From time to time we make statements concerning our expectations, beliefs, plans, objectives, goals, strategies, assumptions of future events, future financial performance or growth and other statements that are not historical facts. These statements are "forward-looking statements" within the meaning of the Private Securities Litigation Reform Act of 1995. You can generally identify our forward-looking statements through the use of words or phrases such as "estimate," "expect," "anticipate," "intend," "plan," "project," "believe," "forecast," "should," "could," and other similar expressions. Forward-looking statements are based on the current expectations, estimates, assumptions or projections of management and are not guarantees of future performance. These expectations, estimates, assumptions or projections may vary materially from actual results. Accordingly, any such statements are qualified in their entirety by reference to, and are accompanied by, the following important factors that could cause our actual results to differ materially from those contained in our forward-looking statements, including, but not limited to:
disruptions in the capital markets or other events that make our access to necessary capital more difficult or costly,
other presently unknown or unforeseen factors.
Other risk factors are detailed in our reports filed with the SEC and updated as necessary, and we encourage you to consult such disclosures.
All such factors are difficult to predict, contain uncertainties that may materially affect our actual results and are beyond our control. You should not place undue reliance on the forward-looking statements, each speaks only as of the date on which such statement is made, and we undertake no obligation to update any forward-looking statement or statements to reflect events or circumstances after the date on which such statement is made or to reflect the occurrence of unanticipated events. New factors emerge from time to time and it is not possible for us to predict all of such factors, nor can we assess the impact of each such factor on the business or the extent to which any factor, or combination of factors, may cause actual results to differ materially from those contained in any forward-looking statements. For more information, see Item 1A, Risk Factors, included in this combined Annual Report on Form 10-K. This Annual Report on Form 10-K also describes material contingencies and critical accounting policies in the accompanyingManagement’sManagement's Discussion and Analysis of Financial Condition and Results of OperationsandCombined Notes to Consolidated Financial Statements. We encourage you to review these items.
Item 1.
Please refer to the Glossary of Terms for definitions of defined terms and abbreviations used in this combined Annual Report on Form 10-K.
The Connecticut Light and Power Company (CL&P), a regulated electric utility that serves residential, commercial and industrial customers in parts of Connecticut;
NSTAR Electric Company (NSTAR Electric), a regulated electric utility that serves residential, commercial and industrial customers in parts of eastern Massachusetts;
Public Service Company of New Hampshire (PSNH), a regulated electric utility that serves residential, commercial and industrial customers in parts of New Hampshire and owns generation assets used to serve customers;
Western Massachusetts Electric Company (WMECO), a regulated electric utility that serves residential, commercial and industrial customers in parts of western Massachusetts and owns solar generating assets;
NSTAR Gas Company (NSTAR Gas), a regulated natural gas utility that serves residential, commercial and industrial customers in parts of Massachusetts; and
Yankee Gas Services Company (Yankee Gas), a regulated natural gas utility that serves residential, commercial and industrial customers in parts of Connecticut.
Under Connecticut law, all of CL&P's customers are entitled to choose their energy suppliers, while CL&P remains their electric distribution company. For those customers who do not choose a competitive energy supplier, under SS rates for customers with less than 500 kilowatts of demand, and LRS rates for customers with 500 kilowatts or more of demand, CL&P purchases power under standard offer contracts and passes the cost of the power to customers through a combined GSC and FMCC charge on customers’customers' bills.
A distribution charge, which includes a fixed customer charge and a demand and/or energy charge to collect the costs of building and expanding the infrastructure to deliver power to its destination,customers, as well as ongoing operating costs to maintain suchthe infrastructure.
A transmission charge that recovers the cost of transporting electricity over high voltage lines from generating plants to substations, including costs allocated by ISO-NE to maintain the wholesale electric market.
A conservation charge, comprised of a statutory rate established to implement cost-effective energy conservation programs and market transformation initiatives, plus a conservation adjustment mechanism charge to recover the residual energy efficiency spending associated with the expanded energy efficiency costs directed by the Comprehensive Energy Strategy Plan for Connecticut.
Each of CL&P, NSTAR Electric, PSNH and WMECO owns and maintains transmission facilities that are part of an interstate power transmission grid over which electricity is transmitted throughout New England. Each of CL&P, NSTAR Electric, PSNH and WMECO, and most other New England utilities, are parties to a series of agreements that provide for coordinated planning and operation of the region's transmission facilities and the rules by which they acquire transmission services. Under these arrangements, ISO-NE, a non-profit corporation whose board of directors and staff are independent of all market participants, serves as the regional transmission organization of the New England transmission system.
Wholesale transmission revenues are recovered through FERC approved formula rates. Transmission revenues are collected from New England customers, the majority of which are distribution customers of CL&P, NSTAR Electric, PSNH and WMECO. The
A distribution charge consisting of a fixed customer charge and a demand and/or energy charge that collects the costs of building and expanding the natural gas infrastructure to deliver natural gas supply to its customers. This also includes collection of ongoing operating costs;
NSTAR Gas purchases financial contracts based on NYMEX natural gas futures in order to reduce cash flow variability associated with the purchase price for approximately one-third of its natural gas purchases. These purchases are made under a program approved by the Massachusetts Department of Public UtilitiesDPU in 2006. This practice attempts to minimize the impact of fluctuations in natural gas prices to NSTAR Gas’Gas' firm natural gas customers. These financial contracts do not procure natural gas supply. All costs incurred or benefits realized when these contracts are settled are included in the CGAC.
NSTAR Gas maintains a flexible resource portfolio consisting of natural gas supply contracts, transportation contracts on interstate pipelines, market area storage and peaking services. NSTAR Gas purchases transportation, storage, and balancing services from Tennessee Gas Pipeline Company and Algonquin Gas Transmission Company, as well as other upstream pipelines that transport gas from major producing regions in the U.S., including the Gulf Coast, Mid-continent region, and Appalachian Shale supplies to the final delivery points in the NSTAR Gas service area. NSTAR Gas purchases all of its natural gas supply fromunder a firm portfolio management contract with a term of one year, which has a maximum quantity of approximately 139,500154,700 MMBtu/day.day of firm flowing natural gas supplies and 76,700 MMBtu/day of firm natural gas storage supplies.
In addition to the firm transportation and natural gas supplies mentioned above, NSTAR Gas utilizes contracts for underground storage and LNG facilities to meet its winter peaking demands. The LNG facilities, described below, are located within NSTAR Gas’Gas' distribution system and are used to liquefy and store pipeline natural gas during the warmer months for vaporization and use during the heating season. During the summer injection season, excess pipeline capacity and supplies are used to deliver and store natural gas in market area underground storage facilities located in the New York and Pennsylvania region.regions. Stored natural gas is withdrawn during the winter season to supplement flowing pipeline supplies in order to meet firm heating demand. NSTAR Gas has firm underground storage contracts and total storage capacity entitlements of approximately 6.6 Bcf.
A portion of the storage of natural gas supply for NSTAR Gas during the winter heating season is provided by Hopkinton a wholly-owned subsidiary of Yankee Energy Systems, Inc. The facilities consist ofLNG Corp., which owns an LNG liquefaction and vaporization plant and three above-ground cryogenic storage tanks in Hopkinton, Massachusetts having an aggregate capacity of 3.0 Bcf of liquefied natural gas. NSTAR Gas also has access to Hopkinton LNG Corp. facilities in Acushnet, Massachusetts that include additional storage capacity of 0.5 Bcf and additional vaporization capacity.
PURA requires that Yankee Gas meet the needs of its firm customers under all weather conditions. Specifically, Yankee Gas must structure its supply portfolio to meet firm customer needs under a design day scenario (defined as the coldest day in 30 years) and under a design year scenario (defined as the average of the four coldest years in the last 30 years). Yankee Gas also owns a 1.2 Bcf LNG facility in Waterbury, Connecticut, which is used primarily to assist Yankee Gas in meeting its supplier-of-last-resort obligations and also enables Yankee Gas to make economic purchases of natural gas, typically in periods of low demand. Yankee Gas’Gas' on-system stored LNG and underground storage supplies help to meet consumption needs during the coldest days of winter. Yankee Gas obtains its interstate capacity from the three interstate pipelines that directly serve Connecticut: the Algonquin, Tennessee and Iroquois Pipelines. Yankee Gas has long-term firm contracts for capacity on TransCanada Pipelines Limited Pipeline, Vector Pipeline, L.P., Tennessee Gas Pipeline, Iroquois Gas Transmission Pipeline, Algonquin Pipeline, Union Gas Limited, Dominion Transmission, Inc., National Fuel Gas Supply Corporation, Transcontinental Gas Pipeline Company, and Texas Eastern Transmission, L.P. pipelines.
Based on information currently available regarding projected growth in demand and estimates of availability of future supplies of pipeline natural gas, NSTAR Gas and Yankee Gas each believes that its present sources ofparticipation in planned and anticipated pipeline and storage expansion projects will be required in order for it to meet current and future sales growth opportunities.
CL&P, NSTAR Electric, PSNH, WMECO and several other New England electric utilities are stockholders in three inactive regional nuclear generation companies, CYAPC, MYAPC and YAEC (collectively, the Yankee Companies). The Yankee Companies have completed the physical decommissioning of their respective generation facilities and are now engaged in the long-term storage of their spent nuclear fuel. EachThe Yankee Company collectsCompanies have completed collection of their decommissioning and closure costs through the proceeds from the spent nuclear fuel litigation against the DOE and has refunded amounts to its member companies. These proceeds were used by the Yankee Companies to offset the decommissioning and closure cost amounts due from their member companies or to decrease the wholesale FERC-approved rates charged under power purchase agreements with CL&P, NSTAR Electric, PSNH and WMECO and several other New England utilities. These companies in turnThe decommissioning rates charged by the Yankee Companies have been reduced to zero. CL&P, NSTAR Electric, PSNH and WMECO can recover these costs from, or refund proceeds to, their customers through state regulatory commission-approved retail rates.
We are regulated in virtually all aspects of our business by various federal and state agencies, including FERC, the SEC, and various state and/or local regulatory authorities with jurisdiction over the industry and the service areas in which each of our companies operates, including the PURA, which has jurisdiction over CL&P and Yankee Gas, the NHPUC, which has jurisdiction over PSNH, and the DPU, which has jurisdiction over NSTAR Electric, NSTAR Gas and WMECO.
We are subject to various federal, state and local requirements with respect to water quality, air quality, toxic substances, hazardous waste and other environmental matters. Additionally, major generation and transmission facilities may not be constructed or significantly modified without a review of the environmental impact of the proposed construction or modification by the applicable federal or state agencies.
The Clean Water Act requires every "point source" discharger of pollutants into navigable waters to obtain a National Pollutant Discharge Elimination System (NPDES) permit from the EPA or state environmental agency specifying the allowable quantity and characteristics of its effluent. States may also require additional permits for discharges into state waters. We are in the process of maintaining or renewing all required NPDES or state discharge permits in effect for ourPSNH's generation facilities.
The Clean Air Act Amendments (CAAA), as well as New Hampshire law, impose stringent requirements on emissions of SO2 and NOX for the purpose of controlling acid rain and ground level ozone. In addition, the CAAA address the control of toxic air pollutants. Requirements for the installation of continuous emissions monitors and expanded permitting provisions also are included.
Each of the states in which we do business also has Renewable Portfolio Standards (RPS) requirements, which generally require fixed percentages of our energy supply to come from renewable energy sources such as solar, hydropower, landfill gas, fuel cells and other similar sources.
Similarly, Connecticut's RPS statute requires increasing percentages of the electricity sold to retail customers to have direct ties to renewable sources. In 2013,2015, the total RPS obligation was 17 percent and19.5 percentand will ultimately reach 27 percent in 2020. CL&P is permitted to recover any costs incurred in complying with RPS from its customers through rates.its GSCrate.
The most significant liabilities currently relate to future clean-up costs at former MGP facilities. These facilities were owned and operated by our predecessor companies from the mid-1800's to mid-1900's. By-products from the manufacture of gas using coal resulted in fuel oils, hydrocarbons, coal tar, purifier wastes, metals and other waste products that may pose risks to human health and the environment. We through our subsidiaries, currently have partial or full ownership responsibilities at former MGP sites that have a reserve balance of $31.4$45.5 million of the total $35.4$51.1 million as of December 31, 2013. Predominantly all2015. Many of these MGP costs are recoverable from customers through our rates.
For more than twenty years, published reports have discussed the possibility of adverse health effects from electric and magnetic fields (EMF) associated with electric transmission and distribution facilities and appliances and wiring in buildings and homes. Although weak health risk associations reported in some epidemiology studies remain unexplained, most researchers, as well as numerous scientific review panels, considering all significant EMF epidemiology and laboratory studies, have concluded that the available body of scientific information does not support the conclusion that EMF affects human health.
In accordance with recommendations of various regulatory bodies and public health organizations, we reduce EMF associated with new transmission lines by the use of designs that can be implemented without additional cost or at a modest cost. We do not believe that other capital expenditures are appropriate to minimize unsubstantiated risks.
Global climate change and greenhouse gas emission issues have received an increased focus from state governments and the federal government. The EPA initiated a rulemaking addressing greenhouse gas emissions and, on December 7, 2009, issued a finding that concluded that greenhouse gas emissions are "air pollution" that endangerendangers public health and welfare and should be regulated. The largest source of greenhouse gas emissions in the U.S. is the electricity generating sector. The EPA has mandated greenhouse gas emission reporting beginning in 2011 for emissions for certain aspects of our business including stationary combustion, volume of gas supplied to large customers and fugitive emissions of SF6 gas and methane.
We are continually evaluating the regulatory risks and regulatory uncertainty presented by climate change concerns. Such concerns could potentially lead to additional rules and regulations that impact how we operate our business, both in terms of the generating facilities we own and operate as well as general utility operations. These could include federal "cap and trade" laws, carbon taxes, fuel and energy taxes, or regulations requiring additional capital expenditures at our generating facilities. We expect that any costs of these rules and regulations would be recovered from customers.
Connecticut, New Hampshire and Massachusetts are each members of the Regional Greenhouse Gas Initiative (RGGI), a cooperative effort by nine northeastern and mid-Atlantic states, to develop a regional program for stabilizing and reducing CO2 emissions from fossil fueledcoal- and oil-fired electric generating plants. Because CO2 allowances issued by any participating state are usable across all nine RGGI state programs, the individual state CO2 trading programs, in the aggregate, form one regional compliance market for CO2 emissions. AThe third three-year control period took effect on January 1, 2015 and extends through December 31, 2017. In this control period, each regulated power plant must hold CO2 allowances equal to 50 percent of its emissions during each of the first two years of the three-year period, and hold CO2 allowances equal to demonstrate compliance100 percent of its remaining emissions for the three-year control period at the end of a three year compliance period that began in 2012.the period.
PSNH customers. Current legislation provides athat the portion of the RGGI auction proceeds in excess of $1 per allowance will be refunded to customers.
Federal Power Act licenses may be issued for hydroelectric projects for terms of 30 to 50 years as determined by the FERC. Upon the expiration of an existing license, (i) the FERC may issue a new license to the existing licensee, (ii) the United States may take over the project, or (iii) the FERC may issue a new license to a new licensee, upon payment to the existing licensee of the lesser of the fair value or the net investment in the project, plus severance damages, less certain amounts earned by the licensee in excess of a reasonable rate of return.
Item 1A.
In addition to the matters set forth under "Safe Harbor Statement Under the Private Securities Litigation Reform Act of 1995" included immediately prior to Item 1,Business, above, we are subject to a variety of significant risks. Our susceptibility to certain risks, including those discussed in detail below, could exacerbate other risks. These risk factors should be considered carefully in evaluating our risk profile.
Cyber breaches, acts of war or terrorism, or grid disturbances could negatively impact our business.
Because our generation and transmission facilities are part of an interconnected regional grid, we face the risk of blackout due to a disruption on a neighboring interconnected system.
Severe weather, such as ice and snow storms, hurricanes and other natural disasters, may cause outages and property damage, which may require us to incur additional costs that may not be recoverable from customers. The cost of repairing damage to our operating subsidiaries' facilities and the potential disruption of their operations due to storms, natural disasters or other catastrophic events could be substantial, particularly as regulators and customers demand better and quicker response times to outages. If, upon review, any of our state regulatory authorities finds that our actions were imprudent, some of those restoration costs may not be recoverable from customers. The inability to recover a significant amount of such costs could have an adverse effect on our financial position, results of operations and cash flows.
Because utility companies, including our electric and natural gas utility subsidiaries, have large consumer customer bases, they are subject to adverse publicity focused on the reliability of their distribution services and the speed with which they are able to respond to electric outages, natural gas leaks and similar interruptions caused by storm damage or other unanticipated events. Adverse publicity of this nature could harm the reputations of NUEversource Energy and its subsidiaries, andsubsidiaries; may make state legislatures, utility commissions and other regulatory authorities less likely to view NUEversource Energy and its subsidiaries in a favorable light,light; and may cause NUEversource Energy and its subsidiaries to be subject to less favorable legislative and regulatory outcomes or increased regulatory oversight. Unfavorable regulatory outcomes can include more stringent laws and regulations governing our operations, such as reliability and customer service quality standards or vegetation management requirements, as well as fines, penalties or other sanctions or requirements. The imposition of any of the foregoing could have a material adverse effect on the business, results of operations, cash flow and financial condition of NUEversource Energy and each of its utility subsidiaries.
Limits on our access to and increases in the cost of capital may adversely impact our ability to execute our business plan.
We use short-term debt and the long-term capital markets as a significant source of liquidity and funding for capital requirements not obtained from our operating cash flow. If access to these sources of liquidity becomes constrained, our ability to implement our business strategy could be adversely affected. In addition, higher interest rates would increase our cost of borrowing, which could adversely impact our results of operations. A downgrade of our credit ratings or events beyond our control, such as a disruption in global capital and credit markets, could increase our cost of borrowing and cost of capital or restrict our ability to access the capital markets and negatively affect our ability to maintain and to expand our businesses.
Our counterparties may not meet their obligations to us or may elect to exercise their termination rights, which could adversely affect our earnings.
We are exposed to the risk that counterparties to various arrangements who owe us money, have contracted to supply us with energy, coal, or other commodities or services, or who work with us as strategic partners, including on significant capital projects, will not be able to perform their obligations, will terminate such arrangements or, with respect to our credit facilities, fail to honor their commitments. Should any of these counterparties fail to perform their obligations or terminate such arrangements, we might be forced to replace the underlying commitment at higher market prices and/or have to delay the completion of, or cancel a capital project. Should any lenders under our credit facilities fail to perform, the level of borrowing capacity under those arrangements could decrease. In any such events, our financial position, results of operations, or cash flows could be adversely affected.
The loss of key personnel or the inability to hire and retain qualified employees could have an adverse effect on our business, financial position and results of operations.
Our operations depend on the continued efforts of our employees. Retaining key employees and maintaining the ability to attract new employees are important to both our operational and financial performance. We cannot guarantee that any member of our management or any key employee at the NUEversource parent or subsidiary level will continue to serve in any capacity for any particular period of time. In addition, a significant portion of our workforce, including many workers with specialized skills maintaining and servicing the electrical infrastructure, will be eligible to retire over the next five to ten years. Such highly skilled individuals cannot be quickly replaced due to the technically complex work they perform. We have developed strategic workforce plans to identify key functions and proactively implement plans to assure a ready and qualified workforce, but cannot predict the impact of these plans on our ability to hire and retain key employees.
Market performance or changes in assumptions require us to make significant contributions to our pension and other post-employmentpostretirement benefit plans.
Costs of compliance with environmental regulations, including climate change legislation, may increase and have an adverse effect on our business and results of operations.
Our subsidiaries' operations are subject to extensive federal, state and local environmental statutes, rules and regulations that govern, among other things, air emissions, water discharges and the management of hazardous and solid waste. Compliance with these requirements requires us to incur significant costs relating to environmental monitoring, installation of pollution control equipment, emission fees, maintenance and upgrading of facilities, remediation and permitting. The costs of compliance with existing legal requirements or legal requirements not yet adopted may increase in the future. An increase in such costs, unless promptly recovered, could have an adverse impact on our business and our financial position, results of operations or cash flows.
In addition, global climate change issues have received an increased focus from federal and state governments, which could potentially lead to additional rules and regulations that impact how we operate our business, both in terms of the power plants we own and operate as well as general utility operations.government agencies . Although we would expect that any costs of these rules and regulations would be recovered from customers, their impact on energy use by customers and the ultimate impact on our business would be dependent upon the specific rules and regulations adopted and cannot be determined at this time. The impact of these additional costs to customers could lead to a further reduction in energy consumption resulting in a decline in electricity and gas sales in our service territories, which would have an adverse impact on our business and financial position, results of operations or cash flows.
Any failure by us to comply with environmental laws and regulations, even if due to factors beyond our control, or reinterpretations of existing requirements, could also increase costs. Existing environmental laws and regulations may be revised or new laws and regulations seeking to protect the environment may be adopted or become applicable to us. Revised or additional laws could result in
significant additional expense and operating restrictions on our facilities or increased compliance costs, which may not be fully recoverable in distribution company rates. The cost impact of any such laws, rules or regulations would be dependent upon the specific requirements adopted and cannot be determined at this time. For further information, see Item 1,Business -Other Regulatory and Environmental Matters, included in this Annual Report on Form 10-K.
Item 1B.
We do not have any unresolved SEC staff comments.
** Claimed capability represents the direct current nameplate capacity of the plant.
CL&P and NSTAR Electric do not own any electric generating plants.
In addition to the right to provide electric transmission and distribution services as set forth above, the franchises of CL&P include, among others, limited rights and powers, as set forth under Connecticut law and the special acts of the General Assembly constituting its charter, to manufacture, generate, purchase and/or sell electricity at retail, including to provide Standard Service, Supplier of Last Resort service and backup service, to sell electricity at wholesale and to erect and maintain certain facilities on public highways and grounds, all subject to such consents and approvals of public authority and others as may be required by law. The franchises of CL&P include the power of eminent domain. Connecticut law prohibits an electric distribution company from owning or operating generation assets. However, under "An Act Concerning Energy Independence," enacted in 2005, CL&P is permitted to own up to 200 MW of peaking facilities if the PURA determines that such facilities will be more cost effective than other options for mitigating FMCC and Locational Installed Capacity (LICAP) costs. In addition, under "An Act Concerning Electricity and Energy Efficiency," enacted in 2007, an electric distribution company, such as CL&P, is permitted to purchase an existing electric generating plant located in Connecticut that is offered for sale, subject to prior approval from the PURA and a determination by the PURA that such purchase is in the public interest. Finally, Connecticut law also allows CL&P to submit a proposal to the DEEP to build, own or operate one or more generation facilities up to 10 MWs using Class 1I renewable energy.
time and are subject to the action of these authorities and the legislature. Under Massachusetts law, with the exception of municipal-owned utilities, no other entity may provide electric or natural gas delivery service to retail
The Massachusetts restructuring legislation defines service territories as those territories actually served on July 1, 1997 and following municipal boundaries to the extent possible. The restructuring legislation further provides that until terminated by law or otherwise, distribution companies shall have the exclusive obligation to serve all retail customers within their service territories and no other person shall provide distribution service within such service territories without the written consent of such distribution companies. Pursuant to the Massachusetts restructuring legislation, the DPU (then, the Department of Telecommunications and Energy) was required to define service territories for each distribution company, including NSTAR Electric. The DPU subsequently determined that there were advantages to the exclusivity of service territories and issued a report to the Massachusetts Legislature recommending against, in this regard, any changes to the restructuring legislation.
In addition to the right to distribute electricity as set forth above, the franchises of PSNH include, among others, rights and powers to manufacture, generate, purchase, and transmit electricity, to sell electricity at wholesale to other utility companies and municipalities and to erect and maintain certain facilities on certain public highways and grounds, all subject to such consents and approvals of public authority and others as may be required by law. PSNH’sPSNH's status as a public utility gives it the ability to petition the NHPUC for the right to exercise eminent domain for its transmission and distribution services in appropriate circumstances.
PSNH is also subject to certain regulatory oversight by the Maine Public Utilities Commission and the Vermont Public Service Board.
The Massachusetts restructuring legislation applicable to NSTAR Electric (described above) is also applicable to WMECO.
Item 3.
iii
EVERSOURCE ENERGY AND SUBSIDIARIES
THE CONNECTICUT LIGHT AND POWER COMPANY
NSTAR ELECTRIC COMPANY AND SUBSIDIARY
PUBLIC SERVICE COMPANY OF NEW HAMPSHIRE AND SUBSIDIARY
WESTERN MASSACHUSETTS ELECTRIC COMPANY
SAFE HARBOR STATEMENT UNDER THE PRIVATE SECURITIES
LITIGATION REFORM ACT OF 1995
References in this Annual Report on Form 10-K to "Eversource," "the Company," "we," "our," and "us" refer to Eversource and its consolidated subsidiaries. On April 30, 2015, the Company's legal name was changed from Northeast Utilities to Eversource Energy. CL&P, NSTAR Electric, PSNH and WMECO are each doing business as Eversource Energy.
From time to time we make statements concerning our expectations, beliefs, plans, objectives, goals, strategies, assumptions of future events, future financial performance or growth and other statements that are not historical facts. These statements are "forward-looking statements" within the meaning of the Private Securities Litigation Reform Act of 1995. You can generally identify our forward-looking statements through the use of words or phrases such as "estimate," "expect," "anticipate," "intend," "plan," "project," "believe," "forecast," "should," "could," and other similar expressions. Forward-looking statements are based on the current expectations, estimates, assumptions or projections of management and are not guarantees of future performance. These expectations, estimates, assumptions or projections may vary materially from actual results. Accordingly, any such statements are qualified in their entirety by reference to, and are accompanied by, the following important factors that could cause our actual results to differ materially from those contained in our forward-looking statements, including, but not limited to:
·
cyber breaches, acts of war or terrorism, or grid disturbances,
·
actions or inaction of local, state and federal regulatory, public policy and taxing bodies,
·
changes in business conditions, which could include disruptive technology related to our current or future business model,
·
changes in economic conditions, including impact on interest rates, tax policies, and customer demand and payment ability,
·
fluctuations in weather patterns,
·
changes in laws, regulations or regulatory policy,
·
changes in levels or timing of capital expenditures,
·
disruptions in the capital markets or other events that make our access to necessary capital more difficult or costly,
·
developments in legal or public policy doctrines,
·
technological developments,
·
changes in accounting standards and financial reporting regulations,
·
actions of rating agencies, and
·
other presently unknown or unforeseen factors.
Other risk factors are detailed in our reports filed with the SEC and updated as necessary, and we encourage you to consult such disclosures.
All such factors are difficult to predict, contain uncertainties that may materially affect our actual results and are beyond our control. You should not place undue reliance on the forward-looking statements, each speaks only as of the date on which such statement is made, and we undertake no obligation to update any forward-looking statement or statements to reflect events or circumstances after the date on which such statement is made or to reflect the occurrence of unanticipated events. New factors emerge from time to time and it is not possible for us to predict all of such factors, nor can we assess the impact of each such factor on the business or the extent to which any factor, or combination of factors, may cause actual results to differ materially from those contained in any forward-looking statements. For more information, see Item 1A, Risk Factors, included in this combined Annual Report on Form 10-K. This Annual Report on Form 10-K also describes material contingencies and critical accounting policies in the accompanyingManagement's Discussion and Analysis of Financial Condition and Results of OperationsandCombined Notes to Consolidated Financial Statements. We encourage you to review these items.
1
EVERSOURCE ENERGY AND SUBSIDIARIES
THE CONNECTICUT LIGHT AND POWER COMPANY
NSTAR ELECTRIC COMPANY AND SUBSIDIARY
PUBLIC SERVICE COMPANY OF NEW HAMPSHIRE AND SUBSIDIARY
WESTERN MASSACHUSETTS ELECTRIC COMPANY
PART I
Item 1.
Business
Please refer to the Glossary of Terms for definitions of defined terms and abbreviations used in this combined Annual Report on Form 10-K.
Eversource Energy, headquartered in Boston, Massachusetts and Hartford, Connecticut, is a public utility holding company subject to regulation by the FERC under the Public Utility Holding Company Act of 2005. We are engaged primarily in the energy delivery business through the following wholly owned utility subsidiaries:
·
The Connecticut Light and Power Company (CL&P), a regulated electric utility that serves residential, commercial and industrial customers in parts of Connecticut;
·
NSTAR Electric Company (NSTAR Electric), a regulated electric utility that serves residential, commercial and industrial customers in parts of eastern Massachusetts;
·
Public Service Company of New Hampshire (PSNH), a regulated electric utility that serves residential, commercial and industrial customers in parts of New Hampshire and owns generation assets used to serve customers;
·
Western Massachusetts Electric Company (WMECO), a regulated electric utility that serves residential, commercial and industrial customers in parts of western Massachusetts and owns solar generating assets;
·
NSTAR Gas Company (NSTAR Gas), a regulated natural gas utility that serves residential, commercial and industrial customers in parts of Massachusetts; and
·
Yankee Gas Services Company (Yankee Gas), a regulated natural gas utility that serves residential, commercial and industrial customers in parts of Connecticut.
CL&P, NSTAR Electric, PSNH and WMECO also serve New England customers through Eversource Energy's electric transmission business.
On April 30, 2015, the Company's legal name was changed from Northeast Utilities to Eversource Energy. CL&P, NSTAR Electric, PSNH and
WMECO are each doing business as Eversource Energy.
Eversource Energy, CL&P, NSTAR Electric, PSNH and WMECO each report their financial results separately. We also include information in this report on a segment basis for Eversource Energy. Eversource Energy recognizes three reportable segments: electric distribution, electric transmission and natural gas distribution. Eversource Energy's electric distribution segment includes the generation businesses of PSNH and WMECO. These three segments represented substantially all of Eversource Energy's total consolidated revenues for the years ended December 31, 2015 and 2014. CL&P, NSTAR Electric, PSNH and WMECO do not report separate business segments.
ELECTRIC DISTRIBUTION SEGMENT
General
Eversource Energy's electric distribution segment consists of the distribution businesses of CL&P, NSTAR Electric, PSNH and WMECO, which are engaged in the distribution of electricity to retail customers in Connecticut, eastern Massachusetts, New Hampshire and western Massachusetts, respectively, plus the regulated electric generation businesses of PSNH and WMECO.
The following table shows the sources of 2015 electric franchise retail revenues for Eversource Energy's electric distribution companies, collectively, based on categories of customers:
| | | | |
(Thousands of Dollars, except percentages) | | 2015 | | % of Total |
Residential | $ | 3,608,155 | | 55 |
Commercial | | 2,476,686 | | 38 |
Industrial | | 326,564 | | 5 |
Other | | 151,195 | | 2 |
Total Retail Electric Revenues | $ | 6,562,600 | | 100% |
2
A summary of our distribution companies' retail electric GWh sales volumes and percentage changes for 2015, as compared to 2014, is as follows:
| | | | | |
| 2015 | | 2014 | | Percentage
Change |
Residential | 21,441 | | 21,317 | | 0.6 % |
Commercial | 27,598 | | 27,449 | | 0.5 % |
Industrial | 5,577 | | 5,676 | | (1.7)% |
Total | 54,616 | | 54,442 | | 0.3 % |
Our 2015 consolidated retail electric sales volumes were slightly higher, as compared to 2014, due primarily to the impact of colder winter weather experienced in the first quarter of 2015 and warmer weather in the third quarter of 2015, partially offset by milder winter weather in the fourth quarter of 2015 throughout our service territories as well as an increase in customer conservation efforts, including the impact of energy efficiency programs sponsored by CL&P, NSTAR Electric, PSNH and WMECO.
Fluctuations in retail electric sales volumes at NSTAR Electric and PSNH impact earnings. For CL&P (effective December 1, 2014) and WMECO, fluctuations in retail electric sales volumes do not impact earnings due to their respective regulatory commission approved revenue decoupling mechanisms. These distribution revenues are decoupled from their customer sales volumes, which breaks the relationship between sales volumes and revenues recognized. CL&P and WMECO reconcile their annual base distribution rate recovery amounts to their respective pre-established levels of baseline distribution delivery service revenues. Any difference between the allowed level of distribution revenue and the actual amount incurred during a 12-month period is adjusted through rates in the following period.
ELECTRIC DISTRIBUTION – CONNECTICUT
THE CONNECTICUT LIGHT AND POWER COMPANY
CL&P's distribution business consists primarily of the purchase, delivery and sale of electricity to its residential, commercial and industrial customers. As of December 31, 2015, CL&P furnished retail franchise electric service to approximately 1.2 million customers in 149 cities and towns in Connecticut, covering an area of 4,400 square miles. CL&P does not own any electric generation facilities.
