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

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 are herein collectively referred to as the "financial statements."

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 earnings and EPS excluding certain integration costs incurred by Eversource parent and our Electric and Natural Gas 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 2017, 2016 and 2015 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 a meaningful representation 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 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 – Electric and Natural Gas Companies" in this Management's Discussion and Analysis of Financial Condition and Results of Operations, herein.

The results of Aquarion and its subsidiaries, hereinafter referred to as "Aquarion," are included from the date of the acquisition, December 4, 2017, through December 31, 2017 throughout this Management's Discussion and Analysis of Financial Condition and Results of Operations.

Financial Condition and Business Analysis

Executive Summary

Results and Future Outlook:


•	We earned $988.0 million, or $3.11 per share, in 2017, compared with $942.3 million, or $2.96 per share, in 2016.


•	Our electric distribution segment, which includes generation results, earned $497.4 million, or $1.57 per share, in 2017, compared with $462.8 million, or $1.46 per share, in 2016. Our electric transmission segment earned $391.9 million, or $1.23 per share, in 2017, compared with $370.8 million, or $1.16 per share, in 2016. Our natural gas distribution segment earned $74.6 million, or $0.23 per share, in 2017, compared with $77.7 million, or $0.24 per share, in 2016.

•

Our electric distribution segment, which includes generation results, earned $497.4 million, or $1.57 per share, in 2017, compared with $462.8 million, or $1.46 per share, in 2016. Our electric transmission segment earned $391.9 million, or $1.23 per share, in 2017, compared with $370.8 million, or $1.16 per share, in 2016. Our natural gas distribution segment earned $74.6 million, or $0.23 per share, in 2017, compared with $77.7 million, or $0.24 per share, in 2016.


•	Eversource parent and other companies earned $24.1 million, or $0.08 per share, in 2017, compared with $31.0 million, or $0.10 per share, in 2016.


•	We currently project 2018 earnings of between $3.20 per share and $3.30 per share.

Liquidity:


•	Cash flows provided by operating activities totaled $2.0 billion in 2017, compared with $2.2 billion in 2016. Investments in property, plant and equipment totaled $2.3 billion in 2017 and $2.0 billion in 2016. Cash and cash equivalents totaled $38.2 million as of December 31, 2017, compared with $30.3 million as of December 31, 2016.


•	In 2017, we issued $2.5 billion of new long-term debt, consisting of $1.2 billion by Eversource parent, $700 million by NSTAR Electric, $525 million by CL&P and $75 million by Yankee Gas. Proceeds from these new issuances were used primarily to pay short-term borrowings and repay long-term debt at maturity. In 2017, Eversource, NSTAR Electric, CL&P, PSNH and NSTAR Gas repaid, at maturity, $745 million, $400 million, $250 million, $70 million and $25 million, respectively, of previously issued long-term debt.

•

In 2017, we issued $2.5 billion of new long-term debt, consisting of $1.2 billion by Eversource parent, $700 million by NSTAR Electric, $525 million by CL&P and $75 million by Yankee Gas. Proceeds from these new issuances were used primarily to pay short-term borrowings and repay long-term debt at maturity. In 2017, Eversource, NSTAR Electric, CL&P, PSNH and NSTAR Gas repaid, at maturity, $745 million, $400 million, $250 million, $70 million and $25 million, respectively, of previously issued long-term debt.


•	In 2017, we paid cash dividends on common shares of $602.1 million, compared with $564.5 million in 2016. On February 7, 2018, our Board of Trustees approved a common share dividend of $0.505 per share, payable on March 30, 2018 to shareholders of record as of March 6, 2018. The 2018 dividend represents an increase of 6.3 percent over the dividend paid in December 2017, and is the equivalent to dividends on common shares of approximately $640 million on an annual basis.

•

In 2017, we paid cash dividends on common shares of $602.1 million, compared with $564.5 million in 2016. On February 7, 2018, our Board of Trustees approved a common share dividend of $0.505 per share, payable on March 30, 2018 to shareholders of record as of March 6, 2018. The 2018 dividend represents an increase of 6.3 percent over the dividend paid in December 2017, and is the equivalent to dividends on common shares of approximately $640 million on an annual basis.


•	We project to make capital expenditures of $10.8 billion from 2018 through 2021, of which we expect $5.7 billion to be in our electric and natural gas distribution segments, $4.1 billion to be in our electric transmission segment and $0.4 billion to be in our water utility business. We also project to invest $0.5 billion in information technology and facilities upgrades and enhancements. These projections do not include any expected investments related to Bay State Wind.

•

We project to make capital expenditures of $10.8 billion from 2018 through 2021, of which we expect $5.7 billion to be in our electric and natural gas distribution segments, $4.1 billion to be in our electric transmission segment and $0.4 billion to be in our water utility business. We also project to invest $0.5 billion in information technology and facilities upgrades and enhancements. These projections do not include any expected investments related to Bay State Wind.

Strategic Items:


•	On January 25, 2018, Northern Pass was selected from the 46 proposals submitted as the winning bidder in the Massachusetts clean energy request for proposal ("RFP"), which successfully positioned Northern Pass to provide a firm delivery of hydropower to Massachusetts. Northern Pass is Eversource's planned 1,090 MW 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. On February 1, 2018, the New Hampshire Site Evaluation Committee ("NHSEC") voted to deny Northern Pass’ siting application. We intend to seek reconsideration of the NHSEC’s decision and to review all options for moving this critical clean energy project forward. As of December 31, 2017, we have approximately $277 million in capitalized costs associated with Northern Pass.

•

On January 25, 2018, Northern Pass was selected from the 46 proposals submitted as the winning bidder in the Massachusetts clean energy request for proposal ("RFP"), which successfully positioned Northern Pass to provide a firm delivery of hydropower to Massachusetts. Northern Pass is Eversource's planned 1,090 MW 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. On February 1, 2018, the New Hampshire Site Evaluation Committee ("NHSEC") voted to deny Northern Pass’ siting application. We intend to seek reconsideration of the NHSEC’s decision and to review all options for moving this critical clean energy project forward. As of December 31, 2017, we have approximately $277 million in capitalized costs associated with Northern Pass.


•	On December 20, 2017, Bay State Wind submitted two proposals, one for 400 MW and the other for 800 MW, in response to the Massachusetts clean energy RFP.


•	On December 4, 2017, Eversource completed the acquisition of Aquarion (formerly Macquarie Utilities Inc.) from Macquarie Infrastructure Partners for $1.675 billion, consisting of approximately $880 million in cash and $795 million of assumed debt. As a result, Aquarion became a wholly-owned subsidiary of Eversource.

Legislative, Regulatory, Policy and Other Items:


•	On November 30, 2017, the DPU issued its decision in the NSTAR Electric distribution rate case, which approved an annual distribution rate increase of $37 million, with rates effective February 1, 2018. As a result of this decision, we recognized an aggregate $44.1 million pre-tax benefit to earnings in 2017. On January 3, 2018, NSTAR Electric filed a motion to reflect a revenue requirement reduction of $56 million due to the decrease in the federal corporate income tax rate, as part of the "Tax Cuts and Jobs Act", resulting in an annual net decrease in rates of $19 million.

•

On November 30, 2017, the DPU issued its decision in the NSTAR Electric distribution rate case, which approved an annual distribution rate increase of $37 million, with rates effective February 1, 2018. As a result of this decision, we recognized an aggregate $44.1 million pre-tax benefit to earnings in 2017. On January 3, 2018, NSTAR Electric filed a motion to reflect a revenue requirement reduction of $56 million due to the decrease in the federal corporate income tax rate, as part of the "Tax Cuts and Jobs Act", resulting in an annual net decrease in rates of $19 million.


•	On January 11, 2018, CL&P filed a distribution rate case settlement agreement for approval with PURA, which included, among other things, rate increases of $97.1 million, $32.7 million and $24.7 million, effective May 1, 2018, 2019, and 2020, respectively, an authorized regulatory ROE of 9.25 percent, and 53 percent common equity in CL&P's capital structure. The rate increases associated with the settlement agreement will be reduced by the impact of the decrease in the federal corporate income tax rate, as part of the "Tax Cuts and Jobs Act", which we currently estimate to average approximately $45 million to $50 million per year.

•

On January 11, 2018, CL&P filed a distribution rate case settlement agreement for approval with PURA, which included, among other things, rate increases of $97.1 million, $32.7 million and $24.7 million, effective May 1, 2018, 2019, and 2020, respectively, an authorized regulatory ROE of 9.25 percent, and 53 percent common equity in CL&P's capital structure. The rate increases associated with the settlement agreement will be reduced by the impact of the decrease in the federal corporate income tax rate, as part of the "Tax Cuts and Jobs Act", which we currently estimate to average approximately $45 million to $50 million per year.


•	On December 22, 2017, the "Tax Cuts and Jobs Act" (the "Act") became law, which amended existing federal tax rules and included numerous provisions that impacted corporations. In particular, the Act reduced the federal corporate income tax rate from 35 percent to 21 percent effective January 1, 2018. As of December 31, 2017, we estimated approximately $2.9 billion of provisional regulated excess ADIT liabilities that we expect to benefit our customers in future periods. The ultimate amount and timing of when certain income tax benefits resulting from the Act benefit our customers will vary by jurisdiction.

•

On December 22, 2017, the "Tax Cuts and Jobs Act" (the "Act") became law, which amended existing federal tax rules and included numerous provisions that impacted corporations. In particular, the Act reduced the federal corporate income tax rate from 35 percent to 21 percent effective January 1, 2018. As of December 31, 2017, we estimated approximately $2.9 billion of provisional regulated excess ADIT liabilities that we expect to benefit our customers in future periods. The ultimate amount and timing of when certain income tax benefits resulting from the Act benefit our customers will vary by jurisdiction.


•	On January 10, 2018, PSNH completed the sale of its thermal generation facilities. In accordance with the Purchase and Sale Agreement, the original purchase price of $175 million was adjusted to reflect working capital adjustments, closing date adjustments and proration of taxes and fees prior to closing, totaling $40.9 million, resulting in net proceeds of $134.1 million. We are targeting for PSNH to complete the sale of its hydroelectric generation facilities by the end of the first quarter of 2018.

•

Overview

Consolidated: Below is a summary of our earnings by business, which also reconciles the non-GAAP financial measure of EPS by business to the most directly comparable GAAP measure of diluted EPS, for the years ended December 31, 2017, 2016 and 2015. Also included in the summary for the year ended December 31, 2015, is a reconciliation of the non-GAAP financial measure of consolidated non-GAAP earnings to the most directly comparable GAAP measure of consolidated Net Income Attributable to Common Shareholders.



	For the Years Ended December 31,
	2017				2016				2015
(Millions of Dollars, Except Per Share Amounts)	Amount		Per Share		Amount		Per Share		Amount			Per Share
Net Income Attributable to Common Shareholders (GAAP)	$	988.0	$	3.11	$	942.3	$	2.96	$	878.5		$	2.76
Electric and Natural Gas Companies	$	963.9	$	3.03	$	911.3	$	2.86	$	884.8		$	2.78
Eversource Parent and Other Companies	24.1		0.08		31.0		0.10		9.5			0.03
Non-GAAP Earnings	N/A		N/A		N/A		N/A		894.3			2.81
Integration Costs (after-tax) (1)	—		—		—		—		(15.8		)	(0.05		)
Net Income Attributable to Common Shareholders (GAAP)	$	988.0	$	3.11	$	942.3	$	2.96	$	878.5		$	2.76

(1) The 2015 integration costs were associated with our branding efforts and severance costs.

Electric and Natural Gas Companies: Our electric and natural gas companies consist of the electric distribution (including PSNH's generation facilities and NSTAR Electric's solar power facilities), electric transmission and natural gas distribution segments. A summary of our segment earnings and EPS is as follows:



	For the Years Ended December 31,
	2017				2016				2015
(Millions of Dollars, Except Per Share Amounts)	Amount		Per Share		Amount		Per Share		Amount			Per Share
Electric Distribution	$	497.4	$	1.57	$	462.8	$	1.46	$	507.9		$	1.59
Electric Transmission	391.9		1.23		370.8		1.16		304.5			0.96
Natural Gas Distribution	74.6		0.23		77.7		0.24		72.4			0.23
Non-GAAP Earnings	N/A		N/A		N/A		N/A		884.8			2.78
Integration Costs (after-tax) (1)	—		—		—		—		(0.8		)	—
Net Income - Electric and Natural Gas Companies	$	963.9	$	3.03	$	911.3	$	2.86	$	884.0		$	2.78

(1) The 2015 Electric and Natural Gas Companies' integration costs include severance in connection with cost saving initiatives.

Our electric distribution segment earnings increased $34.6 million in 2017, as compared to 2016, due primarily to a lower effective tax rate, lower non-tracked operations and maintenance expense, higher lost base revenues at NSTAR Electric and higher distribution revenues at CL&P due in part to a higher rate base for the system resiliency program, partially offset by higher depreciation expense, lower sales volumes primarily driven by the mild summer weather in 2017, as compared to 2016 (primarily at NSTAR Electric), and higher property tax expense.

Our electric transmission segment earnings increased $21.1 million in 2017, as compared to 2016, due primarily to a higher transmission rate base as a result of our continued investment in our transmission infrastructure, partially offset by the absence in 2017 of the FERC-allowed recovery of certain previously expensed merger-related costs in 2016, and a lower benefit in the second quarter of 2017 related to the annual billing and cost reconciliation filing with the FERC.

Our natural gas distribution segment earnings decreased $3.1 million in 2017, as compared to 2016, due primarily to higher depreciation expense, lower demand revenues in Connecticut driven by lower peak usage in 2017, as compared to 2016, higher non-tracked operations and maintenance expense, and higher property tax expense, partially offset by higher sales volumes driven by colder winter weather in the fourth quarter of 2017, as compared to 2016.

Eversource Parent and Other Companies: Eversource parent and other companies earned $24.1 million in 2017, compared with $31.0 million in 2016. The decrease in earnings was due primarily to a higher effective tax rate, higher interest expense and the absence in 2017 of the earnings and gain on the sale of an unregulated business in 2016. These decreases were partially offset by the 2017 DPU-allowed recovery of certain previously expensed merger-related costs in NSTAR Electric's distribution rates, and increased gains on investments recorded in 2017.

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 certain of our electric utilities impact earnings ("Traditional" in the table below). For others, fluctuations in retail electric sales volumes do not impact earnings due to their regulatory commission approved distribution 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.

