperiod in 2013,2014, due primarily to the following:
| Three Months Ended |
| Six Months Ended | ||
(Millions of Dollars) | Increase/(Decrease) |
| Increase/(Decrease) | ||
Base Electric Distribution: |
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|
|
|
|
Bad debt expense | $ | 2.0 |
| $ | 5.2 |
Implementation of a new outage restoration program at CL&P |
| 3.7 |
|
| 3.8 |
Employee costs, including pension and benefit related costs |
| (20.2) |
|
| (30.9) |
Storm costs |
| 0.4 |
|
| (4.8) |
Other operations and maintenance |
| 7.2 |
|
| 9.1 |
Total Base Electric Distribution |
| (6.9) |
|
| (17.6) |
Total Natural Gas Distribution |
| (1.1) |
|
| 3.0 |
Total Tracked costs (Transmission and Electric Distribution) |
| 14.4 |
|
| 23.5 |
Total Distribution and Transmission |
| 6.4 |
|
| 8.9 |
Other and eliminations: |
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|
|
Integration and severance costs |
| 4.7 |
|
| 11.5 |
All other (including eliminations) |
| 4.9 |
|
| 1.2 |
Total Operations and Maintenance | $ | 16.0 |
| $ | 21.6 |
(Millions of Dollars) | Increase/(Decrease) | |
Base Electric Distribution: | ||
Resolution of basic service bad debt adder mechanism at NSTAR Electric | $ | (24.2) |
Increase in employee-related costs, including labor and benefits, as a result of the | 10.5 | |
Implementation of a new outage restoration program at CL&P | 3.9 | |
All other operations and maintenance | 2.6 | |
Total Base Electric Distribution | (7.2) | |
Total Base Natural Gas Distribution | 3.6 | |
Total Tracked costs (Transmission and Electric and Natural Gas Distribution) | (2.7) | |
Total Distribution and Transmission | (6.3) | |
Other and eliminations: | ||
Integration costs | (2.5) | |
All other (including eliminations) | (9.5) | |
Total Operations and Maintenance | $ | (18.3) |
The Operations and Maintenance expenses that are recovered through base electric distribution rates (and therefore impact earnings) decreased $6.9 million and $17.6 million, respectively, forDepreciationincreased in the three and six months ended June 30, 2014,first quarter of 2015, as compared to the same periodsperiod in 2013. The Operations and Maintenance expenses that are recovered through cost tracking mechanisms (and therefore have no earnings impact) increased $14.4 million and $23.5 million, respectively, for the three and six months ended June 30, 2014, as compared to the same periods in 2013. These increases were primarily driven by an increase in bad debt expense ($4.2 million and $8.2 million, respectively) and higher operation and maintenance costs at the PSNH generation business due to the timing of planned outages ($4.2 million and $5.1 million, respectively) for the three and six months ended June 30, 2014, as compared to the same periods in 2013.
Depreciationdecreased for the three and six months ended June 30, 2014, as compared to the same periods in 2013, due primarily to a decrease in CYAPC and YAEC decommissioning costs ($12.5 million and $25 million, respectively), partially offset by an increase related to higher utility plant balances resulting from completed construction projects placed into service ($5 million and $10.6 million, respectively).an increase in depreciation rates at CL&P as a result of the distribution rate case effective December 1, 2014.
Amortization of Regulatory Assets/(Liabilities),Assets, Net, decreased forwhich are tracked costs, include certain regulatory-approved tracking mechanisms. Fluctuations in these costs are recovered from customers in rates and have no impact on earnings. Amortization of Regulatory Assets, Net, increased in the three and six months ended June 30, 2014,first quarter of 2015, as compared to the same periodsperiod in 2013,2014, due primarily to the following:
| Three Months Ended |
| Six Months Ended | ||
(Millions of Dollars) | Increase/(Decrease) |
| Increase/(Decrease) | ||
Recovery of stranded costs at NSTAR Electric | $ | (55.1) |
| $ | (86.4) |
Increases in the SCRC, ES and other amortizations at PSNH |
| (21.5) |
|
| (5.8) |
Amortization of previously deferred congestion costs at CL&P |
| 19.1 |
|
| 38.3 |
Other |
| (0.6) |
|
| (0.3) |
| $ | (58.1) |
| $ | (54.2) |
(Millions of Dollars) | Increase/(Decrease) | |
NSTAR Electric (primarily 2014 Comprehensive Settlement Agreement and | $ | (21.3) |
CL&P (primarily storm cost recovery and energy supply and energy-related costs) | 18.4 | |
PSNH (primarily default energy service charge) | 2.5 | |
WMECO | 3.5 | |
Other | (0.4) | |
Total Amortization of Regulatory Assets, Net | $ | 2.7 |
Amortization of Rate Reduction Bonds decreased for the three and six months ended June 30, 2014, as compared to the same periods in 2013, due to the maturity in 2013 of RRBs of NSTAR Electric, PSNH, and WMECO.
4940
In connection with the 2014 Comprehensive Settlement Agreement, NSTAR Electric recognized an $11.7 million benefit in the first quarter of 2015, which was recorded as a reduction to amortization expense. The CL&P amount reflects an increase in storm cost recovery, which was approved and included in distribution rates effective December 1, 2014.
Energy Efficiency Programs, which are tracked costs, increased forin the three and six months ended June 30, 2014,first quarter of 2015, as compared to the same periodsperiod in 2013,2014, due primarily to an increase in energy efficiency costs in accordance with the three-year program guidelines established by the DPU at NSTAR Electric and WMECO and expanded energy conservation programs at CL&P in 2014, partially offset by a decrease in the amortization of previously deferred costs at NSTAR Electric. All costs are fully recovered through approved tracking mechanisms and therefore do not impact earnings.
Taxes Other Than Income Taxes increased forin the three and six months ended June 30, 2014,first quarter of 2015, as compared to the same periodsperiod in 2013,2014, due primarily to an increase in property taxes ($9.1 million and $16.6 million, respectively) as a result of both an increase in utility plant balances and property tax rates, and an increase in the Connecticut gross earnings tax ($2.2 million and $8.2 million, respectively) attributable to an increase in retail revenues.rates.
Interest Expenseincreased $5.6 million and $19.4 million for the three and six months ended June 30, 2014, as compared to the same periods in 2013, respectively, due primarily to the absence in 2014 of the favorable impact from the resolution of a Connecticut state income tax audit in the first quarter of 2013 ($8.8 million for the six months), lower interest income on deferred transition costs ($3.5 million and $8 million, respectively), and an increase in interest on long-term debt ($1.5 million and $3.6 million, respectively) as a result of new debt issuances in the second quarter and first half of 2014.
Other Income, Netdecreased $5.5 million in the first half of 2014, as compared to the first half of 2013, due primarily to lower unrealized gains on the assets supporting the deferred compensation plans ($5.3 million).
Income Tax Expense
|
| For the Three Months Ended June 30, |
|
| For the Six Months Ended June 30, |
| ||||||||||||||||||
(Millions of Dollars) | 2014 |
| 2013 |
| Decrease |
| Percent |
|
| 2014 |
| 2013 |
| Increase |
| Percent |
| |||||||
Income Tax Expense | $ | 77.8 |
| $ | 95.6 |
| $ | (17.8) |
| (18.6) | % |
| $ | 219.3 |
| $ | 216.1 |
| $ | 3.2 |
| 1.5 | % |
Income Tax Expense decreased for the three months ended June 30, 2014,2015, as compared to the same period in 2013,2014, due primarily to lower pre-tax earningshigher other interest expense ($2.54.5 million) and the tax benefit impact from the reserve recordeddue primarily to interest on regulatory deferral mechanisms.
Other Income, Netincreased in the secondfirst quarter of 2014 as a result of the FERC ROE orders issued in the FERC base ROE complaints ($22.1 million), partially offset by higher state taxes ($4.6 million) and various other tax impacts ($2.2 million).
Income Tax Expense increased for the six months ended June 30, 2014,2015, as compared to the same period in 2013,2014, due primarily to higher AFUDC related to equity funds ($1.9 million) and net gains on marketable securities ($1.6 million).
Income Tax Expense increased in the first quarter of 2015, as compared to the same period in 2014, due primarily to higher pre-tax earnings ($10.610.1 million), and higher state taxes ($8.6 million), the absence of the favorable impact from the resolution of a state income tax audit in the first quarter of 2013 ($4.8 million), and various other tax impacts ($1.3 million), partially offset by the tax benefit impact from the reserve recorded as a result of the FERC ROE orders issued in the FERC base ROE complaints ($22.11.4 million).
