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Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations
Management's Discussion and Analysis of Financial Condition and Results of Operations
NORTHEAST UTILITIES AND SUBSIDIARIES
The following discussion and analysis should be read in conjunction with our consolidated financial statements and related combined notes included in this Annual Report on Form 10-K. References in this Annual Report on Form 10-K to "NU," the "Company," "we," "us," and "our" refer to Northeast Utilities and subsidiaries. Our merger was effective April 10, 2012, and all subsequent results of operations and cash flows include NSTAR and its subsidiaries throughout this Management's Discussion and Analysis of Financial Condition and Results of Operations. On February 2, 2015, NU, CL&P, NSTAR Electric, PSNH and WMECO commenced doing business as Eversource Energy.
All per share amounts are reported on a diluted basis. The consolidated financial statements of NU, NSTAR Electric and PSNH and the financial statements of CL&P and WMECO are herein collectively referred to as the "financial statements." Refer to the Glossary of Terms included in this combined 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 NU. 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 Controlling Interest of each business by the weighted average diluted NU common shares outstanding for the year. The discussion below also includes non-GAAP financial measures referencing our 2014, 2013 and 2012 earnings and EPS excluding certain integration and merger costs related to NU's merger with NSTAR. We use these non-GAAP financial measures to evaluate and to provide details of earnings by business and to more fully compare and explain our 2014, 2013 and 2012 results without including the impact of these items. Due to the nature and significance of these items on Net Income Attributable to Controlling Interest, we believe that the non-GAAP presentation is more representative of our financial performance and provides additional and useful information to readers of this report in analyzing historical and future performance by business. These non-GAAP financial measures should not be considered as an alternative to reported Net Income Attributable to Controlling Interest or EPS determined in accordance with GAAP as an indicator of operating performance.
Reconciliations of the above non-GAAP financial measures to the most directly comparable GAAP measures of consolidated diluted EPS and Net Income Attributable to Controlling Interest are included under "Financial Condition and Business Analysis – Overview – Consolidated" and "Financial Condition and Business Analysis – Overview – Regulated Companies" in Management's Discussion and Analysis of Financial Condition and Results of Operations, herein.
Financial Condition and Business Analysis
Executive Summary
The following items in this executive summary are explained in more detail in this Management's Discussion and Analysis of Financial Condition and Results of Operations:
Results:
·
We earned $819.5 million, or $2.58 per share, in 2014, compared with $786 million, or $2.49 per share, in 2013. Excluding integration costs, we earned $841.6 million, or $2.65 per share, in 2014 and $799.8 million, or $2.53 per share, in 2013.
·
Our electric distribution segment, which includes generation, earned $462.4 million, or $1.45 per share, in 2014, compared with $427 million, or $1.35 per share, in 2013. Our transmission segment earned $295.4 million, or $0.93 per share, in 2014, compared with $287 million, or $0.91 per share, in 2013. Our natural gas distribution segment earned $72.3 million, or $0.23 per share, in 2014, compared with $60.9 million, or $0.19 per share, in 2013.
·
NU parent and other companies had a net loss of $10.6 million, or $0.03 per share, in 2014, compared with earnings of $11.1 million, or $0.04 per share, in 2013. The 2014 and 2013 results reflect $22.1 million, or $0.07 per share, and $13.8 million, or $0.04 per share, respectively, of integration costs.
Legislative, Regulatory, Policy and Other Items:
·
Pursuant to the FERC orders issued and other developments in the pending base ROE complaint proceedings further described in the "FERC Regulatory Issues – FERC Base ROE Complaints" section of this Management's Discussion and Analysis of Financial Condition and Results of Operations, the Company recorded reserves at its electric subsidiaries to recognize the potential financial impact of these rulings and developments in both 2014 and 2013. The net aggregate after-tax charge to earnings totaled $22.4 million and $14.3 million in 2014 and 2013, respectively.
·
On September 16, 2014, NU and Spectra Energy Corp announced Access Northeast, a natural gas pipeline expansion project. Access Northeast will enhance the Algonquin and Maritimes pipeline systems using existing routes. NU and Spectra Energy Corp will have equal ownership interest in the project. On February 18, 2015, NU, Spectra Energy Corp and National Grid announced the addition of National Grid as a co-developer in the project for a total ownership interest of 20 percent, with NU and Spectra Energy Corp each owning 40 percent. The total project cost, subject to FERC approval, is expected to be approximately $3 billion and has an anticipated in-service date of November 2018.
·
In September 2014, pursuant to legislation enacted in 2014, the NHPUC opened a docket that required them to commence and expedite a proceeding to determine whether all or some of PSNH's generation assets should be divested. An NHPUC progress report must be completed by March 31, 2015. In October 2014, the NHPUC concluded its hearings in the Clean Air Project prudence review to determine the prudent costs of PSNH's compliance with the law requiring scrubber installation. On December 26, 2014, PSNH requested that the NHPUC stay this proceeding in order to allow discussions to take place with other significant parties to determine whether a collaborative resolution of all issues was achievable. On January 15, 2015, the NHPUC issued an order granting the motion to stay in this proceeding, and settlement discussions have ensued.
·
On December 17, 2014, PURA issued a final decision in CL&P's rate case, effective December 1, 2014, for a total distribution rate increase of $134 million. The distribution rate increase included a revenue decoupling reconciliation mechanism, system resiliency costs, and, pursuant to a March 12, 2014 PURA order approving such costs, the recovery of 2011 and 2012 storm restoration costs over a six-year period. In addition, CL&P began recovering the 2013 storm costs and residual 2012 Storm Sandy costs over a seven-year period beginning December 1, 2014. Including the $65.4 million of DOE Phase II Damages proceeds CL&P was allowed to credit to its deferred storm costs, CL&P has now been approved to recover all of its previously deferred storm costs in distribution rates.
·
On December 31, 2014, NSTAR Electric, NSTAR Gas and the Massachusetts Attorney General filed a comprehensive settlement agreement with the DPU. The comprehensive settlement agreement included resolution of the outstanding NSTAR Electric CPSL program filings, the NSTAR Electric and NSTAR Gas PAM and energy efficiency-related customer billing adjustments reported in 2012, and the NSTAR Electric energy efficiency program filings regarding LBR. If approved by the DPU, NSTAR Electric and NSTAR Gas will be required to refund a total of $44.7 million to their respective customers, which was included in our regulatory liabilities as of December 31, 2014. Upon the DPU's approval, we will adjust our regulatory liabilities, which we expect will result in an after-tax benefit of approximately $14 million. We expect a response from the DPU in the first quarter of 2015.
Liquidity:
·
Cash and cash equivalents totaled $38.7 million as of December 31, 2014, compared with $43.4 million as of December 31, 2013.
·
Investments in property, plant and equipment totaled $1.6 billion in 2014 and $1.5 billion in 2013.
·
Cash flows provided by operating activities totaled $1.64 billion in 2014, compared with $1.66 billion in 2013. As compared to 2013, the 2014 operating cash flows were favorably impacted by approximately $132 million in DOE Damages proceeds resulting from the spent nuclear fuel litigation received by CL&P, NSTAR Electric, PSNH and WMECO from the Yankee Companies, the absence of 2013 cash disbursements for major storm restoration costs, the decrease of approximately $130 million in Pension and PBOP Plan cash contributions, and changes in the timing of working capital items. These favorable impacts were more than offset by higher income tax payments in 2014 and the unfavorable cash flow impact resulting from lower recoveries from customers in 2014, as compared to 2013, relating to regulatory cost recovery tracking mechanisms.
·
In 2014, we issued $725 million of new long-term debt consisting of $100 million by Yankee Gas on January 2, 2014, $300 million by NSTAR Electric on March 7, 2014, $250 million by CL&P on April 24, 2014 and $75 million by PSNH on October 14, 2014. In 2014, we repaid $575 million of existing long-term debt consisting of $75 million by Yankee Gas on January 1, 2014, $300 million by NSTAR Electric on April 15, 2014, $50 million by PSNH on July 15, 2014, and $150 million by CL&P on September 15, 2014. On January 15, 2015, NU parent issued $450 million of new long-term debt.
·
In 2014, we had cash dividends on common shares of $475.2 million, compared with $462.7 million in 2013. On February 3, 2015, our Board of Trustees approved a common dividend payment of $0.4175 per share, payable on March 31, 2015 to shareholders of record as of March 2, 2015, which represents an increase of 6.4 percent over the dividend paid in December 2014, and is equivalent to a dividend on common shares of approximately $530 million on an annual basis.
·
We project to make capital expenditures of approximately $8.4 billion from 2015 through 2018. Of the $8.4 billion, we expect to invest approximately $4.2 billion in our electric and natural gas distribution segments and $3.9 billion in our electric transmission segment. In addition, we project to invest approximately $360 million in information technology and facilities upgrades and enhancements. These projections do not include capital expenditures related to Access Northeast.
Overview
Consolidated: A summary of our earnings by business, which also reconciles the non-GAAP financial measures of consolidated non-GAAP earnings and EPS, as well as EPS by business, to the most directly comparable GAAP measures of consolidated Net Income Attributable to Controlling Interest and diluted EPS, is as follows:
| For the Years Ended December 31, | ||||||||||||||||||
| 2014 | 2013 | 2012 (1) | ||||||||||||||||
| (Millions of Dollars, Except Per Share Amounts) | Amount | Per Share | Amount | Per Share | Amount | Per Share | ||||||||||||
| Net Income Attributable to Controlling Interest (GAAP) | $ | 819.5 | $ | 2.58 | $ | 786.0 | $ | 2.49 | $ | 525.9 | $ | 1.89 | ||||||
| Regulated Companies | $ | 830.1 | $ | 2.61 | $ | 774.9 | $ | 2.45 | $ | 626.0 | $ | 2.25 | ||||||
| NU Parent and Other Companies | 11.5 | 0.04 | 24.9 | 0.08 | 7.5 | 0.03 | ||||||||||||
| Non-GAAP Earnings | 841.6 | 2.65 | 799.8 | 2.53 | 633.5 | 2.28 | ||||||||||||
| Integration and Merger-Related Costs (after-tax) | (22.1) | (0.07) | (13.8) | (0.04) | (107.6) | (0.39) | ||||||||||||
| Net Income Attributable to Controlling Interest (GAAP) | $ | 819.5 | $ | 2.58 | $ | 786.0 | $ | 2.49 | $ | 525.9 | $ | 1.89 |
(1)
Results include the operations of NSTAR beginning April 10, 2012.
Excluding the impact of integration costs, our 2014 earnings increased by $41.8 million, as compared to 2013. The increase was due primarily to lower operations and maintenance costs that impact earnings, which were primarily driven by lower labor and other employee-related costs, including approximately $30 million of non-tracked pension costs, and lower storm restoration costs, as well as higher firm natural gas sales volumes as a result of the colder weather in the first quarter of 2014, as compared to the first quarter of 2013. Partially offsetting this increase was the absence in 2014 of a favorable impact from the resolution of a state income tax audit in 2013, higher property taxes, higher depreciation expense at our regulated companies, and lower retail electric sales volumes as a result of cooler summer weather in 2014, as compared to the same period in 2013. Earnings were also unfavorably impacted by the 2014 after-tax net reserve of $22.4 million related to the 2014 FERC ROE orders, as compared to the 2013 after-tax reserve of $14.3 million related to the 2013 FERC ALJ initial decision in the FERC base ROE complaints. For further information, see "FERC Regulatory Issues – FERC Base ROE Complaints" in this Management's Discussion and Analysis of Financial Condition and Results of Operations.
The 2014 and 2013 integration costs consisted of costs incurred for employee severance in connection with ongoing integration. As of December 31, 2014, NU employed approximately 8,250 employees, compared to 8,700 as of December 31, 2013. In addition, the 2014 integration costs included costs associated with our rebranding efforts, as well as costs related to facility closures across our service territories.
Regulated Companies: Our Regulated companies consist of the electric distribution, transmission, and natural gas distribution segments. Generation activities of PSNH and WMECO are included in our electric distribution segment. A summary of our segment earnings and EPS is as follows:
| For the Years Ended December 31, | ||||||||||||||||||
| 2014 | 2013 | 2012 (1) | ||||||||||||||||
| (Millions of Dollars, Except Per Share Amounts) | Amount | Per Share | Amount | Per Share | Amount | Per Share | ||||||||||||
| Net Income – Regulated Companies (GAAP) | $ | 830.1 | $ | 2.61 | $ | 774.9 | $ | 2.45 | $ | 572.8 | $ | 2.06 | ||||||
| Electric Distribution | $ | 462.4 | $ | 1.45 | $ | 427.0 | $ | 1.35 | $ | 343.4 | $ | 1.24 | ||||||
| Transmission | 295.4 | 0.93 | 287.0 | 0.91 | 249.7 | 0.89 | ||||||||||||
| Natural Gas Distribution | 72.3 | 0.23 | 60.9 | 0.19 | 32.9 | 0.12 | ||||||||||||
| Net Income – Regulated Companies (Non-GAAP) | 830.1 | 2.61 | 774.9 | 2.45 | 626.0 | 2.25 | ||||||||||||
| Merger-Related Costs (after-tax) (2) | - | - | - | - | (53.2) | (0.19) | ||||||||||||
| Net Income - Regulated Companies (GAAP) | $ | 830.1 | $ | 2.61 | $ | 774.9 | $ | 2.45 | $ | 572.8 | $ | 2.06 |
(1)
Results include the operations of NSTAR beginning April 10, 2012.
(2)
Merger-related costs are attributable to the electric distribution segment ($51.1 million) and the natural gas distribution segment ($2.1 million).
Our electric distribution segment earnings increased $35.4 million in 2014, as compared to 2013, due primarily to lower operations and maintenance costs that impact earnings, which were primarily driven by lower labor and other employee-related costs, including pension costs, and lower storm restoration costs. Partially offsetting these favorable earnings impacts, as compared to 2013, were higher property taxes and depreciation expense, lower retail electric sales volumes as a result of cooler summer weather in 2014, and the absence in 2014 of regulatory interest income on stranded cost deferrals in 2013.
Our transmission segment earnings increased $8.4 million in 2014, as compared to 2013, due primarily to a decrease in transmission segment state income tax expense and a higher transmission rate base as a result of an increased investment in our transmission infrastructure. These favorable impacts were partially offset by the after-tax net reserve of $22.4 million related to the 2014 FERC ROE orders, as compared to the $14.3 million after-tax reserve related to the 2013 FERC ALJ initial decision in the FERC base ROE complaints.
Our natural gas distribution segment earnings increased $11.4 million in 2014, as compared to 2013, due primarily to higher firm natural gas sales volumes and peak demand revenues resulting from colder weather in the first quarter of 2014 and additional natural gas heating customers.
A summary of our retail electric GWh sales volumes and percentage changes, as well as percentage changes in CL&P, NSTAR Electric, PSNH and WMECO retail electric GWh sales volumes, is as follows:
| For the Year Ended December 31, 2014 Compared to 2013 | |||||||||||||
| NU | CL&P | NSTAR Electric | PSNH | WMECO | |||||||||
| Percentage | Percentage | Percentage | |||||||||||
| Sales Volumes (GWh) | Increase/ | Increase/ | Percentage | Increase/ | Percentage | ||||||||
| Electric | 2014 | 2013 | (Decrease) | (Decrease) | Decrease | Decrease | Decrease | ||||||
| Residential | 21,317 | 21,896 | (2.6)% | (2.8)% | (3.0)% | (1.1)% | (3.2)% | ||||||
| Commercial | 27,449 | 27,787 | (1.2)% | (1.3)% | (1.2)% | (0.8)% | (2.0)% | ||||||
| Industrial | 5,676 | 5,648 | 0.5 % | 2.5 % | (1.6)% | 0.6 % | (2.5)% | ||||||
| Total | 54,442 | 55,331 | (1.6)% | (1.6)% | (1.8)% | (0.7)% | (2.6)% |
A summary of our firm natural gas sales volumes in million cubic feet and percentage changes is as follows:
| For the Year Ended December 31, 2014 Compared to 2013 | |||||
| NU | |||||
| Sales Volumes (million cubic feet) | Percentage | ||||
| Firm Natural Gas | 2014 | 2013 | Increase | ||
| Residential | 38,969 | 36,777 | 6.0% | ||
| Commercial | 42,977 | 40,215 | 6.9% | ||
| Industrial | 22,245 | 21,266 | 4.6% | ||
| Total | 104,191 | 98,258 | 6.0% | ||
| Total, Net of Special Contracts (1) | 99,500 | 94,083 | 5.8% |
(1)
Special contracts are unique to the customers who take service under such an arrangement and generally specify the amount of distribution revenue to be paid to Yankee Gas regardless of the customers' usage.
Weather, fluctuations in energy supply costs, conservation measures (including utility-sponsored energy efficiency programs), and economic conditions affect customer energy usage. Industrial sales are less sensitive to temperature variations than residential and commercial sales. In our service territories, weather impacts electric sales during the summer and electric and natural gas sales during the winter (natural gas sales are more sensitive to temperature variations than electric sales). Customer heating or cooling usage may not directly correlate with historical levels or with the level of degree-days that occur.
Our 2014 consolidated retail electric sales volumes were lower, as compared to 2013, due primarily to cooler summer weather in 2014. In 2014, cooling degree days were 13 percent lower in Connecticut and western Massachusetts, 17 percent lower in the Boston metropolitan area, and 23 percent lower in New Hampshire, as compared to 2013. Weather-normalized NU consolidated retail electric sales volumes decreased one percent in 2014, as compared to 2013. We believe the decrease was due primarily to an increase in customer conservation efforts primarily by our residential customers, including the impact of energy efficiency programs sponsored by CL&P, NSTAR Electric and WMECO.