DPU-approved rate decision. See "Regulatory Developments and Rate Matters - Massachusetts - NSTAR Electric Distribution Rate Case Decision" in this Management's Discussion and Analysis of Financial Condition and Results of Operations.

CL&P and NSTAR Electric (for its western Massachusetts customer rates) reconciled their annual base distribution rate recovery amounts to their pre-established levels of baseline distribution delivery service revenues of $1.059 billion and $132.4 million, respectively, through December 31, 2017. Effective February 1, 2018, NSTAR Electric, operating entirely under decoupled rates, will reconcile its annual base distribution rate recovery to its new baseline of $974.8 million. Any difference between the allowed level of distribution revenue and the actual amount realized during a 12-month period is adjusted through rates in the following period.

Fluctuations in natural gas sales volumes in Connecticut impact earnings ("Traditional" in the table below). In Massachusetts, fluctuations in natural gas sales volumes do not impact earnings due to the DPU-approved natural gas distribution revenue decoupling mechanism approved in the last rate case decision ("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.

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



	Electric				Firm Natural Gas
	For the Year Ended December 31, 2017 Compared to 2016				For the Year Ended December 31, 2017 Compared to 2016
	Sales Volumes (GWh)		Percentage Decrease		Sales Volumes (MMcf)			Percentage Increase/(Decrease)
	2017	2016		2017		2016
Traditional:
Residential	9,453	9,654	(2.1	)%	15,502		15,118	2.5	%
Commercial	15,958	16,267	(1.9	)%	20,649		19,846	4.0	%
Industrial	2,444	2,558	(4.5	)%	10,806		10,350	4.4	%
Total - Traditional	27,855	28,479	(2.2	)%	46,957		45,314	3.6	%

Decoupled:
Residential	11,043	11,347	(2.7	)%	21,919		20,616	6.3	%
Commercial	10,612	10,940	(3.0	)%	21,859		21,583	1.3	%
Industrial	2,736	2,876	(4.9	)%	5,882		5,833	0.8	%
Total - Decoupled	24,391	25,163	(3.1	)%	49,660		48,032	3.4	%
Special Contracts (1)	N/A	N/A	N/A		4,409		4,696	(6.1	)%
Total - Decoupled and Special Contracts	24,391	25,163	(3.1	)%	54,069		52,728	2.5	%
Total Sales Volumes	52,246	53,642	(2.6	)%	101,026		98,042	3.0	%


(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.

Retail electric sales volumes at our electric utilities with a traditional rate structure (the eastern region of NSTAR Electric and PSNH) were lower in 2017, as compared to 2016, due primarily to the mild summer weather in 2017, as compared to 2016. Cooling degree days in 2017 were 14.7 percent lower in the Boston metropolitan area and 22.7 percent lower in New Hampshire, as compared to 2016. Sales volumes were positively impacted by improved economic conditions across our service territories, but this trend was offset by lower customer usage driven by the impact of increased customer energy conservation efforts.

On January 28, 2016, Eversource received approval of a three-year energy efficiency plan in Massachusetts, which included recovery of LBR in the NSTAR Electric eastern Massachusetts service territory until it was covered under a decoupled rate structure, which occurred on February 1, 2018. NSTAR Electric recorded LBR related to reductions in sales volume as a result of successful energy efficiency programs. LBR was recovered from retail customers through rates. NSTAR Electric recognized LBR of $73.7 million and $60.7 million in 2017 and 2016, respectively.

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. Consolidated firm natural gas sales volumes were higher in 2017, as compared to 2016, due primarily to colder winter weather in the fourth quarter of 2017, as compared to 2016. Heating degree days in 2017 were 2.5 percent higher in Connecticut, as compared to 2016. Sales volumes were also positively impacted by improved economic conditions across our natural gas service territories.

Liquidity

Consolidated: Cash and cash equivalents totaled $38.2 million as of December 31, 2017, compared with $30.3 million as of December 31, 2016.

Long-Term Debt Issuances and Repayments: The following table summarizes long-term debt issuances and repayments:



(Millions of Dollars)	Issue Date	Issuances/(Repayments)			Maturity Date	Use of Proceeds
CL&P:
3.20% 2017 Series A First Mortgage Bonds	March 2017	$	300.0		2027	Repay short-term debt borrowings
4.30% 2014 Series A First Mortgage Bonds (1)	August 2017	225.0			2044	Refinance short-term debt and fund working capital and capital expenditures
5.375% 2007 Series A First Mortgage Bonds	March 2007	(150.0		)	2017	N/A
5.75% 2007 Series C First Mortgage Bonds	September 2007	(100.0		)	2017	N/A
NSTAR Electric:
3.20% Debentures	May 2017	350.0			2027	Repay short-term borrowings and fund capital expenditures and working capital
3.20% Debentures (2)	October 2017	350.0			2027	Redeem long-term debt that matured in 2017
5.625% Debentures	November 2007	(400.0		)	2017	N/A
PSNH:
6.15% Series N First Mortgage Bonds	September 2007	(70.0		)	2017	N/A
Other:
Yankee Gas 3.02% Series N First Mortgage Bonds	September 2017	75.0			2027	Repay short-term borrowings
NSTAR Gas 7.04% Series M First Mortgage Bonds	September 1997	(25.0		)	2017	N/A
Eversource Parent 2.75% Series K Senior Notes	March 2017	300.0			2022	Repay short-term borrowings
Eversource Parent 2.75% Series K Senior Notes (3)	October 2017	450.0			2022	Repay short-term borrowings
Eversource Parent 2.90% Series L Senior Notes	October 2017	450.0			2024	Repay short-term borrowings
Eversource Parent 2.50% Series I Senior Notes (4)	January 2018	200.0			2021	Repay long-term debt due to mature in 2018 and repay short-term borrowings
Eversource Parent 3.30% Series M Senior Notes	January 2018	450.0			2028	Repay long-term debt due to mature in 2018
Eversource Parent 1.60% Series G Senior Notes (5)	January 2015	(150.0		)	2018	N/A


(1)	These bonds are part of the existing series initially issued by CL&P in 2014. The aggregate outstanding principal amount for these bonds is now $475 million.


(2)	These debentures are part of the same series initially issued by NSTAR Electric in May 2017. The aggregate outstanding principal amount for these debentures is now $700 million.


(3)	These notes are part of the same series issued by Eversource parent in March 2017. The aggregate outstanding principal amount for these notes is now $750 million.


(4)	These notes are part of the same series issued by Eversource parent in March 2016. The aggregate outstanding principal amount for these notes is now $450 million.


(5)	Represents a repayment at maturity on January 15, 2018.

Commercial Paper Programs and Credit Agreements: Eversource parent has a $1.45 billion commercial paper program allowing Eversource parent to issue commercial paper as a form of short-term debt. Eversource parent, CL&P, PSNH, NSTAR Gas and Yankee Gas are also parties to a five-year $1.45 billion revolving credit facility. On December 8, 2017, Eversource parent amended and restated the revolving credit facility. The amended and restated revolving credit facility terminates on December 8, 2022 and serves to backstop Eversource parent's $1.45 billion commercial paper program. There were no borrowings outstanding on the revolving credit facility as of December 31, 2017 or 2016.

NSTAR Electric has a $650 million commercial paper program allowing NSTAR Electric to issue commercial paper as a form of short-term debt. On December 8, 2017, NSTAR Electric increased its commercial paper program from $450 million to $650 million. NSTAR Electric is also a party to a five-year $650 million revolving credit facility. On December 8, 2017, NSTAR Electric amended and restated the revolving credit facility, increasing it from $450 million to $650 million. The amended and restated revolving credit facility terminates on December 8, 2022 and serves to backstop NSTAR Electric's $650 million commercial paper program. There were no borrowings outstanding on the revolving credit facility as of December 31, 2017 or 2016.

The amount of borrowings outstanding and available under the commercial paper programs and revolving credit facility was as follows:



	Borrowings Outstanding as of December 31,				Available Borrowing Capacity as of December 31,				Weighted-Average Interest Rate as of December 31,
(Millions of Dollars)	2017		2016		2017		2016		2017		2016
Eversource Parent Commercial Paper Program	$	979.3	$	1,022.0	$	470.7	$	428.0	1.86	%	0.88	%
NSTAR Electric Commercial Paper Program	234.0		126.5		416.0		323.5		1.55	%	0.71	%
Revolving Credit Facility (1)	76.0		N/A		24.0		N/A		2.66	%	N/A

(1) Aquarion has a $100.0 million revolving credit facility, which expires on August 19, 2019.

Amounts outstanding under the commercial paper programs and revolving credit facility are included in Notes Payable for Eversource and NSTAR Electric and are classified in current liabilities on the balance sheets as all borrowings are outstanding for no more than 364 days at one time. As a result of the Eversource parent long-term debt issuances on January 8, 2018, the net proceeds of which were used to repay short-term borrowings

outstanding under its commercial paper program, $201.2 million of commercial paper borrowings under the Eversource parent commercial paper program were reclassified to Long-Term Debt as of December 31, 2017.

As of December 31, 2017, there were intercompany loans from Eversource parent of $69.5 million to CL&P and $262.9 million to PSNH. As of December 31, 2016, there were intercompany loans from Eversource parent of $80.1 million to CL&P, $160.9 million to PSNH and $51.0 million to NSTAR Electric. These intercompany loans from Eversource parent are included in Notes Payable to Eversource Parent and are classified in current liabilities on the respective subsidiary's balance sheets. Intercompany loans from Eversource parent are eliminated in consolidation on Eversource's balance sheets.

Cash Flows: Cash flows provided by operating activities totaled $2.0 billion in 2017, compared with $2.2 billion in 2016. The decrease in operating cash flows was due primarily to the $166.3 million net unfavorable impact as a result of the change in income tax payments made, or refunds received, in 2017 when compared to 2016. This unfavorable impact was primarily the result of the December 2015 legislation, which extended the accelerated deduction of depreciation from 2015 to 2019. The legislation resulted in a significant refund of approximately $275 million, which we received in the first quarter of 2016. Additionally, there was an increase of $84.1 million in Pension and PBOP Plan cash contributions made in 2017, as compared to 2016, a decrease of $59.8 million related to the absence in 2017 of the Yankee Companies' DOE Damages received in 2016, and the unfavorable impact related to the timing of regulatory recoveries, which were significantly impacted by NSTAR Electric’s timing of collections of purchased power and transmission costs. Partially offsetting these unfavorable impacts was the benefit related to the timing of collections and payments of our working capital items, including accounts payable.

In 2017, we paid cash dividends of $602.1 million, or $1.90 per common share, compared with $564.5 million, or $1.78 per common share in 2016. Our quarterly common share dividend payment was $0.475 per share, in 2017, as compared to $0.445 per common share in 2016. On February 7, 2018, our Board of Trustees approved a common share dividend of $0.505 per share, payable on March 30, 2018 to shareholders of record as of March 6, 2018. The 2018 dividend represents an increase of 6.3 percent over the dividend paid in December 2017, and is the equivalent to dividends on common shares of approximately $640 million on an annual basis.

In 2017, CL&P, NSTAR Electric and PSNH paid $254.8 million, $272.0 million and $23.9 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 2017, investments for Eversource, CL&P, NSTAR Electric and PSNH were $2.3 billion, $824.4 million, $719.6 million and $312.7 million, respectively.

Eversource completed the acquisition of Aquarion from Macquarie Infrastructure Partners on December 4, 2017 for $1.675 billion, consisting of approximately $880 million in cash and $795 million of assumed debt.

Eversource, CL&P, NSTAR Electric and PSNH each 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. 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. 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, totaling approximately $2.3 billion in cash capital spend in 2017. In addition, growth in Eversource's key business initiatives in 2017 required cash contributions of $32.6 million, which are recognized as long-term assets. These factors have resulted in current liabilities exceeding current assets by $1.1 billion, $338.1 million, $137.5 million, and $183.1 million at Eversource, CL&P, NSTAR Electric and PSNH, respectively, as of December 31, 2017.

As of December 31, 2017, $961.0 million of Eversource's long-term debt, including $450.0 million, $300.0 million, $110.0 million, $100.0 million and $1 million for Eversource parent, CL&P, PSNH, Yankee Gas and Aquarion, respectively, will be paid within the next 12 months. Included in the current portion of long-term debt is $35.4 million related to fair value adjustments from our business combinations that will be amortized within 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 and PSNH 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 and PSNH, along with the access to financial markets, will be sufficient to meet any future operating requirements and capital investment forecasted opportunities.

Credit Ratings: On December 5, 2017, S&P upgraded Eversource and its subsidiaries' corporate credit rating to A+ and changed the outlook to stable.

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+	Positive
CL&P	Baa1	Stable	A+	Stable	A-	Stable
NSTAR Electric	A2	Stable	A+	Stable	A	Stable
PSNH	A3	Stable	A+	Stable	A-	Stable

A summary of the current credit ratings and outlooks by Moody's, S&P and Fitch for senior unsecured debt of Eversource parent and NSTAR Electric, 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+	Positive
CL&P	A2	Stable	AA-	Stable	A+	Stable
NSTAR Electric	A2	Stable	A+	Stable	A+	Stable
PSNH	A1	Stable	AA-	Stable	A+	Stable

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 $2.5 billion in 2017, $2.2 billion in 2016, and $1.9 billion in 2015. These amounts included $165.9 million in 2017, $137.7 million in 2016, and $102.0 million in 2015 related to information technology and facilities upgrades and enhancements, primarily at Eversource Service and The Rocky River Realty Company.

Aquarion: On December 4, 2017, Eversource acquired Aquarion (formerly Macquarie Utilities Inc.) from Macquarie Infrastructure Partners for $1.675 billion, consisting of approximately $880 million in cash and $795 million of assumed Aquarion debt. As a result, Aquarion became a wholly-owned subsidiary of Eversource. Aquarion is a regulated water utility holding company that operates three separate regulated water utilities in Connecticut, Massachusetts and New Hampshire. Aquarion collects, treats and distributes water to residential, commercial and industrial customers, to other utilities for resale, and for private and municipal fire protection.

Bay State Wind: Bay State Wind is a proposed offshore wind project being jointly developed by Eversource and Denmark-based Ørsted. Bay State Wind will be located in a 300-square-mile area approximately 25 miles off the coast of Massachusetts that has the ultimate potential to generate more than 2,000 MW of clean, renewable energy. Eversource and Ørsted each hold a 50 percent ownership interest in Bay State Wind.

On June 29, 2017, the Bureau of Ocean Energy Management ("BOEM") approved the project’s Site Assessment Plan ("SAP"), the first BOEM approval of an offshore wind SAP in the U.S.