5041
RESULTS OF OPERATIONS – THE CONNECTICUT LIGHT AND POWER COMPANY
The following provides the amounts and variances in operating revenues and expense line items forin the condensed statements of income for CL&P for the three months ended March 31, 2015 and 2014 included in this Quarterly Report on Form 10-Q for the three and six months ended June 30, 2014 and 2013:10-Q:
|
|
| Operating Revenues and Expenses |
|
| Operating Revenues and Expenses |
| ||||||||||||||||||
|
|
| For the Three Months Ended June 30, |
|
| For the Six Months Ended June 30, |
| ||||||||||||||||||
(Millions of Dollars) | 2014 |
| 2013 |
| Increase/ |
| Percent |
|
| 2014 |
| 2013 |
| Increase/ |
| Percent |
| ||||||||
Operating Revenues | $ | 587.3 |
| $ | 569.3 |
| $ | 18.0 |
| 3.2 | % |
| $ | 1,321.9 |
| $ | 1,193.4 |
| $ | 128.5 |
| 10.8 | % | ||
Operating Expenses: |
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|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| ||
| Purchased Power and Transmission |
| 199.8 |
|
| 184.8 |
|
| 15.0 |
| 8.1 |
|
|
| 481.2 |
|
| 414.1 |
|
| 67.1 |
| 16.2 |
| |
| Operations and Maintenance |
| 131.8 |
|
| 123.8 |
|
| 8.0 |
| 6.5 |
|
|
| 241.3 |
|
| 232.6 |
|
| 8.7 |
| 3.7 |
| |
| Depreciation |
| 46.6 |
|
| 45.1 |
|
| 1.5 |
| 3.3 |
|
|
| 92.7 |
|
| 87.6 |
|
| 5.1 |
| 5.8 |
| |
| Amortization of Regulatory Assets, Net |
| 19.6 |
|
| 0.5 |
|
| 19.1 |
| (a) |
|
|
| 49.5 |
|
| 11.2 |
|
| 38.3 |
| (a) |
| |
| Energy Efficiency Programs |
| 35.3 |
|
| 20.8 |
|
| 14.5 |
| 69.7 |
|
|
| 78.0 |
|
| 43.7 |
|
| 34.3 |
| 78.5 |
| |
| Taxes Other Than Income Taxes |
| 62.1 |
|
| 57.5 |
|
| 4.6 |
| 8.0 |
|
|
| 129.1 |
|
| 117.7 |
|
| 11.4 |
| 9.7 |
| |
|
| Total Operating Expenses |
| 495.2 |
|
| 432.5 |
|
| 62.7 |
| 14.5 |
|
|
| 1,071.8 |
|
| 906.9 |
|
| 164.9 |
| 18.2 |
|
Operating Income | $ | 92.1 |
| $ | 136.8 |
| $ | (44.7) |
| (32.7) | % |
| $ | 250.1 |
| $ | 286.5 |
| $ | (36.4) |
| (12.7) | % | ||
|
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|
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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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| |
CL&P's retail sales were as follows: |
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|
| |||||||||
|
| For the Three Months Ended June 30, |
|
| For the Six Months Ended June 30, |
| ||||||||||||
|
| 2014 |
| 2013 |
| Decrease |
| Percent |
|
| 2014 |
| 2013 |
| Increase |
| Percent |
|
Retail Sales in GWh | 5,050 |
| 5,194 |
| (144) |
| (2.8) | % |
| 10,999 |
| 10,875 |
| 124 |
| 1.1 | % |
| For the Three Months Ended March 31, |
| |||||||||||
|
|
|
|
|
|
| Increase/ |
|
|
| |||
(Millions of Dollars) | 2015 |
| 2014 |
| (Decrease) |
| Percent |
| |||||
Operating Revenues | $ | 804.9 |
| $ | 734.6 |
| $ | 70.3 |
| 9.6 | % | ||
Operating Expenses: |
|
|
|
|
|
|
|
|
|
|
| ||
| Purchased Power and Transmission |
| 333.6 |
|
| 281.4 |
|
| 52.2 |
| 18.6 |
| |
| Operations and Maintenance |
| 117.4 |
|
| 109.5 |
|
| 7.9 |
| 7.2 |
| |
| Depreciation |
| 52.9 |
|
| 46.1 |
|
| 6.8 |
| 14.8 |
| |
| Amortization of Regulatory Assets, Net |
| 48.3 |
|
| 29.9 |
|
| 18.4 |
| 61.5 |
| |
| Energy Efficiency Programs |
| 42.8 |
|
| 42.7 |
|
| 0.1 |
| 0.2 |
| |
| Taxes Other Than Income Taxes |
| 68.1 |
|
| 67.0 |
|
| 1.1 |
| 1.6 |
| |
|
| Total Operating Expenses |
| 663.1 |
|
| 576.6 |
|
| 86.5 |
| 15.0 |
|
Operating Income |
| 141.8 |
|
| 158.0 |
|
| (16.2) |
| (10.3) |
| ||
Interest Expense |
| 36.6 |
|
| 34.2 |
|
| 2.4 |
| 7.0 |
| ||
Other Income, Net |
| 2.2 |
|
| 1.0 |
|
| 1.2 |
| (a) |
| ||
Income Before Income Tax Expense |
| 107.4 |
|
| 124.8 |
|
| (17.4) |
| (13.9) |
| ||
Income Tax Expense |
| 38.2 |
|
| 45.5 |
|
| (7.3) |
| (16.0) |
| ||
Net Income | $ | 69.2 |
| $ | 79.3 |
| $ | (10.1) |
| (12.7) | % | ||
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(a) Percent greater than 100 percent not shown as it is not meaningful. | |||||||||||||
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|
|
Operating Revenues |
|
|
|
|
|
|
|
|
|
|
| ||
CL&P's retail sales volumes were as follows: |
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| ||||
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| For the Three Months Ended March 31, |
| |||||||||
|
|
| 2015 |
| 2014 |
| Increase |
| Percent |
| |||
Retail Sales Volumes in GWh |
| 5,994 |
|
| 5,949 |
|
| 45 |
| 0.8 | % |
CL&P's Operating Revenues increased by $70.3 million in the secondfirst quarter of 2014,2015, as compared to the same period in 2014.
Distribution revenues increased by $78.8 million as a result of 2013.increases in energy supply costs ($101.6 million) and the impact of increased rates on base distribution revenues ($29.2 million), which was primarily attributable to the impact of CL&P's base distribution rate case effective December 1, 2014. The increase in distribution revenues was partially offset by decreased costs associated with federally mandated congestion charges ($30.3 million), and a decrease in retail transmission revenues and competitive transition assessment charges. Energy supply costs were impacted by the overall New England wholesale energy supply market in which natural gas delivery costs are adversely impacting the cost of electric energy purchased for our retail customers. Energy supply costs, federally mandated congestion charges, retail transmission revenues and competitive transition assessment charges are recovered from customers in rates through cost tracking mechanisms and therefore have no impact on earnings.
Effective December 1, 2014, CL&P’s distribution revenues were decoupled from its sales volumes and CL&P no longer recognized LBR. The revenue decoupling mechanism provides a base amount of distribution revenues ($1.041 billion on an annual basis) and effectively breaks the relationship between revenues and customer electricity usage. Revenue decoupling mechanisms ensure the recovery of our approved base distribution revenue requirements. Therefore, changes in sales volumes have no impact on the level of base distribution revenue realized. In the first quarter of 2014, which was colder than normal, CL&P’s rates were not decoupled.
Transmission revenues decreased by $8.5 million due primarily reflectsto the impact of the $12.5 million reserve related to the March 2015 FERC ROE order, partially offset by the recovery of higher revenue requirements associated with ongoing investments in our transmission infrastructure.
Purchased Power and Transmission expense includes costs associated with purchasing electricity on behalf of ourCL&P's customers. Fluctuations in theseThese energy supply costs are recovered from customers in rates and thereforePURA-approved cost tracking mechanisms, which have no impact on earnings. Partially offsetting this increase wasearnings (tracked costs). Purchased Power and Transmission increased in the impact of the reserve recorded during the secondfirst quarter of 2014 as a result of the FERC ROE orders issued in the FERC base ROE complaints. For further information, see "FERC Regulatory Issues - FERC Base ROE Complaints"in thisManagement's Discussion and Analysis. In addition, retail sales volumes decreased 2.8 percent in the second quarter of 2014,2015, as compared to the same period in 2013,2014, due primarily to the following:
(Millions of Dollars) | Increase/(Decrease) | |
Purchased Power Costs | $ | 71.3 |
Transmission Costs | (18.2) | |
Other | (0.9) | |
Total Purchased Power and Transmission | $ | 52.2 |
Included in purchased power are the costs associated with CL&P's generation services charge (GSC) and deferred energy costs. The GSC recovers energy-related costs incurred as a result of milder temperatures in late May and June of 2014.
CL&P's Operating Revenues increased in the first half of 2014, as comparedproviding electric generation service supply to the first half of 2013.all customers that have not migrated to competitive energy suppliers. The increase reflects higher retail sales volumes of 1.1 percent as a result of significantly colder weather in the first quarter of 2014, as comparedpurchased power was due primarily to the same period in 2013, and the overall impact of higher costs associated with the procurement of energy supply. The energy supply costs were impacted by higher natural gas transportation costs, which had an adverse impact on the cost of purchased electric energy for our retail customers. Fluctuations in energy supply costs are recovered from customers in rates and therefore have no impact on earnings. Partially offsetting this increase was the impact of the reserve recorded during the second quarter of 2014increased load as a result of the FERC ROE orders issued in the FERC base ROE complaints.
Purchased Power and Transmission increased for the three and six months ended June 30, 2014, as compared to the same periods in 2013, due primarily to the following:
| Three Months Ended |
| Six Months Ended | ||
(Millions of Dollars) | Increase/(Decrease) |
| Increase/(Decrease) | ||
GSC Supply Costs | $ | 3.2 |
| $ | 104.4 |
Transmission Costs |
| 5.4 |
|
| 11.8 |
Deferred Fuel Costs |
| 26.8 |
|
| (29.0) |
Purchased Power Costs |
| (15.6) |
|
| (15.2) |
Other |
| (4.8) |
|
| (4.9) |
| $ | 15.0 |
| $ | 67.1 |
The increase in GSC supply costs was due primarily to higher average supply prices and an increase in GSC loads as a result of an increase in retail sales and customers returning to standard offer from third party suppliers. On July 1, 2013, CL&P began to procure approximately 30 percent of GSC load. Costs associated with the remaining 70 percent of the GSC load are the contractual amounts CL&P must pay to various energy suppliers that have been awarded the right to supply standard service and supplier of last resort service load through a competitive solicitation process. The increasedecrease in transmission costs was the result of an increasea decrease in the retail transmission cost deferral, which reflects the actual costs of transmission service compared to estimated amounts billed amounts. The decrease in deferred fuel costs for the six months ended June 30, 2014 was due primarily to higher average electric supply prices, as compared to the prices projected when standard service rates were set. Purchased Power and Transmission costs are included in PURA-approved tracking mechanisms and do not impact earnings.customers.