The following table shows the sources of CL&P's 2015 electric franchise retail revenues based on categories of customers:
| | | | | |
| CL&P |
(Thousands of Dollars, except percentages) | | 2015 | | % of Total |
Residential | $ | 1,641,165 | | 61 |
Commercial | | 841,093 | | 31 |
Industrial | | 129,544 | | 5 |
Other | | 62,704 | | 3 |
Total Retail Electric Revenues | $ | 2,674,506 | | 100% |
A summary of CL&P's retail electric GWh sales volumes and percentage changes for 2015, as compared to 2014, is as follows:
| | | | | |
| 2015 | | 2014 | | Percentage
Change |
Residential | 10,094 | | 10,026 | | 0.7 % |
Commercial | 9,635 | | 9,643 | | (0.1)% |
Industrial | 2,342 | | 2,377 | | (1.5)% |
Total | 22,071 | | 22,046 | | 0.1 % |
Rates
CL&P is subject to regulation by the PURA, which, among other things, has jurisdiction over rates, certain dispositions of property and plant, mergers and consolidations, issuances of long-term securities, standards of service and construction and operation of facilities. CL&P's present general rate structure consists of various rate and service classifications covering residential, commercial and industrial services. CL&P's retail rates include a delivery service component, which includes distribution, transmission, conservation, renewables, CTA, SBC and other charges that are assessed on all customers. Connecticut utilities are entitled under state law to charge rates that are sufficient to allow them an opportunity to recover their reasonable operating and capital costs, in order to attract needed capital and maintain their financial integrity, while also protecting relevant public interests.
Under Connecticut law, all of CL&P's customers are entitled to choose their energy suppliers, while CL&P remains their electric distribution company. For those customers who do not choose a competitive energy supplier, under SS rates for customers with less than 500 kilowatts of demand, and LRS rates for customers with 500 kilowatts or more of demand, CL&P purchases power under standard offer contracts and passes the cost of the power to customers through a combined GSC and FMCC charge on customers' bills.
CL&P continues to supply approximately 40 percent of its customer load at SS or LRS rates while the other 60 percent of its customer load has migrated to competitive energy suppliers. Because this customer migration is only for energy supply service, it has no impact on CL&P's electric distribution business or its operating income.
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The rates established by the PURA for CL&P are comprised of the following:
·
An electric generation services charge (GSC), which recovers energy-related costs incurred as a result of providing electric generation service supply to all customers that have not migrated to competitive energy suppliers. The GSC is adjusted periodically and reconciled semi-annually in accordance with the policies and procedures of the PURA, with any differences refunded to, or recovered from, customers.
·
A revenue decoupling adjustment (effective December 1, 2014) that reconciles the amounts recovered from customers, on an annual basis, to the distribution revenue requirement approved by the PURA in its last rate case, which currently is an annual amount of $1.059 billion.
·
A distribution charge, which includes a fixed customer charge and a demand and/or energy charge to collect the costs of building and expanding the infrastructure to deliver power to customers, as well as ongoing operating costs to maintain the infrastructure.
·
A federally-mandated congestion charge (FMCC), which recovers any costs imposed by the FERC as part of the New England Standard Market Design, including locational marginal pricing, locational installed capacity payments, and any costs approved by the PURA to reduce these charges. The FMCC also recovers costs associated with CL&P's system resiliency program. The FMCC is adjusted periodically and reconciled semi-annually in accordance with the policies and procedures of the PURA, with any differences refunded to, or recovered from, customers.
·
A transmission charge that recovers the cost of transporting electricity over high voltage lines from generating plants to substations, including costs allocated by ISO-NE to maintain the wholesale electric market.
·
A competitive transition assessment charge (CTA), assessed to recover stranded costs associated with electric industry restructuring such as various IPP contracts. The CTA is reconciled annually to actual costs incurred and reviewed by the PURA, with any difference refunded to, or recovered from, customers.
·
A systems benefits charge (SBC), established to fund expenses associated with: various hardship and low income programs; a program to compensate municipalities for losses in property tax revenue due to decreases in the value of electric generating facilities resulting directly from electric industry restructuring. The SBC is reconciled annually to actual costs incurred and reviewed by the PURA, with any difference refunded to, or recovered from, customers.
·
A Clean Energy Fund charge, which is used to promote investment in renewable energy sources. Amounts collected by this charge are deposited into the Clean Energy Fund and administered by the Clean Energy Finance and Investment Authority. The Clean Energy Fund charge is set by statute and is currently 0.1 cent per kWh.
·
A conservation charge, comprised of a statutory rate established to implement cost-effective energy conservation programs and market transformation initiatives, plus a conservation adjustment mechanism charge to recover the residual energy efficiency spending associated with the expanded energy efficiency costs directed by the Comprehensive Energy Strategy Plan for Connecticut.
As required by regulation, CL&P, jointly with UI, entered into the following contracts whereby UI will share 20 percent and CL&P will share 80 percent of the costs and benefits (CL&P's portion of these costs are either recovered from, or refunded to, customers through the FMCC charge):
·
Four CfDs (totaling approximately 787 MW of capacity) with three electric generation units and one demand response project, which extend through 2026 and have terms of up to 15 years beginning in 2009. The capacity CfDs obligate both CL&P and UI to make or receive payments on a monthly basis to or from the project and generation owners based on the difference between a contractually set capacity price and the capacity market prices that the project and generation owners receive in the ISO-NE capacity markets.
·
Three CfDs (totaling approximately 500 MW of peaking capacity) with three peaking generation units. The three peaker CfDs pay the generation owners the difference between capacity, forward reserve and energy market revenues and a cost-of service payment stream for 30 years beginning in 2008 (including costs of plant operation and the prices that the generation owners receive for capacity and other products in the ISO-NE markets).
·
Long-term commitments to purchase approximately 250 MW of wind power from a Maine wind farm and 20 MW of solar power from a multi-site project in Connecticut. Both of these projects are expected to be operational by the end of 2016.
On December 17, 2014 the PURA approved CL&P's application to amend customer rates, effective December 1, 2014, for a total base distribution rate increase of $152 million, which includes an authorized ROE of 9.02 percent for the first twelve month period and 9.17 percent thereafter. The distribution rate increase included a revenue decoupling mechanism effective December 1, 2014, and the recovery of 2011 and 2012 storm restoration costs and system resiliency costs. Also in December 2014, the PURA granted a re-opener request to CL&P’s base distribution rate application for further review of the appropriate balance of ADIT utilized in the calculation of rate base. On July 2, 2015, the PURA issued a final order that approved a settlement agreement filed on May 19, 2015 between CL&P and the PURA Prosecutorial Staff, and which included an increase to total allowed annual revenue requirements of $18.4 million beginning December 1, 2014.
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Sources and Availability of Electric Power Supply
As noted above, CL&P does not own any generation assets and purchases energy supply to serve its SS and LRS loads from a variety of competitive sources through requests for proposals. CL&P periodically enters into full requirements contracts for the majority of SS loads for periods of up to one year for its residential customers and small and medium commercial and industrial customers. CL&P is authorized to supply the remainder of the SS loads through a self-managed process that includes bilateral purchases and spot market purchases. CL&P typically enters into full requirements contracts for LRS for larger commercial and industrial customers every three months. Currently, CL&P has full requirements contracts in place for 80 percent of its SS loads for the first half of 2016 and has bilateral purchases in place to self-manage the remaining 20 percent. For the second half of 2016, CL&P has 50 percent of its SS load under full requirements contracts, intends to purchase an additional 30 percent of full requirements and will self-manage the remainder as needed. None of the SS load for 2017 has been procured. CL&P has full requirements contracts in place for its LRS loads through the second quarter of 2016 and intends to purchase 100 percent of full requirements for the third and fourth quarters of 2016.
ELECTRIC DISTRIBUTION – MASSACHUSETTS
NSTAR ELECTRIC COMPANY
WESTERN MASSACHUSETTS ELECTRIC COMPANY
The electric distribution businesses of NSTAR Electric and WMECO consist primarily of the purchase, delivery and sale of electricity to residential, commercial and industrial customers within their respective franchise service territories. As of December 31, 2015, NSTAR Electric furnished retail franchise electric service to approximately 1.2 million customers in Boston and 80 surrounding cities and towns in Massachusetts, including Cape Cod and Martha's Vineyard, covering an area of approximately 1,700 square miles. WMECO provides retail franchise electric service to approximately 209,000 customers in 59 cities and towns in the western region of Massachusetts, covering an area of approximately 1,500 square miles. Neither NSTAR Electric nor WMECO owns any generating facilities used to supply customers, and each purchases its respective energy requirements from competitive energy suppliers.
In 2009, WMECO was authorized by the DPU to install solar energy generation in its service territory. From 2010 through 2014, WMECO completed development of a total of 8 MW solar generation facilities on sites in Pittsfield, Springfield, and East Springfield, Massachusetts. WMECO will sell all energy and other products from its solar generation facilities into the ISO-NE market. NSTAR Electric does not own any solar generation facilities.
The following table shows the sources of the 2015 electric franchise retail revenues of NSTAR Electric and WMECO based on categories of customers:
| | | | | | | | | |
| | NSTAR Electric | | WMECO |
(Thousands of Dollars, except percentages) | | 2015 | | % of Total | | 2015 | | % of Total |
Residential | $ | 1,205,387 | | 48 | | $ | 255,797 | | 59 |
Commercial | | 1,187,452 | | 47 | | | 135,222 | | 31 |
Industrial | | 84,667 | | 3 | | | 35,439 | | 8 |
Other | | 47,610 | | 2 | | | 5,778 | | 2 |
Total Retail Electric Revenues | $ | 2,525,116 | | 100% | | $ | 432,236 | | 100% |
A summary of NSTAR Electric's and WMECO's retail electric GWh sales volumes and percentage changes for 2015, as compared to 2014, is as follows:
| | | | | | | | | | | | |
| | NSTAR Electric | | WMECO |
| | 2015 | | 2014 | | Percentage
Change | | 2015 | | 2014 | | Percentage
Change |
Residential | | 6,687 | | 6,625 | | 0.9 % | | 1,465 | | 1,494 | | (2.0)% |
Commercial | | 13,120 | | 13,009 | | 0.9 % | | 1,478 | | 1,466 | | 0.8 % |
Industrial | | 1,248 | | 1,291 | | (3.3)% | | 620 | | 626 | | (0.9)% |
Total | | 21,055 | | 20,925 | | 0.6 % | | 3,563 | | 3,586 | | (0.6)% |
Rates
NSTAR Electric and WMECO are each subject to regulation by the DPU, which, among other things, has jurisdiction over rates, certain dispositions of property and plant, mergers and consolidations, issuances of long-term securities, acquisition of securities, standards of service and construction and operation of facilities. The present general rate structure for both NSTAR Electric and WMECO consists of various rate and service classifications covering residential, commercial and industrial services. Massachusetts utilities are entitled under state law to charge rates that are sufficient to allow them an opportunity to recover their reasonable operating and capital costs, in order to attract needed capital and maintain their financial integrity, while also protecting relevant public interests.
Under Massachusetts law, all customers of each of NSTAR Electric and WMECO are entitled to choose their energy suppliers, while NSTAR Electric or WMECO remains their electric distribution company. Both NSTAR Electric and WMECO purchase power from competitive suppliers on behalf of, and pass the related cost through to, their respective customers who do not choose a competitive energy supplier (basic service). Most of the residential customers of NSTAR Electric and WMECO have continued to buy their power from NSTAR Electric or WMECO at basic service rates. Most commercial and industrial customers have switched to a competitive energy supplier.
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The Cape Light Compact, an inter-governmental organization consisting of the 21 towns and two counties on Cape Cod and Martha's Vineyard, serves 200,000 customers through the delivery of energy efficiency programs, effective consumer advocacy, competitive electricity supply and green power options. NSTAR Electric continues to provide electric service to these customers including the delivery of power, maintenance of infrastructure, capital investment, meter reading, billing, and customer service.
NSTAR Electric continues to supply approximately 39 percent of its customer load at basic service rates while the other 61 percentof its customer load has migrated to competitive energy suppliers. WMECO continues to supply approximately 41 percent of its customer load at basic service rates while the other 59 percent of its customer load has migrated to competitive energy suppliers. Because customer migration is limited to energy supply service, it has no impact on the delivery business or operating income of NSTAR Electric and WMECO.
The rates established by the DPU for NSTAR Electric and WMECO are comprised of the following:
·
A basic service charge that represents the collection of energy costs, including costs related to charge-offs of uncollectible energy costs from customers. Electric distribution companies in Massachusetts are required to obtain and resell power to retail customers through basic service for those 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). Additionally, the DPU has authorized NSTAR Electric to recover the cost of its Dynamic Pricing Smart Grid Pilot Program and NSTAR Green wind contracts through the basic service charge. Basic service costs are reconciled annually, with any differences refunded to, or recovered from, customers.
·
A distribution charge, which includes a fixed customer charge and a demand and/or energy charge to collect the costs of building and expanding the infrastructure to deliver power to its destination, as well as ongoing operating costs.
·
For WMECO, a revenue decoupling adjustment that reconciles distribution revenue, on an annual basis, to the amount of distribution revenue approved by the DPU in its last rate case in 2011. Currently, WMECO is allowed to collect $132.4 million annually.
·
A transmission charge that recovers the cost of transporting electricity over high voltage lines from generating plants to substations, including costs allocated by ISO-NE to maintain the wholesale electric market.
·
A transition charge that represents costs to be collected primarily from previously held investments in generating plants, costs related to existing above-market power contracts, and contract costs related to long-term power contract buy-outs.
·
An energy efficiency charge that represents a legislatively-mandated charge to collect costs for energy efficiency programs.
·
Reconciling adjustment charges that recover certain DPU-approved costs as follows: pension and PBOP benefits, low income customer discounts, lost revenue and credits associated with net-metering facilities installed by customers, storms, consultants retained by the attorney general, long-term renewable contracts and energy efficiency programs and lost base revenue associated with energy efficiency measures. In addition to these adjustments common to both NSTAR Electric and WMECO, NSTAR Electric has reconciling adjustment charges that collect costs associated with certain safety and reliability projects and a Smart Grid pilot program. WMECO has a reconciling adjustment charge that recovers costs associated with certain solar projects owned and operated by WMECO.
As required by regulation, NSTAR Electric and WMECO, along with two other Massachusetts electric utilities, signed long-term commitments to purchase a combined estimated generating capacity of approximately 334 MW of wind power from two wind farms in Maine over 15 years. The projects are in various stages of permitting, development, or operation. One unit began operating in late 2015, and the other unit is expected to be in operation by December 2016. In addition, WMECO previously signed a long-term commitment to purchase an estimated generating capacity of approximately 37.5 MW of wind power from a wind farm in Maine over 15 years that is expected to be in operation in 2016.
Pursuant to a 2008 DPU order, Massachusetts electric utilities must adopt rate structures that decouple the volume of energy sales from the utility's revenues in their next rate case. WMECO is currently decoupled and NSTAR Electric will propose decoupling in its next rate case.
NSTAR Electric and WMECO are each subject to service quality (SQ) metrics that measure safety, reliability and customer service, and could be required to pay to customers a SQ charge of up to 2.5 percent of annual transmission and distribution revenues for failing to meet such metrics. Neither NSTAR Electric nor WMECO will be required to pay a SQ charge for its 2015 performance as each company achieved results at or above target for all of its respective SQ metrics in 2015.
Sources and Availability of Electric Power Supply
As noted above, neither NSTAR Electric nor WMECO owns any generation assets (other than WMECO's solar generation), and both companies purchase their respective energy requirements from a variety of competitive sources through requests for proposals issued periodically, consistent with DPU regulations. NSTAR Electric and WMECO enter into supply contracts for basic service for 50 percentof their respective residential and small commercial and industrial customers twice per year for twelve month terms. Both NSTAR Electric and WMECO enter into supply contracts for basic service for 100 percentof large commercial and industrial customers every three months.
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ELECTRIC DISTRIBUTION – NEW HAMPSHIRE
PUBLIC SERVICE COMPANY OF NEW HAMPSHIRE
PSNH's distribution business consists primarily of the generation, delivery and sale of electricity to its residential, commercial and industrial customers. As of December 31, 2015, PSNH furnished retail franchise electric service to approximately 503,000 retail customers in 211 cities and towns in New Hampshire, covering an area of approximately 5,630 square miles. PSNH currently owns and operates approximately 1,200 MW of primarily coal-, natural gas-, and oil-fired electricity generation plants. PSNH's distribution business includes the activities of its generation business.
The Clean Air Project, a wet flue gas desulphurization system (Scrubber), was constructed and placed in service by PSNH at its Merrimack Station in 2011. The Scrubber reduces emissions of SO2 and mercury from Merrimack Station by over 90 percent, which is well in excess of state and federal requirements. PSNH is permitted to recover prudent Scrubber costs through its default energy service rates under New Hampshire law. Effective January 1, 2016, PSNH is recovering all Scrubber costs in rates charged to customers. For further information, see "Regulatory Developments and Rate Matters – New Hampshire – Clean Air Project Prudence Proceeding" in the accompanying Item 7,Management's Discussion and Analysis of Financial Condition and Results of Operations.
The following table shows the sources of PSNH's 2015 electric franchise retail revenues based on categories of customers:
| | | | |
| PSNH |
(Thousands of Dollars, except percentages) | | 2015 | | % of Total |
Residential | $ | 505,806 | | 54 |
Commercial | | 312,918 | | 34 |
Industrial | | 76,914 | | 8 |
Other | | 35,103 | | 4 |
Total Retail Electric Revenues | $ | 930,741 | | 100% |
A summary of PSNH's retail electric GWh sales volumes and percentage changes for 2015, as compared to 2014, is as follows:
| | | | | |
| 2015 | | 2014 | | Percentage
Change |
Residential | 3,195 | | 3,172 | | 0.7 % |
Commercial | 3,365 | | 3,332 | | 1.0 % |
Industrial | 1,367 | | 1,382 | | (1.1)% |
Total | 7,927 | | 7,886 | | 0.5 % |
Rates
PSNH is subject to regulation by the NHPUC, which, among other things, has jurisdiction over rates, certain dispositions of property and plant, mergers and consolidations, issuances of securities, standards of service and construction and operation of facilities. New Hampshire utilities are entitled under state law to charge rates that are sufficient to allow them an opportunity to recover their reasonable operating and capital costs, in order to attract needed capital and maintain their financial integrity, while also protecting relevant public interests.
Under New Hampshire law, all of PSNH's customers are entitled to choose competitive energy suppliers, with PSNH providing default energy service under its ES rate for those customers who do not choose a competitive energy supplier. At the end of 2015, approximately 21 percent of all of PSNH's customers (approximately 53 percent of load) were taking service from competitive energy suppliers, compared to 21 percent of customers (approximately 46 percent of load) at the end of 2014.
The rates established by the NHPUC for PSNH are comprised of the following:
·
A default energy service charge which recovers energy-related costs incurred as a result of providing electric generation service supply to all customers that have not migrated to competitive energy suppliers. These charges recover the costs of PSNH's generation, as well as purchased power, and include an allowed ROE of 9.81 percent.
·
A distribution charge, which includes an energy and/or demand-based charge to recover costs related to the maintenance and operation of PSNH's infrastructure to deliver power to its destination, as well as power restoration and service costs. This includes a customer charge to collect the cost of providing service to a customer; such as the installation, maintenance, reading and replacement of meters and maintaining accounts and records.
·
A transmission charge that recovers the cost of transporting electricity over high voltage lines from generating plants to substations, including costs allocated by ISO-NE to maintain the wholesale electric market.
·
A stranded cost recovery charge (SCRC), which allows PSNH to recover its stranded costs, including above-market expenses incurred under mandated power purchase obligations and other long-term investments and obligations.
·
A system benefits charge (SBC), which funds energy efficiency programs for all customers as well as assistance programs for residential customers within certain income guidelines.
7
·
An electricity consumption tax, which is a state mandated tax on electric energy consumption.
The energy charge and SCRC rates change semi-annually and are reconciled annually and differences between actual costs incurred versus current rates are either refunded or recovered in subsequent rates charged to customers.
PSNH distribution rates were set in a 2010 NHPUC rate case settlement, which expired on June 30, 2015. In the 2015 PSNH Settlement Agreement, the Company agreed that its present distribution rates will stay in effect until at least July 1, 2017. However, certain aspects of the 2010 rate case settlement will continue, including funding for reliability enhancement program activities, adjustment of distribution rates for certain exogenous events that in the aggregate exceed $1 million, and major storm reserve funding.
Generation Divestiture
In 2013, the NHPUC opened a docket to investigate market conditions affecting PSNH's default energy service rate, how PSNH will maintain just and reasonable rates in light of those conditions, and any impact of PSNH's generation ownership on the New Hampshire competitive electric market. In April 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. An abbreviated draft update by the consultant dated August 17, 2015, increased the estimated fair market value of PSNH’s generation assets to $235 million.
In 2014, 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 to determine whether all or some of PSNH's generation assets should be divested. 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.
On June 10, 2015, Eversource and PSNH entered into the 2015 Public Service Company of New Hampshire Restructuring and Rate Stabilization Agreement (the Agreement) with the New Hampshire Office of Energy and Planning, certain members of the NHPUC staff, the Office of Consumer Advocate, two state senators, and several other parties. The Agreement was filed with the NHPUC on the same day. Under the terms of the Agreement, PSNH has agreed to divest its generation assets upon NHPUC approval. The Agreement is designed to provide a resolution of issues pertaining to PSNH's generation assets in pending regulatory proceedings before the NHPUC. The Agreement provided for the Clean Air Project prudence proceeding to be resolved and all remaining Clean Air Project costs to be included in rates effective January 1, 2016. As part of the Agreement, PSNH has agreed to forego recovery of $25 million of the deferred equity return related to the Clean Air Project. In addition, PSNH will not seek a general distribution rate increase effective before July 1, 2017 and will contribute $5 million to create a clean energy fund, which will not be recoverable from its customers.
In 2015, the Legislature enacted changes to law to allow the use of securitization financing to recover any stranded costs resulting from the divestiture of PSNH’s generating assets. If the Agreement is approved, following divestiture of PSNH’s generating assets, bonds will be issued to recover resulting stranded costs.
On January 26, 2016, Advisory Staff of the NHPUC and the parties to the Agreement filed a stipulation with the NHPUC agreeing that near-term divestiture of PSNH’s generation was in the public interest and that the Agreement should be approved. Implementation of the Agreement is subject to NHPUC approval, which is expected in early 2016.
Sources and Availability of Electric Power Supply
During 2015, approximately 54 percent of PSNH's load was met through its own generation, long-term power supply provided pursuant to orders of the NHPUC, and contracts with competitive energy suppliers. The remaining 46 percentof PSNH's load was met by short-term (less than one year) purchases and spot purchases in the competitive New England wholesale power market. PSNH expects to meet its load requirements in 2016 in a similar manner. Included in the 54 percent above are PSNH's obligations to purchase power from approximately two dozen IPPs, the output of which it either uses to serve its customer load or sells into the ISO-NE market.
Merrimack and Schiller Stations have recently operated at lower than typical capacity factors due to moderate regional temperatures. The Hydro stations have been operating at high capacity factors. PSNH’s Energy Service Rate has been set at 9.99 cents per kWh effective January 1, 2016, which includes 1.27 cents per kWh reflecting full recovery of costs related to the Clean Air Project.
ELECTRIC TRANSMISSION SEGMENT
General
Each of CL&P, NSTAR Electric, PSNH and WMECO owns and maintains transmission facilities that are part of an interstate power transmission grid over which electricity is transmitted throughout New England. Each of CL&P, NSTAR Electric, PSNH and WMECO, and most other New England utilities, are parties to a series of agreements that provide for coordinated planning and operation of the region's transmission facilities and the rules by which they acquire transmission services. Under these arrangements, ISO-NE, a non-profit corporation whose board of directors and staff are independent of all market participants, serves as the regional transmission organization of the New England transmission system.
8
Wholesale Transmission Revenues
A summary of Eversource Energy's wholesale transmission revenues is as follows:
| | |
1.
Yankee Companies v. U.S. Department(Thousands of EnergyDollars)
|
| DOE Phase I Damages – In 1998, the Yankee Companies (CYAPC, YAEC and MYAPC) filed separate complaints against the DOE in the Court of Federal Claims seeking monetary damages resulting from the DOE's failure to begin accepting spent nuclear fuel for disposal by January 31, 1998 pursuant to the terms of the 1983 spent fuel and high level waste disposal contracts between the Yankee Companies and the DOE (DOE Phase I Damages). Phase I covered damages for the period 1998 through 2002. Following multiple appeals and cross-appeals in December 2012, the judgment awarding CYAPC $39.6 million, YAEC $38.3 million and MYAPC $81.7 million became final.2015
|
In January 2013, the proceeds from the DOE Phase I Damages Claim were received by the Yankee Companies and transferred to each Yankee Company’s respective decommissioning trust. As a result of NU's consolidation of CYAPC and YAEC, the financial statements reflected an increase of $77.9 million in marketable securities for CYAPC and YAEC’s Phase I damage awards that were invested in the nuclear decommissioning trusts in 2013.
On May 1, 2013, CYAPC, YAEC and MYAPC filed applications with the FERC to reduce rates in their wholesale power contracts through the application of the DOE proceeds for the benefit of customers. In its June 27, 2013 order, the FERC granted the proposed rate reductions, and changes to the terms of the wholesale power contracts to become effective on July 1, 2013. In accordance with the FERC order, CL&P
| $ | 513,025 |
NSTAR Electric | | 299,241 |
PSNH and | | 127,509 |
WMECO began receiving the benefit of the DOE proceeds, and the benefits have been or will be passed on to customers. |
|
129,502
|
Total Wholesale Transmission Revenues | $ | 1,069,277 |
Wholesale Transmission Rates
Wholesale transmission revenues are recovered through FERC approved formula rates. Transmission revenues are collected from New England customers, the majority of which are distribution customers of CL&P, NSTAR Electric, PSNH and WMECO. The transmission rates provide for the annual reconciliation of estimated to actual costs. The financial impacts of differences between actual and estimated costs are deferred for future recovery from, or refunded to, transmission customers.
FERC Base ROE Complaints
Three separate complaints have been filed at the FERC by combinations of New England state attorneys general, state regulatory commissions, consumer advocates, consumer groups, municipal parties and other parties (the "Complainants"). In these three separate complaints, the Complainants challenged the NETOs' base ROE of 11.14 percent that had been utilized since 2006 and sought an order to reduce it prospectively from the date of the final FERC order and for the 15-month complaint refund periods stipulated in the separate complaints. In 2014, the FERC ordered a 10.57 percent base ROE for the first complaint refund period and prospectively from October 16, 2014 and that a utility's total or maximum ROE shall not exceed the top of the new zone of reasonableness, which was set at 11.74 percent. The NETOs and the Complainants sought rehearing from the FERC. In late 2014, the NETOs made a compliance filing and the Company began issuing refunds to customers from the first complaint period.
On March 3, 2015, FERC issued an order denying all issues raised on rehearing by the NETOs and Complainants in the first complaint. The FERC order upheld the base ROE of 10.57 percent for the first complaint refund period and prospectively from October 16, 2014, and upheld that the utility's total ROE (the base ROEplus anyincentive adders) for the transmission assets to which the adder applies is capped at the top of the zone of reasonableness, which is currently set at 11.74 percent. The NETOs and Complainants have filed appeals to the D.C. Circuit Court of Appeals, which have been consolidated, and briefing is scheduled to be concluded in the second quarter of 2016. A court decision is expected in late 2016.
For the second and third complaint proceedings, hearings were held in late June and early July 2015 and briefs were filed in July and August 2015. The state parties, municipal utilities and FERC trial staff each believe that the base ROE should be reduced to an amount lower than 10.57 percent. The NETOs believe that the Complainants' positions are without merit, and the existing base ROE of 10.57 is just and reasonable and should be maintained. On December 18, 2015, the FERC ALJ reopened the record to have the NETOs and FERC trial staff review certain calculations. The FERC ALJ’s initial recommendation is expected by March 31, 2016. A final FERC order is expected in late 2016 or early 2017.
Although Eversource is uncertain on the final outcome of the second and third complaints regarding the ROE, we believe the current reserves established are appropriate to reflect probable and reasonably estimable refunds. For further information, see "FERC Regulatory Issues – FERC ROE Complaints" in the accompanying Item 7,Management's Discussion and Analysis of Financial Condition and Results of Operations.
FERC Order No. 1000
On August 15, 2014, the D.C. Circuit Court of Appeals upheld the FERC's authority to order major changes to transmission planning and cost allocation in FERC Order No. 1000 and Order No. 1000-A, including transmission planning for public policy needs, and the requirement that utilities remove from their transmission tariffs their rights of first refusal to build transmission. On March 19, 2015, the FERC acted on all rehearing requests filed by the NETOs, including CL&P, NSTAR Electric, PSNH and WMECO, and other parties and accepted the November 2013 compliance filing made by ISO-NE and the NETOs, subject to further compliance. The FERC accepted our proposal that the new competitive transmission planning process will not apply to certain projects, which have been declared as the preferred solution by ISO-NE, unless ISO-NE later decides a solution must be re-evaluated. The FERC determined on rehearing that we can restore provisions that recognize the NETOs’ rights to retain use and control of their existing rights of ways. Final compliance was filed by the NETOs in November 2015 and was accepted by the FERC on December 14, 2015.
Additionally, the FERC affirmed that it can eliminate our right of first refusal to build transmission in New England even though the FERC previously approved and granted special protections to these rights. The NETOs filed an appeal to the D.C. Circuit Court of Appeals, challenging this FERC ruling. State regulators also filed an appeal, challenging FERC’s determination that ISO-NE should select public policy transmission projects after a competitive process. The Court is expected to resolve the appeals in 2016.
Transmission Projects
During 2015, we were involved in the planning, development and construction of a series of electric transmission projects, including the NEEWS family of projects; the Greater Hartford Central Connecticut (GHCC) solutions; and Greater Boston Reliability Solutions, which are a series of new transmission projects over the next five years that will enhance system reliability and improve capacity. We were involved in the planning and
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development of Northern Pass, which is our 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; and the Clean Energy Connect Project, which is a planned transmission, wind and hydro generation project that we intend to develop with experienced renewable generation companies. For further information, see "Business Development and Capital Expenditures – Electric Transmission Business" in the accompanying Item 7,Management's Discussion and Analysis of Financial Condition and Results of Operations.
Transmission Rate Base
Under our FERC-approved tariff, and with the exception of transmission projects that received specific FERC approval to include CWIP in rate base, transmission projects generally enter rate base after they are placed in commercial operation. At the end of 2015, our estimated transmission rate base was approximately $5.2 billion, including approximately $2.4 billion at CL&P, $1.4 billion at NSTAR Electric, $548 million at PSNH, and $625 million at WMECO.
NATURAL GAS DISTRIBUTION SEGMENT
NSTAR Gas distributes natural gas to approximately 286,000 customers in 51 communities in central and eastern Massachusetts covering 1,067 square miles, and Yankee Gas distributes natural gas to approximately 226,000 customers in 71 cities and towns in Connecticut covering 2,187 square miles. Total throughput (sales and transportation) in 2015 was approximately 71.7 Bcf for NSTAR Gas and 57.8 Bcf for Yankee Gas. Our natural gas businesses provide firm natural gas sales service to retail customers who require a continuous natural gas supply throughout the year, such as residential customers who rely on natural gas for heating, hot water and cooking needs, and commercial and industrial customers who choose to purchase natural gas from Eversource Energy's natural gas distribution companies. A portion of the storage of natural gas supply for NSTAR Gas during the winter heating season is provided by Hopkinton LNG Corp., an indirect, wholly-owned subsidiary of Eversource Energy. NSTAR Gas has access to Hopkinton LNG Corp. facilities in Hopkinton, Massachusetts consisting of a LNG liquefaction and vaporization plant and three above-ground cryogenic storage tanks having an aggregate capacity of 3.0 Bcf of liquefied natural gas. NSTAR Gas also has access to Hopkinton LNG Corp. facilities in Acushnet, Massachusetts that include additional storage capacity of 0.5 Bcf and additional vaporization capacity.