For WMECO and CL&P (effective December 1, 2014), fluctuations in retail electric sales volumes do not impact earnings due to the regulatory commission approved revenue decoupling mechanisms. Distribution revenues are decoupled from their customer sales volumes. CL&P and WMECO reconcile their annual base distribution rate recovery to pre-established levels of baseline distribution delivery service revenues. Any difference between the allowed level of distribution revenue and the actual amount incurred during a 12-month period is adjusted through rates in the following period. The decoupling mechanism effectively breaks the relationship between sales volumes and revenues recognized. Prior to December 1, 2014, CL&P recognized LBR related to reductions in sales volume as a result of successful energy efficiency programs. LBR was recovered from retail customers through the FMCC. Effective December 1, 2014, CL&P no longer recognizes LBR due to its revenue decoupling mechanism. NSTAR Electric continues to recognize LBR through December 31, 2015 in accordance with the 2012 DPU-approved comprehensive merger settlement agreement with the Massachusetts Attorney General. For the year ended December 31, 2014, CL&P and NSTAR Electric recognized LBR of $5.3 million and $39.9 million, respectively.
Our firm natural gas sales are subject to many of the same influences as our retail electric sales. In addition, they have benefited from historically favorable natural gas prices and customer growth across both operating companies. Our 2014 consolidated firm natural gas sales volumes, consisting of the firm natural gas sales volumes of Yankee Gas and NSTAR Gas, were higher, as compared to 2013, due primarily to colder weather in the first quarter of 2014, as compared to the same period in 2013, and increased customer growth in 2014, as compared to 2013. Weather-normalized NU consolidated firm natural gas sales volumes increased 2.9 percent in 2014, as compared to 2013.
NU Parent and Other Companies: NU parent and other companies, which include our unregulated businesses, had a net loss of $10.6 million in 2014, compared with earnings of $11.1 million in 2013. Excluding the impact of integration costs, NU parent and other companies earned $11.5 million in 2014, compared with $24.9 million in 2013. The earnings decrease in 2014 was due primarily to a higher effective tax rate and the absence in 2014 of the favorable impact from the resolution of the Connecticut state income tax audit.
Future Outlook
2015 EPS Guidance: We currently project 2015 earnings of between $2.75 per share and $2.90 per share, which excludes integration costs.
Liquidity
Consolidated: Cash and cash equivalents totaled $38.7 million as of December 31, 2014, compared with $43.4 million as of December 31, 2013.
On January 2, 2014, Yankee Gas issued $100 million of 4.82 percent Series L First Mortgage Bonds, due to mature in 2044. The proceeds, net of issuance costs, were used to repay the $75 million 4.80 percent Series G First Mortgage Bonds that matured on January 1, 2014 and to repay $25 million in short-term borrowings.
On March 7, 2014, NSTAR Electric issued $300 million of 4.40 percent debentures, due to mature in 2044. The proceeds, net of issuance costs, were used to repay the $300 million of 4.875 percent debentures that matured on April 15, 2014.
On April 24, 2014, CL&P issued $250 million of 4.30 percent 2014 Series A First Mortgage Bonds, due to mature in 2044. The proceeds, net of issuance costs, were used to repay short-term borrowings.
On July 15, 2014, PSNH repaid at maturity the $50 million of 5.25 percent Series L First Mortgage Bonds using short-term borrowings.
On September 15, 2014, CL&P repaid at maturity the $150 million of 4.80 percent 2004 Series A First Mortgage Bonds using short-term borrowings.
On October 14, 2014, PSNH issued $75 million of first mortgage bonds at a yield of 3.144 percent, due to mature in 2023. The first mortgage bonds are part of the same series of PSNH's existing 3.50 percent Series S First Mortgage Bonds that were initially issued in November 2013. The proceeds, net of issuance costs, were used to repay short-term borrowings.
On January 15, 2015, NU parent issued $150 million of 1.60 percent Series G Senior Notes, due to mature in 2018 and $300 million of 3.15 percent Series H Senior Notes, due to mature in 2025. The proceeds, net of issuance costs, were used to repay short-term borrowings outstanding under the NU commercial paper program.
On August 27, 2014, PURA approved CL&P's request to extend the authorization period for issuance of up to $366.4 million in long-term debt from December 31, 2014 to December 31, 2015.
NU parent, CL&P, PSNH, WMECO, NSTAR Gas and Yankee Gas are parties to a five-year $1.45 billion revolving credit facility. The revolving credit facility is to be used primarily to backstop NU parent's $1.45 billion commercial paper program. The commercial paper program allows NU parent to issue commercial paper as a form of short-term debt. Effective July 23, 2014, NU parent, CL&P, PSNH, WMECO, NSTAR Gas and Yankee Gas extended the expiration date of their joint revolving credit facility for one additional year to September 6, 2019. CL&P has a borrowing sublimit of $600 million, and PSNH and WMECO each have borrowing sublimits of $300 million. As of December 31, 2014 and 2013, NU parent had approximately $1.1 billion and $1.01 billion, respectively, in short-term borrowings outstanding under its commercial paper program, leaving $348.9 million and $435.5 million of available borrowing capacity as of December 31, 2014 and 2013, respectively. The weighted-average interest rate on these borrowings as of December 31, 2014 and 2013 was 0.43 percent and 0.24 percent, respectively, which is generally based on A2/P2 rated commercial paper. As of December 31, 2014, there were intercompany loans from NU parent of $133.4 million to CL&P, $90.5 million to PSNH and $21.4 million to WMECO. As of December 31, 2013, there were intercompany loans from NU parent of $287.3 million to CL&P and $86.5 million to PSNH.
NSTAR Electric has a five-year $450 million revolving credit facility. This facility serves to backstop NSTAR Electric's existing $450 million commercial paper program. Effective July 23, 2014, NSTAR Electric extended the expiration date of its revolving credit facility for one additional year to September 6, 2019. As of December 31, 2014 and 2013, NSTAR Electric had $302 million and $103.5 million, respectively, in short-term borrowings outstanding under its commercial paper program, leaving $148 million and $346.5 million of available borrowing capacity as of December 31, 2014 and 2013, respectively. The weighted-average interest rate on these borrowings as of December 31, 2014 and 2013 was 0.27 percent and 0.13 percent, respectively, which is generally based on A2/P1 rated commercial paper.
Each of NU, CL&P, NSTAR Electric, PSNH and WMECO use its available capital resources to fund its respective construction expenditures, meet debt requirements, pay operating costs, including storm-related costs, pay dividends and fund other corporate obligations, such as pension contributions. The current growth in NU's construction expenditures utilizes a significant amount of cash for projects that have a long-term return on investment and recovery period. In addition, NU's Regulated companies recover their electric and natural gas distribution construction expenditures as the related project costs are depreciated over the life of the assets. This impacts the timing of the revenue stream designed to fully recover the total investment plus a return on the equity portion of the cost and related financing costs. These factors have resulted in current liabilities exceeding current assets by approximately $442 million, $177 million, $133 million and $24 million at NU, CL&P, NSTAR Electric and WMECO, respectively, as of December 31, 2014.
As of December 31, 2014, $216.7 million of NU's obligations classified as current liabilities relates to long-term debt that will be paid in the next 12 months, consisting of $162 million for CL&P, $4.7 million for NSTAR Electric and $50 million for WMECO. The remaining $28.9 million of NU's obligations classified as current liabilities relates to fair value adjustments from the merger that will be amortized in the next 12 months and have no cash flow impact. NU, with its strong credit ratings, has several options available in the financial markets to repay or refinance these maturities with the issuance of new long-term debt. NU, CL&P, NSTAR Electric, PSNH and WMECO will reduce their short-term borrowings with cash received from operating cash flows or with the issuance of new long-term debt, determined considering capital requirements and maintenance of NU's credit
rating and profile. Management expects the future operating cash flows of NU, CL&P, NSTAR Electric, PSNH and WMECO, along with the access to financial markets, will be sufficient to meet any future operating requirements and capital investment forecasted opportunities.
Cash flows provided by operating activities totaled $1.64 billion in 2014, compared with $1.66 billion in 2013 and $1.16 billion in 2012. The 2014 operating cash flows were favorably impacted by approximately $132 million in DOE Damages proceeds resulting from the spent nuclear fuel litigation received by CL&P, NSTAR Electric, PSNH and WMECO from the Yankee Companies, the absence of 2013 cash disbursements for major storm restoration costs, the decrease of approximately $130 million in Pension and PBOP Plan cash contributions and changes in the timing of working capital items. These favorable impacts were more than offset by higher income tax payments in 2014 and the unfavorable cash flow impact resulting from lower recoveries from customers in 2014, as compared to 2013, relating to regulatory cost recovery tracking mechanisms. For further information on the spent nuclear fuel litigation, see Note 11C, "Commitments and Contingencies – Contractual Obligations – Yankee Companies," in this combined Annual Report on Form 10-K. The improved operating cash flows in 2013, as compared to 2012, were due primarily to the addition of NSTAR, a decrease in cash disbursements for storm restoration, and the absence in 2013 of cash disbursements related to customer bill credits and merger-related payments made in 2012. Partially offsetting these favorable cash flow impacts was an increase in Pension Plan cash contributions, increases in fuel inventories, and changes in traditional working capital amounts due primarily to the timing of accounts receivable and accounts payable.
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 | |||||||
| NU Parent | Baa1 | Stable | A- | Positive | BBB+ | Stable | ||||||
| CL&P | Baa1 | Stable | A- | Positive | BBB+ | Stable | ||||||
| NSTAR Electric | A2 | Stable | A- | Positive | A | Stable | ||||||
| PSNH | Baa1 | Stable | A- | Positive | BBB+ | Stable | ||||||
| WMECO | A3 | Stable | A- | Positive | BBB+ | Stable |
A summary of the current credit ratings and outlooks by Moody's, S&P and Fitch for senior unsecured debt of NU parent, NSTAR Electric, and WMECO and senior secured debt of CL&P and PSNH is as follows:
| Moody's | S&P | Fitch | ||||||||||
| Current | Outlook | Current | Outlook | Current | Outlook | |||||||
| NU Parent | Baa1 | Stable | BBB+ | Positive | BBB+ | Stable | ||||||
| CL&P | A2 | Stable | A | Positive | A | Stable | ||||||
| NSTAR Electric | A2 | Stable | A- | Positive | A+ | Stable | ||||||
| PSNH | A2 | Stable | A | Positive | A | Stable | ||||||
| WMECO | A3 | Stable | A- | Positive | A- | Stable |
On January 31, 2014, Moody's upgraded corporate credit and securities ratings of NU, CL&P and PSNH by one level and WMECO by two levels. On April 7, 2014, Fitch affirmed the corporate credit ratings and outlook of NU, CL&P, NSTAR Electric, PSNH, WMECO and NSTAR Gas. On April 25, 2014, S&P affirmed the corporate credit ratings and revised the outlooks to positive from stable of NU, CL&P, NSTAR Electric, PSNH, WMECO, Yankee Gas and NSTAR Gas.
In 2014, we had cash dividends on common shares of $475.2 million, compared with $462.7 million in 2013. On December 31, 2014, we paid a common dividend of $0.3925 per share, which was approved by our Board of Trustees on December 3, 2014, to shareholders of record as of December 15, 2014. On February 3, 2015, our Board of Trustees approved a common dividend payment of $0.4175 per share, payable on March 31, 2015 to shareholders of record as of March 2, 2015. The dividend represented an increase of 6.4 percent over the dividend paid in December 2014.
In 2014, CL&P, NSTAR Electric, PSNH, and WMECO paid $171.2 million, $253 million, $66 million, and $60 million, respectively, in common dividends to NU 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 2014, investments for NU, CL&P, NSTAR Electric, PSNH, and WMECO were $1.6 billion, $515.7 million, $465 million, $256.2 million, and $116.2 million, respectively.
Business Development and Capital Expenditures
Consolidated: Our consolidated capital expenditures, including amounts incurred but not paid, cost of removal, AFUDC, and the capitalized portions of pension expense (all of which are non-cash factors), totaled $1.7 billion in 2014, $1.6 billion in 2013, and $1.5 billion in 2012. These amounts included $58.3 million in 2014, $44.7 million in 2013, and $43.1 million in 2012, related to information technology and facilities upgrades and enhancements, primarily at NUSCO and The Rocky River Realty Company.
Access Northeast: On September 16, 2014, NU and Spectra Energy Corp announced Access Northeast, a natural gas pipeline expansion project. Access Northeast will enhance the Algonquin and Maritimes pipeline systems using existing routes and is expected to be capable of delivering approximately one billion cubic feet of natural gas per day to New England. NU and Spectra Energy Corp will have equal ownership interest in the project with the option of additional investors joining in the future. On February 18, 2015, NU, Spectra Energy Corp and National Grid announced the addition of National Grid as a co-developer in the project for a total ownership interest of 20 percent, with NU and Spectra Energy Corp each owning 40 percent. The total project cost, subject to FERC approval, is expected to be approximately $3 billion and has an anticipated in-service date of November 2018.
On December 8, 2014, NU and Spectra Energy Corp announced an alliance with Iroquois Gas Transmission for the Access Northeast project. This alliance will provide New England natural gas distribution companies and generators with additional access to natural gas supplies from multiple, diverse receipt points along the Algonquin pipeline system, including the Iroquois pipeline system.
Transmission Business: Overall, transmission business capital expenditures increased by $41.1 million in 2014, as compared to 2013. A summary of transmission capital expenditures by company is as follows:
| For the Years Ended December 31, | |||||||||
| (Millions of Dollars) | 2014 | 2013 | 2012 (1) | ||||||
| CL&P | $ | 259.2 | $ | 211.9 | $ | 182.5 | |||
| NSTAR Electric | 223.8 | 220.8 | 160.7 | ||||||
| PSNH | 120.8 | 99.7 | 55.7 | ||||||
| WMECO | 68.5 | 87.2 | 214.7 | ||||||
| NPT | 28.3 | 39.9 | 35.4 | ||||||
| Total Transmission Segment | $ | 700.6 | $ | 659.5 | $ | 649.0 |
(1)
Results include the transmission capital expenditures of NSTAR Electric beginning April 10, 2012.
NEEWS: GSRP, the first, largest and most complicated project within the NEEWS family of projects, was fully energized on November 20, 2013. As of December 31, 2014, CL&P and WMECO have placed $642 million in service.
The Interstate Reliability Project (IRP) is the second major NEEWS project. It includes CL&P's construction of an approximately 40-mile, 345 kV overhead line from Lebanon, Connecticut to the Connecticut-Rhode Island border in Thompson, Connecticut where it will connect to transmission enhancements being constructed by National Grid in Rhode Island and Massachusetts. All siting approvals have been received and construction is underway in all three states. NU's portion of the cost is estimated to be $218 million, and IRP was approximately 78 percent complete as of December 31, 2014. As of December 31, 2014, CL&P had placed $35 million in service. We expect to complete IRP by the end of 2015.
The Greater Hartford Central Connecticut Study (GHCC) includes the reassessment of the Central Connecticut Reliability Project and continues to make progress. The final need results showed existing and worsening severe regional and local thermal overloads and voltage violations within each of the areas studied and across the interfaces of those areas. These results were presented to the ISO-NE Planning Advisory Committee in November 2013. On July 15, 2014, ISO-NE presented the preferred transmission solutions to its Planning Advisory Committee. These solutions are comprised of many 115 kV upgrades and are expected to cost approximately $350 million and be placed in service from 2016 through 2018. We expect to begin work on the initial solutions in late 2015 and complete GHCC-related work in 2018.
Included as part of NEEWS are several associated reliability related projects, $96 million of which have been placed in service. As of the second quarter of 2014, all construction on the associated reliability related projects was completed.
Through December 31, 2014, CL&P and WMECO capitalized $351.5 million and $573.6 million, respectively, in costs associated with NEEWS, of which $98.7 million and $6.6 million, respectively, were capitalized in 2014. Included in the NEEWS amounts are costs for IRP, of which CL&P capitalized $168.8 million in costs through December 31, 2014, and $95.8 million related to costs capitalized in 2014.
Northern Pass: Northern Pass is NU's planned HVDC transmission line from the Québec-New Hampshire border to Franklin, New Hampshire and an associated alternating current radial transmission line between Franklin and Deerfield, New Hampshire. Northern Pass will interconnect at the Québec-New Hampshire border with a planned HQ HVDC transmission line. NPT received ISO-NE approval under Section I.3.9 of the ISO tariff in 2013. The DOE continues to work on the draft Environmental Impact Statement (EIS) for Northern Pass. This includes a review of our proposed route and various alternative routes. We currently expect the DOE to issue the draft EIS in April 2015. We expect to file the state permit application in mid-2015 after receipt of the draft EIS. The $1.4 billion project is subject to comprehensive federal and state public permitting processes and is expected to be operational in the second half of 2018.
Greater Boston Reliability Solutions: NSTAR Electric and PSNH expect to implement a series of new transmission projects over the next five years to enhance the region's system reliability. On February 12, 2015, ISO-NE selected NU's and National Grid's proposed Greater Boston and New Hampshire Solution (Solution) as its preferred option because it is significantly less expensive than an alternate proposal and has superior performance criteria. The Solution consists of a portfolio of important electric transmission upgrades encompassing the Merrimack Valley and metropolitan Boston areas of southern New Hampshire and eastern Massachusetts. Our estimated investment in the Solution chosen by ISO-NE is $489 million and we will now pursue the necessary regulatory approvals.
Distribution Business: A summary of distribution capital expenditures by company is as follows:
| For the Years Ended December 31, | ||||||||
| (Millions of Dollars) | 2014 | 2013 | 2012 (1) | |||||
| CL&P: | ||||||||
| Basic Business | $ | 120.2 | $ | 60.9 | $ | 69.2 | ||
| Aging Infrastructure | 118.0 | 160.7 | 177.8 | |||||
| Load Growth | 66.3 | 76.9 | 65.8 | |||||
| Total CL&P | 304.5 | 298.5 | 312.8 | |||||
| NSTAR Electric: | ||||||||
| Basic Business | 99.0 | 98.5 | 47.3 | |||||
| Aging Infrastructure | 104.2 | 110.6 | 111.5 | |||||
| Load Growth | 43.1 | 53.6 | 17.4 | |||||
| Total NSTAR Electric | 246.3 | 262.7 | 176.2 | |||||
| PSNH: | ||||||||
| Basic Business | 62.1 | 22.7 | 25.3 | |||||
| Aging Infrastructure | 45.3 | 50.5 | 50.2 | |||||
| Load Growth | 27.1 | 29.3 | 20.2 | |||||
| Total PSNH | 134.5 | 102.5 | 95.7 | |||||
| WMECO: | ||||||||
| Basic Business | 19.0 | 7.9 | 12.7 | |||||
| Aging Infrastructure | 16.1 | 24.6 | 18.5 | |||||
| Load Growth | 6.1 | 9.2 | 6.5 | |||||
| Total WMECO | 41.2 | 41.7 | 37.7 | |||||
| Total - Electric Distribution (excluding Generation) | 726.5 | 705.4 | 622.4 | |||||
| Other Distribution | - | 0.7 | 0.1 | |||||
| PSNH Generation | 13.1 | 9.7 | 29.9 | |||||
| WMECO Generation | 7.6 | 4.5 | 0.7 | |||||
| Total - Natural Gas | 193.7 | 175.2 | 162.9 | |||||
| Total Distribution Segment | $ | 940.9 | $ | 895.5 | $ | 816.0 |
(1)
Results include the electric and natural gas distribution capital expenditures of NSTAR beginning April 10, 2012.