In August 2016, Massachusetts passed clean energy legislation that requires EDCs to jointly solicit RFPs and enter into long-term contracts for offshore wind, creating RFP opportunities for projects like Bay State Wind. On June 29, 2017, the Massachusetts RFP was issued, seeking bids for a minimum of 400 MW of offshore wind capacity. The RFP stated that bids of up to 800 MW would be considered, provided they demonstrated significant net economic benefits to customers. On December 20, 2017, Bay State Wind submitted two proposals, one for 400 MW and the other for 800 MW, in response to the Massachusetts clean energy RFP.

For more information regarding the clean energy legislation, see "Regulatory Developments and Rate Matters – Massachusetts – Massachusetts RFPs" in this Management's Discussion and Analysis of Financial Condition and Results of Operations.

Electric Transmission Business:

Our consolidated electric transmission business capital expenditures increased by $35.4 million in 2017, as compared to 2016. A summary of electric transmission capital expenditures by company is as follows:



	For the Years Ended December 31,
(Millions of Dollars)	2017		2016		2015
CL&P	$	431.5	$	338.3	$	252.9
NSTAR Electric	301.9		398.7		354.2
PSNH	155.6		119.0		161.2
NPT	43.3		40.9		38.3
Total Electric Transmission Segment	$	932.3	$	896.9	$	806.6

Northern Pass: Northern Pass is Eversource's planned 1,090 MW HVDC transmission line that will interconnect 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 has achieved several key milestones, including the following:


•	Receiving NHPUC approval on February 12, 2018 for the proposed lease of certain land and easement rights from PSNH to NPT, concluding that the lease is in the public interest;


•	Receiving the U.S. Forest Service Record of Decision on January 5, 2018, which allows NPT to install approximately 11 miles of underground transmission lines in areas along existing roads through the White Mountain National Forest;


•	Receiving the Province of Québec permit granted to HQ on December 21, 2017 to construct the hydroelectric transmission line that will connect at the border of New Hampshire;


•	Receiving the DOE Record of Decision and Presidential Permit on November 16, 2017, which will allow construction of transmission facilities at the Québec-New Hampshire border; and


•	Receiving the DOE final Environmental Impact Statement issued on August 10, 2017, which concluded that the proposed Northern Pass route is the preferred alternative, providing substantial benefits with only minimal impacts.

On January 25, 2018, Northern Pass was selected from the 46 proposals submitted as the winning bidder in the Massachusetts clean energy request for proposal ("RFP"), which successfully positioned Northern Pass to provide a firm delivery of hydropower to Massachusetts. On February 1, 2018, the NHSEC voted to deny Northern Pass’ siting application. On February 14, 2018, pursuant to the NHSEC’s decision, the Massachusetts EDCs, in coordination with the DOER and an independent evaluator, notified NPT that the EDCs will continue contract negotiations, with the option of discontinuing discussions and terminating its conditional selection by March 27, 2018.

Consistent with Eversource’s and HQ’s long-term relationship to bring clean energy into New England, Eversource and HQ continue to support Northern Pass and the many benefits this project will bring to our customers and region. We intend to seek reconsideration of the NHSEC’s decision and to review all options for moving this critical clean energy project forward.

As of December 31, 2017, we have approximately $277 million in capitalized costs associated with Northern Pass. We continue to believe that the Northern Pass project is probable of being placed in service. If in the future, events and changes in circumstances indicate that the Northern Pass project's capitalized costs may not be fully recoverable, we will then evaluate those costs for impairment. Should we conclude that these capitalized costs are impaired, this would have a significant negative impact on our financial position, results of operations, and cash flows.

For more information regarding the Massachusetts clean energy RFP, see "Regulatory Developments and Rate Matters – Massachusetts –Massachusetts RFPs" in this Management's Discussion and Analysis of Financial Condition and Results of Operations.

Greater Boston Reliability Solution: In February 2015, ISO-NE selected the Greater Boston and New Hampshire Solution (the "Solution"), proposed by Eversource and National Grid, to satisfy the requirements identified in the Greater Boston study. The Solution consists of a portfolio of electric transmission upgrades covering southern New Hampshire and northern Massachusetts and continuing into the greater Boston metropolitan area, of which 28 upgrades are in Eversource's service territory. The NHSEC issued its written order approving the New Hampshire upgrades on October 4, 2016. We are currently pursuing the necessary regulatory and siting application approvals in Massachusetts. To date, we have received approval for three of these projects from the Massachusetts Energy Facilities Siting Board. Construction has also begun on multiple smaller projects, several of which have been placed in service. All upgrades are expected to be completed by the end of 2019. We estimate our portion of the investment in the Solution will be approximately $560 million, of which $235.8 million has been capitalized through December 31, 2017.

GHCC: The Greater Hartford Central Connecticut ("GHCC") projects, which have been approved by ISO-NE, consist of 27 projects with an expected investment of approximately $350 million that are expected to be placed in service through 2019. As of December 31, 2017, 18 projects have been placed in service, and six projects are in active construction. As of December 31, 2017, CL&P had capitalized $210.0 million in costs associated with GHCC.

Seacoast Reliability Project: On April 12, 2016, PSNH filed a siting application with the NHSEC for the Seacoast Reliability Project, a 13-mile, 115kV transmission line within several New Hampshire communities, which proposes to use a combination of overhead, underground and underwater line design to help meet the growing demand for electricity in the Seacoast region. In June 2016, the NHSEC accepted our application as complete. The New Hampshire Department of Environmental Services has experienced delays with the issuance of permit conditions and now expects to complete its review in February 2018. As a result, siting hearings have yet to be rescheduled and we now expect the NHSEC decision in late-2018. This project is expected to be completed by the end of 2019. We estimate our investment in this project to be approximately $84 million, of which, PSNH had capitalized $24.5 million in costs, through December 31, 2017.

Distribution Business:

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



	For the Years Ended December 31,
(Millions of Dollars)	CL&P		NSTAR Electric		PSNH		Total Electric		Natural Gas		Total Electric and Natural Gas Distribution Segments
2017
Basic Business	$	214.0	$	166.1	$	67.2	$	447.3	$	67.7	$	515.0
Aging Infrastructure	180.7		95.4		87.8		363.9		219.9		583.8
Load Growth and Other	52.3		96.6		13.2		162.1		47.7		209.8
Total Distribution	447.0		358.1		168.2		973.3		335.3		1,308.6
Solar Power and Generation	—		100.1		8.5		108.6		—		108.6
Total	$	447.0	$	458.2	$	176.7	$	1,081.9	$	335.3	$	1,417.2

2016
Basic Business	$	179.8	$	146.0	$	70.0	$	395.8	$	70.7	$	466.5
Aging Infrastructure	144.7		105.7		84.7		335.1		155.9		491.0
Load Growth and Other	48.6		89.2		17.3		155.1		44.2		199.3
Total Distribution	373.1		340.9		172.0		886.0		270.8		1,156.8
Generation	—		—		17.5		17.5		—		17.5
Total	$	373.1	$	340.9	$	189.5	$	903.5	$	270.8	$	1,174.3

2015
Basic Business	$	141.1	$	126.9	$	59.2	$	327.2	$	46.8	$	374.0
Aging Infrastructure	151.0		121.6		57.3		329.9		122.3		452.2
Load Growth and Other	42.2		58.5		25.5		126.2		43.5		169.7
Total Distribution	334.3		307.0		142.0		783.3		212.6		995.9
Generation	—		—		33.3		33.3		—		33.3
Total	$	334.3	$	307.0	$	175.3	$	816.6	$	212.6	$	1,029.2

For the electric distribution business, basic business includes the purchase of meters, tools, vehicles, information technology, transformer replacements, equipment facilities, and the relocation of plant. Aging infrastructure relates to reliability and the replacement of overhead lines, plant substations, underground cable replacement, and equipment failures. Load growth and other includes requests for new business and capacity additions on distribution lines and substation additions and expansions. For the natural gas distribution business, basic business addresses daily operational needs including meters, pipe relocations due to public works projects, vehicles, and tools. Aging infrastructure projects seek to improve the reliability of the system through enhancements related to cast iron and bare steel replacement of main and services, corrosion mediation, and station upgrades. Load growth and other reflects growth in existing service territories including new developments, installation of services, and expansion.

The natural gas distribution segment's capital spending program increased by $64.5 million in 2017, as compared to 2016, primarily due to an increased investment in system replacement and reliability, as well as upgrades to our LNG facilities. We expect the LNG facility upgrades to cost approximately $200 million and to be placed in service in late 2019.

Projected Capital Expenditures: A summary of the projected capital expenditures for the regulated companies' electric transmission and for the total electric distribution, solar development and natural gas distribution businesses for 2018 through 2021, including information technology and facilities upgrades and enhancements on behalf of the regulated companies, is as follows:



	Years
(Millions of Dollars)	2018		2019		2020		2021		2018-2021 Total
CL&P Transmission	$	390	$	228	$	155	$	128	$	901
NSTAR Electric Transmission	333		293		267		248		1,141
PSNH Transmission	149		144		138		147		578
NPT	300		718		436		70		1,524
Total Electric Transmission	$	1,172	$	1,383	$	996	$	593	$	4,144
Electric Distribution	$	1,094	$	963	$	984	$	940	$	3,981
Solar Development	76		—		—		—		76
Natural Gas Distribution	422		425		380		389		1,616
Total Distribution	$	1,592	$	1,388	$	1,364	$	1,329	$	5,673
Water	$	100	$	102	$	108	$	125	$	435
Information Technology and All Other	$	178	$	124	$	111	$	112	$	525
Total	$	3,042	$	2,997	$	2,579	$	2,159	$	10,777

The projections do not include investments related to Bay State Wind. Actual capital expenditures could vary from the projected amounts for the companies and years above.

FERC Regulatory Issues

FERC ROE Complaints: Four separate complaints have been filed at the FERC by combinations of New England state attorneys general, state regulatory commissions, consumer advocates, consumer groups, municipal parties and other parties (collectively the "Complainants"). In each of the first three complaints, the Complainants challenged the NETOs' base ROE of 11.14 percent that had been utilized since 2005 and sought an order to reduce it prospectively from the date of the final FERC order and for the separate 15-month complaint periods. In the fourth complaint, filed April 29, 2016, the Complainants challenged the NETOs' base ROE of 10.57 percent and the maximum ROE for transmission incentive ("incentive cap") of 11.74 percent, asserting that these ROEs were unjust and unreasonable.

In response to appeals of the FERC decision in the first complaint filed by the NETOs and the Complainants, the U.S. Court of Appeals for the D.C. Circuit (the "Court") issued a decision on April 14, 2017 vacating and remanding the FERC's decision. The Court found that the FERC failed to make an explicit finding that the 11.14 percent base ROE was unjust and unreasonable, as required under Section 206 of the Federal Power Act, before it set a new base ROE. The Court also found that the FERC did not provide a rational connection between the record evidence and its decision to select the midpoint of the upper half of the zone of reasonableness for the new base ROE.

Hearings on the fourth complaint were held in December 2017 before the Administrative Law Judge ("ALJ"), who is expected to issue an initial decision in March 2018.

A summary of the four separate complaints and the base ROEs pertinent to those complaints are as follows:



Complaint	15-Month Time Period of Complaint (Beginning as of Complaint Filing Date)	Original Base ROE Authorized by FERC at Time of Complaint Filing Date (1)	Base ROE Subsequently Authorized by FERC for First Complaint Period and also Effective from October 16, 2014 through April 14, 2017 (1)	Reserve (Pre-Tax and Excluding Interest) as of December 31, 2017 (in millions)		FERC ALJ Recommendation of Base ROE on Second and Third Complaints (Issued March 22, 2016)
First	10/1/2011 - 12/31/2012	11.14%	10.57%	$—	(2)	N/A
Second	12/27/2012 - 3/26/2014	11.14%	N/A	39.1	(3)	9.59%
Third	7/31/2014 - 10/30/2015	11.14%	10.57%	—		10.90%
Fourth	4/29/2016 - 7/28/2017	10.57%	10.57%	—		N/A


(1)	The ROE billed during the period October 1, 2011 through October 15, 2014 consisted of a base ROE of 11.14 percent and incentives up to 13.1 percent. On October 16, 2014, the FERC set the base ROE at 10.57 percent and an incentive cap at 11.74 percent for the first complaint period and also effective from the date of the FERC order on October 16, 2014. This FERC order was vacated on April 14, 2017.

(1)

The ROE billed during the period October 1, 2011 through October 15, 2014 consisted of a base ROE of 11.14 percent and incentives up to 13.1 percent. On October 16, 2014, the FERC set the base ROE at 10.57 percent and an incentive cap at 11.74 percent for the first complaint period and also effective from the date of the FERC order on October 16, 2014. This FERC order was vacated on April 14, 2017.


(2)	CL&P, NSTAR Electric and PSNH have refunded all amounts associated with the first complaint period, totaling $38.9 million (pre-tax and excluding interest) at Eversource (consisting of $22.4 million at CL&P, $13.7 million at NSTAR Electric and $2.8 million at PSNH), reflecting both the base ROE and incentive cap prescribed by the FERC order.


(3)	The reserve represents the difference between the billed rates during the second complaint period and a 10.57 percent base ROE and 11.74 percent incentive cap. The reserve consisted of $21.4 million for CL&P, $14.6 million for NSTAR Electric and $3.1 million for PSNH as of December 31, 2017.

On June 5, 2017, the NETOs, including Eversource, submitted a filing to the FERC to reinstate the base ROE of 11.14 percent with an associated ROE incentive cap of 13.5 percent effective June 8, 2017, as these were the last ROEs lawfully in effect for transmission billing purposes prior to the FERC order vacated by the Court on April 14, 2017. On October 6, 2017, the FERC did not accept the NETOs filing, temporarily leaving in place the ROEs (10.57 percent base ROE with an 11.74 percent incentive cap ROE) set in the first complaint proceeding until the FERC addresses the Court’s decision. On November 6, 2017, the NETOs submitted a request for rehearing of the FERC’s October 6, 2017 Order rejecting the compliance filing.

On October 5, 2017, the NETOs filed a series of motions, requesting that the FERC dismiss the four complaint proceedings. Alternatively, if the FERC does not dismiss the proceedings, the NETOs requested that the FERC consolidate all four complaint proceedings for expeditious resolution and/or stay the trial in the fourth complaint proceeding and resolve it based on the standards set in the April 14, 2017 Court decision.