Yankee Gas owns a 1.2 Bcf LNG facility in Waterbury, Connecticut, which is used primarily to assist Yankee Gas in meeting its supplier-of-last-resort obligations and also enables it to provide economic supply and make economic refill of natural gas typically during periods of low demand.
NSTAR Gas and Yankee Gas generate revenues primarily through the sale and/or transportation of natural gas. Predominantly all residential customers in the NSTAR Gas service territory buy gas supply and delivery from NSTAR Gas while all customers may choose their natural gas suppliers. Retail natural gas service in Connecticut is partially unbundled: residential customers in Yankee Gas' service territory buy natural gas supply and delivery only from Yankee Gas while commercial and industrial customers may choose their natural gas suppliers. NSTAR Gas offers firm transportation service to all customers who purchase natural gas from sources other than NSTAR Gas while Yankee Gas offers firm transportation service to its commercial and industrial customers who purchase natural gas from sources other than Yankee Gas. In addition, both natural gas distribution companies offer interruptible transportation and interruptible natural gas sales service to those high volume commercial and industrial customers, generally during the colder months, that have the capability to switch from natural gas to an alternative fuel on short notice, for whom NSTAR Gas and Yankee Gas can interrupt service during peak demand periods or at any other time to maintain distribution system integrity.
The following table shows the sources of the 2015 total Eversource Energy natural gas franchise retail revenues based on categories of customers:
| | | | |
(Thousands of Dollars, except percentages) | | 2015 | | % of Total |
Residential | $ | 497,873 | | 54 |
Commercial | | 327,439 | | 36 |
Industrial | | 93,378 | | 10 |
Total Retail Natural Gas Revenues | $ | 918,690 | | 100% |
A summary of our firm natural gas sales volumes in million cubic feet and percentage changes for 2015, as compared to 2014, is as follows:
| | | | | |
| | | Percentage |
| 2015 | | 2014 | | Change |
Residential | 38,455 | | 38,969 | | (1.3)% |
Commercial | 43,006 | | 42,977 | | 0.1 % |
Industrial | 21,538 | | 22,245 | | (3.2)% |
Total | 102,999 | | 104,191 | | (1.1)% |
Total, Net of Special Contracts(1) | 98,458 | | 99,500 | | (1.0)% |
(1)
Special contracts are unique to the customers who take service under such an arrangement and generally specify the amount of distribution revenue to be paid to Yankee Gas regardless of the customers' usage.
Our firm natural gas sales volumes are subject to many of the same influences as our retail electric sales volumes. In addition, they have benefited from customer growth in both of our natural gas distribution companies. In 2015, consolidated firm natural gas sales volumes were lower, as compared to 2014. The 2015 firm natural gas sales volumes were negatively impacted by record warm weather in the fourth quarter of 2015, when compared to 2014, partially offset by colder winter weather in the first quarter of 2015, as compared to 2014, throughout our natural gas service territories. Weather-normalized Eversource consolidated firm natural gas sales volumes increased 2.5 percent in 2015, as compared to 2014, due primarily to improved economic conditions as well as residential and commercial customer growth, through conversions to natural gas service.
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Rates
NSTAR Gas and Yankee Gas are subject to regulation by the DPU and the PURA, respectively, which, among other things, have jurisdiction over rates, certain dispositions of property and plant, mergers and consolidations, issuances of long-term securities, standards of service and construction and operation of facilities. Both of Eversource Energy's natural gas companies are entitled under their respective state law to charge rates that are sufficient to allow them an opportunity to recover their reasonable operating and capital costs, in order to attract needed capital and maintain their financial integrity, while also protecting relevant public interests.
Retail natural gas delivery and supply rates are established by the DPU and the PURA and are comprised of:
·
A distribution charge consisting of a fixed customer charge and a demand and/or energy charge that collects the costs of building and expanding the natural gas infrastructure to deliver natural gas supply to its customers. This also includes collection of ongoing operating costs;
·
A seasonal cost of gas adjustment clause (CGAC) at NSTAR Gas that collects natural gas supply costs, pipeline and storage capacity costs, costs related to charge-offs of uncollected energy costs and working capital related costs. The CGAC is reset semi-annually. In addition, NSTAR Gas files interim changes to its CGAC factor when the actual costs of natural gas supply vary from projections by more than five percent; and
·
A local distribution adjustment clause (LDAC) at NSTAR Gas that collects all energy efficiency and related program costs, environmental costs, pension and PBOP related costs, attorney general consultant costs, and costs associated with low income customers. The LDAC is reset annually and provides for the recovery of certain costs applicable to both sales and transportation customers.
·
Purchased Gas Adjustment (PGA) clause, which allows Yankee Gas to recover the costs of the procurement of natural gas for its firm and seasonal customers. Differences between actual natural gas costs and collection amounts on August 31st of each year are deferred and then recovered from or refunded to customers during the following year. Carrying charges on outstanding balances are calculated using Yankee Gas' weighted average cost of capital in accordance with the directives of the PURA; and
·
Conservation Adjustment Mechanism (CAM) at Yankee Gas, which allows 100 percent recovery of conservation costs through this mechanism including program incentives to promote energy efficiency, as well as recovery of any lost revenues associated with implementation of energy conservation measures. A reconciliation of CAM revenues to expenses is performed annually with any difference being recovered from or refunded to customers, with carrying charges, during the following year.
NSTAR Gas purchases financial contracts based on NYMEX natural gas futures in order to reduce cash flow variability associated with the purchase price for approximately one-third of its natural gas purchases. These purchases are made under a program approved by the DPU in 2006. This practice attempts to minimize the impact of fluctuations in natural gas prices to NSTAR Gas' firm natural gas customers. These financial contracts do not procure natural gas supply. All costs incurred or benefits realized when these contracts are settled are included in the CGAC.
NSTAR Gas is subject to service quality (SQ) metrics that measure safety, reliability and customer service and could be required to pay to customers a SQ charge of up to 2.5 percent of annual distribution revenues for failing to meet such metrics. NSTAR Gas will not be required to pay a SQ charge for its 2015 performance as it achieved results at or above target for all of its SQ metrics in 2015.
On October 30, 2015, the DPU issued its order in the NSTAR Gas distribution rate case, which approved an annualized base rate increase of $15.8 million, plus other increases of approximately $11.5 million, mostly relating to recovery of pension and PBOP expenses and the Hopkinton Gas Service Agreement, effective January 1, 2016. In the order, the DPU also approved an authorized regulatory ROE of 9.8 percent, the establishment of a revenue decoupling mechanism, the recovery of certain bad debt expenses, and a 52.1 percent equity component of its capital structure. On November 19, 2015, NSTAR Gas filed a motion for reconsideration of the order with the DPU seeking the correction of mathematical errors and other plant and cost of service items.
Yankee Gas’ last rate proceeding was in 2011, which approved an allowed ROE of 8.83 percent and allowed for a substantial increase in annual spending for bare steel and cast iron pipeline replacement. In 2015, Yankee Gas entered into a settlement agreement with the PURA staff pursuant to which Yankee Gas provided a $1.5 million rate credit to firm customers beginning in December 2015, and established an earnings sharing mechanism whereby Yankee Gas and its customers will share equally in any earnings exceeding a 9.5 percent ROE in a twelve month period commencing with the period from April 1, 2015 through March 31, 2016.
Massachusetts Natural Gas Replacement and Expansion
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.
In October 2014, pursuant to the Act, NSTAR Gas filed the Gas System Enhancement Program (GSEP) with the DPU. NSTAR Gas' program accelerates the replacement of certain natural gas distribution facilities in the system to within 25 years. The GSEP includes a new tariff effective January 1, 2016 that provides NSTAR Gas an opportunity to collect the costs for the program on an annual basis through a newly designed
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reconciling factor. On April 30, 2015, the DPU approved the GSEP. We expect capital expenditures of approximately $255 million for the period 2016 through 2019 for the GSEP.
Connecticut Natural Gas Expansion Plan
In 2013, in accordance with Connecticut law and regulations, the PURA approved a comprehensive joint natural gas infrastructure expansion plan (expansion plan) filed by Yankee Gas and other Connecticut natural gas distribution companies. The expansion plan described how Yankee Gas expects to add approximately 82,000 new natural gas heating customers over a 10-year period. Yankee Gas estimates that its portion of the plan will cost approximately $700 million over 10 years. In January 2015, the PURA approved a joint settlement agreement proposed by Yankee Gas and other Connecticut natural gas distribution companies and regulatory agencies that clarified the procedures and oversight criteria applicable to the expansion plan. On March 20, 2015, Yankee Gas filed its initial System Expansion (SE) Rate reconciliation for 2014. The proposed SE rate was approved by the PURA for implementation as of April 1, 2015, pending final PURA approval following a contested hearing.
Sources and Availability of Natural Gas Supply
NSTAR Gas maintains a flexible resource portfolio consisting of natural gas supply contracts, transportation contracts on interstate pipelines, market area storage and peaking services. NSTAR Gas purchases transportation, storage, and balancing services from Tennessee Gas Pipeline Company and Algonquin Gas Transmission Company, as well as other upstream pipelines that transport gas from major producing regions in the U.S., including the Gulf Coast, Mid-continent region, and Appalachian Shale supplies to the final delivery points in the NSTAR Gas service area. NSTAR Gas purchases all of its natural gas supply under a firm portfolio management contract with a term of one year, which has a maximum quantity of approximately 154,700 MMBtu/day of firm flowing natural gas supplies and 76,700 MMBtu/day of firm natural gas storage supplies.
In addition to the firm transportation and natural gas supplies mentioned above, NSTAR Gas utilizes contracts for underground storage and LNG facilities to meet its winter peaking demands. The LNG facilities, described below, are located within NSTAR Gas' distribution system and are used to liquefy and store pipeline natural gas during the warmer months for vaporization and use during the heating season. During the summer injection season, excess pipeline capacity and supplies are used to deliver and store natural gas in market area underground storage facilities located in the New York and Pennsylvania regions. Stored natural gas is withdrawn during the winter season to supplement flowing pipeline supplies in order to meet firm heating demand. NSTAR Gas has firm underground storage contracts and total storage capacity entitlements of approximately 6.6 Bcf.
A portion of the storage of natural gas supply for NSTAR Gas during the winter heating season is provided by Hopkinton LNG Corp., which owns an LNG liquefaction and vaporization plant and three above-ground cryogenic storage tanks having an aggregate capacity of 3.0 Bcf of liquefied natural gas. NSTAR Gas also has access to Hopkinton LNG Corp. facilities that include additional storage capacity of 0.5 Bcf and additional vaporization capacity.
The PURA requires that Yankee Gas meet the needs of its firm customers under all weather conditions. Specifically, Yankee Gas must structure its supply portfolio to meet firm customer needs under a design day scenario (defined as the coldest day in 30 years) and under a design year scenario (defined as the average of the four coldest years in the last 30 years). Yankee Gas' on-system stored LNG and underground storage supplies help to meet consumption needs during the coldest days of winter. Yankee Gas obtains its interstate capacity from the three interstate pipelines that directly serve Connecticut: the Algonquin, Tennessee and Iroquois Pipelines. Yankee Gas has long-term firm contracts for capacity on TransCanada Pipelines Limited Pipeline, Vector Pipeline, L.P., Tennessee Gas Pipeline, Iroquois Gas Transmission Pipeline, Algonquin Pipeline, Union Gas Limited, Dominion Transmission, Inc., National Fuel Gas Supply Corporation, Transcontinental Gas Pipeline Company, and Texas Eastern Transmission, L.P. pipelines.
Based on information currently available regarding projected growth in demand and estimates of availability of future supplies of pipeline natural gas, NSTAR Gas and Yankee Gas each believes that participation in planned and anticipated pipeline and storage expansion projects will be required in order for it to meet current and future sales growth opportunities.
NATURAL GAS PIPELINE EXPANSION
Access Northeast is a natural gas pipeline and storage project (the "Project") being developed jointly by Eversource, Spectra Energy Corp and National Grid. Access Northeast will enhance the Algonquin and Maritimes & Northeast pipeline systems using existing routes and will include two new LNG storage tanks and liquefaction and vaporization facilities in Acushnet, Massachusetts that will be connected to the Algonquin gas pipeline. The Project is expected to be capable of delivering approximately 900 million cubic feet of additional natural gas per day to New England on peak demand days. Eversource and Spectra Energy Corp each own a 40 percent interest in the Project, with the remaining 20 percent interest owned by National Grid. The total projected cost for both the pipeline and the LNG storage is expected to be approximately $3 billion with anticipated in-service dates commencing in November 2018. The Project is subject to FERC and other federal and state regulatory approvals. On November 17, 2015, the FERC accepted the Project’s request to initiate the pre-filing review process. Upon completion of the pre-filing review, a certificate application will be filed with the FERC. In late 2015, the Project bid into the New England Natural Gas Pipeline Capacity RFP conducted by certain EDCs in Massachusetts and Rhode Island, including NSTAR Electric and WMECO in Massachusetts, and in December 2015 and January 2016, those Massachusetts EDCs filed with the DPU seeking approval of the contracts for pipeline and storage capacity with the Project. We expect the Rhode Island EDC to file its selected contracts with the Rhode Island regulatory agencies in the first half of 2016. In February 2016, PSNH filed for approval with the NHPUC, of its proposed contract for natural gas pipeline capacity and storage with the Project.
PROJECTED CAPITAL EXPENDITURES
We project to make capital expenditures of approximately $9.2 billion from 2016 through 2019. Of the $9.2 billion, we expect to invest approximately $4.9 billion in our electric and natural gas distribution segments and $3.9 billion in our electric transmission segment. In addition, we
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project to invest approximately $0.4 billion in information technology and facilities upgrades and enhancements. These projections do not include capital expenditures related to Access Northeast or Clean Energy Connect.
FINANCING
Our credit facilities and indentures require that Eversource Energy parent and certain of its subsidiaries, including CL&P, NSTAR Electric, NSTAR Gas, PSNH, WMECO and Yankee Gas, comply with certain financial and non-financial covenants as are customarily included in such agreements, including maintaining a ratio of consolidated debt to total capitalization of no more than 65 percent. All of these companies currently are, and expect to remain, in compliance with these covenants.
As of December 31, 2015, a total of $200 million of Eversource’s long-term debt, all at NSTAR Electric, will be paid in the next 12 months.
NUCLEAR FUEL STORAGE
CL&P, NSTAR Electric, PSNH, WMECO and several other New England electric utilities are stockholders in three inactive regional nuclear generation companies, CYAPC, MYAPC and YAEC (collectively, the Yankee Companies). The Yankee Companies have completed the physical decommissioning of their respective generation facilities and are now engaged in the long-term storage of their spent nuclear fuel. The Yankee Companies have completed collection of their decommissioning and closure costs through the proceeds from the spent nuclear fuel litigation against the DOE and has refunded amounts to its member companies. These proceeds were used by the Yankee Companies to offset the decommissioning and closure cost amounts due from their member companies or to decrease the wholesale FERC-approved rates charged under power purchase agreements with CL&P, NSTAR Electric, PSNH and WMECO and several other New England utilities. The decommissioning rates charged by the Yankee Companies have been reduced to zero. CL&P, NSTAR Electric, PSNH and WMECO can recover these costs from, or refund proceeds to, their customers through state regulatory commission-approved retail rates.
We consolidate the assets and obligations of CYAPC and YAEC on our consolidated balance sheet because we own more than 50 percent of these companies.
For information on the DOE proceeds received related to the spent nuclear fuel litigation, see Note 11C, "Commitments and Contingencies – Contractual Obligations – Yankee Companies," in the accompanying Item 8,Financial Statements and Supplementary Data.
OTHER REGULATORY AND ENVIRONMENTAL MATTERS
General
We are regulated in virtually all aspects of our business by various federal and state agencies, including FERC, the SEC, and various state and/or local regulatory authorities with jurisdiction over the industry and the service areas in which each of our companies operates, including the PURA, which has jurisdiction over CL&P and Yankee Gas, the NHPUC, which has jurisdiction over PSNH, and the DPU, which has jurisdiction over NSTAR Electric, NSTAR Gas and WMECO.
Environmental Regulation
We are subject to various federal, state and local requirements with respect to water quality, air quality, toxic substances, hazardous waste and other environmental matters. Additionally, major generation and transmission facilities may not be constructed or significantly modified without a review of the environmental impact of the proposed construction or modification by the applicable federal or state agencies.
Water Quality Requirements
The Clean Water Act requires every "point source" discharger of pollutants into navigable waters to obtain a National Pollutant Discharge Elimination System (NPDES) permit from the EPA or state environmental agency specifying the allowable quantity and characteristics of its effluent. States may also require additional permits for discharges into state waters. We are in the process of maintaining or renewing all required NPDES or state discharge permits in effect for PSNH's generation facilities.
In 1997, PSNH filed in a timely manner for a renewal of the NPDES permit for the Merrimack Station. As a result, the existing permit was administratively continued. In 2011, the EPA issued a draft renewal NPDES permit for PSNH's Merrimack Station for public review and comment. The proposed permit contains many significant conditions to future operation. The proposed permit would require PSNH to install a closed-cycle cooling system (including cooling towers) at the station. The EPA estimated that the net present value cost to install this system and operate it over a 20-year period would be approximately $112 million. PSNH and other electric utility groups filed thousands of pages of comments contesting EPA's draft permit requirements. PSNH stated that the data and studies supplied to the EPA demonstrate the fact that a closed-cycle cooling system is not warranted. On April 18, 2015 EPA issued a revised section of the draft NPDES permit for Merrimack Station. The revised portion of the draft permit deals solely with the treatment of wastewater from the flue gas desulfurization system. On August 18, 2015 PSNH again submitted comments. The EPA does not have a set deadline to consider comments and to issue a final permit. Merrimack Station is permitted to continue to operate under its present permit pending issuance of the final permit and subsequent resolution of matters appealed by PSNH and other parties. Due to the site specific characteristics of PSNH's other coal- and oil-fired electric generating stations, we believe it is unlikely that they would face similar permitting determinations.
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Air Quality Requirements
The Clean Air Act Amendments (CAAA), as well as New Hampshire law, impose stringent requirements on emissions of SO2 and NOX for the purpose of controlling acid rain and ground level ozone. In addition, the CAAA address the control of toxic air pollutants. Requirements for the installation of continuous emissions monitors and expanded permitting provisions also are included.
In 2011, the EPA finalized the Mercury and Air Toxic Standards (MATS) that require the reduction of emissions of hazardous air pollutants from new and existing coal- and oil-fired electric generating stations. Previously referred to as the Utility MACT (maximum achievable control technology) rules, it establishes emission limits for mercury, arsenic and other hazardous air pollutants from coal- and oil-fired electric generating stations. MATS is the first implementation of a nationwide emissions standard for hazardous air pollutants across all electric generating units and provides utility companies with up to five years to meet the requirements. PSNH owns and operates approximately 1,000 MW of coal- and oil-fired electric generating stations subject to MATS, including the two units at Merrimack Station, Newington Station and the two coal units at Schiller Station. We believe the Clean Air Project at our Merrimack Station, together with existing equipment, will enable the facility to meet the MATS requirements. At Schiller Station additional controls are being installed at the two coal-fired units, the cost of which is estimated to be approximately $2.5 million.
Each of the states in which we do business also has Renewable Portfolio Standards (RPS) requirements, which generally require fixed percentages of our energy supply to come from renewable energy sources such as solar, hydropower, landfill gas, fuel cells and other similar sources.
New Hampshire's RPS provision requires increasing percentages of the electricity sold to retail customers to have direct ties to renewable sources. In 2015, the total RPS obligation was 8.3 percent and it will ultimately reach 24.8 percent in 2025. Energy suppliers, like PSNH, must possess sufficient quantities of RECs to satisfy the RPS requirements. PSNH owns renewable sources and uses a portion of internally generated RECs to meet its RPS obligations and sells other internally generated RECs when it is economically beneficial to do so. To the extent that a supplier, like PSNH, does not possess sufficient RECs to satisfy its RPS requirements, it makes up any shortfall by making an alternative compliance payment at a rate per REC established by law. The costs of both the RECs and alternative compliance payments are recovered by PSNH through its default energy service rates charged to customers.
Similarly, Connecticut's RPS statute requires increasing percentages of the electricity sold to retail customers to have direct ties to renewable sources. In 2015, the total RPS obligation was 19.5 percentand will ultimately reach 27 percent in 2020. CL&P is permitted to recover any costs incurred in complying with RPS from its customers through its GSCrate.
Massachusetts' RPS program also requires electricity suppliers to meet renewable energy standards. For 2015, the requirement was 19.25 percent, and will ultimately reach 22.1 percent in 2020. NSTAR Electric and WMECO are permitted to recover any costs incurred in complying with RPS from its customers through rates. WMECO also owns renewable solar generation resources. The RECs generated from WMECO's solar units are sold to other energy suppliers, and the proceeds from these sales are credited back to customers.
Hazardous Materials Regulations
We have recorded a liability for what we believe, based upon currently available information, is our reasonably estimable environmental investigation, remediation, and/or Natural Resource Damages costs for waste disposal sites for which we have probable liability. Under federal and state law, government agencies and private parties can attempt to impose liability on us for recovery of investigation and remediation costs at hazardous waste sites. As of December 31, 2015, the liability recorded for our reasonably estimable and probable environmental remediation costs for known sites needing investigation and/or remediation, exclusive of recoveries from insurance or from third parties, was approximately $51.1 million, representing 64 sites. These costs could be significantly higher if additional remediation becomes necessary or when additional information as to the extent of contamination becomes available.
The most significant liabilities currently relate to future clean-up costs at former MGP facilities. These facilities were owned and operated by our predecessor companies from the mid-1800's to mid-1900's. By-products from the manufacture of gas using coal resulted in fuel oils, hydrocarbons, coal tar, purifier wastes, metals and other waste products that may pose risks to human health and the environment. We currently have partial or full ownership responsibilities at former MGP sites that have a reserve balance of $45.5 million of the total $51.1 million as of December 31, 2015. Many of these MGP costs are recoverable from customers through our rates.
Electric and Magnetic Fields
For more than twenty years, published reports have discussed the possibility of adverse health effects from electric and magnetic fields (EMF) associated with electric transmission and distribution facilities and appliances and wiring in buildings and homes. Although weak health risk associations reported in some epidemiology studies remain unexplained, most researchers, as well as numerous scientific review panels, considering all significant EMF epidemiology and laboratory studies, have concluded that the available body of scientific information does not support the conclusion that EMF affects human health.
In accordance with recommendations of various regulatory bodies and public health organizations, we reduce EMF associated with new transmission lines by the use of designs that can be implemented without additional cost or at a modest cost. We do not believe that other capital expenditures are appropriate to minimize unsubstantiated risks.
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Global Climate Change and Greenhouse Gas Emission Issues
Global climate change and greenhouse gas emission issues have received an increased focus from state governments and the federal government. The EPA initiated a rulemaking addressing greenhouse gas emissions and, on December 7, 2009, issued a finding that concluded that greenhouse gas emissions are "air pollution" that endangers public health and welfare and should be regulated. The largest source of greenhouse gas emissions in the U.S. is the electricity generating sector. The EPA has mandated greenhouse gas emission reporting beginning in 2011 for emissions for certain aspects of our business including stationary combustion, volume of gas supplied to large customers and fugitive emissions of SF6 gas and methane.
We are continually evaluating the regulatory risks and regulatory uncertainty presented by climate change concerns. Such concerns could potentially lead to additional rules and regulations that impact how we operate our business, both in terms of the generating facilities we own and operate as well as general utility operations. These could include federal "cap and trade" laws, carbon taxes, fuel and energy taxes, or regulations requiring additional capital expenditures at our generating facilities. We expect that any costs of these rules and regulations would be recovered from customers.
Connecticut, New Hampshire and Massachusetts are each members of the Regional Greenhouse Gas Initiative (RGGI), a cooperative effort by nine northeastern and mid-Atlantic states, to develop a regional program for stabilizing and reducing CO2 emissions from coal- and oil-fired electric generating plants. Because CO2 allowances issued by any participating state are usable across all nine RGGI state programs, the individual state CO2 trading programs, in the aggregate, form one regional compliance market for CO2 emissions. The third three-year control period took effect on January 1, 2015 and extends through December 31, 2017. In this control period, each regulated power plant must hold CO2 allowances equal to 50 percent of its emissions during each of the first two years of the three-year period, and hold CO2 allowances equal to 100 percent of its remaining emissions for the three-year control period at the end of the period.
PSNH anticipates that its generating units will emit between one million and three million tons of CO2 per year, depending on the capacity factor and the utilization of the respective generation plant, excluding emissions from the operation of PSNH's Northern Wood Power Project, which emissions are an offset. PSNH satisfied its RGGI requirements by purchasing CO2 allowances at auction. The cost of complying with RGGI requirements is recoverable from PSNH customers. Current legislation provides that the portion of the RGGI auction proceeds in excess of $1 per allowance will be refunded to customers.
Because none of Eversource Energy's other subsidiaries, CL&P, NSTAR Electric or WMECO, currently owns any generating assets (other than WMECO's solar photovoltaic facilities that do not emit CO2), none of them is required to acquire CO2 allowances. However, the CO2 allowance costs borne by the generating facilities that are utilized by wholesale energy suppliers to satisfy energy supply requirements to CL&P, NSTAR Electric and WMECO are likely to be included in the overall wholesale rates charged, which costs are then recoverable from customers.
FERC Hydroelectric Project Licensing
Federal Power Act licenses may be issued for hydroelectric projects for terms of 30 to 50 years as determined by the FERC. Upon the expiration of an existing license, (i) the FERC may issue a new license to the existing licensee, (ii) the United States may take over the project, or (iii) the FERC may issue a new license to a new licensee, upon payment to the existing licensee of the lesser of the fair value or the net investment in the project, plus severance damages, less certain amounts earned by the licensee in excess of a reasonable rate of return.
PSNH currently owns nine hydroelectric generating stations with a current claimed capability representing winter rates of approximately 71 MW, eight of which are licensed by the FERC under long-term licenses that expire on varying dates from 2017 through 2047. PSNH and its hydroelectric projects are subject to conditions set forth in such licenses, the Federal Power Act and related FERC regulations, including provisions related to the condemnation of a project upon payment of just compensation, amortization of project investment from excess project earnings, possible takeover of a project after expiration of its license upon payment of net investment and severance damages and other matters. PSNH is currently completing the relicensing application for its 6.5 MW Eastman Falls Hydro Station, the license for which expires in 2017.
EMPLOYEES
As of December 31, 2015, Eversource Energy employed a total of 7,943 employees, excluding temporary employees, of which 1,037 were employed by CL&P, 1,240 were employed by NSTAR Electric, 694 were employed by PSNH, and 291 were employed by WMECO. Approximately 50 percent of our employees are members of the International Brotherhood of Electrical Workers, the Utility Workers Union of America or The United Steelworkers, and are covered by 14 collective bargaining agreements.
INTERNET INFORMATION
Our website address is www.eversource.com. We make available through our website a link to the SEC's EDGAR website (http://www.sec.gov/edgar/searchedgar/companysearch.html), at which site Eversource Energy's, CL&P's, NSTAR Electric's, PSNH's and WMECO's Annual Reports on Form 10-K, Quarterly Reports on Form 10-Q, Current Reports on Form 8-K and any amendments to those reports may be reviewed. Information contained on the Company's website or that can be accessed through the website is not incorporated into and does not constitute a part of this Annual Report on Form 10-K. Printed copies of these reports may be obtained free of charge by writing to our Investor Relations Department at Eversource Energy, 107 Selden Street, Berlin, CT 06037.
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Item 1A.
Risk Factors
In addition to the matters set forth under "Safe Harbor Statement Under the Private Securities Litigation Reform Act of 1995" included immediately prior to Item 1,Business, above, we are subject to a variety of significant risks. Our susceptibility to certain risks, including those discussed in detail below, could exacerbate other risks. These risk factors should be considered carefully in evaluating our risk profile.
Cyber breaches, acts of war or terrorism, or grid disturbances could negatively impact our business.
Cyber breaches, acts of war or terrorism, physical attacks or grid disturbances resulting from internal or external sources could target our transmission, distribution and generation facilities or our information technology systems. Such actions could impair our ability to manage these facilities, operate our systems effectively, or properly manage our data, networks and programs, resulting in loss of service to customers.
We have instituted safeguards to protect our operational systems and information technology assets. We devote substantial resources to network and application security, encryption and other measures to protect our computer systems and infrastructure from unauthorized access or misuse and interface with numerous external entities to improve our cybersecurity situational awareness. FERC, through the North American Electric Reliability Corporation, requires certain safeguards to be implemented to deter cyber and/or physical attacks. These safeguards may not always be effective due to the evolving nature of cyber and/or physical attacks.
Because our generation and transmission facilities are part of an interconnected regional grid, we face the risk of blackout due to a disruption on a neighboring interconnected system.
Any such cyber breaches, acts of war or terrorism, physical attacks or grid disturbances could result in a significant decrease in revenues, significant expense to repair system damage or security breaches, and liability claims, which could have a material adverse impact on our financial position, results of operations or cash flows.
Strategic development opportunities in both electric and natural gas transmission may not be successful and projects may not commence operation as scheduled or be completed, which could have a material adverse effect on our business prospects.
We are pursuing broader strategic development investment opportunities that will benefit the New England region related to the construction of electric and natural gas transmission facilities, interconnections to generating resources and other investment opportunities. The development, construction and expansion of electric transmission and natural gas transmission facilities involve numerous risks. Various factors could result in increased costs or result in delays or cancellation of these projects. Risks include regulatory approval processes, new legislation, economic events or factors, environmental and community concerns, design and siting issues, difficulties in obtaining required rights of way, competition from incumbent utilities and other entities, and actions of strategic partners. Should any of these factors result in such delays or cancellations, our financial position, results of operations, and cash flows could be adversely affected or our future growth opportunities may not be realized as anticipated.
As a result of legislative and regulatory changes during 2015, the states in which we provide service have implemented new procedures to select for construction new major electric transmission and gas pipeline facilities. These procedures require the review of competing projects and permit the selection of only those projects that are expected to provide the greatest benefit to customers. If the projects in which we have invested are not selected for construction, it would have a material adverse effect on our future financial position, results of operations and cash flows.
The actions of regulators and legislators can significantly affect our earnings, liquidity and business activities.
The rates that our electric and gas companies charge their customers are determined by their state regulatory commissions and by FERC. These commissions also regulate the companies' accounting, operations, the issuance of certain securities and certain other matters. FERC also regulates the transmission of electric energy, the sale of electric energy at wholesale, accounting, issuance of certain securities and certain other matters.
Under state and federal law, our electric and gas companies are entitled to charge rates that are sufficient to allow them an opportunity to recover their reasonable operating and capital costs, to attract needed capital and maintain their financial integrity, while also protecting relevant public interests. Each of these companies prepares and submits periodic rate filings with their respective regulatory commissions for review and approval.
The FERC has jurisdiction over our transmission costs recovery and the allowed return on equity. The ROE has been contested by outside parties as unjust and unreasonable. Certain outside parties have filed three complaints against all electric companies under the jurisdiction of ISO-NE alleging that the ROE is unjust and unreasonable. The first complaint, which was concluded in 2015, resulted in a decrease of the allowed ROE. The second and third complaints are currently under review with the FERC. The FERC has initiated a review of the regional and local transmission rates due to a lack of adequate transparency. FERC also found that the formula rates generally lacked sufficient details to determine how costs are derived and recovered in rates.
A federal appeals court decision has upheld the FERC's authority to order major changes to transmission planning and cost allocation in FERC Order No. 1000 and Order No. 1000-A, including transmission planning for public policy needs, and the requirement that utilities remove from their transmission tariffs their rights of first refusal to build transmission. Additionally, the FERC affirmed that it can eliminate our right of first refusal to build transmission in New England even though the FERC previously approved and granted special protections to these rights. Implementation of FERC's goals in New England, including within our service territories, may expose us to competition for construction of transmission projects, additional regulatory considerations, and potential delay with respect to future transmission projects, which may adversely affect our results of operation.
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There is no assurance that the commissions will approve the recovery of all costs incurred by our electric and gas companies, including costs for construction, operation and maintenance, as well as a reasonable return on their respective regulated assets. The amount of costs incurred by the companies, coupled with increases in fuel and energy prices, could lead to consumer or regulatory resistance to the timely recovery of such costs, thereby adversely affecting our financial position, results of operations or cash flows.
If our settlement agreement regarding the divestiture of our generation assets in New Hampshire is not approved, it could have a material adverse effect on our earnings.