Operations and Maintenanceexpense includes tracked costs that are recovered in rates through cost tracking mechanisms, which have no earnings impact (tracked costs), and costs that are recovered throughpart of base electric distribution rates (and therefore impact earnings)with changes impacting earnings (non-tracked costs). Operations and Maintenance increased in the secondfirst quarter of 2014,2015, as compared to the same period in 2013,2014, driven by a $5.2$6.7 million increase in trackednon-tracked costs, that have no earnings impact, which was primarily attributable to higher bad debt expense of $3.6 million. There was also an increase in costs that impact earnings of $2.8 million, which was primarily attributable tofor the implementation of a new outage restoration program
42
that began in the second quarter of $3.7 million,2014, higher routinestorm restoration costs and higher vegetation management costs, of $3.7 million and higher bad debt expense of $1.3 million, partially offset by lower employeeemployee-related costs, (including pension andincluding benefit related costs) of $8.4 million.costs. Additionally, there was a $1.2 million increase in tracked costs, which have no earnings impact, that was primarily attributable to increased transmission expenses.
51
Operations and MaintenanceDepreciation increased in the first halfquarter of 2014,2015, as compared to the same period in 2013, driven by a $9.6 million2014, due primarily to an increase in costsdepreciation rates as a result of the distribution rate case decision that have no earnings impact, primarily attributable to higher bad debt expense of $7.2 million. Partially offsetting this increase was a decrease in costs that impact earnings of $0.9 million, primarily attributable to lower employee costs (including pensioneffective December 1, 2014 and benefit related costs) of $13.1 million, partially offset by the implementation of a new outage restoration program of $3.8 million, higher bad debt expense of $2.9 million and higher routine vegetation management costs of $3.4 million.
Depreciation increased for the three and six months ended June 30, 2014, as compared to the same periods in 2013, due primarily to higher utility plant balances resulting from completed construction projects placed into service.
Amortization of Regulatory Assets, NetNet¸increased forin the three and six months ended June 30, 2014,first quarter of 2015, as compared to the same periodsperiod in 2013,2014, due primarily to an increase in amortization expense related to previously deferred congestion charges.
Energy Efficiency Programsincreased for the threestorm cost recovery, which was approved and six months ended June 30,included in distribution rates effective December 1, 2014, as comparedwell as energy supply and energy-related costs that can fluctuate from period to period based on the same periodstiming of costs incurred and related rate changes to recover these costs. Fluctuations in 2013, due primarily to expanded energy conservation programssupply and energy-related costs, which are the primary drivers in 2014. All costsamortization, are fully recovered through PURA-approved tracking mechanismsfrom customers in rates and therefore do nothave no impact on earnings.
Taxes Other Than Income Taxes increased forin the three and six months ended June 30, 2014,first quarter of 2015, as compared to the same periodsperiod in 2013,2014, due primarily to an increase in property taxes as a result of both an increase in utility plant balances and property tax rates ($3.9 million and $7.8 million, respectively). In addition, there was an increase in the Connecticut gross earnings tax attributable to an increase in retail revenues ($1.1 million and $4.7 million, respectively).rates.
Interest Expenseincreased $3.5 million and $8 million forin the three and six months ended June 30, 2014,first quarter of 2015, as compared to the same periodsperiod in 2013, respectively,2014, due primarily to the absence in 2014 of the favorable impact from the resolution of a state income tax audit in the first quarter of 2013 ($6 million for the six months), an increase in other interest expense due to interest on regulatory deferral mechanisms ($1 million and $2.2 million, respectively)1.8 million), and an increase in interest on long-term debt ($2 million and $2.2 million, respectively).0.6 million) as a result of a new debt issuance in April 2014.
Other Income, Netdecreased $2.9 millionincreased in the first six monthsquarter of 2014,2015, as compared to the same period in 2013,2014, due primarily to lower unrealized gains on the assets supporting the deferred compensation planshigher AFUDC related to equity funds ($1.4 million) and lower AFUDC-Equity ($1.20.8 million).
Income Tax Expense
|
| For the Three Months Ended June 30, |
|
| For the Six Months Ended June 30, |
| ||||||||||||||||||
(Millions of Dollars) | 2014 |
| 2013 |
| Decrease |
| Percent |
|
| 2014 |
| 2013 |
| Decrease |
| Percent |
| |||||||
Income Tax Expense | $ | 20.4 |
| $ | 37.8 |
| $ | (17.4) |
| (46.0) | % |
| $ | 65.9 |
| $ | 77.0 |
| $ | (11.1) |
| (14.4) | % |
Income Tax Expense decreased forin the three and six months ended June 30, 2014,first quarter of 2015, as compared to the same periodsperiod in 2013,2014, due primarily to lower pre-tax earnings ($5.8 million6.1 million) and $4.2 million, respectively) and the tax benefit impact from the FERC ROE orders issued in the second quarter of 2014lower state taxes ($12.8 million for the three and six months), partially offset by the absence in 2014 of the state audit closure benefit impact ($2.9 million for the six months) and various other tax impacts ($1.2 million and $3.0 million, respectively)1.1 million).
EARNINGS SUMMARY
|
| For the Three Months Ended June 30, |
|
| For the Six Months Ended June 30, |
| ||||||||||||||||||
(Millions of Dollars) | 2014 |
| 2013 |
| Decrease |
| Percent |
|
| 2014 |
| 2013 |
| Decrease |
| Percent |
| |||||||
Net Income | $ | 37.4 |
| $ | 67.9 |
| $ | (30.5) |
| (44.9) | % |
| $ | 116.7 |
| $ | 152.9 |
| $ | (36.2) |
| (23.7) | % |
CL&P's secondearnings decreased $10.1 million in the first quarter 2014 earnings were lower than the same period in 2013 due primarily to the establishment of an $18.5 million after-tax reserve related to the June 2014 FERC ROE orders, lower retail sales as a result of milder temperatures in late May and June of 2014,2015, as compared to the same period in 2013, higher property tax expense, increased interest expense relating2014, due primarily to a $7.9 million after-tax reserve related to the March 2015 FERC ROE order, an increase in operations and maintenance costs, which was primarily attributable to an Aprilincrease in costs for the implementation of a new outage restoration program that began in the second quarter of 2014, financing,higher storm restoration costs and higher vegetation management costs, and higher depreciation and property tax expense. Partially offsetting these unfavorable earnings impacts were increased investments in the transmission infrastructure.
For the six months ended June 30, 2014, CL&P's earnings decreased, as compared to the same period in 2013,higher distribution revenues due primarily to the establishmentimpact of the after-tax reserve related to the JuneDecember 1, 2014 FERC ROE orders, higher property tax expense and increased interest expense relating to an April 2014 financing. Partially offsetting these unfavorable earnings impacts were higher retail electric sales as a result of colder weather in the first quarter of 2014 and increased investments in the transmission infrastructure.
52base distribution rate increase.
LIQUIDITY
CL&P had cash flows provided by operating activities of $275.4$133.9 million in the first halfquarter of 2014,2015, compared with $178.2$95.5 million in the first halfquarter of 2013.2014. The improved operating cash flows were due primarily to $65.4 million in DOE Phase II Damages proceeds received on June 1, 2014 from the Yankee Companies associated with the spent nuclear fuel litigation, the absence of cash disbursements for major storm restoration costs and an increase in regulatory overrecoveries, partially offset by income tax paymentsrefunds of $3.8$122.4 million in the first halfquarter of 2014, as2015, compared towith income tax refunds of $6$11.7 million in the first halfquarter of 2013, and an unfavorable cash flow2014. Partially offsetting this favorable impact relating towas the timing of regulatory recoveries, resulting from the increase in federally mandated congestion charges, along with timing of collections and payments related to our working capital items, including accounts receivable payments madeand accounts payable. Accounts receivable increased due primarily to affiliated companiesthe basic service rate increase effective January 1, 2015 and the increase in the second quarter ofdistribution rates effective December 1, 2014.
Investments in Property, Plant and Equipment on the accompanying statements of cash flows do not include amounts incurred on capital projects but not yet paid, cost of removal, AFUDC related to equity funds, and the capitalized portions of pension expense. In the first halfquarter of 2014,2015, investments for CL&P were $221.4$127.6 million.
On April 24, 2014,1, 2015, CL&P issued $250repaid at maturity the $100 million of 4.305.00 percent 2014 Series A First and Refunding Mortgage Bonds dueusing short-term borrowings. On April 1, 2015, CL&P also redeemed the $62 million 1996A Series 1.55 percent PCRBs that were subject to mature in April 2044. The proceeds, net of issuance costs, were used to repay short-termmandatory tender, using short term borrowings.
Effective July 23, 2014, NUES parent, and certain of its subsidiaries, including CL&P, amended their jointare parties to a five-year $1.45 billion revolving credit facility to extend the expiration date an additional year tothat expires September 6, 2019. The revolving credit facility is to be used primarily to backstop NUES parent's $1.45 billion commercial paper program. The commercial paper program allows NUES parent to issue commercial paper as a form of short-term debt with intercompany loans to itscertain subsidiaries, including CL&P. As of June 30, 2014 and DecemberMarch 31, 2013,2015, there were intercompany loans from NUES parent of $6.4$190.1 million and $287.3to CL&P. As of December 31, 2014, there were intercompany loans from ES parent of $133.4 million respectively, to CL&P.
Additional financingFinancing activities in the first halfquarter of 20142015 included $85.6$49 million in common stock dividends paid to NUES parent.
