Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations

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Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations

Management's Discussion and Analysis of Financial Condition and Results of Operations

EVERSOURCE ENERGY AND SUBSIDIARIES

The following discussion and analysis should be read in conjunction with our consolidated financial statements and related combined notes included in this combined Annual Report on Form 10-K. References in this Annual Report on Form 10-K to "Eversource," the "Company," "we," "us," and "our" refer to Eversource Energy and its consolidated subsidiaries. All per share amounts are reported on a diluted basis. The consolidated financial statements of Eversource, NSTAR Electric and PSNH and the financial statements of CL&P and WMECO are herein collectively referred to as the "financial statements."

On April 30, 2015, the Company's legal name was changed from Northeast Utilities to Eversource Energy. CL&P, NSTAR Electric, PSNH and WMECO are each doing business as Eversource Energy.

Refer to the Glossary of Terms included in this combined Annual Report on Form 10-K for abbreviations and acronyms used throughout this Management's Discussion and Analysis of Financial Condition and Results of Operations.

The only common equity securities that are publicly traded are common shares of Eversource. The earnings and EPS of each business discussed below do not represent a direct legal interest in the assets and liabilities of 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 Common Shareholders of each business by the weighted average diluted Eversource common shares outstanding for the period. The discussion below also includes non-GAAP financial measures referencing our 2015, 2014 and 2013 earnings and EPS excluding certain integration costs incurred by Eversource parent and our Regulated companies. 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 2015, 2014 and 2013 results without including the impact of these items. Due to the nature and significance of these items on Net Income Attributable to Common Shareholders, 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 Common Shareholders 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 Common Shareholders are included under "Financial Condition and Business Analysis – Overview – Consolidated" and "Financial Condition and Business Analysis – Overview – Regulated Companies" in Management's Discussion and Analysis of Financial Condition and Results of Operations, herein.

Financial Condition and Business Analysis

Executive Summary

Results:

We earned $878.5 million, or $2.76 per share, in 2015, compared with $819.5 million, or $2.58 per share, in 2014. Excluding integration costs, we earned $894.3 million, or $2.81 per share, in 2015 and $841.6 million, or $2.65 per share, in 2014.

Our electric distribution segment, which includes generation, earned $507.9 million, or $1.59 per share, in 2015, compared with $462.4 million, or $1.45 per share, in 2014. Our electric transmission segment earned $304.5 million, or $0.96 per share, in 2015, compared with $295.4 million, or $0.93 per share, in 2014. Our natural gas distribution segment earned $72.4 million, or $0.23 per share, in 2015, compared with $72.3 million, or $0.23 per share, in 2014. The 2015 electric and natural gas distribution results exclude $0.8 million of after-tax integration costs.

Eversource parent and other companies earned $9.5 million, or $0.03 per share, in 2015, compared with $11.5 million, or $0.04 per share, in 2014. The 2015 and 2014 results exclude $15 million, or $0.05 per share, and $22.1 million, or $0.07 per share, respectively, of after-tax integration costs.

Liquidity:

Cash flows provided by operating activities totaled $1.4 billion in 2015, compared with $1.6 billion in 2014. Investments in property, plant and equipment totaled $1.7 billion in 2015 and $1.6 billion in 2014. Cash and cash equivalents totaled $23.9 million as of December 31, 2015, compared with $38.7 million as of December 31, 2014.

In 2015, we issued approximately $1.23 billion of new long-term debt consisting of $450 million by Eversource parent, $350 million by CL&P, $250 million by NSTAR Electric, $100 million by NSTAR Gas, and $75 million by Yankee Gas. In 2015, we repaid $212 million of existing long-term debt consisting of $162 million by CL&P and $50 million by WMECO.

In 2015, we paid cash dividends on common shares of $529.8 million, compared with $475.2 million in 2014. On February 3, 2016, our Board of Trustees approved a common share dividend payment of $0.445 per share, payable on March 31, 2016 to shareholders of record as of March 2, 2016. The 2016 dividend represented an increase of 6.6 percent over the dividend paid in December 2015, and is the equivalent to dividends on common shares of approximately $565 million on an annual basis.

We project to make capital expenditures of approximately $9.2 billion from 2016 through 2019. Of the $9.2 billion, we expect to invest approximately $4.9 billion in our electric and natural gas distribution segments and $3.9 billion in our electric transmission segment. In addition, we project to invest approximately $0.4 billion in information technology and facilities upgrades and enhancements. These projections do not include capital investments related to Access Northeast or Clean Energy Connect.

Strategic, Legislative, Regulatory, Policy and Other Items:

On December 18, 2015, the New Hampshire Site Evaluation Committee (NH SEC) accepted NPT’s application as complete allowing the formal siting process to move forward. The project is expected to be operational in the first half of 2019. On January 28, 2016, NPT bid into the three-state Clean Energy RFP process.

The Clean Energy Connect Project is a planned transmission, wind and hydro generation project that we plan to co-develop with experienced renewable generation companies. On January 28, 2016, the Clean Energy Connect project was bid into the three-state Clean Energy RFP process. Our investment, should the Clean Energy Connect Project be selected in the RFP process, is currently estimated to be at least $400 million and will consist of the Massachusetts portion of a new 25-mile, 345 kV transmission line with a 600 MW capacity.

On January 28, 2016, the DPU approved NSTAR Electric’s, WMECO’s, and NSTAR Gas’ three-year electric and natural gas energy efficiency plan, which was jointly developed with other Massachusetts electric distribution companies (EDCs) and natural gas distribution companies. On December 31, 2015, DEEP approved CL&P’s and Yankee Gas’ three-year electric and natural gas C&LM plan, which was jointly developed with other Connecticut EDCs and natural gas distribution companies. These electric and natural gas energy efficiency and C&LM plans include the ability to earn performance incentives as well as recover LBR for NSTAR Electric until it is operating under a decoupled rate structure.

On January 7, 2015, the DPU issued an order concluding that NSTAR Electric had removed energy-related bad debt costs from base distribution rates effective January 1, 2006. As a result of the DPU order, in the first quarter of 2015 NSTAR Electric increased its regulatory assets and reduced its operations and maintenance expense by $24.2 million for energy-related bad debt costs through 2014, resulting in after-tax earnings of $14.5 million. NSTAR Electric filed for recovery of the energy-related bad debt costs regulatory asset from customers and on November 20, 2015, the DPU approved NSTAR Electric’s proposed rate increase to recover these costs over a 12-month period, beginning January 1, 2016.

Overview

Consolidated: A summary of our earnings by business, which also reconciles the non-GAAP financial measures of consolidated non-GAAP earnings and EPS, as well as EPS by business, to the most directly comparable GAAP measures of consolidated Net Income Attributable to Common Shareholders and diluted EPS, is as follows:


	For the Years Ended December 31,
	2015				2014				2013
(Millions of Dollars, Except Per Share Amounts)	Amount		Per Share		Amount		Per Share		Amount		Per Share
Net Income Attributable to Common Shareholders (GAAP)	$	878.5	$	2.76	$	819.5	$	2.58	$	786.0	$	2.49
Regulated Companies	$	884.8	$	2.78	$	830.1	$	2.61	$	774.9	$	2.45
Eversource Parent and Other Companies		9.5		0.03		11.5		0.04		24.9		0.08
Non-GAAP Earnings		894.3		2.81		841.6		2.65		799.8		2.53
Integration Costs (after-tax)		(15.8)		(0.05)		(22.1)		(0.07)		(13.8)		(0.04)
Net Income Attributable to Common Shareholders (GAAP)	$	878.5	$	2.76	$	819.5	$	2.58	$	786.0	$	2.49

The 2015 and 2014 integration costs are associated with our branding efforts and severance costs.

Regulated Companies: Our Regulated companies consist of the electric distribution, electric 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 is as follows:


	For the Years Ended December 31,
	2015				2014				2013
(Millions of Dollars, Except Per Share Amounts)	Amount		Per Share		Amount		Per Share		Amount		Per Share
Electric Distribution	$	507.9	$	1.59	$	462.4	$	1.45	$	427.0	$	1.35
Electric Transmission		304.5		0.96		295.4		0.93		287.0		0.91
Natural Gas Distribution		72.4		0.23		72.3		0.23		60.9		0.19
Non-GAAP Earnings		884.8		2.78		830.1		2.61		774.9		2.45
Integration Costs (after-tax)		(0.8)		-		-		-		-		-
Net Income - Regulated Companies	$	884.0	$	2.78	$	830.1	$	2.61	$	774.9	$	2.45

The 2015 Regulated companies' integration costs include severance in connection with cost saving initiatives.

Excluding integration costs, our electric distribution segment earnings increased $45.5 million in 2015, as compared to 2014, due primarily to the impact of the December 1, 2014 CL&P base distribution rate increase, the $27.5 million favorable earnings impact related to the resolution of NSTAR Electric’s basic service bad debt adder and the settlement with the Massachusetts Attorney General on eleven open dockets covering the CPSL program filings and the recovery of LBR related to 2009 through 2011 energy efficiency programs at NSTAR Electric, an increase in the recovery of LBR at NSTAR Electric related to 2015 energy efficiency programs, and higher retail sales volumes at NSTAR Electric and PSNH. Partially offsetting these favorable earnings impacts were a higher effective tax rate in 2015, higher property taxes, higher depreciation expense and a $5 million contribution in 2015 to create a clean energy fund in connection with the PSNH divestiture agreement.

Our electric transmission segment earnings increased $9.1 million in 2015, as compared to 2014, due primarily to the result of lower reserve charges associated with the FERC ROE complaint proceedings of $12.4 million recorded in 2015, as compared to $22.4 million recorded in 2014, and a higher transmission rate base as a result of an increased investment in our transmission infrastructure. These favorable earnings impacts were partially offset by a higher effective tax rate in 2015.

Our natural gas distribution segment earnings increased $0.1 million in 2015, as compared to 2014. Our natural gas distribution segment earnings were favorably impacted by a decrease in operations and maintenance costs primarily attributable to lower employee-related expenses, a lower effective tax rate in 2015, and additional natural gas heating customers. These favorable earnings impacts were offset by a decrease in firm natural gas sales volumes driven by record warm weather in the fourth quarter of 2015, as compared to 2014, higher depreciation expense and higher property taxes.

Eversource Parent and Other Companies: Excluding the impact of integration costs, Eversource parent and other companies had earnings of $9.5 million in 2015, compared with earnings of $11.5 million in 2014. The earnings decrease was due primarily to a higher effective tax rate at Eversource parent in 2015, as compared to 2014, higher interest expense at Eversource parent as a result of new debt issuances in January 2015, and reduced earnings in 2015 from Eversource's unregulated electrical contracting business, which was sold in April 2015. These unfavorable earnings impacts were partially offset by a reduction in operations and maintenance costs.

Electric and Natural Gas Sales Volumes: Weather, fluctuations in energy supply costs, conservation measures (including utility-sponsored energy efficiency programs), and economic conditions affect customer energy usage. Industrial sales volumes are less sensitive to temperature variations than residential and commercial sales volumes. In our service territories, weather impacts electric sales volumes during the summer and both electric and natural gas sales volumes during the winter; however, natural gas sales volumes are more sensitive to temperature variations than are electric sales volumes. Customer heating or cooling usage may not directly correlate with historical levels or with the level of degree-days that occur.

Fluctuations in retail electric sales volumes at NSTAR Electric and PSNH impact earnings ("Traditional" in the table below). For CL&P (effective December 1, 2014) and WMECO, fluctuations in retail electric sales volumes do not impact earnings due to their respective regulatory commission approved revenue decoupling mechanisms (“Decoupled” in the table below). These distribution revenues are decoupled from their customer sales volumes, which breaks the relationship between sales volumes and revenues recognized. CL&P and WMECO reconcile their annual base distribution rate recovery amounts to their respective pre-established levels of baseline distribution delivery service revenues. Any difference between the allowed level of distribution revenue and the actual amount incurred during a 12-month period is adjusted through rates in the following period.

A summary of our retail electric GWh sales volumes and our firm natural gas sales volumes in million cubic feet and percentage changes is as follows:


	For the Year Ended December 31, 2015 Compared to 2014
	Sales Volumes (GWh)		Percentage
Electric	2015	2014	Increase/(Decrease)
Traditional:
Residential	9,882	9,798	0.9%
Commercial	16,486	16,340	0.9%
Industrial	2,614	2,673	(2.2)%
Total - Traditional	28,982	28,811	0.6%

Decoupled:
Residential	11,559	11,519	0.3%
Commercial	11,112	11,109	- %
Industrial	2,963	3,003	(1.3)%
Total - Decoupled	25,634	25,631	- %
Total Sales Volumes	54,616	54,442	0.3%

	For the Year Ended December 31, 2015 Compared to 2014
	Sales Volumes (million cubic feet)		Percentage
Firm Natural Gas	2015	2014	Increase/(Decrease)
Residential	38,455	38,969	(1.3)%
Commercial	43,006	42,977	0.1 %
Industrial	21,538	22,245	(3.2)%
Total Sales Volumes	102,999	104,191	(1.1)%
Total, Net of Special Contracts (1)	98,458	99,500	(1.0)%

(1)

Special contracts are unique to the natural gas distribution 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.

Our 2015 retail electric sales volumes at our electric utilities with a traditional rate structure (NSTAR Electric and PSNH) were slightly higher, as compared to 2014, due primarily to the impact of colder winter weather experienced in the first quarter of 2015 and warmer weather in the third quarter of 2015, partially offset by milder winter weather in the fourth quarter of 2015 throughout those service territories. In 2015, heating degree days were 1 percent lower in the Boston metropolitan area, and 5 percent lower in New Hampshire, as compared to 2014. Cooling degree days in 2015 were 19 percent higher in the Boston metropolitan area and 57 percent higher in New Hampshire, as compared to 2014. Weather-normalized retail electric sales volumes were relatively unchanged in 2015, as compared to 2014. Improved economic conditions were offset by an increase in customer conservation efforts resulting from company-sponsored energy efficiency programs.

Our firm natural gas sales volumes are subject to many of the same influences as our retail electric sales volumes. In addition, they have benefited from customer growth in both of our natural gas distribution companies. In 2015, consolidated firm natural gas sales volumes were lower, as compared to 2014. The 2015 firm natural gas sales volumes were negatively impacted by record warm weather in the fourth quarter of 2015, when compared to 2014, partially offset by colder winter weather in the first quarter of 2015, as compared to 2014, throughout our natural gas service territories. Weather-normalized Eversource consolidated firm natural gas sales volumes increased 2.5 percent in 2015, as compared to 2014, due primarily to improved economic conditions as well as residential and commercial customer growth, partially offset by customer conservation efforts resulting from company-sponsored energy efficiency programs. On October 30, 2015, the DPU issued its order in the NSTAR Gas distribution rate case, which included the establishment of a revenue decoupling mechanism beginning January 1, 2016.

Prior to December 1, 2014, CL&P earned 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 earns LBR due to its revenue decoupling mechanism. NSTAR Electric recognized LBR of $60.6 million in 2015 and $39.9 million in 2014. On January 28, 2016, NSTAR Electric received approval of a three-year energy efficiency plan, which includes recovery of LBR until it is operating under a decoupled rate structure.

For further information, see "Regulatory Developments and Rate Matters - Massachusetts - NSTAR Electric, WMECO and NSTAR Gas Energy Efficiency Plan" and "Regulatory Developments and Rate Matters - Massachusetts - NSTAR Gas Distribution Rates" in this Management's Discussion and Analysis of Financial Conditions and Results of Operations.

Future Outlook

2016 EPS Guidance: We currently project 2016 earnings of between $2.90 per diluted share and $3.05 per diluted share.

Liquidity

Consolidated: Cash and cash equivalents totaled $23.9 million as of December 31, 2015, compared with $38.7 million as of December 31, 2014.

Long-Term Debt Issuances and Repayments: On January 15, 2015, Eversource parent issued $150 million of 1.60 percent Series G Senior Notes, due to mature in 2018, and $300 million of 3.15 percent Series H Senior Notes, due to mature in 2025.

On May 20, 2015 and December 1, 2015, CL&P issued $300 million and $50 million, respectively, of 4.15 percent 2015 Series A First and Refunding Mortgage Bonds due to mature in 2045.

On September 10, 2015, Yankee Gas issued $75 million of 3.35 percent 2015 Series M First Mortgage Bonds due to mature in 2025.

On November 18, 2015, NSTAR Electric issued $250 million of 3.25 percent debentures, due to mature in 2025.

On December 8, 2015, NSTAR Gas issued $100 million of 4.35 percent Series O First Mortgage Bonds due to mature in 2045.

The proceeds of all debt issuances, net of issuance costs, were used to repay short-term borrowings and fund capital expenditures and working capital.