For the electric distribution business, basic business includes the purchase of meters, tools, vehicles, information technology, transformer replacements, equipment facilities, and the relocation of plant. Aging infrastructure relates to reliability and the replacement of overhead lines, plant substations, underground cable replacement, and equipment failures. Load growth includes requests for new business and capacity additions on distribution lines and substation additions and expansions.
Natural Gas Business Expansion and Enhancement: In 2013, in accordance with Connecticut law and regulation, PURA approved a comprehensive joint natural gas infrastructure expansion plan (expansion plan) filed by Yankee Gas and other Connecticut natural gas distribution companies. The expansion plan described how Yankee Gas expects to add approximately 82,000 new natural gas heating customers over the next 10 years. Yankee Gas estimates that its portion of the plan will cost approximately $700 million over 10 years. In January 2015, PURA approved a joint settlement agreement proposed by Yankee Gas and other Connecticut natural gas distribution companies and regulatory agencies that clarified the procedures and oversight criteria applicable to the expansion plan.
On October 31, 2014, pursuant to new legislation, NSTAR Gas filed the Gas System Enhancement Program (GSEP) with the DPU. NSTAR Gas' program accelerates the replacement of certain natural gas distribution facilities in the system within 25 years. The GSEP includes a new tariff that provides NSTAR Gas an opportunity to collect the costs for the program on an annual basis through a newly designed reconciling factor to be approved by the DPU. We expect a decision on the program in April 2015. We have projected capital expenditures of approximately $200 million for the period 2015 through 2018 for the GSEP, which are consistent with our request in the NSTAR Gas rate case application currently before the DPU.
Projected Capital Expenditures: A summary of the projected capital expenditures for the Regulated companies' electric transmission and for the total electric distribution, generation, and natural gas distribution businesses for 2015 through 2018, including information technology and facilities upgrades and enhancements on behalf of the Regulated companies, is as follows:
| Years | ||||||||||||||
| (Millions of Dollars) | 2015 | 2016 | 2017 | 2018 | 2015-2018 Total | |||||||||
| CL&P Transmission | $ | 214 | $ | 241 | $ | 258 | $ | 158 | $ | 871 | ||||
| NSTAR Electric Transmission | 231 | 262 | 236 | 295 | 1,024 | |||||||||
| PSNH Transmission | 133 | 76 | 73 | 19 | 301 | |||||||||
| WMECO Transmission | 128 | 80 | 34 | 8 | 250 | |||||||||
| NPT | 34 | 309 | 620 | 466 | 1,429 | |||||||||
| Total Transmission | $ | 740 | $ | 968 | $ | 1,221 | $ | 946 | $ | 3,875 | ||||
| Electric Distribution | $ | 755 | $ | 778 | $ | 758 | $ | 748 | $ | 3,039 | ||||
| Generation | 38 | 20 | 15 | 15 | 88 | |||||||||
| Natural Gas | 228 | 256 | 275 | 300 | 1,059 | |||||||||
| Total Distribution | $ | 1,021 | $ | 1,054 | $ | 1,048 | $ | 1,063 | $ | 4,186 | ||||
| Information Technology and All Other | $ | 90 | $ | 92 | $ | 94 | $ | 83 | $ | 359 | ||||
| Total | $ | 1,851 | $ | 2,114 | $ | 2,363 | $ | 2,092 | $ | 8,420 |
The projections do not include capital expenditures related to Access Northeast. Actual capital expenditures could vary from the projected amounts for the companies and years above.
FERC Regulatory Issues
FERC Base ROE Complaints:
First Complaint: On September 30, 2011, a complaint was filed jointly at FERC under Sections 206 and 306 of the Federal Power Act (the "first complaint") by several New England state attorneys general, state regulatory commissions, consumer advocates and other parties (the "Complainants"). The Complainants alleged that the base ROE of 11.14 percent that has been utilized since 2006 in the calculation of formula rates for transmission service under the ISO-NE Open Access Transmission Tariff by NETOs, including CL&P, NSTAR Electric, PSNH and WMECO, was unjust and unreasonable and asserted that the rate was excessive due to changes in the capital markets. Complainants sought an order to reduce the base ROE prospectively from the date of a final FERC order, and for the 15-month period October 1, 2011 to December 31, 2012 (the "first complaint refund period"), and to require refunds. The FERC set the case for trial before a FERC ALJ after settlement negotiations were unsuccessful in August 2012.
On August 6, 2013, the FERC ALJ issued an initial decision on the first complaint finding that the base ROE in effect during the first complaint refund period was not reasonable and recommended separate base ROEs for the first complaint refund period of 10.6 percent and for the period beginning when FERC issues its final decision (the "prospective period") of 9.7 percent, leaving policy considerations and additional adjustments to the FERC. In 2013, the Company recorded reserves at its electric subsidiaries to recognize the potential financial impact from the FERC ALJ's initial decision for the first complaint refund period.
On June 19, 2014, FERC issued an order on the first complaint partially affirming and partially reversing the FERC ALJ's initial decision. FERC set a single tentative base ROE of 10.57 percent for the first complaint refund period and prospective period. FERC also modified its traditional methodology by adopting a two-step discounted cash flow analysis consistent with the method that it utilizes to determine the ROEs of both natural gas and oil pipeline projects. Using this methodology, FERC determined a new zone of reasonableness of 7.03 percent to 11.74 percent, and set the tentative base ROE halfway between the midpoint and the top of the zone of reasonableness. FERC also stated that a utility's "total ROE, inclusive of transmission incentive ROE adders" should not exceed the top of the new zone of reasonableness produced by this methodology. FERC instituted a paper hearing on the long-term growth rate portion of the methodology (the "paper hearing"). Rehearing requests on this new methodology were filed in July 2014, and briefs were filed in August and September 2014 by the parties on the appropriate long-term growth rate.
On October 16, 2014, the FERC issued an order in the paper hearing, which confirmed that the base ROE should be set at 10.57 percent and that a utility's total or maximum ROE should not exceed the top of the new zone of reasonableness (11.74 percent). The FERC ordered the NETOs to provide refunds to customers for the first complaint refund period, and set the prospective new base ROE at this time. In November 2014, the NETOs requested rehearing and clarification from FERC. In late 2014, the NETOs made a compliance filing, and began refunding amounts from the first complaint period, inclusive of incentive ROE adders that exceeded the 11.74 percent as compared to the total company transmission ROE. Complainants have challenged the compliance filing.
In 2014, the Company recorded additional reserves at its electric subsidiaries to recognize the potential financial impact from the FERC's orders.
Second Complaint: On December 27, 2012, a second complaint was filed jointly at FERC by several additional consumer groups and municipal parties (the "second complaint"), challenging the NETOs' existing base ROE, requesting FERC to reduce the NETOs' base ROE prospectively from the date of the final FERC order and seeking refunds for the 15-month period of December 27, 2012 to March 27, 2014 (the "second complaint refund period").
On June 19, 2014, FERC issued an order finding that the second complaint raised issues of material fact, and setting the complaint for settlement or hearing. On July 21, 2014, the NETOs filed a rehearing request in this proceeding. On October 24, 2014, the FERC assigned the case for trial before a FERC ALJ after settlement negotiations were unsuccessful. The FERC ALJ set a trial date beginning June 8, 2015, and indicated he could issue an initial decision on or before October 26, 2015. This schedule was subsequently modified by a November 24, 2014 order on the third complaint (see below). In 2014, the Company recorded reserves at its electric subsidiaries to recognize the potential financial impact from the FERC's June 19th order for the second complaint refund period.
Third Complaint: On July 31, 2014, a third complaint was filed at FERC (the "third complaint") by most of the Complainants to the first and second complaints, claiming that the base ROE and incentive adders exceed the range of permissible ROEs, requesting FERC to reduce the NETOs' base ROE prospectively from the date of a final FERC order, and seeking refunds for the 15-month period of July 31, 2014 to October 31, 2015 (the "third complaint refund period"). On November 24, 2014, FERC issued an order finding that the third complaint raised issues of material fact and set the case for trial. In this order, FERC also consolidated the third complaint with the second complaint for purposes of hearing and decision. Due to the establishment of two refund periods, the FERC also stated that it is appropriate for the parties to litigate a separate ROE for each refund period. On December 24, 2014, the NETOs filed for rehearing of this order. The trial judge has set a hearing beginning June 23, 2015 for the two complaints. The trial judge's recommended initial decision is expected by November 30, 2015 with a FERC order issued by September 30, 2016.
Rehearing requests of NETOs that were filed in all three complaint proceedings have not yet been acted upon by FERC. At this time, the Company cannot determine the outcome of these rehearing requests.
Cumulative Reserves: The following is a summary of the cumulative pre-tax reserves (excluding interest) that the Company established in 2013 and 2014 to recognize the potential financial impacts of the first and second complaints. The Company is unable to determine any amount related to the third complaint.
| NU | |||||||||||||||||||
| For the Years Ended December 31, | |||||||||||||||||||
| (Millions of Dollars) | 2013 | 2014 | Total | ||||||||||||||||
| 1st Complaint - Base ROE | $ | 23.7 | $ | 1.2 | $ | 24.9 | |||||||||||||
| 2nd Complaint - Base ROE | - | 27.4 | 27.4 | ||||||||||||||||
| Incentive ROE (1st and 2nd Complaint) | - | 8.4 | 8.4 | ||||||||||||||||
| Cumulative Reserve | $ | 23.7 | $ | 37.0 | $ | 60.7 | |||||||||||||
| CL&P | NSTAR Electric | ||||||||||||||||||
| For the Years Ended December 31, | For the Years Ended December 31, | ||||||||||||||||||
| (Millions of Dollars) | 2013 | 2014 | Total | 2013 | 2014 | Total | |||||||||||||
| 1st Complaint - Base ROE | $ | 12.8 | $ | 0.5 | $ | 13.3 | $ | 5.7 | $ | 0.4 | $ | 6.1 | |||||||
| 2nd Complaint - Base ROE | - | 13.5 | 13.5 | - | 7.5 | 7.5 | |||||||||||||
| Incentive ROE (1st and 2nd Complaint) | - | 6.7 | 6.7 | - | - | - | |||||||||||||
| Cumulative Reserve | $ | 12.8 | $ | 20.7 | $ | 33.5 | $ | 5.7 | $ | 7.9 | $ | 13.6 | |||||||
| PSNH | WMECO | ||||||||||||||||||
| For the Years Ended December 31, | For the Years Ended December 31, | ||||||||||||||||||
| (Millions of Dollars) | 2013 | 2014 | Total | 2013 | 2014 | Total | |||||||||||||
| 1st Complaint - Base ROE | $ | 2.3 | $ | 0.1 | $ | 2.4 | $ | 2.9 | $ | 0.2 | $ | 3.1 | |||||||
| 2nd Complaint - Base ROE | - | 2.7 | 2.7 | - | 3.7 | 3.7 | |||||||||||||
| Incentive ROE (1st and 2nd Complaint) | - | - | - | - | 1.7 | 1.7 | |||||||||||||
| Cumulative Reserve | $ | 2.3 | $ | 2.8 | $ | 5.1 | $ | 2.9 | $ | 5.6 | $ | 8.5 |
As of December 31, 2014, the cumulative reserves above do not reflect refunds totaling $4.8 million at NU, $2.7 million at CL&P, $1 million at NSTAR Electric, $0.5 million at PSNH and $0.6 million at WMECO for the first complaint refund period.
In the fourth quarter of 2014, we finalized our reserve analysis based on the October FERC order and our subsequent refund filing. As a result, the net aggregate after-tax charge to 2014 earnings resulting from the June 19, 2014 and October 16, 2014 FERC orders totaled $22.4 million at NU, $12.4 million at CL&P, $4.9 million at NSTAR Electric, $1.7 million at PSNH and $3.4 million at WMECO. In 2013, the aggregate after-tax charge to earnings totaled $14.3 million at NU, $7.7 million at CL&P, $3.4 million at NSTAR Electric, $1.4 million at PSNH and $1.8 million at WMECO.
Regulatory Developments and Rate Matters
Electric and Natural Gas Base Distribution Rates:
Each NU utility subsidiary is subject to the regulatory jurisdiction of the state in which it operates: CL&P and Yankee Gas operate in Connecticut and are subject to PURA regulation; NSTAR Electric, WMECO and NSTAR Gas operate in Massachusetts and are subject to DPU regulation; and PSNH operates in New Hampshire and is subject to NHPUC regulation.
In Connecticut, CL&P distribution rates were established in a 2014 PURA approved rate case. See Connecticut – Distribution Rates in this Regulatory Developments and Rate Matters section for further information. Yankee Gas distribution rates were established in a 2011 PURA approved rate case.
In Massachusetts, electric utility companies are required to file at least one distribution rate case every five years and natural gas companies to file at least one distribution rate case every 10 years, and those companies are limited to one settlement agreement in any 10-year period. Pursuant to the April 2012 DPU-approved Massachusetts comprehensive merger settlement agreements, NSTAR Electric, WMECO and NSTAR Gas are subject to a base distribution rate freeze through December 31, 2015. On December 17, 2014, NSTAR Gas filed an application with the DPU to amend base distribution rates, effective January 1, 2016.
In New Hampshire, PSNH is currently operating under the 2010 NHPUC approved distribution rate case settlement, which is effective through June 30, 2015. Under the settlement, PSNH is permitted to file a request to collect certain exogenous costs and step increases on an annual basis. See New Hampshire - Distribution Rates in this Regulatory Developments and Rate Matters section for further information.
Major Storms:
CL&P, NSTAR Electric, PSNH and WMECO experienced several significant storm events, including Tropical Storm Irene in 2011, the October 2011 snowstorm, Storm Sandy in 2012, and the February 2013 blizzard. As a result of these storm events, each company suffered extensive damage to its distribution and transmission systems resulting in customer outages. Each company incurred significant costs to repair damage and restore customers' service. In addition, on November 26, 2014, a snowstorm caused damage to the electric delivery systems of PSNH and WMECO. This snowstorm resulted in estimated deferred storm restoration costs of approximately $23 million at PSNH and approximately $3 million at WMECO.
The magnitude of these storm restoration costs met the criteria for cost deferral in Connecticut, Massachusetts, and New Hampshire. As a result, the storms had no material impact on the results of operations of CL&P, NSTAR Electric, PSNH and WMECO. We believe the storm restoration costs were prudent and meet the criteria for specific cost recovery in Connecticut, Massachusetts and New Hampshire, and that recovery from customers is probable through the applicable regulatory recovery process. Each electric utility has sought, or is seeking, recovery of its deferred storm restoration costs through its applicable regulatory recovery process. As of December 31, 2014, all CL&P deferred storm costs have been reviewed and approved for recovery in distribution rates, NSTAR Electric received DPU approval for recovery of $34.2 million of deferred storm costs related to Tropical Storm Irene in 2011 and the October 2011 snowstorm, PSNH received an NHPUC audit report, which found no exception with storm costs from 2011 through March 2013, and WMECO received DPU approval to begin recovering the October 2011 snowstorm and 2012 Storm Sandy restoration costs, of which the DPU approved the majority of deferred storm costs through 2011.
DPU Storm Penalties: In December 2012, in separate orders issued by the DPU, the DPU ordered penalties of $4.1 million and $2 million for NSTAR Electric and WMECO, respectively, related to the electric utilities' responses to Tropical Storm Irene and the October 2011 snowstorm, which were refunded to their customers. In December 2012, NSTAR Electric and WMECO each filed appeals with the SJC arguing the DPU penalties should be vacated. On September 4, 2014, the SJC vacated $2 million of NSTAR Electric's $4.1 million penalties, as it did not believe that substantial evidence existed to support such penalties, while it upheld the WMECO penalties. Subsequently, the DPU reinstated approximately $0.4 million of NSTAR Electric storm penalties pursuant to a December 22, 2014 order.
Connecticut:
Distribution Rates: On June 9, 2014, CL&P filed an application with PURA to amend distribution rates, effective December 1, 2014. The application included an increase to base distribution rates, as well as increases for the recovery of previously approved 2011 and 2012 deferred storm restoration costs and previously approved electric system resiliency costs. After the legal briefing process, CL&P updated its requested increase to reflect a reduction to the storm cost recovery amounts. The reduction primarily related to applying the impact of the $65.4 million DOE Phase II Damages proceeds received on June 1, 2014 to the total deferred storm restoration costs of $365 million, as ordered by PURA on June 17, 2014.
On December 17, 2014, PURA issued a final order and approved a total distribution rate increase of $134 million, which includes an authorized ROE of 9.02 percent for the first twelve month period and 9.17 percent thereafter. The 2011 and 2012 storm costs were approved in their entirety, to be recovered over a six-year period, and adjustments to storm cost recovery and system resiliency cost recovery reflect the lower approved ROE. PURA granted a re-opener to the rate application for further review of the appropriate treatment of deferred income taxes for rate base purposes. If PURA concludes that CL&P's treatment of its deferred taxes for rate base purposes is correct, it would result in an additional annual increase to total distribution rates of $22 million. CL&P is currently responding to information requests and has provided additional information with respect to the treatment of deferred income taxes for rate base purposes and expects a decision no later than the third quarter of 2015.