At this time, the Company cannot reasonably estimate a range of gain or loss for the complaint proceedings. No events in 2017 provided a reasonable basis for a change to the reserve balance of $39.1 million (pre-tax, excluding interest) for the second complaint period, and the Company has not changed its reserve or recognized ROEs for any of the complaint periods.

Management cannot at this time predict the ultimate effect of the Court decision or future FERC action on any of the complaint periods or the estimated impacts on the financial position, results of operations or cash flows of Eversource, CL&P, NSTAR Electric or PSNH.

The average impact of a 10 basis point change to the base ROE for each of the 15-month complaint periods would affect Eversource's after-tax earnings by approximately $3 million.

Regulatory Developments and Rate Matters

Electric, Natural Gas, and Water Utility Base Distribution Rates:

Each Eversource utility subsidiary is subject to the regulatory jurisdiction of the state in which it operates: CL&P, Yankee Gas and Aquarion operate in Connecticut and are subject to PURA regulation; NSTAR Electric, NSTAR Gas and Aquarion operate in Massachusetts and are subject to DPU regulation; and PSNH and Aquarion operate in New Hampshire and are 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, electric and natural gas utilities are required to file a distribution rate case, or for PURA to initiate a rate review, within four years of the last rate case. CL&P distribution rates were established in a 2014 PURA-approved rate case. On January 11, 2018, CL&P filed a distribution rate case settlement agreement for approval with PURA. See "Regulatory Developments and Rate Matters - Connecticut - CL&P Rate Case Settlement" in this Management's Discussion and Analysis of Financial Condition and Results of Operations, for more information. Yankee Gas distribution rates were established in a 2011 PURA-approved rate case. The requirement for Yankee Gas to file a base distribution rate case in 2015 was eliminated due to a rate review conducted by PURA and a resulting settlement in 2015 between Yankee Gas and PURA.

In Massachusetts, electric distribution companies are required to file at least one distribution rate case every five years, and natural gas local distribution 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. On November 30, 2017, the DPU approved the NSTAR Electric rate case application. See "Regulatory Developments and Rate Matters - Massachusetts - NSTAR Electric Distribution Rate Case Decision" in this Management's Discussion and Analysis of Financial Condition and Results of Operations, for more information. NSTAR Gas distribution rates were established in a 2015 DPU-approved rate case.

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 of those rates, and increased funding via rates, of PSNH's reliability enhancement program.

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 other 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 cost 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.

U.S. Federal Corporate Income Taxes: On December 22, 2017, the "Tax Cuts and Jobs Act" (the "Act") became law, which amended existing federal tax rules and included numerous provisions that impacted corporations. In particular, the Act reduced the U.S. federal corporate income tax rate from 35 percent to 21 percent effective January 1, 2018. For our regulated companies, the most significant changes will be (1) the benefit of incurring a lower federal income tax expense, which we expect to be passed back to customers, and (2) the provisional regulated excess ADIT liabilities that we expect to benefit our customers in future periods, which were estimated to be approximately $2.9 billion and recognized as regulatory liabilities as of December 31, 2017. We are currently working with our state regulatory commissions, who have opened investigations to examine the impact of the Act on customer rates. FERC has yet to address how the Act would impact transmission rates.

We will continue to evaluate the impacts of the Act on our statement of financial position, results of operations, and cash flows. The impacts will vary depending on the ultimate amount and timing of when certain income tax benefits will benefit our customers, and will vary by jurisdiction.

Connecticut:

CL&P Rate Case Settlement: On April 20, 2017, PURA approved the joint request of CL&P, the Connecticut Office of Consumer Counsel ("OCC") and the Connecticut Attorney General to amend the deadline to establish new electric distribution rates in the 2012 Connecticut merger settlement agreement from "no later than December 1, 2017" to "no later than July 1, 2018." On November 22, 2017, CL&P filed its application with PURA, which sought a rate increase of $255.8 million, $45.0 million and $36.0 million effective in May 2018, 2019, and 2020, respectively. On December, 15, 2017, CL&P, the Prosecutorial Unit of PURA, and the OCC reached a settlement in principle.

On January 11, 2018, CL&P filed a distribution rate case settlement agreement for approval by PURA, which included, among other things, rate increases of $97.1 million, $32.7 million and $24.7 million, effective May 1, 2018, 2019, and 2020, respectively, an authorized regulatory ROE of 9.25 percent, 53 percent common equity in CL&P's capital structure, and a new capital tracker through 2020 for capital additions, system resiliency, and grid modernization. The rate increases associated with the settlement agreement will be reduced by the impact of the decrease in the federal corporate income tax rate, as part of the "Tax Cuts and Jobs Act", which we currently estimate to average approximately $45 million to $50 million per year, while amounts related to ADIT will be addressed in a separate manner. We expect to receive final approval from PURA in the second quarter of 2018.

Clean Energy RFP: On January 31, 2018, pursuant to Section 8 of Public Act 13-303, "An Act Concerning Connecticut’s Clean Energy Goals," as amended by Section 10 of Public Act 17-144, “An Act Promoting the Use of Fuel Cells for Electric Distribution System Benefits and Reliability and Amending Various Energy-Related Programs and Requirements,” DEEP issued the Connecticut Clean Energy RFP, seeking bids from developers of qualified offshore wind, fuel cell and anaerobic digestion Class I resources. The maximum authorized procurement for qualified clean energy and RECs is 899,250 MWh per year, of which no more than 825,000 MWh per year may be provided by offshore wind, which in aggregate is the equivalent to the output of an approximate 200 MW facility. Energy deliveries under any resulting agreement must begin no earlier than July 1, 2019 and no later than December 31, 2025. The Connecticut EDC's, including CL&P, will be part of the evaluation team responsible for conducting an evaluation and ranking bids received. Eversource and Ørsted are expected to submit a bid in response to this RFP.

Massachusetts:

NSTAR Electric Distribution Rate Case Decision: On November 30, 2017, the DPU issued its decision in the NSTAR Electric distribution rate case, which approved an annual distribution rate increase of $37 million, with rates effective February 1, 2018. On January 3, 2018, NSTAR Electric filed a motion to reflect a revenue requirement reduction of $56 million (due to the decrease in the federal corporate income tax rate, as part of the "Tax Cuts and Jobs Act"), resulting in an annual net decrease in rates of $19 million.

In addition to its decision regarding rates, the DPU approved an authorized regulatory ROE of 10 percent, the establishment of a revenue decoupling rate mechanism for the portion of the NSTAR Electric business that did not previously have a decoupling mechanism, and the implementation of an inflation-based adjustment mechanism with a five-year stay-out until January 1, 2023.

Among other items, the DPU approved the recovery of previously expensed merger-related costs over a 10-year period and the recovery of previously deferred storm costs with carrying charges at the prime rate, but disallowed certain property taxes. The rate case decision resulted in the recognition of an aggregate $44.1 million pre-tax benefit recorded in 2017.

Eversource and NSTAR Electric Boston Harbor Civil Action: On July 15, 2016, the United States Attorney on behalf of the United States Army Corps of Engineers filed a civil action in the United States District Court for the District of Massachusetts under provisions of the Rivers and Harbors Act of 1899 and the Clean Water Act against NSTAR Electric, Harbor Electric Energy Company, a wholly-owned subsidiary of NSTAR Electric ("HEEC"), and the Massachusetts Water Resources Authority (together with NSTAR Electric and HEEC, the "Defendants"). The action alleged that the Defendants failed to comply with certain permitting requirements related to the placement of the HEEC-owned electric distribution cable beneath Boston Harbor. The action sought an order to compel HEEC to comply with cable depth requirements in the United States Army Corps of Engineers' permit or alternatively to remove the electric distribution cable and cease unauthorized work in U.S. waterways. The action also sought civil penalties and other costs.

The parties reached a settlement pursuant to which HEEC agreed to install a new 115kV distribution cable across Boston Harbor to Deer Island, utilizing a different route, and remove portions of the existing cable. Upon the installation and completion of the new cable and the removal of the portions of the existing cable, all issues surrounding the current permit from the United States Army Corps of Engineers are expected to be resolved, and such litigation is expected to be dismissed with prejudice.

In 2017, as a result of the settlement, NSTAR Electric expensed $4.9 million (pre-tax) of previously incurred capitalized costs associated with engineering work performed on the existing cable that will no longer be used. In addition, NSTAR Electric agreed to provide a rate base credit of $17.5 million to the Massachusetts Water Resources Authority for the new cable. This negotiated credit will result in the initial $17.5 million of construction costs on the new cable to be expensed as incurred. Of this amount, NSTAR Electric expensed $11.1 million (pre-tax) of costs incurred on the new cable in 2017. Construction of the new cable is expected to be completed in 2019.

Massachusetts RFPs: On March 31, 2017, pursuant to a comprehensive energy law enacted in 2016, "An Act to Promote Energy Diversity," (the "Act") the Massachusetts EDCs, including NSTAR Electric, and the DOER issued a joint RFP for 9.45 terawatt hours of clean energy per year, such as hydropower, land-based wind or solar. The RFP seeks proposals for long-term contracts of 15 to 20 years to provide the state's EDCs with clean energy generation with a submission due date of July 27, 2017.

On January 25, 2018, the Northern Pass project was selected from the 46 proposals submitted as a winning bidder. On February 1, 2018, the NHSEC voted to deny Northern Pass’ siting application. On February 14, 2018, pursuant to the NHSEC’s decision, the Massachusetts EDCs, in coordination with the DOER and an independent evaluator, notified NPT that the EDCs will continue contract negotiations, with the option of discontinuing discussions and terminating its conditional selection by March 27, 2018.

On June 29, 2017, pursuant to the Act, the Massachusetts EDCs, including NSTAR Electric, and the DOER issued a joint RFP for long-term contracts for offshore wind energy projects, seeking bids for a minimum of 400 MW of offshore wind capacity. The RFP stated that bids of up to 800 MW would be considered, provided they demonstrated significant net economic benefits to customers. On December 20, 2017, Bay State Wind submitted two proposals in response to the Massachusetts clean energy RFP to the EDCs. One proposal was for 400 MW and the other was for 800 MW. The selection of the winning proposals for further negotiation of power purchase agreements with the EDCs is currently expected to occur by April 23, 2018.

New Hampshire:

Generation Divestiture: In June 2015, Eversource and PSNH entered into the 2015 Public Service Company of New Hampshire Restructuring and Rate Stabilization Agreement, under the terms of which PSNH agreed to divest its generation assets, subject to NHPUC approval. The NHPUC approval for this agreement, as well as NHPUC approval of the final divestiture plan and auction process, were received in the second half of 2016. In October 2017, PSNH entered into two Purchase and Sale Agreements ("Agreements") to sell its thermal and hydroelectric generation assets to private investors at purchase prices of $175 million and $83 million, respectively, subject to adjustments as set forth in the Agreements. The NHPUC approved the Agreements in late November 2017.

On January 10, 2018, PSNH completed the sale of its thermal generation facilities. In accordance with the Purchase and Sale Agreement, the original purchase price of $175 million was adjusted to reflect working capital adjustments, closing date adjustments and proration of taxes and fees prior to closing, totaling $40.9 million, resulting in net proceeds of $134.1 million. We are targeting for PSNH to complete the sale of its hydroelectric generation facilities by the end of the first quarter of 2018 at a sale price of $83 million, subject to adjustment. On January 30, 2018, the NHPUC approved the issuance of rate reduction bonds up to $690 million to recover stranded costs, subject to an audit by the NHPUC Audit Staff. This order is subject to an appeal period of 30 days.

Upon completion of the divestiture, full recovery of PSNH's generation assets and transaction-related costs are expected to occur through a combination of cash flows during the remaining operating period, sales proceeds, and recovery of stranded costs via the issuance of bonds that will be secured by a non-bypassable charge or through recoveries in future rates billed to PSNH's customers.

Legislative and Policy Matters

Federal: On December 22, 2017, the "Tax Cuts and Jobs Act" (the "Act") became law, which amended existing federal tax rules and included numerous provisions that will impact corporations. In particular, the Act reduced the federal corporate income tax rate from 35 percent to 21 percent effective January 1, 2018. See "Regulatory Developments and Rate Matters - U.S. Federal Corporate Income Taxes" in this Management's Discussion and Analysis of Financial Condition and Results of Operations, for more information.

Massachusetts: On August 11, 2017, Massachusetts issued final legislation, pursuant to Executive Order 569, which established volumetric limits on multiple greenhouse emission sources to ensure reductions are realized by deadlines established in the Massachusetts Global Warming Solutions Act enacted in 2008. Under this legislation, the initial target date for reduction in greenhouse gas emissions has been established in the year 2020. The legislation is not expected to have a material impact on the financial statements of Eversource or NSTAR Electric.

New Hampshire: On January 11, 2018, the New Hampshire Supreme Court issued a decision affirming the lower court's October 2016 decision that the Town of Bow, New Hampshire had over-assessed the value of the property owned by PSNH for the 2012 and 2013 property tax years. We estimate that the result of this decision will be approximately $7.5 million in property taxes and interest payable to PSNH. PSNH plans to account for any recovery on the same basis that the taxes were originally expensed in the respective periods covered by the decision.

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 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.

Unbilled revenues are recognized by allocating estimated unbilled sales volumes to the respective customer classes, and then applying an estimated rate by customer class to those sales volumes. Unbilled revenues can vary significantly from period to period as a result of seasonality, weather, customer usage patterns, customer rates in effect for customer classes, and the timing of customer billing. The estimate of unbilled revenues can significantly impact the amount of revenues recorded at the operating companies that do not have a revenue decoupling mechanism. CL&P, NSTAR Electric and NSTAR Gas record a regulatory deferral to reflect the actual allowed amount of revenue associated with their respective decoupled distribution rate design.

Pension, SERP and PBOP: We sponsor Pension, SERP and PBOP Plans to provide retirement benefits to our employees. 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 and mortality and retirement assumptions. 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.

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, 2017, 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 2018 pension and PBOP expense, our expected long-term rate of return of 8.25 percent will be used reflecting our target asset allocations.

Discount Rate: Payment obligations related to the Pension, SERP 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 2017 pension, SERP 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, 2017, the discount rates used to determine the funded status were within a range of 3.43 percent to 3.75 percent for the Pension and SERP Plans, and within a range of 3.55 percent to 3.70 percent for the PBOP Plans. As of December 31, 2016, the discount rates used were within a range of 4.01 percent to 4.33 percent for the Pension and SERP Plans, and 4.21 percent for the PBOP Plan. The decrease in the discount rates used to calculate the funded status resulted in an increase to the Pension and PBOP Plans' liability of approximately $390 million and $64 million, respectively, as of December 31, 2017.