On April 1, 2015, CL&P repaid at maturity the $100 million 5.00 percent 2005 Series A First and Refunding Mortgage Bonds and also redeemed the $62 million 1996A Series 1.55 percent PCRBs that were subject to mandatory tender, using short term borrowings.

On August 3, 2015, WMECO repaid at maturity the $50 million 5.24 percent Series C Senior Notes, using short-term borrowings.

Long-Term Debt Issuance Authorizations: On November 25, 2015, PURA approved Yankee Gas’ request to extend the authorization period for issuance of up to $125 million in long-term debt from December 31, 2015 to December 31, 2016. On December 4, 2015, the DPU authorized WMECO to issue up to $100 million in long-term debt for the period through December 31, 2016. On December 4, 2015, the DPU approved NSTAR Electric’s request to extend the authorization period for issuance of up to $250 million in long-term debt from December 31, 2015 to December 31, 2016.

Credit Agreements and Commercial Paper Programs: Eversource parent, CL&P, PSNH, WMECO, NSTAR Gas and Yankee Gas are parties to a five-year $1.45 billion revolving credit facility. On October 26, 2015, this revolving credit facility was amended and restated and the termination date was extended to September 4, 2020. Under the revolving credit facility, CL&P has a borrowing sublimit of $600 million, and PSNH and WMECO each have borrowing sublimits of $300 million. The revolving credit facility serves to backstop Eversource parent's $1.45 billion commercial paper program. The commercial paper program allows Eversource parent to issue commercial paper as a form of short-term debt. As of December 31, 2015 and 2014, Eversource parent had approximately $1.1 billion in short-term borrowings outstanding on each date under the

Eversource parent commercial paper program, leaving $351.5 million and $348.9 million of available borrowing capacity as of December 31, 2015 and 2014, respectively. The weighted-average interest rate on these borrowings as of December 31, 2015 and 2014 was 0.72 percent and 0.43 percent, respectively. As of December 31, 2015, there were intercompany loans from Eversource parent of $277.4 million to CL&P, $231.3 million to PSNH and $143.4 million to WMECO. As of December 31, 2014, there were intercompany loans from Eversource parent of $133.4 million to CL&P, $90.5 million to PSNH and $21.4 million to WMECO.

NSTAR Electric has a five-year $450 million revolving credit facility. On October 26, 2015, this revolving credit facility was amended and restated and the termination date was extended to September 4, 2020. The facility serves to backstop NSTAR Electric's $450 million commercial paper program. As of December 31, 2015 and 2014, NSTAR Electric had $62.5 million and $302 million, respectively, in short-term borrowings outstanding under its commercial paper program, leaving $387.5 million and $148 million of available borrowing capacity as of December 31, 2015 and 2014, respectively. The weighted-average interest rate on these borrowings as of December 31, 2015 and 2014 was 0.40 percent and 0.27 percent, respectively.

Cash Flows: Cash flows provided by operating activities totaled $1.4 billion in 2015, compared with $1.6 billion in 2014. The decrease in operating cash flows in 2015 compared to 2014 was due primarily to the $302 million payment made to fully satisfy the obligation with the DOE, as discussed below, and an increase in purchased power and congestion costs at NSTAR Electric, WMECO and CL&P that will be recovered in future periods. Also contributing to the decrease in operating cash flows were DOE Damages proceeds received from the Yankee Companies of $4.7 million in 2015, compared to $132 million in 2014. Partially offsetting these unfavorable cash flow impacts were a decrease of $49.2 million in Pension and PBOP Plan cash contributions in 2015, as compared to 2014, and lower federal income tax payments of approximately $324 million in 2015, as compared to 2014, primarily due to the extension of the accelerated depreciation deduction.

In late 2015, CL&P and WMECO made payments of $244.6 million and $57.4 million, respectively, to fully satisfy their obligations with the DOE, which were classified as long-term debt on the balance sheets as of December 31, 2014, for costs associated with the disposal of spent nuclear fuel and high-level radioactive waste for all periods prior to 1983 from their previous ownership interest in the Millstone nuclear power station. CL&P and WMECO divested their ownership interest in Millstone in 2001. These payments included accumulated interest of $178 million and $41.8 million for CL&P and WMECO, respectively. CL&P funded its payment with the issuance of debt, and WMECO liquidated its spent nuclear fuel trust to satisfy its obligation with the DOE.

On December 18, 2015, the "Protecting Americans from Tax Hikes" Act became law, which extended the accelerated deduction of depreciation to businesses from 2015 through 2019. This extended stimulus provides us with cash flow benefits in 2016 of approximately $275 million (including approximately $105 million for CL&P) due to a refund of taxes paid in 2015 and lower expected tax payments in 2016 of approximately $300 million.

In 2015, we paid cash dividends of $529.8 million, or $1.67 per common share, compared with $475.2 million, or $1.57 per share in 2014. Our quarterly common share dividend payment was $0.4175 per share, in 2015, as compared to $0.3925 per share, in 2014. On February 3, 2016, our Board of Trustees approved a common share dividend payment of $0.445 per share, payable on March 31, 2016 to shareholders of record as of March 2, 2016. The 2016 dividend represented an increase of 6.6 percent over the dividend paid in December 2015, and is equivalent to dividends on common shares of approximately $565 million on an annual basis.

In 2015, CL&P, NSTAR Electric, PSNH, and WMECO paid $196 million, $198 million, $106 million, and $37.2 million, respectively, in common stock dividends to Eversource parent.

Investments in Property, Plant and Equipment on the 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 2015, investments for Eversource, CL&P, NSTAR Electric, PSNH, and WMECO were $1.7 billion, $523.8 million, $469.5 million, $308 million, and $134.6 million, respectively.

Each of Eversource, CL&P, NSTAR Electric, PSNH and WMECO use its available capital resources to fund its respective construction expenditures, meet debt requirements, pay operating costs, including storm-related costs, pay dividends and fund other corporate obligations, such as pension contributions. The current growth in Eversource's construction expenditures utilizes a significant amount of cash for projects that have a long-term return on investment and recovery period. In addition, Eversource'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 and debt used to finance the investments. These factors have resulted in current liabilities exceeding current assets by approximately $371 million and $82 million at Eversource and WMECO, respectively, as of December 31, 2015.

As of December 31, 2015, a total of $200 million of Eversource’s long-term debt classified as current liabilities, all at NSTAR Electric, will be paid in the next 12 months. The remaining $28.9 million of Eversource's long-term debt classified as current liabilities relates to fair value adjustments from the merger that will be amortized in the next 12 months and have no cash flow impact. Eversource, 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. Eversource, CL&P, NSTAR Electric, PSNH and WMECO will reduce their short-term borrowings with operating cash flows or with the issuance of new long-term debt, determined by considering capital requirements and maintenance of Eversource's credit rating and profile. We expect the future operating cash flows of Eversource, 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.

Credit Ratings: On April 23, 2015, S&P upgraded the corporate credit ratings by one level and changed the outlooks to stable from positive of Eversource parent, CL&P, NSTAR Electric, PSNH, WMECO, Yankee Gas and NSTAR Gas. On May 19, 2015, Moody's changed the outlooks of PSNH and WMECO to positive from stable and affirmed their corporate credit ratings. On June 2, 2015, Fitch changed the outlooks to positive from stable of CL&P, PSNH and WMECO and affirmed its corporate credit ratings of Eversource parent, CL&P, NSTAR Electric, PSNH, WMECO and NSTAR Gas.

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
Eversource Parent	Baa1	Stable	A	Stable	BBB+	Stable
CL&P	Baa1	Stable	A	Stable	BBB+	Positive
NSTAR Electric	A2	Stable	A	Stable	A	Stable
PSNH	Baa1	Positive	A	Stable	BBB+	Positive
WMECO	A3	Positive	A	Stable	BBB+	Positive

A summary of the current credit ratings and outlooks by Moody's, S&P and Fitch for senior unsecured debt of Eversource parent, NSTAR Electric, and WMECO and senior secured debt of CL&P and PSNH is as follows:


	Moody's		S&P		Fitch
	Current	Outlook	Current	Outlook	Current	Outlook
Eversource Parent	Baa1	Stable	A-	Stable	BBB+	Stable
CL&P	A2	Stable	A+	Stable	A	Positive
NSTAR Electric	A2	Stable	A	Stable	A+	Stable
PSNH	A2	Positive	A+	Stable	A	Positive
WMECO	A3	Positive	A	Stable	A-	Positive

Business Development and Capital Expenditures

Our consolidated capital expenditures, including amounts incurred but not paid, cost of removal, AFUDC, and the capitalized portions of pension expense (all of which are non-cash factors), totaled $1.9 billion in 2015, $1.7 billion in 2014, and $1.6 billion in 2013. These amounts included $102 million in 2015, $58.3 million in 2014, and $44.7 million in 2013 related to information technology and facilities upgrades and enhancements, primarily at Eversource Service and The Rocky River Realty Company.

Natural Gas Transmission Business:

Access Northeast: Access Northeast is a natural gas pipeline and storage project (the "Project") being developed jointly by Eversource, Spectra Energy Corp and National Grid. Access Northeast will enhance the Algonquin and Maritimes & Northeast pipeline systems using existing routes and will include two new LNG storage tanks and liquefaction and vaporization facilities in Acushnet, Massachusetts that will be connected to the Algonquin gas pipeline. The Project is expected to be capable of delivering approximately 900 million cubic feet of additional natural gas per day to New England on peak demand days. Eversource and Spectra Energy Corp each own a 40 percent interest in the Project, with the remaining 20 percent interest owned by National Grid. The total projected cost for both the pipeline and the LNG storage is expected to be approximately $3 billion with anticipated in-service dates commencing in November 2018. The Project is subject to FERC and other federal and state regulatory approvals. On November 17, 2015, the FERC accepted the Project’s request to initiate the pre-filing review process. Upon completion of the pre-filing review, a certificate application will be filed with the FERC. In late 2015, the Project bid into the New England Natural Gas Pipeline Capacity RFP conducted by certain EDCs in Massachusetts and Rhode Island, including NSTAR Electric and WMECO in Massachusetts, and in December 2015 and January 2016, those Massachusetts EDCs filed with the DPU seeking approval of the contracts for pipeline and storage capacity with the Project. We expect the Rhode Island EDC to file its selected contracts with the Rhode Island regulatory agencies in the first half of 2016. In February 2016, PSNH filed for approval with the NHPUC, its proposed contract for natural gas pipeline capacity and storage with the Project. For further information on the RFP process, see "Regulatory Developments and Rate Matters – General – New England Natural Gas Pipeline Capacity" in this Management's Discussion and Analysis of Financial Conditions and Results of Operations.

Electric Transmission Business: Our consolidated electric transmission business capital expenditures increased by $106 million in 2015, as compared to 2014. A summary of electric transmission capital expenditures by company is as follows:


	For the Years Ended December 31,
(Millions of Dollars)	2015		2014		2013
CL&P	$	252.9	$	259.2	$	211.9
NSTAR Electric		238.2		223.8		220.8
PSNH		161.2		120.8		99.7
WMECO		116.0		68.5		87.2
NPT		38.3		28.3		39.9
Total Electric Transmission Segment	$	806.6	$	700.6	$	659.5

NEEWS: The Interstate Reliability Project (IRP), the second project within the NEEWS family of projects, was fully energized on December 18, 2015. The project involved CL&P's construction of an approximately 40-mile, 345-kV overhead line from Lebanon, Connecticut to the Connecticut-Rhode Island border where it connects to transmission enhancements constructed by National Grid in Rhode Island. IRP was placed in service in December 2015 at a final cost to CL&P of $192.6 million. Through December 31, 2015, CL&P and WMECO capitalized $377.9 million and $570.6 million, respectively, in costs associated with NEEWS.

GHCC: The Greater Hartford Central Connecticut (GHCC) solutions are comprised of 27 projects and are expected to cost approximately $350 million and be placed in service from 2016 through 2018. ISO-NE posted the final Solutions Study for GHCC in late February 2015 and approved our Proposed Plan Applications on April 16, 2015. Through December 31, 2015, we have filed siting applications for five projects all of which have been approved by the Connecticut Siting Council. During 2016, fifteen projects are expected to be in active construction, and three additional siting applications are expected to be filed. All GHCC projects are expected to be completed by late 2018. As of December 31, 2015, CL&P had capitalized $50.6 million in costs associated with GHCC.

Northern Pass: Northern Pass is Eversource's planned HVDC transmission line from the Québec-New Hampshire border to Franklin, New Hampshire and an associated alternating current radial transmission line between Franklin and Deerfield, New Hampshire. Northern Pass will interconnect at the Québec-New Hampshire border with a planned HQ HVDC transmission line. On July 21, 2015, the DOE issued the draft Environmental Impact Statement (EIS) for Northern Pass representing a key milestone in the permitting process. On August 18, 2015, a revised route was announced with an additional 52 miles of the route underground in and around the White Mountain National Forest region. As a result, the NPT project cost estimate increased from $1.4 billion to $1.6 billion. Concurrently, NPT announced the Forward NH Plan, which is a commitment to allocate $200 million to projects associated with economic development, community betterment, and clean energy innovations to benefit the state of New Hampshire. This commitment is contingent upon the Northern Pass transmission line going into commercial operation.

On October 19, 2015, NPT filed its NH SEC application, which was accepted as complete by the NH SEC on December 18, 2015, allowing the formal siting process to move forward. In response to requests by the New Hampshire congressional delegation, the DOE announced that it would issue a supplement to the draft EIS. Public hearings on the draft EIS will be held in March 2016. The DOE has asked for comments by April 4, 2016. The project is expected to be operational in the first half of 2019. On January 28, 2016, NPT bid into the three-state Clean Energy RFP process. For further information on the RFP process, see "Regulatory Developments and Rate Matters – General – Clean Energy RFP" in this Management's Discussion and Analysis of Financial Conditions and Results of Operations.

Clean Energy Connect: The Clean Energy Connect project is a planned transmission, wind and hydro generation project that we plan to co-develop with experienced renewable generation companies. On January 28, 2016, the Clean Energy Connect project was bid into the three-state Clean Energy RFP process. Our investment, should the Clean Energy Connect Project be selected in the RFP process, is currently estimated to be at least $400 million, and would involve the construction of a new 25-mile, 345kV transmission line with a 600 MW capacity from western Massachusetts to eastern New York.

Greater Boston Reliability Solutions: In February 2015, ISO-NE selected Eversource's and National Grid's proposed Greater Boston and New Hampshire Solution (Solution) to satisfy the requirements identified in the Greater Boston study. The Solution consists of a portfolio of electric transmission upgrades straddling southern New Hampshire and northern Massachusetts in the Merrimack Valley and continuing into the greater Boston metropolitan area. We are pursuing the necessary regulatory approvals and have filed several siting applications in Massachusetts and New Hampshire. We estimate our portion of the investment in the Solution will be $544 million.

Distribution Business: A summary of distribution capital expenditures by company is as follows:


	For the Years Ended December 31,
(Millions of Dollars)	2015		2014		2013
CL&P:
Basic Business	$	141.1	$	120.2	$	60.9
Aging Infrastructure		151.0		118.0		160.7
Load Growth		42.2		66.3		76.9
Total CL&P		334.3		304.5		298.5
NSTAR Electric:
Basic Business		108.7		99.0		98.5
Aging Infrastructure		103.1		104.2		110.6
Load Growth		51.9		43.1		53.6
Total NSTAR Electric		263.7		246.3		262.7
PSNH:
Basic Business		59.2		62.1		22.7
Aging Infrastructure		57.3		45.3		50.5
Load Growth		25.5		27.1		29.3
Total PSNH		142.0		134.5		102.5
WMECO:
Basic Business		18.2		19.0		7.9
Aging Infrastructure		18.5		16.1		24.6
Load Growth		6.6		6.1		9.2
Total WMECO		43.3		41.2		41.7
Total - Electric Distribution (excluding Generation)		783.3		726.5		705.4
Other Distribution		-		-		0.7
PSNH Generation		33.3		13.1		9.7
WMECO Generation		-		7.6		4.5
Natural Gas		212.6		193.7		175.2
Total Electric and Natural Gas Distribution Segment	$	1,029.2	$	940.9	$	895.5

For the electric distribution business, basic business includes the purchase of meters, tools, vehicles, information technology, transformer replacements, equipment facilities, and the relocation of plant. Aging infrastructure relates to reliability and the replacement of overhead lines, plant substations, underground cable replacement, and equipment failures. Load growth includes requests for new business and capacity additions on distribution lines and substation additions and expansions.

Natural Gas Distribution 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 estimated that its portion of the plan would cost approximately $700 million over 10 years. In January 2015, the 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. On March 20, 2015, Yankee Gas filed its initial System Expansion (SE) Rate reconciliation for 2014. The proposed SE rate was approved by the PURA for implementation as of April 1, 2015, pending final PURA approval following a contested hearing.