Under our settlement agreement for the divestiture of our generation assets in New Hampshire, we will be entitled to collect from customers an amount equal to the difference between the proceeds from the sale of these assets and the undepreciated book value of those assets. Costs related to the divestiture would also be recoverable. To minimize the financial impact on customers in New Hampshire, the legislature passed legislation that allows for the securitization of stranded costs to be recovered. If the NHPUC does not approve the settlement, we may not be able to fully recover these costs in future rate proceedings, which could have a material adverse effect on our financial position, results of operations and cash flows.
Our transmission, distribution and generation systems may not operate as expected, and could require unplanned expenditures, which could adversely affect our financial position, results of operations and cash flows.
Our ability to properly operate our transmission, distribution and generation systems is critical to the financial performance of our business. Our transmission, distribution and generation businesses face several operational risks, including the breakdown, failure of, or damage to operating equipment, information technology systems, or processes, especially due to age; labor disputes; disruptions in the delivery of electricity and natural gas, including impacts on us or our customers; increased capital expenditure requirements, including those due to environmental regulation; catastrophic events such as fires, explosions, or other similar occurrences; extreme weather conditions beyond equipment and plant design capacity; other unanticipated operations and maintenance expenses and liabilities; and potential claims for property damage or personal injuries beyond the scope of our insurance coverage. Many of our transmission projects are expected to alleviate identified reliability issues and reduce customers' costs. However, if the in-service date for one or more of these projects is delayed due to economic events or factors, or regulatory or other delays, the risk of failures in the electricity transmission system may increase. Any failure of our transmission, distribution and generation systems to operate as planned may result in increased capital costs, reduced earnings or unplanned increases in operation and maintenance costs. Outages at generating stations may be deemed imprudent by the NHPUC resulting in disallowance of replacement power and repair costs. Such costs that are not recoverable from our customers would have an adverse effect on our financial position, results of operations and cash flows.
Increases in electric and gas prices and/or a weak economy can lead to changes in legislative and regulatory policy promoting increased energy efficiency, conservation, and self-generation and/or a reduction in our customers' ability to pay their bills, which may adversely impact our business.
Energy consumption is significantly impacted by the general level of economic activity and cost of energy supply. Economic downturns or periods of high energy supply costs typically can lead to the development of legislative and regulatory policy designed to promote reductions in energy consumption and increased energy efficiency and self-generation by customers. This focus on conservation, energy efficiency and self-generation may result in a decline in electricity and natural gas sales in our service territories. Economic downturns or periods of high energy supply costs can also impact customers’ ability to pay their energy bills, resulting in increased bad debt expense. If energy use were to decline or bad debt expense were to increase, without corresponding adjustments in rates at our electric and gas companies that do not currently have revenue decoupling, then our revenues would be reduced, which would have an adverse effect on our financial position, results of operations and cash flows.
Severe storms could cause significant damage to any of our facilities requiring extensive expenditures, the recovery for which is subject to approval by regulators.
Severe weather, such as ice and snow storms, hurricanes and other natural disasters, may cause outages and property damage, which may require us to incur additional costs that may not be recoverable from customers. The cost of repairing damage to our operating subsidiaries' facilities and the potential disruption of their operations due to storms, natural disasters or other catastrophic events could be substantial, particularly as regulators and customers demand better and quicker response times to outages. If, upon review, any of our state regulatory authorities finds that our actions were imprudent, some of those restoration costs may not be recoverable from customers. The inability to recover a significant amount of such costs could have an adverse effect on our financial position, results of operations and cash flows.
Our goodwill is valued and recorded at an amount that, if impaired and written down, could adversely affect our future operating results and total capitalization.
We have a significant amount of goodwill on our consolidated balance sheet. As of December 31, 2015, goodwill totaled $3.5 billion. The carrying value of goodwill represents the fair value of an acquired business in excess of identifiable assets and liabilities as of the acquisition date. We test our goodwill balances for impairment on an annual basis or whenever events occur or circumstances change that would indicate a potential for impairment. A determination that goodwill is deemed to be impaired would result in a non-cash charge that could materially adversely affect our financial position, results of operations and total capitalization. The annual goodwill impairment test in 2015 resulted in a conclusion that our goodwill is not impaired.
Eversource Energy and its utility subsidiaries are exposed to significant reputational risks, which make them vulnerable to increased regulatory oversight or other sanctions.
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Because utility companies, including our electric and natural gas utility subsidiaries, have large customer bases, they are subject to adverse publicity focused on the reliability of their distribution services and the speed with which they are able to respond to electric outages, natural gas leaks and similar interruptions caused by storm damage or other unanticipated events. Adverse publicity of this nature could harm the reputations of Eversource Energy and its subsidiaries; may make state legislatures, utility commissions and other regulatory authorities less likely to view Eversource Energy and its subsidiaries in a favorable light; and may cause Eversource Energy and its subsidiaries to be subject to less favorable legislative and regulatory outcomes or increased regulatory oversight. Unfavorable regulatory outcomes can include more stringent laws and regulations governing our operations, such as reliability and customer service quality standards or vegetation management requirements, as well as fines, penalties or other sanctions or requirements. The imposition of any of the foregoing could have a material adverse effect on the business, results of operations, cash flow and financial condition of Eversource Energy and each of its utility subsidiaries.
Limits on our access to and increases in the cost of capital may adversely impact our ability to execute our business plan.
We use short-term debt and the long-term capital markets as a significant source of liquidity and funding for capital requirements not obtained from our operating cash flow. If access to these sources of liquidity becomes constrained, our ability to implement our business strategy could be adversely affected. In addition, higher interest rates would increase our cost of borrowing, which could adversely impact our results of operations. A downgrade of our credit ratings or events beyond our control, such as a disruption in global capital and credit markets, could increase our cost of borrowing and cost of capital or restrict our ability to access the capital markets and negatively affect our ability to maintain and to expand our businesses.
Our counterparties may not meet their obligations to us or may elect to exercise their termination rights, which could adversely affect our earnings.
We are exposed to the risk that counterparties to various arrangements who owe us money, have contracted to supply us with energy, coal, or other commodities or services, or who work with us as strategic partners, including on significant capital projects, will not be able to perform their obligations, will terminate such arrangements or, with respect to our credit facilities, fail to honor their commitments. Should any of these counterparties fail to perform their obligations or terminate such arrangements, we might be forced to replace the underlying commitment at higher market prices and/or have to delay the completion of, or cancel a capital project. Should any lenders under our credit facilities fail to perform, the level of borrowing capacity under those arrangements could decrease. In any such events, our financial position, results of operations, or cash flows could be adversely affected.
The unauthorized access to and the misappropriation of confidential and proprietary customer, employee, financial or system operating information could adversely affect our business operations and adversely impact our reputation.
In the regular course of business we maintain sensitive customer, employee, financial and system operating information and are required by various federal and state laws to safeguard this information. Cyber intrusions, security breaches, theft or loss of this information by cyber crime or otherwise could lead to the release of critical operating information or confidential customer or employee information, which could adversely affect our business operations or adversely impact our reputation, and could result in significant costs, fines and litigation. We maintain limited privacy protection liability insurance to cover limited damages and defense costs arising from unauthorized disclosure of, or failure to protect, private information as well as costs for notification to, or for credit card monitoring of, customers, employees and other persons in the event of a breach of private information. This insurance covers amounts paid to avert, prevent or stop a network attack or the disclosure of personal information, and costs of a qualified forensics firm to determine the cause, source and extent of a network attack or to investigate, examine and analyze our network to find the cause, source and extent of a data breach. While we have implemented measures designed to prevent cyber-attacks and mitigate their effects should they occur. These measures may not be effective due to the continually evolving nature of efforts to access confidential information.
The loss of key personnel or the inability to hire and retain qualified employees could have an adverse effect on our business, financial position and results of operations.
Our operations depend on the continued efforts of our employees. Retaining key employees and maintaining the ability to attract new employees are important to both our operational and financial performance. We cannot guarantee that any member of our management or any key employee at the Eversource parent or subsidiary level will continue to serve in any capacity for any particular period of time. In addition, a significant portion of our workforce, including many workers with specialized skills maintaining and servicing the electrical infrastructure, will be eligible to retire over the next five to ten years. Such highly skilled individuals cannot be quickly replaced due to the technically complex work they perform. We have developed strategic workforce plans to identify key functions and proactively implement plans to assure a ready and qualified workforce, but cannot predict the impact of these plans on our ability to hire and retain key employees.
Market performance or changes in assumptions require us to make significant contributions to our pension and other postretirement benefit plans.
We provide a defined benefit pension plan and other postretirement benefits for a substantial number of employees, former employees and retirees. Our future pension obligations, costs and liabilities are highly dependent on a variety of factors beyond our control. These factors include estimated investment returns, interest rates, discount rates, health care cost trends, benefit changes, salary increases and the demographics of plan participants. If our assumptions prove to be inaccurate, our future costs could increase significantly.In addition, various factors, including underperformance of plan investments and changes in law or regulation, could increase the amount of contributions required to fund our pension plan in the future. Additional large funding requirements, when combined with the financing requirements of our construction program, could impact the timing and amount of future financings and negatively affect our financial position, results of operations or cash flows. For further information, see Note 9A, "Employee Benefits - Pensions and Postretirement Benefits Other Than Pensions," to the financial statements.
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Costs of compliance with environmental regulations, including climate change legislation, may increase and have an adverse effect on our business and results of operations.
Our subsidiaries' operations are subject to extensive federal, state and local environmental statutes, rules and regulations that govern, among other things, air emissions, water discharges and the management of hazardous and solid waste. Compliance with these requirements requires us to incur significant costs relating to environmental monitoring, maintenance and upgrading of facilities, remediation and permitting. The costs of compliance with existing legal requirements or legal requirements not yet adopted may increase in the future. An increase in such costs, unless promptly recovered, could have an adverse impact on our business and our financial position, results of operations or cash flows.
In addition, global climate change issues have received an increased focus from federal and state government agencies . Although we would expect that any costs of these rules and regulations would be recovered from customers, their impact on energy use by customers and the ultimate impact on our business would be dependent upon the specific rules and regulations adopted and cannot be determined at this time. The impact of these additional costs to customers could lead to a further reduction in energy consumption resulting in a decline in electricity and gas sales in our service territories, which would have an adverse impact on our business and financial position, results of operations or cash flows. Any failure by us to comply with environmental laws and regulations, even if due to factors beyond our control, or reinterpretations of existing requirements, could also increase costs. Existing environmental laws and regulations may be revised or new laws and regulations seeking to protect the environment may be adopted or become applicable to us. Revised or additional laws could result in significant additional expense and operating restrictions on our facilities or increased compliance costs, which may not be fully recoverable in distribution company rates. The cost impact of any such laws, rules or regulations would be dependent upon the specific requirements adopted and cannot be determined at this time. For further information, see Item 1, Business -Other Regulatory and Environmental Matters, included in this Annual Report on Form 10-K.
As a holding company with no revenue-generating operations, Eversource parent's liquidity is dependent on dividends from its subsidiaries, its commercial paper program, and its ability to access the long-term debt and equity capital markets.
Eversource parent is a holding company and as such, has no revenue-generating operations of its own. Its ability to meet its debt service obligations and to pay dividends on its common shares is largely dependent on the ability of its subsidiaries to pay dividends to or repay borrowings from Eversource parent, and/or Eversource parent's ability to access its commercial paper program or the long-term debt and equity capital markets. Prior to funding Eversource parent, the subsidiary companies have financial obligations that must be satisfied, including among others, their operating expenses, debt service, preferred dividends of certain subsidiaries, and obligations to trade creditors. Additionally, the subsidiary companies could retain their free cash flow to fund their capital expenditures in lieu of receiving equity contributions from Eversource parent. Should the subsidiary companies not be able to pay dividends or repay funds due to Eversource parent, or if Eversource parent cannot access its commercial paper programs or the long-term debt and equity capital markets, Eversource parent's ability to pay interest, dividends and its own debt obligations would be restricted.
Item 1B.
Unresolved Staff Comments
We do not have any unresolved SEC staff comments.
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DOE Phase II Damages - In December 2007, the Yankee Companies each filed subsequent lawsuits against the DOE seeking recovery of actual damages incurred in the years following 2001 and 2002 related to the alleged failure of the DOE to provide for a permanent facility to store spent nuclear fuel generated in years after 2001 for CYAPC and YAEC and after 2002 for MYAPC (DOE Phase II Damages). On November 18, 2011, the court ordered the record closed in the YAEC case, and closed the record in the CYAPC and MYAPC cases subject to a limited opportunity of the government to reopen the records for further limited proceedings.
On November 15, 2013, the court issued a final judgment awarding CYAPC $126.3 million, YAEC $73.3 million, and MYAPC $35.8 million. On January 14, 2014, the Yankee Companies received a letter from the U.S. Department of Justice stating that the DOE will not appeal the court's final judgment. As of December 31, 2013, CL&P, NSTAR Electric, PSNH, WMECO, CYAPC, and YAEC have not reflected the impact of these expected receivables on their financial statements.
The methodology for applying the DOE Phase II Damages recovered from the DOE for the benefit of customers of CL&P, NSTAR Electric, PSNH and WMECO will be addressed in FERC rate proceedings.
DOE Phase III Damages – On August 15, 2013, the Yankee Companies each filed subsequent lawsuits against the DOE seeking recovery of actual damages incurred in the years 2009 through 2012. Responsive pleading from the Department of Justice was filed on November 18, 2013, and discovery is expected to begin once a protective order is in place.
Item 2. Conservation Law Foundation v. PSNHProperties
On July 21, 2011, the Conservation Law Foundation (CLF) filed a citizens suit under the provisions of the federal Clean Air Act against PSNH alleging permitting violations at the company’s Merrimack generating station. The suit alleges that PSNH failed to have proper permits for replacement of the Unit 2 turbine at Merrimack, installation of activated carbon injection equipment for the unit, and violated a permit condition concerning operation of the electrostatic precipitators at the station. The suit seeks injunctive relief, civil penalties, and costs. CLF has pursued similar claims before the NHPUC, the N.H. Air Resources Council, and the N.H. Site Evaluation Committee, all of which have been denied. PSNH believes this suit is without merit and intends to defend it vigorously. On September 27, 2012, the federal court dismissed portions of CLF’s suit pertaining to the installation of activated carbon injection and the electrostatic precipitators. The case is expected to proceed to trial over the course of the next two years.
3.
Other Legal Proceedings
For further discussion of legal proceedings, see Item 1,Business: "- Electric Distribution Segment," "- Electric Transmission Segment," and "- Natural Gas Distribution Segment" for information about various state regulatory and rate proceedings, civil lawsuits related thereto, and information about proceedings relating to power, transmission and pricing issues; "- Nuclear Decommissioning" for information related to high-level nuclear waste; and "- Other Regulatory and Environmental Matters" for information about proceedings involving surface water and air quality requirements, toxic substances and hazardous waste, electric and magnetic fields, licensing of hydroelectric projects, and other matters. In addition, see Item 1A,Risk Factors, for general information about several significant risks.
Item 4.
Mine Safety Disclosures
Not applicable.
EXECUTIVE OFFICERS OF THE REGISTRANT
The following table sets forth the executive officers of NU as of February 15, 2014. All of the Company’s officers serve terms of one year and until their successors are elected and qualified:
|
| | | | |
Name
| | Age
| | Title
|
Jay S. Buth
| | 44
| | Vice President, Controller and Chief Accounting Officer.
|
Gregory B. Butler
| | 56
| | Senior Vice President, General Counsel and Secretary.
|
Christine M. Carmody*
| | 51
| | Senior Vice President-Human Resources of NUSCO.
|
James J. Judge
| | 58
| | Executive Vice President and Chief Financial Officer.
|
Thomas J. May
| | 66
| | Chairman of the Board, President and Chief Executive Officer.
|
David R. McHale
| | 53
| | Executive Vice President and Chief Administrative Officer.
|
Joseph R. Nolan, Jr.*
| | 50
| | Senior Vice President-Corporate Relations of NUSCO.
|
Leon J. Olivier
| | 65
| | Executive Vice President and Chief Operating Officer.
|
* Deemed an executive officer of NU pursuant to Rule 3b-7 under the Securities Exchange Act of 1934.
Jay S. Buth. Mr. Buth has served as Vice President, Controller and Chief Accounting Officer of NU, CL&P, NSTAR Electric, NSTAR Gas, PSNH, WMECO, Yankee Gas and NUSCO since April 10, 2012. Previously, Mr. Buth served as Vice President-Accounting and Controller of NU, CL&P, PSNH, WMECO, Yankee Gas and NUSCO from June 2009 until April 10, 2012. From June 2006 through January 2009, Mr. Buth served as the Vice President and Controller for New Jersey Resources Corporation, an energy services holding company that provides natural gas and wholesale energy services, including transportation, distribution and asset management.
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Gregory B. Butler. Mr. Butler has served as Senior Vice President, General Counsel and Secretary of NU and Senior Vice President and General Counsel of NSTAR Electric and NSTAR Gas since April 10, 2012. He has served as Senior Vice President and General Counsel of CL&P, PSNH, WMECO, Yankee Gas and NUSCO since March 9, 2006. Mr. Butler has served as a Director of NSTAR Electric and NSTAR Gas since April 10, 2012. He has served as a Director of NUSCO since November 27, 2012, and of CL&P, PSNH, WMECO and Yankee Gas since April 22, 2009. Previously Mr. Butler served as Senior Vice President and General Counsel of NU from December 1, 2005 to April 10, 2012. Mr. Butler has served as a Trustee of the NSTAR Foundation since April 10, 2012. He has served as a Director of Northeast Utilities Foundation, Inc. since December 1, 2002.
Christine M. Carmody. Ms. Carmody has served as Senior Vice President-Human Resources of NUSCO since April 10, 2012 and of CL&P, PSNH, WMECO and Yankee Gas since November 27, 2012. She has served as Senior Vice President-Human Resources of NSTAR Electric and NSTAR Gas since August 1, 2008. Ms. Carmody has served as a Director of CL&P, PSNH, WMECO and Yankee Gas since April 10, 2012, and of NSTAR Electric, NSTAR Gas, and NUSCO since November 27, 2012. Previously, Ms. Carmody served as Vice President-Organizational Effectiveness of NSTAR, NSTAR Electric and NSTAR Gas from June 2006 to August 2008. Ms. Carmody has served as a Director of Northeast Utilities Foundation, Inc. since April 10, 2012. She has served as a Trustee of the NSTAR Foundation since August 1, 2008.
James J. Judge. Mr. Judge has served as Executive Vice President and Chief Financial Officer of NU, CL&P, NSTAR Electric, NSTAR Gas, PSNH, WMECO, Yankee Gas and NUSCO since April 10, 2012. Mr. Judge has served as a Director of CL&P, PSNH, WMECO, Yankee Gas and NUSCO since April 10, 2012. He has served as a Director of NSTAR Electric and NSTAR Gas since September 27, 1999. Previously, Mr. Judge served as Senior Vice President and Chief Financial Officer of NSTAR, NSTAR Electric and NSTAR Gas from 1999 until April 2012. Mr. Judge has served as Treasurer and a Director of Northeast Utilities Foundation, Inc. since April 10, 2012. He has served as a Trustee of the NSTAR Foundation since December 12, 1995.
Thomas J. May. Mr. May has served as Chairman of the Board of NU since October 10, 2013, and President and Chief Executive Officer and a Trustee of NU; Chairman and a Director of CL&P, NSTAR Electric, NSTAR Gas, PSNH, WMECO and Yankee Gas; and Chairman, President and Chief Executive Officer and a Director of NUSCO since April 10, 2012. Mr. May has served as a Director of NSTAR Electric and NSTAR Gas (or their predecessor companies) since September 27, 1999. Previously, Mr. May served as Chairman, President and Chief Executive Officer and a Trustee of NSTAR, and as Chairman, President and Chief Executive Officer of NSTAR Electric and NSTAR Gas until April 10, 2012. He served as Chairman, Chief Executive Officer and a Trustee since NSTAR was formed in 1999, and was elected President in 2002. Mr. May has served as Chairman of the Board and President of Northeast Utilities Foundation, Inc. since October 15, 2013, and has served as a Director of Northeast Utilities Foundation, Inc. since April 10, 2012. He has served as a Trustee of the NSTAR Foundation since August 18, 1987.
David R. McHale. Mr. McHale has served as Executive Vice President and Chief Administrative Officer of NU, CL&P, NSTAR Electric, NSTAR Gas, PSNH, WMECO, Yankee Gas and NUSCO since April 10, 2012. Mr. McHale has served as a Director of NSTAR Electric and NSTAR Gas since November 27, 2012, of PSNH, WMECO, Yankee Gas and NUSCO since January 1, 2005, and of CL&P since January 15, 2007. Previously, Mr. McHale served as Executive Vice President and Chief Financial Officer of NU, CL&P, PSNH, WMECO, Yankee Gas and NUSCO from January 2009 to April 2012, and Senior Vice President and Chief Financial Officer of NU, CL&P, PSNH, WMECO, Yankee Gas and NUSCO from January 2005 to December 2008. Mr. McHale has served as a Trustee of the NSTAR Foundation since April 10, 2012. He has served as a Director of Northeast Utilities Foundation, Inc. since January 1, 2005.
Joseph R. Nolan, Jr. Mr. Nolan has served as Senior Vice President-Corporate Relations of NSTAR Electric, NSTAR Gas and NUSCO since April 10, 2012. He has served as Senior Vice President-Corporate Relations of CL&P, PSNH, WMECO and Yankee Gas since November 27, 2012. Mr. Nolan has served as a Director of CL&P, PSNH, WMECO and Yankee Gas since April 10, 2012, and of NSTAR Electric, NSTAR Gas and NUSCO since November 27, 2012. Previously, Mr. Nolan served as Senior Vice President-Customer & Corporate Relations of NSTAR, NSTAR Electric and NSTAR Gas from 2006 until April 10, 2012. Mr. Nolan has served as a Director of Northeast Utilities Foundation, Inc. since April 10, 2012, and has served as Executive Director of Northeast Utilities Foundation, Inc. since October 15, 2013. He has served as a Trustee of the NSTAR Foundation since October 1, 2000.
Leon J. Olivier. Mr. Olivier has served as Executive Vice President and Chief Operating Officer of NU and NUSCO since May 13, 2008. He became Chief Executive Officer of NSTAR Electric and NSTAR Gas on April 10, 2012. Mr. Olivier has served as Chief Executive Officer of CL&P, PSNH, WMECO and Yankee Gas since January 15, 2007. Mr. Olivier has served as a Director of NSTAR Electric and NSTAR Gas since November 27, 2012, of PSNH, WMECO and Yankee Gas since January 17, 2005, and of CL&P effective September 10, 2001. Previously, Mr. Olivier served as Executive Vice President-Operations of NU from February 13, 2007 to May 12, 2008. Mr. Olivier has served as a Trustee of the NSTAR Foundation since April 10, 2012. He has served as a Director of Northeast Utilities Foundation, Inc. since April 1, 2006.
27 | | | | | |
Transmission and Distribution System | | | | |
| | | | | |
As of December 31, 2015, Eversource and our electric operating subsidiaries owned the following: |
| | | | | |
| | Electric | | Electric | |
Eversource | Distribution | | Transmission | |
Number of substations owned | 512 | | 66 | |
Transformer capacity (in kVa) | 41,484,000 | | 13,780,000 | |
Overhead lines (in circuit miles) | 40,258 | | 3,932 | |
Capacity range of overhead transmission lines (in kV) | N/A | | 69 to 345 | |
Underground lines (distribution in circuit miles and transmission in cable miles) | 16,778 | | 407 | |
Capacity range of underground transmission lines (in kV) | N/A | | 69 to 345 | |
| | | | | | | | | | | | | | | | | |
| | | CL&P | | NSTAR Electric | | PSNH | | WMECO |
| | | Distribution | | Transmission | | Distribution | | Transmission | | Distribution | | Transmission | | Distribution | | Transmission |
Number of substations owned | | 182 | | 19 | | 133 | | 24 | | 154 | | 16 | | 43 | | 7 |
Transformer capacity (in kVa) | | 19,605,000 | | 3,117,000 | | 11,431,000 | | 6,728,000 | | 5,257,000 | | 3,868,000 | | 5,191,000 | | 67,000 |
Overhead lines (in circuit miles) | | 16,951 | | 1,662 | | 7,983 | | 750 | | 11,913 | | 1,039 | | 3,411 | | 481 |
Capacity range of overhead transmission lines (in kV) | | N/A | | 69 to 345 | | N/A | | 115 to 345 | | N/A | | 115 to 345 | | N/A | | 69 to 345 |
Underground lines (distribution in circuit miles and transmission in cable miles) | | 6,528 | | 136 | | 7,354 | | 260 | | 1,821 | | 1 | | 1,075 | | 10 |
Capacity range of underground transmission lines (in kV) | | N/A | | 69 to 345 | | N/A | | 115 to 345 | | N/A | | 115 | | N/A | | 115 |
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| | | | | | | | | | | | | | | | |
| | | | | | | | | NSTAR | | | | | | |
| | | Eversource | | CL&P | | Electric | | PSNH | | WMECO |
Underground and overhead line transformers in service | | 618,387 | | | 288,352 | | | 126,353 | | | 160,848 | | | 42,834 | |
Aggregate capacity (in kVa) | | 35,097,967 | | | 15,300,765 | | | 11,429,921 | | | 6,202,270 | | | 2,165,011 | |
Electric Generating Plants
As of December 31, 2015, PSNH owned the following electric generating plants:
| | | | | | |
Type of Plant | | Number
of Units | | Year
Installed | | Claimed Capability*
(kilowatts) |
Steam Plants | | 5 | | 1952-74 | | 935,343 |
Hydro | | 20 | | 1901-83 | | 58,115 |
Internal Combustion | | 5 | | 1968-70 | | 101,869 |
Biomass | | 1 | | 2006 | | 42,594 |
Total PSNH Generating Plant | | 31 | | | | 1,137,921 |
*
Claimed capability represents winter ratings as of December 31, 2015. The combined nameplate capacity of the generating plants is approximately 1,200 MW.
As of December 31, 2015, WMECO owned the following electric generating plants:
| | | | | | | |
Type of Plant | | | Number
of Sites | | Year
Installed | | Claimed Capability**
(kilowatts) |
Solar Fixed Tilt, Photovoltaic | | 3 | | 2010-14 | | 8,000 |
** Claimed capability represents the direct current nameplate capacity of the plant.
CL&P and NSTAR Electric do not own any electric generating plants.
Natural Gas Distribution System
As of December 31, 2015, Yankee Gas owned 28 active gate stations, 203 district regulator stations, and approximately 3,317 miles of natural gas main pipeline. Yankee Gas also owns a liquefaction and vaporization plant and above ground storage tank with a storage capacity equivalent of 1.2 Bcf of natural gas in Waterbury, Connecticut.
As of December 31, 2015, NSTAR Gas owned 21 active gate stations, 164 district regulator stations, and approximately 3,250 miles of natural gas main pipeline. Hopkinton, another subsidiary of Eversource, owns a satellite vaporization plant and above ground storage tanks in Acushnet, MA. In addition, Hopkinton owns a liquefaction and vaporization plant with above ground storage tanks in Hopkinton, MA. Combined, the two plants' tanks have an aggregate storage capacity equivalent to 3.5 Bcf of natural gas that is provided to NSTAR Gas under contract.
Franchises
CL&P Subject to the power of alteration, amendment or repeal by the General Assembly of Connecticut and subject to certain approvals, permits and consents of public authority and others prescribed by statute, CL&P has, subject to certain exceptions not deemed material, valid franchises free from burdensome restrictions to provide electric transmission and distribution services in the respective areas in which it is now supplying such service.
In addition to the right to provide electric transmission and distribution services as set forth above, the franchises of CL&P include, among others, limited rights and powers, as set forth under Connecticut law and the special acts of the General Assembly constituting its charter, to manufacture, generate, purchase and/or sell electricity at retail, including to provide Standard Service, Supplier of Last Resort service and backup service, to sell electricity at wholesale and to erect and maintain certain facilities on public highways and grounds, all subject to such consents and approvals of public authority and others as may be required by law. The franchises of CL&P include the power of eminent domain. Connecticut law prohibits an electric distribution company from owning or operating generation assets. However, under "An Act Concerning Energy Independence," enacted in 2005, CL&P is permitted to own up to 200 MW of peaking facilities if the PURA determines that such facilities will be more cost effective than other options for mitigating FMCC and Locational Installed Capacity (LICAP) costs. In addition, under "An Act Concerning Electricity and Energy Efficiency," enacted in 2007, an electric distribution company, such as CL&P, is permitted to purchase an existing electric generating plant located in Connecticut that is offered for sale, subject to prior approval from the PURA and a determination by the PURA that such purchase is in the public interest. Finally, Connecticut law also allows CL&P to submit a proposal to the DEEP to build, own or operate one or more generation facilities up to 10 MWs using Class I renewable energy.
NSTAR Electric and NSTAR GasThrough their charters, which are unlimited in time, NSTAR Electric and NSTAR Gas have the right to engage in the business of delivering and selling electricity and natural gas within their respective service territories, and have powers incidental thereto and are entitled to all the rights and privileges of and subject to the duties imposed upon electric and natural gas companies under Massachusetts laws. The locations in public ways for electric transmission and distribution lines and natural gas distribution pipelines are obtained from municipal and other state authorities who, in granting these locations, act as agents for the state. In some cases the actions of these authorities are subject to appeal to the DPU. The rights to these locations are not limited in time and are subject to the action of these authorities and the legislature. Under Massachusetts law, with the exception of municipal-owned utilities, no other entity may provide electric or natural gas delivery service to retail
20
customers within NSTAR's service territory without the written consent of NSTAR Electric and/or NSTAR Gas. This consent must be filed with the DPU and the municipality so affected.
The Massachusetts restructuring legislation defines service territories as those territories actually served on July 1, 1997 and following municipal boundaries to the extent possible. The restructuring legislation further provides that until terminated by law or otherwise, distribution companies shall have the exclusive obligation to serve all retail customers within their service territories and no other person shall provide distribution service within such service territories without the written consent of such distribution companies. Pursuant to the Massachusetts restructuring legislation, the DPU (then, the Department of Telecommunications and Energy) was required to define service territories for each distribution company, including NSTAR Electric. The DPU subsequently determined that there were advantages to the exclusivity of service territories and issued a report to the Massachusetts Legislature recommending against, in this regard, any changes to the restructuring legislation.
PSNH The NHPUC, pursuant to statutory requirements, has issued orders granting PSNH exclusive franchises to distribute electricity in the respective areas in which it is now supplying such service.
In addition to the right to distribute electricity as set forth above, the franchises of PSNH include, among others, rights and powers to manufacture, generate, purchase, and transmit electricity, to sell electricity at wholesale to other utility companies and municipalities and to erect and maintain certain facilities on certain public highways and grounds, all subject to such consents and approvals of public authority and others as may be required by law. PSNH's status as a public utility gives it the ability to petition the NHPUC for the right to exercise eminent domain for its transmission and distribution services in appropriate circumstances.
PSNH is also subject to certain regulatory oversight by the Maine Public Utilities Commission and the Vermont Public Service Board.
WMECO WMECO is authorized by its charter to conduct its electric business in the territories served by it, and has locations in the public highways for transmission and distribution lines. Such locations are granted pursuant to the laws of Massachusetts by the Department of Public Works of Massachusetts or local municipal authorities and are of unlimited duration, but the rights thereby granted are not vested. Such locations are for specific lines only and for extensions of lines in public highways. Further similar locations must be obtained from the Department of Public Works of Massachusetts or the local municipal authorities. In addition, WMECO has been granted easements for its lines in the Massachusetts Turnpike by the Massachusetts Turnpike Authority and pursuant to state laws, has the power of eminent domain.
The Massachusetts restructuring legislation applicable to NSTAR Electric (described above) is also applicable to WMECO.
Yankee Gas Yankee Gas holds valid franchises to sell natural gas in the areas in which Yankee Gas supplies natural gas service, which it acquired either directly or from its predecessors in interest. Generally, Yankee Gas holds franchises to serve customers in areas designated by those franchises as well as in most other areas throughout Connecticut so long as those areas are not occupied and served by another natural gas utility under a valid franchise of its own or are not subject to an exclusive franchise of another natural gas utility. Yankee Gas' franchises are perpetual but remain subject to the power of alteration, amendment or repeal by the General Assembly of the State of Connecticut, the power of revocation by the PURA and certain approvals, permits and consents of public authorities and others prescribed by statute. Generally, Yankee Gas' franchises include, among other rights and powers, the right and power to manufacture, generate, purchase, transmit and distribute natural gas and to erect and maintain certain facilities on public highways and grounds, and the right of eminent domain, all subject to such consents and approvals of public authorities and others as may be required by law.