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, SERP 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 2017 service costs were within a range of 3.58 percent to 3.90 percent for the Pension and SERP Plans, and 4.64 percent for the PBOP Plans. The discount rates used to estimate the 2017 interest costs were within a range of 3.20 percent and 3.36 percent for the Pension and SERP Plans, and 3.48 percent for the PBOP Plans.

Mortality Assumptions: Assumptions as to mortality of the participants in our Pension, SERP 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. In 2017, the IRS issued a revised mortality table used for determining lump sum payments from the Pension Plan, resulting in an increase to the liability of approximately $38 million. Also in 2017, 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 revised mortality scale resulted in a decrease of approximately $26 million and $4 million for the Pension and PBOP Plans, respectively, as of December 31, 2017.

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 and SERP Plan participants receive in the future. As of December 31, 2017, the compensation/progression rate used to determine the funded status was within a range of 3.50 percent to 4.00 percent. As of December 31, 2016, this rate was 3.50 percent.

Health Care Cost: In August 2016, we amended the Eversource PBOP Plan to standardize benefit design and make benefit changes. As a result, this plan is no longer subject to health care cost trends.

Actuarial Determination of Expense: Pension, SERP 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. Pre-tax net periodic benefit expense for the Pension and SERP Plans was $64.9 million, $71.9 million and $134.7 million for the years ended December 31, 2017, 2016 and 2015, respectively. The pre-tax net periodic PBOP cost is income of $39.6 million and $17.9 million for the years ended December 31, 2017 and 2016, respectively, and expense of $2.4 million for the year ended December 31, 2015.

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 and SERP Plans will be approximately $45 million and income for the PBOP Plans will be approximately $45 million in 2018. Pension, SERP 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.

Our policy is to fund the Pension Plans annually in an amount at least equal to the amount that will satisfy all federal funding requirements. We contributed $235.2 million to the Pension Plans in 2017. We currently estimate contributing approximately $180 million to the Pension Plans in 2018.

For the PBOP Plans, it is our policy to fund the PBOP Plans annually through tax deductible contributions to external trusts. We contributed $7.6 million to the PBOP Plans in 2017. We currently estimate contributing $10 million to the PBOP Plans in 2018.

Sensitivity Analysis: The following represents the hypothetical increase to the Pension Plans' (excluding the SERP Plans) and PBOP Plans' 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	2017		2016		2017		2016
Lower expected long-term rate of return	$	20.4	$	19.5	$	4.1	$	3.9
Lower discount rate	19.7		20.7		3.6		3.9
Higher compensation rate	9.3		10.2		N/A		N/A

Goodwill: We recorded goodwill on our balance sheet associated with previous mergers and acquisitions. On December 4, 2017, we completed the acquisition of Aquarion, resulting in the addition of $0.9 billion of goodwill. As of December 31, 2017, a total of $4.4 billion of goodwill is recorded on our balance sheet. We have identified our reporting units for purposes of allocating and testing goodwill as Electric Distribution, Electric Transmission, Natural Gas Distribution and Water. 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 and PSNH. The Natural Gas Distribution reporting unit includes the carrying values of NSTAR Gas and Yankee Gas. The Water reporting unit was created upon completion of the acquisition of Aquarion and includes its water utility businesses. As of December 31, 2017, goodwill was allocated to the reporting units as follows: $2.5 billion to Electric Distribution, $0.6 billion to Electric Transmission, $0.4 billion to Natural Gas Distribution and $0.9 billion to Water.

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 amount 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, 2017 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 2017 goodwill impairment test resulted in a conclusion that goodwill is not impaired and no reporting unit is at risk of a goodwill impairment.

Long-Lived Assets: Impairment evaluations of long-lived assets, including property, plant and equipment and strategic, infrastructure and other investments, involve a significant degree of estimation and judgment, including identifying circumstances that indicate an impairment may exist. Impairment analysis is required when events or changes in circumstances indicate that the carrying value of a long-lived asset may not be recoverable. Indicators of potential impairment include a deteriorating business climate, unfavorable regulatory action, decline in value that is other than temporary in nature, plans to dispose of a long-lived asset significantly before the end of its useful life, and accumulation of costs that are in excess of amounts allowed for recovery. The review of long-lived assets for impairment utilizes significant assumptions about operating strategies and external developments, including assessment of current and projected market conditions that can impact future cash flows.

As of December 31, 2017, we did not identify any impairment indicators for our long-lived assets. If events or changes in circumstances indicate the carrying value of a long-lived asset may not be recoverable, we would perform an impairment analysis. An impairment analysis would consist of two steps: first, the estimated undiscounted future cash flows attributable to the asset would be compared with the carrying value of the asset, and second, if the carrying value is greater than the undiscounted future cash flows, an impairment charge would be recognized equal to the amount by which the carrying value of the asset exceeds its estimated fair value.

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.

On December 22, 2017, the "Tax Cuts and Jobs Act" (the "Act") became law, which amended existing federal tax rules and included numerous provisions that impacted corporations. In particular, the Act reduced the U.S. federal corporate income tax rate from 35 percent to 21 percent effective January 1, 2018. For our regulated companies, the most significant changes will be (1) the benefit of incurring a lower federal income tax expense, which we expect to be passed back to customers, and (2) the provisional regulated excess ADIT liabilities that we expect to benefit our customers in future periods, which were estimated to be approximately $2.9 billion and recognized as regulatory liabilities as of December 31, 2017.

We will continue to evaluate the impacts of the Act, which will vary depending on the ultimate amount and timing of when certain income tax benefits will benefit our customers, and will vary by jurisdiction. Although the impacts could not be finalized upon the issuance of this combined Annual Report on Form 10-K, reasonable provisional estimates were recognized as of December 31, 2017. In accordance with SEC Staff Accounting Bulletin No. 118 ("SAB 118"), additional re-measurement may occur based on final analyses, computations, technical corrections, or other forms of guidance issued from regulatory agencies or commissions. While we believe the impacts of the Act were appropriately accounted for in accordance with applicable authoritative guidance, the ultimate outcome may be different from the provisional estimates recorded, and those differences may materially impact our future statement of 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, for which we may have potential liability. 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 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 1D, "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, 2017, is summarized annually through 2022 and thereafter as follows:



Eversource
(Millions of Dollars)	2018		2019		2020		2021		2022		Thereafter		Total
Long-term debt maturities (a)	$	961.0	$	801.0	$	296.1	$	922.8	$	1,188.9	$	7,643.1	$	11,812.9
Estimated interest payments on existing debt (b)	446.4		417.4		378.9		361.5		328.9		2,994.5		4,927.6
Capital leases (c)	2.9		3.3		3.3		2.8		1.3		2.5		16.1
Operating leases (d)	13.2		11.4		10.0		8.9		7.4		19.7		70.6
Funding of pension obligations (d) (e)	180.0		—		—		—		—		—		180.0
Funding of PBOP obligations (d) (e)	10.0		—		—		—		—		—		10.0
Estimated future annual long-term contractual costs (f)	599.0		578.2		542.8		497.2		459.5		2,869.4		5,546.1
Total (g)	$	2,212.5	$	1,811.3	$	1,231.1	$	1,793.2	$	1,986.0	$	13,529.2	$	22,563.3



CL&P
(Millions of Dollars)	2018		2019		2020		2021		2022		Thereafter		Total
Long-term debt maturities (a)	$	300.0	$	250.0	$	—	$	—	$	—	$	2,515.3	$	3,065.3
Estimated interest payments on existing debt (b)	137.1		121.7		114.8		114.8		114.8		1,462.8		2,066.0
Capital leases (c)	2.0		2.0		2.0		1.4		—		—		7.4
Operating leases (d)	1.8		1.5		1.3		1.1		1.0		1.0		7.7
Funding of pension obligations (d) (e)	82.0		—		—		—		—		—		82.0
Estimated future annual long-term contractual costs (f)	177.9		175.4		198.2		187.8		175.6		836.9		1,751.8
Total (g)	$	700.8	$	550.6	$	316.3	$	305.1	$	291.4	$	4,816.0	$	6,980.2


(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 2017 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.

(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 2017 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 expected pension and PBOP contributions for 2018. Future contributions will vary depending on many factors, including the performance of existing plan assets, valuation of the plans' liabilities and long-term discount rates.


(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 Eversource's equity method investments, as we cannot make reasonable estimates of the periods or the investment contributions.

(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 Eversource's equity method investments, 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 13, "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, 2017 and 2016 included in this Annual Report on Form 10-K:



	For the Years Ended December 31,
(Millions of Dollars)	2017		2016		Increase/(Decrease)
Operating Revenues	$	7,752.0	$	7,639.1	$	112.9
Operating Expenses:
Purchased Power, Fuel and Transmission	2,535.3		2,500.8		34.5
Operations and Maintenance	1,277.1		1,323.5		(46.4		)
Depreciation	773.8		715.5		58.3
Amortization of Regulatory Assets, Net	90.0		71.7		18.3
Energy Efficiency Programs	480.8		533.7		(52.9		)
Taxes Other Than Income Taxes	676.8		634.0		42.8
Total Operating Expenses	5,833.8		5,779.2		54.6
Operating Income	1,918.2		1,859.9		58.3
Interest Expense	421.8		401.0		20.8
Other Income, Net	78.0		45.9		32.1
Income Before Income Tax Expense	1,574.4		1,504.8		69.6
Income Tax Expense	578.9		555.0		23.9
Net Income	995.5		949.8		45.7
Net Income Attributable to Noncontrolling Interests	7.5		7.5		—
Net Income Attributable to Common Shareholders	$	988.0	$	942.3	$	45.7

Operating Revenues

A summary of our Operating Revenues by segment was as follows:



	For the Years Ended December 31,
(Millions of Dollars)	2017			2016			Increase/(Decrease)
Electric Distribution	$	5,542.9		$	5,594.3		$	(51.4	)
Natural Gas Distribution	947.3			857.7			89.6
Electric Transmission	1,301.7			1,210.0			91.7
Other and Eliminations	(39.9		)	(22.9		)	(17.0		)
Total Operating Revenues	$	7,752.0		$	7,639.1		$	112.9

A summary of our retail electric GWh sales volumes and our firm natural gas sales volumes in MMcf and percentage changes was as follows:



	Electric						Firm Natural Gas
	For the Years Ended December 31,						For the Years Ended December 31,
	2017	2016	Decrease		Percent		2017	2016	Increase	Percent
Traditional	27,855	28,479	(624	)	(2.2	)%	46,957	45,314	1,643	3.6	%
Decoupled and Natural Gas Special Contracts	24,391	25,163	(772	)	(3.1	)%	54,069	52,728	1,341	2.5	%
Total Sales Volumes	52,246	53,642	(1,396	)	(2.6	)%	101,026	98,042	2,984	3.0	%

Fluctuations in sales volumes at certain of the electric and natural gas utilities impact earnings ("Traditional" in the table above). Fluctuations in CL&P's, NSTAR Electric's (for a portion of its sales volumes as of December 31, 2017) and NSTAR Gas' sales volumes do not impact the level of base distribution revenue realized or earnings due to the commission-approved revenue decoupling mechanisms ("Decoupled and Natural Gas Special Contracts" in the table above). The revenue decoupling mechanisms permit recovery of a base amount of distribution revenues and breaks the relationship between sales volumes and revenues recognized. Effective February 1, 2018, all of NSTAR Electric's distribution revenues were decoupled as a result of the DPU-approved rate case decision.

Operating Revenues, which primarily consist of base electric and natural gas distribution revenues and tracked revenues further described below, increased by $112.9 million in 2017, as compared to 2016.

Base electric and natural gas distribution revenues: Base electric distribution segment revenues, excluding LBR, decreased $12.3 million in 2017, as compared to 2016, due primarily to a decrease in sales volumes driven by the mild summer weather in 2017 at our non-decoupled electric companies. LBR increased $13.0 million in 2017, as compared to 2016. Effective February 1, 2018, NSTAR Electric no longer has an LBR mechanism. Base natural gas distribution revenues increased $2.9 million in 2017, as compared to 2016. The impact of higher firm natural gas

sales volumes, which was driven by colder winter weather in the fourth quarter of 2017, was partially offset by lower demand revenues in Connecticut driven by lower peak usage in 2017, as compared to 2016.

Tracked natural gas distribution segment revenues increased as a result of an increase in natural gas supply costs ($68.7 million) and an increase in energy efficiency program revenues ($18.1 million). Tracked electric distribution revenues decreased as a result of a decrease in electric energy supply costs ($21.7 million), driven by decreased average retail prices and lower sales volumes, a decrease in retail electric transmission charges ($14.8 million), a decrease in transition and stranded cost recovery revenues ($46.2 million), a decrease in pension rate adjustment mechanisms ($21.6 million), a decrease in revenues related to the timing of the sale of PSNH's RECs ($16.3 million), and a decrease in energy efficiency program revenues ($10.4 million). Partially offsetting these decreases were increases in tracked electric distribution revenues related to federally-mandated congestion charges ($30.1 million), net metering revenues ($29.8 million) and revenues related to renewable energy requirements ($41.9 million).

Electric transmission revenues: The electric transmission segment revenues increased by $91.7 million due primarily to the recovery of higher revenue requirements associated with ongoing investments in our transmission infrastructure.