On April 7, 2014, Fitch affirmed the corporate credit rating and outlook of CL&P. On April 25, 2014, S&P affirmed the corporate credit rating and revised the outlook to positive from stable of CL&P.
5343
RESULTS OF OPERATIONS – NSTAR ELECTRIC COMPANY AND SUBSIDIARY
The following provides the amounts and variances in operating revenues and expense line items forin the condensed consolidated statements of income for NSTAR Electric for the three months ended March 31, 2015 and 2014 included in this Quarterly Report on Form 10-Q for the six months ended June 30, 2014 and 2013:10-Q:
|
|
| Operating Revenues and Expenses |
| |||||||||
| For the Six Months Ended June 30, |
| |||||||||||
(Millions of Dollars) | 2014 |
| 2013 |
| Increase/ |
| Percent |
| |||||
(Decrease) |
| ||||||||||||
Operating Revenues | $ | 1,227.7 |
| $ | 1,162.7 |
| $ | 65.0 |
| 5.6 | % | ||
Operating Expenses: |
|
|
|
|
|
|
|
|
|
|
| ||
| Purchased Power and Transmission |
| 562.0 |
|
| 403.9 |
|
| 158.1 |
| 39.1 |
| |
| Operations and Maintenance |
| 164.9 |
|
| 180.2 |
|
| (15.3) |
| (8.5) |
| |
| Depreciation |
| 93.6 |
|
| 90.9 |
|
| 2.7 |
| 3.0 |
| |
| Amortization of Regulatory Assets, Net |
| 14.1 |
|
| 100.5 |
|
| (86.4) |
| (86.0) |
| |
| Amortization of Rate Reduction Bonds |
| - |
|
| 15.0 |
|
| (15.0) |
| (100.0) |
| |
| Energy Efficiency Programs |
| 88.6 |
|
| 102.4 |
|
| (13.8) |
| (13.5) |
| |
| Taxes Other Than Income Taxes |
| 64.6 |
|
| 62.7 |
|
| 1.9 |
| 3.0 |
| |
|
| Total Operating Expenses |
| 987.8 |
|
| 955.6 |
|
| 32.2 |
| 3.4 |
|
Operating Income | $ | 239.9 |
| $ | 207.1 |
| $ | 32.8 |
| 15.8 | % |
Operating Revenues |
|
|
|
|
|
|
|
|
|
| |
NSTAR Electric's retail sales were as follows: |
|
|
|
| |||||||
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| For the Six Months Ended June 30, |
|
| ||||||
|
|
| 2014 |
| 2013 |
| Decrease |
| Percent |
|
|
Retail Sales in GWh |
| 10,183 |
| 10,198 |
| (15) |
| (0.1) | % |
|
| For the Three Months Ended March 31, |
| |||||||||||
|
|
|
|
| Increase/ |
|
|
| |||||
(Millions of Dollars) | 2015 |
| 2014 |
| (Decrease) |
| Percent |
| |||||
Operating Revenues | $ | 766.8 |
| $ | 666.2 |
| $ | 100.6 |
| 15.1 | % | ||
Operating Expenses: |
|
|
|
|
|
|
|
|
|
|
| ||
| Purchased Power and Transmission |
| 401.9 |
|
| 319.1 |
|
| 82.8 |
| 25.9 |
| |
| Operations and Maintenance |
| 75.8 |
|
| 85.9 |
|
| (10.1) |
| (11.8) |
| |
| Depreciation |
| 48.8 |
|
| 46.6 |
|
| 2.2 |
| 4.7 |
| |
| Amortization of Regulatory Assets/(Liabilities), Net |
| (5.6) |
|
| 15.7 |
|
| (21.3) |
| (a) |
| |
| Energy Efficiency Programs |
| 55.4 |
|
| 48.3 |
|
| 7.1 |
| 14.7 |
| |
| Taxes Other Than Income Taxes |
| 31.0 |
|
| 32.2 |
|
| (1.2) |
| (3.7) |
| |
|
| Total Operating Expenses |
| 607.3 |
|
| 547.8 |
|
| 59.5 |
| 10.9 |
|
Operating Income |
| 159.5 |
|
| 118.4 |
|
| 41.1 |
| 34.7 |
| ||
Interest Expense |
| 20.4 |
|
| 21.1 |
|
| (0.7) |
| (3.3) |
| ||
Other Income, Net |
| 0.6 |
|
| - |
|
| 0.6 |
| (a) |
| ||
Income Before Income Tax Expense |
| 139.7 |
|
| 97.3 |
|
| 42.4 |
| 43.6 |
| ||
Income Tax Expense |
| 56.1 |
|
| 39.2 |
|
| 16.9 |
| 43.1 |
| ||
Net Income | $ | 83.6 |
| $ | 58.1 |
| $ | 25.5 |
| 43.9 | % | ||
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(a) Percent greater than 100 percent not shown as it is not meaningful. |
| ||||||||||||
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating Revenues |
|
|
|
|
|
|
|
|
|
|
| ||
NSTAR Electric's retail sales volumes were as follows: |
| ||||||||||||
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| For the Three Months Ended March 31, |
| |||||||||
|
|
| 2015 |
| 2014 |
| Increase |
| Percent |
| |||
Retail Sales Volumes in GWh |
| 5,433 |
|
| 5,358 |
|
| 75 |
| 1.4 | % |
NSTAR Electric's Operating Revenues increased by $100.6 million in the first halfquarter of 2014,2015, as compared to the first halfsame period in 2014.
Distribution revenues increased due primarily to an increase in rates related to the recovery of 2013. The increase primarily reflects the overall impact of higher costs associated with the procurement of energy supply. Oursupply, which increased $110.5 million, and increased cost recovery related to our energy efficiency programs. The energy supply costs were impacted by higherthe overall wholesale electricity market in New England in which natural gas transportationdelivery costs which had an adverse impact onare adversely impacting the cost of purchased electric energy purchased for our retail customers. FluctuationsIn addition, base distribution revenues increased as a result of the impact from the recognition of LBR ($3.8 million) and the colder winter weather in 2015 ($2.6 million). These increases were partially offset by decreased retail transmission revenues and transition cost recovery revenues. Energy supply costs, energy efficiency program costs, retail transmission revenues and transition cost recovery revenues are recovered from customers in rates through cost tracking mechanisms and therefore have no impact on earnings.
Transmission revenues increased $7.1 million in the first quarter of 2015, as compared to the same period in 2014, due primarily to the recovery of higher revenue requirements associated with ongoing investments in our transmission infrastructure, partially offset by the impact of a $2.4 million reserve related to the March 2015 FERC ROE order. For further information on the March 2015 FERC ROE order, see "FERC Regulatory Issues – FERC ROE Complaints" in thisManagement's Discussion and Analysis of Financial Conditions and Results of Operations.
Additionally, in connection with the 2014 Comprehensive Settlement Agreement, NSTAR Electric recognized an $11 million benefit in the first quarter of 2015, which was recorded as an increase to operating revenues. For further information, see "Regulatory Developments and Rate Matters – Massachusetts – 2014 Comprehensive Settlement Agreement" in thisManagement's Discussion and Analysis of Financial Conditions and Results of Operations.
Purchased Power and Transmissionexpense includes costs associated with purchasing electricity on behalf of NSTAR Electric's customers. These energy supply costs are recovered from customers in rates and thereforeDPU-approved cost tracking mechanisms which have no impact on earnings. Partially offsetting this increase was the impact of the reserve recorded during the second quarter of 2014 as a result of the FERC ROE orders issued in the FERC base ROE complaints. For further information, see "FERC Regulatory Issues - FERC Base ROE Complaints"in thisManagement's Discussionearnings (tracked costs). Purchased Power and Analysis. Additionally, stranded cost recovery revenues decreased during the period, reflecting the full collection in 2013 of previously deferred costs, as well as the full amortization of RRBs. Base distribution revenues were relatively flatTransmission increased in the first halfquarter of 2014,2015, as compared to the same period in 2013, reflecting comparable sales, which was due primarily to colder weather in the first quarter of 2014, offset by milder temperatures in late May and June of 2014 and customer savings due to the impact of its energy efficiency programs. NSTAR Electric is permitted to bill customers for lost base revenues related to reductions in sales volume as a result of their energy efficiency. In the first half of 2014, base distribution revenues increased $5.4 million, compared to the first half of 2013 (including the impact from the recognition of lost base revenues).
Purchased Power and Transmission increased in the first half of 2014, as compared to the first half of 2013, due primarily to the following:
(Millions of Dollars) |
| |
| $ |
|
Transmission Costs |
|
|
|
|
|
|
| |
Total Purchased Power and Transmission | $ |
|
The increase in Basic Service costspurchased power was due primarily related to higher average supply prices.costs associated with the procurement of energy supply. The increasedecrease in transmission costs was due primarily to higherlower RNS expense, and the increase in purchased power costs was due primarily to higher congestion charges. The decrease in deferred fuel costs was due primarily to higher average electricity supply prices, as compared to the prices projected when Basic Service rates were set. Purchased Power and Transmission costs are included in DPU-approved tracking mechanisms and do not impact earnings.service expense.
Operations and Maintenanceexpense includes tracked costs that are recovered in rates through cost tracking mechanisms, which have no earnings impact (tracked costs), and costs that are recovered throughpart of base electric distribution rates (and therefore impact earnings)with changes impacting earnings (non-tracked costs). Operations and Maintenance decreased in the first halfquarter of 2014,2015, as compared to the first half of 2013,same period in 2014, driven by a $21.5an $11.2 million reduction in non-tracked costs, that impact earnings (primarilywhich was primarily attributable to lower employee costs and benefit coststhe resolution of $15.7 million and lower storm costs of $3 million. Partially offsetting this decrease wasthe basic service bad debt adder mechanism ($24.2 million), partially offset by an increase in labor and employee benefits expense, as a result of the impact from winter weather and storms, as
44
compared to the first quarter of 2014. Tracked costs, thatwhich have no earnings impact, of $6.2increased $1.1 million, (primarilywhich was primarily attributable to higher storm costs of $3 million).increased transmission expenses.