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 to within 25 years. The GSEP includes a new tariff effective January 1, 2016 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 expect capital expenditures of approximately $255 million for the period 2016 through 2019 for the GSEP.

Projected Capital Expenditures: A summary of the projected capital expenditures for the Regulated companies' electric transmission and for the total electric distribution, generation, and natural gas distribution businesses for 2016 through 2019, including information technology and facilities upgrades and enhancements on behalf of the Regulated companies, is as follows:


	Years
(Millions of Dollars)	2016		2017		2018		2019		2016-2019 Total
CL&P Transmission	$	351	$	250	$	215	$	157	$	973
NSTAR Electric Transmission		302		216		238		149		905
PSNH Transmission		112		65		38		56		271
WMECO Transmission		115		78		22		40		255
NPT		31		684		636		149		1,500
Total Electric Transmission	$	911	$	1,293	$	1,149	$	551	$	3,904
Electric Distribution	$	892	$	963	$	888	$	840	$	3,583
Generation		20		-		-		-		20
Natural Gas		284		318		339		357		1,298
Total Distribution	$	1,196	$	1,281	$	1,227	$	1,197	$	4,901
Information Technology and All Other	$	105	$	88	$	82	$	87	$	362
Total	$	2,212	$	2,662	$	2,458	$	1,835	$	9,167

The projections do not include capital investments related to Access Northeast or Clean Energy Connect. Actual capital expenditures could vary from the projected amounts for the companies and years above.

FERC Regulatory Issues

FERC ROE Complaints: Three separate complaints have been filed at FERC by combinations of New England state attorneys general, state regulatory commissions, consumer advocates, consumer groups, municipal parties and other parties (the "Complainants"). In these three separate complaints, the Complainants challenged the NETOs' base ROE of 11.14 percent that had been utilized since 2006 and 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 a 10.57 percent base ROE for the first complaint refund period and prospectively from October 16, 2014, and that a utility's total or maximum ROE shall not exceed the top of the new zone of reasonableness, which was set at 11.74 percent. The NETOs and the Complainants sought rehearing from FERC. In late 2014, the NETOs made a compliance filing and the Company began issuing refunds to customers from the first complaint period.

As a result of the actions taken by the FERC and other developments in the first complaint matter, the Company recorded reserves at its electric subsidiaries in 2015, 2014 and 2013. In 2015, Eversource recognized an after-tax charge to earnings (excluding interest) of $12.4 million, of which $7.9 million was recorded at CL&P, $1.4 million at NSTAR Electric, $0.6 million at PSNH, and $2.5 million at WMECO. The net aggregate after-tax charge to earnings (excluding interest) in 2014 totaled $22.4 million, of which $12.4 million was recorded at CL&P, $4.9 million at NSTAR Electric, $1.7 million at PSNH and $3.4 million at WMECO. The aggregate after-tax charge to earnings (excluding interest) in 2013 totaled $14.3 million, of which $7.7 million was recorded at CL&P, $3.4 million at NSTAR Electric, $1.4 million at PSNH and $1.8 million at WMECO. The NETOs and Complainants have filed appeals to the D.C. Circuit Court of Appeals. A court decision is expected in late 2016.

For the second and third complaints, the state parties, municipal utilities and FERC trial staff each believe that the base ROE should be reduced to an amount lower than 10.57 percent. The NETOs believe that the Complainants' positions are without merit, and the existing base ROE of 10.57 percent is just and reasonable and should be maintained. The FERC ALJ’s initial recommendation is expected by March 31, 2016. A final FERC order is expected in late 2016 or early 2017.

As of December 31, 2015, CL&P, NSTAR Electric, PSNH, and WMECO had approximately $2.7 billion of aggregate shareholder equity invested in their transmission facilities. As a result, each 10 basis point change in the authorized base ROE would change annual consolidated earnings by an approximate $2.7 million. Although we are uncertain on the final outcome of the second and third complaints regarding the ROE, we believe the current reserves established are appropriate to reflect probable and reasonably estimable refunds.

FERC Order No. 1000: On August 15, 2014, the D.C. Circuit Court of Appeals upheld the FERC's authority to order major changes to transmission planning and cost allocation in FERC Order No. 1000 and Order No. 1000-A, including transmission planning for public policy needs, and the requirement that utilities remove from their transmission tariffs their rights of first refusal to build transmission. On March 19, 2015, the FERC acted on all rehearing requests filed by the NETOs, 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. The 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 a solution must be re-evaluated. The 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. Final compliance was filed by the NETOs in November 2015 and was accepted by the FERC on December 14, 2015.

Additionally, the FERC affirmed that it can eliminate our right of first refusal to build transmission in New England even though the FERC previously approved and granted special protections to these rights. The NETOs filed an appeal to the D.C. Circuit Court of Appeals, challenging this FERC ruling. State regulators also filed an appeal, challenging FERC’s determination that ISO-NE should select public policy transmission projects after a competitive process. The Court is expected to resolve the appeals in 2016.

Regulatory Developments and Rate Matters

General:

Clean Energy RFP: In February 2015, pursuant to clean energy goals established in three New England states (Connecticut, Massachusetts and Rhode Island), CL&P, NSTAR Electric, WMECO, other EDCs, and state agencies in the three states jointly developed and issued a draft request for proposal (RFP) for clean energy resources (including Class I renewable generation and large hydroelectric generation). The draft RFP solicits offers for clean energy and the transmission to deliver that energy to the three states. The procurement will allow the states to identify large-scale projects that may offer the potential to meet their clean energy goals in a cost-effective manner when entered into jointly, while complying with the clean energy statutes within the three states.

The DPU and the Rhode Island Public Utilities Commission (PUC) approved the draft RFP that was jointly submitted by certain EDCs. The draft RFP encompassed the timetable and method for the solicitation and execution of any associated long-term contracts. On August 31, 2015, the DEEP issued a notice of proceeding on the Connecticut portion of the draft RFP and accepted public comment through September 30, 2015. On November 12, 2015, the DEEP and the Massachusetts and Rhode Island EDCs issued the RFP to a wide range of potentially interested bidders. In late January 2016, bidders submitted project proposals, among which were the Northern Pass and Clean Energy Connect projects, selection of which will take place between April and July 2016. The expected timeframe within which EDCs will execute contracts and submit them for regulatory commission approval from the respective state regulators is from June through October 2016 with approval expected in late 2016.

New England Natural Gas Pipeline Capacity: In 2014, the six New England states began to explore ways to address and mitigate winter natural gas price volatility and the associated impact on electric power supply costs attributable to winter pipeline capacity constraints. Five states are currently pursuing natural gas capacity expansion efforts. In 2014, Rhode Island approved legislation authorizing the Rhode Island Division of Public Utilities and Carriers and the Office of Energy Resources to participate in the RFP process and file proposals with the PUC. In late 2015, Access Northeast bid on the natural gas pipeline and storage RFP issued by the Rhode Island EDC. We expect the EDC will file their selected contracts with the PUC in the first half of 2016. The Massachusetts DPU determined that it has the authority to allow EDCs to contract for natural gas pipeline capacity and in late 2015, certain Massachusetts EDCs, including NSTAR Electric and WMECO, issued a natural gas pipeline capacity RFP. In December 2015 and January 2016, those Massachusetts EDCs filed with the DPU seeking approval of the contracts for pipeline and storage capacity, including Access Northeast. On January 19, 2016, the NHPUC issued an order accepting a staff report that concluded that the NHPUC could approve contracts between pipelines and EDCs if they were shown to reduce electricity costs and be in the public interest. In February 2016, PSNH filed for approval with the NHPUC, its proposed contract for natural gas pipeline capacity and storage with Access Northeast. The Connecticut DEEP expects to provide an opportunity for public comment on a natural gas pipeline capacity RFP in the first quarter of 2016.

Electric and Natural Gas Base Distribution Rates:

Each Eversource utility subsidiary is subject to the regulatory jurisdiction of the state in which it operates: CL&P and Yankee Gas operate in Connecticut and are subject to PURA regulation; NSTAR Electric, WMECO and NSTAR Gas operate in Massachusetts and are subject to DPU regulation; and PSNH operates in New Hampshire and is subject to NHPUC regulation. 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.

In Connecticut, CL&P distribution rates were established in a 2014 PURA approved rate case. Yankee Gas distribution rates were established in a 2011 PURA approved rate case. In Massachusetts, electric utility companies are required to file at least one distribution rate case every five years, and natural gas companies to file at least one distribution rate case every 10 years, and those companies are limited to one settlement agreement in any 10-year period. NSTAR Electric and WMECO were subject to a base distribution rate freeze through December 31, 2015. NSTAR Gas distribution rates effective January 1, 2016 were established in an October 30, 2015 DPU distribution rate order. See Massachusetts – NSTAR Gas Distribution Rates in this Regulatory Developments and Rate Matters section for further information. In New Hampshire, PSNH distribution rates were established in a settlement approved by the NHPUC in 2010. Prior to the expiration of that settlement, the NHPUC approved the continuation, and increased funding via rates, of PSNH’s reliability enhancement program. See New Hampshire - Distribution Rates in this Regulatory Developments and Rate Matters section for further information.

Electric and Natural Gas Retail Rates:

The Eversource EDCs obtain and resell power to retail customers who choose not to buy energy from a competitive energy supplier. The natural gas distribution companies procure natural gas for firm and seasonal customers. These energy supply procurement costs are recovered from customers in energy supply rates that are approved by the respective state regulatory commission. The rates are reset periodically and are fully reconciled to their costs. Each electric and natural gas distribution company fully recovers its energy supply costs through approved regulatory rate mechanisms and, therefore, such costs have no impact on earnings.

The electric and natural gas distribution companies also recover certain costs on a fully reconciling basis through regulatory commission-approved cost tracking mechanisms and, therefore, such costs have no impact on earnings. Costs recovered through costs tracking mechanisms include energy efficiency program costs, electric transmission charges, electric federally mandated congestion charges, system resiliency costs, certain uncollectible hardship bad debt expenses, and restructuring and stranded costs resulting from deregulation. The reconciliation filings compare the total actual costs allowed to revenue requirements related to these services and the difference between the costs incurred (or the rate recovery allowed) and the actual costs allowed is deferred and included, to be either recovered or refunded, in future customer rates.

Connecticut:

CL&P Distribution Rates: In December 2014, the PURA granted a re-opener request to CL&P’s base distribution rate application for further review of the appropriate balance of ADIT utilized in the calculation of rate base. On July 2, 2015, the PURA issued a final order that approved a settlement agreement filed on May 19, 2015 between CL&P and the PURA Prosecutorial Staff. The order allows for an increase to rate base of approximately $163 million associated with ADIT, including a regulatory asset to recover the incremental revenue requirement for the period December 1, 2014 through November 30, 2015 over a subsequent 24-month period. The rate base increase provided an increase to total allowed annual revenue requirements of $18.4 million beginning December 1, 2014. As part of the settlement agreement, the $18.4 million for the period December 1, 2014 through November 30, 2015 was recorded as a regulatory asset with a corresponding increase in Operating Revenues, and is being collected from customers in rates over a 24-month period beginning December 1, 2015.

CL&P and Yankee Gas Conservation and Load Management Plan: On December 31, 2015, DEEP approved the three-year electric and natural gas C&LM plan filed by CL&P and Yankee Gas, which was jointly developed with the Connecticut EDCs and natural gas distribution companies. The C&LM plan, which covers the years 2016 through 2018, was built upon the continued success and momentum of the previous C&LM plans and includes performance incentives totaling $24 million over the three-year period related to proposed savings goals for CL&P and Yankee Gas.

Yankee Gas Settlement Agreement: On April 29, 2015, the PURA approved a settlement agreement entered into among Yankee Gas, the Connecticut Office of Consumer Counsel, and the PURA Staff, which eliminated the requirement to file a base distribution rate case in 2015. Under the terms of the settlement agreement, Yankee Gas provided a $1.5 million rate credit to firm customers beginning in December 2015 and continued through February 2016, and established an earnings sharing mechanism whereby Yankee Gas and its customers will share equally in any earnings exceeding a 9.5 percent ROE in a twelve month period commencing with the period from April 1, 2015 through March 31, 2016. Additionally, Yankee Gas shall forgo its right to file a rate case for an increase in its base distribution rates prior to January 1, 2017. This does not impact the rates charged under the Connecticut comprehensive energy strategy (CES) program. The settlement agreement also resolved two pending regulatory proceedings before the PURA pertaining to a review of Yankee Gas’ overearnings. In 2015, Yankee Gas recorded the $1.5 million expected refund to customers as a reduction to operating revenues.

Massachusetts:

NSTAR Electric and NSTAR Gas 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 2009 through 2011 (11 dockets in total). In the first quarter of 2015, as a result of the DPU order, NSTAR Electric and NSTAR Gas commenced refunding a combined $44.7 million to customers, which was recorded as a regulatory liability. Refunds to customers will continue through December 2016. As a result of the Settlement, NSTAR Electric increased its operating revenues and decreased its amortization expense in 2015, resulting in the recognition of a $13 million after-tax benefit.

NSTAR Electric Basic Service Bad Debt Adder: On January 7, 2015, the DPU issued an order concluding that NSTAR Electric had removed energy-related bad debt costs from base distribution rates effective January 1, 2006. As a result of the DPU order, in the first quarter of 2015, NSTAR Electric increased its regulatory assets and reduced its operations and maintenance expense by an under recovered amount of $24.2 million for energy-related bad debt costs through 2014, resulting in after-tax earnings of $14.5 million. NSTAR Electric filed for recovery of the energy-related bad debt costs regulatory asset from customers and on November 20, 2015, the DPU approved NSTAR Electric’s proposed rate increase to recover these costs over a 12-month period, beginning January 1, 2016.

NSTAR Electric and WMECO Grid Modernization Plan: As part of the DPU’s investigation into the modernization of the electric grid, in August 2015, NSTAR Electric and WMECO filed a comprehensive ten-year plan with the DPU. The plan focuses on technologies and investments that modernize the grid with proposed investments in equipment that reduces the frequency and duration of power outages, optimizes and manages electrical demand, integrates distributed energy resources, and improves workforce and asset management. The plan includes incremental spending of approximately $430 million over the first five years, which would be recovered from customers in rates, and is pending DPU review and approval. There is currently no timeline for the DPU to take any action on this plan.

NSTAR Electric, WMECO and NSTAR Gas Energy Efficiency Plan: The Massachusetts EDCs and natural gas distribution companies have increased their energy efficiency savings achievements significantly since the enactment of the Green Communities Act in 2008, with electric savings almost tripling between 2008 and 2014. On January 28, 2016, the DPU issued an order approving NSTAR Electric’s, WMECO’s, and NSTAR Gas’ three-year electric and natural gas energy efficiency plan, which was jointly developed with other Massachusetts EDCs and natural gas distribution companies. As part of this plan, which covers the years 2016 through 2018, NSTAR Electric, WMECO, and NSTAR Gas will maintain aggressive savings goals. The plan includes the ability to earn performance incentives related to these aggressive savings goals totaling $58 million over the three-year period for NSTAR Electric, WMECO and NSTAR Gas, as well as recovery of LBR of approximately $50 million on an annual basis for NSTAR Electric until it is operating under a decoupled rate structure.

NSTAR Electric DPU Safety and Reliability Programs: The safety and reliability programs allowed NSTAR Electric to recover $15 million per year, through December 31, 2015, related to DPU approved safety and reliability programs, which are designed to mitigate stray voltage and repair and replace portions of the system to increase and enhance customer safety.

NSTAR Gas Distribution Rates: On October 30, 2015, the DPU issued its order in the NSTAR Gas distribution rate case, which approved an annualized base rate increase of $15.8 million, plus other increases of approximately $11.5 million, mostly relating to recovery of pension and PBOP expenses and the Hopkinton Gas Service Agreement (GSA), effective January 1, 2016. In the order, the DPU also approved an authorized regulatory

ROE of 9.8 percent, the establishment of a revenue decoupling mechanism, the recovery of certain bad debt expenses, and a 52.1 percent equity component of its capital structure. On November 19, 2015, NSTAR Gas filed a motion for reconsideration of the order with the DPU seeking the correction of mathematical errors and other plant and cost of service items.

As a result of this order, Eversource recorded regulatory deferrals for costs that have been approved for recovery or are expected to be approved for recovery in future rate proceedings, which resulted in the recognition of a $10.3 million after-tax benefit in 2015. Included in this amount is a $6.3 million after-tax benefit recorded at NSTAR Electric for certain uncollectible hardship accounts receivable that are expected to be recovered in future rates given the allowed recoveries of uncollectible hardship accounts receivable by WMECO and NSTAR Gas.