Item 3.
PART II
| Item 5. | Market for the Registrants' Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities |
24
|
(a)
Market Information and (c) Dividends
NU. Our common shares are listed on the New York Stock Exchange. The ticker symbol is "NU," although it is frequently presented as "Noeast Util" and/or "NE Util" in various financial publications. The high and low sales prices of our common shares and the dividends declared, for the past two years, by quarter, are shown below.
| | | | | | | | | | | | Year | | Quarter | | High | | Low | | Dividends
Declared | | | | | | | | | | | | | 2013 | | First | | $ | 43.49 | | $ | 38.60 | | $ | 0.368 |
| | | | | | | | | | | | | | Second | | | 45.66 | | | 39.35 | | | 0.368 | | | Third | | | 45.13 | | | 40.01 | | | 0.368 | | | Fourth | | | 43.75 | | | 40.60 | | | 0.368 | | | | | | | | | | | | | 2012 | | First | | $ | 37.64 | | $ | 33.48 | | $ | 0.294 |
| | | | | | | | | | | | | | Second | | | 39.09 | | | 34.84 | | | 0.343 | | | Third | | | 40.86 | | | 36.68 | | | 0.343 | | | Fourth | | | 40.38 | | | 37.53 | | | 0.343 |
Information with respect to dividend restrictions for us, CL&P, NSTAR Electric, PSNH, and WMECO is contained in Item 7,6.
| Selected Consolidated Financial Data | 26 |
Item 7. | Management's Discussion and Analysis of Financial Condition and Results of Operations, under the caption "Liquidity" | 28 |
Item 7A. | Quantitative and Qualitative Disclosures about Market Risk | 60 |
Item 8,8. | Financial Statements and Supplementary Data, | 61 |
Item 9. | Changes in theCombined Notes to Consolidatedand Disagreements with Accountants on Accounting and Financial Statements, within this Annual Report on Form 10-K. Disclosure |
136
|
There is no established public trading market for the common stock of CL&P, NSTAR Electric, PSNHItem 9A.
| Controls and WMECO. All of the common stock of CL&P, NSTAR Electric, PSNHProcedures | 136 |
Item 9B. | Other Information | 136 |
| | |
PART III | |
Item 10. | Directors, Executive Officers and WMECO is held solely by NU.Corporate Governance |
137
|
During 2013 and 2012, CL&P approved and paid $152 million and $100.5 million, respectively, of common stock dividends to NU.
During 2013, NSTAR Electric approved and paid $56 million of common stock dividends to its parent company. For the period April 10, 2012 to December 31, 2012, NSTAR Electric approved and paid $159.9 million of common stock dividends to its parent company.
During 2013 and 2012, PSNH approved and paid $68 million and $90.7 million, respectively, of common stock dividends to NU.
During 2013 and 2012, WMECO approved and paid $40 million and $9.4 million, respectively, of common stock dividends to NU.
(b)
Holders
As of January 31, 2014, there were 46,983 registered common shareholders of our company on record. As of the same date, there were a total of 315,434,940 common shares issued.
(c)
Securities Authorized for Issuance Under Equity Compensation Plans
For information regarding securities authorized for issuance under equity compensation plans, see Item 12,11.
| Executive Compensation | 140 |
Item 12. | Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters | 165 |
Item 13. | Certain Relationships and Related Transactions, and Director Independence | 166 |
Item 14. | Principal Accountant Fees and Services | 167 |
| | |
PART IV | |
Item 15. | Exhibits and Financial Statement Schedules | 169 |
Signatures | 170 |
iii
EVERSOURCE ENERGY AND SUBSIDIARIES
THE CONNECTICUT LIGHT AND POWER COMPANY
NSTAR ELECTRIC COMPANY AND SUBSIDIARY
PUBLIC SERVICE COMPANY OF NEW HAMPSHIRE AND SUBSIDIARY
WESTERN MASSACHUSETTS ELECTRIC COMPANY
SAFE HARBOR STATEMENT UNDER THE PRIVATE SECURITIES
LITIGATION REFORM ACT OF 1995
References in this Annual Report on Form 10-K to "Eversource," "the Company," "we," "our," and "us" refer to Eversource and its consolidated subsidiaries. On April 30, 2015, the Company's legal name was changed from Northeast Utilities to Eversource Energy. CL&P, NSTAR Electric, PSNH and WMECO are each doing business as Eversource Energy.
From time to time we make statements concerning our expectations, beliefs, plans, objectives, goals, strategies, assumptions of future events, future financial performance or growth and other statements that are not historical facts. These statements are "forward-looking statements" within the meaning of the Private Securities Litigation Reform Act of 1995. You can generally identify our forward-looking statements through the use of words or phrases such as "estimate," "expect," "anticipate," "intend," "plan," "project," "believe," "forecast," "should," "could," and other similar expressions. Forward-looking statements are based on the current expectations, estimates, assumptions or projections of management and are not guarantees of future performance. These expectations, estimates, assumptions or projections may vary materially from actual results. Accordingly, any such statements are qualified in their entirety by reference to, and are accompanied by, the following important factors that could cause our actual results to differ materially from those contained in our forward-looking statements, including, but not limited to:
·
cyber breaches, acts of war or terrorism, or grid disturbances,
·
actions or inaction of local, state and federal regulatory, public policy and taxing bodies,
·
changes in business conditions, which could include disruptive technology related to our current or future business model,
·
changes in economic conditions, including impact on interest rates, tax policies, and customer demand and payment ability,
·
fluctuations in weather patterns,
·
changes in laws, regulations or regulatory policy,
·
changes in levels or timing of capital expenditures,
·
disruptions in the capital markets or other events that make our access to necessary capital more difficult or costly,
·
developments in legal or public policy doctrines,
·
technological developments,
·
changes in accounting standards and financial reporting regulations,
·
actions of rating agencies, and
·
other presently unknown or unforeseen factors.
Other risk factors are detailed in our reports filed with the SEC and updated as necessary, and we encourage you to consult such disclosures.
All such factors are difficult to predict, contain uncertainties that may materially affect our actual results and are beyond our control. You should not place undue reliance on the forward-looking statements, each speaks only as of the date on which such statement is made, and we undertake no obligation to update any forward-looking statement or statements to reflect events or circumstances after the date on which such statement is made or to reflect the occurrence of unanticipated events. New factors emerge from time to time and it is not possible for us to predict all of such factors, nor can we assess the impact of each such factor on the business or the extent to which any factor, or combination of factors, may cause actual results to differ materially from those contained in any forward-looking statements. For more information, see Item 1A, Risk Factors, included in this combined Annual Report on Form 10-K. This Annual Report on Form 10-K also describes material contingencies and critical accounting policies in the accompanyingManagement's Discussion and Analysis of Financial Condition and Results of OperationsandCombined Notes to Consolidated Financial Statements. We encourage you to review these items.
1
EVERSOURCE ENERGY AND SUBSIDIARIES
THE CONNECTICUT LIGHT AND POWER COMPANY
NSTAR ELECTRIC COMPANY AND SUBSIDIARY
PUBLIC SERVICE COMPANY OF NEW HAMPSHIRE AND SUBSIDIARY
WESTERN MASSACHUSETTS ELECTRIC COMPANY
PART I
Item 1.
Business
Please refer to the Glossary of Terms for definitions of defined terms and abbreviations used in this combined Annual Report on Form 10-K.
Eversource Energy, headquartered in Boston, Massachusetts and Hartford, Connecticut, is a public utility holding company subject to regulation by the FERC under the Public Utility Holding Company Act of 2005. We are engaged primarily in the energy delivery business through the following wholly owned utility subsidiaries:
·
The Connecticut Light and Power Company (CL&P), a regulated electric utility that serves residential, commercial and industrial customers in parts of Connecticut;
·
NSTAR Electric Company (NSTAR Electric), a regulated electric utility that serves residential, commercial and industrial customers in parts of eastern Massachusetts;
·
Public Service Company of New Hampshire (PSNH), a regulated electric utility that serves residential, commercial and industrial customers in parts of New Hampshire and owns generation assets used to serve customers;
·
Western Massachusetts Electric Company (WMECO), a regulated electric utility that serves residential, commercial and industrial customers in parts of western Massachusetts and owns solar generating assets;
·
NSTAR Gas Company (NSTAR Gas), a regulated natural gas utility that serves residential, commercial and industrial customers in parts of Massachusetts; and
·
Yankee Gas Services Company (Yankee Gas), a regulated natural gas utility that serves residential, commercial and industrial customers in parts of Connecticut.
CL&P, NSTAR Electric, PSNH and WMECO also serve New England customers through Eversource Energy's electric transmission business.
On April 30, 2015, the Company's legal name was changed from Northeast Utilities to Eversource Energy. CL&P, NSTAR Electric, PSNH and
WMECO are each doing business as Eversource Energy.
Eversource Energy, CL&P, NSTAR Electric, PSNH and WMECO each report their financial results separately. We also include information in this report on a segment basis for Eversource Energy. Eversource Energy recognizes three reportable segments: electric distribution, electric transmission and natural gas distribution. Eversource Energy's electric distribution segment includes the generation businesses of PSNH and WMECO. These three segments represented substantially all of Eversource Energy's total consolidated revenues for the years ended December 31, 2015 and 2014. CL&P, NSTAR Electric, PSNH and WMECO do not report separate business segments.
ELECTRIC DISTRIBUTION SEGMENT
General
Eversource Energy's electric distribution segment consists of the distribution businesses of CL&P, NSTAR Electric, PSNH and WMECO, which are engaged in the distribution of electricity to retail customers in Connecticut, eastern Massachusetts, New Hampshire and western Massachusetts, respectively, plus the regulated electric generation businesses of PSNH and WMECO.
The following table shows the sources of 2015 electric franchise retail revenues for Eversource Energy's electric distribution companies, collectively, based on categories of customers:
| | | | |
(Thousands of Dollars, except percentages) | | 2015 | | % of Total |
Residential | $ | 3,608,155 | | 55 |
Commercial | | 2,476,686 | | 38 |
Industrial | | 326,564 | | 5 |
Other | | 151,195 | | 2 |
Total Retail Electric Revenues | $ | 6,562,600 | | 100% |
2
A summary of our distribution companies' retail electric GWh sales volumes and percentage changes for 2015, as compared to 2014, is as follows:
| | | | | |
| 2015 | | 2014 | | Percentage
Change |
Residential | 21,441 | | 21,317 | | 0.6 % |
Commercial | 27,598 | | 27,449 | | 0.5 % |
Industrial | 5,577 | | 5,676 | | (1.7)% |
Total | 54,616 | | 54,442 | | 0.3 % |
Our 2015 consolidated retail electric sales volumes were slightly higher, as compared to 2014, due primarily to the impact of colder winter weather experienced in the first quarter of 2015 and warmer weather in the third quarter of 2015, partially offset by milder winter weather in the fourth quarter of 2015 throughout our service territories as well as an increase in customer conservation efforts, including the impact of energy efficiency programs sponsored by CL&P, NSTAR Electric, PSNH and WMECO.
Fluctuations in retail electric sales volumes at NSTAR Electric and PSNH impact earnings. For CL&P (effective December 1, 2014) and WMECO, fluctuations in retail electric sales volumes do not impact earnings due to their respective regulatory commission approved revenue decoupling mechanisms. These distribution revenues are decoupled from their customer sales volumes, which breaks the relationship between sales volumes and revenues recognized. CL&P and WMECO reconcile their annual base distribution rate recovery amounts to their respective pre-established levels of baseline distribution delivery service revenues. Any difference between the allowed level of distribution revenue and the actual amount incurred during a 12-month period is adjusted through rates in the following period.
ELECTRIC DISTRIBUTION – CONNECTICUT
THE CONNECTICUT LIGHT AND POWER COMPANY
CL&P's distribution business consists primarily of the purchase, delivery and sale of electricity to its residential, commercial and industrial customers. As of December 31, 2015, CL&P furnished retail franchise electric service to approximately 1.2 million customers in 149 cities and towns in Connecticut, covering an area of 4,400 square miles. CL&P does not own any electric generation facilities.
The following table shows the sources of CL&P's 2015 electric franchise retail revenues based on categories of customers:
| | | | | |
| CL&P |
(Thousands of Dollars, except percentages) | | 2015 | | % of Total |
Residential | $ | 1,641,165 | | 61 |
Commercial | | 841,093 | | 31 |
Industrial | | 129,544 | | 5 |
Other | | 62,704 | | 3 |
Total Retail Electric Revenues | $ | 2,674,506 | | 100% |
A summary of CL&P's retail electric GWh sales volumes and percentage changes for 2015, as compared to 2014, is as follows:
| | | | | |
| 2015 | | 2014 | | Percentage
Change |
Residential | 10,094 | | 10,026 | | 0.7 % |
Commercial | 9,635 | | 9,643 | | (0.1)% |
Industrial | 2,342 | | 2,377 | | (1.5)% |
Total | 22,071 | | 22,046 | | 0.1 % |
Rates
CL&P is subject to regulation by the PURA, which, among other things, has jurisdiction over rates, certain dispositions of property and plant, mergers and consolidations, issuances of long-term securities, standards of service and construction and operation of facilities. CL&P's present general rate structure consists of various rate and service classifications covering residential, commercial and industrial services. CL&P's retail rates include a delivery service component, which includes distribution, transmission, conservation, renewables, CTA, SBC and other charges that are assessed on all customers. Connecticut utilities are entitled under state law to charge rates that are sufficient to allow them an opportunity to recover their reasonable operating and capital costs, in order to attract needed capital and maintain their financial integrity, while also protecting relevant public interests.
Under Connecticut law, all of CL&P's customers are entitled to choose their energy suppliers, while CL&P remains their electric distribution company. For those customers who do not choose a competitive energy supplier, under SS rates for customers with less than 500 kilowatts of demand, and LRS rates for customers with 500 kilowatts or more of demand, CL&P purchases power under standard offer contracts and passes the cost of the power to customers through a combined GSC and FMCC charge on customers' bills.
CL&P continues to supply approximately 40 percent of its customer load at SS or LRS rates while the other 60 percent of its customer load has migrated to competitive energy suppliers. Because this customer migration is only for energy supply service, it has no impact on CL&P's electric distribution business or its operating income.
3
The rates established by the PURA for CL&P are comprised of the following:
·
An electric generation services charge (GSC), which recovers energy-related costs incurred as a result of providing electric generation service supply to all customers that have not migrated to competitive energy suppliers. The GSC is adjusted periodically and reconciled semi-annually in accordance with the policies and procedures of the PURA, with any differences refunded to, or recovered from, customers.
·
A revenue decoupling adjustment (effective December 1, 2014) that reconciles the amounts recovered from customers, on an annual basis, to the distribution revenue requirement approved by the PURA in its last rate case, which currently is an annual amount of $1.059 billion.
·
A distribution charge, which includes a fixed customer charge and a demand and/or energy charge to collect the costs of building and expanding the infrastructure to deliver power to customers, as well as ongoing operating costs to maintain the infrastructure.
·
A federally-mandated congestion charge (FMCC), which recovers any costs imposed by the FERC as part of the New England Standard Market Design, including locational marginal pricing, locational installed capacity payments, and any costs approved by the PURA to reduce these charges. The FMCC also recovers costs associated with CL&P's system resiliency program. The FMCC is adjusted periodically and reconciled semi-annually in accordance with the policies and procedures of the PURA, with any differences refunded to, or recovered from, customers.
·
A transmission charge that recovers the cost of transporting electricity over high voltage lines from generating plants to substations, including costs allocated by ISO-NE to maintain the wholesale electric market.
·
A competitive transition assessment charge (CTA), assessed to recover stranded costs associated with electric industry restructuring such as various IPP contracts. The CTA is reconciled annually to actual costs incurred and reviewed by the PURA, with any difference refunded to, or recovered from, customers.
·
A systems benefits charge (SBC), established to fund expenses associated with: various hardship and low income programs; a program to compensate municipalities for losses in property tax revenue due to decreases in the value of electric generating facilities resulting directly from electric industry restructuring. The SBC is reconciled annually to actual costs incurred and reviewed by the PURA, with any difference refunded to, or recovered from, customers.
·
A Clean Energy Fund charge, which is used to promote investment in renewable energy sources. Amounts collected by this charge are deposited into the Clean Energy Fund and administered by the Clean Energy Finance and Investment Authority. The Clean Energy Fund charge is set by statute and is currently 0.1 cent per kWh.
·
A conservation charge, comprised of a statutory rate established to implement cost-effective energy conservation programs and market transformation initiatives, plus a conservation adjustment mechanism charge to recover the residual energy efficiency spending associated with the expanded energy efficiency costs directed by the Comprehensive Energy Strategy Plan for Connecticut.
As required by regulation, CL&P, jointly with UI, entered into the following contracts whereby UI will share 20 percent and CL&P will share 80 percent of the costs and benefits (CL&P's portion of these costs are either recovered from, or refunded to, customers through the FMCC charge):
·
Four CfDs (totaling approximately 787 MW of capacity) with three electric generation units and one demand response project, which extend through 2026 and have terms of up to 15 years beginning in 2009. The capacity CfDs obligate both CL&P and UI to make or receive payments on a monthly basis to or from the project and generation owners based on the difference between a contractually set capacity price and the capacity market prices that the project and generation owners receive in the ISO-NE capacity markets.
·
Three CfDs (totaling approximately 500 MW of peaking capacity) with three peaking generation units. The three peaker CfDs pay the generation owners the difference between capacity, forward reserve and energy market revenues and a cost-of service payment stream for 30 years beginning in 2008 (including costs of plant operation and the prices that the generation owners receive for capacity and other products in the ISO-NE markets).
·
Long-term commitments to purchase approximately 250 MW of wind power from a Maine wind farm and 20 MW of solar power from a multi-site project in Connecticut. Both of these projects are expected to be operational by the end of 2016.
On December 17, 2014 the PURA approved CL&P's application to amend customer rates, effective December 1, 2014, for a total base distribution rate increase of $152 million, which includes an authorized ROE of 9.02 percent for the first twelve month period and 9.17 percent thereafter. The distribution rate increase included a revenue decoupling mechanism effective December 1, 2014, and the recovery of 2011 and 2012 storm restoration costs and system resiliency costs. Also in December 2014, the PURA granted a re-opener request to CL&P’s base distribution rate application for further review of the appropriate balance of ADIT utilized in the calculation of rate base. On July 2, 2015, the PURA issued a final order that approved a settlement agreement filed on May 19, 2015 between CL&P and the PURA Prosecutorial Staff, and which included an increase to total allowed annual revenue requirements of $18.4 million beginning December 1, 2014.
4
Sources and Availability of Electric Power Supply
As noted above, CL&P does not own any generation assets and purchases energy supply to serve its SS and LRS loads from a variety of competitive sources through requests for proposals. CL&P periodically enters into full requirements contracts for the majority of SS loads for periods of up to one year for its residential customers and small and medium commercial and industrial customers. CL&P is authorized to supply the remainder of the SS loads through a self-managed process that includes bilateral purchases and spot market purchases. CL&P typically enters into full requirements contracts for LRS for larger commercial and industrial customers every three months. Currently, CL&P has full requirements contracts in place for 80 percent of its SS loads for the first half of 2016 and has bilateral purchases in place to self-manage the remaining 20 percent. For the second half of 2016, CL&P has 50 percent of its SS load under full requirements contracts, intends to purchase an additional 30 percent of full requirements and will self-manage the remainder as needed. None of the SS load for 2017 has been procured. CL&P has full requirements contracts in place for its LRS loads through the second quarter of 2016 and intends to purchase 100 percent of full requirements for the third and fourth quarters of 2016.
ELECTRIC DISTRIBUTION – MASSACHUSETTS
NSTAR ELECTRIC COMPANY
WESTERN MASSACHUSETTS ELECTRIC COMPANY
The electric distribution businesses of NSTAR Electric and WMECO consist primarily of the purchase, delivery and sale of electricity to residential, commercial and industrial customers within their respective franchise service territories. As of December 31, 2015, NSTAR Electric furnished retail franchise electric service to approximately 1.2 million customers in Boston and 80 surrounding cities and towns in Massachusetts, including Cape Cod and Martha's Vineyard, covering an area of approximately 1,700 square miles. WMECO provides retail franchise electric service to approximately 209,000 customers in 59 cities and towns in the western region of Massachusetts, covering an area of approximately 1,500 square miles. Neither NSTAR Electric nor WMECO owns any generating facilities used to supply customers, and each purchases its respective energy requirements from competitive energy suppliers.
In 2009, WMECO was authorized by the DPU to install solar energy generation in its service territory. From 2010 through 2014, WMECO completed development of a total of 8 MW solar generation facilities on sites in Pittsfield, Springfield, and East Springfield, Massachusetts. WMECO will sell all energy and other products from its solar generation facilities into the ISO-NE market. NSTAR Electric does not own any solar generation facilities.
The following table shows the sources of the 2015 electric franchise retail revenues of NSTAR Electric and WMECO based on categories of customers:
| | | | | | | | | |
| | NSTAR Electric | | WMECO |
(Thousands of Dollars, except percentages) | | 2015 | | % of Total | | 2015 | | % of Total |
Residential | $ | 1,205,387 | | 48 | | $ | 255,797 | | 59 |
Commercial | | 1,187,452 | | 47 | | | 135,222 | | 31 |
Industrial | | 84,667 | | 3 | | | 35,439 | | 8 |
Other | | 47,610 | | 2 | | | 5,778 | | 2 |
Total Retail Electric Revenues | $ | 2,525,116 | | 100% | | $ | 432,236 | | 100% |
A summary of NSTAR Electric's and WMECO's retail electric GWh sales volumes and percentage changes for 2015, as compared to 2014, is as follows:
| | | | | | | | | | | | |
| | NSTAR Electric | | WMECO |
| | 2015 | | 2014 | | Percentage
Change | | 2015 | | 2014 | | Percentage
Change |
Residential | | 6,687 | | 6,625 | | 0.9 % | | 1,465 | | 1,494 | | (2.0)% |
Commercial | | 13,120 | | 13,009 | | 0.9 % | | 1,478 | | 1,466 | | 0.8 % |
Industrial | | 1,248 | | 1,291 | | (3.3)% | | 620 | | 626 | | (0.9)% |
Total | | 21,055 | | 20,925 | | 0.6 % | | 3,563 | | 3,586 | | (0.6)% |
Rates
NSTAR Electric and WMECO are each subject to regulation by the DPU, which, among other things, has jurisdiction over rates, certain dispositions of property and plant, mergers and consolidations, issuances of long-term securities, acquisition of securities, standards of service and construction and operation of facilities. The present general rate structure for both NSTAR Electric and WMECO consists of various rate and service classifications covering residential, commercial and industrial services. Massachusetts utilities are entitled under state law to charge rates that are sufficient to allow them an opportunity to recover their reasonable operating and capital costs, in order to attract needed capital and maintain their financial integrity, while also protecting relevant public interests.
Under Massachusetts law, all customers of each of NSTAR Electric and WMECO are entitled to choose their energy suppliers, while NSTAR Electric or WMECO remains their electric distribution company. Both NSTAR Electric and WMECO purchase power from competitive suppliers on behalf of, and pass the related cost through to, their respective customers who do not choose a competitive energy supplier (basic service). Most of the residential customers of NSTAR Electric and WMECO have continued to buy their power from NSTAR Electric or WMECO at basic service rates. Most commercial and industrial customers have switched to a competitive energy supplier.
5
The Cape Light Compact, an inter-governmental organization consisting of the 21 towns and two counties on Cape Cod and Martha's Vineyard, serves 200,000 customers through the delivery of energy efficiency programs, effective consumer advocacy, competitive electricity supply and green power options. NSTAR Electric continues to provide electric service to these customers including the delivery of power, maintenance of infrastructure, capital investment, meter reading, billing, and customer service.
NSTAR Electric continues to supply approximately 39 percent of its customer load at basic service rates while the other 61 percentof its customer load has migrated to competitive energy suppliers. WMECO continues to supply approximately 41 percent of its customer load at basic service rates while the other 59 percent of its customer load has migrated to competitive energy suppliers. Because customer migration is limited to energy supply service, it has no impact on the delivery business or operating income of NSTAR Electric and WMECO.
The rates established by the DPU for NSTAR Electric and WMECO are comprised of the following:
·
A basic service charge that represents the collection of energy costs, including costs related to charge-offs of uncollectible energy costs from customers. Electric distribution companies in Massachusetts are required to obtain and resell power to retail customers through basic service for those 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). Additionally, the DPU has authorized NSTAR Electric to recover the cost of its Dynamic Pricing Smart Grid Pilot Program and NSTAR Green wind contracts through the basic service charge. Basic service costs are reconciled annually, with any differences refunded to, or recovered from, customers.
·
A distribution charge, which includes a fixed customer charge and a demand and/or energy charge to collect the costs of building and expanding the infrastructure to deliver power to its destination, as well as ongoing operating costs.
·
For WMECO, a revenue decoupling adjustment that reconciles distribution revenue, on an annual basis, to the amount of distribution revenue approved by the DPU in its last rate case in 2011. Currently, WMECO is allowed to collect $132.4 million annually.
·
A transmission charge that recovers the cost of transporting electricity over high voltage lines from generating plants to substations, including costs allocated by ISO-NE to maintain the wholesale electric market.
·
A transition charge that represents costs to be collected primarily from previously held investments in generating plants, costs related to existing above-market power contracts, and contract costs related to long-term power contract buy-outs.
·
An energy efficiency charge that represents a legislatively-mandated charge to collect costs for energy efficiency programs.
·
Reconciling adjustment charges that recover certain DPU-approved costs as follows: pension and PBOP benefits, low income customer discounts, lost revenue and credits associated with net-metering facilities installed by customers, storms, consultants retained by the attorney general, long-term renewable contracts and energy efficiency programs and lost base revenue associated with energy efficiency measures. In addition to these adjustments common to both NSTAR Electric and WMECO, NSTAR Electric has reconciling adjustment charges that collect costs associated with certain safety and reliability projects and a Smart Grid pilot program. WMECO has a reconciling adjustment charge that recovers costs associated with certain solar projects owned and operated by WMECO.
As required by regulation, NSTAR Electric and WMECO, along with two other Massachusetts electric utilities, signed long-term commitments to purchase a combined estimated generating capacity of approximately 334 MW of wind power from two wind farms in Maine over 15 years. The projects are in various stages of permitting, development, or operation. One unit began operating in late 2015, and the other unit is expected to be in operation by December 2016. In addition, WMECO previously signed a long-term commitment to purchase an estimated generating capacity of approximately 37.5 MW of wind power from a wind farm in Maine over 15 years that is expected to be in operation in 2016.
Pursuant to a 2008 DPU order, Massachusetts electric utilities must adopt rate structures that decouple the volume of energy sales from the utility's revenues in their next rate case. WMECO is currently decoupled and NSTAR Electric will propose decoupling in its next rate case.
NSTAR Electric and WMECO are each subject to service quality (SQ) metrics that measure safety, reliability and customer service, and could be required to pay to customers a SQ charge of up to 2.5 percent of annual transmission and distribution revenues for failing to meet such metrics. Neither NSTAR Electric nor WMECO will be required to pay a SQ charge for its 2015 performance as each company achieved results at or above target for all of its respective SQ metrics in 2015.
Sources and Availability of Electric Power Supply
As noted above, neither NSTAR Electric nor WMECO owns any generation assets (other than WMECO's solar generation), and both companies purchase their respective energy requirements from a variety of competitive sources through requests for proposals issued periodically, consistent with DPU regulations. NSTAR Electric and WMECO enter into supply contracts for basic service for 50 percentof their respective residential and small commercial and industrial customers twice per year for twelve month terms. Both NSTAR Electric and WMECO enter into supply contracts for basic service for 100 percentof large commercial and industrial customers every three months.
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ELECTRIC DISTRIBUTION – NEW HAMPSHIRE
PUBLIC SERVICE COMPANY OF NEW HAMPSHIRE
PSNH's distribution business consists primarily of the generation, delivery and sale of electricity to its residential, commercial and industrial customers. As of December 31, 2015, PSNH furnished retail franchise electric service to approximately 503,000 retail customers in 211 cities and towns in New Hampshire, covering an area of approximately 5,630 square miles. PSNH currently owns and operates approximately 1,200 MW of primarily coal-, natural gas-, and oil-fired electricity generation plants. PSNH's distribution business includes the activities of its generation business.
The Clean Air Project, a wet flue gas desulphurization system (Scrubber), was constructed and placed in service by PSNH at its Merrimack Station in 2011. The Scrubber reduces emissions of SO2 and mercury from Merrimack Station by over 90 percent, which is well in excess of state and federal requirements. PSNH is permitted to recover prudent Scrubber costs through its default energy service rates under New Hampshire law. Effective January 1, 2016, PSNH is recovering all Scrubber costs in rates charged to customers. For further information, see "Regulatory Developments and Rate Matters – New Hampshire – Clean Air Project Prudence Proceeding" in the accompanying Item 7,Management's Discussion and Analysis of Financial Condition and Results of Operations.
The following table shows the sources of PSNH's 2015 electric franchise retail revenues based on categories of customers:
| | | | |
| PSNH |
(Thousands of Dollars, except percentages) | | 2015 | | % of Total |
Residential | $ | 505,806 | | 54 |
Commercial | | 312,918 | | 34 |
Industrial | | 76,914 | | 8 |
Other | | 35,103 | | 4 |
Total Retail Electric Revenues | $ | 930,741 | | 100% |
A summary of PSNH's retail electric GWh sales volumes and percentage changes for 2015, as compared to 2014, is as follows:
| | | | | |
| 2015 | | 2014 | | Percentage
Change |
Residential | 3,195 | | 3,172 | | 0.7 % |
Commercial | 3,365 | | 3,332 | | 1.0 % |
Industrial | 1,367 | | 1,382 | | (1.1)% |
Total | 7,927 | | 7,886 | | 0.5 % |
Rates
PSNH is subject to regulation by the NHPUC, which, among other things, has jurisdiction over rates, certain dispositions of property and plant, mergers and consolidations, issuances of securities, standards of service and construction and operation of facilities. New Hampshire utilities are entitled under state law to charge rates that are sufficient to allow them an opportunity to recover their reasonable operating and capital costs, in order to attract needed capital and maintain their financial integrity, while also protecting relevant public interests.
Under New Hampshire law, all of PSNH's customers are entitled to choose competitive energy suppliers, with PSNH providing default energy service under its ES rate for those customers who do not choose a competitive energy supplier. At the end of 2015, approximately 21 percent of all of PSNH's customers (approximately 53 percent of load) were taking service from competitive energy suppliers, compared to 21 percent of customers (approximately 46 percent of load) at the end of 2014.
The rates established by the NHPUC for PSNH are comprised of the following:
·
A default energy service charge which recovers energy-related costs incurred as a result of providing electric generation service supply to all customers that have not migrated to competitive energy suppliers. These charges recover the costs of PSNH's generation, as well as purchased power, and include an allowed ROE of 9.81 percent.
·
A distribution charge, which includes an energy and/or demand-based charge to recover costs related to the maintenance and operation of PSNH's infrastructure to deliver power to its destination, as well as power restoration and service costs. This includes a customer charge to collect the cost of providing service to a customer; such as the installation, maintenance, reading and replacement of meters and maintaining accounts and records.
·
A transmission charge that recovers the cost of transporting electricity over high voltage lines from generating plants to substations, including costs allocated by ISO-NE to maintain the wholesale electric market.
·
A stranded cost recovery charge (SCRC), which allows PSNH to recover its stranded costs, including above-market expenses incurred under mandated power purchase obligations and other long-term investments and obligations.
·
A system benefits charge (SBC), which funds energy efficiency programs for all customers as well as assistance programs for residential customers within certain income guidelines.
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·
An electricity consumption tax, which is a state mandated tax on electric energy consumption.
The energy charge and SCRC rates change semi-annually and are reconciled annually and differences between actual costs incurred versus current rates are either refunded or recovered in subsequent rates charged to customers.
PSNH distribution rates were set in a 2010 NHPUC rate case settlement, which expired on June 30, 2015. In the 2015 PSNH Settlement Agreement, the Company agreed that its present distribution rates will stay in effect until at least July 1, 2017. However, certain aspects of the 2010 rate case settlement will continue, including funding for reliability enhancement program activities, adjustment of distribution rates for certain exogenous events that in the aggregate exceed $1 million, and major storm reserve funding.