The PURA also approved the establishment of a revenue decoupling reconciliation mechanism, effective December 1, 2014, whereby actual base distribution rate recovery is reconciled with pre-established revenue requirement level on an annual basis. Any difference between the allowed level of distribution revenue and the actual amount incurred in a calendar year is adjusted through rates in the following year. The baseline allowed distribution revenue is $1.041 billion, which will remain constant until CL&P's next rate case. With the implementation of the decoupling mechanism, LBR will no longer be recognized effective December 1, 2014, and CL&P will not experience significant fluctuations to its base distribution revenues regardless of the impact of weather and energy efficiency by its customers.
The PURA also allowed CL&P recovery of $31.1 million in 2013 storm costs and residual 2012 Storm Sandy costs over a seven-year period beginning December 1, 2014.
CL&P 2014 Storm Order: On March 12, 2014, PURA approved recovery of $365 million of deferred storm restoration costs (with carrying charges) associated with five major storms that occurred in 2011 and 2012 and ordered CL&P to capitalize approximately $18 million of the deferred storm restoration costs as utility plant, which will be recovered through depreciation expense in future rate proceedings. On December 1, 2014, CL&P began recovering approximately $300 million in its distribution rates over a six-year period, which was net of $65.4 million of DOE Phase II Damages proceeds. The remaining costs were either disallowed or are probable of recovery from other sources. These costs did not have a material impact on CL&P's financial position or results of operations.
CL&P Standard Service and Last Resort Service Rates: CL&P's residential and small to intermediate commercial and industrial customers who do not choose competitive energy suppliers are served under SS rates, and large commercial and industrial customers who do not choose competitive energy suppliers are served under LRS rates. Effective January 1, 2015, the PURA approved an increase to CL&P's energy supply portion of the total average SS rate to 12.446 cents per kWh and the energy supply portion of the total average LRS rate to 17.714 cents per kWh. These changes were due primarily to the market conditions for the procurement of energy. The SS and LRS rates reflect CL&P's costs to procure energy for its customers. Adjustments to these rates do not impact earnings, as CL&P is fully recovering the costs of its SS and LRS services from customers.
CL&P CTA and SBC Reconciliation: CL&P filed its 2013 CTA and SBC reconciliation on March 31, 2014, which compared CTA and SBC billed revenues to revenue requirements, as required by PURA. The 2013 reconciliation filing produced net over recoveries of $16.9 million and $4.3 million for the CTA and SBC, respectively, and was approved by PURA.
CL&P FMCC Filing: CL&P files with PURA its FMCC filing, which reconciles actual FMCC revenues and charges and GSC revenues and expenses. The filing identifies a total net over or under recovery, which includes the remaining uncollected or non-refunded portions from previous filings. On February 3, 2014, CL&P filed with PURA its FMCC filing for the period July 1, 2013 through December 31, 2013. The filing identified a total net over recovery through December 31, 2013 of $24.1 million and was approved by PURA.
CL&P Conservation Adjustment Mechanism: In 2012, CL&P filed an application with PURA for the establishment of a CAM. The CAM would collect the costs associated with expanded energy efficiency programs beyond that already collected through the statutory charge and the revenues lost because of the expanded energy efficiency programs. In 2013, DEEP approved CL&P's request of an expanded conservation spending budget and reiterated that PURA is directed to approve a CAM to fund the expanded conservation budget. The PURA approved a CAM effective January 1, 2014 subject to a future review of its revenue and expense reconciliation filing to be submitted by CL&P. CL&P has continued its approved January 1, 2014 CAM rate through 2015.
Massachusetts:
Basic Service Rates: Electric distribution companies in Massachusetts are required to obtain and resell power to retail customers through Basic Service for those customers who choose not to buy energy from a competitive energy supplier. Basic Service rates are reset every six months (every three months for large commercial and industrial customers). NSTAR Electric and WMECO fully recover their energy costs through DPU-approved regulatory rate mechanisms.
2015 Annual Reconciliation Filing: In the fourth quarter of 2014, NSTAR Electric and WMECO filed separately their respective 2015 annual cost recovery mechanisms, including the mechanisms to collect the costs to provide retail transmission, energy supply and energy efficiency services to its customers as well as the costs related to pension and other post-retirement employee benefit costs. The reconciliation filings compared the total revenues to revenue requirements related to these services. In December 2014, the DPU issued a final decision approving the rates as filed, subject to future review and reconciliation.
Energy Efficiency Plans: In accordance with Massachusetts law passed in 2008 known as the Green Communities Act, natural gas and electric distribution companies must file three-year energy efficiency plans, which were initially filed by NSTAR Electric and WMECO, and approved by the DPU, in 2010 covering the period 2010 through 2012. The NSTAR Electric and WMECO three-year plans covering the period 2013 through 2015 were approved by the DPU in 2013. Distribution companies that do not yet have rate decoupling mechanisms in place, like NSTAR Electric, include LBR rate adjustment mechanisms in order to offset reduced distribution rate revenues as a result of successful energy efficiency programs. NSTAR Electric's LBR rate adjustment mechanism is in place through December 31, 2015.
DPU Safety and Reliability Programs (CPSL): The CPSL program allows NSTAR Electric to recover $15 million per year related to DPU approved safety and reliability programs, which are designed to mitigate stray voltage and repair and replace portions of the system to increase and enhance customer safety. This annual level of recovery was established by the 2012 DPU-approved comprehensive merger settlement agreement with the Massachusetts Attorney General. The CPSL program will expire on December 31, 2015.
2014 Comprehensive Settlement Agreement: On December 31, 2014, NSTAR Electric, NSTAR Gas and the Massachusetts Attorney General filed a comprehensive settlement agreement with the DPU. The comprehensive settlement agreement included resolution of the outstanding NSTAR Electric CPSL program filings for the periods 2006 through 2011, the NSTAR Electric and NSTAR Gas PAM and energy efficiency-related customer billing adjustments reported in 2012, and the NSTAR Electric energy efficiency program filings regarding LBR for the periods 2008 through 2011. If approved by the DPU, NSTAR Electric and NSTAR Gas will be required to refund a total of $44.7 million to their respective customers, which was included in our regulatory liabilities as of December 31, 2014. Upon the DPU's approval, we will adjust our regulatory liabilities, which we expect will result in an after-tax benefit of approximately $14 million. We expect a response from the DPU in the first quarter of 2015.
Basic Service Bad Debt Adder: In accordance with a generic 2005 DPU order, electric utilities in Massachusetts recover the energy-related portion of bad debt costs in their Basic Service rates. In 2007, NSTAR Electric filed its 2006 Basic Service reconciliation with the DPU proposing an adjustment related to the increase of its Basic Service bad debt charge-offs. The DPU issued an order approving the implementation of a revised Basic Service rate but instructed NSTAR Electric to reduce distribution rates by an amount equal to the increase in its Basic Service bad debt charge-offs. This adjustment to NSTAR Electric's distribution rates would eliminate the fully reconciling nature of the Basic Service bad debt adder.
In 2010, NSTAR Electric filed an appeal of the DPU's order with the SJC. NSTAR Electric's position was that it had fully removed the collection of energy-related bad debt costs from its distribution rates effective January 1, 2006. Therefore, no further adjustment to distribution rates was warranted. In 2012, the SJC vacated the DPU order and remanded the matter to the DPU for further review.
As of December 31, 2014, NSTAR Electric has a total deferred regulatory asset of approximately $33 million of costs associated with energy-related bad debt.
On January 7, 2015, the DPU issued an order on remand stating that NSTAR Electric had, in fact, removed energy-related bad debt costs from distribution rates effective January 1, 2006. The DPU order approved NSTAR Electric's 2005 and 2006 reconciliation filings and ordered NSTAR Electric and the Massachusetts Attorney General to collaborate on the submission of a proposal for the reconciliation of energy-related bad debt costs for the open years of 2007 through 2014 by April 7, 2015. Management expects to present a proposal to the Attorney General in the first quarter of 2015 with a decision from the DPU later in 2015.
Long-Term Wind Contracts: On January 6, 2015, NSTAR Electric terminated a 15-year renewable energy contract with Cape Wind Associates, LLC due to Cape Wind Associates, LLC's failure to fulfill obligations under the contract. Under this contract, NSTAR Electric would have purchased 129 MW of renewable energy from an offshore wind energy facility, which was scheduled to achieve commercial operation by December 2016. As a result, and in accordance with the 2012 DPU-approved comprehensive merger settlement agreement with the DOER, NSTAR Electric will issue a request for proposal (RFP) for new Massachusetts RPS Class I qualified renewable contracts with a term of at least 15 years, for approximately 2 percent of its electric load requirement. The RFP shall be issued no later than March 31, 2016 in accordance with the provisions of the procurement obligations of the Green Communities Act.
NSTAR Gas Distribution Rates: On December 17, 2014, NSTAR Gas filed an application with the DPU requesting an increase in rates, effective January 1, 2016. NSTAR Gas requested an increase in base distribution rates of $33.9 million. We expect a final decision in the fourth quarter of 2015.
New Hampshire:
Distribution Rates: In 2014, PSNH filed for a distribution rate decrease in accordance with the Earnings Sharing Agreement addressed in the 2010 NHPUC approved distribution rate case settlement. On June 27, 2014, the NHPUC approved a one year decrease to distribution rates of $1.3 million, effective July 1, 2014.
ES and SCRC Rates: On December 15, 2014, PSNH updated its request with the NHPUC to adjust its ES and SCRC rates effective January 1, 2015. PSNH's update proposed to increase the current ES and SCRC billing rates to reflect projected costs for 2015. On December 29, 2014, the NHPUC approved the request. The approved energy supply portion of the 2015 rate is 10.56 cents per kWh and the SCRC rate for 2015 is 0.110 cents per kWh.
Clean Air Project Prudence Proceeding: The Clean Air Project, which involved the installation of wet scrubber technology at PSNH's Merrimack coal-fired generation station in Bow, New Hampshire, pursuant to state law, was placed in service in September 2011. In November 2011, the NHPUC opened a docket to review the Clean Air Project, including the establishment of temporary rates for near-term recovery of Clean Air Project costs, a prudence review of PSNH's overall construction program, and establishment of permanent rates for recovery of prudently incurred Clean Air Project costs. In April 2012, the NHPUC issued an order authorizing temporary rates to recover a significant portion of the Clean Air Project costs. The docket remains open to conduct a comprehensive prudence review of the Clean Air Project and the establishment of permanent rates. The temporary rates will remain in effect until permanent rates allowing full recovery of all prudently incurred costs are approved. At that time, the NHPUC will reconcile recoveries collected under the temporary rates with approved permanent rates.
The NHPUC concluded its prudence hearings in October 2014. On December 26, 2014, PSNH requested that the NHPUC stay this proceeding in order to allow discussions to take place with other significant parties to determine whether a collaborative resolution of all issues was achievable. The New Hampshire Governor and Senate Majority Leader expressed support for this effort. On January 15, 2015, the NHPUC issued an order granting the motion to stay in this proceeding, and settlement discussions have ensued.
While we cannot predict with certainty the outcome of the Clean Air Project prudence review, we believe all costs were incurred appropriately and continue to remain probable of recovery.
Generation: In 2013, the NHPUC opened a docket to investigate market conditions affecting PSNH's ES rate, how PSNH will maintain just and reasonable rates in light of those conditions, and any impact of PSNH's generation ownership on the New Hampshire competitive electric market. The NHPUC accepted from the NHPUC Staff a "Report on Investigation into Market Conditions, Default Service Rate, Generation Ownership and Impact on the Competitive Electricity Market." The report recommended that the NHPUC examine whether default service rates remain sustainable on a going forward basis, define "just and reasonable" with respect to default service in the context of competitive retail markets, analyze the current and expected value of PSNH's generating units, and identify means to mitigate and address stranded cost recovery.
In 2013, the NHPUC issued a Request for Proposal to hire a valuation expert to determine the market value of PSNH's generation assets and entitlements. The State of New Hampshire Legislative Oversight Committee on Electric Utility Restructuring (Oversight Committee) requested that the NHPUC conduct an analysis to determine whether it is now in the economic interest of PSNH's retail customers for PSNH to divest its interest in generation plants. The Oversight Committee asked for a preliminary report on the findings by April 1, 2014 that would include at a minimum the NHPUC Staff's position, the analysis of the valuation expert, and any recommendations for legislation that may be needed concerning divestiture or otherwise related to this issue.
On April 1, 2014, the NHPUC staff issued a "Preliminary Status Report Addressing the Economic Interest of PSNH's Retail Customers as it Relates to the Potential Divestiture of PSNH's Generating Plants," which included a consultant's analysis of the fair market value of PSNH generating assets and long-term power purchase contracts. The consultant's analysis estimated the fair market value of PSNH's generation assets to be $225 million as of December 31, 2013 and compared that amount to a stated net book value of $660 million, implying potential "stranded costs" of approximately $435 million. NHPUC staff made three recommendations: (1) that any further actions relating to PSNH's generating assets await a final decision in the Clean Air Project (scrubber) prudence proceeding; (2) that existing laws regarding divestiture, energy service, and cost recovery be harmonized; and (3) that ISO-NE provide input on the economic and reliability consequences of retirement of PSNH's coal- and oil-fired electric generating plants.
During the 2014 Legislative session, in response to the NHPUC staff report, the Legislature enacted changes to the laws governing divestiture of PSNH's generation assets, effective September 30, 2014. The new law required the NHPUC to initiate a proceeding before January 1, 2015, to determine whether all or some of PSNH's generation assets should be divested. The NHPUC opened its docket DE 14-238 on September 16, 2014. A progress report from the NHPUC must be provided to the Oversight Committee by March 31, 2015. The law gives the NHPUC express authority
to order the divestiture of all or some of PSNH's generation assets if the NHPUC finds it is in the economic interest of customers to do so. The law also clarified the definition of "stranded costs" to include costs approved for recovery by the NHPUC in connection with the divestiture or retirement of PSNH's generation assets.
In the event of generation asset divestiture or retirement, present law and the PSNH Restructuring Settlement Agreement approved in 2000 require that the NHPUC provide recovery of any stranded costs by PSNH. We continue to believe generation investments and prudently-incurred costs remain probable of recovery.
Legislative and Policy Matters
Federal:
On December 19, 2014, the "Tax Increase Prevention Act of 2014" became law, which extended the accelerated deduction of depreciation to businesses through 2014. This extended stimulus provides NU with cash flow benefits of approximately $200 million (approximately $70 million at CL&P) in 2015.
Massachusetts:
On July 7, 2014, Massachusetts enacted "An Act Relative to Natural Gas Leaks" (the Act). The Act establishes a uniform natural gas leak classification standard for all Massachusetts natural gas utilities and a program that accelerates the replacement of aging natural gas infrastructure. The program will enable companies, including NSTAR Gas, to better manage the scheduling and costs of replacement. The Act also calls for the DPU to authorize natural gas utilities to design and offer programs to customers that will increase the availability, affordability and feasibility of natural gas service for new customers. On October 31, 2014, NSTAR Gas filed the GSEP with the DPU. We expect a decision on the program in April 2015.
Critical Accounting Policies
The preparation of financial statements in conformity with GAAP requires management to make estimates, assumptions and, at times, difficult, subjective or complex judgments. Changes in these estimates, assumptions and judgments, in and of themselves, could materially impact our financial position, results of operations or cash flows. Our management communicates to and discusses with the Audit Committee of our Board of Trustees significant matters relating to critical accounting policies. Our critical accounting policies 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: The accounting policies of the Regulated companies follow the application of accounting guidance for entities with rate-regulated operations and reflect the effects of the rate-making process.
The application of accounting guidance for rate-regulated enterprises results in recording regulatory assets and liabilities. Regulatory assets represent the deferral of incurred costs that are probable of future recovery in customer rates. Regulatory assets are amortized as the incurred costs are recovered through customer rates. In some cases, we record regulatory assets before approval for recovery has been received from the applicable regulatory commission. We must use judgment to conclude that costs deferred as regulatory assets are probable of future recovery. We base our conclusion on certain factors, including, but not limited to, regulatory precedent. Regulatory liabilities represent revenues received from customers to fund expected costs that have not yet been incurred or probable future refunds to customers.
We use our best judgment when recording regulatory assets and liabilities; however, regulatory commissions can reach different conclusions about the recovery of costs, and those conclusions could have a material impact on our financial statements. We believe it is probable that the Regulated companies will recover the regulatory assets that have been recorded. If we determined that we could no longer apply the accounting guidance applicable to rate-regulated enterprises to our operations, or that we could not conclude that it is probable that costs would 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 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, when there is a change in estimates and under other circumstances.
The Regulated companies estimate unbilled sales monthly using the daily load cycle method. The daily load cycle method allocates billed sales to the current calendar month based on the daily load for each billing cycle. The billed sales are subtracted from total month load, net of delivery losses, to estimate unbilled sales. Unbilled revenues are estimated by first allocating unbilled sales to the respective customer classes, then applying an estimated rate by customer class to those sales. The estimate of unbilled revenues is sensitive to numerous factors, such as energy demands, weather and changes in the composition of customer classes that can significantly impact the amount of revenues recorded.
Pension and PBOP: We sponsor Pension and PBOP Plans to provide retirement benefits to our employees. Effective January 1, 2015, the two Pension Plans were merged into one Pension Plan, sponsored by NUSCO, and the PBOP Plans were merged into one PBOP Plan, sponsored by NUSCO. For each of these plans, several significant assumptions are used to determine the projected benefit obligation, funded status and net periodic benefit cost. These assumptions include the expected long-term rate of return on plan assets, discount rate, compensation/progression rate, mortality assumptions, and health care cost trend rates. We evaluate these assumptions at least annually and adjust them as necessary. Changes in these assumptions could have a material impact on our financial position, results of operations or cash flows.
Pre-tax net periodic benefit expense (excluding SERP) for the Pension Plans was $118.4 million, $236.3 million and $234.9 million for the years ended December 31, 2014, 2013 and 2012, respectively. The pre-tax net periodic benefit expense for the PBOP Plans was $8.1 million, $32.6 million and $72.3 million for the years ended December 31, 2014, 2013 and 2012, respectively. NSTAR Pension and PBOP expense was included in NU beginning April 10, 2012.