Depreciationincreased in the first halfquarter of 2014,2015, as compared to the first half of 2013,same period in 2014, due primarily to higher utility plant balances resulting from completed construction projects placed into service.
Amortization of Regulatory Assets,Assets/(Liabilities), Net, decreased in the first half of 2014, as compared to the first half of 2013, due primarily toreflects a decrease in the recovery of previously deferred stranded costs.
Amortization of Rate Reduction Bondsdecreased intracked transition costs for the first halfquarter of 2014, as compared to the first half of 2013, due to the maturity of the RRBs in March 2013.
54
Energy Efficiency Programs decreased in the first half of 2014, as compared to the first half of 2013, due primarily to a decrease in the amortization of previously deferred costs. All costs are fully recovered through DPU-approved tracking mechanisms and therefore do not impact earnings.
Taxes Other Than Income Taxes increased in the first half of 2014, as compared to the first half of 2013, due to an increase in property taxes as a result of an increase in utility plant balances, partially offset by lower average municipal property tax rates.
Interest Expense increased $8.6 million in the first half of 2014, as compared to the first half of 2013, due primarily to lower interest income on deferred transition costs ($8 million), as well as an increase in interest on long-term debt.
Other Income/(Loss), Netdecreased $1.4 million in the first half of 2014, as compared to the first half of 2013, due primarily to lower unrealized gains on the assets supporting the deferred compensation plans.
Income Tax Expense
|
| For the Six Months Ended June 30, | |||||||||||
(Millions of Dollars) | 2014 |
| 2013 |
| Increase |
| Percent |
| |||||
Income Tax Expense | $ | 79.7 |
| $ | 68.9 |
| $ | 10.8 |
| 15.7 | % |
Income Tax Expense increased in the first half of 2014,2015, as compared to the same period in 2013,2014. Fluctuations in these costs are recovered from customers in rates and have no impact on earnings. Additionally, in connection with the 2014 Comprehensive Settlement Agreement, NSTAR Electric recognized an $11.7 million benefit in the first quarter of 2015, which was recorded as a reduction to amortization expense. For further information, see "Regulatory Developments and Rate Matters – Massachusetts – 2014 Comprehensive Settlement Agreement" in thisManagement's Discussion and Analysis of Financial Conditions and Results of Operations.
Energy Efficiency Programs, which are tracked costs, increased in the first quarter of 2015, as compared to the same period in 2014, due primarily to an increase in energy efficiency costs incurred in accordance with the three-year program guidelines established by the DPU.
Interest Expense decreased in the first quarter of 2015, as compared to the same period in 2014, due primarily to a decrease in interest on long-term debt ($2.1 million), partially offset by an increase in other interest expense in connection with the 2014 Comprehensive Settlement Agreement ($1 million).
Income Tax Expense increased in the first quarter of 2015, as compared to the same period in 2014, due primarily to higher pre-tax earnings ($11.614.8 million) and higher state taxes ($3.5 million), partially offset by the tax benefit impact from the FERC ROE orders issued in the second quarter of 2014 ($4.12.3 million).
EARNINGS SUMMARY
|
| For the Six Months Ended June 30, |
| |||||||||
(Millions of Dollars) | 2014 |
| 2013 |
| Increase |
| Percent |
| ||||
Net Income | $ | 118.2 |
| $ | 106.2 |
| $ | 12.0 |
| 11.3 | % |
In the first half of 2014, NSTAR Electric's earnings increased $25.5 million in the first quarter of 2015, as compared to the same period in 2013,2014, due primarily to lower operationsthe resolution of the basic service bad debt adder mechanism ($14.5 million), the favorable impact associated with the 2014 Comprehensive Settlement Agreement ($13 million), higher LBR and maintenance expenses attributed to lower employee costs, benefit costs and lower storm costs. Partially offsetting thesehigher retail sales volumes. These favorable earnings impacts were partially offset by an increase in operations and maintenance costs due primarily to an increase in labor and employee benefits expense as a result of the establishment ofimpact from winter weather and storms, a $6.1$1.4 million after-tax reserve related to the June 2014March 2015 FERC ROE ordersorder, and higher depreciation and property tax expenses.expense.
LIQUIDITY
NSTAR Electric had cash flows provided by operating activities of $387.7$221.3 million in the first halfquarter of 2014,2015, compared with $91.6$191.4 million in the first halfquarter of 2013.2014. The increase inimproved operating cash flows waswere due primarily to the absence of cash disbursements for major storm restoration costs associated with the February 2013 blizzard,changes in working capital items, including the timing of collections of accounts receivablesreceivable from affiliated companies, $29.1and income tax refunds of $84.6 million in DOE Phase II Damages proceeds received on June 1, 2014 from the Yankee Companies associatedfirst quarter of 2015, compared with the spent nuclear fuel litigation, a decrease in income tax payments of $17.3 million in the first halfquarter of 2014, as compared to the first half of 2013, and the absence of Pension Plan cash contributions in the first half of 2014, as compared to the first half of 2013. These2014. Partially offsetting these favorable cash flow impacts were partially offset by the absencetiming of regulatory recoveries, resulting from the increase in purchased power costs, recovered in ratesalong with the timing of collections related to the RRBs that were fully amortizedour accounts receivable. Accounts receivable increased due primarily to higher sales volumes in the first quarter of 2013.2015 as a result of colder weather and an increase in basic service rates effective January 1, 2015.
Effective July 23, 2014, NSTAR Electric amended itshas a five-year $450 million revolving credit facility to extend the expiration date an additional year tothat expires September 6, 2019. This facility serves to backstop NSTAR Electric's existing $450 million commercial paper program. As of June 30, 2014March 31, 2015 and December 31, 2013,2014, NSTAR Electric had $194.5$215.5 million and $103.5$302 million, respectively, in short-term borrowings outstanding under its commercial paper program, leaving $255.5$234.5 million and $346.5$148 million respectively, of available borrowing capacity.capacity as of March 31, 2015 and December 31, 2014, respectively. The weighted-average interest rate on these borrowings as of June 30, 2014March 31, 2015 and December 31, 20132014 was 0.160.35 percent and 0.130.27 percent, respectively, which is generally based on A2/P1 rated commercial paper.
5545
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 forin the condensed consolidated statements of income for PSNH for the three months ended March 31, 2015 and 2014 included in this Quarterly Report on Form 10-Q for the six months ended June 30, 2014 and 2013:10-Q:
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| Operating Revenues and Expenses |
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| For the Six Months Ended June 30, |
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(Millions of Dollars) | 2014 |
| 2013 |
| (Decrease) |
| Percent |
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Operating Revenues | $ | 511.5 |
| $ | 489.9 |
| $ | 21.6 |
| 4.4 | % |
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Operating Expenses: |
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| Purchased Power, Fuel and Transmission |
| 183.6 |
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| 151.1 |
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| 32.5 |
| 21.5 |
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| Operations and Maintenance |
| 132.5 |
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| 122.1 |
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| 10.4 |
| 8.5 |
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| Depreciation |
| 48.7 |
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| 45.5 |
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| 3.2 |
| 7.0 |
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| Amortization of Regulatory Assets/(Liabilities), Net |
| (7.8) |
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| (2.0) |
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| (5.8) |
| (a) |
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| Amortization of Rate Reduction Bonds |
| - |
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| 19.8 |
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| (19.8) |
| (100.0) |
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| Energy Efficiency Programs |
| 7.1 |
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| 7.1 |
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| - |
| - |
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| Taxes Other Than Income Taxes |
| 34.3 |
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| 33.9 |
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| 0.4 |
| 1.2 |
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| Total Operating Expenses |
| 398.4 |
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| 377.5 |
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| 20.9 |
| 5.5 |
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Operating Income | $ | 113.1 |
| $ | 112.4 |
| $ | 0.7 |
| 0.6 | % |
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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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PSNH's retail sales were as follows: |
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| For the Six Months Ended June 30, |
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| 2014 |
| 2013 |
| Increase |
| Percent |
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Retail Sales in GWh | 3,909 |
| 3,837 |
| 72 |
| 1.9 | % |
| For the Three Months Ended March 31, |
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| Increase/ |
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(Millions of Dollars) | 2015 |
| 2014 |
| (Decrease) |
| Percent |
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Operating Revenues | $ | 284.8 |
| $ | 299.8 |
| $ | (15.0) |
| (5.0) | % |
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Operating Expenses: |
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| Purchased Power, Fuel and Transmission |
| 99.6 |
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| 115.3 |
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| (15.7) |
| (13.6) |
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| Operations and Maintenance |
| 58.4 |
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| 62.2 |
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| (3.8) |
| (6.1) |
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| Depreciation |
| 25.6 |
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| 24.2 |
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| 1.4 |
| 5.8 |
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| Amortization of Regulatory Assets, Net |
| 15.1 |
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| 12.6 |
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| 2.5 |
| 19.8 |
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| Energy Efficiency Programs |
| 3.8 |
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| 3.8 |
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| - |
| - |
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| Taxes Other Than Income Taxes |
| 19.1 |
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| 17.7 |
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| 1.4 |
| 7.9 |
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| Total Operating Expenses |
| 221.6 |
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| 235.8 |
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| (14.2) |
| (6.0) |
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Operating Income |
| 63.2 |
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| 64.0 |
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| (0.8) |
| (1.3) |
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Interest Expense |
| 11.3 |
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| 12.0 |
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| (0.7) |
| (5.8) |
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Other Income, Net |
| 0.4 |
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| 0.3 |
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| 0.1 |
| 33.3 |
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Income Before Income Tax Expense |
| 52.3 |
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| 52.3 |
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| - |
| - |
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Income Tax Expense |
| 20.3 |
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| 19.7 |
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| 0.6 |
| 3.0 |
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Net Income | $ | 32.0 |
| $ | 32.6 |
| $ | (0.6) |
| (1.8) | % |
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Operating Revenues |
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PSNH's retail sales volumes were as follows: |
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| For the Three Months Ended March 31, |
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| 2015 |
| 2014 |
| Decrease |
| Percent |
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Retail Sales Volumes in GWh |
| 2,067 |
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| 2,076 |
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| (9) |
| (0.5) | % |
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PSNH's Operating Revenues increased in the first half of 2014, as compared to the first half of 2013, due primarily to an increase of 1.9 percent in retail sales as a result of the colder weatherdecreased $15 million in the first quarter of 2014,2015, as compared to the same period in 2013.2014. The average daily temperaturedecrease primarily relates to a $6.8 million reduction in New Hampshirewholesale generation revenues, which impact the timing of the recovery of generation and energy supply costs from customers. In addition, stranded costs revenues decreased $5 million in the first quarter of 2015, as compared to the same period in 2014 and there was over five degrees lower thanthe impact of a $1 million reserve related to the March 2015 FERC ROE order recorded in the first quarter of 2013. In addition,2015. Base distribution revenues increased due$1.1 million, as compared to the overall impactfirst quarter of higher2014, as a result of the colder winter weather in 2015 and its impacts on residential retail sales.