Generation Divestiture
In 2013, the NHPUC opened a docket to investigate market conditions affecting PSNH's default energy service rate, how PSNH will maintain just and reasonable rates in light of those conditions, and any impact of PSNH's generation ownership on the New Hampshire competitive electric market. In April 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. An abbreviated draft update by the consultant dated August 17, 2015, increased the estimated fair market value of PSNH’s generation assets to $235 million.
In 2014, 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 to determine whether all or some of PSNH's generation assets should be divested. 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.
On June 10, 2015, Eversource and PSNH entered into the 2015 Public Service Company of New Hampshire Restructuring and Rate Stabilization Agreement (the Agreement) with the New Hampshire Office of Energy and Planning, certain members of the NHPUC staff, the Office of Consumer Advocate, two state senators, and several other parties. The Agreement was filed with the NHPUC on the same day. Under the terms of the Agreement, PSNH has agreed to divest its generation assets upon NHPUC approval. The Agreement is designed to provide a resolution of issues pertaining to PSNH's generation assets in pending regulatory proceedings before the NHPUC. The Agreement provided for the Clean Air Project prudence proceeding to be resolved and all remaining Clean Air Project costs to be included in rates effective January 1, 2016. As part of the Agreement, PSNH has agreed to forego recovery of $25 million of the deferred equity return related to the Clean Air Project. In addition, PSNH will not seek a general distribution rate increase effective before July 1, 2017 and will contribute $5 million to create a clean energy fund, which will not be recoverable from its customers.
In 2015, the Legislature enacted changes to law to allow the use of securitization financing to recover any stranded costs resulting from the divestiture of PSNH’s generating assets. If the Agreement is approved, following divestiture of PSNH’s generating assets, bonds will be issued to recover resulting stranded costs.
On January 26, 2016, Advisory Staff of the NHPUC and the parties to the Agreement filed a stipulation with the NHPUC agreeing that near-term divestiture of PSNH’s generation was in the public interest and that the Agreement should be approved. Implementation of the Agreement is subject to NHPUC approval, which is expected in early 2016.
Sources and Availability of Electric Power Supply
During 2015, approximately 54 percent of PSNH's load was met through its own generation, long-term power supply provided pursuant to orders of the NHPUC, and contracts with competitive energy suppliers. The remaining 46 percentof PSNH's load was met by short-term (less than one year) purchases and spot purchases in the competitive New England wholesale power market. PSNH expects to meet its load requirements in 2016 in a similar manner. Included in the 54 percent above are PSNH's obligations to purchase power from approximately two dozen IPPs, the output of which it either uses to serve its customer load or sells into the ISO-NE market.
Merrimack and Schiller Stations have recently operated at lower than typical capacity factors due to moderate regional temperatures. The Hydro stations have been operating at high capacity factors. PSNH’s Energy Service Rate has been set at 9.99 cents per kWh effective January 1, 2016, which includes 1.27 cents per kWh reflecting full recovery of costs related to the Clean Air Project.
ELECTRIC TRANSMISSION SEGMENT
General
Each of CL&P, NSTAR Electric, PSNH and WMECO owns and maintains transmission facilities that are part of an interstate power transmission grid over which electricity is transmitted throughout New England. Each of CL&P, NSTAR Electric, PSNH and WMECO, and most other New England utilities, are parties to a series of agreements that provide for coordinated planning and operation of the region's transmission facilities and the rules by which they acquire transmission services. Under these arrangements, ISO-NE, a non-profit corporation whose board of directors and staff are independent of all market participants, serves as the regional transmission organization of the New England transmission system.
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Wholesale Transmission Revenues
A summary of Eversource Energy's wholesale transmission revenues is as follows:
| | |
(Thousands of Dollars) | | 2015 |
CL&P | $ | 513,025 |
NSTAR Electric | | 299,241 |
PSNH | | 127,509 |
WMECO | | 129,502 |
Total Wholesale Transmission Revenues | $ | 1,069,277 |
Wholesale Transmission Rates
Wholesale transmission revenues are recovered through FERC approved formula rates. Transmission revenues are collected from New England customers, the majority of which are distribution customers of CL&P, NSTAR Electric, PSNH and WMECO. The transmission rates provide for the annual reconciliation of estimated to actual costs. The financial impacts of differences between actual and estimated costs are deferred for future recovery from, or refunded to, transmission customers.
FERC Base ROE Complaints
Three separate complaints have been filed at the FERC by combinations of New England state attorneys general, state regulatory commissions, consumer advocates, consumer groups, municipal parties and other parties (the "Complainants"). In these three separate complaints, the Complainants challenged the NETOs' base ROE of 11.14 percent that had been utilized since 2006 and sought an order to reduce it prospectively from the date of the final FERC order and for the 15-month complaint refund periods stipulated in the separate complaints. In 2014, the FERC ordered a 10.57 percent base ROE for the first complaint refund period and prospectively from October 16, 2014 and that a utility's total or maximum ROE shall not exceed the top of the new zone of reasonableness, which was set at 11.74 percent. The NETOs and the Complainants sought rehearing from the FERC. In late 2014, the NETOs made a compliance filing and the Company began issuing refunds to customers from the first complaint period.
On March 3, 2015, FERC issued an order denying all issues raised on rehearing by the NETOs and Complainants in the first complaint. The FERC order upheld the base ROE of 10.57 percent for the first complaint refund period and prospectively from October 16, 2014, and upheld that the utility's total ROE (the base ROEplus anyincentive adders) for the transmission assets to which the adder applies is capped at the top of the zone of reasonableness, which is currently set at 11.74 percent. The NETOs and Complainants have filed appeals to the D.C. Circuit Court of Appeals, which have been consolidated, and briefing is scheduled to be concluded in the second quarter of 2016. A court decision is expected in late 2016.
For the second and third complaint proceedings, hearings were held in late June and early July 2015 and briefs were filed in July and August 2015. The state parties, municipal utilities and FERC trial staff each believe that the base ROE should be reduced to an amount lower than 10.57 percent. The NETOs believe that the Complainants' positions are without merit, and the existing base ROE of 10.57 is just and reasonable and should be maintained. On December 18, 2015, the FERC ALJ reopened the record to have the NETOs and FERC trial staff review certain calculations. The FERC ALJ’s initial recommendation is expected by March 31, 2016. A final FERC order is expected in late 2016 or early 2017.
Although Eversource is uncertain on the final outcome of the second and third complaints regarding the ROE, we believe the current reserves established are appropriate to reflect probable and reasonably estimable refunds. For further information, see "FERC Regulatory Issues – FERC ROE Complaints" in the accompanying Item 7,Management's Discussion and Analysis of Financial Condition and Results of Operations.
FERC Order No. 1000
On August 15, 2014, the D.C. Circuit Court of Appeals upheld the FERC's authority to order major changes to transmission planning and cost allocation in FERC Order No. 1000 and Order No. 1000-A, including transmission planning for public policy needs, and the requirement that utilities remove from their transmission tariffs their rights of first refusal to build transmission. On March 19, 2015, the FERC acted on all rehearing requests filed by the NETOs, including CL&P, NSTAR Electric, PSNH and WMECO, and other parties and accepted the November 2013 compliance filing made by ISO-NE and the NETOs, subject to further compliance. The FERC accepted our proposal that the new competitive transmission planning process will not apply to certain projects, which have been declared as the preferred solution by ISO-NE, unless ISO-NE later decides a solution must be re-evaluated. The FERC determined on rehearing that we can restore provisions that recognize the NETOs’ rights to retain use and control of their existing rights of ways. Final compliance was filed by the NETOs in November 2015 and was accepted by the FERC on December 14, 2015.
Additionally, the FERC affirmed that it can eliminate our right of first refusal to build transmission in New England even though the FERC previously approved and granted special protections to these rights. The NETOs filed an appeal to the D.C. Circuit Court of Appeals, challenging this FERC ruling. State regulators also filed an appeal, challenging FERC’s determination that ISO-NE should select public policy transmission projects after a competitive process. The Court is expected to resolve the appeals in 2016.
Transmission Projects
During 2015, we were involved in the planning, development and construction of a series of electric transmission projects, including the NEEWS family of projects; the Greater Hartford Central Connecticut (GHCC) solutions; and Greater Boston Reliability Solutions, which are a series of new transmission projects over the next five years that will enhance system reliability and improve capacity. We were involved in the planning and
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development of Northern Pass, which is our 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; and the Clean Energy Connect Project, which is a planned transmission, wind and hydro generation project that we intend to develop with experienced renewable generation companies. For further information, see "Business Development and Capital Expenditures – Electric Transmission Business" in the accompanying Item 7,Management's Discussion and Analysis of Financial Condition and Results of Operations.
Transmission Rate Base
Under our FERC-approved tariff, and with the exception of transmission projects that received specific FERC approval to include CWIP in rate base, transmission projects generally enter rate base after they are placed in commercial operation. At the end of 2015, our estimated transmission rate base was approximately $5.2 billion, including approximately $2.4 billion at CL&P, $1.4 billion at NSTAR Electric, $548 million at PSNH, and $625 million at WMECO.
NATURAL GAS DISTRIBUTION SEGMENT
NSTAR Gas distributes natural gas to approximately 286,000 customers in 51 communities in central and eastern Massachusetts covering 1,067 square miles, and Yankee Gas distributes natural gas to approximately 226,000 customers in 71 cities and towns in Connecticut covering 2,187 square miles. Total throughput (sales and transportation) in 2015 was approximately 71.7 Bcf for NSTAR Gas and 57.8 Bcf for Yankee Gas. Our natural gas businesses provide firm natural gas sales service to retail customers who require a continuous natural gas supply throughout the year, such as residential customers who rely on natural gas for heating, hot water and cooking needs, and commercial and industrial customers who choose to purchase natural gas from Eversource Energy's natural gas distribution companies. A portion of the storage of natural gas supply for NSTAR Gas during the winter heating season is provided by Hopkinton LNG Corp., an indirect, wholly-owned subsidiary of Eversource Energy. NSTAR Gas has access to Hopkinton LNG Corp. facilities in Hopkinton, Massachusetts consisting of a LNG liquefaction and vaporization plant and three above-ground cryogenic storage tanks having an aggregate capacity of 3.0 Bcf of liquefied natural gas. NSTAR Gas also has access to Hopkinton LNG Corp. facilities in Acushnet, Massachusetts that include additional storage capacity of 0.5 Bcf and additional vaporization capacity.
Yankee Gas owns a 1.2 Bcf LNG facility in Waterbury, Connecticut, which is used primarily to assist Yankee Gas in meeting its supplier-of-last-resort obligations and also enables it to provide economic supply and make economic refill of natural gas typically during periods of low demand.
NSTAR Gas and Yankee Gas generate revenues primarily through the sale and/or transportation of natural gas. Predominantly all residential customers in the NSTAR Gas service territory buy gas supply and delivery from NSTAR Gas while all customers may choose their natural gas suppliers. Retail natural gas service in Connecticut is partially unbundled: residential customers in Yankee Gas' service territory buy natural gas supply and delivery only from Yankee Gas while commercial and industrial customers may choose their natural gas suppliers. NSTAR Gas offers firm transportation service to all customers who purchase natural gas from sources other than NSTAR Gas while Yankee Gas offers firm transportation service to its commercial and industrial customers who purchase natural gas from sources other than Yankee Gas. In addition, both natural gas distribution companies offer interruptible transportation and interruptible natural gas sales service to those high volume commercial and industrial customers, generally during the colder months, that have the capability to switch from natural gas to an alternative fuel on short notice, for whom NSTAR Gas and Yankee Gas can interrupt service during peak demand periods or at any other time to maintain distribution system integrity.
The following table shows the sources of the 2015 total Eversource Energy natural gas franchise retail revenues based on categories of customers:
| | | | |
(Thousands of Dollars, except percentages) | | 2015 | | % of Total |
Residential | $ | 497,873 | | 54 |
Commercial | | 327,439 | | 36 |
Industrial | | 93,378 | | 10 |
Total Retail Natural Gas Revenues | $ | 918,690 | | 100% |
A summary of our firm natural gas sales volumes in million cubic feet and percentage changes for 2015, as compared to 2014, is as follows:
| | | | | |
| | | Percentage |
| 2015 | | 2014 | | Change |
Residential | 38,455 | | 38,969 | | (1.3)% |
Commercial | 43,006 | | 42,977 | | 0.1 % |
Industrial | 21,538 | | 22,245 | | (3.2)% |
Total | 102,999 | | 104,191 | | (1.1)% |
Total, Net of Special Contracts(1) | 98,458 | | 99,500 | | (1.0)% |
(1)
Special contracts are unique to the customers who take service under such an arrangement and generally specify the amount of distribution revenue to be paid to Yankee Gas regardless of the customers' usage.
Our firm natural gas sales volumes are subject to many of the same influences as our retail electric sales volumes. In addition, they have benefited from customer growth in both of our natural gas distribution companies. In 2015, consolidated firm natural gas sales volumes were lower, as compared to 2014. The 2015 firm natural gas sales volumes were negatively impacted by record warm weather in the fourth quarter of 2015, when compared to 2014, partially offset by colder winter weather in the first quarter of 2015, as compared to 2014, throughout our natural gas service territories. Weather-normalized Eversource consolidated firm natural gas sales volumes increased 2.5 percent in 2015, as compared to 2014, due primarily to improved economic conditions as well as residential and commercial customer growth, through conversions to natural gas service.
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Rates
NSTAR Gas and Yankee Gas are subject to regulation by the DPU and the PURA, respectively, which, among other things, have jurisdiction over rates, certain dispositions of property and plant, mergers and consolidations, issuances of long-term securities, standards of service and construction and operation of facilities. Both of Eversource Energy's natural gas companies are entitled under their respective state law to charge rates that are sufficient to allow them an opportunity to recover their reasonable operating and capital costs, in order to attract needed capital and maintain their financial integrity, while also protecting relevant public interests.
Retail natural gas delivery and supply rates are established by the DPU and the PURA and are comprised of:
·
A distribution charge consisting of a fixed customer charge and a demand and/or energy charge that collects the costs of building and expanding the natural gas infrastructure to deliver natural gas supply to its customers. This also includes collection of ongoing operating costs;
·
A seasonal cost of gas adjustment clause (CGAC) at NSTAR Gas that collects natural gas supply costs, pipeline and storage capacity costs, costs related to charge-offs of uncollected energy costs and working capital related costs. The CGAC is reset semi-annually. In addition, NSTAR Gas files interim changes to its CGAC factor when the actual costs of natural gas supply vary from projections by more than five percent; and
·
A local distribution adjustment clause (LDAC) at NSTAR Gas that collects all energy efficiency and related program costs, environmental costs, pension and PBOP related costs, attorney general consultant costs, and costs associated with low income customers. The LDAC is reset annually and provides for the recovery of certain costs applicable to both sales and transportation customers.
·
Purchased Gas Adjustment (PGA) clause, which allows Yankee Gas to recover the costs of the procurement of natural gas for its firm and seasonal customers. Differences between actual natural gas costs and collection amounts on August 31st of each year are deferred and then recovered from or refunded to customers during the following year. Carrying charges on outstanding balances are calculated using Yankee Gas' weighted average cost of capital in accordance with the directives of the PURA; and
·
Conservation Adjustment Mechanism (CAM) at Yankee Gas, which allows 100 percent recovery of conservation costs through this mechanism including program incentives to promote energy efficiency, as well as recovery of any lost revenues associated with implementation of energy conservation measures. A reconciliation of CAM revenues to expenses is performed annually with any difference being recovered from or refunded to customers, with carrying charges, during the following year.
NSTAR Gas purchases financial contracts based on NYMEX natural gas futures in order to reduce cash flow variability associated with the purchase price for approximately one-third of its natural gas purchases. These purchases are made under a program approved by the DPU in 2006. This practice attempts to minimize the impact of fluctuations in natural gas prices to NSTAR Gas' firm natural gas customers. These financial contracts do not procure natural gas supply. All costs incurred or benefits realized when these contracts are settled are included in the CGAC.
NSTAR Gas is subject to service quality (SQ) metrics that measure safety, reliability and customer service and could be required to pay to customers a SQ charge of up to 2.5 percent of annual distribution revenues for failing to meet such metrics. NSTAR Gas will not be required to pay a SQ charge for its 2015 performance as it achieved results at or above target for all of its SQ metrics in 2015.
On October 30, 2015, the DPU issued its order in the NSTAR Gas distribution rate case, which approved an annualized base rate increase of $15.8 million, plus other increases of approximately $11.5 million, mostly relating to recovery of pension and PBOP expenses and the Hopkinton Gas Service Agreement, effective January 1, 2016. In the order, the DPU also approved an authorized regulatory ROE of 9.8 percent, the establishment of a revenue decoupling mechanism, the recovery of certain bad debt expenses, and a 52.1 percent equity component of its capital structure. On November 19, 2015, NSTAR Gas filed a motion for reconsideration of the order with the DPU seeking the correction of mathematical errors and other plant and cost of service items.
Yankee Gas’ last rate proceeding was in 2011, which approved an allowed ROE of 8.83 percent and allowed for a substantial increase in annual spending for bare steel and cast iron pipeline replacement. In 2015, Yankee Gas entered into a settlement agreement with the PURA staff pursuant to which Yankee Gas provided a $1.5 million rate credit to firm customers beginning in December 2015, and established an earnings sharing mechanism whereby Yankee Gas and its customers will share equally in any earnings exceeding a 9.5 percent ROE in a twelve month period commencing with the period from April 1, 2015 through March 31, 2016.
Massachusetts Natural Gas Replacement and Expansion
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.
In October 2014, pursuant to the Act, NSTAR Gas filed the Gas System Enhancement Program (GSEP) with the DPU. NSTAR Gas' program accelerates the replacement of certain natural gas distribution facilities in the system to within 25 years. The GSEP includes a new tariff effective January 1, 2016 that provides NSTAR Gas an opportunity to collect the costs for the program on an annual basis through a newly designed
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reconciling factor. On April 30, 2015, the DPU approved the GSEP. We expect capital expenditures of approximately $255 million for the period 2016 through 2019 for the GSEP.
Connecticut Natural Gas Expansion Plan
In 2013, in accordance with Connecticut law and regulations, the PURA approved a comprehensive joint natural gas infrastructure expansion plan (expansion plan) filed by Yankee Gas and other Connecticut natural gas distribution companies. The expansion plan described how Yankee Gas expects to add approximately 82,000 new natural gas heating customers over a 10-year period. Yankee Gas estimates that its portion of the plan will cost approximately $700 million over 10 years. In January 2015, the PURA approved a joint settlement agreement proposed by Yankee Gas and other Connecticut natural gas distribution companies and regulatory agencies that clarified the procedures and oversight criteria applicable to the expansion plan. On March 20, 2015, Yankee Gas filed its initial System Expansion (SE) Rate reconciliation for 2014. The proposed SE rate was approved by the PURA for implementation as of April 1, 2015, pending final PURA approval following a contested hearing.
Sources and Availability of Natural Gas Supply
NSTAR Gas maintains a flexible resource portfolio consisting of natural gas supply contracts, transportation contracts on interstate pipelines, market area storage and peaking services. NSTAR Gas purchases transportation, storage, and balancing services from Tennessee Gas Pipeline Company and Algonquin Gas Transmission Company, as well as other upstream pipelines that transport gas from major producing regions in the U.S., including the Gulf Coast, Mid-continent region, and Appalachian Shale supplies to the final delivery points in the NSTAR Gas service area. NSTAR Gas purchases all of its natural gas supply under a firm portfolio management contract with a term of one year, which has a maximum quantity of approximately 154,700 MMBtu/day of firm flowing natural gas supplies and 76,700 MMBtu/day of firm natural gas storage supplies.
In addition to the firm transportation and natural gas supplies mentioned above, NSTAR Gas utilizes contracts for underground storage and LNG facilities to meet its winter peaking demands. The LNG facilities, described below, are located within NSTAR Gas' distribution system and are used to liquefy and store pipeline natural gas during the warmer months for vaporization and use during the heating season. During the summer injection season, excess pipeline capacity and supplies are used to deliver and store natural gas in market area underground storage facilities located in the New York and Pennsylvania regions. Stored natural gas is withdrawn during the winter season to supplement flowing pipeline supplies in order to meet firm heating demand. NSTAR Gas has firm underground storage contracts and total storage capacity entitlements of approximately 6.6 Bcf.
A portion of the storage of natural gas supply for NSTAR Gas during the winter heating season is provided by Hopkinton LNG Corp., which owns an LNG liquefaction and vaporization plant and three above-ground cryogenic storage tanks having an aggregate capacity of 3.0 Bcf of liquefied natural gas. NSTAR Gas also has access to Hopkinton LNG Corp. facilities that include additional storage capacity of 0.5 Bcf and additional vaporization capacity.
The PURA requires that Yankee Gas meet the needs of its firm customers under all weather conditions. Specifically, Yankee Gas must structure its supply portfolio to meet firm customer needs under a design day scenario (defined as the coldest day in 30 years) and under a design year scenario (defined as the average of the four coldest years in the last 30 years). Yankee Gas' on-system stored LNG and underground storage supplies help to meet consumption needs during the coldest days of winter. Yankee Gas obtains its interstate capacity from the three interstate pipelines that directly serve Connecticut: the Algonquin, Tennessee and Iroquois Pipelines. Yankee Gas has long-term firm contracts for capacity on TransCanada Pipelines Limited Pipeline, Vector Pipeline, L.P., Tennessee Gas Pipeline, Iroquois Gas Transmission Pipeline, Algonquin Pipeline, Union Gas Limited, Dominion Transmission, Inc., National Fuel Gas Supply Corporation, Transcontinental Gas Pipeline Company, and Texas Eastern Transmission, L.P. pipelines.
Based on information currently available regarding projected growth in demand and estimates of availability of future supplies of pipeline natural gas, NSTAR Gas and Yankee Gas each believes that participation in planned and anticipated pipeline and storage expansion projects will be required in order for it to meet current and future sales growth opportunities.
NATURAL GAS PIPELINE EXPANSION
Access Northeast is a natural gas pipeline and storage project (the "Project") being developed jointly by Eversource, Spectra Energy Corp and National Grid. Access Northeast will enhance the Algonquin and Maritimes & Northeast pipeline systems using existing routes and will include two new LNG storage tanks and liquefaction and vaporization facilities in Acushnet, Massachusetts that will be connected to the Algonquin gas pipeline. The Project is expected to be capable of delivering approximately 900 million cubic feet of additional natural gas per day to New England on peak demand days. Eversource and Spectra Energy Corp each own a 40 percent interest in the Project, with the remaining 20 percent interest owned by National Grid. The total projected cost for both the pipeline and the LNG storage is expected to be approximately $3 billion with anticipated in-service dates commencing in November 2018. The Project is subject to FERC and other federal and state regulatory approvals. On November 17, 2015, the FERC accepted the Project’s request to initiate the pre-filing review process. Upon completion of the pre-filing review, a certificate application will be filed with the FERC. In late 2015, the Project bid into the New England Natural Gas Pipeline Capacity RFP conducted by certain EDCs in Massachusetts and Rhode Island, including NSTAR Electric and WMECO in Massachusetts, and in December 2015 and January 2016, those Massachusetts EDCs filed with the DPU seeking approval of the contracts for pipeline and storage capacity with the Project. We expect the Rhode Island EDC to file its selected contracts with the Rhode Island regulatory agencies in the first half of 2016. In February 2016, PSNH filed for approval with the NHPUC, of its proposed contract for natural gas pipeline capacity and storage with the Project.
PROJECTED CAPITAL EXPENDITURES
We project to make capital expenditures of approximately $9.2 billion from 2016 through 2019. Of the $9.2 billion, we expect to invest approximately $4.9 billion in our electric and natural gas distribution segments and $3.9 billion in our electric transmission segment. In addition, we
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project to invest approximately $0.4 billion in information technology and facilities upgrades and enhancements. These projections do not include capital expenditures related to Access Northeast or Clean Energy Connect.
FINANCING
Our credit facilities and indentures require that Eversource Energy parent and certain of its subsidiaries, including CL&P, NSTAR Electric, NSTAR Gas, PSNH, WMECO and Yankee Gas, comply with certain financial and non-financial covenants as are customarily included in such agreements, including maintaining a ratio of consolidated debt to total capitalization of no more than 65 percent. All of these companies currently are, and expect to remain, in compliance with these covenants.
As of December 31, 2015, a total of $200 million of Eversource’s long-term debt, all at NSTAR Electric, will be paid in the next 12 months.
NUCLEAR FUEL STORAGE
CL&P, NSTAR Electric, PSNH, WMECO and several other New England electric utilities are stockholders in three inactive regional nuclear generation companies, CYAPC, MYAPC and YAEC (collectively, the Yankee Companies). The Yankee Companies have completed the physical decommissioning of their respective generation facilities and are now engaged in the long-term storage of their spent nuclear fuel. The Yankee Companies have completed collection of their decommissioning and closure costs through the proceeds from the spent nuclear fuel litigation against the DOE and has refunded amounts to its member companies. These proceeds were used by the Yankee Companies to offset the decommissioning and closure cost amounts due from their member companies or to decrease the wholesale FERC-approved rates charged under power purchase agreements with CL&P, NSTAR Electric, PSNH and WMECO and several other New England utilities. The decommissioning rates charged by the Yankee Companies have been reduced to zero. CL&P, NSTAR Electric, PSNH and WMECO can recover these costs from, or refund proceeds to, their customers through state regulatory commission-approved retail rates.
We consolidate the assets and obligations of CYAPC and YAEC on our consolidated balance sheet because we own more than 50 percent of these companies.
For information on the DOE proceeds received related to the spent nuclear fuel litigation, see Note 11C, "Commitments and Contingencies – Contractual Obligations – Yankee Companies," in the accompanying Item 8,Financial Statements and Supplementary Data.
OTHER REGULATORY AND ENVIRONMENTAL MATTERS
General
We are regulated in virtually all aspects of our business by various federal and state agencies, including FERC, the SEC, and various state and/or local regulatory authorities with jurisdiction over the industry and the service areas in which each of our companies operates, including the PURA, which has jurisdiction over CL&P and Yankee Gas, the NHPUC, which has jurisdiction over PSNH, and the DPU, which has jurisdiction over NSTAR Electric, NSTAR Gas and WMECO.
Environmental Regulation
We are subject to various federal, state and local requirements with respect to water quality, air quality, toxic substances, hazardous waste and other environmental matters. Additionally, major generation and transmission facilities may not be constructed or significantly modified without a review of the environmental impact of the proposed construction or modification by the applicable federal or state agencies.
Water Quality Requirements
The Clean Water Act requires every "point source" discharger of pollutants into navigable waters to obtain a National Pollutant Discharge Elimination System (NPDES) permit from the EPA or state environmental agency specifying the allowable quantity and characteristics of its effluent. States may also require additional permits for discharges into state waters. We are in the process of maintaining or renewing all required NPDES or state discharge permits in effect for PSNH's generation facilities.
In 1997, PSNH filed in a timely manner for a renewal of the NPDES permit for the Merrimack Station. As a result, the existing permit was administratively continued. In 2011, the EPA issued a draft renewal NPDES permit for PSNH's Merrimack Station for public review and comment. The proposed permit contains many significant conditions to future operation. The proposed permit would require PSNH to install a closed-cycle cooling system (including cooling towers) at the station. The EPA estimated that the net present value cost to install this system and operate it over a 20-year period would be approximately $112 million. PSNH and other electric utility groups filed thousands of pages of comments contesting EPA's draft permit requirements. PSNH stated that the data and studies supplied to the EPA demonstrate the fact that a closed-cycle cooling system is not warranted. On April 18, 2015 EPA issued a revised section of the draft NPDES permit for Merrimack Station. The revised portion of the draft permit deals solely with the treatment of wastewater from the flue gas desulfurization system. On August 18, 2015 PSNH again submitted comments. The EPA does not have a set deadline to consider comments and to issue a final permit. Merrimack Station is permitted to continue to operate under its present permit pending issuance of the final permit and subsequent resolution of matters appealed by PSNH and other parties. Due to the site specific characteristics of PSNH's other coal- and oil-fired electric generating stations, we believe it is unlikely that they would face similar permitting determinations.
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Air Quality Requirements
The Clean Air Act Amendments (CAAA), as well as New Hampshire law, impose stringent requirements on emissions of SO2 and NOX for the purpose of controlling acid rain and ground level ozone. In addition, the CAAA address the control of toxic air pollutants. Requirements for the installation of continuous emissions monitors and expanded permitting provisions also are included.
In 2011, the EPA finalized the Mercury and Air Toxic Standards (MATS) that require the reduction of emissions of hazardous air pollutants from new and existing coal- and oil-fired electric generating stations. Previously referred to as the Utility MACT (maximum achievable control technology) rules, it establishes emission limits for mercury, arsenic and other hazardous air pollutants from coal- and oil-fired electric generating stations. MATS is the first implementation of a nationwide emissions standard for hazardous air pollutants across all electric generating units and provides utility companies with up to five years to meet the requirements. PSNH owns and operates approximately 1,000 MW of coal- and oil-fired electric generating stations subject to MATS, including the two units at Merrimack Station, Newington Station and the two coal units at Schiller Station. We believe the Clean Air Project at our Merrimack Station, together with existing equipment, will enable the facility to meet the MATS requirements. At Schiller Station additional controls are being installed at the two coal-fired units, the cost of which is estimated to be approximately $2.5 million.
Each of the states in which we do business also has Renewable Portfolio Standards (RPS) requirements, which generally require fixed percentages of our energy supply to come from renewable energy sources such as solar, hydropower, landfill gas, fuel cells and other similar sources.
New Hampshire's RPS provision requires increasing percentages of the electricity sold to retail customers to have direct ties to renewable sources. In 2015, the total RPS obligation was 8.3 percent and it will ultimately reach 24.8 percent in 2025. Energy suppliers, like PSNH, must possess sufficient quantities of RECs to satisfy the RPS requirements. PSNH owns renewable sources and uses a portion of internally generated RECs to meet its RPS obligations and sells other internally generated RECs when it is economically beneficial to do so. To the extent that a supplier, like PSNH, does not possess sufficient RECs to satisfy its RPS requirements, it makes up any shortfall by making an alternative compliance payment at a rate per REC established by law. The costs of both the RECs and alternative compliance payments are recovered by PSNH through its default energy service rates charged to customers.
Similarly, Connecticut's RPS statute requires increasing percentages of the electricity sold to retail customers to have direct ties to renewable sources. In 2015, the total RPS obligation was 19.5 percentand will ultimately reach 27 percent in 2020. CL&P is permitted to recover any costs incurred in complying with RPS from its customers through its GSCrate.
Massachusetts' RPS program also requires electricity suppliers to meet renewable energy standards. For 2015, the requirement was 19.25 percent, and will ultimately reach 22.1 percent in 2020. NSTAR Electric and WMECO are permitted to recover any costs incurred in complying with RPS from its customers through rates. WMECO also owns renewable solar generation resources. The RECs generated from WMECO's solar units are sold to other energy suppliers, and the proceeds from these sales are credited back to customers.
Hazardous Materials Regulations
We have recorded a liability for what we believe, based upon currently available information, is our reasonably estimable environmental investigation, remediation, and/or Natural Resource Damages costs for waste disposal sites for which we have probable liability. Under federal and state law, government agencies and private parties can attempt to impose liability on us for recovery of investigation and remediation costs at hazardous waste sites. As of December 31, 2015, the liability recorded for our reasonably estimable and probable environmental remediation costs for known sites needing investigation and/or remediation, exclusive of recoveries from insurance or from third parties, was approximately $51.1 million, representing 64 sites. These costs could be significantly higher if additional remediation becomes necessary or when additional information as to the extent of contamination becomes available.
The most significant liabilities currently relate to future clean-up costs at former MGP facilities. These facilities were owned and operated by our predecessor companies from the mid-1800's to mid-1900's. By-products from the manufacture of gas using coal resulted in fuel oils, hydrocarbons, coal tar, purifier wastes, metals and other waste products that may pose risks to human health and the environment. We currently have partial or full ownership responsibilities at former MGP sites that have a reserve balance of $45.5 million of the total $51.1 million as of December 31, 2015. Many of these MGP costs are recoverable from customers through our rates.