Expected Long-Term Rate of Return on Plan Assets: In developing this assumption, we consider historical and expected returns and 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, 2014, 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 2015 Pension and PBOP expense, our expected long-term rate of return of 8.25 percent for all plans was used reflecting our target asset allocations.
Discount Rate: Payment obligations related to the Pension and PBOP Plans are discounted at interest rates applicable to the expected timing of each plan's cash flows. The discount rate that is utilized in determining the Pension and PBOP obligations is based on a yield-curve approach. This approach is based on 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, 2014, the discount rates used to determine the funded status were 4.2 percent for the Pension Plans and 4.22 percent for the PBOP Plans. As of December 31, 2013, the discount rates used were 5.03 percent for the NUSCO Pension Plan, 4.85 percent for the NSTAR Pension Plan, 4.78 percent for the NUSCO PBOP Plans and 5.10 percent for the NSTAR PBOP Plan. As of December 31, 2014, the decreases in the discount rates resulted in an increase on NU’s funded status liability of approximately $530 million and $110 million for the Pension and PBOP Plans, respectively.
Compensation/Progression Rate: This assumption reflects the expected long-term salary growth rate, including consideration of the levels of increases built into collective bargaining agreements, and impacts the estimated benefits that Pension Plan participants receive in the future. As of December 31, 2014, the compensation/progression rate used to determine the funded status was 3.5 percent.
Mortality Assumptions: Assumptions as to mortality of the participants in our Pension and PBOP Plans are a key estimate in measuring the expected payments a participant may receive over their lifetime and the plan liability we need to record. During 2014, the Society of Actuaries released a series of updated mortality tables resulting from recent studies that measured mortality rates for various groups of individuals. The updated mortality tables released in 2014 reflect increased life expectancy of plan participants by 3 to 5 years and have the effect of increasing the estimate of benefits to be provided to plan participants. As of December 31, 2014, the impact of this adoption on NU’s funded status was an increase in the liability of approximately $340 million and $82 million for the Pension and PBOP Plans, respectively.
Actuarial Determination of Expense: Pension and PBOP expense is determined by our actuaries and consists of service cost and prior service cost, interest cost based on the discounting of the obligations, amortization of actuarial gains and losses and amortization of the net transition obligation (which was fully amortized in 2013), offset by the expected return on plan assets. Actuarial gains and losses represent differences between assumptions and actual information or updated assumptions.
Effective January 1, 2015, as a result of the merger of the NUSCO Pension and PBOP plans into the respective NSTAR plans, the NSTAR accounting policies became effective for the NUSCO plans. For the NSTAR Pension and PBOP plans, we apply a corridor approach to determine the potential actuarial gain or loss to be amortized in the Pension and PBOP net periodic benefit expense. This amortization approach is applied if the unrecognized actuarial gains or losses exceed 10 percent of the greater of the fair value of plan assets or the projected benefit obligation. This excess is amortized over the average remaining service period of active plan participants. In addition, for the NSTAR plans, 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 actuarial gains and losses. For the years ended December 31, 2014, 2013 and 2012, the NUSCO Pension and PBOP plans did not utilize the corridor approach, and the expected return on plan assets was determined by applying our assumed long-term rate of return to a four-year rolling average of plan asset fair values. This calculation recognized investment gains or losses over a four-year period from the years in which they occurred.
Forecasted Expenses and Expected Contributions: We estimate that the expense for the Pension and PBOP Plans will be approximately $130 million and $4 million, respectively, in 2015. Pension and PBOP expense for subsequent years will depend on future investment performance, changes in future discount rates and other assumptions, and various other factors related to the populations participating in the plans. Pension and PBOP expense charged to earnings is net of the amounts capitalized.
Our policy is to annually fund the Pension Plans in an amount at least equal to the amount that will satisfy federal requirements. We contributed $171.6 million to the Pension Plans in 2014, of which $101 million was contributed by NSTAR Electric. We currently estimate approximately $155 million of contributions to the Pension Plan in 2015.
For the PBOP Plans, it is our policy to annually fund the PBOP Plans up to the maximum tax-deductible level permitted. We contributed $40 million to the PBOP Plans in 2014. We currently estimate approximately $27 million in contributions to the PBOP Plan in 2015.
Sensitivity Analysis: The following represents the hypothetical increase to the Pension Plans' (excluding SERP) and PBOP Plans' reported annual cost as a result of a change in the following assumptions by 50 basis points:
| Increase in Pension Plan Cost | Increase in PBOP Plan Cost | |||||||||||
| (Millions of Dollars) | As of December 31, | |||||||||||
| Assumption Change | 2014 | 2013 | 2014 | 2013 | ||||||||
| NU | ||||||||||||
| Lower expected long-term rate of return | $ | 19.3 | $ | 17.2 | $ | 4.0 | $ | 3.4 | ||||
| Lower discount rate | $ | 19.1 | $ | 22.3 | $ | 2.2 | $ | 6.8 | ||||
| Higher compensation rate | $ | 10.2 | $ | 12.4 | N/A | N/A |
Health Care Cost: As of December 31, 2014, the health care cost trend rate assumption used to determine the PBOP Plans' year end funded status was 6.5 percent, subsequently decreasing to an ultimate rate of 4.5 percent in 2023. The effect of a hypothetical increase in the health care cost trend rate by one percentage point would be an increase to the service and interest cost components of PBOP Plan expense by $5.3 million in 2014, and a $111.2 million increase to the PBOP obligation.
Goodwill: We have recorded approximately $3.5 billion of goodwill associated with previous mergers and acquisitions. We have identified our reporting units for purposes of allocating and testing goodwill as Electric Distribution, Electric Transmission and Natural Gas Distribution. These reporting units are consistent with our operating segments underlying our reportable segments. Electric Distribution and Electric Transmission reporting units include carrying values for the respective components of CL&P, NSTAR Electric, PSNH and WMECO. The Natural Gas Distribution reporting unit includes the carrying values of NSTAR Gas and Yankee Gas. As of December 31, 2014, goodwill was allocated to the reporting units as follows: $2.5 billion to Electric Distribution, $0.6 billion to Electric Transmission, and $0.4 billion to Natural Gas Distribution.
We are required to test goodwill balances for impairment at least annually by considering the fair values of the reporting units, which requires us to use estimates and judgments. We have selected October 1st of each year as the annual goodwill impairment testing date. Goodwill impairment is deemed to exist if the carrying value of a reporting unit exceeds its estimated fair value and if the implied fair value of goodwill based on the estimated fair values of the reporting units' assets and liabilities is less than the carrying amount of the goodwill. If goodwill were deemed to be impaired, it would be written down in the current period to the extent of the impairment.
We performed an impairment test of goodwill as of October 1, 2014 for the Electric Distribution, Electric Transmission and Natural Gas Distribution reporting units. This evaluation required the test 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. The 2014 goodwill impairment test resulted in a conclusion that goodwill is not impaired and none of the reporting units is at risk of a goodwill impairment.
Income Taxes: Income tax expense is estimated annually for each of the jurisdictions in which we operate. This process 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, including items that directly impact our tax return as a result of a 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. The income tax estimation process impacts all of our segments. We record income tax expense quarterly using an estimated annualized effective tax rate.
We also account for uncertainty in income taxes, which applies to all income tax positions previously filed in a tax return and income tax positions expected to be taken in a future tax return that have been reflected on our balance sheets. The determination of whether a tax position meets the recognition threshold under applicable accounting guidance is based on facts and circumstances available to us. Once a tax position meets the recognition threshold, the tax benefit is measured using a cumulative probability assessment. Assigning probabilities in measuring a recognized tax position and evaluating new information or events in subsequent periods requires significant judgment and could change previous conclusions used to measure the tax position estimate. New information or events may include tax examinations or appeals (including information gained from those examinations), developments in case law, settlements of tax positions, changes in tax law and regulations, rulings by taxing authorities and statute of limitation expirations. Such information or events may have a significant impact on our financial position, results of operations and cash flows.
Accounting for Environmental Reserves: Environmental reserves are accrued when assessments indicate it is probable that a liability has been incurred and an amount can be reasonably estimated. Adjustments made to estimates of environmental liabilities could have a significant 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. Our estimates 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, our valuations of investments in our Pension and PBOP Plans, and nonrecurring fair value measurements of nonfinancial assets such as goodwill and AROs.
Changes in fair value of the Regulated company derivative contracts are recorded as Regulatory Assets or Liabilities, as we recover the costs of these contracts in rates charged to customers. These valuations are sensitive to the prices of energy and energy-related products in future years for which markets have not yet developed and assumptions are made.
We use quoted market prices when available to determine fair values of financial instruments. If quoted market prices are not available, fair value is determined using quoted prices for similar instruments in active markets, quoted prices for identical or similar instruments that are not active and model-derived valuations. When quoted prices in active markets for the same or similar instruments are not available, we value derivative contracts using models that incorporate both observable and unobservable inputs. Significant unobservable inputs utilized in the models include energy and energy-related product prices for future years for long-dated derivative contracts and market volatilities. Discounted cash flow valuations incorporate estimates of premiums or discounts, reflecting risk adjusted profit that would be required by a market participant to arrive at an exit price, using available historical market transaction information. Valuations of derivative contracts also reflect our estimates of nonperformance risk, including credit risk.
Other Matters
Accounting Standards: For information regarding new accounting standards, see Note 1C, "Summary of Significant Accounting Policies - Accounting Standards," to the financial statements.
Contractual Obligations and Commercial Commitments: Information regarding our contractual obligations and commercial commitments as of December 31, 2014 is summarized annually through 2019 and thereafter as follows:
| NU | |||||||||||||||||||||
| (Millions of Dollars) | 2015 | 2016 | 2017 | 2018 | 2019 | Thereafter | Total | ||||||||||||||
| Long-term debt maturities (a) | $ | 216.7 | $ | 200.0 | $ | 745.0 | $ | 810.0 | $ | 800.0 | $ | 4,956.6 | $ | 7,728.3 | |||||||
| Estimated interest payments on existing debt (b) | 336.5 | 330.7 | 326.2 | 273.9 | 246.2 | 2,502.3 | 4,015.8 | ||||||||||||||
| Capital leases (c) | 2.4 | 2.2 | 2.1 | 2.1 | 2.0 | 3.5 | 14.3 | ||||||||||||||
| Operating leases (d) | 20.1 | 17.6 | 14.6 | 10.5 | 8.6 | 22.5 | 93.9 | ||||||||||||||
| Funding of pension obligations (d) (e) | 154.6 | 146.2 | 145.4 | 76.0 | 15.0 | N/A | 537.2 | ||||||||||||||
| Funding of PBOP obligations (d) | 26.5 | 27.9 | 26.3 | 7.1 | 4.1 | 4.5 | 96.4 | ||||||||||||||
| Estimated future annual long-term contractual costs (f) | 685.8 | 598.2 | 421.6 | 327.6 | 290.0 | 2,198.4 | 4,521.6 | ||||||||||||||
| Total (g) | $ | 1,442.6 | $ | 1,322.8 | $ | 1,681.2 | $ | 1,507.2 | $ | 1,365.9 | $ | 9,687.8 | $ | 17,007.5 |
| CL&P | |||||||||||||||||||||
| (Millions of Dollars) | 2015 | 2016 | 2017 | 2018 | 2019 | Thereafter | Total | ||||||||||||||
| Long-term debt maturities (a) | $ | 162.0 | $ | - | $ | 250.0 | $ | 300.0 | $ | 250.0 | $ | 1,640.3 | $ | 2,602.3 | |||||||
| Estimated interest payments on existing debt (b) | 129.0 | 126.5 | 122.5 | 104.2 | 88.8 | 1,138.8 | 1,709.8 | ||||||||||||||
| Capital leases (c) | 2.0 | 1.9 | 2.0 | 2.0 | 2.0 | 3.5 | 13.4 | ||||||||||||||
| Operating leases (d) | 4.3 | 3.8 | 2.6 | 1.5 | 1.1 | 4.0 | 17.3 | ||||||||||||||
| Funding of pension obligations (d) (e) | - | 0.8 | 19.7 | 18.4 | 4.3 | N/A | 43.2 | ||||||||||||||
| Estimated future annual long-term contractual costs (f) | 233.4 | 241.8 | 169.1 | 123.4 | 106.4 | 779.7 | 1,653.8 | ||||||||||||||
| Total (g) | $ | 530.7 | $ | 374.8 | $ | 565.9 | $ | 549.5 | $ | 452.6 | $ | 3,566.3 | $ | 6,039.8 |
(a)
Long-term debt maturities exclude the spent nuclear fuel obligation, net unamortized premiums and discounts, 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 2014 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 NU's estimated minimum pension contributions to its qualified Pension Plans required under federal legislation. Contributions in 2016 through 2019 and thereafter will vary depending on many factors, including the performance of existing plan assets, valuation of the plan's liabilities and long-term discount rates, and are subject to change.
(f)
Other than certain derivative contracts held by the Regulated companies, these obligations are not included on our balance sheets.
(g)
Does not include other long-term liabilities recorded on our balance sheet, such as environmental reserves, employee medical insurance, workers compensation and long-term disability insurance reserves, ARO liability reserves and other reserves, as we cannot make reasonable estimates of the timing of payments. Also does not include an NU contingent commitment not included on our balance sheets of approximately $30 million to an energy investment fund, which would be invested under certain conditions, as we cannot make reasonable estimates of the periods or the investment contributions.
For further information regarding our contractual obligations and commercial commitments, see Note 6, "Asset Retirement Obligations," Note 7, "Short-Term Debt," Note 8, "Long-Term Debt," Note 9A, "Employee Benefits - Pension Benefits and Postretirement Benefits Other Than Pensions," Note 11, "Commitments and Contingencies," and Note 12, "Leases," to the financial statements.
RESULTS OF OPERATIONS – NORTHEAST UTILITIES AND SUBSIDIARIES
The following provides the amounts and variances in operating revenues and expense line items in the statements of income for NU for the years ended December 31, 2014, 2013, and 2012 included in this Annual Report on Form 10-K. The year ended December 31, 2012 amounts include the operations of NSTAR beginning April 10, 2012.
Comparison of 2014 to 2013:
| For the Years Ended December 31, | |||||||||||||
| Increase/ | |||||||||||||
| (Millions of Dollars) | 2014 | 2013 | (Decrease) | Percent | |||||||||
| Operating Revenues | $ | 7,741.9 | $ | 7,301.2 | $ | 440.7 | 6.0 | % | |||||
| Operating Expenses: | |||||||||||||
| Purchased Power, Fuel and Transmission | 3,021.6 | 2,483.0 | 538.6 | 21.7 | |||||||||
| Operations and Maintenance | 1,427.6 | 1,515.0 | (87.4) | (5.8) | |||||||||
| Depreciation | 614.7 | 610.8 | 3.9 | 0.6 | |||||||||
| Amortization of Regulatory Assets, Net | 10.7 | 206.3 | (195.6) | (94.8) | |||||||||
| Amortization of Rate Reduction Bonds | - | 42.6 | (42.6) | (100.0) | |||||||||
| Energy Efficiency Programs | 473.1 | 401.9 | 71.2 | 17.7 | |||||||||
| Taxes Other Than Income Taxes | 561.4 | 512.2 | 49.2 | 9.6 | |||||||||
| Total Operating Expenses | 6,109.1 | 5,771.8 | 337.3 | 5.8 | |||||||||
| Operating Income | 1,632.8 | 1,529.4 | 103.4 | 6.8 | |||||||||
| Interest Expense | 362.1 | 338.7 | 23.4 | 6.9 | |||||||||
| Other Income, Net | 24.6 | 29.9 | (5.3) | (17.7) | |||||||||
| Income Before Income Tax Expense | 1,295.3 | 1,220.6 | 74.7 | 6.1 | |||||||||
| Income Tax Expense | 468.3 | 426.9 | 41.4 | 9.7 | |||||||||
| Net Income | 827.0 | 793.7 | 33.3 | 4.2 | |||||||||
| Net Income Attributable to Noncontrolling Interests | 7.5 | 7.7 | (0.2) | (2.6) | |||||||||
| Net Income Attributable to Controlling Interest | $ | 819.5 | $ | 786.0 | $ | 33.5 | 4.3 | % | |||||
| Operating Revenues | |||||||||||||
| For the Years Ended December 31, | |||||||||||||
| Increase / | |||||||||||||
| (Millions of Dollars) | 2014 | 2013 | (Decrease) | Percent | |||||||||
| Electric Distribution | $ | 5,663.4 | $ | 5,362.3 | $ | 301.1 | 5.6 | % | |||||
| Natural Gas Distribution | 1,007.3 | 855.8 | 151.5 | 17.7 | |||||||||
| Transmission | 1,018.2 | 978.7 | 39.5 | 4.0 | |||||||||
| Other and Eliminations | 53.0 | 104.4 | (51.4) | (49.2) | |||||||||
| Total Operating Revenues | $ | 7,741.9 | $ | 7,301.2 | $ | 440.7 | 6.0 | % | |||||
| A summary of our retail electric sales volumes and firm natural gas sales volumes were as follows: | |||||||||||||
| For the Years Ended December 31, | |||||||||||||
| Increase/ | |||||||||||||
| 2014 | 2013 | (Decrease) | Percent | ||||||||||
| Retail Electric Sales Volumes in GWh | 54,442 | 55,331 | (889) | (1.6) | % | ||||||||
| Firm Natural Gas Sales Volumes in Million Cubic Feet | 104,191 | 98,258 | 5,933 | 6.0 |
Operating Revenues increased $440.7 million in 2014 compared to 2013.
The most significant factor in the increase in revenues relates to cost tracking mechanisms for the recovery of higher costs associated with the procurement of energy supply, which increased $506.8 million and $126.9 million for electric distribution and natural gas distribution, respectively. These costs were impacted by the overall New England wholesale energy supply market in which higher natural gas delivery costs had an adverse impact on the cost of electric energy purchased for our retail electric customers and the cost of natural gas purchased on behalf of our retail natural gas customers. Energy supply costs are recovered from customers in rates through cost tracking mechanisms and therefore have no impact on earnings. These costs and related recovery impacts were partially offset by decreases in transition cost recovery revenues, which are recovered through cost tracking mechanisms, reflecting the full collection in 2013 of previously deferred costs, as well as the full amortization of RRBs.