Other: Other revenues decreased due primarily to the sale of Eversource's unregulated telecommunication business on December 31, 2016 ($20.0 million), partially offset by the addition of Aquarion revenues due to the acquisition on December 4, 2017 ($15.9 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 commission-approved cost tracking mechanisms, which have no impact on earnings (tracked costs). Purchased Power, Fuel and Transmission expense increased in 2017, as compared to 2016, due primarily to the following:



(Millions of Dollars)	(Decrease)/Increase
Electric Distribution	$	(68.9	)
Natural Gas Distribution	59.5
Transmission	43.9
Total Purchased Power, Fuel and Transmission	$	34.5

The decrease in purchased power expense at the electric distribution business in 2017, as compared to 2016, was driven primarily by lower prices associated with the procurement of energy supply and lower sales volumes. The increase in purchased power expense at the natural gas distribution business was due to higher average natural gas prices and higher sales volumes. The increase in transmission costs in 2017, as compared to 2016, was primarily the result of an increase in costs billed by ISO-NE that support regional grid investment, and Local Network Service charges, which reflect the cost of transmission service provided by Eversource over our local transmission network. This was partially offset by 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 electric and natural gas distribution rates with changes impacting earnings (non-tracked costs). Operations and Maintenance expense decreased in 2017, as compared to 2016, due primarily to the following:



(Millions of Dollars)	Increase/(Decrease)
Base Electric Distribution:
Employee-related expenses, including labor and benefits	$	(47.4	)
Bad debt expense	(14.5		)
Shared corporate costs (including computer software depreciation at Eversource Service)	24.2
Boston Harbor civil action settlement charges	16.0
Other non-tracked operations and maintenance	7.4
Total Base Electric Distribution	(14.3		)
Base Natural Gas Distribution	3.7
Tracked costs (Electric Distribution, Electric Transmission and Natural Gas Distribution):
Absence in 2017 of earnings benefit related to merger-related costs allowed for recovery through transmission rates	27.5
Other tracked operations and maintenance	(15.4		)
Total Tracked costs (Electric Distribution, Electric Transmission and Natural Gas Distribution)	12.1
Other and eliminations:
Merger-related costs allowed for recovery through NSTAR Electric distribution rates as a result of the November 30, 2017 DPU distribution rate case decision (earnings benefit)	(30.5		)
Addition of Aquarion operations and maintenance expenses due to acquisition on December 4, 2017	7.2
Eversource Parent and Other Companies - other operations and maintenance	8.2
Eliminations	(32.8		)
Total Operations and Maintenance	$	(46.4	)

Depreciation expense increased in 2017, as compared to 2016, due primarily to higher utility plant in service balances.

Amortization of Regulatory Assets, Net expense includes the deferral of energy supply and energy-related costs included in certain regulatory-approved tracking mechanisms, and the amortization of certain costs. The deferral adjusts expense to match the corresponding revenues. Amortization of Regulatory Assets, Net increased in 2017, as compared to 2016, due primarily to the deferral of energy supply and energy-related costs which can fluctuate from period to period based on the timing of costs incurred and the related rate changes to recover these costs. Energy supply and energy-related costs at the electric and natural gas companies are recovered from customers in rates and have no impact on earnings.

Energy Efficiency Programs expense decreased in 2017, as compared to 2016, due primarily to a State of Connecticut policy change impacting CL&P requiring the remittance of $25.4 million of 2017 energy efficiency funds to the State (resulting in these costs being classified as Taxes Other than Income Taxes), and the deferral adjustment at NSTAR Electric. The deferral adjustment reflects the actual costs of energy efficiency programs compared to the estimated amounts billed to customers. The deferral adjusts costs incurred to match energy efficiency revenue billed to customers and the timing of the recovery of energy efficiency costs. The costs for various state energy policy initiatives and expanded energy efficiency programs are recovered from customers in rates and have no impact on earnings.

Taxes Other Than Income Taxes expense increased in 2017, as compared to 2016, due primarily to a State of Connecticut policy change requiring $25.4 million of 2017 CL&P energy efficiency costs to be remitted to the State of Connecticut that is included in Taxes Other than Income Taxes, an increase in property taxes as a result of higher utility plant balances, partially offset by a decrease in gross earnings taxes. Gross earnings taxes are recovered from customers in rates and have no impact on earnings.

Interest Expense increased in 2017, as compared to 2016, due primarily to an increase in interest on long-term debt ($30.3 million) as a result of new debt issuances and an increase in interest on notes payable ($5.1 million), partially offset by a decrease in regulatory deferrals, primarily at NSTAR Electric, which decreased interest expense ($14.7 million) due primarily to the November 30, 2017 NSTAR Electric DPU distribution rate case decision which allowed for a higher rate on carrying charges for past storm costs.

Other Income, Net increased in 2017, as compared to 2016, due primarily to increased gains on investments ($27.2 million), primarily related to Eversource's investment in a renewable energy fund, changes in the market value related to deferred compensation plans ($8.3 million) and higher AFUDC related to equity funds ($8.2 million). Partially offsetting these favorable impacts was the absence in 2017 of a gain on the sale of an unregulated business in 2016 ($11.8 million) and lower interest income ($3.3 million).

Income Tax Expense increased in 2017, as compared to 2016, due primarily to higher pre-tax earnings ($29.1 million), lower excess tax benefit ($16.2 million), the absence of tax credits in 2017 ($3.5 million), and the impact from federal tax rate change ($0.5 million), partially offset by items that impact our tax rate as a result of regulatory treatment (flow-through items) and permanent differences ($11.4 million), the sale of an unregulated business in 2016 ($10.2 million), and lower state taxes ($3.8 million).

RESULTS OF OPERATIONS –

THE CONNECTICUT LIGHT AND POWER COMPANY

NSTAR ELECTRIC COMPANY AND SUBSIDIARY

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 CL&P, NSTAR Electric and PSNH for the years ended December 31, 2017 and 2016 included in this Annual Report on Form 10-K:



	For the Years Ended December 31,
	CL&P							NSTAR Electric							PSNH
(Millions of Dollars)	2017		2016		Increase/(Decrease)			2017		2016		Increase/(Decrease)			2017			2016		Increase/(Decrease)
Operating Revenues	$	2,887.4	$	2,806.0	$	81.4		$	2,980.6	$	3,041.6	$	(61.0	)	$	981.6		$	959.5	$	22.1
Operating Expenses:
Purchased Power, Fuel and Transmission	930.8		919.7		11.1			1,025.4		1,084.3		(58.9		)	237.5			210.8		26.7
Operations and Maintenance	500.4		490.1		10.3			463.7		489.9		(26.2		)	257.2			260.8		(3.6		)
Depreciation	249.4		230.5		18.9			274.0		259.3		14.7			128.2			116.5		11.7
Amortization of Regulatory Assets/ (Liabilities), Net	83.2		38.8		44.4			33.8		34.3		(0.5		)	(16.6		)	11.2		(27.8		)
Energy Efficiency Programs	114.7		154.0		(39.3		)	294.1		321.8		(27.7		)	13.8			14.2		(0.4		)
Taxes Other Than Income Taxes	323.8		299.7		24.1			182.0		177.8		4.2			89.7			82.9		6.8
Total Operating Expenses	2,202.3		2,132.8		69.5			2,273.0		2,367.4		(94.4		)	709.8			696.4		13.4
Operating Income	685.1		673.2		11.9			707.6		674.2		33.4			271.8			263.1		8.7
Interest Expense	143.0		144.1		(1.1		)	105.7		108.4		(2.7		)	51.0			50.0		1.0
Other Income, Net	21.2		13.5		7.7			14.9		10.8		4.1			3.9			1.2		2.7
Income Before Income Tax Expense	563.3		542.6		20.7			616.8		576.6		40.2			224.7			214.3		10.4
Income Tax Expense	186.6		208.3		(21.7		)	242.1		225.8		16.3			88.7			82.3		6.4
Net Income	$	376.7	$	334.3	$	42.4		$	374.7	$	350.8	$	23.9		$	136.0		$	132.0	$	4.0

Operating Revenues

A summary of our retail electric GWh sales volumes was as follows:



	Rate	For the Years Ended December 31,
	Structure	2017	2016	Decrease		Percent
CL&P	Decoupled	20,950	21,617	(667	)	(3.1	)%
NSTAR Electric (eastern Massachusetts)	Traditional	20,097	20,619	(522	)	(2.5	)%
NSTAR Electric (western Massachusetts)	Decoupled	3,441	3,546	(105	)	(3.0	)%
PNSH	Traditional	7,758	7,860	(102	)	(1.3	)%

Fluctuations in retail electric sales volumes at certain of the electric utilities impact earnings ("Traditional" in the table above). For others, fluctuations in retail electric sales volumes do not impact earnings due to their regulatory commission-approved distribution revenue decoupling mechanisms ("Decoupled" in the table above). These distribution revenues are decoupled from their customer sales volumes, which breaks the relationship between sales volumes and revenues recognized.

In 2017 and 2016, NSTAR Electric operated under two different rate structures based on its service territory geography. For customers that were served in eastern Massachusetts, including metropolitan Boston, Cape Cod and Martha's Vineyard, NSTAR Electric operated using traditional rates. For customers that were served in western Massachusetts, including the metropolitan Springfield region, NSTAR Electric operated using decoupled rates. Effective February 1, 2018, all of NSTAR Electric's distribution revenues were decoupled as a result of the DPU-approved rate decision. See "Regulatory Developments and Rate Matters - Massachusetts - NSTAR Electric Distribution Rate Case Decision" in this Management's Discussion and Analysis of Financial Condition and Results of Operations.

CL&P and NSTAR Electric (for its western Massachusetts customer rates) reconcile their annual base distribution rate recovery amounts to their pre-established levels of baseline distribution delivery service revenues of $1.059 billion and $132.4 million, respectively, through December 31, 2017. Effective February 1, 2018, NSTAR Electric, operating entirely under decoupled rates, will reconcile its annual base distribution rate recovery to its new baseline of $974.8 million. Any difference between the allowed level of distribution revenue and the actual amount realized during a 12-month period is adjusted through rates in the following period.

Operating Revenues, which consist of base distribution revenues and tracked revenues further described below, increased/(decreased) in 2017, as compared to 2016 as follows:



(Millions of Dollars)	CL&P		NSTAR Electric			PSNH
Operating Revenues	$	81.4	$	(61.0	)	$	22.1

Base Distribution Revenues, with changes that impact earnings:


•	NSTAR Electric's base distribution revenues, excluding LBR, decreased $10.8 million in 2017, as compared to 2016, as a result of lower sales volumes driven by the mild summer weather in 2017. LBR increased $13.0 million in 2017, as compared to 2016. Effective February 1, 2018, NSTAR Electric no longer has an LBR mechanism.


•	PSNH's base distribution revenues decreased $1.5 million in 2017, as compared to 2016, as a result of lower sales volumes driven by the mild summer weather in 2017.

Tracked Revenues: 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 commission-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, net metering for distributed generation and restructuring and stranded cost recovery revenues. In addition, tracked revenues include certain incentives earned and carrying charges. Tracked revenues increased/(decreased) in 2017, as compared to 2016, due primarily to the following:



(Millions of Dollars)	CL&P		NSTAR Electric			PSNH
Energy supply procurement	$	18.8	$	(50.8	)	$	10.3
All other distribution tracking mechanisms	35.0		(33.7		)	(12.7		)

Transmission Revenues: Transmission revenues increased by $34.2 million, $31.0 million and $26.5 million at CL&P, NSTAR Electric and PSNH, respectively, due primarily to higher revenue requirements associated with ongoing investments in our transmission infrastructure.

Purchased Power, Fuel and Transmission expense includes costs associated with purchasing electricity on behalf of CL&P, NSTAR Electric and PSNH's customers. For PSNH, these costs also include PSNH's generation of electricity. These energy supply costs are recovered from customers in commission-approved cost tracking mechanisms, which have no impact on earnings (tracked costs). Purchased Power, Fuel and Transmission expense increased/(decreased) in 2017, as compared to 2016, due primarily to the following:



(Millions of Dollars)	CL&P			NSTAR Electric			PSNH
Purchased Power Costs	$	(41.4	)	$	(27.9	)	$	3.7
Transmission Costs	52.5			(31.0		)	23.0
Total Purchased Power, Fuel and Transmission	$	11.1		$	(58.9	)	$	26.7

Purchased Power Costs: Included in purchased power costs are the costs associated with certain energy supply tracking mechanisms and deferred energy supply costs. Energy supply tracking mechanisms recover energy-related costs incurred as a result of providing electric generation service supply to all customers who have not migrated to third party suppliers. In order to meet the demand of customers who have not migrated to third party suppliers, PSNH procures power through power supply contracts and spot purchases in the competitive New England wholesale power market and/or produces power through its own generation. The increase/(decrease) in purchased power costs in 2017, as compared to 2016, was due primarily to the following:


•	The decrease at CL&P was due primarily to a decrease in the price of standard offer supply associated with the GSC.


•	The decrease at NSTAR Electric was due primarily to lower prices associated with the procurement of energy supply, lower sales volumes and the expiration of certain purchase power agreements.


•	The increase at PSNH was due primarily to higher purchased power energy expenses that are recovered as a component of the Energy Service rate, and Regional Greenhouse Gas Initiative related expenses recovered in the SCRC.

Transmission Costs: Included in transmission costs are charges that recover the cost of transporting electricity over high-voltage lines from generating plants to substations, including costs allocated by ISO-NE to maintain the wholesale electric market. The increase/(decrease) in transmission costs in 2017, as compared to 2016, was due primarily to the following:


•	The increase at CL&P was primarily the result of an increase in costs billed by ISO-NE that support regional grid investment, Local Network Service charges, which reflect the cost of transmission service, and the retail transmission cost deferral, which reflects the actual costs of transmission service compared to estimated amounts billed to customers.


•	The decrease at NSTAR Electric was primarily the result of a decrease in the retail transmission cost deferral. This was partially offset by an increase in costs billed by ISO-NE.


•	The increase at PSNH was primarily the result of increases in costs billed by ISO-NE, Local Network Service charges, and the retail transmission cost deferral.

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 expense increased/(decreased) in 2017, as compared to 2016, due primarily to the following:



(Millions of Dollars)	CL&P			NSTAR Electric			PSNH
Base Electric Distribution (Non-Tracked Costs):
Employee-related expenses, including labor and benefits	$	(4.5	)	$	(36.6	)	$	(6.3	)
Bad debt expense	(6.8		)	(7.5		)	(0.2		)
Shared corporate costs (including computer software depreciation at Eversource Service)	7.8			12.6			3.8
Boston Harbor civil action settlement charges	—			16.0			—
Other non-tracked operations and maintenance	8.8			0.6			(2.0		)
Total Base Electric Distribution (Non-Tracked Costs)	5.3			(14.9		)	(4.7		)
Tracked Costs:
Employee-related expenses, including labor and benefits	1.3			(16.2		)	(0.5		)
Other tracked operations and maintenance	3.7			4.9			1.6
Total Tracked Costs	5.0			(11.3		)	1.1
Total Operations and Maintenance	$	10.3		$	(26.2	)	$	(3.6	)

Depreciation increased at CL&P, NSTAR Electric and PSNH in 2017, as compared to 2016, due primarily to higher utility plant in service balances.

Amortization of Regulatory Assets/(Liabilities), Net expense includes the deferral of energy supply and energy-related costs and the amortization of storm and other costs. Amortization of Regulatory Assets/(Liabilities), Net increased at CL&P and decreased for both NSTAR Electric and PSNH in 2017, as compared to 2016, due primarily to the deferral adjustment 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. The deferral adjusts expense to match the corresponding revenues. Energy supply and energy-related costs, which are the primary drivers of amortization, are recovered from customers in rates and have no impact on earnings.