Purchased Power, Fuel and Transmissionexpense includes costs associated with the procurementPSNH's generation of energy supply. The energy supply costs were impacted by higher natural gas transportation costs, which had an adverse impactelectricity as well as purchasing electricity on the costbehalf of purchased electric energy for our retailits customers. Fluctuations inThese generation and energy supply costs are recovered from customers in rates and thereforeNHPUC-approved cost tracking mechanisms, which have no impact on earnings. Also reflected in the revenue increase were increases of $6.4 million related to NHPUC-approved distribution rate increases effective July 1, 2013 and increases in transmission revenues as a result of the recovery of higher transmission expenses including ongoing investments in our transmission infrastructure, partially offset by the impact of the reserve recorded during the second quarter of 2014 as a result of the FERC ROE orders issued in the FERC base ROE complaints. For further information, see "FERC Regulatory Issues - FERC Base ROE Complaints"in thisManagement's Discussion and Analysis.
earnings (tracked costs). Purchased Power, Fuel and Transmission increased decreased in the first halfquarter of 2014,2015, as compared to the first half of 2013,same period in 2014, due primarily to the following:
(Millions of Dollars) | Increase/(Decrease) | |
Generation Fuel Costs | $ | |
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Purchased Power Costs |
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Other |
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Total Purchased Power, Fuel and Transmission | $ | |
PSNH procures power through its own generation, long-term power supply contracts and short-term purchases and spot purchases in the competitive New England wholesale power market. The increasedecrease in generation fuel costs was due primarily to an increasea decrease in the amount of electricity generated by PSNH facilities. The increasefacilities and a decrease in renewable energy costs was a result of lower regional greenhouse gas initiative auction proceeds, partially offset by lower renewable energy requirements set by the NHPUC. The increase in transmission costs was as a result of an increasefuel prices in the retail transmission cost deferral, which reflects the actual costsfirst quarter of transmission service2015, as compared to estimated amounts billed to customers. the same period in 2014. The decrease in purchased power costs was a resultdue to lower power prices of additional customer migrationshort-term and spot purchases made in the wholesale power market in the first quarter of 2015, as compared to third party suppliers. Purchased Power, Fuel and Transmission costs are includedthe same period in NHPUC-approved tracking mechanisms and do not impact earnings.2014.
Operations and Maintenanceexpense includes tracked costs and costs that are recoveredpart of base distribution rates with changes impacting earnings (non-tracked costs). Operations and Maintenance decreased in rates through cost tracking mechanisms,the first quarter of 2015, as compared to the same period in 2014, driven by a $2.1 million reduction in tracked costs, which have no earnings impact, (tracked costs), and a $1.7 million reduction in non-tracked costs, that are recovered through base electric distribution rates (and therefore impact earnings). Operations and Maintenance increased in the first halfboth of 2014, as compared to the first half of 2013, driven by an $8 million increase in costs that have no earnings impact (primarilywhich were primarily attributable to higher operations and maintenance costs at the generation business of $5.1 million due to the timing of planned outages and higher bad debt expense of $1 million, partially offset by lower employeeemployee-related costs, including pension and benefit related costs, of $2.4 million). Additionally, there was an increase in costs that impact earnings of $2.4 million.costs.
Depreciationincreased in the first halfquarter of 2014,2015, as compared to the first half of 2013,same period in 2014, due primarily to higher utility plant balances resulting from completed construction projects placed into service.
Amortization of Regulatory Assets/(Liabilities),Assets, Net, reflects an increase in the recovery of the default energy service charge and other amortizations for the first quarter of 2015, as compared to the same period in 2014. Fluctuations in these costs are recovered from customers in rates and have no impact on earnings.
Taxes Other Than Income Taxesincreased in the first halfquarter of 2014,2015, as compared to the first half of 2013,same period in 2014, due primarily to increasesan increase in the stranded cost recovery charge, default energy service, and other amortizationsproperty taxes as a result of $1.7 million, $0.2 million, and $3.9 million, respectively. an increase in utility plant balances.
5646
Amortization of Rate Reduction BondsIncome Tax Expense decreasedincreased in the first halfquarter of 2014,2015, as compared to the first half of 2013, due to the maturity of the RRBssame period in May 2013.
Income Tax Expense
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| For the Six Months Ended June 30, | |||||||||||
(Millions of Dollars) | 2014 |
| 2013 |
| Change |
| Percent |
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Income Tax Expense | $ | 34.6 |
| $ | 34.6 |
| $ | - |
| - | % |
Income Tax Expense was relatively flat in the first half of 2014, as compared to the first half of 2013, due primarily to higher pre-tax earningslower permanent tax impacts ($1.5 million), offset by the tax benefit impact from the FERC ROE orders issued in the second quarter of 2014 ($1.50.6 million).
EARNINGS SUMMARY
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| For the Six Months Ended June 30, |
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(Millions of Dollars) | 2014 |
| 2013 |
| Increase |
| Percent |
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Net Income | $ | 56.7 |
| $ | 56.2 |
| $ | 0.5 |
| 0.1 | % |
InPSNH's earnings decreased $0.6 million in the first halfquarter of 2014, PSNH's earnings increased,2015, as compared to the same period in 2013,2014, due primarily to higher distribution retail revenues, which were favorably impacted by the PSNH annualized distribution rate increases effective July 1, 2013, and higher retail electric sales. Partially offsetting these favorable earnings impacts were the establishment of a $2$0.6 million after-tax reserve related to the June 2014March 2015 FERC ROE orders,order, higher depreciation expense and higher depreciationproperty tax expense. Partially offsetting these unfavorable earnings impacts were lower operations and maintenance costs primarily attributable to lower employee-related costs.
LIQUIDITY
PSNH had cash flows provided by operating activities of $142.4$113.9 million in the first halfquarter of 2014,2015, compared with $138.7$129.3 million in the first halfquarter of 2013.2014. The improveddecrease in operating cash flows werewas due primarily to $13.1 million in DOE Phase II Damages proceeds received on June 1, 2014 from the Yankee Companies associated with the spent nuclear fuel litigation, the absencetiming of approximately $45 million in NUSCO Pension Plan cash contributions in the first half of 2014,collections and payments related to our working capital items, including accounts receivable, and the favorable impacttiming of the 2010 rate case settlement related to the additional increase to annualized rates that was effective July 1, 2013. These favorableour regulatory recoveries, which were in a net underrecovery position. Partially offsetting these unfavorable cash flow impacts were partially offset byincome tax refunds of $1.8 million in the first quarter of 2015, compared with income tax payments of $28.8$16.1 million in the first half of 2014, compared with income tax refunds of $12.1 million in the first half of 2013, and the absence of costs recovered in rates related to the RRBs that were fully amortized in the second quarter of 2013.2014.