Firm base natural gas distribution revenues increased $26.3 million in 2014, as compared to 2013, which reflected a 6 percent increase in firm natural gas sales volumes. The increase in sales volumes was driven primarily by the colder winter weather experienced throughout our service territories in the first quarter of 2014. The weather conditions experienced were significantly colder than both normal and the same period last year throughout New England and our service territories in Connecticut and Massachusetts. Weather-normalized total firm natural gas sales volumes (based on 30-year average temperatures) increased 2.9 percent in 2014, as compared to 2013, due primarily to residential and commercial customer growth.
Base electric distribution revenues decreased $12.1 million in 2014 compared to 2013. This reflected the impact of a 1.6 percent decrease in retail electric sales volumes. The decrease in sales volumes was driven primarily by the cooler summer weather in 2014 compared to 2013, as well as the impact of our utility-sponsored energy efficiency programs. Weather-normalized retail electric sales volumes decreased 1 percent in 2014, as compared to 2013, reflecting the impact of our utility-sponsored energy efficiency programs. The negative sales volume impact was partially offset by the impact of CL&P's base distribution rate increase effective December 1, 2014.
CL&P and NSTAR Electric recognized lost base revenue (LBR) related to reductions in sales volume as a result of energy efficiency. LBR is recovered from retail distribution customers. Including the impact from the recognition of LBR, base distribution revenues increased in 2014, as compared to 2013. We recognized $45.2 million of LBR in 2014, compared to $20.3 million in 2013. Effective December 1, 2014, CL&P no longer recognizes LBR due to its revenue decoupling mechanism, which, similar to WMECO's revenue decoupling mechanism, provides a base amount of distribution revenues ($1.041 billion on an annual basis) that effectively breaks the relationship between revenues and customer electricity usage. The revenue decoupling mechanism is designed to allow each of CL&P and WMECO to encourage energy efficiency for its customers without negatively impacting its revenues.
Transmission revenues increased $39.5 million in 2014, as compared to 2013, due primarily to the recovery of higher revenue requirements associated with ongoing investments in our transmission infrastructure. This increase was partially offset by the impact of the $37 million net reserve recorded in 2014 as a result of the 2014 FERC ROE orders, compared to the $23.7 million reserve recorded in 2013 for the FERC ALJ initial decision in the FERC base ROE complaints.
Purchased Power, Fuel and Transmission expense includes costs associated with purchasing electricity and natural gas on behalf of our customers. These energy supply costs are recovered from customers in rates through reconciling cost tracking mechanisms, which have no impact on earnings (tracked costs). Purchased Power, Fuel and Transmission increased in 2014, as compared to 2013, due primarily to the following:
| (Millions of Dollars) | Increase/(Decrease) | |
| Electric Distribution | $ | 458.2 |
| Natural Gas Distribution | 104.1 | |
| Transmission | (2.8) | |
| Other and Eliminations | (20.9) | |
| Total Purchased Power, Fuel and Transmission | $ | 538.6 |
The increase in purchased power, fuel and transmission at the electric and natural gas distribution businesses were driven by the higher costs associated with the procurement of energy supply. As a result of increases in the New England wholesale energy supply market for both electricity and natural gas, the costs incurred to purchase energy on behalf of our customers were significantly higher in 2014 compared to 2013. Our energy supply costs were impacted by higher natural gas delivery costs, which had an adverse impact on the cost of electric energy purchased for our retail electric customers and the cost of natural gas purchased on behalf of our retail natural gas customers.
Operations and Maintenance expense includes tracked costs and costs that are recovered through base electric and natural gas distribution rates, which therefore impact earnings (non-tracked costs). Operations and Maintenance decreased in 2014, as compared to 2013, due primarily to the following:
| (Millions of Dollars) | Increase/(Decrease) | |
| Base Electric Distribution: | ||
| Labor and other employee-related costs, including pension costs | $ | (77.3) |
| Implementation of a new outage restoration program at CL&P | 9.2 | |
| Storm restoration costs | (11.4) | |
| All other operations and maintenance | (29.4) | |
| Total Base Electric Distribution | (108.9) | |
| Total Base Natural Gas Distribution | (0.9) | |
| Total Tracked costs (Transmission and Electric and Natural Gas Distribution) | 16.6 | |
| Total Distribution and Transmission | (93.2) | |
| Other and eliminations: | ||
| Integration and severance costs | 13.3 | |
| All other (including eliminations) | (7.5) | |
| Total Operations and Maintenance | $ | (87.4) |
Depreciation increased in 2014, as compared to 2013, due primarily to an increase related to higher utility plant balances resulting from completed construction projects placed into service ($34.5 million), partially offset by a decrease in the CYAPC and YAEC decommissioning costs, which do not impact earnings ($30.6 million).
Amortization of Regulatory Assets, Net, which are tracked costs, include certain regulatory-approved tracking mechanisms. Fluctuations in these costs are recovered from customers in rates and have no impact on earnings. Amortization of Regulatory Assets, Net, decreased in 2014, as compared to 2013, due primarily to the following:
| (Millions of Dollars) | Increase/(Decrease) | |
| NSTAR Electric (primarily recovery of transition costs) | $ | (236.4) |
| PSNH (primarily default energy service charge) | (9.2) | |
| CL&P (primarily energy supply and energy-related costs) | 54.4 | |
| WMECO (primarily recovery of transition costs) | (3.0) | |
| Other | (1.4) | |
| Total Amortization of Regulatory Assets, Net | $ | (195.6) |
Amortization of Rate Reduction Bonds decreased in 2014, as compared to 2013, due to the maturity in 2013 of RRBs of NSTAR Electric, PSNH and WMECO.
Energy Efficiency Programs, which are tracked costs, increased in 2014, as compared to 2013, due primarily to the expanded energy conservation programs at CL&P in 2014 as a result of 2013 legislative action, and an increase in energy efficiency costs in accordance with the three-year program guidelines established by the DPU at NSTAR Electric and WMECO, partially offset by a decrease in the amortization of previously deferred costs at NSTAR Electric.
Taxes Other Than Income Taxes increased in 2014, as compared to 2013, due primarily to an increase in property taxes as a result of both an increase in utility plant balances and property tax rates.
Interest Expense increased in 2014, as compared to 2013, due primarily to lower interest income related to a decrease in the recovery of previously deferred transition costs ($9.9 million), an increase in interest on long-term debt ($4 million) as a result of new debt issuances in 2014 and the absence in 2014 of the favorable impact from the resolution of a Connecticut state income tax audit in 2013.
Other Income, Net decreased in 2014, as compared to 2013, due primarily to lower unrealized gains on the assets supporting the deferred compensation plans ($13 million), and the absence in 2014 of an insurance policy claim received in 2013 ($1.5 million), partially offset by higher AFUDC related to equity funds ($6.6 million), and a net gain on the sale of land ($4.5 million).
Income Tax Expense increased in 2014, as compared to 2013, due primarily to higher pre-tax earnings ($26.1 million), and higher state taxes and various other impacts ($15.3 million). The higher state taxes include a net reduction in the valuation allowance for state tax positions, which is based on the most recent available data.
Comparison of 2013 to 2012:
| Operating Revenues and Expenses | |||||||||||||
| For the Years Ended December 31, | |||||||||||||
| (Millions of Dollars) | 2013 | 2012 (a) | Increase/ | Percent | |||||||||
| (Decrease) | |||||||||||||
| Operating Revenues | $ | 7,301.2 | $ | 6,273.8 | $ | 1,027.4 | 16.4 | % | |||||
| Operating Expenses: | |||||||||||||
| Purchased Power, Fuel and Transmission | 2,483.0 | 2,084.4 | 398.6 | 19.1 | |||||||||
| Operations and Maintenance | 1,515.0 | 1,583.1 | (68.1) | (4.3) | |||||||||
| Depreciation | 610.8 | 519.0 | 91.8 | 17.7 | |||||||||
| Amortization of Regulatory Assets, Net | 206.3 | 79.8 | 126.5 | (b) | |||||||||
| Amortization of Rate Reduction Bonds | 42.6 | 142.0 | (99.4) | (70.0) | |||||||||
| Energy Efficiency Programs | 401.9 | 313.1 | 88.8 | 28.4 | |||||||||
| Taxes Other Than Income Taxes | 512.2 | 434.2 | 78.0 | 18.0 | |||||||||
| Total Operating Expenses | 5,771.8 | 5,155.6 | 616.2 | 12.0 | |||||||||
| Operating Income | $ | 1,529.4 | $ | 1,118.2 | $ | 411.2 | 36.8 | % |
| (a) | The 2012 results include the operations of NSTAR beginning April 10, 2012. |
| (b) | Percent greater than 100 percent not shown as it is not meaningful. |
| Operating Revenues | ||||||||||||
| For the Years Ended December 31, | ||||||||||||
| (Millions of Dollars) | 2013 | 2012 (a) | Increase/ (Decrease) | Percent | ||||||||
| Electric Distribution | $ | 5,362.3 | $ | 4,716.5 | $ | 645.8 | 13.7 | % | ||||
| Natural Gas Distribution | 855.8 | 572.9 | 282.9 | 49.4 | ||||||||
| Total Distribution | 6,218.1 | 5,289.4 | 928.7 | 17.6 | ||||||||
| Transmission | 978.7 | 861.5 | 117.2 | 13.6 | ||||||||
| Total Regulated Companies | 7,196.8 | 6,150.9 | 1,045.9 | 17.0 | ||||||||
| Other and Eliminations | 104.4 | 122.9 | (18.5) | (15.1) | ||||||||
| Total Operating Revenues | $ | 7,301.2 | $ | 6,273.8 | $ | 1,027.4 | 16.4 | % | ||||
| (a) The 2012 results include the operations of NSTAR beginning April 10, 2012. |
| A summary of our retail electric sales and firm natural gas sales were as follows: | |||||||||
| For the Years Ended December 31, | |||||||||
| 2013 | 2012 (a) | Increase | Percent | ||||||
| Retail Electric Sales in GWh | 55,331 | 54,808 | 523 | 1.0 | % | ||||
| Firm Natural Gas Sales in Million Cubic Feet | 98,258 | 87,527 | 10,731 | 12.3 |
| (a) Results include retail electric sales of NSTAR Electric and the firm natural gas sales of NSTAR Gas from January 1, 2012 through December 31, 2012 for comparative purposes only. |
Our Operating Revenues increased in 2013, as compared to 2012, due primarily to the addition of NSTAR's operations. During the first quarter of 2013, the former operating subsidiaries of NSTAR contributed approximately $800 million of operating revenues. Absent the first quarter 2013 NSTAR operating revenues, our Operating Revenues increased approximately $227 million, as compared to 2012, due primarily to:
·
A $62.5 million increase in transmission revenues, net of applicable eliminations, as a result of the recovery of higher transmission expenses and continuing investments in our transmission infrastructure. The increase was partially offset by the establishment of a reserve related to the FERC ALJ initial decision in the third quarter of 2013.
·
A $34.3 million increase in base electric distribution revenues, net of applicable eliminations, reflecting an increase of approximately 1 percent in retail electric sales. The increase in sales volumes was driven primarily by the colder winter weather experienced throughout our service territories in early and late 2013. In addition, the increase in revenues resulted from the NHPUC-approved distribution rate increases at PSNH effective July 1, 2012 and July 1, 2013 as a result of the 2010 distribution rate case settlement. These positive impacts on revenue were partially offset by the impact of our utility-sponsored energy efficiency programs.
·
A $28.8 million increase in firm natural gas distribution revenues. This increase was driven by the colder winter weather in early and late 2013, residential customer growth, an increase in natural gas conversions, the migration of interruptible customers switching to firm service rates and the addition of gas-fired distributed generation.
·
The remaining increase was due primarily to higher revenues from increases related to our fully reconciling cost recovery mechanisms (tracked costs) related to the recovery of energy supply, retail transmission and utility-sponsored energy efficiency programs. Revenues related to cost recovery mechanisms vary from period to period based on the timing of collections of the costs incurred. These revenues do not result in an impact on earnings.
Purchased Power, Fuel and Transmission increased in 2013, as compared to 2012, due primarily to the following:
| (Millions of Dollars) | Increase/(Decrease) | ||
| The addition of NSTAR's operations | $ | 321.4 | |
| Transmission segment costs | 70.8 | ||
| Firm natural gas sales related costs | 42.0 | ||
| Partially offset by: | |||
| Electric distribution segment fuel and energy supply costs | (13.9) | ||
| CfDs and capacity contracts | (12.0) | ||
| All other items | (9.7) | ||
| $ | 398.6 |
Operations and Maintenance decreased in 2013, as compared to 2012, due primarily to the following:
| (Millions of Dollars) | Increase/(Decrease) | |
| The addition of NSTAR's operations | $ | 123.6 |
| Partially offset by: | ||
| Integration, merger and settlement agreement costs | (150.3) | |
| NU's unregulated contracting business costs | (17.4) | |
| General and administrative costs | (12.9) | |
| Transmission segment costs | (5.2) | |
| Natural gas segment costs | 10.5 | |
| Electric distribution segment costs | 1.3 | |
| All other items | (17.7) | |
| $ | (68.1) |
Depreciation increased in 2013, as compared to 2012, due primarily to the addition of NSTAR ($54.2 million) and the consolidation of CYAPC and YAEC ($13.7 million). Excluding the impact of NSTAR and the consolidation of CYAPC and YAEC, depreciation increased due primarily to higher utility plant balances resulting from completed construction projects placed into service.
Amortization of Regulatory Assets, Net increased in 2013, as compared to 2012, due primarily to the following:
| (Millions of Dollars) | Increase/(Decrease) | |
| The addition of NSTAR's operations | $ | 45.8 |
| Recovery of transition costs at NSTAR Electric | 91.9 | |
| Amortization related to CL&P's SBC and CTA | (6.8) | |
| Other | (4.4) | |
| $ | 126.5 |
Amortization of Rate Reduction Bonds decreased in 2013, as compared to 2012, due primarily to the maturity of NSTAR Electric's, PSNH's, and WMECO's RRBs in 2013, partially offset by the addition of NSTAR Electric's amortization ($15.1 million).
Energy Efficiency Programs increased in 2013, as compared to 2012, due primarily to the addition of NSTAR's operations ($68.6 million), as well as an increase in energy efficiency costs in accordance with the three-year program guidelines established by the DPU at NSTAR Electric and WMECO. All costs are fully recovered through DPU-approved tracking mechanisms and therefore do not impact earnings.
Taxes Other Than Income Taxes increased in 2013, as compared to 2012, due primarily to the addition of NSTAR's operations ($37.8 million). In addition, there was an increase in property taxes ($36.6 million) as a result of an increase in Property, Plant and Equipment and an increase in the property tax rates, and an increase in the Connecticut gross earnings tax ($9.1 million) attributable to an increase in gross earnings.
Interest Expense increased $8.8 million in 2013, as compared to 2012, due primarily to the addition of NSTAR's operations ($22 million) and lower interest income on deferred transition costs ($10.6 million), partially offset by a decrease in Other Interest due primarily to the favorable impact from the resolution of a state income tax audit in the first quarter of 2013, lower interest on short-term debt ($8.8 million) and lower interest on RRBs ($6.1 million).
Other Income, Net increased $10.2 million in 2013, as compared to 2012, due primarily to higher gains on the NU supplemental benefit trust ($6 million) and an increase related to officer insurance policies ($1.7 million).
| Income Tax Expense | ||||||||||||
| For the Years Ended December 31, | ||||||||||||
| (Millions of Dollars) | 2013 | 2012 (a) | Increase | Percent | ||||||||
| Income Tax Expense | $ | 426.9 | $ | 274.9 | $ | 152.0 | 55.3 | % |
(a) The 2012 results include the operations of NSTAR beginning April 10, 2012.
Income Tax Expense increased in 2013, as compared to 2012, due primarily to higher pre-tax earnings ($81 million), the absence in 2013 of both prior year Connecticut and Massachusetts merger settlement agreement impacts ($41 million) and integration merger impacts ($23 million), along with various other items ($7 million).
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, 2014, 2013, and 2012 included in this Annual Report on Form 10-K:
Comparison of 2014 to 2013:
| For the Years Ended December 31, | ||||||||||||||
| Increase/ | ||||||||||||||
| (Millions of Dollars) | 2014 | 2013 | (Decrease) | Percent | ||||||||||
| Operating Revenues | $ | 2,692.6 | $ | 2,442.3 | $ | 250.3 | 10.2 | % | ||||||
| Operating Expenses: | ||||||||||||||
| Purchased Power and Transmission | 982.9 | 872.8 | 110.1 | 12.6 | ||||||||||
| Operations and Maintenance | 494.6 | 523.2 | (28.6) | (5.5) | ||||||||||
| Depreciation | 188.8 | 177.6 | 11.2 | 6.3 | ||||||||||
| Amortization of Regulatory Assets, Net | 59.3 | 4.9 | 54.4 | (a) | ||||||||||
| Energy Efficiency Programs | 156.3 | 89.8 | 66.5 | 74.1 | ||||||||||
| Taxes Other Than Income Taxes | 255.4 | 234.4 | 21.0 | 9.0 | ||||||||||
| Total Operating Expenses | 2,137.3 | 1,902.7 | 234.6 | 12.3 | ||||||||||
| Operating Income | 555.3 | 539.6 | 15.7 | 2.9 | ||||||||||
| Interest Expense | 147.4 | 133.6 | 13.8 | 10.3 | ||||||||||
| Other Income, Net | 13.4 | 15.1 | (1.7) | (11.3) | ||||||||||
| Income Before Income Tax Expense | 421.3 | 421.1 | 0.2 | - | ||||||||||
| Income Tax Expense | 133.5 | 141.7 | (8.2) | (5.8) | ||||||||||
| Net Income | $ | 287.8 | $ | 279.4 | $ | 8.4 | 3.0 | % | ||||||
| (a) Percent greater than 100 percent not shown as it is not meaningful. | ||||||||||||||
| Operating Revenues | ||||||||||||||
| CL&P's retail sales volumes were as follows: | ||||||||||||||
| For the Years Ended December 31, | ||||||||||||||
| 2014 | 2013 | Decrease | Percent | |||||||||||
| Retail Sales Volumes in GWh | 22,046 | 22,404 | (358) | (1.6) | % |
CL&P's Operating Revenues increased $250.3 million in 2014 compared to 2013. The increase primarily reflects recovery of higher costs associated with the procurement of energy supply, which increased $275.4 million, and increased cost recovery related to our energy efficiency programs. The energy supply costs were impacted by the overall wholesale electricity market in New England in which higher natural gas delivery costs had an adverse impact on the cost of electric energy purchased for our retail customers. Energy supply costs are recovered from customers in rates through cost tracking mechanisms and therefore have no impact on earnings.