NSTAR Gas - Gas Service Agreement: On April 29, 2015, the DPU approved the GSA, subject to DPU modifications, between NSTAR Gas and Hopkinton LNG Corp. (HOPCO), an indirect, wholly-owned subsidiary of Eversource. On October 30, 2015, the DPU issued its order in the NSTAR Gas distribution rate case that required minor changes to the GSA. On May 22, 2015 and November 17, 2015, we filed revised GSAs with the DPU reflecting these modifications. The GSA effectively replaces the former gas services agreement in place between NSTAR Gas and HOPCO, maintains NSTAR Gas Company's entitlement to 100 percent of the current capacity of the HOPCO facilities, and provides for the recovery of costs associated with planned capital expenditures at the HOPCO facilities. We currently estimate the HOPCO facilities’ capital expenditures to be approximately $200 million, most of which will be invested and placed into service in the first five years of the GSA. The GSA has a 30-year term commencing on January 1, 2016.

New Hampshire:

Distribution Rates: PSNH distribution rates were established in a settlement approved by the NHPUC in 2010. Rates established therein will continue until changed by the NHPUC in a subsequent distribution rate proceeding. In June 2015, PSNH sought and obtained approval for a distribution rate increase to fund continuation of the reliability enhancement program beyond the end of the PSNH's 2010 distribution rate settlement.

Generation Divestiture:

On June 10, 2015, Eversource and PSNH entered into the 2015 Public Service Company of New Hampshire Restructuring and Rate Stabilization Agreement (the Agreement) with the New Hampshire Office of Energy and Planning, certain members of the NHPUC staff, the Office of Consumer Advocate, two State Senators, and several other parties. The Agreement was filed with the NHPUC on the same day. Under the terms of the Agreement, PSNH has agreed to divest its generation assets upon NHPUC approval. The Agreement is designed to provide a resolution of issues pertaining to PSNH's generation assets in pending regulatory proceedings before the NHPUC. The Agreement provided for the Clean Air Project prudence proceeding to be resolved and all remaining Clean Air Project costs to be included in rates effective January 1, 2016. As part of the Agreement, PSNH has agreed to forego recovery of $25 million of the deferred equity return related to the Clean Air Project. In addition, PSNH will not seek a general distribution rate increase effective before July 1, 2017 and will contribute $5 million to create a clean energy fund, which will not be recoverable from its customers. In 2015, PSNH recorded the $5 million contribution as a long-term liability and an increase to Operations and Maintenance expense on the statements of income.

Upon completion of the divestiture process, all remaining stranded costs will be recovered via bonds that will be secured by a non-bypassable charge or through other recoveries in rates billed to PSNH's customers. For further information on the securitization legislation that was signed into law on July 9, 2015, see "Legislative and Policy Matters – New Hampshire" in this Management's Discussion and Analysis of Financial Conditions and Results of Operations.

On January 26, 2016, Advisory Staff of the NHPUC and the parties to the Agreement filed a stipulation with the NHPUC agreeing that near-term divestiture of PSNH’s generation was in the public interest and that the Agreement should be approved. Implementation of the Agreement is subject to NHPUC approval, which is expected in early 2016.

We believe that full recovery of PSNH's generation assets is probable through a combination of cash flows during the remaining operating period, sales proceeds upon divestiture, and recovery of stranded costs in future rates.

Clean Air Project Prudence Proceeding: The Clean Air Project, which involved the installation of wet scrubber technology at PSNH's Merrimack coal-fired generation station in Bow, New Hampshire, pursuant to state law, was placed in service in September 2011. In April 2012, the NHPUC issued an order authorizing temporary rates to recover a significant portion of the Clean Air Project costs.

Pursuant to the Agreement, on December 22, 2015, the NHPUC approved PSNH’s request to increase its default energy service rate for full recovery of costs (including a return) related to the Clean Air Project, as well as a deferred equity return, effective January 1, 2016. The approved energy supply portion of the 2016 rate is 9.99 cents per kWh (including all Clean Energy Project-related costs), and the SCRC rate for 2016 is a credit to customers of 0.017 cents per kWh.

Legislative and Policy Matters

Federal: On December 18, 2015, the "Protecting Americans from Tax Hikes" Act became law, which extended the accelerated deduction of depreciation to businesses from 2015 through 2019. This extended stimulus provides us with cash flow benefits of approximately $275 million (including approximately $105 million for CL&P) due to a refund of taxes paid in 2015 and lower expected tax payments in 2016 of approximately $300 million.

New Hampshire: On July 9, 2015, the Governor of New Hampshire signed "An Act Relative to Electric Rate Reduction Financing" (the Act) permitting the NHPUC to issue finance orders that authorize the issuance of rate reduction bonds in accordance with the PSNH divestiture agreement and the expected NHPUC divestiture order, regarding cost recovery of the Clean Air project and divestiture of PSNH’s remaining generation plants.

Connecticut: In 2015, the state of Connecticut enacted several changes to its corporate tax laws. Among the changes, commencing as of January 1, 2015, is the reduction in the amount of tax credits that corporations can utilize against its tax liability in a year and a continuation of the corporate income tax surcharge through 2018, which effectively increases the state corporate tax rate to 9 percent for the years 2016 and 2017 and 8.25 percent for 2018. Also, effective January 1, 2016, all Connecticut companies have a mandatory unitary tax filing requirement. We continue to review the tax law changes and their impact on the effective tax rates of Eversource and CL&P.

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 discusses with the Audit Committee of our Board of Trustees significant matters relating to critical accounting policies. Our critical accounting policies are discussed below. See the combined notes to our financial statements for further information concerning the accounting policies, estimates and assumptions used in the preparation of our financial statements.

Regulatory Accounting: Our Regulated companies are subject to rate-regulation that is based on cost recovery and meets the criteria for application of accounting guidance for rate-regulated operations, which considers the effect of regulation on the timing of the recognition of certain revenues and expenses. The Regulated companies' financial statements reflect the effects of the rate-making process.

The application of accounting guidance for rate-regulated enterprises results in recording regulatory assets and liabilities. Regulatory assets represent the deferral of incurred costs that are probable of future recovery in customer rates. Regulatory assets are amortized as the incurred costs are recovered through customer rates. In some cases, we record regulatory assets before approval for recovery has been received from the applicable regulatory commission. We must use judgment to conclude that costs deferred as regulatory assets are probable of future recovery. We base our conclusion on certain factors, including, but not limited to, regulatory precedent. Regulatory liabilities represent revenues received from customers to fund expected costs that have not yet been incurred or probable future refunds to customers.

We use our best judgment when recording regulatory assets and liabilities; however, regulatory commissions can reach different conclusions about the recovery of costs, and those conclusions could have a material impact on our financial statements. We believe it is probable that each of the Regulated companies will recover the regulatory assets that have been recorded. If we determine that we can no longer apply the accounting guidance applicable to rate-regulated enterprises to our operations, or that we cannot conclude it is probable that costs will be recovered from customers in future rates, the costs would be charged to earnings in the period in which the determination is made.

Unbilled Revenues: The determination of retail energy sales to residential, commercial and industrial customers is based on the reading of meters, which occurs regularly throughout the month. Billed revenues are based on these meter readings, and the majority of our recorded annual revenues is based on actual billings. Because customers are billed throughout the month based on pre-determined cycles rather than on a calendar month basis, an estimate of electricity or natural gas delivered to customers for which the customers have not yet been billed is calculated as of the balance sheet date.

Unbilled revenues represent an estimate of electricity or natural gas delivered to customers but not yet billed. Unbilled revenues are included in Operating Revenues on the statement of income and are assets on the balance sheet that are reclassified to Accounts Receivable in the following month as customers are billed. Such estimates are subject to adjustment when actual meter readings become available or when there is a change in our estimates.

The Regulated companies estimate unbilled sales monthly using the daily load cycle method. The daily load cycle method allocates billed sales to the current calendar month based on the daily load for each billing cycle. The billed sales are subtracted from total month load, net of delivery losses, to estimate unbilled sales. Unbilled revenues are estimated by first allocating unbilled sales to the respective customer classes, then applying an estimated rate by customer class to those sales. The estimate of unbilled revenues is sensitive to factors such as energy demand, weather and changes in the composition of customer classes that can significantly impact the amount of revenues recorded at NSTAR Electric and PSNH because they do not have a revenue decoupling mechanism. CL&P and WMECO record a regulatory deferral to reflect the actual allowed amount of revenue for decoupling, and unbilled revenues estimation is not critical to CL&P and WMECO.

Pension and PBOP: We sponsor Pension and PBOP Plans to provide retirement benefits to our employees. Effective January 1, 2015, the two Pension Plans were merged into one Pension Plan, sponsored by Eversource Service, and our PBOP Plans were merged into one PBOP Plan, sponsored by Eversource Service. For each of these plans, several significant assumptions are used to determine the projected benefit obligation, funded status and net periodic benefit cost. These assumptions include the expected long-term rate of return on plan assets, discount rate, compensation/progression rate, mortality assumptions, and health care cost trend rates. We evaluate these assumptions at least annually and adjust them as necessary. Changes in these assumptions could have a material impact on our financial position, results of operations or cash flows.

Pre-tax net periodic benefit expense for the Pension Plan (excluding the SERP Plans) was $124.2 million, $118.4 million and $236.3 million for the years ended December 31, 2015, 2014 and 2013, respectively. The pre-tax net periodic benefit expense for the PBOP Plan was $2.4 million, $8.1 million and $32.6 million for the years ended December 31, 2015, 2014 and 2013, respectively.

Expected Long-Term Rate of Return on Plan Assets: In developing this assumption, we consider historical and expected returns as well as input from our consultants. Our expected long-term rate of return on assets is based on assumptions regarding target asset allocations and corresponding expected rates of return for each asset class. We routinely review the actual asset allocations and periodically rebalance the investments to the targeted asset allocations when appropriate. For the year ended December 31, 2015, our aggregate expected long-term rate of return assumption of 8.25 percent was used to determine our pension and PBOP expense. For the forecasted 2016 pension and PBOP expense, our expected long-term rate of return of 8.25 percent for all plans was used reflecting our target asset allocations.

Discount Rate: Payment obligations related to the Pension and PBOP Plans are discounted at interest rates applicable to the expected timing of each plan's cash flows. The discount rate that was utilized in determining the 2015 pension and PBOP obligations was based on a yield-curve approach. This approach utilizes a population of bonds with an average rating of AA based on bond ratings by Moody's, S&P and Fitch, and uses bonds with above median yields within that population. As of December 31, 2015, the discount rates used to determine the funded status were 4.6 percent for the Pension Plan and 4.62 percent for the PBOP Plan. As of December 31, 2014, the discount rates used were 4.2 percent for the Pension Plans and 4.22 percent for the PBOP Plans. The increase in the discount rate used to calculate the funded status resulted in a decrease on the Pension and PBOP Plan's liability of approximately $267 million and $60 million, respectively, as of December 31, 2015.

Compensation/Progression Rate: This assumption reflects the expected long-term salary growth rate, including consideration of the levels of increases built into collective bargaining agreements, and impacts the estimated benefits that Pension Plan participants receive in the future. As of both December 31, 2015 and 2014, the compensation/progression rate used to determine the funded status was 3.5 percent.

Mortality Assumptions: Assumptions as to mortality of the participants in our Pension and PBOP Plans are a key estimate in measuring the expected payments a participant may receive over their lifetime and the corresponding plan liability we need to record. During 2014, the Society of Actuaries released a series of updated mortality tables resulting from studies that measured mortality rates for various groups of individuals. The updated mortality tables released in 2014 increased the life expectancy of plan participants by three to five years and had the effect of increasing the estimated benefits to be provided to plan participants. The impact of adopting the updated mortality tables on Eversource's liability as of December 31, 2014 was an increase of approximately $340 million and $82 million for the Pension and PBOP Plans, respectively. In 2015, a revised scale for the mortality table was released having the effect of decreasing the estimate of benefits to be provided to plan participants. The impact of the adoption of the new mortality scale resulted in a decrease of $48 million and $23 million for the Pension and PBOP Plans' liability, respectively, as of December 31, 2015.

Actuarial Determination of Expense: Pension and PBOP expense is determined by our actuaries and consists of service cost and prior service cost, interest cost based on the discounting of the obligations, and amortization of actuarial gains and losses, offset by the expected return on plan assets. Actuarial gains and losses represent differences between assumptions and actual information or updated assumptions.

The expected return on plan assets is determined by applying the assumed long-term rate of return to the Pension and PBOP Plan asset balances. This calculated expected return is compared to the actual return or loss on plan assets at the end of each year to determine the investment gains or losses to be immediately reflected in unrecognized actuarial gains and losses.

Forecasted Expenses and Expected Contributions: We estimate that the expense for the Pension Plan (excluding the SERP Plans) will be approximately $65 million and income for the PBOP Plan will be approximately $7.7 million, respectively, in 2016. Effective January 1, 2016, we elected to transition the discount rate to the spot rate methodology from the yield-curve approach for the service and interest cost components of Pension and PBOP expense because it provides a more precise measurement by matching projected cash flows to the corresponding spot rates on the yield curve. Historically, these components were estimated using the same weighted-average discount rate as for the funded status. The discount rates used to estimate the 2016 service costs are 4.91 percent and 5.14 percent for the Pension and PBOP Plans, respectively. The discount rates used to estimate the 2016 interest costs are 3.80 percent and 3.72 percent for the Pension and PBOP Plans, respectively. Pension and PBOP expense for subsequent years will depend on future investment performance, changes in future discount rates and other assumptions, and various other factors related to the populations participating in the plans. Pension and PBOP expense charged to earnings is net of the amounts capitalized.

Our policy is to annually fund the Pension Plan in an amount at least equal to the amount that will satisfy all federal funding requirements. We contributed $154.6 million to the Pension Plan in 2015. We currently estimate approximately $146 million of contributions to the Pension Plan in 2016.

For the PBOP Plan, it is our policy to annually fund the PBOP Plan though tax deductible contributions to external trusts. We contributed $7.9 million to the PBOP Plan in 2015. We currently estimate approximately $9.5 million in contributions to the PBOP Plan in 2016.

Sensitivity Analysis: The following represents the hypothetical increase to the Pension Plan's (excluding the SERP Plans) and PBOP Plan's reported annual cost as a result of a change in the following assumptions by 50 basis points:


(Millions of Dollars)	Increase in Pension Plan Cost				Increase in PBOP Plan Cost
Assumption Change	As of December 31,
Eversource		2015		2014	2015		2014
Lower expected long-term rate of return	$	20.6	$	19.3	$	4.2	$	4.0


Lower discount rate		$	26.3		$	19.1		$	6.2		$	2.2


Higher compensation rate		$	12.4		$	10.2			N/A			N/A

Health Care Cost: As of December 31, 2015, the health care cost trend rate assumption used to determine the PBOP Plan's year end funded status was 6.25 percent, subsequently decreasing to an ultimate rate of 4.5 percent in 2023. The effect of a hypothetical increase in the health care cost trend rate by one percentage point would be an increase to the service and interest cost components of PBOP Plan expense by $8.5 million in 2015, and a $115.3 million increase to the PBOP obligation.

Goodwill: We have recorded approximately $3.5 billion of goodwill associated with previous mergers and acquisitions. We have identified our reporting units for purposes of allocating and testing goodwill as Electric Distribution, Electric Transmission and Natural Gas Distribution. These reporting units are consistent with our operating segments underlying our reportable segments. Electric Distribution and Electric Transmission reporting units include carrying values for the respective components of CL&P, NSTAR Electric, PSNH and WMECO. The Natural Gas Distribution reporting unit includes the carrying values of NSTAR Gas and Yankee Gas. As of December 31, 2015, goodwill was allocated to the reporting units as follows: $2.5 billion to Electric Distribution, $0.6 billion to Electric Transmission, and $0.4 billion to Natural Gas Distribution.

We are required to test goodwill balances for impairment at least annually by considering the fair values of the reporting units, which requires us to use estimates and judgments. We have selected October 1st of each year as the annual goodwill impairment testing date. Goodwill impairment is deemed to exist if the carrying value of a reporting unit exceeds its estimated fair value and if the implied fair value of goodwill based on the estimated fair values of the reporting units' assets and liabilities is less than the carrying amount of the goodwill. If goodwill were deemed to be impaired, it would be written down in the current period to the extent of the impairment.

We performed an impairment test of goodwill as of October 1, 2015 for the Electric Distribution, Electric Transmission and Natural Gas Distribution reporting units. This evaluation required the consideration of several factors that impact the fair value of the reporting units, including conditions and assumptions that affect the future cash flows of the reporting units. Key considerations include discount rates, utility sector market performance and merger transaction multiples, and internal estimates of future cash flows and net income.

The 2015 goodwill impairment test resulted in a conclusion that goodwill is not impaired and no reporting unit is at risk of a goodwill impairment.