5747
RESULTS OF OPERATIONS – WESTERN MASSACHUSETTS ELECTRIC COMPANY
The following provides the amounts and variances in operating revenues and expense line items forin the condensed statements of income for WMECO for the three months ended March 31, 2015 and 2014 included in this Quarterly Report on Form 10-Q for the six months ended June 30, 2014 and 2013:10-Q:
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| Operating Revenues and Expenses |
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| For the Six Months Ended June 30, | ||||||||||||
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(Millions of Dollars) | 2014 |
| 2013 |
| (Decrease) |
| Percent |
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Operating Revenues | $ | 245.7 |
| $ | 240.0 |
| $ | 5.7 |
| 2.4 | % | ||
Operating Expenses: |
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| Purchased Power and Transmission |
| 87.1 |
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| 72.3 |
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| 14.8 |
| 20.5 |
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| Operations and Maintenance |
| 46.3 |
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| 44.1 |
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| 2.2 |
| 5.0 |
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| Depreciation |
| 20.6 |
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| 18.3 |
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| 2.3 |
| 12.6 |
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| Amortization of Regulatory Assets, Net |
| 0.7 |
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| 0.8 |
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| (0.1) |
| (12.5) |
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| Amortization of Rate Reduction Bonds |
| - |
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| 7.8 |
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| (7.8) |
| (100.0) |
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| Energy Efficiency Programs |
| 22.1 |
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| 16.2 |
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| 5.9 |
| 36.4 |
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| Taxes Other Than Income Taxes |
| 16.5 |
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| 12.5 |
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| 4.0 |
| 32.0 |
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| Total Operating Expenses |
| 193.3 |
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| 172.0 |
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| 21.3 |
| 12.4 |
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Operating Income | $ | 52.4 |
| $ | 68.0 |
| $ | (15.6) |
| (22.9) | % |
Operating Revenues |
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WMECO's retail sales were as follows: |
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| For the Six Months Ended June 30, |
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| 2014 |
| 2013 |
| Decrease |
| Percent |
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Retail Sales in GWh |
| 1,793 |
| 1,798 |
| (5) |
| (0.2) | % |
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| For the Three Months Ended March 31, |
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(Millions of Dollars) | 2015 |
| 2014 |
| (Decrease) |
| Percent |
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Operating Revenues | $ | 152.9 |
| $ | 137.4 |
| $ | 15.5 |
| 11.3 | % | ||
Operating Expenses: |
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| Purchased Power and Transmission |
| 69.7 |
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| 49.4 |
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| 20.3 |
| 41.1 |
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| Operations and Maintenance |
| 19.8 |
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| 22.6 |
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| (2.8) |
| (12.4) |
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| Depreciation |
| 10.4 |
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| 10.3 |
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| 0.1 |
| 1.0 |
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| Amortization of Regulatory Assets, Net |
| 3.9 |
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| 0.4 |
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| 3.5 |
| (a) |
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| Energy Efficiency Programs |
| 11.1 |
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| 11.9 |
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| (0.8) |
| (6.7) |
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| Taxes Other Than Income Taxes |
| 9.4 |
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| 8.1 |
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| 1.3 |
| 16.0 |
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| Total Operating Expenses |
| 124.3 |
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| 102.7 |
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| 21.6 |
| 21.0 |
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Operating Income |
| 28.6 |
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| 34.7 |
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| (6.1) |
| (17.6) |
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Interest Expense |
| 6.8 |
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| 5.6 |
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| 1.2 |
| 21.4 |
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Other Income, Net |
| 0.5 |
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| 0.6 |
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| (0.1) |
| (16.7) |
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Income Before Income Tax Expense |
| 22.3 |
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| 29.7 |
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| (7.4) |
| (24.9) |
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Income Tax Expense |
| 9.1 |
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| 11.6 |
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| (2.5) |
| (21.6) |
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Net Income | $ | 13.2 |
| $ | 18.1 |
| $ | (4.9) |
| (27.1) | % | ||
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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 volumes were as follows: |
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| For the Three Months Ended March 31, |
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| 2015 |
| 2014 |
| Decrease |
| Percent |
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Retail Sales Volumes in GWh |
| 955 |
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| 965 |
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| (10) |
| (1.1) | % |
WMECO's Operating Revenues increased in the first half of 2014, as compared to the first half of 2013, due primarily to a $3.9 million increase in revenues that impacts earnings due to the reversal of a previously established wholesale billing adjustment. The remaining increase primarily reflects a higher level of recovery related to WMECO's energy supply and energy efficiency programs. These revenues are fully reconciled to the related costs. Therefore this increase in revenues had no material impact on earnings. Partially offsetting this increase was the impact of the reserve recorded during the second quarter of 2014 as a result of the FERC ROE orders issued in the FERC base ROE complaints. For further information, see "FERC Regulatory Issues - FERC Base ROE Complaints"in thisManagement's Discussion and Analysis. Base distribution revenues were relatively flat in the first half of 2014, as compared to the same period in 2013. Fluctuations in WMECO's kWh sales volumes have no impact on total operating revenues or earnings, as itsWMECO’s revenues are decoupled from sales volumes and changesvolumes. Fluctuations in the overall level of operating revenues are primarily related to changes in its cost tracking mechanisms.mechanisms, which primarily include the costs associated with the procurement of energy supply, transmission related costs, energy efficiency programs, and restructuring and stranded costs as a result of deregulation.
WMECO's Operating Revenues increased $15.5 million in the first quarter of 2015, as compared to the same period in 2014. The increase primarily reflects an increase in rates related to the recovery of costs associated with the procurement of energy supply, which increased $24.2 million. The energy supply costs were impacted by the overall wholesale electricity market in New England in which natural gas delivery costs are adversely impacting the cost of electric energy purchased for our retail customers. Energy supply costs are recovered from customers in rates through cost tracking mechanisms and therefore have no impact on earnings. Partially offsetting the increase was the impact of the $4.1 million reserve related to the March 2015 FERC ROE order, and a $3.9 million decrease in revenues that impacts earnings due to the absence of a 2014 wholesale billing adjustment.
For further information on the March 2015 FERC ROE order, see "FERC Regulatory Issues – FERC ROE Complaints" in thisManagement's Discussion and Analysis of Financial Conditions and Results of Operations.
Purchased Power and Transmissionincreasedexpense includes costs associated with the procurement of energy supply on behalf of WMECO's customers. These energy supply costs are recovered from customers in DPU-approved cost tracking mechanisms, which have no impact on earnings (tracked costs). Purchased Power and Transmissionincreased in the first halfquarter of 2014,2015, as compared to the first half of 2013,same period in 2014, due primarily to anthe following:
(Millions of Dollars) | Increase/(Decrease) | |
Purchased Power Costs | $ | 23.2 |
Transmission Costs | (2.9) | |
Total Purchased Power and Transmission | $ | 20.3 |
Included in purchased power are the costs associated with WMECO's basic service charge and deferred energy supply costs. The basic service charge recovers energy-related costs incurred as a result of providing electric generation service supply to all customers that have not migrated to third party suppliers. The increase in supplier contract pricespurchased power was due primarily to higher costs associated with the procurement of energy supply and an increase inincreased load as a result of customers returning to defaultbasic service from third party suppliers ($13.9 million)and an increasesuppliers. The decrease in transmission costs ($5.7 million)was as a result of an increasea decrease in the retail transmission cost deferral, which reflects the actual costs of transmission service compared to estimated amounts billed to customers. Partially offsetting this increase was the impact of the change in deferred fuel costs ($2.4 million) due primarily to higher average electric supply prices, as compared to the prices projected when basic service rates were set. Purchased Power and Transmission costs are included in DPU-approved tracking mechanisms and do not impact earnings.
Operations and Maintenanceexpense includes tracked costs and costs that are recoveredpart of base distribution rates with changes impacting earnings (non-tracked costs). Operations and Maintenance decreased in rates through cost tracking mechanisms,the first quarter of 2015, as compared to the same period in 2014, driven by a $1.7 million reduction in tracked costs, which have no earnings impact, (tracked costs), and costs that are recovered through base electric distribution rates (and therefore impact earnings). Operations and Maintenance increased in the first half of 2014, as compared to the first half of 2013, driven by a $2.5 million increase in costs that impact earnings (primarilywas primarily attributable to an increaselower employee-related costs, including benefit costs, and a $1.1 million reduction in workers' compensation claims of $1.9 millionnon-tracked costs, which was primarily attributable to lower uncollectible expense and higher bad debt expense of $0.8 million). Partially offsetting this increase was a decrease in costs that have no earnings impact of $0.3 million.lower vegetation management costs.
Depreciation increased in the first half of 2014, as compared to the first half of 2013, due primarily to higher utility plant balances resulting from completed construction projects placed into service.
48
Amortization of Rate Reduction BondsRegulatory Assets, Netdecreased in,reflects the first halfabsence of the refund of the Phase I DOE proceeds to customers in 2014 as comparedwell as other energy and energy related costs and amortizations that can fluctuate period to the first halfperiod based on timing of 2013, duecosts incurred and related rate changes to the maturity of the RRBs in June 2013.
Energy Efficiency Programsincreased in the first half of 2014, as compared to the first half of 2013, due primarily to an increaserecover these costs. Fluctuations in energy efficiency costs in accordance with the three-year program guidelines established by the DPU. Alland energy related costs are fully recovered through DPU-approved tracking mechanismsfrom customers in rates and therefore do nothave no impact on earnings.
Taxes Other Than Income Taxes increased in the first halfquarter of 2014,2015, as compared to the first half of 2013,same period in 2014, due primarily to an increase in property taxes as a result of both an increase in utility plant balances and property tax rates.balances.
Income TaxInterest Expense
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| For the Six Months Ended June 30, | |||||||||||
(Millions of Dollars) | 2014 |
| 2013 |
| Decrease |
| Percent |
| |||||
Income Tax Expense | $ | 16.1 |
| $ | 21.8 |
| $ | (5.7) |
| (26.1) | % |
Income Tax Expense decreasedincreased in the first half of 2014, as compared to the first half of 2013, due primarily to the tax benefit impact from the FERC ROE orders issued in the second quarter of 2014 ($3.6 million) and lower pre-tax earnings ($2.3 million).
58
EARNINGS SUMMARY
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| For the Six Months Ended June 30, | |||||||||||
(Millions of Dollars) | 2014 |
| 2013 |
| Decrease |
| Percent |
| |||||
Net Income | $ | 25.1 |
| $ | 35.0 |
| $ | (9.9) |
| (28.3) | % |
In the first half of 2014, WMECO's earnings decreased,2015, as compared to the same period in 2013,2014, due primarily to the establishmentabsence of a $5.52014 wholesale billing adjustment.
Income Tax Expense decreased in the first quarter of 2015, as compared to the same period in 2014, due primarily to lower pre-tax earnings ($2.6 million).
EARNINGS SUMMARY
WMECO's earnings decreased $4.9 million in the first quarter of 2015, as compared to the same period in 2014, due primarily to the $2.5 million after-tax reserve related to the June 2014March 2015 FERC ROE orders, anorder and a decrease in revenues and increase in workers' compensation claims, and higher depreciation and property tax expense.interest expense resulting from the absence of a 2014 wholesale billing adjustment. Partially offsetting these unfavorable earnings impacts were an increase in generation earnings andwas a decrease in other interest expense.operations and maintenance expenses primarily attributable to lower uncollectible expense and lower vegetation management costs.