Partially offsetting this increase was the impact of the $20.7 million net reserve recorded in 2014 as a result of the 2014 FERC ROE orders, as compared to the $12.8 million reserve recorded in 2013 for the FERC ALJ initial decision in the FERC base ROE complaints.
Base distribution revenues increased $9.1 million in 2014 compared to 2013, which was primarily attributable to the impact of the December 1, 2014 base distribution rate increase and the impact of LBR, partially offset by the impact of cooler summer weather as well as energy efficiency programs. Enhancements to CL&P's energy efficiency programs were mandated by the Connecticut legislature in 2013. Through November 30, 2014, CL&P was permitted to bill customers for LBR related to reductions in sales volume as a result of energy efficiency and effective December 1, 2014, fluctuations in retail electric sales volumes do not impact earnings due to the PURA-approved revenue decoupling mechanism as a result of CL&P's base distribution rate case. The revenue decoupling mechanism provides a base amount of distribution revenues ($1.041 billion on an annual basis) that effectively breaks the relationship between revenues and customer electricity usage. The revenue decoupling mechanism is designed to allow CL&P to encourage energy efficiency for its customers without negatively impacting its revenues.
Purchased Power and Transmission expense includes costs associated with purchasing electricity on behalf of CL&P's customers. These energy supply costs are recovered from customers in PURA-approved cost tracking mechanisms, which have no impact on earnings (tracked costs). Purchased Power and Transmission increased in 2014, as compared to 2013, due primarily to the following:
| (Millions of Dollars) | Increase/(Decrease) | |
| Purchased Power Costs | $ | 169.7 |
| Transmission Costs | (50.8) | |
| Other | (8.8) | |
| Total Purchased Power and Transmission | $ | 110.1 |
Included in purchased power are the costs associated with CL&P's generation services charge (GSC) and deferred energy supply costs. The GSC recovers energy-related costs incurred as a result of providing electric generation service supply to all customers that have not migrated to third party suppliers. The increase in purchased power was due primarily to higher average supply prices and increased standard offer load as a result of customers returning from third party suppliers. The decrease in transmission costs was the result of a decrease in the retail transmission cost deferral, which reflects the actual costs of transmission service compared to estimated amounts billed to customers.
Operations and Maintenance expense includes tracked costs and costs that are part of base distribution rates with changes impacting earnings (non-tracked costs). Operations and Maintenance decreased in 2014, as compared to 2013, driven by a $38.4 million reduction in non-tracked costs, which was primarily attributable to lower labor and other employee-related costs, including pension costs, and lower storm restoration costs, partially offset
by an increase in costs for the implementation of a new outage restoration program that began in the second quarter of 2014. Partially offsetting this decrease was a $9.8 million increase in tracked costs, which have no earnings impact, that was primarily attributable to higher tracked bad debt expense and increased transmission maintenance expenses.
Depreciation increased in 2014, as compared to 2013, due primarily to higher utility plant balances resulting from completed construction projects placed into service.
Amortization of Regulatory Assets, Net¸ increased in 2014, as compared to 2013. Fluctuations in energy supply and energy-related costs, which are the primary drivers in amortization, are recovered from customers in rates through cost tracking mechanisms and have no impact on earnings.
Energy Efficiency Programs, which are tracked costs, increased in 2014, as compared to 2013, due primarily to expanded energy conservation programs in 2014 as a result of 2013 legislative action. In 2013, Connecticut enacted into law Public Act 13-298, which implemented a number of recommendations, including allowing electric distribution companies to recover their costs as well as LBR from various state energy policy initiatives and expanded energy efficiency programs.
Taxes Other Than Income Taxes increased in 2014, as compared to 2013, due primarily to an increase in property taxes as a result of both an increase in utility plant balances and property tax rates.
Interest Expense increased in 2014, as compared to 2013, due primarily to an increase in interest on long-term debt ($5 million) as a result of a new debt issuance in April 2014 and an increase in regulatory interest due to the refund of the DOE proceeds in 2014 and the absence in 2014 of the favorable impact from the resolution of a state income tax audit in 2013.
Other Income, Net decreased in 2014, as compared to 2013, due primarily to lower unrealized gains on the assets supporting the deferred compensation plans ($6.7 million), partially offset by a gain on the sale of land ($4.5 million).
Income Tax Expense decreased in 2014, as compared to 2013, due primarily to lower state taxes, which includes the reduction in the valuation allowance for state tax positions, and various other impacts.
EARNINGS SUMMARY
CL&P's earnings increased in 2014, as compared to 2013, due primarily to a decrease in operations and maintenance costs primarily attributable to lower employee-related costs, as well as lower income tax expense due to the net reduction in the valuation allowance for state tax positions. Partially offsetting these favorable earnings impacts were lower retail electric sales volumes, higher depreciation expense, higher property tax expense, higher interest expense and the after-tax reserve recorded for the 2014 FERC ROE orders as compared to the reserve recorded in 2013 for the FERC ALJ initial decision in the FERC base ROE complaints.
Comparison of 2013 to 2012:
| Operating Revenues and Expenses | |||||||||||||
| For the Years Ended December 31, | |||||||||||||
| (Millions of Dollars) | 2013 | 2012 | Increase/ | Percent | |||||||||
| (Decrease) | |||||||||||||
| Operating Revenues | $ | 2,442.3 | $ | 2,407.4 | $ | 34.9 | 1.4 | % | |||||
| Operating Expenses: | |||||||||||||
| Purchased Power and Transmission | 872.8 | 858.2 | 14.6 | 1.7 | |||||||||
| Operations and Maintenance | 523.2 | 635.7 | (112.5) | (17.7) | |||||||||
| Depreciation | 177.6 | 166.9 | 10.7 | 6.4 | |||||||||
| Amortization of Regulatory Assets, Net | 4.9 | 14.4 | (9.5) | (66.0) | |||||||||
| Energy Efficiency Programs | 89.8 | 89.3 | 0.5 | 0.6 | |||||||||
| Taxes Other Than Income Taxes | 234.4 | 215.9 | 18.5 | 8.6 | |||||||||
| Total Operating Expenses | 1,902.7 | 1,980.4 | (77.7) | (3.9) | |||||||||
| Operating Income | $ | 539.6 | $ | 427.0 | $ | 112.6 | 26.4 | % |
| Operating Revenues | |||||||||
| CL&P's retail sales were as follows: | |||||||||
| For the Years Ended December 31, | |||||||||
| 2013 | 2012 | Increase | Percent | ||||||
| Retail Sales in GWh | 22,404 | 22,109 | 295 | 1.3 | % |
CL&P's Operating Revenues increased in 2013, as compared to 2012, due primarily to:
·
A $15.8 million increase in transmission revenues reflecting recovery of higher transmission expenses and continuing transmission infrastructure investments. The increase was partially offset by the establishment of a reserve related to the FERC ALJ initial decision in the third quarter of 2013.
·
A $13.5 million increase in base distribution revenues reflecting a 1.3 percent increase in retail sales. This increase was due primarily to the colder winter weather experienced in early and late 2013.
·
The remaining $5.6 million increase was due primarily to higher collections of costs through reconciling cost tracking mechanisms. These revenues are fully reconciled to the related costs. Therefore this increase in revenues had no impact on earnings.
Purchased Power and Transmission increased in 2013, as compared to 2012, due primarily to the following:
| (Millions of Dollars) | Increase/(Decrease) | |
| Transmission Costs | $ | 45.8 |
| Deferred Fuel Costs | 28.7 | |
| GSC Supply Costs | (44.2) | |
| Purchased Power Contracts | (12.1) | |
| CfD Costs | (7.3) | |
| Other | 3.7 | |
| $ | 14.6 |
The increase in transmission costs was the result of an increase in the retail transmission deferral, which related rates are adjusted on an annual basis as a result of collecting or refunding costs of the transmission systems to customers. The decrease in GSC supply costs was due primarily to lower average supply prices. On July 1, 2013, CL&P began to procure approximately thirty percent of GSC load. Costs associated with the remaining seventy percent of the GSC load are the contractual amounts CL&P must pay to various suppliers that have been awarded the right to supply SS and LRS load through a competitive solicitation process. Purchased Power and Transmission costs are included in regulatory-approved tracking mechanisms and do not impact earnings.
Operations and Maintenance decreased in 2013, as compared to 2012, due primarily to the absence in 2013 of costs recognized in the second quarter of 2012 as a result of the Connecticut merger settlement agreement (which established a $40 million storm fund reserve and provided a $25 million bill credit to customers). In addition, there were lower distribution operating costs ($10.2 million), the absence in 2013 of amortization of the PBOP transition obligation ($6.1 million), lower distribution general and administrative costs ($7.5 million) and lower distribution costs related to customer Energy Independence Act incentives ($6.3 million). These lower costs were partially offset by an increase in distribution routine maintenance and storm-related costs ($7.4 million).
Depreciation increased in 2013, as compared to 2012, due primarily to higher utility plant balances resulting from completed construction projects placed into service.
Amortization of Regulatory Assets, Net decreased in 2013, as compared to 2012, due primarily to a lower net SBC deferral, partially offset by a higher net CTA deferral. SBC revenues were $23 million lower in 2013, as compared to 2012, partially offset by higher hardship program costs of $6.6 million in 2013. CTA revenues were $13.9 million higher in 2013, as compared to 2012, and costs were $30.5 million lower in 2013, as compared to 2012. DOE refunds of $21.6 million were returned to customers in the second half of 2013. All of these items represent reconciliations of previously incurred costs and have a corresponding revenue offset, so there is no earnings impact.
Taxes Other Than Income Taxes increased in 2013, as compared to 2012, due primarily to an increase in property taxes as a result of an increase in Property, Plant and Equipment and an increase in the property tax rates ($11.5 million). In addition, there was an increase in the Connecticut gross earnings tax attributable to an increase in gross earnings ($7.6 million).
Interest Expense increased $0.5 million in 2013, as compared to 2012, due primarily to higher interest on long-term debt ($5.7 million), partially offset by a decrease in other interest as a result of a favorable impact from the resolution of a state income tax audit in the first quarter of 2013 ($5.4 million).
Other Income increased $4.8 million in 2013, as compared to 2012, due primarily to higher gains on the NU supplemental benefit trust.
Income Tax Expense
| For the Years Ended December 31, | |||||||||||
| (Millions of Dollars) | 2013 | 2012 | Increase | Percent | |||||||
| Income Tax Expense | $ | 141.7 | $ | 94.4 | $ | 47.3 | 50.1 | % |
Income Tax Expense increased in 2013, as compared to 2012, due primarily to higher pre-tax earnings ($17.1 million), the absence in 2013 of the impact of costs recognized as a result of the Connecticut merger settlement agreement ($26.6 million), and higher state taxes ($5.7 million), partially offset by various other items ($2.1 million).
LIQUIDITY
In 2014, CL&P had cash flows provided by operating activities of $612.4 million, compared with $495.3 million in 2013. The improved operating cash flows were due primarily to $68.6 million in DOE damages proceeds received in 2014 from the Yankee Companies associated with the spent nuclear fuel litigation, the absence of cash disbursements for major storm restoration costs, and the favorable cash flow impact resulting from an increase in recoveries from customers in 2014, as compared to 2013, relating to regulatory cost recovery tracking mechanisms, partially offset by higher income tax payments in 2014, as compared to 2013, and changes in working capital items.
In 2013, CL&P had cash flows provided by operating activities of $495.3 million, compared with $211.9 million in 2012. The improved cash flows were due primarily to a decrease of approximately $75 million in cash disbursements for storm restoration costs associated primarily with Tropical Storm Irene and the October 2011 snowstorm, the absence of approximately $27 million in 2012 CL&P customer bill credits associated with the October 2011 snowstorm and the absence of $25 million in 2012 CL&P customer bill credits associated with the Connecticut settlement agreement. In addition, operating cash flows benefited from an increase in regulatory overrecoveries where such revenues exceeded costs resulting in a favorable cash flow impact, higher net income and timing of payables. Partially offsetting improved cash flows were income tax payments of $55 million in 2013, compared with income tax refunds of $42 million in 2012.
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 $515.7 million in 2014, compared with $434.9 million in 2013.
Effective July 23, 2014, NU parent and certain of its subsidiaries, including CL&P, extended the expiration date of their joint $1.45 billion revolving credit facility for one additional year to September 6, 2019. The revolving credit facility is to be used primarily to backstop NU parent's $1.45 billion commercial paper program. The commercial paper program allows NU parent to issue commercial paper as a form of short-term debt with intercompany loans to certain subsidiaries, including CL&P. As of December 31, 2014 and 2013, there were intercompany loans from NU parent of $133.4 million and $287.3 million, respectively, to CL&P.
On April 24, 2014, CL&P issued $250 million of 4.30 percent 2014 Series A First Mortgage Bonds, due to mature in 2044. The proceeds, net of issuance costs, were used to repay short-term borrowings.
On September 15, 2014, CL&P repaid at maturity the $150 million of 4.80 percent 2004 Series A First Mortgage Bonds.
On August 27, 2014, PURA approved CL&P's request to extend the authorization period for issuance of up to $366.4 million in long-term debt from December 31, 2014 to December 31, 2015.
Financing activities in 2014 included $171.2 million in common stock dividends paid to NU parent.
RESULTS OF OPERATIONS – NSTAR ELECTRIC COMPANY AND SUBSIDIARY
The following provides the amounts and variances in operating revenues and expense line items in the statements of income for NSTAR Electric for the years ended December 31, 2014 and 2013 included in this Annual Report on Form 10-K:
| For the Years Ended December 31, | |||||||||||||
| Increase/ | |||||||||||||
| (Millions of Dollars) | 2014 | 2013 | (Decrease) | Percent | |||||||||
| Operating Revenues | $ | 2,536.7 | $ | 2,493.5 | $ | 43.2 | 1.7 | % | |||||
| Operating Expenses: | |||||||||||||
| Purchased Power and Transmission | 1,122.3 | 849.1 | 273.2 | 32.2 | |||||||||
| Operations and Maintenance | 327.0 | 376.4 | (49.4) | (13.1) | |||||||||
| Depreciation | 188.7 | 180.3 | 8.4 | 4.7 | |||||||||
| Amortization of Regulatory Assets/(Liabilities), Net | (6.3) | 230.1 | (236.4) | (a) | |||||||||
| Amortization of Rate Reduction Bonds | - | 15.1 | (15.1) | (100.0) | |||||||||
| Energy Efficiency Programs | 193.5 | 206.5 | (13.0) | (6.3) | |||||||||
| Taxes Other Than Income Taxes | 133.0 | 127.8 | 5.2 | 4.1 | |||||||||
| Total Operating Expenses | 1,958.2 | 1,985.3 | (27.1) | (1.4) | |||||||||
| Operating Income | 578.5 | 508.2 | 70.3 | 13.8 | |||||||||
| Interest Expense | 77.9 | 70.4 | 7.5 | 10.7 | |||||||||
| Other Income, Net | 4.5 | 3.6 | 0.9 | 25.0 | |||||||||
| Income Before Income Tax Expense | 505.1 | 441.4 | 63.7 | 14.4 | |||||||||
| Income Tax Expense | 202.0 | 172.9 | 29.1 | 16.8 | |||||||||
| Net Income | $ | 303.1 | $ | 268.5 | $ | 34.6 | 12.9 | % | |||||
| (a) Percent greater than 100 percent not shown as it is not meaningful. | |||||||||||||
| Operating Revenues | |||||||||||||
| NSTAR Electric's retail sales volumes were as follows: | |||||||||||||
| For the Years Ended December 31, | |||||||||||||
| 2014 | 2013 | Decrease | Percent | ||||||||||
| Retail Sales Volumes in GWh | 20,925 | 21,306 | (381) | (1.8) | % |
NSTAR Electric's Operating Revenues increased $43.2 million in 2014 compared to 2013. The increase primarily reflects recovery of higher costs associated with the procurement of energy supply, which increased $195.5 million. The energy supply costs were impacted by the overall wholesale electricity market in New England in which higher natural gas delivery costs had an adverse impact on the cost of electric energy purchased for our retail customers. Energy supply costs are recovered from customers in rates through cost tracking mechanisms and therefore have no impact on earnings. These costs and related recovery impacts were partially offset by decreases in transition cost recovery revenues, which are recovered through cost tracking mechanisms, reflecting the full collection in 2013 of previously deferred costs, as well as the full amortization of RRBs.
Base distribution revenues decreased in 2014, as compared to 2013, due primarily to cooler summer weather and an increase in customer conservation efforts due to the impact of energy efficiency programs. NSTAR Electric recovers LBR related to reductions in sales volume as a result of energy efficiency. In 2014, including the impact from the recognition of LBR, base distribution revenues increased in 2014, compared to 2013, by $3.7 million.
Transmission revenues increased $21.7 million in 2014, as compared to 2013, due primarily to the recovery of higher revenue requirements associated with ongoing investments in our transmission infrastructure. This increase was partially offset by the impact of the $7.9 million net reserve recorded in 2014 as a result of the 2014 FERC ROE orders, compared to the $5.7 million reserve recorded in 2013 for the FERC ALJ initial decision in the FERC base ROE complaints.