Income Taxes: Income tax expense is estimated for each of the jurisdictions in which we operate and is recorded each quarter using an estimated annualized effective tax rate. This process to record income tax expense involves estimating current and deferred income tax expense or benefit and the impact of temporary differences resulting from differing treatment of items for financial reporting and income tax return reporting purposes. Such differences are the result of timing of the deduction for expenses, as well as any impact of permanent differences, non-tax deductible expenses, or other items that directly impact income tax expense as a result of regulatory activity (flow-through items). The temporary differences and flow-through items result in deferred tax assets and liabilities that are included in the balance sheets.

We also account for uncertainty in income taxes, which applies to all income tax positions previously filed in a tax return and income tax positions expected to be taken in a future tax return that have been reflected on our balance sheets. The determination of whether a tax position meets the recognition threshold under applicable accounting guidance is based on facts and circumstances available to us. Once a tax position meets the recognition threshold, the tax benefit is measured using a cumulative probability assessment. Assigning probabilities in measuring a recognized tax position and evaluating new information or events in subsequent periods requires significant judgment and could change previous conclusions used to measure the tax position estimate. New information or events may include tax examinations or appeals (including information gained from those examinations), developments in case law, settlements of tax positions, changes in tax law and regulations, rulings by taxing authorities and statute of limitation expirations. Such information or events may have a significant impact on our financial position, results of operations and cash flows.

Accounting for Environmental Reserves: Environmental reserves are accrued when assessments indicate it is probable that a liability has been incurred and an amount can be reasonably estimated. Adjustments made to estimates of environmental liabilities could have an adverse impact on earnings. We estimate these liabilities based on findings through various phases of the assessment, considering the most likely action plan from a variety of available remediation options (ranging from no action required to full site remediation and long-term monitoring), current site information from our site assessments, remediation estimates from third party engineering and remediation contractors, and our prior experience in remediating contaminated sites. If a most likely action plan cannot yet be determined, we estimate the liability based on the low end of a range of possible action plans. A significant portion of our environmental sites and reserve amounts relate to 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. As assessments on these sites are performed, we may receive new information to be considered in our estimates related to the extent and nature of the contamination and the costs of required remediation.

Our estimates also incorporate currently enacted state and federal environmental laws and regulations and data released by the EPA and other organizations. The estimates associated with each possible action plan are judgmental in nature partly because there are usually several different remediation options from which to choose. Our estimates are subject to revision in future periods based on actual costs or new information from other sources, including the level of contamination at the site, the extent of our responsibility or the extent of remediation required, recently enacted laws and regulations or a change in cost estimates due to certain economic factors.

Fair Value Measurements: We follow fair value measurement guidance that defines fair value as the price that would be received for the sale of an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date (an exit price). We have applied this guidance to our Company's derivative contracts that are not elected or designated as "normal purchases or normal sales" (normal), to marketable securities held in trusts, to our investments in our Pension and PBOP Plans, and to nonfinancial assets such as goodwill and AROs. This guidance was also applied in estimating the fair value of preferred stock and long-term debt.

Changes in fair value of the Regulated company derivative contracts are recorded as Regulatory Assets or Liabilities, as we recover the costs of these contracts in rates charged to customers. These valuations are sensitive to the prices of energy and energy-related products in future years for which markets have not yet developed and assumptions are made.

We use quoted market prices when available to determine the fair value of financial instruments. If quoted market prices are not available, fair value is determined using quoted prices for similar instruments in active markets, quoted prices for identical or similar instruments that are not active and model-derived valuations. When quoted prices in active markets for the same or similar instruments are not available, we value derivative contracts using models that incorporate both observable and unobservable inputs. Significant unobservable inputs utilized in the models include energy and energy-related product prices for future years for long-dated derivative contracts and market volatilities. Discounted cash flow valuations incorporate estimates of premiums or discounts, reflecting risk adjusted profit that would be required by a market participant to arrive at an exit price, using available historical market transaction information. Valuations of derivative contracts also reflect our estimates of nonperformance risk, including credit risk.

Other Matters

Accounting Standards: For information regarding new accounting standards, see Note 1C, "Summary of Significant Accounting Policies - Accounting Standards," to the financial statements.

Contractual Obligations and Commercial Commitments: Information regarding our contractual obligations and commercial commitments as of December 31, 2015 is summarized annually through 2020 and thereafter as follows:


Eversource
(Millions of Dollars)		2016		2017		2018		2019		2020		Thereafter		Total
Long-term debt maturities (a)	$	200.0	$	745.0	$	960.0	$	800.0	$	295.0	$	5,736.6	$	8,736.6
Estimated interest payments on existing debt (b)		371.2		366.6		313.1		284.2		245.8		2,849.6		4,430.5
Capital leases (c)		2.2		2.1		2.1		2.0		2.0		1.4		11.8
Operating leases (d)		16.4		13.8		10.4		8.5		6.8		15.4		71.3
Funding of pension obligations (d) (e)		146.0		167.5		114.5		70.6		20.2		-		518.8
Funding of PBOP obligations (d)		9.5		9.2		9.4		9.6		-		-		37.7
Estimated future annual long-term contractual costs (f)		684.5		590.6		442.3		376.2		344.9		2,371.7		4,810.2
Total (g)	$	1,429.8	$	1,894.8	$	1,851.8	$	1,551.1	$	914.7	$	10,974.7	$	18,616.9

CL&P
(Millions of Dollars)		2016		2017		2018		2019		2020		Thereafter		Total
Long-term debt maturities (a)	$	-	$	250.0	$	300.0	$	250.0	$	-	$	1,990.3	$	2,790.3
Estimated interest payments on existing debt (b)		140.0		136.0		117.8		102.4		95.5		1,402.7		1,994.4
Capital leases (c)		1.9		1.9		2.0		2.0		2.0		1.4		11.2
Operating leases (d)		2.9		2.0		1.3		1.0		0.7		1.7		9.6
Funding of pension obligations (d) (e)		0.4		15.5		26.3		21.1		6.1		-		69.4
Estimated future annual long-term contractual costs (f)		279.4		207.9		159.5		126.9		114.5		711.6		1,599.8
Total (g)	$	424.6	$	613.3	$	606.9	$	503.4	$	218.8	$	4,107.7	$	6,474.7

(a)

Long-term debt maturities exclude the CYAPC pre-1983 spent nuclear fuel obligation, net unamortized premiums, discounts and debt issuance costs, and other fair value adjustments.

(b)

Estimated interest payments on fixed-rate debt are calculated by multiplying the coupon rate on the debt by its scheduled notional amount outstanding for the period of measurement. Estimated interest payments on floating-rate debt are calculated by multiplying the end of 2015 floating-rate reset on the debt by its scheduled notional amount outstanding for the period of measurement. This same rate is then assumed for the remaining life of the debt.

(c)

The capital lease obligations include interest.

(d)

Amounts are not included on our balance sheets.

(e)

These amounts represent Eversource's estimated pension contributions to its qualified Pension Plan. Contributions in 2017 through 2020 and thereafter will vary depending on many factors, including the performance of existing plan assets, valuation of the plan's liabilities and long-term discount rates, and are subject to change.

(f)

Other than certain derivative contracts held by the Regulated companies, these obligations are not included on our balance sheets.

(g)

Does not include other long-term liabilities recorded on our balance sheet, such as environmental reserves, employee medical insurance, workers compensation and long-term disability insurance reserves, ARO liability reserves and other reserves, as we cannot make reasonable estimates of the timing of payments. Also does not include amounts not included on our balance sheets for future funding of the Access Northeast project or for a contingent commitment of approximately $20 million to an energy investment fund, which would be invested under certain conditions, as we cannot make reasonable estimates of the periods or the investment contributions.

For further information regarding our contractual obligations and commercial commitments, see Note 6, "Asset Retirement Obligations," Note 7, "Short-Term Debt," Note 8, "Long-Term Debt," Note 9A, "Employee Benefits - Pension Benefits and Postretirement Benefits Other Than Pensions," Note 11, "Commitments and Contingencies," and Note 12, "Leases," to the financial statements.

RESULTS OF OPERATIONS – EVERSOURCE ENERGY AND SUBSIDIARIES

The following provides the amounts and variances in operating revenues and expense line items in the statements of income for Eversource for the years ended December 31, 2015, 2014, and 2013 included in this Annual Report on Form 10-K.

Comparison of 2015 to 2014:


			For the Years Ended December 31,
								Increase/
(Millions of Dollars)			2015		2014		(Decrease)	Percent
Operating Revenues			$	7,954.8		$	7,741.9	$	212.9	2.7	%
Operating Expenses:
	Purchased Power, Fuel and Transmission			3,086.9			3,021.6		65.3	2.2
	Operations and Maintenance			1,329.3			1,427.6		(98.3)	(6.9)
	Depreciation			665.9			614.7		51.2	8.3
	Amortization of Regulatory Assets, Net			22.3			10.7		11.6	(a)
	Energy Efficiency Programs			495.7			473.1		22.6	4.8
	Taxes Other Than Income Taxes			590.5			561.4		29.1	5.2
		Total Operating Expenses		6,190.6			6,109.1		81.5	1.3
Operating Income				1,764.2			1,632.8		131.4	8.0
Interest Expense				372.4			362.1		10.3	2.8
Other Income, Net				34.2			24.6		9.6	39.0
Income Before Income Tax Expense				1,426.0			1,295.3		130.7	10.1
Income Tax Expense				540.0			468.3		71.7	15.3
Net Income				886.0			827.0		59.0	7.1
Net Income Attributable to Noncontrolling Interests				7.5			7.5		-	-
Net Income Attributable to Common Shareholders			$	878.5		$	819.5	$	59.0	7.2	%

(a) Percent greater than 100 percent not shown as it is not meaningful.

Operating Revenues
			For the Years Ended December 31,
								Increase /
(Millions of Dollars)			2015		2014		(Decrease)	Percent
Electric Distribution			$	5,903.6		$	5,663.4	$	240.2	4.2	%
Natural Gas Distribution				995.5			1,007.3		(11.8)	(1.2)
Electric Transmission				1,069.1			1,018.2		50.9	5.0
Other and Eliminations				(13.4)			53.0		(66.4)	(a)
Total Operating Revenues			$	7,954.8		$	7,741.9	$	212.9	2.7	%

(a) Percent greater than 100 percent not shown as it is not meaningful.

A summary of our retail electric sales volumes and firm natural gas sales volumes were as follows:

			For the Years Ended December 31,
								Increase/
			2015		2014		(Decrease)	Percent
Electric Sales Volumes in GWh:
	Traditional			28,982			28,811		171	0.6	%
	Decoupled			25,634			25,631		3	-
Total Electric Sales Volumes in GWh				54,616			54,442		174	0.3	%

Firm Natural Gas Sales Volumes in Million Cubic Feet				102,999			104,191		(1,192)	(1.1)	%

Operating Revenues, which primarily consist of base electric and natural gas distribution revenues and tracked revenues further described below, increased by $212.9 million in the aggregate in 2015 compared to 2014.

Base electric and natural gas distribution revenues: Base electric distribution segment revenues increased $150.9 million due primarily to CL&P’s base distribution rate increase, effective December 1, 2014 ($136.3 million) and higher retail sales volumes driven by weather impacts at our non-decoupled operating companies (traditional). In addition, Operating Revenues increased $19.9 million at CL&P due to the PURA-approved settlement agreement regarding ADIT, $11 million for the Comprehensive Settlement Agreement associated with the recovery of LBR related to 2009 through 2011 energy efficiency programs at NSTAR Electric, and $20.7 million increase of 2015 LBR recognition at NSTAR Electric compared to 2014 LBR amounts. The $19.9 million represents CL&P's revenue requirement from the settlement agreement's rate increase through December 31, 2015, and is being collected from customers in rates over a 24-month period beginning December 1, 2015. The impact of colder winter weather experienced in the first quarter of 2015 and warmer weather in the third quarter of 2015, partially offset by milder winter weather in the fourth quarter of 2015, all as compared to the same periods in 2014, were the primary drivers of the increase in 2015 retail electric sales volumes of 0.6 percent and base electric distribution revenues at NSTAR Electric and PSNH.

For CL&P (effective December 1, 2014) and WMECO, fluctuations in retail electric sales volumes do not impact earnings due to their respective regulatory commission approved revenue decoupling mechanisms. The revenue decoupling mechanisms permit recovery of a base amount of distribution revenues and break the relationship between sales volumes and revenues recognized. Revenue decoupling mechanisms result in the

recovery of our approved base distribution revenue requirements. Therefore, changes in sales volumes had no impact on the level of base distribution revenue realized at our decoupled companies.

Firm natural gas base distribution segment revenues decreased $4.9 million due primarily to a 1.1 percent decrease in firm natural gas sales volumes in 2015, as compared to 2014. This was due to record warm weather in the fourth quarter of 2015 when compared to 2014, partially offset by colder winter weather in the first quarter of 2015 compared to 2014. Weather-normalized firm natural gas sales volumes (based on 30-year average temperatures) increased 2.5 percent in 2015 compared to 2014, due primarily to improved economic conditions as well as residential and commercial customer growth, partially offset by the impact of customer conservation efforts resulting from company-sponsored energy efficiency programs.

Tracked distribution revenues: Tracked revenues consist of certain costs that are recovered from customers in rates through regulatory commission-approved cost tracking mechanisms and therefore have no impact on earnings. Costs recovered through cost tracking mechanisms include energy supply procurement costs and other energy-related costs for our electric and natural gas customers, retail transmission charges, energy efficiency program costs, and restructuring and stranded cost recovery revenues. Tracked electric distribution segment revenues increased primarily as a result of increases in energy supply costs ($176.4 million), driven by increased average retail rates, and increases in energy efficiency program revenues ($18.3 million). These increases were partially offset by a decrease in retail electric transmission charges ($77.5 million) and a decrease in the federally mandated congestion charge primarily driven by refunds in 2015 for a prior year overrecovery ($103.9 million). Tracked natural gas supply revenues decreased $20.1 million as a result of a decrease in average rates related to the recovery of natural gas supply costs.

Electric transmission revenues: The electric transmission segment revenues increased by $50.9 million due primarily to the result of lower reserves associated with the FERC ROE complaint proceedings in 2015 compared to 2014 and higher revenue requirements associated with ongoing investments in our transmission infrastructure.

Other: Other revenues decreased due primarily to the sale of Eversource's unregulated contracting business on April 13, 2015 ($55 million).

Purchased Power, Fuel and Transmission expense includes costs associated with purchasing electricity and natural gas on behalf of our customers. These energy supply costs are recovered from customers in rates through reconciling cost tracking mechanisms, which have no impact on earnings (tracked costs). Purchased Power, Fuel and Transmission increased in 2015, as compared to 2014, due primarily to the following:


(Millions of Dollars)	Increase/(Decrease)
Electric Distribution	$	74.8
Natural Gas Distribution		(1.6)
Electric Transmission		2.8
Other and Eliminations		(10.7)
Total Purchased Power, Fuel and Transmission	$	65.3

The increase in purchased power costs at the electric distribution business was driven by higher prices associated with the procurement of energy supply in 2015, as compared to 2014. The decrease in purchased power costs at the natural gas distribution business was due to lower average natural gas prices in 2015, as compared to 2014.

Operations and Maintenance expense includes tracked costs and costs that are part of base electric and natural gas distribution rates with changes impacting earnings (non-tracked costs). Operations and Maintenance decreased in 2015, as compared to 2014, due primarily to the following:



(Millions of Dollars)	Increase/(Decrease)
Base Electric Distribution:
Resolution of basic service bad debt adder mechanism at NSTAR Electric	$	(24.2)
Contribution to create clean energy fund in connection with the generation divestiture agreement at PSNH		5.0
Increase in employee-related expenses, including labor and benefits		1.8
Other operations and maintenance		7.0
Total Base Electric Distribution		(10.4)
Total Base Natural Gas Distribution		(1.5)
Total Tracked costs (Transmission and Electric and Natural Gas Distribution)		(9.3)
Total Distribution and Transmission		(21.2)
Other and eliminations:
Integration costs		(8.4)
Absence of Eversource's unregulated electrical contracting business due to sale in April 2015, net		(45.7)
Merger-related costs allowed for recovery		(7.0)
ES Parent and Other Companies		(16.0)
Total Operations and Maintenance	$	(98.3)

Depreciation increased in 2015, as compared to 2014, due primarily to higher utility plant in service balances resulting from completed construction projects placed into service and an increase in depreciation rates at CL&P as a result of the distribution rate case effective December 1, 2014.