Electric and Magnetic Fields
For more than twenty years, published reports have discussed the possibility of adverse health effects from electric and magnetic fields (EMF) associated with electric transmission and distribution facilities and appliances and wiring in buildings and homes. Although weak health risk associations reported in some epidemiology studies remain unexplained, most researchers, as well as numerous scientific review panels, considering all significant EMF epidemiology and laboratory studies, have concluded that the available body of scientific information does not support the conclusion that EMF affects human health.
In accordance with recommendations of various regulatory bodies and public health organizations, we reduce EMF associated with new transmission lines by the use of designs that can be implemented without additional cost or at a modest cost. We do not believe that other capital expenditures are appropriate to minimize unsubstantiated risks.
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Global Climate Change and Greenhouse Gas Emission Issues
Global climate change and greenhouse gas emission issues have received an increased focus from state governments and the federal government. The EPA initiated a rulemaking addressing greenhouse gas emissions and, on December 7, 2009, issued a finding that concluded that greenhouse gas emissions are "air pollution" that endangers public health and welfare and should be regulated. The largest source of greenhouse gas emissions in the U.S. is the electricity generating sector. The EPA has mandated greenhouse gas emission reporting beginning in 2011 for emissions for certain aspects of our business including stationary combustion, volume of gas supplied to large customers and fugitive emissions of SF6 gas and methane.
We are continually evaluating the regulatory risks and regulatory uncertainty presented by climate change concerns. Such concerns could potentially lead to additional rules and regulations that impact how we operate our business, both in terms of the generating facilities we own and operate as well as general utility operations. These could include federal "cap and trade" laws, carbon taxes, fuel and energy taxes, or regulations requiring additional capital expenditures at our generating facilities. We expect that any costs of these rules and regulations would be recovered from customers.
Connecticut, New Hampshire and Massachusetts are each members of the Regional Greenhouse Gas Initiative (RGGI), a cooperative effort by nine northeastern and mid-Atlantic states, to develop a regional program for stabilizing and reducing CO2 emissions from coal- and oil-fired electric generating plants. Because CO2 allowances issued by any participating state are usable across all nine RGGI state programs, the individual state CO2 trading programs, in the aggregate, form one regional compliance market for CO2 emissions. The third three-year control period took effect on January 1, 2015 and extends through December 31, 2017. In this control period, each regulated power plant must hold CO2 allowances equal to 50 percent of its emissions during each of the first two years of the three-year period, and hold CO2 allowances equal to 100 percent of its remaining emissions for the three-year control period at the end of the period.
PSNH anticipates that its generating units will emit between one million and three million tons of CO2 per year, depending on the capacity factor and the utilization of the respective generation plant, excluding emissions from the operation of PSNH's Northern Wood Power Project, which emissions are an offset. PSNH satisfied its RGGI requirements by purchasing CO2 allowances at auction. The cost of complying with RGGI requirements is recoverable from PSNH customers. Current legislation provides that the portion of the RGGI auction proceeds in excess of $1 per allowance will be refunded to customers.
Because none of Eversource Energy's other subsidiaries, CL&P, NSTAR Electric or WMECO, currently owns any generating assets (other than WMECO's solar photovoltaic facilities that do not emit CO2), none of them is required to acquire CO2 allowances. However, the CO2 allowance costs borne by the generating facilities that are utilized by wholesale energy suppliers to satisfy energy supply requirements to CL&P, NSTAR Electric and WMECO are likely to be included in the overall wholesale rates charged, which costs are then recoverable from customers.
FERC Hydroelectric Project Licensing
Federal Power Act licenses may be issued for hydroelectric projects for terms of 30 to 50 years as determined by the FERC. Upon the expiration of an existing license, (i) the FERC may issue a new license to the existing licensee, (ii) the United States may take over the project, or (iii) the FERC may issue a new license to a new licensee, upon payment to the existing licensee of the lesser of the fair value or the net investment in the project, plus severance damages, less certain amounts earned by the licensee in excess of a reasonable rate of return.
PSNH currently owns nine hydroelectric generating stations with a current claimed capability representing winter rates of approximately 71 MW, eight of which are licensed by the FERC under long-term licenses that expire on varying dates from 2017 through 2047. PSNH and its hydroelectric projects are subject to conditions set forth in such licenses, the Federal Power Act and related FERC regulations, including provisions related to the condemnation of a project upon payment of just compensation, amortization of project investment from excess project earnings, possible takeover of a project after expiration of its license upon payment of net investment and severance damages and other matters. PSNH is currently completing the relicensing application for its 6.5 MW Eastman Falls Hydro Station, the license for which expires in 2017.
EMPLOYEES
As of December 31, 2015, Eversource Energy employed a total of 7,943 employees, excluding temporary employees, of which 1,037 were employed by CL&P, 1,240 were employed by NSTAR Electric, 694 were employed by PSNH, and 291 were employed by WMECO. Approximately 50 percent of our employees are members of the International Brotherhood of Electrical Workers, the Utility Workers Union of America or The United Steelworkers, and are covered by 14 collective bargaining agreements.
INTERNET INFORMATION
Our website address is www.eversource.com. We make available through our website a link to the SEC's EDGAR website (http://www.sec.gov/edgar/searchedgar/companysearch.html), at which site Eversource Energy's, CL&P's, NSTAR Electric's, PSNH's and WMECO's Annual Reports on Form 10-K, Quarterly Reports on Form 10-Q, Current Reports on Form 8-K and any amendments to those reports may be reviewed. Information contained on the Company's website or that can be accessed through the website is not incorporated into and does not constitute a part of this Annual Report on Form 10-K. Printed copies of these reports may be obtained free of charge by writing to our Investor Relations Department at Eversource Energy, 107 Selden Street, Berlin, CT 06037.
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Item 1A.
Risk Factors
In addition to the matters set forth under "Safe Harbor Statement Under the Private Securities Litigation Reform Act of 1995" included immediately prior to Item 1,Business, above, we are subject to a variety of significant risks. Our susceptibility to certain risks, including those discussed in detail below, could exacerbate other risks. These risk factors should be considered carefully in evaluating our risk profile.
Cyber breaches, acts of war or terrorism, or grid disturbances could negatively impact our business.
Cyber breaches, acts of war or terrorism, physical attacks or grid disturbances resulting from internal or external sources could target our transmission, distribution and generation facilities or our information technology systems. Such actions could impair our ability to manage these facilities, operate our systems effectively, or properly manage our data, networks and programs, resulting in loss of service to customers.
We have instituted safeguards to protect our operational systems and information technology assets. We devote substantial resources to network and application security, encryption and other measures to protect our computer systems and infrastructure from unauthorized access or misuse and interface with numerous external entities to improve our cybersecurity situational awareness. FERC, through the North American Electric Reliability Corporation, requires certain safeguards to be implemented to deter cyber and/or physical attacks. These safeguards may not always be effective due to the evolving nature of cyber and/or physical attacks.
Because our generation and transmission facilities are part of an interconnected regional grid, we face the risk of blackout due to a disruption on a neighboring interconnected system.
Any such cyber breaches, acts of war or terrorism, physical attacks or grid disturbances could result in a significant decrease in revenues, significant expense to repair system damage or security breaches, and liability claims, which could have a material adverse impact on our financial position, results of operations or cash flows.
Strategic development opportunities in both electric and natural gas transmission may not be successful and projects may not commence operation as scheduled or be completed, which could have a material adverse effect on our business prospects.
We are pursuing broader strategic development investment opportunities that will benefit the New England region related to the construction of electric and natural gas transmission facilities, interconnections to generating resources and other investment opportunities. The development, construction and expansion of electric transmission and natural gas transmission facilities involve numerous risks. Various factors could result in increased costs or result in delays or cancellation of these projects. Risks include regulatory approval processes, new legislation, economic events or factors, environmental and community concerns, design and siting issues, difficulties in obtaining required rights of way, competition from incumbent utilities and other entities, and actions of strategic partners. Should any of these factors result in such delays or cancellations, our financial position, results of operations, and cash flows could be adversely affected or our future growth opportunities may not be realized as anticipated.
As a result of legislative and regulatory changes during 2015, the states in which we provide service have implemented new procedures to select for construction new major electric transmission and gas pipeline facilities. These procedures require the review of competing projects and permit the selection of only those projects that are expected to provide the greatest benefit to customers. If the projects in which we have invested are not selected for construction, it would have a material adverse effect on our future financial position, results of operations and cash flows.
The actions of regulators and legislators can significantly affect our earnings, liquidity and business activities.
The rates that our electric and gas companies charge their customers are determined by their state regulatory commissions and by FERC. These commissions also regulate the companies' accounting, operations, the issuance of certain securities and certain other matters. FERC also regulates the transmission of electric energy, the sale of electric energy at wholesale, accounting, issuance of certain securities and certain other matters.
Under state and federal law, our electric and gas companies are entitled to charge rates that are sufficient to allow them an opportunity to recover their reasonable operating and capital costs, to attract needed capital and maintain their financial integrity, while also protecting relevant public interests. Each of these companies prepares and submits periodic rate filings with their respective regulatory commissions for review and approval.
The FERC has jurisdiction over our transmission costs recovery and the allowed return on equity. The ROE has been contested by outside parties as unjust and unreasonable. Certain outside parties have filed three complaints against all electric companies under the jurisdiction of ISO-NE alleging that the ROE is unjust and unreasonable. The first complaint, which was concluded in 2015, resulted in a decrease of the allowed ROE. The second and third complaints are currently under review with the FERC. The FERC has initiated a review of the regional and local transmission rates due to a lack of adequate transparency. FERC also found that the formula rates generally lacked sufficient details to determine how costs are derived and recovered in rates.
A federal appeals court decision has upheld the FERC's authority to order major changes to transmission planning and cost allocation in FERC Order No. 1000 and Order No. 1000-A, including transmission planning for public policy needs, and the requirement that utilities remove from their transmission tariffs their rights of first refusal to build transmission. Additionally, the FERC affirmed that it can eliminate our right of first refusal to build transmission in New England even though the FERC previously approved and granted special protections to these rights. Implementation of FERC's goals in New England, including within our service territories, may expose us to competition for construction of transmission projects, additional regulatory considerations, and potential delay with respect to future transmission projects, which may adversely affect our results of operation.
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There is no assurance that the commissions will approve the recovery of all costs incurred by our electric and gas companies, including costs for construction, operation and maintenance, as well as a reasonable return on their respective regulated assets. The amount of costs incurred by the companies, coupled with increases in fuel and energy prices, could lead to consumer or regulatory resistance to the timely recovery of such costs, thereby adversely affecting our financial position, results of operations or cash flows.
If our settlement agreement regarding the divestiture of our generation assets in New Hampshire is not approved, it could have a material adverse effect on our earnings.
Under our settlement agreement for the divestiture of our generation assets in New Hampshire, we will be entitled to collect from customers an amount equal to the difference between the proceeds from the sale of these assets and the undepreciated book value of those assets. Costs related to the divestiture would also be recoverable. To minimize the financial impact on customers in New Hampshire, the legislature passed legislation that allows for the securitization of stranded costs to be recovered. If the NHPUC does not approve the settlement, we may not be able to fully recover these costs in future rate proceedings, which could have a material adverse effect on our financial position, results of operations and cash flows.
Our transmission, distribution and generation systems may not operate as expected, and could require unplanned expenditures, which could adversely affect our financial position, results of operations and cash flows.
Our ability to properly operate our transmission, distribution and generation systems is critical to the financial performance of our business. Our transmission, distribution and generation businesses face several operational risks, including the breakdown, failure of, or damage to operating equipment, information technology systems, or processes, especially due to age; labor disputes; disruptions in the delivery of electricity and natural gas, including impacts on us or our customers; increased capital expenditure requirements, including those due to environmental regulation; catastrophic events such as fires, explosions, or other similar occurrences; extreme weather conditions beyond equipment and plant design capacity; other unanticipated operations and maintenance expenses and liabilities; and potential claims for property damage or personal injuries beyond the scope of our insurance coverage. Many of our transmission projects are expected to alleviate identified reliability issues and reduce customers' costs. However, if the in-service date for one or more of these projects is delayed due to economic events or factors, or regulatory or other delays, the risk of failures in the electricity transmission system may increase. Any failure of our transmission, distribution and generation systems to operate as planned may result in increased capital costs, reduced earnings or unplanned increases in operation and maintenance costs. Outages at generating stations may be deemed imprudent by the NHPUC resulting in disallowance of replacement power and repair costs. Such costs that are not recoverable from our customers would have an adverse effect on our financial position, results of operations and cash flows.
Increases in electric and gas prices and/or a weak economy can lead to changes in legislative and regulatory policy promoting increased energy efficiency, conservation, and self-generation and/or a reduction in our customers' ability to pay their bills, which may adversely impact our business.
Energy consumption is significantly impacted by the general level of economic activity and cost of energy supply. Economic downturns or periods of high energy supply costs typically can lead to the development of legislative and regulatory policy designed to promote reductions in energy consumption and increased energy efficiency and self-generation by customers. This focus on conservation, energy efficiency and self-generation may result in a decline in electricity and natural gas sales in our service territories. Economic downturns or periods of high energy supply costs can also impact customers’ ability to pay their energy bills, resulting in increased bad debt expense. If energy use were to decline or bad debt expense were to increase, without corresponding adjustments in rates at our electric and gas companies that do not currently have revenue decoupling, then our revenues would be reduced, which would have an adverse effect on our financial position, results of operations and cash flows.
Severe storms could cause significant damage to any of our facilities requiring extensive expenditures, the recovery for which is subject to approval by regulators.
Severe weather, such as ice and snow storms, hurricanes and other natural disasters, may cause outages and property damage, which may require us to incur additional costs that may not be recoverable from customers. The cost of repairing damage to our operating subsidiaries' facilities and the potential disruption of their operations due to storms, natural disasters or other catastrophic events could be substantial, particularly as regulators and customers demand better and quicker response times to outages. If, upon review, any of our state regulatory authorities finds that our actions were imprudent, some of those restoration costs may not be recoverable from customers. The inability to recover a significant amount of such costs could have an adverse effect on our financial position, results of operations and cash flows.
Our goodwill is valued and recorded at an amount that, if impaired and written down, could adversely affect our future operating results and total capitalization.
We have a significant amount of goodwill on our consolidated balance sheet. As of December 31, 2015, goodwill totaled $3.5 billion. The carrying value of goodwill represents the fair value of an acquired business in excess of identifiable assets and liabilities as of the acquisition date. We test our goodwill balances for impairment on an annual basis or whenever events occur or circumstances change that would indicate a potential for impairment. A determination that goodwill is deemed to be impaired would result in a non-cash charge that could materially adversely affect our financial position, results of operations and total capitalization. The annual goodwill impairment test in 2015 resulted in a conclusion that our goodwill is not impaired.
Eversource Energy and its utility subsidiaries are exposed to significant reputational risks, which make them vulnerable to increased regulatory oversight or other sanctions.
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Because utility companies, including our electric and natural gas utility subsidiaries, have large customer bases, they are subject to adverse publicity focused on the reliability of their distribution services and the speed with which they are able to respond to electric outages, natural gas leaks and similar interruptions caused by storm damage or other unanticipated events. Adverse publicity of this nature could harm the reputations of Eversource Energy and its subsidiaries; may make state legislatures, utility commissions and other regulatory authorities less likely to view Eversource Energy and its subsidiaries in a favorable light; and may cause Eversource Energy and its subsidiaries to be subject to less favorable legislative and regulatory outcomes or increased regulatory oversight. Unfavorable regulatory outcomes can include more stringent laws and regulations governing our operations, such as reliability and customer service quality standards or vegetation management requirements, as well as fines, penalties or other sanctions or requirements. The imposition of any of the foregoing could have a material adverse effect on the business, results of operations, cash flow and financial condition of Eversource Energy and each of its utility subsidiaries.
Limits on our access to and increases in the cost of capital may adversely impact our ability to execute our business plan.
We use short-term debt and the long-term capital markets as a significant source of liquidity and funding for capital requirements not obtained from our operating cash flow. If access to these sources of liquidity becomes constrained, our ability to implement our business strategy could be adversely affected. In addition, higher interest rates would increase our cost of borrowing, which could adversely impact our results of operations. A downgrade of our credit ratings or events beyond our control, such as a disruption in global capital and credit markets, could increase our cost of borrowing and cost of capital or restrict our ability to access the capital markets and negatively affect our ability to maintain and to expand our businesses.
Our counterparties may not meet their obligations to us or may elect to exercise their termination rights, which could adversely affect our earnings.
We are exposed to the risk that counterparties to various arrangements who owe us money, have contracted to supply us with energy, coal, or other commodities or services, or who work with us as strategic partners, including on significant capital projects, will not be able to perform their obligations, will terminate such arrangements or, with respect to our credit facilities, fail to honor their commitments. Should any of these counterparties fail to perform their obligations or terminate such arrangements, we might be forced to replace the underlying commitment at higher market prices and/or have to delay the completion of, or cancel a capital project. Should any lenders under our credit facilities fail to perform, the level of borrowing capacity under those arrangements could decrease. In any such events, our financial position, results of operations, or cash flows could be adversely affected.
The unauthorized access to and the misappropriation of confidential and proprietary customer, employee, financial or system operating information could adversely affect our business operations and adversely impact our reputation.
In the regular course of business we maintain sensitive customer, employee, financial and system operating information and are required by various federal and state laws to safeguard this information. Cyber intrusions, security breaches, theft or loss of this information by cyber crime or otherwise could lead to the release of critical operating information or confidential customer or employee information, which could adversely affect our business operations or adversely impact our reputation, and could result in significant costs, fines and litigation. We maintain limited privacy protection liability insurance to cover limited damages and defense costs arising from unauthorized disclosure of, or failure to protect, private information as well as costs for notification to, or for credit card monitoring of, customers, employees and other persons in the event of a breach of private information. This insurance covers amounts paid to avert, prevent or stop a network attack or the disclosure of personal information, and costs of a qualified forensics firm to determine the cause, source and extent of a network attack or to investigate, examine and analyze our network to find the cause, source and extent of a data breach. While we have implemented measures designed to prevent cyber-attacks and mitigate their effects should they occur. These measures may not be effective due to the continually evolving nature of efforts to access confidential information.
The loss of key personnel or the inability to hire and retain qualified employees could have an adverse effect on our business, financial position and results of operations.
Our operations depend on the continued efforts of our employees. Retaining key employees and maintaining the ability to attract new employees are important to both our operational and financial performance. We cannot guarantee that any member of our management or any key employee at the Eversource parent or subsidiary level will continue to serve in any capacity for any particular period of time. In addition, a significant portion of our workforce, including many workers with specialized skills maintaining and servicing the electrical infrastructure, will be eligible to retire over the next five to ten years. Such highly skilled individuals cannot be quickly replaced due to the technically complex work they perform. We have developed strategic workforce plans to identify key functions and proactively implement plans to assure a ready and qualified workforce, but cannot predict the impact of these plans on our ability to hire and retain key employees.
Market performance or changes in assumptions require us to make significant contributions to our pension and other postretirement benefit plans.
We provide a defined benefit pension plan and other postretirement benefits for a substantial number of employees, former employees and retirees. Our future pension obligations, costs and liabilities are highly dependent on a variety of factors beyond our control. These factors include estimated investment returns, interest rates, discount rates, health care cost trends, benefit changes, salary increases and the demographics of plan participants. If our assumptions prove to be inaccurate, our future costs could increase significantly.In addition, various factors, including underperformance of plan investments and changes in law or regulation, could increase the amount of contributions required to fund our pension plan in the future. Additional large funding requirements, when combined with the financing requirements of our construction program, could impact the timing and amount of future financings and negatively affect our financial position, results of operations or cash flows. For further information, see Note 9A, "Employee Benefits - Pensions and Postretirement Benefits Other Than Pensions," to the financial statements.
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Costs of compliance with environmental regulations, including climate change legislation, may increase and have an adverse effect on our business and results of operations.
Our subsidiaries' operations are subject to extensive federal, state and local environmental statutes, rules and regulations that govern, among other things, air emissions, water discharges and the management of hazardous and solid waste. Compliance with these requirements requires us to incur significant costs relating to environmental monitoring, maintenance and upgrading of facilities, remediation and permitting. The costs of compliance with existing legal requirements or legal requirements not yet adopted may increase in the future. An increase in such costs, unless promptly recovered, could have an adverse impact on our business and our financial position, results of operations or cash flows.
In addition, global climate change issues have received an increased focus from federal and state government agencies . Although we would expect that any costs of these rules and regulations would be recovered from customers, their impact on energy use by customers and the ultimate impact on our business would be dependent upon the specific rules and regulations adopted and cannot be determined at this time. The impact of these additional costs to customers could lead to a further reduction in energy consumption resulting in a decline in electricity and gas sales in our service territories, which would have an adverse impact on our business and financial position, results of operations or cash flows. Any failure by us to comply with environmental laws and regulations, even if due to factors beyond our control, or reinterpretations of existing requirements, could also increase costs. Existing environmental laws and regulations may be revised or new laws and regulations seeking to protect the environment may be adopted or become applicable to us. Revised or additional laws could result in significant additional expense and operating restrictions on our facilities or increased compliance costs, which may not be fully recoverable in distribution company rates. The cost impact of any such laws, rules or regulations would be dependent upon the specific requirements adopted and cannot be determined at this time. For further information, see Item 1, Business -Other Regulatory and Environmental Matters, included in this Annual Report on Form 10-K.
As a holding company with no revenue-generating operations, Eversource parent's liquidity is dependent on dividends from its subsidiaries, its commercial paper program, and its ability to access the long-term debt and equity capital markets.
Eversource parent is a holding company and as such, has no revenue-generating operations of its own. Its ability to meet its debt service obligations and to pay dividends on its common shares is largely dependent on the ability of its subsidiaries to pay dividends to or repay borrowings from Eversource parent, and/or Eversource parent's ability to access its commercial paper program or the long-term debt and equity capital markets. Prior to funding Eversource parent, the subsidiary companies have financial obligations that must be satisfied, including among others, their operating expenses, debt service, preferred dividends of certain subsidiaries, and obligations to trade creditors. Additionally, the subsidiary companies could retain their free cash flow to fund their capital expenditures in lieu of receiving equity contributions from Eversource parent. Should the subsidiary companies not be able to pay dividends or repay funds due to Eversource parent, or if Eversource parent cannot access its commercial paper programs or the long-term debt and equity capital markets, Eversource parent's ability to pay interest, dividends and its own debt obligations would be restricted.
Item 1B.
Unresolved Staff Comments
We do not have any unresolved SEC staff comments.
| | | | | |
Transmission and Distribution System | | | | |
| | | | | |
As of December 31, 2015, Eversource and our electric operating subsidiaries owned the following: |
| | | | | |
| | Electric | | Electric | |
Eversource | Distribution | | Transmission | |
Number of substations owned | 512 | | 66 | |
Transformer capacity (in kVa) | 41,484,000 | | 13,780,000 | |
Overhead lines (in circuit miles) | 40,258 | | 3,932 | |
Capacity range of overhead transmission lines (in kV) | N/A | | 69 to 345 | |
Underground lines (distribution in circuit miles and transmission in cable miles) | 16,778 | | 407 | |
Capacity range of underground transmission lines (in kV) | N/A | | 69 to 345 | |
| | | | | | | | | | | | | | | | | |
| | | CL&P | | NSTAR Electric | | PSNH | | WMECO |
| | | Distribution | | Transmission | | Distribution | | Transmission | | Distribution | | Transmission | | Distribution | | Transmission |
Number of substations owned | | 182 | | 19 | | 133 | | 24 | | 154 | | 16 | | 43 | | 7 |
Transformer capacity (in kVa) | | 19,605,000 | | 3,117,000 | | 11,431,000 | | 6,728,000 | | 5,257,000 | | 3,868,000 | | 5,191,000 | | 67,000 |
Overhead lines (in circuit miles) | | 16,951 | | 1,662 | | 7,983 | | 750 | | 11,913 | | 1,039 | | 3,411 | | 481 |
Capacity range of overhead transmission lines (in kV) | | N/A | | 69 to 345 | | N/A | | 115 to 345 | | N/A | | 115 to 345 | | N/A | | 69 to 345 |
Underground lines (distribution in circuit miles and transmission in cable miles) | | 6,528 | | 136 | | 7,354 | | 260 | | 1,821 | | 1 | | 1,075 | | 10 |
Capacity range of underground transmission lines (in kV) | | N/A | | 69 to 345 | | N/A | | 115 to 345 | | N/A | | 115 | | N/A | | 115 |
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| | | | | | | | | | | | | | | | |
| | | | | | | | | NSTAR | | | | | | |
| | | Eversource | | CL&P | | Electric | | PSNH | | WMECO |
Underground and overhead line transformers in service | | 618,387 | | | 288,352 | | | 126,353 | | | 160,848 | | | 42,834 | |
Aggregate capacity (in kVa) | | 35,097,967 | | | 15,300,765 | | | 11,429,921 | | | 6,202,270 | | | 2,165,011 | |
Electric Generating Plants
As of December 31, 2015, PSNH owned the following electric generating plants:
| | | | | | |
Type of Plant | | Number
of Units | | Year
Installed | | Claimed Capability*
(kilowatts) |
Steam Plants | | 5 | | 1952-74 | | 935,343 |
Hydro | | 20 | | 1901-83 | | 58,115 |
Internal Combustion | | 5 | | 1968-70 | | 101,869 |
Biomass | | 1 | | 2006 | | 42,594 |
Total PSNH Generating Plant | | 31 | | | | 1,137,921 |
*
Claimed capability represents winter ratings as of December 31, 2015. The combined nameplate capacity of the generating plants is approximately 1,200 MW.
As of December 31, 2015, WMECO owned the following electric generating plants:
| | | | | | | |
Type of Plant | | | Number
of Sites | | Year
Installed | | Claimed Capability**
(kilowatts) |
Solar Fixed Tilt, Photovoltaic | | 3 | | 2010-14 | | 8,000 |
** Claimed capability represents the direct current nameplate capacity of the plant.
CL&P and NSTAR Electric do not own any electric generating plants.
Natural Gas Distribution System
As of December 31, 2015, Yankee Gas owned 28 active gate stations, 203 district regulator stations, and approximately 3,317 miles of natural gas main pipeline. Yankee Gas also owns a liquefaction and vaporization plant and above ground storage tank with a storage capacity equivalent of 1.2 Bcf of natural gas in Waterbury, Connecticut.
As of December 31, 2015, NSTAR Gas owned 21 active gate stations, 164 district regulator stations, and approximately 3,250 miles of natural gas main pipeline. Hopkinton, another subsidiary of Eversource, owns a satellite vaporization plant and above ground storage tanks in Acushnet, MA. In addition, Hopkinton owns a liquefaction and vaporization plant with above ground storage tanks in Hopkinton, MA. Combined, the two plants' tanks have an aggregate storage capacity equivalent to 3.5 Bcf of natural gas that is provided to NSTAR Gas under contract.
Franchises
CL&P Subject to the power of alteration, amendment or repeal by the General Assembly of Connecticut and subject to certain approvals, permits and consents of public authority and others prescribed by statute, CL&P has, subject to certain exceptions not deemed material, valid franchises free from burdensome restrictions to provide electric transmission and distribution services in the respective areas in which it is now supplying such service.
In addition to the right to provide electric transmission and distribution services as set forth above, the franchises of CL&P include, among others, limited rights and powers, as set forth under Connecticut law and the special acts of the General Assembly constituting its charter, to manufacture, generate, purchase and/or sell electricity at retail, including to provide Standard Service, Supplier of Last Resort service and backup service, to sell electricity at wholesale and to erect and maintain certain facilities on public highways and grounds, all subject to such consents and approvals of public authority and others as may be required by law. The franchises of CL&P include the power of eminent domain. Connecticut law prohibits an electric distribution company from owning or operating generation assets. However, under "An Act Concerning Energy Independence," enacted in 2005, CL&P is permitted to own up to 200 MW of peaking facilities if the PURA determines that such facilities will be more cost effective than other options for mitigating FMCC and Locational Installed Capacity (LICAP) costs. In addition, under "An Act Concerning Electricity and Energy Efficiency," enacted in 2007, an electric distribution company, such as CL&P, is permitted to purchase an existing electric generating plant located in Connecticut that is offered for sale, subject to prior approval from the PURA and a determination by the PURA that such purchase is in the public interest. Finally, Connecticut law also allows CL&P to submit a proposal to the DEEP to build, own or operate one or more generation facilities up to 10 MWs using Class I renewable energy.
NSTAR Electric and NSTAR GasThrough their charters, which are unlimited in time, NSTAR Electric and NSTAR Gas have the right to engage in the business of delivering and selling electricity and natural gas within their respective service territories, and have powers incidental thereto and are entitled to all the rights and privileges of and subject to the duties imposed upon electric and natural gas companies under Massachusetts laws. The locations in public ways for electric transmission and distribution lines and natural gas distribution pipelines are obtained from municipal and other state authorities who, in granting these locations, act as agents for the state. In some cases the actions of these authorities are subject to appeal to the DPU. The rights to these locations are not limited in time and are subject to the action of these authorities and the legislature. Under Massachusetts law, with the exception of municipal-owned utilities, no other entity may provide electric or natural gas delivery service to retail
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customers within NSTAR's service territory without the written consent of NSTAR Electric and/or NSTAR Gas. This consent must be filed with the DPU and the municipality so affected.
The Massachusetts restructuring legislation defines service territories as those territories actually served on July 1, 1997 and following municipal boundaries to the extent possible. The restructuring legislation further provides that until terminated by law or otherwise, distribution companies shall have the exclusive obligation to serve all retail customers within their service territories and no other person shall provide distribution service within such service territories without the written consent of such distribution companies. Pursuant to the Massachusetts restructuring legislation, the DPU (then, the Department of Telecommunications and Energy) was required to define service territories for each distribution company, including NSTAR Electric. The DPU subsequently determined that there were advantages to the exclusivity of service territories and issued a report to the Massachusetts Legislature recommending against, in this regard, any changes to the restructuring legislation.
PSNH The NHPUC, pursuant to statutory requirements, has issued orders granting PSNH exclusive franchises to distribute electricity in the respective areas in which it is now supplying such service.
In addition to the right to distribute electricity as set forth above, the franchises of PSNH include, among others, rights and powers to manufacture, generate, purchase, and transmit electricity, to sell electricity at wholesale to other utility companies and municipalities and to erect and maintain certain facilities on certain public highways and grounds, all subject to such consents and approvals of public authority and others as may be required by law. PSNH's status as a public utility gives it the ability to petition the NHPUC for the right to exercise eminent domain for its transmission and distribution services in appropriate circumstances.
PSNH is also subject to certain regulatory oversight by the Maine Public Utilities Commission and the Vermont Public Service Board.
WMECO WMECO is authorized by its charter to conduct its electric business in the territories served by it, and has locations in the public highways for transmission and distribution lines. Such locations are granted pursuant to the laws of Massachusetts by the Department of Public Works of Massachusetts or local municipal authorities and are of unlimited duration, but the rights thereby granted are not vested. Such locations are for specific lines only and for extensions of lines in public highways. Further similar locations must be obtained from the Department of Public Works of Massachusetts or the local municipal authorities. In addition, WMECO has been granted easements for its lines in the Massachusetts Turnpike by the Massachusetts Turnpike Authority and pursuant to state laws, has the power of eminent domain.
The Massachusetts restructuring legislation applicable to NSTAR Electric (described above) is also applicable to WMECO.
Yankee Gas Yankee Gas holds valid franchises to sell natural gas in the areas in which Yankee Gas supplies natural gas service, which it acquired either directly or from its predecessors in interest. Generally, Yankee Gas holds franchises to serve customers in areas designated by those franchises as well as in most other areas throughout Connecticut so long as those areas are not occupied and served by another natural gas utility under a valid franchise of its own or are not subject to an exclusive franchise of another natural gas utility. Yankee Gas' franchises are perpetual but remain subject to the power of alteration, amendment or repeal by the General Assembly of the State of Connecticut, the power of revocation by the PURA and certain approvals, permits and consents of public authorities and others prescribed by statute. Generally, Yankee Gas' franchises include, among other rights and powers, the right and power to manufacture, generate, purchase, transmit and distribute natural gas and to erect and maintain certain facilities on public highways and grounds, and the right of eminent domain, all subject to such consents and approvals of public authorities and others as may be required by law.
Item 3.
Legal Proceedings
1.