Energy Efficiency Programs expense includes costs for various state policy initiatives and are recovered from customers in rates and have no impact on earnings. Energy Efficiency Programs expense decreased in 2017, as compared to 2016, due primarily to the following:


•	The decrease at CL&P is due primarily to a State of Connecticut policy change requiring the remittance of $25.4 million of 2017 energy efficiency funds to the State. These amounts collected from customers were reclassified to Taxes Other than Income Taxes.


•	The decrease at NSTAR Electric is due to the deferral adjustment, which reflects the actual cost of energy efficiency programs compared to the estimated amounts billed to customers and the timing of the recovery of energy efficiency costs. The deferral adjusts costs to match energy efficiency revenue billed to customers.

Taxes Other Than Income Taxes increased in 2017, as compared to 2016, due primarily to the following:


•	The increase at CL&P is due primarily to a State of Connecticut policy change requiring the remittance of $25.4 million of 2017 energy efficiency funds to the State and higher utility plant balances, partially offset by a decrease in gross earnings taxes. Gross earnings taxes are recovered from customers in rates and have no impact on earnings.


•	The increase at NSTAR Electric is due primarily to higher property taxes resulting from disallowed costs in the November 30, 2017 NSTAR Electric DPU distribution rate case decision and higher employee-related payroll taxes, partially offset by a decrease in property tax rates in Boston.


•	The increase at PSNH is due to an increase in property taxes as a result of higher utility plant balances.

Interest Expense at NSTAR Electric decreased in 2017, as compared to 2016, due primarily to lower deferred regulatory interest expense ($14.0 million), primarily as a result of the November 30, 2017 NSTAR Electric DPU distribution rate case decision, which allowed for a higher interest rate on carrying charges for past storm costs, partially offset by an increase in interest on long-term debt ($9.6 million).

Other Income, Net increased in 2017, as compared to 2016, due primarily to the following:


•	The increase at CL&P is due to higher AFUDC related to equity funds ($5.9 million) and market value changes related to the deferred compensation plans ($6.3 million), partially offset by lower interest income ($4.4 million).


•	The increase at NSTAR Electric is due to market value changes related to the deferred compensation plans ($1.6 million), an increase in amounts related to officer life insurance policies ($1.3 million) and an increase in interest income ($1.2 million).


•	The increase at PSNH is due to market value changes related to the deferred compensation plans ($1.5 million).

Income Tax Expense increased/(decreased) in 2017, as compared to 2016, due primarily to the following:

•

The decrease at CL&P is due primarily to the tax reform impacts on the federal tax effect of state reserves and credits ($10.7 million), items that impact our tax rate as a result of regulatory treatment (flow-through items) and permanent differences ($10.1 million), the true up of the return to provision impacts ($2.6 million), and lower state taxes ($5.5 million), partially offset by higher pre-tax earnings ($7.2 million).


•	The increase at NSTAR Electric is due primarily to higher pre-tax earnings ($14.5 million), higher state taxes ($2.4 million), partially offset by items that impact our tax rate as a result of flow-through items and permanent differences ($0.6 million).


•	The increase at PSNH is due primarily to higher pre-tax earnings ($3.6 million) and the absence of tax credits in 2017 ($3.5 million), partially offset by items that impact our tax rate as a result of flow-through items and permanent differences ($0.7 million).

EARNINGS SUMMARY

CL&P's earnings increased $42.4 million in 2017, as compared to 2016, due primarily to a lower effective tax rate, an increase in transmission earnings driven by a higher transmission rate base, and higher distribution revenues due in part to a higher rate base for the system resiliency program. These favorable earnings impacts were partially offset by higher depreciation expense, higher operations and maintenance expense, and higher property tax expense.

NSTAR Electric's earnings increased $23.9 million in 2017, as compared to 2016, due primarily to higher distribution revenues related to lost base revenues, net metering and the PAM, lower operations and maintenance expense, lower interest expense as a result of the November 30, 2017 NSTAR Electric distribution rate case decision, and an increase in transmission earnings driven by a higher transmission rate base. These favorable earnings impacts were partially offset by lower sales volumes driven by the mild summer weather in 2017, higher depreciation expense, and higher property tax expense.

PSNH's earnings increased $4.0 million in 2017, as compared to 2016, due primarily to an increase in transmission earnings driven by a higher transmission rate base and lower operations and maintenance expense. These favorable earnings impacts were partially offset by lower generation earnings, higher depreciation expense, higher property tax expense, lower sales volumes driven by the mild summer weather in 2017, and a higher effective tax rate.

LIQUIDITY

CL&P:

Cash totaled $6.0 million as of December 31, 2017, compared with $6.6 million as of December 31, 2016.

CL&P had cash flows provided by operating activities of $804.6 million in 2017, compared with $811.5 million in 2016. The decrease in operating cash flows was due primarily to income tax payments of $68.8 million made in 2017, compared to the income tax refunds of $73.9 million received in 2016. Partially offsetting this decrease was the timing of regulatory recoveries, an increase in distribution rates due to higher rate base, and the timing of collections and payments related to our working capital items.

Eversource parent has a $1.45 billion commercial paper program allowing Eversource parent to issue commercial paper as a form of short-term debt, with intercompany loans to certain subsidiaries, including CL&P. The weighted-average interest rate on the commercial paper borrowings as of December 31, 2017 and 2016 was 1.86 percent and 0.88 percent, respectively. As of December 31, 2017 and 2016, there were intercompany loans from Eversource parent to CL&P of $69.5 million and $80.1 million, respectively. Eversource parent, and certain of its subsidiaries, including CL&P, are parties to a five-year $1.45 billion revolving credit facility. On December 8, 2017, Eversource parent amended and restated the revolving credit facility. The amended and restated credit facility terminates on December 8, 2022 and serves to backstop Eversource parent's $1.45 billion commercial paper program. There were no borrowings outstanding on the revolving credit facility as of December 31, 2017 or 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 $824.4 million in 2017, compared with $612.0 million in 2016.

Financing activities in 2017 included $254.8 million in common stock dividends paid to Eversource parent.

NSTAR Electric:

NSTAR Electric had cash flows provided by operating activities of $638.4 million in 2017, as compared to $808.7 million in 2016. The decrease in operating cash flows was due primarily to a decrease in regulatory recoveries, which were significantly impacted by the timing of collections of purchased power and transmission costs, an increase of $53.4 million in Pension and PBOP Plan cash contributions and an increase of $29.5 million in income tax payments made in 2017, compared to 2016. Also contributing to the decrease was the timing of working capital items, including accounts payable and inventory.

NSTAR Electric has a $650.0 million commercial paper program allowing NSTAR Electric to issue commercial paper as a form of short-term debt. On December 8, 2017, NSTAR Electric increased its commercial paper program from $450 million to $650 million. As of December 31, 2017 and 2016, NSTAR Electric had $234.0 million and $126.5 million, respectively, in short-term borrowings outstanding under its commercial paper program, leaving $416.0 million and $323.5 million of available borrowing capacity as of December 31, 2017 and 2016, respectively. The weighted-average interest rate on these borrowings as of December 31, 2017 and 2016 was 1.55 percent and 0.71 percent, respectively. NSTAR Electric is also a party to a five-year $650.0 million revolving credit facility. On December 8, 2017, NSTAR Electric amended and restated the revolving credit facility, increasing it from $450 million to $650 million. The amended and restated credit facility terminates on December 8, 2022 and serves to backstop NSTAR Electric's $650.0 million commercial paper program. There were no borrowings outstanding on the revolving credit facility as of December 31, 2017 or 2016.

PSNH:

PSNH had cash flows provided by operating activities of $300.9 million in 2017, as compared to $361.8 million in 2016. The decrease in operating cash flows was due primarily to the income tax payments of $26.1 million made in 2017, compared to the income tax refunds of $36.0 million received in 2016 and the unfavorable impacts related to the timing of regulatory recoveries. Partially offsetting these decreases were the timing of collections and payments of our working capital items, including accounts payable and inventory, and a $16.3 million decrease in Pension Plan cash contributions.

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, 2016 and 2015 included in this Annual Report on Form 10-K:



	For the Years Ended December 31,
(Millions of Dollars)	2016		2015		Increase/(Decrease)			Percent
Operating Revenues	$	7,639.1	$	7,954.8	$	(315.7	)	(4.0	)%
Operating Expenses:
Purchased Power, Fuel and Transmission	2,500.8		3,086.9		(586.1		)	(19.0	)
Operations and Maintenance	1,323.5		1,329.3		(5.8		)	(0.4	)
Depreciation	715.5		665.9		49.6			7.4
Amortization of Regulatory Assets, Net	71.7		22.3		49.4			(a)
Energy Efficiency Programs	533.7		495.7		38.0			7.7
Taxes Other Than Income Taxes	634.0		590.5		43.5			7.4
Total Operating Expenses	5,779.2		6,190.6		(411.4		)	(6.6	)
Operating Income	1,859.9		1,764.2		95.7			5.4
Interest Expense	401.0		372.4		28.6			7.7
Other Income, Net	45.9		34.2		11.7			34.2
Income Before Income Tax Expense	1,504.8		1,426.0		78.8			5.5
Income Tax Expense	555.0		540.0		15.0			2.8
Net Income	949.8		886.0		63.8			7.2
Net Income Attributable to Noncontrolling Interests	7.5		7.5		—			—
Net Income Attributable to Common Shareholders	$	942.3	$	878.5	$	63.8		7.3	%

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

Operating Revenues

A summary of our Operating Revenues by segment was as follows:



	For the Years Ended December 31,
(Millions of Dollars)	2016			2015			Increase/(Decrease)			Percent
Electric Distribution	$	5,594.3		$	5,903.6		$	(309.3	)	(5.2	)%
Natural Gas Distribution	857.7			995.5			(137.8		)	(13.8	)
Electric Transmission	1,210.0			1,069.1			140.9			13.2
Other and Eliminations	(22.9		)	(13.4		)	(9.5		)	70.9
Total Operating Revenues	$	7,639.1		$	7,954.8		$	(315.7	)	(4.0	)%

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



	For the Years Ended December 31,
	2016	2015	Decrease		Percent
Electric
Traditional	28,479	28,982	(503	)	(1.7	)%
Decoupled	25,163	25,634	(471	)	(1.8	)
Total Electric	53,642	54,616	(974	)	(1.8	)%

Firm Natural Gas
Traditional	45,314	47,600	(2,286	)	(4.8	)%
Decoupled and Special Contracts	52,728	55,399	(2,671	)	(4.8	)
Total Firm Natural Gas	98,042	102,999	(4,957	)	(4.8	)%

Operating Revenues, which primarily consist of base electric and natural gas distribution revenues and tracked revenues further described below, decreased by $315.7 million in 2016, as compared to 2015.

Base electric and natural gas distribution revenues: Base electric distribution segment revenues increased by $19.9 million due primarily to a higher rate base resulting from the 2015 PURA ADIT settlement agreement that is being collected from customers in distribution rates at CL&P ($26.1 million) and the absence of a required ROE reduction in 2015, as stipulated in the PURA 2014 rate case decision, at CL&P ($4 million). This increase was partially offset by the absence of the benefit recognized in 2015 in Operating Revenues due to the PURA ADIT settlement agreement. In addition, traditional electric base distribution revenues decreased $10.1 million due to a 1.7 percent decrease in non-decoupled retail electric sales volumes due primarily to increased customer energy conservation efforts, partly offset by PSNH distribution rate increases effective July 1, 2015 and July 1, 2016.

Contributing to the decrease in Operating Revenues in 2016 was the absence of an $11 million benefit related to the Comprehensive Settlement Agreement associated with the recovery of LBR related to 2009 through 2011 energy efficiency programs recorded at NSTAR Electric in 2015.

Firm natural gas base distribution segment revenues increased $11.7 million due primarily to the impact of the NSTAR Gas base distribution rate increase effective January 1, 2016, partially offset by a 4.8 percent decrease in traditional firm natural gas sales volumes as a result of warmer than normal weather experienced in the first quarter of 2016, as compared to much colder than normal temperatures in 2015.

Fluctuations in CL&P's, NSTAR Electric's and NSTAR Gas' sales volumes do not impact the level of base distribution revenue realized or 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.

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. In addition, tracked revenues include certain incentives earned and carrying charges. Tracked electric distribution segment revenues decreased as a result of decreases in energy supply costs ($625.2 million), driven by decreased average retail rates and lower sales volumes, partially offset by an increase in retail electric transmission charges ($84.6 million), an increase in federally mandated congestion charges ($103.0 million), an increase in energy efficiency program revenues ($51.7 million), an increase in stranded cost recovery charges ($39.2 million) and an increase in net metering for distributed generation revenues ($34.0 million). In addition, as a result of a change to the amounts collected in the system benefits charge, CL&P's calculated rate base increased, providing an increase to distribution revenues that positively impacted earnings by $23.2 million.

In 2016, tracked natural gas distribution segment revenues decreased as a result of decreases in natural gas supply costs ($128.2 million) driven by decreased average rates and lower sales volumes, and a decrease in energy efficiency program revenues ($22.7 million).

Electric transmission revenues: The electric transmission segment revenues increased by $140.9 million due primarily to the recovery of higher revenue requirements associated with ongoing investments in our transmission infrastructure and the absence in 2016 of a $20 million reserve charge recorded in 2015 associated with the March 2015 FERC ROE order.

Other: Other revenues decreased due primarily to the sale of Eversource's unregulated contracting business on April 13, 2015 ($11.4 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 cost tracking mechanisms, which have no impact on earnings (tracked costs). Purchased Power, Fuel and Transmission expense decreased in 2016, as compared to 2015, due primarily to the following:



(Millions of Dollars)	(Decrease)/Increase
Electric Distribution	$	(625.9	)
Natural Gas Distribution	(130.3		)
Transmission	170.1
Total Purchased Power, Fuel and Transmission	$	(586.1	)

The decrease in purchased power expense at the electric distribution business was driven by lower prices associated with the procurement of energy supply, lower sales volumes, and a decrease in the amount of electricity generated by PSNH facilities in 2016, as compared to 2015. The decrease in purchased power expense at the natural gas distribution business was due to lower sales volumes and lower average natural gas prices. The increase in transmission costs was primarily the result of an increase in costs billed by ISO-NE that support regional grid investment.