Amortization of Regulatory Assets, Net, which 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 2015, as compared to 2014, due primarily to the following:


(Millions of Dollars)	Increase/(Decrease)
CL&P:
Amortization increase (including storm cost recovery) approved and included in base distribution rates	$	61.0
Energy and energy-related supply costs tracking mechanism		(108.0)
NSTAR Electric (primarily the recognition of the Comprehensive Settlement Agreement, partially offset by transition costs tracking mechanism)		(6.7)
PSNH (primarily default energy service charge tracking mechanism)		45.9
WMECO (primarily the absence of the refund of DOE proceeds to customers in 2014 and energy and energy-related cost tracking mechanisms)		20.7
Other		(1.3)
Total Amortization of Regulatory Assets, Net	$	11.6

The increase in CL&P's amortization was due primarily to an increase in storm cost recovery, which was approved and included in distribution rates effective December 1, 2014. In connection with the Comprehensive Settlement Agreement associated with the CPSL program filings, NSTAR Electric recognized an $11.7 million benefit in the first quarter of 2015, which was recorded as a reduction to amortization expense.

The remaining fluctuations in amortization expense are driven by the deferral of energy supply and energy-related costs, which can fluctuate from period to period based on the timing of costs incurred and related rate changes to recover these costs. Fluctuations in energy supply and energy-related costs, which are the primary drivers in amortization, are recovered from customers in rates and have no impact on earnings.

Energy Efficiency Programs, which are tracked costs, increased in 2015, as compared to 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.

Taxes Other Than Income Taxes increased in 2015, as compared to 2014, due primarily to an increase in property taxes as a result of both an increase in utility plant balances and property tax rates.

Interest Expense increased in 2015, as compared to 2014, due primarily to an increase in interest on long-term debt ($9.3 million) as a result of new debt issuances in 2015 and an increase in interest on notes payable ($1.9 million).

Other Income, Net increased in 2015, as compared to 2014, due primarily to higher equity AFUDC amounts ($5.1 million) and an increase in interest income related to the deferred compensation plans ($4.3 million), partially offset by the absence in 2015 of a gain on the sale of land recorded in 2014 at CL&P ($4.5 million).

Income Tax Expense increased in 2015, as compared to 2014, due primarily to higher pre-tax earnings ($45.7 million), higher state taxes, the impact of adjusting our estimated tax expense to what was filed on our tax return (provision to return), the lower tax benefit in 2015 compared to 2014 from a change in tax reserves ($19.8 million), and higher items that impact our tax rate as a result of regulatory treatment (flow-through items) ($6.2 million).

Comparison of 2014 to 2013:


			For the Years Ended December 31,
								Increase/
(Millions of Dollars)			2014		2013		(Decrease)	Percent
Operating Revenues			$	7,741.9		$	7,301.2	$	440.7	6.0	%
Operating Expenses:
	Purchased Power, Fuel and Transmission			3,021.6			2,483.0		538.6	21.7
	Operations and Maintenance			1,427.6			1,515.0		(87.4)	(5.8)
	Depreciation			614.7			610.8		3.9	0.6
	Amortization of Regulatory Assets, Net			10.7			206.3		(195.6)	(94.8)
	Amortization of Rate Reduction Bonds			-			42.6		(42.6)	(100.0)
	Energy Efficiency Programs			473.1			401.9		71.2	17.7
	Taxes Other Than Income Taxes			561.4			512.2		49.2	9.6
		Total Operating Expenses		6,109.1			5,771.8		337.3	5.8
Operating Income				1,632.8			1,529.4		103.4	6.8
Interest Expense				362.1			338.7		23.4	6.9
Other Income, Net				24.6			29.9		(5.3)	(17.7)
Income Before Income Tax Expense				1,295.3			1,220.6		74.7	6.1
Income Tax Expense				468.3			426.9		41.4	9.7
Net Income				827.0			793.7		33.3	4.2
Net Income Attributable to Noncontrolling Interests				7.5			7.7		(0.2)	(2.6)
Net Income Attributable to Controlling Interest			$	819.5		$	786.0	$	33.5	4.3	%

Operating Revenues
			For the Years Ended December 31,
								Increase /
(Millions of Dollars)			2014		2013		(Decrease)	Percent
Electric Distribution			$	5,663.4		$	5,362.3	$	301.1	5.6	%
Natural Gas Distribution				1,007.3			855.8		151.5	17.7
Transmission				1,018.2			978.7		39.5	4.0
Other and Eliminations				53.0			104.4		(51.4)	(49.2)
Total Operating Revenues			$	7,741.9		$	7,301.2	$	440.7	6.0	%

A summary of our retail electric sales volumes and firm natural gas sales volumes were as follows:

			For the Years Ended December 31,
								Increase/
			2014		2013		(Decrease)	Percent
Retail Electric Sales Volumes in GWh				54,442			55,331		(889)	(1.6)	%
Firm Natural Gas Sales Volumes in Million Cubic Feet				104,191			98,258		5,933	6.0

Operating Revenues increased $440.7 million in 2014 compared to 2013.

The most significant factor in the increase in revenues relates to cost tracking mechanisms for the recovery of higher costs associated with the procurement of energy supply, which increased $506.8 million and $126.9 million for electric distribution and natural gas distribution, respectively. These costs were impacted by the overall New England wholesale energy supply market in which higher natural gas delivery costs had an adverse impact on the cost of electric energy purchased for our retail electric customers and the cost of natural gas purchased on behalf of our retail natural gas customers. Energy supply costs are recovered from customers in rates through cost tracking mechanisms and therefore have no impact on earnings. These costs and related recovery impacts were partially offset by decreases in transition cost recovery revenues, which are recovered through cost tracking mechanisms, reflecting the full collection in 2013 of previously deferred costs, as well as the full amortization of RRBs.

Firm base natural gas distribution revenues increased $26.3 million in 2014, as compared to 2013, which reflected a 6 percent increase in firm natural gas sales volumes. The increase in sales volumes was driven primarily by the colder winter weather experienced throughout our service territories in the first quarter of 2014. The weather conditions experienced were significantly colder than both normal and the same period last year throughout New England and our service territories in Connecticut and Massachusetts. Weather-normalized total firm natural gas sales volumes (based on 30-year average temperatures) increased 2.9 percent in 2014, as compared to 2013, due primarily to residential and commercial customer growth.

Base electric distribution revenues decreased $12.1 million in 2014 compared to 2013. This reflected the impact of a 1.6 percent decrease in retail electric sales volumes. The decrease in sales volumes was driven primarily by the cooler summer weather in 2014 compared to 2013, as well as the impact of our utility-sponsored energy efficiency programs. Weather-normalized retail electric sales volumes decreased 1 percent in 2014, as compared to 2013, reflecting the impact of our utility-sponsored energy efficiency programs. The negative sales volume impact was partially offset by the impact of CL&P's base distribution rate increase effective December 1, 2014.

CL&P and NSTAR Electric recognized lost base revenue (LBR) related to reductions in sales volume as a result of energy efficiency. LBR is recovered from retail distribution customers. Including the impact from the recognition of LBR, base distribution revenues increased in 2014, as compared to 2013. We recognized $45.2 million of LBR in 2014, compared to $20.3 million in 2013. Effective December 1, 2014, CL&P no longer recognizes LBR due to its revenue decoupling mechanism, which, similar to WMECO's revenue decoupling mechanism, provides a base amount of distribution revenues ($1.059 billion on an annual basis) that effectively breaks the relationship between revenues and customer electricity usage. The revenue decoupling mechanism is designed to allow each of CL&P and WMECO to encourage energy efficiency for its customers without negatively impacting its revenues.

Transmission revenues increased $39.5 million in 2014, as compared to 2013, due primarily to the recovery of higher revenue requirements associated with ongoing investments in our transmission infrastructure. This increase was partially offset by the impact of the $37 million net reserve recorded in 2014 as a result of the 2014 FERC ROE orders, compared to the $23.7 million reserve recorded in 2013 for the FERC ALJ initial decision in the FERC base ROE complaints.

Purchased Power, Fuel and Transmission expense includes costs associated with purchasing electricity and natural gas on behalf of our customers. These energy supply costs are recovered from customers in rates through reconciling cost tracking mechanisms, which have no impact on earnings (tracked costs). Purchased Power, Fuel and Transmission increased in 2014, as compared to 2013, due primarily to the following:


(Millions of Dollars)	Increase/(Decrease)
Electric Distribution	$	458.2
Natural Gas Distribution		104.1
Transmission		(2.8)
Other and Eliminations		(20.9)
Total Purchased Power, Fuel and Transmission	$	538.6

The increase in purchased power, fuel and transmission at the electric and natural gas distribution businesses were driven by the higher costs associated with the procurement of energy supply. As a result of increases in the New England wholesale energy supply market for both electricity and natural gas, the costs incurred to purchase energy on behalf of our customers were significantly higher in 2014 compared to 2013. Our energy supply costs were impacted by higher natural gas delivery costs, which had an adverse impact on the cost of electric energy purchased for our retail electric customers and the cost of natural gas purchased on behalf of our retail natural gas customers.

Operations and Maintenance expense includes tracked costs and costs that are recovered through base electric and natural gas distribution rates, which therefore impact earnings (non-tracked costs). Operations and Maintenance decreased in 2014, as compared to 2013, due primarily to the following:


(Millions of Dollars)	Increase/(Decrease)
Base Electric Distribution:
Labor and other employee-related costs, including pension costs	$	(77.3)
Implementation of a new outage restoration program at CL&P		9.2
Storm restoration costs		(11.4)
All other operations and maintenance		(29.4)
Total Base Electric Distribution		(108.9)
Total Base Natural Gas Distribution		(0.9)
Total Tracked costs (Transmission and Electric and Natural Gas Distribution)		16.6
Total Distribution and Transmission		(93.2)
Other and eliminations:
Integration and severance costs		13.3
All other (including eliminations)		(7.5)
Total Operations and Maintenance	$	(87.4)

Depreciation increased in 2014, as compared to 2013, due primarily to an increase related to higher utility plant balances resulting from completed construction projects placed into service ($34.5 million), partially offset by a decrease in the CYAPC and YAEC decommissioning costs, which do not impact earnings ($30.6 million).

Amortization of Regulatory Assets, Net, which 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, decreased in 2014, as compared to 2013, due primarily to the following:


(Millions of Dollars)	Increase/(Decrease)
NSTAR Electric (primarily recovery of transition costs)	$	(236.4)
PSNH (primarily default energy service charge)		(9.2)
CL&P (primarily energy supply and energy-related costs)		54.4
WMECO (primarily recovery of transition costs)		(3.0)
Other		(1.4)
Total Amortization of Regulatory Assets, Net	$	(195.6)

Amortization of Rate Reduction Bonds decreased in 2014, as compared to 2013, due to the maturity in 2013 of RRBs of NSTAR Electric, PSNH and WMECO.

Energy Efficiency Programs, which are tracked costs, increased in 2014, as compared to 2013, due primarily to the expanded energy conservation programs at CL&P in 2014 as a result of 2013 legislative action, and an increase in energy efficiency costs in accordance with the three-year program guidelines established by the DPU at NSTAR Electric and WMECO, partially offset by a decrease in the amortization of previously deferred costs at NSTAR Electric.

Taxes Other Than Income Taxes increased in 2014, as compared to 2013, due primarily to an increase in property taxes as a result of both an increase in utility plant balances and property tax rates.

Interest Expense increased in 2014, as compared to 2013, due primarily to lower interest income related to a decrease in the recovery of previously deferred transition costs ($9.9 million), an increase in interest on long-term debt ($4 million) as a result of new debt issuances in 2014 and the absence in 2014 of the favorable impact from the resolution of a Connecticut state income tax audit in 2013.

Other Income, Net decreased in 2014, as compared to 2013, due primarily to lower unrealized gains on the assets supporting the deferred compensation plans ($13 million), and the absence in 2014 of an insurance policy claim received in 2013 ($1.5 million), partially offset by higher AFUDC related to equity funds ($6.6 million), and a net gain on the sale of land ($4.5 million).

Income Tax Expense increased in 2014, as compared to 2013, due primarily to higher pre-tax earnings ($26.1 million), and higher state taxes and various other impacts ($15.3 million). The higher state taxes include a net reduction in the valuation allowance for state tax positions, which is based on the most recent available data.

EARNINGS SUMMARY

Excluding the impact of integration costs, our 2014 earnings increased by $41.8 million, as compared to 2013. The increase was due primarily to lower operations and maintenance costs that impact earnings, which were primarily driven by lower labor and other employee-related costs, including approximately $30 million of non-tracked pension costs, and lower storm restoration costs, as well as higher firm natural gas sales volumes as a result of the colder weather in the first quarter of 2014, as compared to the first quarter of 2013. Partially offsetting this increase was the absence in 2014 of a favorable impact from the resolution of a state income tax audit in 2013, higher property taxes, higher depreciation expense at our regulated companies, and lower retail electric sales volumes as a result of cooler summer weather in 2014, as compared to the same period in 2013. Earnings were also unfavorably impacted by the 2014 after-tax net reserve of $22.4 million related to the 2014 FERC ROE orders, as compared to the 2013 after-tax reserve of $14.3 million related to the 2013 FERC ALJ initial decision in the FERC base ROE complaints.

Our electric distribution segment earnings increased $35.4 million in 2014, as compared to 2013, due primarily to lower operations and maintenance costs that impact earnings, which were primarily driven by lower labor and other employee-related costs, including pension costs, and lower storm restoration costs. Partially offsetting these favorable earnings impacts, as compared to 2013, were higher property taxes and depreciation expense, lower retail electric sales volumes as a result of cooler summer weather in 2014, and the absence in 2014 of regulatory interest income on stranded cost deferrals in 2013.

Our transmission segment earnings increased $8.4 million in 2014, as compared to 2013, due primarily to a decrease in transmission segment state income tax expense and a higher transmission rate base as a result of an increased investment in our transmission infrastructure. These favorable impacts were partially offset by the after-tax net reserve of $22.4 million related to the 2014 FERC ROE orders, as compared to the $14.3 million after-tax reserve related to the 2013 FERC ALJ initial decision in the FERC base ROE complaints.

Our natural gas distribution segment earnings increased $11.4 million in 2014, as compared to 2013, due primarily to higher firm natural gas sales volumes and peak demand revenues resulting from colder weather in the first quarter of 2014 and additional natural gas heating customers.

ES parent and other companies, which include our unregulated businesses, had a net loss of $10.6 million in 2014, compared with earnings of $11.1 million in 2013. Excluding the impact of integration costs, ES parent and other companies earned $11.5 million in 2014, compared with $24.9 million in 2013. The earnings decrease in 2014 was due primarily to a higher effective tax rate.

LIQUIDITY

Cash flows provided by operating activities totaled $1.64 billion in 2014, compared with $1.66 billion in 2013. The 2014 operating cash flows were favorably impacted by approximately $132 million in DOE Damages proceeds resulting from the spent nuclear fuel litigation received by CL&P, NSTAR Electric, PSNH and WMECO from the Yankee Companies, the absence of 2013 cash disbursements for major storm restoration costs, the decrease of approximately $130 million in Pension and PBOP Plan cash contributions and changes in the timing of working capital items. These favorable impacts were more than offset by higher income tax payments in 2014 and the unfavorable cash flow impact resulting from lower recoveries from customers in 2014, as compared to 2013, relating to regulatory cost recovery tracking mechanisms. For further information on the spent nuclear fuel litigation, see Note 11C, "Commitments and Contingencies – Contractual Obligations – Yankee Companies," in this combined Annual Report on Form 10-K.

RESULTS OF OPERATIONS – THE CONNECTICUT LIGHT AND POWER COMPANY

The following provides the amounts and variances in operating revenues and expense line items in the statements of income for CL&P for the years ended December 31, 2015, 2014, and 2013 included in this Annual Report on Form 10-K:

Comparison of 2015 to 2014:


			For the Years Ended December 31,
								Increase/
(Millions of Dollars)			2015		2014		(Decrease)	Percent
Operating Revenues			$	2,802.7		$	2,692.6	$	110.1	4.1	%
Operating Expenses:
	Purchased Power and Transmission			1,054.3			982.9		71.4	7.3
	Operations and Maintenance			487.3			494.6		(7.3)	(1.5)
	Depreciation			215.3			188.8		26.5	14.0
	Amortization of Regulatory Assets, Net			12.3			59.3		(47.0)	(79.3)
	Energy Efficiency Programs			153.7			156.3		(2.6)	(1.7)
	Taxes Other Than Income Taxes			268.7			255.4		13.3	5.2
		Total Operating Expenses		2,191.6			2,137.3		54.3	2.5
Operating Income				611.1			555.3		55.8	10.0
Interest Expense				145.8			147.4		(1.6)	(1.1)
Other Income, Net				11.5			13.4		(1.9)	(14.2)
Income Before Income Tax Expense				476.8			421.3		55.5	13.2
Income Tax Expense				177.4			133.5		43.9	32.9
Net Income			$	299.4		$	287.8	$	11.6	4.0	%

Operating Revenues
CL&P's retail sales volumes were as follows:
			For the Years Ended December 31,
			2015			2014		Increase		Percent
Retail Sales Volumes in GWh				22,071			22,046		25	0.1	%

Operating Revenues

CL&P's Operating Revenues, which consist of base distribution revenues and tracked revenues further described below, increased by $110.1 million in the aggregate in 2015 compared to 2014.