LIQUIDITY
WMECO had cash flows used in operating activities of $1.4 million in the first quarter of 2015, compared with cash flows provided by operating activities of $96.6$46.3 million in the first halfquarter of 2014, compared with $119.3 million in the first half of 2013.2014. The decrease in operating cash flows was due primarily to the timing of collections and payments related to our working capital items, including accounts receivable. Accounts receivable increased due primarily to an increase in basic service rates effective January 1, 2015. In addition, the operating cash flows decrease was due to the timing of regulatory recoveries, resulting from the increase in purchased power costs. Partially offsetting these unfavorable cash flow impacts were income tax refunds of $3.7 million in the first quarter of 2015, compared with income tax payments of $16.9$14.1 million in the first half of 2014, compared with income tax refunds of $32.4 million in the first half of 2013 and the absence of costs recovered in rates related to the RRBs that were fully amortized in the second quarter of 2013, partially offset by the receipt of $18.1 million in DOE Phase II Damages proceeds received on June 1, 2014 from the Yankee Companies associated with the spent nuclear fuel litigation and an increase in regulatory overrecoveries.
2014.
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ITEM 3.
QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
Market Risk Information
Commodity Price Risk Management: Our Regulated companies enter into energy contracts to serve our customers and the economic impacts of those contracts are passed on to our customers. Accordingly, the Regulated companies have no exposure to loss of future earnings or fair values due to these market risk-sensitive instruments. NU'sEversource's Energy Supply Risk Committee, comprised of senior officers, reviews and approves all large scale energy related transactions entered into by its Regulated companies.
Other Risk Management Activities
Interest Rate Risk Management: We manage our interest rate risk exposure in accordance with our written policies and procedures by maintaining a mix of fixed and variable rate long-term debt.
Credit Risk Management: Credit risk relates to the risk of loss that we would incur as a result of non-performance by counterparties pursuant to the terms of our contractual obligations. We serve a wide variety of customers and transact with suppliers that include IPPs, industrial companies, natural 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.
IfOur Regulated companies are subject to credit risk from certain long-term or high-volume supply contracts with energy marketing companies. Our Regulated companies manage the respective unsecured debt ratingscredit risk with these counterparties in accordance with established credit risk practices and monitor contracting risks, including credit risk. As of NU or its subsidiaries were reducedMarch 31, 2015, our Regulated companies held collateral (cash and letters of credit) from counterparties related to below investment grade by either Moody's or S&P, certainour standard service contracts of NU's contracts would require additional collateral in the formapproximately $9 million. As of March 31, 2015, Eversource had cash posted of approximately $11 million with ISO-NE related to be provided to counterparties and independent system operators. NU would have been and remains able to provide that collateral.
For further information on cash collateral deposited and posted with counterparties as well as any cash collateral netted against the fair value of the related derivative contracts, see Note 4, "Derivative Instruments," to the financial statements. energy purchase transactions.
We have provided additional disclosures regarding interest rate risk management and credit risk management in Part II, Item 7A, "Quantitative and Qualitative Disclosures about Market Risk," in NU's 2013Eversource's 2014 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 2013Eversource 2014 Form 10-K.
ITEM 4.
CONTROLS AND PROCEDURES
Management, on behalf of NU,Eversource, CL&P, NSTAR Electric, PSNH and WMECO, evaluated the design and operation of the disclosure controls and procedures as of June 30, 2014March 31, 2015 to determine whether they are effective in ensuring that the disclosure of required information is made timely and in accordance with the Securities Exchange Act of 1934 and the rules and regulations of the SEC. This evaluation was made under management's supervision and with management's participation, including the principal executive officersofficer 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 officersofficer and principal financial officer have concluded, based on their review, that the disclosure controls and procedures of NU,Eversource, 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 officersofficer 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,Eversource, CL&P, NSTAR Electric, PSNH and WMECO during the quarter ended June 30, 2014March 31, 2015 that have materially affected, or are reasonably likely to materially affect, internal controls over financial reporting.
6050
PART II. OTHER INFORMATION
ITEM 1.
LEGAL PROCEEDINGS
We are parties to various legal proceedings. We have identified these legal proceedings in Part I, Item 3, "Legal Proceedings," and elsewhere in our 20132014 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 20132014 Form 10-K.
ITEM 1A.
RISK FACTORS
We are subject to a variety of significant risks in addition to the matters set forth under "Forward-Looking Statements," in Item 2, "Management's Discussion and Analysis of Financial Condition and Results of Operations," of this Quarterly Report on Form 10-Q. We have identified a number of these risk factors in Part I, Item 1A, "Risk Factors," in our 20132014 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 20132014 Form 10-K.
ITEM 2.
UNREGISTERED SALES OF EQUITY SECURITIES AND USE OF PROCEEDS
The following table discloses purchases of our common shares made by us or on our behalf for the periods shown below. The common shares purchased consist of open market purchases made by the Company or an independent agent. These share transactions related to the Company's Long-Term Incentive Plans.
| Period |
| Total Number |
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| Average | Total Number of | Approximate Dollar |
| April 1 – April 30, 2014 |
| - |
| $ | - | - | - |
| May 1 – May 31, 2014 |
| - |
|
| - | - | - |
| June 1 – June 30, 2014 |
| 208,608 |
|
| 46.93 | - | - |
| Total |
| 208,608 |
| $ | 46.93 | - | - |
Period |
| Total Number |
|
| Average | Total Number of | Approximate Dollar |
January 1 – January 31, 2015 |
| - |
| $ | - | - | - |
February 1 – February 28, 2015 |
| 51,915 |
|
| 56.45 | - | - |
March 1 – March 31, 2015 |
| - |
|
| - | - | - |
Total |
| 51,915 |
| $ | 56.45 | - | - |
6151
ITEM 6.
EXHIBITS
Each document described below is filed herewith, unless designated with an asterisk (*), which exhibits are incorporated by reference by the registrant under whose name the exhibit appears.
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Exhibit No.
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Listing of Exhibits (NU,(Eversource)
3.1
Declaration of Trust of Eversource Energy, as amended through April 29, 2015
* 4
Sixth Supplemental Indenture between Northeast Utilities, now known as Eversource Energy, and The Bank of New York Trust Company N.A., as Trustee, dated as of January 1, 2015, relating to $150 million of Senior Notes, Series G, due 2018 and $300 million of Senior Notes, Series H, due 2025 (Exhibit 4.1, NU Current Report on Form 8-K filed January 21, 2015, File No. 001-05324)
12
Ratio of Earnings to Fixed Charges
31
Certification of Thomas J. May, Chairman, President and Chief Executive Officer of Eversource Energy, 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 6, 2015
31.1
Certification of James J. Judge, Executive Vice President and Chief Financial Officer of Eversource Energy, 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 6, 2015
32
Certification of Thomas J. May, Chairman, President and Chief Executive Officer of Eversource Energy, and James J. Judge, Executive Vice President and Chief Financial Officer of Eversource Energy, pursuant to 18 U.S.C. Section 1350 as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, dated May 6, 2015
Listing of Exhibits (CL&P)
12
Ratio of Earnings to Fixed Charges
31
Certification of Thomas J. May, Chairman 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 May 6, 2015
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 May 6, 2015
32
Certification of Thomas J. May, Chairman 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 May 6, 2015
Listing of Exhibits (NSTAR Electric Company)
12
Ratio of Earnings to Fixed Charges
31
Certification of Thomas J. May, Chairman 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 May 6, 2015
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 May 6, 2015
32
Certification of Thomas J. May, Chairman 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 May 6, 2015
52
Listing of Exhibits (PSNH)
12
Ratio of Earnings to Fixed Charges
31
Certification of Thomas J. May, Chairman 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 May 6, 2015
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 May 6, 2015
32
Certification of Thomas J. May, Chairman 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 May 6, 2015
Listing of Exhibits (WMECO)
12
Ratio of Earnings to Fixed Charges
31
Certification of Thomas J. May, Chairman 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 May 6, 2015
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 May 6, 2015
32
Certification of Thomas J. May, Chairman 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 May 6, 2015
Listing of Exhibits (Eversource, CL&P, NSTAR Electric, PSNH, WMECO)
101.INS XBRL Instance Document 101.SCH XBRL Taxonomy Extension Schema 101.CAL XBRL Taxonomy Extension Calculation 101.DEF XBRL Taxonomy Extension Definition 101.LAB XBRL Taxonomy Extension Labels |
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101.PRE | XBRL Taxonomy Extension Presentation |
6353
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.
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| By: | /s/ Jay S. Buth |
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| Jay S. Buth |
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| Vice President, Controller and Chief Accounting Officer |
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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.
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| THE CONNECTICUT LIGHT AND POWER COMPANY | |
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| By: | /s/ Jay S. Buth |
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| Jay S. Buth |
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| Vice President, Controller and Chief Accounting Officer |
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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.
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| NSTAR ELECTRIC COMPANY | |
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| By: | /s/ Jay S. Buth |
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| Jay S. Buth |
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| Vice President, Controller and Chief Accounting Officer |
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6454
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.
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| PUBLIC SERVICE COMPANY OF NEW HAMPSHIRE | |
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| By: | /s/ Jay S. Buth |
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| Jay S. Buth |
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| Vice President, Controller and Chief Accounting Officer |
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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.
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| WESTERN MASSACHUSETTS ELECTRIC COMPANY | |
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| By: | /s/ Jay S. Buth |
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| Jay S. Buth |
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| Vice President, Controller and Chief Accounting Officer |
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6555