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 expense decreased in 2016, as compared to 2015, due primarily to the following:



(Millions of Dollars)	Increase/(Decrease)
Base Electric Distribution:
Absence of 2015 resolution of basic service bad debt adder mechanism at NSTAR Electric	$	24.2
Absence of 2015 regulatory proceedings benefiting NSTAR Electric	10.5
Employee-related expenses, including labor and benefits	(27.0		)
Storm restoration costs	15.0
Write-off of software design costs	9.2
Other operations and maintenance	14.1
Total Base Electric Distribution	46.0
Total Base Natural Gas Distribution:
Employee-related expenses, including labor and benefits	(15.5		)
Other operations and maintenance	8.2
Total Base Natural Gas Distribution	(7.3		)
Tracked costs (Electric Distribution, Electric Transmission and Natural Gas Distribution):
Merger-related costs allowed for recovery through transmission rates (earnings benefit)	(27.5		)
Other tracked operations and maintenance	41.8
Total Tracked costs (Electric Distribution, Electric Transmission and Natural Gas Distribution)	14.3
Other and eliminations:
Integration costs	(27.2		)
Absence of Eversource's unregulated electrical contracting business due to sale in April 2015, net	(13.9		)
Eversource Parent and Other Companies	(2.8		)
Eliminations	(14.9		)
Total Operations and Maintenance	$	(5.8	)

Depreciation expense increased in 2016, as compared to 2015, due primarily to higher utility plant in service balances.

Amortization of Regulatory Assets, Net expense includes the deferral of energy supply and energy-related costs included in certain regulatory-approved tracking mechanisms and the amortization of certain costs. The deferral adjusts expense to match the corresponding revenues. Amortization of Regulatory Assets, Net increased in 2016, as compared to 2015, due primarily to the deferral of energy supply and energy-related costs which can fluctuate from period to period based on the timing of costs incurred and the related rate changes to recover these costs. Energy supply and energy-related costs at CL&P, NSTAR Electric and PSNH, which are the primary drivers in amortization, are recovered from customers in rates and have no impact on earnings. The increase in Amortization of Regulatory Assets, Net for the year ended December 31, 2016 also includes the absence in 2016 of the $11.7 million benefit recorded in 2015 at NSTAR Electric in connection with the Comprehensive Settlement Agreement.

Energy Efficiency Programs expense increased in 2016, as compared to 2015, due primarily to deferral adjustments at NSTAR Electric, partially offset by deferral adjustments for the natural gas businesses, which reflect the actual costs of energy efficiency programs compared to the estimated amounts billed to customers, and the timing of the recovery of energy efficiency costs incurred in accordance with the three-year program guidelines established by the DPU. The deferrals adjust expense to match the energy efficiency programs revenue. The costs for various state energy policy initiatives and expanded energy efficiency programs are recovered from customers in rates and have no impact on earnings.

Taxes Other Than Income Taxes expense increased in 2016, as compared to 2015, due primarily to an increase in property taxes as a result of higher utility plant balances and an increase in gross earnings taxes. Gross earnings taxes are recovered from customers in rates and have no impact on earnings.

Interest Expense increased in 2016, as compared to 2015, due primarily to an increase in interest on long-term debt ($33.8 million) as a result of new debt issuances and an increase in interest on notes payable ($2.2 million), partially offset by a decrease in regulatory deferrals which decreased interest expense ($5.5 million).

Other Income, Net increased in 2016, as compared to 2015, due primarily to higher equity AFUDC amounts ($7.4 million), higher gains related to the sales of unregulated businesses ($9.4 million) and an increase in interest income ($4.1 million). Partially offsetting these favorable impacts were the market value changes related to deferred compensation plans ($9.6 million).

Income Tax Expense increased in 2016, as compared to 2015, due primarily to higher pre-tax earnings ($24.2 million), higher state taxes ($7.5 million), and the sale of an unregulated business ($10.2 million), partially offset by the excess tax benefit due to the adoption of new accounting guidance related to share based payment transactions ($19.1 million), the true-up of the return to provision impacts and a higher tax benefit from a reduction in tax reserves ($7.6 million), and items that impact our tax rate as a result of regulatory treatment (flow-through items) and permanent differences ($0.2 million).

EARNINGS SUMMARY

Regulated Companies: Our electric distribution segment earnings decreased $44.3 million in 2016, as compared to 2015. The decrease was due primarily to the absence in 2016 of the resolution of NSTAR Electric's basic service bad debt adder mechanism recorded in 2015 ($14.5 million), the absence in 2016 of the favorable impact associated with the NSTAR Electric Comprehensive Settlement Agreement recorded in 2015 ($13.0 million), and higher depreciation expense. In addition, earnings decreased due to higher operations and maintenance expense (primarily related to the absence of a $6.3 million regulatory benefit related to certain uncollectible hardship accounts receivable that was recorded in 2015 at NSTAR Electric, as well as higher storm restoration costs, higher vegetation management costs and the write-off of software design costs), higher property tax expense, and lower non-decoupled retail electric sales volumes due primarily to increased customer energy conservation efforts. These unfavorable earnings impacts were partially offset by increased CL&P distribution revenues primarily as a result of higher rate base and the absence of a required ROE reduction, as stipulated in the PURA 2014 rate case decision, and higher generation earnings.

Our electric transmission segment earnings increased $66.3 million in 2016, as compared to 2015, due primarily to a higher transmission rate base as a result of increased investments in our transmission infrastructure, the FERC-allowed recovery of certain merger-related costs in 2016 ($16.5 million), and the absence in 2016 of reserve charges in 2015 associated with the FERC ROE complaint proceedings ($12.4 million).

Our natural gas distribution segment earnings increased $5.3 million in 2016, as compared to 2015, due primarily to the impact of the NSTAR Gas base distribution rate increase effective January 1, 2016, the higher return earned on the NSTAR Gas System Enhancement Program ("GSEP") capital tracker mechanism effective in 2016, and lower operations and maintenance expense. These favorable earnings impacts were partially offset by lower non-decoupled firm natural gas sales volumes driven by the warmer than normal weather in the first quarter of 2016, as compared to the much colder than normal weather in the first quarter of 2015, higher property tax expense, and higher interest expense.

Eversource Parent and Other Companies: Eversource parent and other companies had earnings of $31.0 million in 2016, compared with a net loss of $5.5 million in 2015. The earnings increase was due primarily to lower income tax expense as a result of recognizing tax benefits from executive deferred compensation payments, which resulted from the adoption of a new accounting standard, and the absence in 2016 of integration costs, partially offset by higher interest expense.

LIQUIDITY

Cash flows provided by operating activities totaled $2.2 billion in 2016, compared with $1.4 billion in 2015. The increase in operating cash flows was due primarily to the absence in 2016 of $302 million in payments made in 2015 to fully satisfy the obligation with the DOE for costs associated with the disposal of spent nuclear fuel and high-level radioactive waste at previously owned generation facilities. In addition, there was an increase of $226.0 million in regulatory recoveries, primarily at NSTAR Electric, due to $98.1 million of collections from customers in excess of purchased power costs, the favorable impact associated with the December 2015 legislation that extended tax bonus depreciation, which resulted in a $145.8 million decrease in income tax payments in 2016, as compared to 2015, and an increase of $55.2 million of the Yankee Companies' DOE Damages and other proceeds received in 2016, as compared to 2015. Partially offsetting these favorable impacts was the timing of collections and payments related to our working capital items.

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, 2016 and 2015 included in this Annual Report on Form 10-K:



	For the Years Ended December 31,
(Millions of Dollars)	2016		2015		Increase/(Decrease)			Percent
Operating Revenues	$	2,806.0	$	2,802.7	$	3.3		0.1	%
Operating Expenses:
Purchased Power and Transmission	919.7		1,054.3		(134.6		)	(12.8	)
Operations and Maintenance	490.1		487.3		2.8			0.6
Depreciation	230.5		215.3		15.2			7.1
Amortization of Regulatory Assets, Net	38.8		12.3		26.5			(a)
Energy Efficiency Programs	154.0		153.7		0.3			0.2
Taxes Other Than Income Taxes	299.7		268.7		31.0			11.5
Total Operating Expenses	2,132.8		2,191.6		(58.8		)	(2.7	)
Operating Income	673.2		611.1		62.1			10.2
Interest Expense	144.1		145.8		(1.7		)	(1.2	)
Other Income, Net	13.5		11.5		2.0			17.4
Income Before Income Tax Expense	542.6		476.8		65.8			13.8
Income Tax Expense	208.3		177.4		30.9			17.4
Net Income	$	334.3	$	299.4	$	34.9		11.7	%

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

Operating Revenues

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



	For the Years Ended December 31,
	2016	2015	Decrease		Percent
Retail Sales Volumes in GWh	21,617	22,071	(454	)	(2.1	)%

CL&P's Operating Revenues, which consist of base distribution revenues and tracked revenues further described below, increased by $3.3 million in 2016, as compared to 2015.

Base distribution revenues increased by $30.1 million due to a higher rate base resulting from the 2015 PURA ADIT settlement agreement that is being collected from customers in distribution rates ($26.1 million) and the absence of a required ROE reduction, as stipulated in the PURA 2014 rate case decision, recorded in 2015 ($4 million). This increase was partially offset by the absence of the benefit recognized in 2015 in Operating Revenues due to the PURA ADIT settlement agreement.

Fluctuations in CL&P's sales volumes do not impact the level of base distribution revenue realized or earnings due to the PURA approved revenue decoupling mechanism. CL&P's revenue decoupling mechanism permits recovery of a base amount of distribution revenues ($1.059 billion annually) and breaks the relationship between sales volumes and revenues recognized. The revenue decoupling mechanism results in the recovery of approved base distribution revenue requirements.

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 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. In addition, tracked revenues include certain incentives earned and carrying charges. Tracked distribution revenues decreased primarily as a result of a decrease in energy supply costs ($222.4 million) driven by decreased average retail rates and lower sales volumes. Partially offsetting this decrease was an increase in federally mandated congestion charges ($103.0 million) and an increase in competitive transition assessment charges ($31.7 million). In addition, as a result of a change to the amounts collected in the system benefits charge, CL&P's calculated rate base increased, providing an increase to distribution revenues that impacted earnings of $23.2 million.

Transmission revenues increased by $62.7 million due primarily to higher revenue requirements associated with ongoing investments in our transmission infrastructure and the absence in 2016 of a $12.5 million reserve charge recorded in 2015 associated with the March 2015 FERC ROE order.

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 expense decreased in 2016, as compared to 2015, due primarily to the following:



(Millions of Dollars)	(Decrease)/Increase
Purchased Power Costs	$	(173.1	)
Transmission Costs	38.5
Total Purchased Power and Transmission	$	(134.6	)

Included in purchased power costs are the costs associated with CL&P's 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 who have not migrated to third party suppliers. The decrease in purchased power costs in 2016, compared to 2015, was due primarily to a decrease in the price of standard offer supply, as well as lower sales volumes. The increase in transmission costs was primarily the result of an increase in costs billed by ISO-NE that support regional grid investment.

Operations and Maintenance expense increased in 2016, as compared to 2015, driven by a $9.2 million increase in tracked costs, which have no earnings impact, that was primarily attributable to higher transmission expenses, partially offset by a $6.4 million decrease in non-tracked costs, which was primarily attributable to lower employee-related expenses, partially offset by higher storm restoration costs and the write-off of software design costs.

Depreciation increased in 2016, as compared to 2015, due primarily to higher utility plant in service balances.

Amortization of Regulatory Assets, Net expense includes the deferral of energy supply and energy-related costs and the amortization of storm and other costs. Amortization of Regulatory Assets, Net increased in 2016, as compared to 2015, due primarily to the deferral adjustment 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. The deferral adjusts expense to match the corresponding revenues. Energy supply and energy-related costs, which are the primary drivers of amortization, are recovered from customers in rates and have no impact on earnings.

Taxes Other Than Income Taxes expense increased in 2016, as compared to 2015, due primarily to an increase in property taxes as a result of both an increase in utility plant balances and an increase in gross earnings taxes. Gross earnings taxes are recovered from customers in rates and have no impact on earnings.

Interest Expense decreased in 2016, as compared to 2015, due primarily to lower deferred regulatory interest expense ($5.0 million) and a decrease in interest expense related to deposits ($1.3 million), partially offset by an increase in interest on long-term debt ($5.1 million).

Income Tax Expense increased in 2016, as compared to 2015, due primarily to higher pre-tax earnings ($23.2 million), higher state taxes ($1.5 million), and items that impact our tax rate as a result of regulatory treatment (flow-through items) and permanent differences ($7.7 million), partially offset by the excess tax benefit due to the adoption of new accounting guidance related to share-based payment transactions ($0.9 million), and the true-up of the return to provision impacts and a lower tax benefit from a reduction in tax reserves ($0.5 million).

EARNINGS SUMMARY

CL&P's earnings increased $34.9 million in 2016, as compared to 2015, due primarily to an increase in transmission earnings driven by a higher transmission rate base, as well as the absence in 2016 of the 2015 FERC ROE complaint proceedings reserve charge, higher distribution revenues as a result of higher rate base and the absence of a required ROE reduction, as stipulated in the PURA 2014 rate case decision, and lower operations and maintenance expense. These favorable earnings impacts were partially offset by higher property and other tax expense, a higher effective tax rate and higher depreciation expense.

LIQUIDITY

Cash totaled $6.6 million as of December 31, 2016, compared with $1.1 million as of December 31, 2015.

Eversource parent, and certain of its subsidiaries, including CL&P, are parties to a five-year $1.45 billion revolving credit facility. Effective September 26, 2016, the revolving credit facility's termination date was extended for one additional year to September 4, 2021. There were no borrowings outstanding on the revolving credit facility as of December 31, 2016 or 2015.

In 2016, CL&P had cash flows provided by operating activities of $811.5 million, compared with $298.3 million in 2015. The increase in operating cash flows was due primarily to the absence in 2016 of $244.6 million in payments made in 2015 to fully satisfy the pre-1983 spent nuclear fuel obligation with the DOE, and the favorable impact associated with the December 2015 legislation that extended tax bonus depreciation, which resulted in income tax refunds of $73.9 million received in 2016, as compared to income tax payments of $55.2 million made in 2015. Also contributing to the favorable impact was an increase in distribution rates due to higher rate base and the timing of collections and payments related to our working capital items, including accounts receivable and accounts payable. Partially offsetting these impacts was the timing of regulatory recoveries primarily related to energy efficiency program costs.

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 $612.0 million in 2016, compared with $523.8 million in 2015.

Financing activities in 2016 included $199.6 million in common stock dividends paid to Eversource parent.

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