Base distribution revenues: Base distribution revenues increased $136.3 million due to a base distribution rate increase effective December 1, 2014. In addition, CL&P recognized $19.9 million in Operating Revenues due to the PURA-approved settlement agreement regarding ADIT. The $19.9 million represents the revenue requirement from the settlement agreement's rate increase through December 31, 2015, and is being collected from customers in rates over a 24-month period beginning December 1, 2015.

Effective December 1, 2014, CL&P’s distribution revenues were decoupled from its sales volumes. As a result, CL&P no longer earns LBR related to its energy efficiency programs. The revenue decoupling mechanism permits recovery of a base amount of distribution revenues ($1.059 billion annually effective December 1, 2014) and breaks the relationship between sales volumes and revenues recognized. Revenue decoupling mechanisms result in the recovery of our approved base distribution revenue requirements. Therefore, changes in sales volumes had no impact on the level of base distribution revenue realized in 2015 and prospectively.

Tracked revenues: Tracked revenues consist of certain costs that are recovered from customers in rates through PURA-approved cost tracking mechanisms and therefore have no impact on earnings. Costs recovered through cost tracking mechanisms include energy supply procurement and other energy-related costs, retail transmission charges, energy efficiency program costs and restructuring and stranded cost recovery revenues. Tracked distribution revenues decreased primarily as a result of a decrease in the federally mandated congestion charge primarily driven by refunds in 2015 for a prior year overrecovery ($103.9 million) and a decrease in competitive transition assessment charges ($17 million), partially offset by an increase in energy supply costs ($51.1 million) driven by increased average retail rates, and an increase in retail transmission charges ($22.7 million).

Transmission revenues increased $5.8 million due primarily to the result of lower reserves associated with the FERC ROE complaint proceedings recorded in 2015 as compared to 2014, and 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 CL&P's customers. These energy supply costs are recovered from customers in PURA-approved cost tracking mechanisms, which have no impact on earnings (tracked costs). Purchased Power and Transmission increased in 2015, as compared to 2014, due primarily to the following:


(Millions of Dollars)	Increase/(Decrease)
Purchased Power Costs	$	54.6
Transmission Costs		17.8
Other		(1.0)
Total Purchased Power and Transmission	$	71.4

suppliers. The increase in purchased power was due primarily to higher prices associated with the procurement of energy supply related to standard offer from third party suppliers. The increase in transmission costs was primarily the result of higher Local Network Service (LNS) expenses, which are included in the retail transmission cost deferral.

Depreciation increased in 2015, as compared to 2014, due primarily to an increase in depreciation rates as a result of the distribution rate case decision that was effective December 1, 2014 and higher utility plant in service balances.

Amortization of Regulatory Assets, Net decreased in 2015, as compared to 2014, due primarily to a decrease in the deferral of energy supply and energy-related costs that can fluctuate from period to period based on the timing of costs incurred and related rate changes to recover these costs ($108 million decrease in 2015 compared to 2014), partially offset by an increase in storm cost recovery and other cost recovery approved and included in distribution rates effective December 1, 2014 ($61 million increase in 2015 compared to 2014). Fluctuations in energy supply and energy-related costs, which are the primary drivers in amortization, are recovered from customers in rates and have no impact on earnings.

Energy Efficiency Programs, which are tracked costs, decreased in 2015, as compared to 2014, due primarily to a decrease in the deferral, which reflects the actual costs of energy efficiency programs compared to estimated amounts billed to customers. CL&P is allowed to recover its costs for various state energy policy initiatives and expanded energy efficiency programs.

Other Income, Net decreased in 2015, as compared to 2014, due primarily to the absence in 2015 of a gain on the sale of land recorded in 2014 ($4.5 million), partially offset by higher equity AFUDC amounts ($2.3 million).

Income Tax Expense increased in 2015, as compared to 2014, due primarily to higher pre-tax earnings ($19.4 million), higher state income taxes, the impact of adjusting estimated tax expense to what was filed on our tax return (provision to return), the lower tax benefit in 2015 compared to 2014 from a change in tax reserves ($17.3 million), and higher items that impact our tax rate as a result of regulatory treatment (flow-through items) ($7.2 million).

EARNINGS SUMMARY

CL&P's earnings increased $11.6 million in 2015, as compared to 2014, driven by higher distribution revenues due primarily to the impact of the December 1, 2014 base distribution rate increase and the PURA-approved settlement agreement. In addition, earnings increased due to lower operations and maintenance costs, which were primarily attributable to lower employee-related expenses, and lower reserves associated with the FERC ROE complaint proceedings recorded in 2015 compared to 2014. These favorable earnings impacts were partially offset by higher income tax expense as a result of lower tax benefits available for utilization in 2015, higher property taxes and the absence of a gain on the sale of land recorded in 2014.

LIQUIDITY

In 2015, CL&P had cash flows provided by operating activities of $298.3 million, compared with $612.4 million in 2014. The decrease in operating cash flows was due primarily to the approximate $245 million in payments made to fully satisfy the pre-1983 spent nuclear fuel obligation with the DOE. Also contributing to the decrease in operating cash flows were DOE Damages proceeds received from the Yankee Companies of $2.3 million in 2015, compared to $68.6 million in 2014.

In late 2015, CL&P made a payment of $244.6 million to fully satisfy its obligation with the DOE, which was classified as long-term debt on the balance sheet as of December 31, 2014, for costs associated with the disposal of spent nuclear fuel and high-level radioactive waste for all periods prior to 1983 from its previous ownership interest in the Millstone nuclear power station. CL&P divested its ownership interest in Millstone in 2001. This payment included accumulated interest of $178 million. CL&P funded its payment with the issuance of debt.

On December 18, 2015, the "Protecting Americans from Tax Hikes" Act became law, which extended the accelerated deduction of depreciation to businesses from 2015 through 2019. This extended stimulus provides CL&P with cash flow benefits in 2016 of approximately $105 million due to a refund of taxes paid in 2015 and lower expected tax payments in 2016.

Investments in Property, Plant and Equipment on the statements of cash flows do not include amounts incurred on capital projects but not yet paid, cost of removal, AFUDC related to equity funds, and the capitalized portions of pension expense. CL&P's investments totaled $523.8 million in 2015, compared with $515.7 million in 2014.

On October 26, 2015, ES parent and certain of its subsidiaries, including CL&P, amended and restated their joint $1.45 billion revolving credit facility and the termination date was extended to September 4, 2020. The revolving credit facility serves to backstop ES parent's $1.45 billion commercial paper program. The commercial paper program allows ES parent to issue commercial paper as a form of short-term debt with

intercompany loans to certain subsidiaries, including CL&P. As of December 31, 2015 and 2014, there were intercompany loans from ES parent of $277.4 million and $133.4 million, respectively, to CL&P.

On May 20, 2015 and December 1, 2015, CL&P issued $300 million and $50 million, respectively, of 4.15 percent 2015 Series A First and Refunding Mortgage Bonds due to mature in 2045. The proceeds, net of issuance costs, were used to repay short-term borrowings.

On April 1, 2015, CL&P repaid at maturity the $100 million 5.00 percent 2005 Series A First and Refunding Mortgage Bonds using short-term borrowings and also redeemed the $62 million 1996A Series 1.55 percent PCRBs that were subject to mandatory tender, using short term borrowings.

Financing activities in 2015 included $196 million in common stock dividends paid to ES parent.

Comparison of 2014 to 2013:


			For the Years Ended December 31,
								Increase/
(Millions of Dollars)			2014		2013		(Decrease)		Percent
Operating Revenues			$	2,692.6		$	2,442.3	$		250.3	10.2	%
Operating Expenses:
	Purchased Power and Transmission			982.9			872.8			110.1	12.6
	Operations and Maintenance			494.6			523.2			(28.6)	(5.5)
	Depreciation			188.8			177.6			11.2	6.3
	Amortization of Regulatory Assets, Net			59.3			4.9			54.4	(a)
	Energy Efficiency Programs			156.3			89.8			66.5	74.1
	Taxes Other Than Income Taxes			255.4			234.4			21.0	9.0
		Total Operating Expenses		2,137.3			1,902.7			234.6	12.3
Operating Income				555.3			539.6			15.7	2.9
Interest Expense				147.4			133.6			13.8	10.3
Other Income, Net				13.4			15.1			(1.7)	(11.3)
Income Before Income Tax Expense				421.3			421.1			0.2	-
Income Tax Expense				133.5			141.7			(8.2)	(5.8)
Net Income			$	287.8		$	279.4	$		8.4	3.0	%

(a) Percent greater than 100 percent not shown as it is not meaningful.

Operating Revenues
CL&P's retail sales volumes were as follows:

			For the Years Ended December 31,
			2014			2013		Decrease			Percent
Retail Sales Volumes in GWh				22,046			22,404		(358)		(1.6)	%

CL&P's Operating Revenues increased $250.3 million in 2014 compared to 2013. The increase primarily reflects recovery of higher costs associated with the procurement of energy supply, which increased $275.4 million, and increased cost recovery related to our energy efficiency programs. The energy supply costs were impacted by the overall wholesale electricity market in New England in which higher natural gas delivery costs had an adverse impact on 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 this increase was the impact of the $20.7 million net reserve recorded in 2014 as a result of the 2014 FERC ROE orders, as compared to the $12.8 million reserve recorded in 2013 for the FERC ALJ initial decision in the FERC base ROE complaints.

Base distribution revenues increased $9.1 million in 2014 compared to 2013, which was primarily attributable to the impact of the December 1, 2014 base distribution rate increase and the impact of LBR, partially offset by the impact of cooler summer weather as well as energy efficiency programs. Enhancements to CL&P's energy efficiency programs were mandated by the Connecticut legislature in 2013. Through November 30, 2014, CL&P was permitted to bill customers for LBR related to reductions in sales volume as a result of energy efficiency, and effective December 1, 2014, fluctuations in retail electric sales volumes do not impact earnings due to the PURA-approved revenue decoupling mechanism as a result of CL&P's base distribution rate case. The revenue decoupling mechanism provides a base amount of distribution revenues ($1.059 billion on an annual basis) that effectively breaks the relationship between revenues and customer electricity usage. The revenue decoupling mechanism is designed to allow CL&P to encourage energy efficiency for its customers without negatively impacting its revenues.

Purchased Power and Transmission expense includes costs associated with purchasing electricity on behalf of CL&P's customers. These energy supply costs are recovered from customers in PURA-approved cost tracking mechanisms, which have no impact on earnings (tracked costs). Purchased Power and Transmission increased in 2014, as compared to 2013, due primarily to the following:


(Millions of Dollars)	Increase/(Decrease)
Purchased Power Costs	$	169.7
Transmission Costs		(50.8)
Other		(8.8)
Total Purchased Power and Transmission	$	110.1

Included in purchased power are the costs associated with CL&P's generation services charge (GSC) and deferred energy supply costs. The GSC 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 purchased power was due primarily to higher average supply prices and increased standard offer load as a result of customers returning from third party suppliers. The decrease in transmission costs was the result of a decrease in the retail transmission cost deferral, which reflects the actual costs of transmission service compared to estimated amounts billed to customers.

Operations and Maintenance expense includes tracked costs and costs that are part of base distribution rates with changes impacting earnings (non-tracked costs). Operations and Maintenance decreased in 2014, as compared to 2013, driven by a $38.4 million reduction in non-tracked costs, which was primarily attributable to lower labor and other employee-related costs, including pension costs, and lower storm restoration costs, partially offset by an increase in costs for the implementation of a new outage restoration program that began in the second quarter of 2014. Partially offsetting this decrease was a $9.8 million increase in tracked costs, which have no earnings impact, that was primarily attributable to higher tracked bad debt expense and increased transmission maintenance expenses.

Depreciation increased in 2014, as compared to 2013, due primarily to higher utility plant balances resulting from completed construction projects placed into service.

Amortization of Regulatory Assets, Net increased in 2014, as compared to 2013. Fluctuations in energy supply and energy-related costs, which are the primary drivers in amortization, are recovered from customers in rates through cost tracking mechanisms and have no impact on earnings.

Energy Efficiency Programs, which are tracked costs, increased in 2014, as compared to 2013, due primarily to expanded energy conservation programs in 2014 as a result of 2013 legislative action. In 2013, Connecticut enacted into law Public Act 13-298, which implemented a number of recommendations, including allowing electric distribution companies to recover their costs from various state energy policy initiatives and expanded energy efficiency programs.

Interest Expense increased in 2014, as compared to 2013, due primarily to an increase in interest on long-term debt ($5 million) as a result of a new debt issuance in April 2014 and an increase in regulatory interest due to the refund of the DOE proceeds in 2014 and the absence in 2014 of the favorable impact from the resolution of a state income tax audit in 2013.

Other Income, Net decreased in 2014, as compared to 2013, due primarily to lower unrealized gains on the assets supporting the deferred compensation plans ($6.7 million), partially offset by a gain on the sale of land ($4.5 million).

Income Tax Expense decreased in 2014, as compared to 2013, due primarily to lower state taxes, which includes the reduction in the valuation allowance for state tax positions, and various other impacts.

EARNINGS SUMMARY

CL&P's earnings increased in 2014, as compared to 2013, due primarily to a decrease in operations and maintenance costs primarily attributable to lower employee-related costs, as well as lower income tax expense due to the net reduction in the valuation allowance for state tax positions. Partially offsetting these favorable earnings impacts were lower retail electric sales volumes, higher depreciation expense, higher property tax expense, higher interest expense and the after-tax reserve recorded for the 2014 FERC ROE orders as compared to the reserve recorded in 2013 for the FERC ALJ initial decision in the FERC base ROE complaints.

LIQUIDITY

In 2014, CL&P had cash flows provided by operating activities of $612.4 million, compared with $495.3 million in 2013. The improved operating cash flows were due primarily to $68.6 million in DOE damages proceeds received in 2014 from the Yankee Companies associated with the spent nuclear fuel litigation, the absence of cash disbursements for major storm restoration costs, and the favorable cash flow impact resulting from an increase in recoveries from customers in 2014, as compared to 2013, relating to regulatory cost recovery tracking mechanisms, partially offset by higher income tax payments in 2014, as compared to 2013, and changes in working capital items.

RESULTS OF OPERATIONS – NSTAR ELECTRIC COMPANY AND SUBSIDIARY

The following provides the amounts and variances in operating revenues and expense line items in the statements of income for NSTAR Electric for the years ended December 31, 2015 and 2014 included in this Annual Report on Form 10-K:


			For the Years Ended December 31,
								Increase/
(Millions of Dollars)			2015		2014		(Decrease)	Percent
Operating Revenues			$	2,681.3		$	2,536.7	$	144.6	5.7	%
Operating Expenses:
	Purchased Power and Transmission			1,190.2			1,122.3		67.9	6.1
	Operations and Maintenance			306.5			327.0		(20.5)	(6.3)
	Depreciation			196.8			188.7		8.1	4.3
	Amortization of Regulatory Liabilities, Net			(13.0)			(6.3)		(6.7)	(a)
	Energy Efficiency Programs			224.8			193.5		31.3	16.2
	Taxes Other Than Income Taxes			133.2			133.0		0.2	0.2
		Total Operating Expenses		2,038.5			1,958.2		80.3	4.1
Operating Income				642.8			578.5		64.3	11.1
Interest Expense				75.4			77.9		(2.5)	(3.2)
Other Income, Net				5.1			4.5		0.6	13.3
Income Before Income Tax Expense				572.5			505.1		67.4	13.3
Income Tax Expense				228.0			202.0		26.0	12.9
Net Income			$	344.5		$	303.1	$	41.4	13.7	%

(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 Years Ended December 31,
			2015			2014		Increase		Percent
Retail Sales Volumes in GWh				21,055			20,925		130	0.6	%

NSTAR Electric's Operating Revenues, which consist of base distribution revenues and tracked revenues further described below, increased by $144.6 million in the aggregate in 2015 compared to 2014.

Base distribution revenues: Base distribution revenues, excluding LBR, increased $6.5 million as a result of weather impacts. The impact of colder winter weather experienced in the first quarter of 2015 and warmer weather in the third quarter of 2015, partially offset by milder winter weather in the fourth quarter of 2015, all as compared to the same periods in 2014, were the primary drivers of the increase in 2015 retail electric sales volumes of 0.6 percent. In addition, NSTAR Electric is allowed to recover LBR related to reductions in sales volumes as a result of successful energy efficiency programs. NSTAR Electric recognized $20.7 million more LBR in 2015 compared to 2014.