Purchased Power and Transmission expense includes costs associated with purchasing electricity on behalf of NSTAR Electric's customers. These energy supply costs are recovered from customers in DPU-approved cost tracking mechanisms, which have no impact on earnings (tracked costs). Purchased Power and Transmission increased in 2014, as compared to 2013, due primarily to the following:
| (Millions of Dollars) | Increase | |
| Purchased Power Costs | $ | 202.9 |
| Transmission Costs | 64.6 | |
| Other | 5.7 | |
| Total Purchased Power and Transmission | $ | 273.2 |
Included in purchased power are the costs associated with NSTAR Electric's basic service charge and deferred energy supply costs. The basic service charge recovers energy-related costs incurred as a result of providing electric generation service supply to all customers that have not migrated to third party suppliers. The increase in purchased power was due primarily to higher average energy supply prices. The increase in transmission costs was due primarily to higher regional transmission expense.
Operations and Maintenance expense includes tracked costs and costs that are part of base distribution rates with changes impacting earnings (non-tracked costs). Operations and Maintenance decreased in 2014, as compared to 2013, driven by a $57.4 million reduction in non-tracked costs, which was primarily attributable to lower labor and other employee-related costs and lower storm restoration costs. Partially offsetting this decrease was an $8 million increase in tracked costs, which have no earnings impact, that was primarily attributable to an increased level of recovery of deferred storm costs and increased transmission maintenance expenses.
Depreciation increased in 2014, as compared to 2013, due primarily to higher utility plant balances resulting from completed construction projects placed into service.
Amortization of Regulatory Assets/(Liabilities), Net, decreased due primarily to the absence in 2014 of the recovery of tracked transition costs, reflecting the full collection in 2013 of these previously deferred costs. Fluctuations in these costs are recovered from customers in rates through cost tracking mechanisms and have no impact on earnings.
Amortization of Rate Reduction Bonds decreased in 2014, as compared to 2013, due to the maturity of the RRBs in March 2013.
Energy Efficiency Programs, which are tracked costs, decreased in 2014, as compared to 2013, due primarily to a decrease in the amortization of previously deferred costs. This was partially offset by an increase in energy efficiency costs incurred in accordance with the three-year program guidelines established by the DPU.
Taxes Other Than Income Taxes increased in 2014, as compared to 2013, due primarily to an increase in property taxes as a result of both an increase in utility plant balances and property tax rates.
Interest Expense increased in 2014, as compared to 2013, due primarily to lower interest income from a decrease in the recovery of previously deferred tracked transition costs ($9.9 million), partially offset by a decrease in interest on long-term debt ($2 million).
Income Tax Expense increased in 2014, as compared to 2013, due primarily to higher pre-tax earnings ($22.4 million), and higher state taxes ($6.7 million).
EARNINGS SUMMARY
NSTAR Electric's earnings increased in 2014, as compared to 2013, due primarily to lower operations and maintenance costs primarily attributable to lower employee-related costs and higher transmission earnings, partially offset by higher interest expense, higher depreciation expense, higher property tax expense and the after-tax reserve recorded for the 2014 FERC ROE orders as compared to the reserve recorded in 2013 for the FERC ALJ initial decision in the FERC base ROE complaints.
LIQUIDITY
NSTAR Electric had cash flows provided by operating activities of $533 million in 2014, compared with $510.4 million in 2013. The improved operating cash flows were due primarily to the absence of cash disbursements for major storm restoration costs associated with the February 2013 blizzard, collections of accounts receivable from affiliated companies, and $30.2 million in DOE damages proceeds in 2014 from the Yankee Companies associated with the spent nuclear fuel litigation. These favorable cash flow impacts were partially offset by a $38.3 million increase in Pension and PBOP Plan cash contributions in 2014 compared to 2013, the unfavorable cash flow impact resulting from the absence in 2014 of the recovery of previously deferred tracked transition costs that were fully collected in 2013, the absence of costs recovered in rates related to the RRBs that were fully amortized in 2013, and an increase in income taxes paid.
NSTAR Electric has a five-year $450 million revolving credit facility. This facility serves to backstop NSTAR Electric's existing $450 million commercial paper program. Effective July 23, 2014, NSTAR Electric extended the expiration date of its revolving credit facility for one additional year to September 6, 2019. As of December 31, 2014 and 2013, NSTAR Electric had $302 million and $103.5 million, respectively, in short-term borrowings outstanding under its commercial paper program, leaving $148 million and $346.5 million of available borrowing capacity as of December 31, 2014 and 2013, respectively. The weighted-average interest rate on these borrowings as of December 31, 2014 and 2013 was 0.27 percent and 0.13 percent, respectively, which is generally based on A2/P1 rated commercial paper.
RESULTS OF OPERATIONS – PUBLIC SERVICE COMPANY OF NEW HAMPSHIRE AND SUBSIDIARY
The following provides the amounts and variances in operating revenues and expense line items in the statements of income for PSNH for the years ended December 31, 2014 and 2013 included in this Annual Report on Form 10-K:
| For the Years Ended December 31, | |||||||||||||
| Increase/ | |||||||||||||
| (Millions of Dollars) | 2014 | 2013 | (Decrease) | Percent | |||||||||
| Operating Revenues | $ | 959.5 | $ | 935.4 | $ | 24.1 | 2.6 | % | |||||
| Operating Expenses: | |||||||||||||
| Purchased Power, Fuel and Transmission | 313.7 | 269.8 | 43.9 | 16.3 | |||||||||
| Operations and Maintenance | 261.9 | 267.8 | (5.9) | (2.2) | |||||||||
| Depreciation | 98.4 | 91.6 | 6.8 | 7.4 | |||||||||
| Amortization of Regulatory Liabilities, Net | (29.6) | (20.4) | (9.2) | 45.1 | |||||||||
| Amortization of Rate Reduction Bonds | - | 19.7 | (19.7) | (100.0) | |||||||||
| Energy Efficiency Programs | 14.3 | 14.5 | (0.2) | (1.4) | |||||||||
| Taxes Other Than Income Taxes | 71.4 | 67.2 | 4.2 | 6.3 | |||||||||
| Total Operating Expenses | 730.1 | 710.2 | 19.9 | 2.8 | |||||||||
| Operating Income | 229.4 | 225.2 | 4.2 | 1.9 | |||||||||
| Interest Expense | 45.4 | 46.2 | (0.8) | (1.7) | |||||||||
| Other Income, Net | 2.0 | 3.5 | (1.5) | (42.9) | |||||||||
| Income Before Income Tax Expense | 186.0 | 182.5 | 3.5 | 1.9 | |||||||||
| Income Tax Expense | 72.1 | 71.1 | 1.0 | 1.4 | |||||||||
| Net Income | $ | 113.9 | $ | 111.4 | $ | 2.5 | 2.2 | % | |||||
| Operating Revenues | |||||||||||||
| PSNH's retail sales volumes were as follows: | |||||||||||||
| For the Years Ended December 31, | |||||||||||||
| 2014 | 2013 | Decrease | Percent | ||||||||||
| Retail Sales Volumes in GWh | 7,886 | 7,938 | (52) | (0.7) | % |
PSNH's Operating Revenues increased $24.1 million in 2014 compared to 2013. The increase primarily reflects the recovery of higher costs associated with the procurement of energy supply and the generation of electricity for our customers, which increased $19.8 million. The energy supply costs were impacted by higher natural gas delivery costs, which had an adverse impact on the cost of electric energy purchased for our retail customers. Also reflected in the revenue increase were increases of $6.3 million related to NHPUC-approved distribution rate increases effective July 1, 2013 and increases in transmission revenues as a result of the recovery of higher transmission expenses including ongoing investments in our transmission infrastructure. These increases were partially offset by a decrease in stranded cost recovery revenues, which are recovered through cost tracking mechanisms, due to the refund to customers of DOE damages proceeds received from the Yankee Companies resulting from the spent nuclear fuel litigation.
Purchased Power, Fuel and Transmission expense includes costs associated with PSNH's generation of electricity as well as purchasing electricity on behalf of its customers. These energy supply costs are recovered from customers in NHPUC-approved cost tracking mechanisms, which have no impact on earnings (tracked costs). Purchased Power, Fuel and Transmission increased in 2014, as compared to 2013, due primarily to the following:
| (Millions of Dollars) | Increase/(Decrease) | |
| Generation Fuel Costs | $ | 41.6 |
| Transmission Costs | 13.2 | |
| Purchased Power Costs | (9.4) | |
| Other | (1.5) | |
| Total Purchased Power, Fuel and Transmission | $ | 43.9 |
The increase in generation fuel costs was due primarily to an increase in the amount of electricity generated by PSNH facilities in 2014, as compared to 2013. Included in purchased power are the costs associated with the PSNH energy service charge. The decrease in purchased power costs was a result of purchasing less power from third party suppliers due to increased PSNH generation. The increase in transmission costs was the result of an increase in the retail transmission cost deferral, which reflects the actual costs of transmission service compared to estimated amounts billed to customers**.**
Operations and Maintenance expense includes tracked costs and costs that are part of base distribution rates with changes impacting earnings (non-tracked costs). Operations and Maintenance decreased in 2014, as compared to 2013, driven by an $8.3 million reduction in non-tracked costs, which was primarily attributable to lower labor and other employee-related costs, including pension costs, and lower storm restoration costs. Partially offsetting this decrease was a $2.4 million increase in tracked costs, which have no earnings impact, that was primarily attributable to increased maintenance activities at PSNH's generating facilities.
Depreciation increased in 2014, as compared to 2013, due primarily to higher utility plant balances resulting from completed construction projects placed into service.
Amortization of Regulatory Liabilities, Net, reflects a decrease in the recovery of the default energy service charge and other amortizations in 2014, as compared to 2013. Fluctuations in these costs are recovered from customers in rates through cost tracking mechanisms and have no impact on earnings.
Amortization of Rate Reduction Bonds decreased in 2014, as compared to 2013, due to the maturity of the RRBs in May 2013.
Taxes Other Than Income Taxes increased in 2014, as compared to 2013, due primarily to an increase in property taxes as a result of both an increase in utility plant balances and property tax rates.
Other Income, Net decreased in 2014, as compared to 2013, due primarily to lower unrealized gains on the assets supporting the deferred compensation plans ($1.8 million).
Income Tax Expense increased in 2014, as compared to 2013, due primarily to higher pre-tax earnings.
EARNINGS SUMMARY
PSNH's earnings increased in 2014, as compared to 2013, due primarily to higher transmission earnings, a decrease in operations and maintenance costs primarily attributable to lower employee-related costs, and higher distribution retail revenues, which were favorably impacted by the PSNH annualized distribution rate increases effective July 1, 2013. Partially offsetting this favorable earnings impact was higher depreciation expense.
LIQUIDITY
PSNH had cash flows provided by operating activities of $248 million in 2014, compared with $188.1 million in 2013. The improved operating cash flows were due primarily to the absence of $108.3 million in Pension Plan cash contributions made in 2013, $14.5 million in DOE damages proceeds received in 2014 from the Yankee Companies associated with the spent nuclear fuel litigation, and the favorable impact of the NHPUC-approved distribution rate increases that were effective July 1, 2013. These favorable cash flow impacts were partially offset by higher income tax payments in 2014, as compared to 2013, and the absence of costs recovered in rates related to the RRBs that were fully amortized in 2013.
RESULTS OF OPERATIONS – WESTERN MASSACHUSETTS ELECTRIC COMPANY
The following provides the amounts and variances in operating revenues and expense line items in the statements of income for WMECO for the years ended December 31, 2014 and 2013 included in this Annual Report on Form 10-K:
| For the Years Ended December 31, | |||||||||||||
| Increase/ | |||||||||||||
| (Millions of Dollars) | 2014 | 2013 | (Decrease) | Percent | |||||||||
| Operating Revenues | $ | 493.4 | $ | 472.7 | $ | 20.7 | 4.4 | % | |||||
| Operating Expenses: | |||||||||||||
| Purchased Power and Transmission | 172.9 | 147.1 | 25.8 | 17.5 | |||||||||
| Operations and Maintenance | 89.4 | 96.2 | (6.8) | (7.1) | |||||||||
| Depreciation | 41.9 | 37.6 | 4.3 | 11.4 | |||||||||
| Amortization of Regulatory Assets/(Liabilities), Net | (6.2) | (3.2) | (3.0) | 93.8 | |||||||||
| Amortization of Rate Reduction Bonds | - | 7.8 | (7.8) | (100.0) | |||||||||
| Energy Efficiency Programs | 42.9 | 39.5 | 3.4 | 8.6 | |||||||||
| Taxes Other Than Income Taxes | 34.9 | 28.4 | 6.5 | 22.9 | |||||||||
| Total Operating Expenses | 375.8 | 353.4 | 22.4 | 6.3 | |||||||||
| Operating Income | 117.6 | 119.3 | (1.7) | (1.4) | |||||||||
| Interest Expense | 24.9 | 24.8 | 0.1 | 0.4 | |||||||||
| Other Income, Net | 2.4 | 3.3 | (0.9) | (27.3) | |||||||||
| Income Before Income Tax Expense | 95.1 | 97.8 | (2.7) | (2.8) | |||||||||
| Income Tax Expense | 37.3 | 37.4 | (0.1) | (0.3) | |||||||||
| Net Income | $ | 57.8 | $ | 60.4 | $ | (2.6) | (4.3) | % | |||||
| Operating Revenues | |||||||||||||
| WMECO's retail sales volumes were as follows: | |||||||||||||
| For the Years Ended December 31, | |||||||||||||
| 2014 | 2013 | Decrease | Percent | ||||||||||
| Retail Sales Volumes in GWh | 3,586 | 3,683 | (97) | (2.6) | % |
WMECO's Operating Revenues increased $20.7 million in 2014 compared to 2013. The increase primarily reflects recovery of higher costs associated with the procurement of energy supply, which increased $15.2 million. The energy supply costs were impacted by the overall wholesale electricity market in New England in which higher natural gas delivery costs had an adverse impact on the cost of electric energy purchased for our retail customers. Energy supply costs are recovered from customers in rates through cost tracking mechanisms and therefore have no impact on earnings.
Transition cost recovery revenues, which are recovered through cost tracking mechanisms, decreased due to the refund to customers of DOE damages proceeds received from the Yankee Companies resulting from the spent nuclear fuel litigation.
Fluctuations in WMECO's kWh sales have no impact on earnings, as its revenues are decoupled from sales volumes and changes in revenues are primarily related to changes in its cost tracking mechanisms.
Transmission revenues increased in 2014 compared to 2013 due primarily to the recovery of higher revenue requirements associated with ongoing investments in our transmission infrastructure. There was also a $3.9 million increase in revenues that impacts earnings due to the reversal in 2014 of a previously established wholesale billing adjustment. Partially offsetting the increase was the impact of the $5.6 million net reserve recorded in 2014 as a result of the 2014 FERC ROE orders, as compared to the $2.9 million reserve recorded in 2013 for the FERC ALJ initial decision in the FERC base ROE complaints.
Purchased Power and Transmission expense includes costs associated with purchasing electricity on behalf of WMECO's customers. These energy supply costs are recovered from customers in DPU-approved cost tracking mechanisms, which have no impact on earnings (tracked costs). Purchased Power and Transmission increased in 2014, as compared to 2013, due primarily to the following:
| (Millions of Dollars) | Increase/(Decrease) | |
| Purchased Power Costs | $ | 16.6 |
| Transmission Costs | 11.6 | |
| Other | (2.4) | |
| Total Purchased Power and Transmission | $ | 25.8 |
Included in purchased power are the costs associated with WMECO's basic service charge and deferred energy supply costs. The basic service charge recovers energy-related costs incurred as a result of providing electric generation service supply to all customers that have not migrated to third party suppliers. The increase in purchased power was due primarily to higher average supply prices and increased load as a result of customers returning to basic service from third party suppliers. The increase in transmission costs was as a result of an increase in the retail transmission cost deferral, which reflects the actual costs of transmission service compared to estimated amounts billed to customers.
Operations and Maintenance expense includes tracked costs and costs that are part of base distribution rates with changes impacting earnings (non-tracked costs). Operations and Maintenance decreased in 2014, as compared to 2013, driven by a $4.8 million reduction in non-tracked costs, which was primarily attributable to lower labor and other employee-related costs, and a $2 million reduction in tracked costs, which have no earnings impact, that was primarily attributable to lower labor and other employee-related costs, including pension costs.
Depreciation increased in 2014, as compared to 2013, due primarily to higher utility plant balances resulting from completed construction projects placed into service.
Amortization of Regulatory Assets/(Liabilities), Net¸ reflects a decrease in the recovery of transition costs primarily due to the refund of the DOE damages proceeds to customers in 2014, as compared to 2013. Fluctuations in these costs are recovered from or refunded to customers in rates through cost tracking mechanisms and have no impact on earnings.
Amortization of Rate Reduction Bonds decreased in 2014, as compared to 2013, due to the maturity of the RRBs in June 2013.
Energy Efficiency Programs, which are tracked costs, increased in 2014, as compared to 2013, due primarily to an increase in energy efficiency costs in accordance with the three-year program guidelines established by the DPU.
Taxes Other Than Income Taxes increased in 2014, as compared to 2013, due primarily to an increase in property taxes as a result of both an increase in utility plant balances and property tax rates.
Other Income, Net decreased in 2014, as compared to 2013, due primarily to lower unrealized gains on the assets supporting the deferred compensation plans ($1.4 million).
Income Tax Expense decreased in 2014, as compared to 2013, due primarily to lower pre-tax earnings.
EARNINGS SUMMARY
WMECO's earnings decreased in 2014, as compared to 2013, due primarily to the after-tax reserve recorded for the 2014 FERC ROE orders as compared to the reserve recorded in 2013 for the FERC ALJ initial decision in the FERC base ROE complaints, higher depreciation expense and higher property tax expense. Partially offsetting these unfavorable earnings impacts were a decrease in operations and maintenance expense primarily attributable to lower employee-related costs, and the reversal of a previously established wholesale billing adjustment.
LIQUIDITY
WMECO had cash flows provided by operating activities of $153.3 million in 2014, compared with $178.8 million in 2013. The decrease in operating cash flows was due primarily to higher income tax payments in 2014, as compared to 2013, and the absence of costs recovered in rates related to the RRBs that were fully amortized in 2013, partially offset by the favorable impact of changes in working capital and $18.9 million in DOE damages proceeds received in 2014 from the Yankee Companies associated with the spent nuclear fuel litigation.
Previous: Item 6. Selected Consolidated Financial Data · Next: Item 7A. Quantitative and Qualitative Disclosures about Market Risk