In connection with the Comprehensive Settlement Agreement, NSTAR Electric recognized an $11 million benefit in the first quarter of 2015 associated with the recovery of LBR related to 2009 through 2011 energy efficiency programs, which was recorded as an increase to Operating Revenues. For further information, see "Regulatory Developments and Rate Matters – Massachusetts – NSTAR Electric and NSTAR Gas Comprehensive Settlement Agreement" in this Management's Discussion and Analysis of Financial Condition and Results of Operations.

Tracked revenues: Tracked revenues consist of certain costs that are recovered from customers in rates through DPU-approved cost tracking mechanisms and therefore have no impact on earnings. Costs recovered through cost tracking mechanisms include energy supply costs, retail transmission charges, energy efficiency program costs, net metering for distributed generation and transition cost recovery revenues. Tracked distribution revenues increased primarily as a result of an increase in energy supply costs ($116.2 million), driven by increased average retail rates, and increased cost recovery related to energy efficiency programs ($31.1 million). These increases were partially offset by decreased retail transmission charges ($80.6 million).

Transmission revenues increased by $23.9 million due primarily to higher revenue requirements associated with ongoing investments in our transmission infrastructure and the result of lower reserves associated with the FERC ROE complaint proceedings recorded in 2015 as compared to 2014.

Purchased Power and Transmission expense includes costs associated with purchasing electricity on behalf of NSTAR Electric'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 Transmission increased in 2015, as compared to 2014, due primarily to the following:


(Millions of Dollars)	Increase/(Decrease)
Purchased Power Costs	$	133.2
Transmission Costs		(65.4)
Other		0.1
Total Purchased Power and Transmission	$	67.9

Included in purchased power are the costs associated with NSTAR Electric'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 purchased power costs was due primarily to higher prices associated with the procurement of energy supply. The decrease in transmission costs was primarily the result of a decrease in the retail transmission cost deferral, which reflects the actual costs of transmission service compared to estimated amounts billed to customers.

Operations and Maintenance expense includes tracked costs and costs that are part of base distribution rates with changes impacting earnings (non-tracked costs). Operations and Maintenance decreased in 2015, as compared to 2014, driven by a $6.8 million reduction in non-tracked costs, which was primarily attributable to the resolution of the basic service bad debt adder mechanism ($24.2 million) and lower bad debt expense, partially offset by increased employee-related expenses. Tracked costs, which have no earnings impact, decreased $13.7 million, which was primarily attributable to lower employee-related expenses. As a result of the October 30, 2015 DPU order in the NSTAR Gas distribution rate case, which allows for the recovery of certain uncollectible hardship accounts receivable, NSTAR Electric recorded regulatory deferrals for costs expected to be recovered in future rates given the allowed recoveries of uncollectible hardship accounts receivable by WMECO and NSTAR Gas, which resulted in the recognition of a $10.5 million pre-tax benefit in 2015.

Depreciation increased in 2015, as compared to 2014, due primarily to higher utility plant in service balances.

Amortization of Regulatory Liabilities, Net, reflects an $11.7 million benefit recognized in connection with the Comprehensive Settlement Agreement associated with the CPSL program filings 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 – NSTAR Electric and NSTAR Gas Comprehensive Settlement Agreement" in this Management's Discussion and Analysis of Financial Condition and Results of Operations. Partially offsetting this benefit was an increase in the recovery of previously deferred tracked transition costs, which increased amortization expense, in 2015 compared to 2014. Fluctuations in these costs are recovered from customers in rates and have no impact on earnings.

Energy Efficiency Programs, which are tracked costs, increased in 2015, as compared to 2014, due primarily to an increase in energy efficiency costs incurred in accordance with the three-year program guidelines established by the DPU.

Income Tax Expense increased in 2015, as compared to 2014, due primarily to higher pre-tax earnings ($23.6 million), and higher state taxes and the impact of adjusting estimated tax expense to what was filed on our tax return (provision to return) ($2.4 million).

EARNINGS SUMMARY

NSTAR Electric's earnings increased $41.4 million in 2015, as compared to 2014, due primarily to the resolution of the basic service bad debt adder mechanism ($14.5 million), the favorable impact associated with the Comprehensive Settlement Agreement, which resolved eleven open dockets including the CPSL program filings and the recovery of LBR related to 2009 through 2011 energy efficiency programs ($13 million), the recovery of higher LBR related to 2015 energy efficiency programs, an increase in transmission earnings due primarily to a higher transmission rate base and lower reserves associated with the FERC ROE complaint proceedings recorded in 2015 compared to 2014, and higher retail sales volumes. These favorable earnings impacts were partially offset by an increase in employee-related expenses and higher depreciation expense.

LIQUIDITY

NSTAR Electric had cash flows provided by operating activities of $657 million in 2015, compared with $533 million in 2014. The improved operating cash flows were due primarily to a $110 million decrease in Pension and PBOP Plan cash contributions in 2015 compared to 2014, the $236.9 million favorable impact of receiving net income tax refunds in 2015 compared with making net income tax payments in 2014 due to the extension of the accelerated depreciation deduction. These favorable cash flow impacts were partially offset by the impact of the timing of regulatory recoveries resulting from the increase in purchased power costs and the timing of collections and payments related to our working capital items, including affiliated company receivables, accounts receivable and accounts payable. Accounts receivable increased due primarily to an increase in basic service rates effective January 1, 2015. Also offsetting the favorable impacts were DOE Damages proceeds received from the Yankee Companies of $0.8 million in 2015, compared to $30.2 million in 2014.

NSTAR Electric has a five-year $450 million revolving credit facility. On October 26, 2015, this revolving credit facility was amended and restated and the termination date was extended to September 4, 2020. This facility serves to backstop NSTAR Electric's existing $450 million commercial paper program. As of December 31, 2015 and 2014, NSTAR Electric had $62.5 million and $302 million, respectively, in short-term borrowings outstanding under its commercial paper program, leaving $387.5 million and $148 million of available borrowing capacity as of December 31, 2015 and 2014, respectively. The weighted-average interest rate on these borrowings as of December 31, 2015 and 2014 was 0.40 percent and 0.27 percent, respectively.

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 in the statements of income for PSNH for the years ended December 31, 2015 and 2014 included in this Annual Report on Form 10-K:


			For the Years Ended December 31,
								Increase/
(Millions of Dollars)			2015		2014		(Decrease)	Percent
Operating Revenues			$	972.2		$	959.5	$	12.7	1.3	%
Operating Expenses:
	Purchased Power, Fuel and Transmission			247.7			313.7		(66.0)	(21.0)
	Operations and Maintenance			276.5			261.9		14.6	5.6
	Depreciation			105.4			98.4		7.0	7.1
	Amortization of Regulatory Assets/(Liabilities), Net			16.3			(29.6)		45.9	(a)
	Energy Efficiency Programs			14.3			14.3		-	-
	Taxes Other Than Income Taxes			81.8			71.4		10.4	14.6
		Total Operating Expenses		742.0			730.1		11.9	1.6
Operating Income				230.2			229.4		0.8	0.3
Interest Expense				46.0			45.4		0.6	1.3
Other Income, Net				3.3			2.0		1.3	65.0
Income Before Income Tax Expense				187.5			186.0		1.5	0.8
Income Tax Expense				73.1			72.1		1.0	1.4
Net Income			$	114.4		$	113.9	$	0.5	0.4	%

(a) Percent greater than 100 percent not shown as it is not meaningful.

Operating Revenues
PSNH's retail sales volumes were as follows:

			For the Years Ended December 31,
			2015			2014		Increase		Percent
Retail Sales Volumes in GWh				7,927			7,886		41	0.5	%

PSNH's Operating Revenues, which consist of base distribution revenues and tracked revenues further described below, increased by $12.7 million in the aggregate in 2015 compared to 2014.

Base distribution revenues: Base distribution revenues increased $8.1 million as a result of a distribution rate increase effective July 1, 2015 and higher retail sales volumes driven by weather impacts. Sales volumes increased 0.5 percent in 2015, as compared to 2014, primarily related to the impact of colder winter weather experienced in the first quarter of 2015 and warmer weather in the third quarter of 2015, partially offset by milder winter weather in the fourth quarter of 2015, all as compared to the same periods in 2014.

Tracked revenues: Tracked revenues consist of certain costs that are recovered from customers in rates through NHPUC-approved cost tracking mechanisms and therefore have no impact on earnings. Costs recovered through cost tracking mechanisms include energy supply costs and costs associated with the generation of electricity for customers, retail transmission charges, energy efficiency program costs and stranded cost recovery revenues. Tracked distribution revenues decreased primarily as a result of a reduction in wholesale generation revenues, partially offset by an increase in energy supply costs in 2015, as compared to 2014 ($11.2 million).

Transmission revenues increased by $12.5 million due primarily to higher revenue requirements associated with ongoing investments in our transmission infrastructure and lower reserves associated with the FERC ROE complaint proceedings recorded in 2015 compared to 2014.

Purchased Power, Fuel and Transmission expense includes costs associated with PSNH's generation of electricity as well as purchasing electricity on behalf of its customers. These energy supply costs are recovered from customers in NHPUC-approved cost tracking mechanisms, which have no impact on earnings (tracked costs). Purchased Power, Fuel and Transmission decreased in 2015, as compared to 2014, due primarily to the following:


(Millions of Dollars)	Decrease
Generation Fuel Costs	$	(25.0)
Purchased Power Costs		(23.6)
Transmission Costs		(14.1)
Other		(3.3)
Total Purchased Power, Fuel and Transmission	$	(66.0)

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 decrease in generation fuel costs was due primarily to a decrease in the amount of electricity generated by PSNH facilities during 2015, as compared to 2014. The decrease in purchased power costs was due to lower power prices of short-term and spot purchases made in the wholesale power market during 2015, as compared to 2014. The decrease in transmission costs was primarily the result of a decrease in the retail transmission cost deferral, which reflects the actual costs of transmission service compared to estimated amounts billed to customers.

Depreciation increased in 2015, as compared to 2014, due primarily to higher utility plant in service balances.

Amortization of Regulatory Assets/(Liabilities), Net reflects an increase in the deferral to expense of energy supply costs and other amortizations for 2015, as compared to 2014. Fluctuations in these costs are recovered from customers in rates and have no impact on earnings.

Taxes Other Than Income Taxes increased in 2015, as compared to 2014, due primarily to an increase in property taxes as a result of an increase in utility plant balances.

EARNINGS SUMMARY

PSNH's earnings increased $0.5 million in 2015 compared to 2014, driven by higher distribution revenues due primarily to the impact of the distribution rate increase effective July 1, 2015 and higher retail sales volumes, and an increase in transmission earnings due primarily to a higher transmission rate base and lower reserves associated with the FERC ROE complaint proceedings recorded in 2015 compared to 2014. These favorable earnings impacts were offset by a $5 million contribution to create a clean energy fund recorded in 2015 in connection with the generation divestiture agreement, which is not recoverable from customers, higher property tax expense, higher depreciation expense and an increase in operations and maintenance costs.

LIQUIDITY

PSNH had cash flows provided by operating activities of $274.5 million in 2015, as compared to $248 million in 2014. The increase in operating cash flows was due primarily to the timing of payments related to fuel, materials and supplies as well as an increase in recoveries from customers in 2015, compared to 2014, and the timing of collections and payments related to our working capital items, including accounts receivable and accounts payable. Partially offsetting these favorable impacts were DOE Damages proceeds received from the Yankee Companies of $1 million in 2015, compared to $14.5 million in 2014.

RESULTS OF OPERATIONS – WESTERN MASSACHUSETTS ELECTRIC COMPANY

The following provides the amounts and variances in operating revenues and expense line items in the statements of income for WMECO for the years ended December 31, 2015 and 2014 included in this Annual Report on Form 10-K:


			For the Years Ended December 31,
								Increase/
(Millions of Dollars)			2015		2014		(Decrease)	Percent
Operating Revenues			$	518.1		$	493.4	$	24.7	5.0	%
Operating Expenses:
	Purchased Power and Transmission			177.2			172.9		4.3	2.5
	Operations and Maintenance			86.3			89.4		(3.1)	(3.5)
	Depreciation			43.4			41.9		1.5	3.6
	Amortization of Regulatory Assets/(Liabilities), Net			14.5			(6.2)		20.7	(a)
	Energy Efficiency Programs			42.9			42.9		-	-
	Taxes Other Than Income Taxes			38.3			34.9		3.4	9.7
		Total Operating Expenses		402.6			375.8		26.8	7.1
Operating Income				115.5			117.6		(2.1)	(1.8)
Interest Expense				24.7			24.9		(0.2)	(0.8)
Other Income, Net				2.7			2.4		0.3	12.5
Income Before Income Tax Expense				93.5			95.1		(1.6)	(1.7)
Income Tax Expense				37.0			37.3		(0.3)	(0.8)
Net Income			$	56.5		$	57.8	$	(1.3)	(2.2)	%

(a) Percent greater than 100 percent not shown as it is not meaningful

Operating Revenues
WMECO's retail sales volumes were as follows:
			For the Years Ended December 31,
			2015			2014		Decrease		Percent
Retail Sales Volumes in GWh				3,563			3,586		(23)	(0.6)	%

Operating Revenues

WMECO's Operating Revenues increased by $24.7 million in 2015 compared to 2014.

Fluctuations in WMECO's sales volumes have no impact on total operating revenues or earnings, as WMECO’s revenues are decoupled from sales volumes. Fluctuations in the overall level of operating revenues are primarily related to tracked revenues. Tracked revenues consist of certain costs that are recovered from customers in rates through DPU-approved cost tracking mechanisms and therefore have no impact on earnings. Costs recovered through cost tracking mechanisms include energy supply costs, transmission related costs, energy efficiency programs, low income assistance programs, and restructuring and stranded costs as a result of deregulation. Tracked revenues increased due primarily to an increase in energy supply costs ($20.3 million) driven by increased average retail rates. The increase in Operating Revenues was partially offset by a $3.9 million decrease in revenues that impacts earnings due to the absence of a 2014 wholesale billing adjustment.

Transmission revenues increased by $8.7 million due primarily to higher revenue requirements associated with ongoing investments in our transmission infrastructure and the impact of a lower FERC ROE complaint proceedings reserve recorded in 2015 as compared to 2014.

Purchased Power and Transmission expense includes costs associated with purchasing electricity 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 Transmission increased in 2015, as compared to 2014, due primarily to the following:


(Millions of Dollars)	Increase/(Decrease)
Purchased Power Costs	$	18.1
Transmission Costs		(13.8)
Total Purchased Power and Transmission	$	4.3

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 competitive energy suppliers. The increase in purchased power costs was due primarily to higher prices associated with the procurement of energy supply. The decrease in transmission costs was as a result of a decrease in the retail transmission cost deferral, which reflects the actual costs of transmission service compared to estimated amounts billed to customers.

Depreciation increased in 2015, as compared to 2014, due primarily to higher utility plant in service balances.

Amortization of Regulatory Assets/(Liabilities), Net reflects the absence of the refund of the DOE proceeds to customers in 2014 as well as energy and energy related costs and amortizations that can fluctuate period to period based on timing of costs incurred and related rate changes to recover these costs. Fluctuations in energy and energy related costs are recovered from customers in rates and have no impact on earnings.

Taxes Other Than Income Taxes increased in 2015, as compared 2014, due primarily to an increase in property taxes as a result of an increase in utility plant balances.

EARNINGS SUMMARY

WMECO's earnings decreased $1.3 million in 2015, as compared to 2014, due primarily to the absence of a 2014 wholesale billing adjustment, which favorably impacted 2014 revenues and interest expense, higher property tax expense and an increase in non-tracked operations and maintenance costs. Partially offsetting these unfavorable earnings impacts was an increase in transmission earnings due primarily to a higher transmission rate base and lower reserves associated with the FERC ROE complaint proceedings recorded in 2015 compared to 2014.

LIQUIDITY

WMECO had cash flows provided by operating activities of $43 million in 2015, compared with $153.3 million in 2014. The decrease in operating cash flows was due primarily to the $57.4 million payment made from WMECO’s spent nuclear fuel trust to fully satisfy the pre-1983 spent nuclear fuel obligation with the DOE. Also contributing to the decrease in operating cash flows were DOE Damages proceeds received from the Yankee Companies of $0.6 million in 2015, compared to $18.9 million in 2014, the unfavorable impact of accounts receivable due primarily to an increase in basic service rates effective January 1, 2015, and the timing of regulatory recoveries resulting from the increase in purchased power costs. Partially offsetting these unfavorable cash flow impacts were lower income tax payments in 2015 compared to 2014.

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