Yankee Companies v. U.S. Department of Energy
DOE Phase I Damages - In 1998, the Yankee Companies (CYAPC, YAEC and MYAPC) filed separate complaints against the DOE in the Court of Federal Claims seeking monetary damages resulting from the DOE's failure to begin accepting spent nuclear fuel for disposal by January 31, 1998 pursuant to the terms of the 1983 spent fuel and high level waste disposal contracts between the Yankee Companies and the DOE (DOE Phase I Damages). Phase I covered damages for the period 1998 through 2002. Following multiple appeals and cross-appeals in December 2012, the judgment awarding CYAPC $39.6 million, YAEC $38.3 million and MYAPC $81.7 million became final.
In January 2013, the proceeds from the DOE Phase I Damages Claim were received by the Yankee Companies and transferred to each Yankee Company's respective decommissioning trust.
In June 2013, FERC approved CYAPC, YAEC and MYAPC to reduce rates in their wholesale power contracts through the application of the DOE proceeds for the benefit of customers. Changes to the terms of the wholesale power contracts became effective on July 1, 2013. In accordance with the FERC order, CL&P, NSTAR Electric, PSNH and WMECO began receiving the benefit of the DOE proceeds, and the benefits have been passed on to customers.
On September 17, 2014, in accordance with the MYAPC’s three-year refund plan, MYAPC returned a portion of the DOE Phase I Damages proceeds to the member companies, including CL&P, NSTAR Electric, PSNH, and WMECO, in the amount of $3.2 million, $1.1 million, $1.4 million and $0.8 million, respectively. On September 28, 2015, MYAPC returned the remaining DOE Phase I Damages proceeds to the member companies, including CL&P, NSTAR Electric, PSNH, and WMECO, in the amount of $2.3 million, $0.8 million, $1 million and $0.6 million, respectively.
DOE Phase II Damages - In December 2007, the Yankee Companies each filed subsequent lawsuits against the DOE seeking recovery of actual damages incurred related to the alleged failure of the DOE to provide for a permanent facility to store spent nuclear fuel generated in years 2001 through 2008 for CYAPC and YAEC and from 2002 through 2008 for MYAPC (DOE Phase II Damages). In November 2013, the court issued a
21
final judgment awarding CYAPC $126.3 million, YAEC $73.3 million, and MYAPC $35.8 million. On January 14, 2014, the Yankee Companies received a letter from the U.S. Department of Justice stating that the DOE will not appeal the court's final judgment.
In March and April 2014, CYAPC, YAEC and MYAPC received payment of $126.3 million, $73.3 million and $35.8 million, respectively, of the DOE Phase II Damages proceeds and made the required informational filing with FERC in accordance with the process and methodology outlined in the 2013 FERC order. The Yankee Companies returned the DOE Phase II Damages proceeds to the member companies, including CL&P, NSTAR Electric, PSNH, and WMECO, for the benefit of their respective customers, on June 1, 2014. Refunds to CL&P's, NSTAR Electric's, PSNH's and WMECO's customers for these DOE proceeds began in the third quarter of 2014 and all refunds under these proceedings have been disbursed.
DOE Phase III Damages - In August 2013, the Yankee Companies each filed subsequent lawsuits against the DOE seeking recovery of actual damages incurred in the years 2009 through 2012. The trial on this matter was held on June 30 and July 1, 2015, with a post-trial briefing that concluded on October 14, 2015. The parties are awaiting a decision from the court.
2.
Conservation Law Foundation v. PSNH
On July 21, 2011, the Conservation Law Foundation (CLF) filed a citizens suit under the provisions of the federal Clean Air Act against PSNH alleging permitting violations at the company's Merrimack generating station. The suit alleges that PSNH failed to have proper permits for replacement of the Unit 2 turbine at Merrimack, installation of activated carbon injection equipment for the unit, and violated a permit condition concerning operation of the electrostatic precipitators at the station. On September 27, 2012, the federal court dismissed portions of CLF's suit pertaining to the installation of activated carbon injection and the electrostatic precipitators. CLF filed an amended complaint on May 28, 2013, related to routine maintenance of the boiler performed in 2008 and 2009. The suit seeks injunctive relief, civil penalties, and costs. CLF has pursued similar claims before the NHPUC, the N.H. Air Resources Council, and the N.H. Site Evaluation Committee, all of which have been denied. PSNH continues to believe this suit is without merit and intends to defend it vigorously. However, at this time the case has been stayed while the State settlement process related to the divestiture of generating assets, including Merrimack Station, continues.
3.
Other Legal Proceedings
For further discussion of legal proceedings, see Item 1,Business: "- Electric Distribution Segment," "- Electric Transmission Segment," and "- Natural Gas Distribution Segment" for information about various state and federal regulatory and rate proceedings, civil lawsuits related thereto, and information about proceedings relating to power, transmission and pricing issues; "- Nuclear Fuel Storage" for information related to high-level nuclear waste; and "- Other Regulatory and Environmental Matters" for information about proceedings involving surface water and air quality requirements, toxic substances and hazardous waste, electric and magnetic fields, licensing of hydroelectric projects, and other matters. In addition, see Item 1A,Risk Factors, for general information about several significant risks.
Item 4.
Mine Safety Disclosures
Not applicable.
EXECUTIVE OFFICERS OF THE REGISTRANT
The following table sets forth the executive officers of Eversource Energy as of February 16, 2016. All of the Company's officers serve terms of one year and until their successors are elected and qualified:
| | | | |
Name | | Age | | Title |
Thomas J. May | | 68 | | Chairman of the Board, President and Chief Executive Officer |
James J. Judge | | 60 | | Executive Vice President and Chief Financial Officer |
Leon J. Olivier | | 67 | | Executive Vice President-Enterprise Energy Strategy and Business Development |
David R. McHale | | 55 | | Executive Vice President and Chief Administrative Officer |
Werner J. Schweiger | | 56 | | Executive Vice President and Chief Operating Officer |
Gregory B. Butler | | 58 | | Senior Vice President and General Counsel |
Christine M. Carmody* | | 53 | | Senior Vice President-Human Resources of Eversource Service |
Joseph R. Nolan, Jr.* | | 52 | | Senior Vice President-Corporate Relations of Eversource Service |
Jay S. Buth | | 46 | | Vice President, Controller and Chief Accounting Officer |
*Deemed an executive officer of Eversource Energy pursuant to Rule 3b-7 under the Securities Exchange Act of 1934.
Thomas J. May. Mr. May has served as Chairman of the Board of Eversource Energy since October 10, 2013, and as President and Chief Executive Officer and as a Trustee of Eversource Energy; as Chairman and a Director of CL&P, NSTAR Electric, NSTAR Gas, PSNH, WMECO and Yankee Gas; and as Chairman, President and Chief Executive Officer and a Director of Eversource Service since April 10, 2012. Mr. May has served as a Director of NSTAR Electric and NSTAR Gas since September 27, 1999. Mr. May previously served as Chairman, President and Chief Executive Officer and a Trustee of NSTAR, and as Chairman, President and Chief Executive Officer of NSTAR Electric and NSTAR Gas until April 10, 2012. He served as Chairman, Chief Executive Officer and a Trustee since NSTAR was formed in 1999, and was elected President in 2002. Mr. May has served as Chairman of the Board of Eversource Energy Foundation, Inc. since October 15, 2013, and as a Director of Eversource Energy Foundation, Inc. since April 10, 2012. He previously served as President of Eversource Energy Foundation, Inc. from October 15, 2013 to September 29, 2014. He has served as a Trustee of the NSTAR Foundation since August 18, 1987.
22
James J. Judge. Mr. Judge has served as Executive Vice President and Chief Financial Officer of Eversource Energy, CL&P, NSTAR Electric, NSTAR Gas, PSNH, WMECO, Yankee Gas and Eversource Service and as a Director of CL&P, PSNH, WMECO, Yankee Gas and Eversource Service since April 10, 2012 and of NSTAR Electric and NSTAR Gas since September 27, 1999. Previously, Mr. Judge served as Senior Vice President and Chief Financial Officer of NSTAR, NSTAR Electric and NSTAR Gas from 1999 until April 2012. Mr. Judge has served as Treasurer and as a Director of Eversource Energy Foundation, Inc. since April 10, 2012. He has served as a Trustee of the NSTAR Foundation since December 12, 1995.
Leon J. Olivier. Mr. Olivier has served as Executive Vice President-Enterprise Energy Strategy and Business Development of Eversource Energy since September 2, 2014 and as a Director of Eversource Service since January 17, 2005. Mr. Olivier previously served as Executive Vice President and Chief Operating Officer of Eversource Energy and Eversource Service from May 13, 2008 until September 2, 2014, and as Chief Executive Officer of NSTAR Electric and NSTAR Gas from April 10, 2012 until August 11, 2014, of CL&P, PSNH, WMECO and Yankee Gas from January 15, 2007 to September 29, 2014, and of CL&P from September 10, 2001 to September 29, 2014, and as a Director of NSTAR Electric and NSTAR Gas from November 27, 2012 to September 29, 2014, of PSNH, WMECO and Yankee Gas from January 17, 2005 to September 29, 2014, and of CL&P from September 10, 2001 to September 29, 2014. Previously, Mr. Olivier served as Executive Vice President-Operations of Eversource Energy from February 13, 2007 to May 12, 2008. He has served as a Director of Eversource Energy Foundation, Inc. since April 1, 2006. Mr. Olivier has served as a Trustee of the NSTAR Foundation since April 10, 2012.
David R. McHale. Mr. McHale has served as Executive Vice President and Chief Administrative Officer of Eversource Energy and Eversource Service since April 10, 2012 and as a Director of Eversource Service since January 1, 2005. Mr. McHale previously served as Executive Vice President and Chief Administrative Officer of CL&P, NSTAR Electric, NSTAR Gas, PSNH, WMECO and Yankee Gas from April 10, 2012 to September 29, 2014 and as a Director of NSTAR Electric and NSTAR Gas from November 27, 2012 to September 29, 2014, of PSNH, WMECO and Yankee Gas from January 1, 2005 to September 29, 2014, and of CL&P from January 15, 2007 to September 29, 2014. Previously, Mr. McHale served as Executive Vice President and Chief Financial Officer of Eversource Energy, CL&P, PSNH, WMECO, Yankee Gas and Eversource Service from January 2009 to April 2012, and as Senior Vice President and Chief Financial Officer of Eversource Energy, CL&P, PSNH, WMECO, Yankee Gas and Eversource Service from January 2005 to December 2008. He has served as a Director of Eversource Energy Foundation, Inc. since January 1, 2005. Mr. McHale has served as a Trustee of the NSTAR Foundation since April 10, 2012.
Werner J. Schweiger. Mr. Schweiger has served as Executive Vice President and Chief Operating Officer of Eversource Energy since September 2, 2014 and of Eversource Service since August 11, 2014, and as President of CL&P since June 2, 2015 and as Chief Executive Officer of CL&P, NSTAR Electric, NSTAR Gas, PSNH, WMECO and Yankee Gas since August 11, 2014, and as a Director of Eversource Service, NSTAR Gas and Yankee Gas since September 29, 2014 and of CL&P, PSNH, NSTAR Electric and WMECO since May 28, 2013. He previously served as President-Electric Distribution of Eversource Service from January 16, 2013 until August 11, 2014 and as President of NSTAR Electric from April 10, 2012 until January 16, 2013 and as a Director of NSTAR Electric from November 27, 2012 to January 16, 2013. From February 27, 2002 until April 10, 2012, Mr. Schweiger was Senior Vice President-Operations of NSTAR Electric and NSTAR Gas. Mr. Schweiger has served as a Director of Eversource Energy Foundation, Inc. since September 29, 2014. He has served as a Trustee of the NSTAR Foundation since September 29, 2014.
Gregory B. Butler. Mr. Butler has served as Senior Vice President and General Counsel of Eversource Energy since May 1, 2014, of NSTAR Electric, and NSTAR Gas since April 10, 2012, and of CL&P, PSNH, WMECO, Yankee Gas and Eversource Service since March 9, 2006. Mr. Butler has served as a Director of NSTAR Electric and NSTAR Gas since April 10, 2012, of Eversource Service since November 27, 2012, and of CL&P, PSNH, WMECO and Yankee Gas since April 22, 2009. Mr. Butler previously served as Senior Vice President, General Counsel and Secretary of Eversource Energy from April 10, 2012 until May 1, 2014, and as Senior Vice President and General Counsel of Eversource Energy from December 1, 2005 to April 10, 2012. He has served as a Director of Eversource Energy Foundation, Inc. since December 1, 2002. He has been a Trustee of the NSTAR Foundation since April 10, 2012.
Christine M. Carmody. Ms. Carmody has served as Senior Vice President-Human Resources of Eversource Service since April 10, 2012 and as a Director of Eversource Service since November 27, 2012. Ms. Carmody previously served as Senior Vice President-Human Resources of CL&P, PSNH, WMECO and Yankee Gas from November 27, 2012 to September 29, 2014, and of NSTAR Electric and NSTAR Gas from August 1, 2008 to September 29, 2014, and as a Director of CL&P, PSNH, WMECO and Yankee Gas from April 10, 2012 to September 29, 2014 and of NSTAR Electric and NSTAR Gas from November 27, 2012 to September 29, 2014. Previously, Ms. Carmody served as Vice President-Organizational Effectiveness of NSTAR, NSTAR Electric and NSTAR Gas from June 2006 to August 2008. Ms. Carmody has served as a Director of Eversource Energy Foundation, Inc. since April 10, 2012. She has served as a Trustee of the NSTAR Foundation since August 1, 2008.
Joseph R. Nolan, Jr. Mr. Nolan has served as Senior Vice President-Corporate Relations of Eversource Service since April 10, 2012 and as a Director of Eversource Service since November 27, 2012. Mr. Nolan previously served as Senior Vice President-Corporate Relations of NSTAR Electric and NSTAR Gas from April 10, 2012 to September 29, 2014, and of CL&P, PSNH, WMECO and Yankee Gas from November 27, 2012 to September 29, 2014, as a Director of CL&P, PSNH, WMECO and Yankee Gas from April 10, 2012 to September 29, 2014 and of NSTAR Electric and NSTAR Gas from November 27, 2012 to September 29, 2014. Previously, Mr. Nolan served as Senior Vice President-Customer & Corporate Relations of NSTAR, NSTAR Electric and NSTAR Gas from 2006 until April 10, 2012. Mr. Nolan has served as a Director of Eversource Energy Foundation, Inc. since April 10, 2012, and has served as Executive Director of Eversource Energy Foundation, Inc. since October 15, 2013. He has served as a Trustee of the NSTAR Foundation since October 1, 2000.
Jay S. Buth. Mr. Buth has served as Vice President, Controller and Chief Accounting Officer of Eversource Energy, CL&P, NSTAR Electric, NSTAR Gas, PSNH, WMECO, Yankee Gas and Eversource Service since April 10, 2012. Previously, Mr. Buth served as Vice President-Accounting and Controller of Eversource Energy, CL&P, PSNH, WMECO, Yankee Gas and Eversource Service from June 2009 until April 10, 2012. From June 2006 through January 2009, Mr. Buth served as the Vice President and Controller for New Jersey Resources Corporation, an energy services holding company that provides natural gas and wholesale energy services, including transportation, distribution and asset management.
23
PART II
Item 5.
Market for the Registrants' Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities
(a)
Market Information and (c) Dividends
Eversource. Our common shares are listed on the New York Stock Exchange. The ticker symbol is "ES." The high and low sales prices of our common shares and the dividends declared, for the past two years, by quarter, are shown below.
| | | | | | | | | | | |
Year | | Quarter | | High | | Low | | Dividends
Declared |
2015 | | First | | $ | 56.83 | | $ | 48.54 | | $ | 0.4175 |
| | | | | | | | | | | |
| | Second | | | 51.42 | | | 45.20 | | | 0.4175 |
| | Third | | | 52.15 | | | 44.64 | | | 0.4175 |
| | Fourth | | | 52.85 | | | 48.18 | | | 0.4175 |
| | | | | | | | | | | |
2014 | | First | | $ | 45.69 | | $ | 41.28 | | $ | 0.3925 |
| | | | | | | | | | | |
| | Second | | | 47.60 | | | 44.28 | | | 0.3925 |
| | Third | | | 47.37 | | | 41.92 | | | 0.3925 |
| | Fourth | | | 56.66 | | | 44.37 | | | 0.3925 |
Information with respect to dividend restrictions for us, CL&P, NSTAR Electric, PSNH, and WMECO is contained in Item 7,Management's Discussion and Analysis of Financial Condition and Results of Operations, under the caption "Liquidity" and Item 8,Financial Statements and Supplementary Data, in theCombined Notes to Financial Statements, within this Annual Report on Form 10-K.
There is no established public trading market for the common stock of CL&P, NSTAR Electric, PSNH and WMECO. All of the common stock of CL&P, NSTAR Electric, PSNH and WMECO is held solely by Eversource.
Common stock dividends approved and paid to Eversource during the year were as follows:
| | | | | |
| For the Years Ended December 31, |
(Millions of Dollars) | 2015 | | 2014 |
CL&P | $ | 196.0 | | $ | 171.2 |
NSTAR Electric | | 198.0 | | | 253.0 |
PSNH | | 106.0 | | | 66.0 |
WMECO | | 37.2 | | | 60.0 |
(b)
Holders
As of January 31, 2016, there were 42,493 registered common shareholders of our company on record. As of the same date, there were a total of 317,191,249 common shares issued.
(d)
Securities Authorized for Issuance Under Equity Compensation Plans
For information regarding securities authorized for issuance under equity compensation plans, see Item 12,Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters, included in this Annual Report on Form 10-K.
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(e)
Performance Graph
The performance graph below illustrates a five-year comparison of cumulative total returns based on an initial investment of $100 in 20082010 in Northeast UtilitiesEversource Energy common stock, as compared with the S&P 500 Stock Index and the EEI Index for the period 20092011 through 2013,2015, assuming all dividends are reinvested.
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(e)
Purchases of Equity Securities by the Issuer and Affiliated Purchasers
The following table discloses purchases of shares of our common stockshares made by us or on our behalf for the periods shown below. The common shares purchased consist of open market purchases made by the Company or an independent agent. These share transactions related to shares awarded under the Company's Incentive Plan and Dividend Reinvestment Plan and matching contributions under the Eversource 401k Plan.
| | | | | | | | | |
| | Period | | Total Number of Shares Purchased | | | Average Price Paid per Share | Total Number of Shares Purchased as Part of Publicly Announced Plans or Programs | Approximate Dollar Value of Shares that May Yet Be Purchased Under the Plans and Programs (at month end) |
| | October 1 - October 31, 2013 | | - | | $ | - | - | - |
| | November 1 - November 30, 2013 | | - | | | - | - | - |
| | December 1 - December 31, 2013 | | 75,700 | | | 42.22 | - | - |
| | Total | | 75,700 | | $ | 42.22 | - | - |
| | | | | | | | | |
| | Period | | Total Number of Shares Purchased | | | Average Price Paid per Share | Total Number of Shares Purchased as Part of Publicly Announced Plans or Programs | Approximate Dollar Value of Shares that May Yet Be Purchased Under the Plans and Programs (at month end) |
| | October 1 - October 31, 2015 | | 117,887 | | $ | 50.33 | - | - |
| | November 1 - November 30, 2015 | | 3,178 | | | 50.76 | - | - |
| | December 1 - December 31, 2015 | | 6,001 | | | 51.17 | - | - |
| | Total | | 127,066 | | $ | 50.38 | - | - |
2925
| | | | | | | | | | | | | | | | | | | |
Item 6. Selected Consolidated Financial Data | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | | | |
NU Selected Consolidated Financial Data (Unaudited) | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | | | |
(Thousands of Dollars, except percentages and common share information) | 2013 | | 2012 (a) | | 2011 | | 2010 | | 2009 | |
|
Balance Sheet Data: | | | | | | | | | | | | | | | |
| Property, Plant and Equipment, Net | $ | 17,576,186 | | $ | 16,605,010 | | $ | 10,403,065 | | $ | 9,567,726 | | $ | 8,839,965 | |
| Total Assets | | 27,795,537 | | | 28,302,824 | | | 15,647,066 | | | 14,472,601 | | | 14,057,679 | |
| Total Capitalization (b) (c) | | 18,077,274 | | | 17,356,112 | | | 9,078,321 | | | 8,627,985 | | | 8,253,323 | |
| Obligations Under Capital Leases (b) | | 10,744 | | | 11,071 | | | 12,358 | | | 12,236 | | | 12,873 | |
Income Statement Data: | | | | | | | | | | | | | | | |
| Operating Revenues | $ | 7,301,204 | | $ | 6,273,787 | | $ | 4,465,657 | | $ | 4,898,167 | | $ | 5,439,430 | |
| Net Income | | 793,689 | | | 533,077 | | | 400,513 | | | 394,107 | | | 335,592 | |
| Net Income Attributable to Noncontrolling Interests | | 7,682 | | | 7,132 | | | 5,820 | | | 6,158 | | | 5,559 | |
| Net Income Attributable to Controlling Interest | $ | 786,007 | | $ | 525,945 | | $ | 394,693 | | $ | 387,949 | | $ | 330,033 | |
Common Share Data: | | | | | | | | | | | | | | | |
| Basic Earnings Per Common Share: | | | | | | | | | | | | | | | |
| | Net Income Attributable to Controlling Interests | $ | 2.49 | | $ | 1.90 | | $ | 2.22 | | $ | 2.20 | | $ | 1.91 | |
| Diluted Earnings Per Common Share: | | | | | | | | | | | | | | | |
| | Net Income Attributable to Controlling Interest | $ | 2.49 | | $ | 1.89 | | $ | 2.22 | | $ | 2.19 | | $ | 1.91 | |
| Weighted Average Common Shares Outstanding | | | | | | | | | | | | | | | |
| | Basic | | 315,311,387 | | | 277,209,819 | | | 177,410,167 | | | 176,636,086 | | | 172,567,928 | |
| | Diluted | | 316,211,160 | | | 277,993,631 | | | 177,804,568 | | | 176,885,387 | | | 172,717,246 | |
| Dividends Declared Per Share | $ | 1.47 | | $ | 1.32 | | $ | 1.10 | | $ | 1.03 | | $ | 0.95 | |
| Market Price - Closing (high) (d) | $ | 45.33 | | $ | 40.57 | | $ | 36.31 | | $ | 32.05 | | $ | 26.33 | |
| Market Price - Closing (low) (d) | $ | 38.67 | | $ | 33.53 | | $ | 30.46 | | $ | 24.78 | | $ | 19.45 | |
| Market Price - Closing (end of year) (d) | $ | 42.39 | | $ | 39.08 | | $ | 36.07 | | $ | 31.88 | | $ | 25.79 | |
| Book Value Per Share (end of year) | $ | 30.49 | | $ | 29.41 | | $ | 22.65 | | $ | 21.60 | | $ | 20.37 | |
| Tangible Book Value Per Share (end of year) (e) | $ | 19.32 | | $ | 18.21 | | $ | 21.03 | | $ | 19.97 | | $ | 18.74 | |
| Rate of Return Earned on Average Common Equity (%) (f) | | 8.3 | | | 7.9 | | | 10.1 | | | 10.7 | | | 10.2 | |
| Market-to-Book Ratio (end of year) (g) | | 1.4 | | | 1.3 | | | 1.6 | | | 1.5 | | | 1.3 | |
Capitalization: | | | | | | | | | | | | | | | |
| Total Equity | | 53 | % | | 53 | % | | 44 | % | | 44 | % | | 44 | % |
| Preferred Stock, not subject to mandatory redemption | | 1 | | | 1 | | | 1 | | | 1 | | | 1 | |
| Long-Term Debt (b) (c) | | 46 | | | 46 | | | 55 | | | 55 | | | 55 | |
| | | | | | 100 | % | | 100 | % | | 100 | % | | 100 | % | | 100 | % |
| | | | | | | | | | | | | | | | | | | |
|
(a) | The 2012 results include the operations of NSTAR beginning April 10, 2012. | | |
(b) | Includes portions due within one year. | | |
(c) | Excludes RRBs. | | |
(d) | Market price information reflects closing prices as reflected by the New York Stock Exchange. | | |
(e) | Common Shareholder's Equity adjusted for goodwill and intangibles divided by total common shares outstanding. | | |
(f) | Net Income Attributable to Controlling Interest divided by average Common Shareholders' Equity. | | |
(g) | The closing market price divided by the book value per share. | | | | | |
Item 6. | Selected Consolidated Financial Data | | | | | | | | | | |
| | | | | | | | | | | | | | |
Eversource Selected Consolidated Financial Data (Unaudited) | | | | | | | | | |
| | | | | | | | | | | | | | |
(Thousands of Dollars, except percentages and
common share information) | 2015 | | 2014 | | 2013 | | 2012(a) | | 2011 | |
|
Balance Sheet Data: | | | | | | | | | | | | |
| Property, Plant and Equipment, Net | $ | 19,892,441 | | $ | 18,647,041 | | $ | 17,576,186 | | $ | 16,605,010 | | $ | 10,403,065 | |
| Total Assets(b) | | 30,580,309 | | 29,740,387 | | 27,760,315 | | 28,269,780 | | 15,617,627 | |
| Total Capitalization (b) (c) (d) | | 19,542,240 | | 18,946,395 | | 18,042,052 | | 17,323,068 | | 9,048,882 | |
| Obligations Under Capital Leases (c) | | 8,222 | | | 9,434 | | | 10,744 | | | 11,071 | | | 12,358 | |
Income Statement Data: | | | | | | | | | | | |
| Operating Revenues | $ | 7,954,827 | | $ | 7,741,856 | | $ | 7,301,204 | | $ | 6,273,787 | | $ | 4,465,657 | |
| Net Income | | 886,004 | | 827,065 | | 793,689 | | 533,077 | | 400,513 | |
| Net Income Attributable to Noncontrolling Interests | | 7,519 | | | 7,519 | | | 7,682 | | | 7,132 | | | 5,820 | |
| Net Income Attributable to Common Shareholders | $ | 878,485 | | $ | 819,546 | | $ | 786,007 | | $ | 525,945 | | $ | 394,693 | |
Common Share Data: | | | | | | | | | | | |
| Net Income Attributable to Common Shareholders: | | | | | | | | | | | |
| | Basic Earnings Per Common Share | $ | 2.77 | | $ | 2.59 | | $ | 2.49 | | $ | 1.90 | | $ | 2.22 | |
| | Diluted Earnings Per Common Share | $ | 2.76 | | $ | 2.58 | | $ | 2.49 | | $ | 1.89 | | $ | 2.22 | |
| Weighted Average Common Shares Outstanding: | | | | | | | | | | | |
| | Basic | | 317,336,881 | | 316,136,748 | | 315,311,387 | | 277,209,819 | | 177,410,167 | |
| | Diluted | | 318,432,687 | | 317,417,414 | | 316,211,160 | | 277,993,631 | | 177,804,568 | |
| Dividends Declared Per Common Share | $ | 1.67 | | $ | 1.57 | | $ | 1.47 | | $ | 1.32 | | $ | 1.10 | |
| Market Price - Closing (high)(e) | $ | 54.52 | | $ | 56.15 | | $ | 45.33 | | $ | 40.57 | | $ | 36.31 | |
| Market Price - Closing (low)(e) | $ | 44.63 | | $ | 41.52 | | $ | 38.67 | | $ | 33.53 | | $ | 30.46 | |
| Market Price - Closing (end of year)(e) | $ | 51.07 | | $ | 53.52 | | $ | 42.39 | | $ | 39.08 | | $ | 36.07 | |
| Book Value Per Common Share (end of year) | $ | 32.64 | | $ | 31.47 | | $ | 30.49 | | $ | 29.41 | | $ | 22.65 | |
| Tangible Book Value Per Common Share (end of year) (f) | $ | 21.54 | | $ | 20.37 | | $ | 19.32 | | $ | 18.21 | | $ | 21.03 | |
| Rate of Return Earned on Average Common Equity (%)(g) | | 8.7 | | | 8.4 | | | 8.3 | | | 7.9 | | | 10.1 | |
| Market-to-Book Ratio (end of year) (h) | | 1.6 | | | 1.7 | | | 1.4 | | | 1.3 | | | 1.6 | |
Capitalization: | | | | | | | | | | | | | | | |
| Total Equity | | 53 | % | | 53 | % | | 53 | % | | 53 | % | | 44 | % |
| Preferred Stock Not Subject to Mandatory Redemption | | 1 | | 1 | | 1 | | 1 | | 1 | |
| Long-Term Debt(b) (c) (d) | | 46 | | | 46 | | | 46 | | | 46 | | | 55 | |
| | | | | | | | | 100 | % | | 100 | % | | 100 | % | | 100 | % | | 100 | % |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | |
CL&P Selected Financial Data (Unaudited) | CL&P Selected Financial Data (Unaudited) | | | | | | | | | | CL&P Selected Financial Data (Unaudited) | | | | | | | | | |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | |
(Thousands of Dollars) | (Thousands of Dollars) | 2013 | | 2012 | | 2011 | | 2010 | | 2009 | | (Thousands of Dollars) | 2015 | | 2014 | | 2013 | | 2012 | | 2011 | |
Operating Revenues | Operating Revenues | $ | 2,442,341 | | $ | 2,407,449 | | $ | 2,548,387 | | $ | 2,999,102 | | $ | 3,424,538 | | Operating Revenues | $ | 2,802,675 | | $ | 2,692,582 | | $ | 2,442,341 | | $ | 2,407,449 | | $ | 2,548,387 | |
Net Income | Net Income | | 279,412 | | 209,725 | | 250,164 | | 244,143 | | 216,316 | | Net Income | | 299,360 | | 287,754 | | 279,412 | | 209,725 | | 250,164 | |
Cash Dividends on Common Stock | Cash Dividends on Common Stock | | 151,999 | | 100,486 | | 243,218 | | 217,691 | | 113,848 | | Cash Dividends on Common Stock | | 196,000 | | 171,200 | | 151,999 | | 100,486 | | 243,218 | |
Property, Plant and Equipment, Net | Property, Plant and Equipment, Net | | 6,451,259 | | 6,152,959 | | 5,827,384 | | 5,586,504 | | 5,340,561 | | Property, Plant and Equipment, Net | | 7,156,809 | | 6,809,664 | | 6,451,259 | | 6,152,959 | | 5,827,384 | |
Total Assets | | 8,980,502 | | 9,142,088 | | 8,791,396 | | 8,255,192 | | 8,364,564 | |
Rate Reduction Bonds | | - | | - | | - | | - | | 195,587 | |
Long-Term Debt (a) (b) | | 2,741,208 | | 2,862,790 | | 2,583,753 | | 2,583,102 | | 2,582,361 | |
Total Assets(b) | | 9,592,957 | | 9,344,400 | | 8,965,906 | | 9,127,602 | | 8,775,451 | |
Long-Term Debt (b) (c) | | 2,763,682 | | 2,826,243 | | 2,726,613 | | 2,848,303 | | 2,567,808 | |
Preferred Stock Not Subject to Mandatory Redemption | Preferred Stock Not Subject to Mandatory Redemption | | 116,200 | | 116,200 | | 116,200 | | 116,200 | | 116,200 | | Preferred Stock Not Subject to Mandatory Redemption | | 116,200 | | 116,200 | | 116,200 | | 116,200 | | 116,200 | |
Obligations Under Capital Leases (a) | | 9,309 | | | 9,960 | | | 10,715 | | | 10,613 | | | 10,956 | |
Obligations Under Capital Leases(c) | | 7,624 | | | 8,439 | | | 9,309 | | | 9,960 | | | 10,715 | |
| | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | |
(a) | (a) | Includes portions due within one year. | | (a) | The 2012 results include the operations of NSTAR beginning April 10, 2012. | | |
| | | | | | | | | | | | | | |
(b) | (b) | Excludes RRBs. | | | | | | | | | | | | | The 2011 through 2014 amounts reflect reclassifications due to the adoption of new accounting guidance that changed the balance sheet presentation of debt issuance costs. Unamortized debt issuance costs are now presented as a direct reduction from the carrying amount of the debt liability rather than as a deferred cost. Prior year amounts were retrospectively adjusted to conform to the current year presentation. See Note 1C, "Summary of Significant Accounting Policies – Accounting Standards," for further information. |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | |
(c) | | Includes portions due within one year. | | |
| | | | | | | | | | | | | | |
(d) | | Excludes RRBs. | | |
| | | | | | | | | | | | | | |
(e) | | Market price information reflects closing prices as reflected by the New York Stock Exchange. | | |
| | | | | | | | | | | | | | |
(f) | | Common Shareholders' Equity adjusted for goodwill and intangibles divided by total common shares outstanding. | | |
| | | | | | | | | | | | | | |
(g) | Net Income Attributable to Common Shareholders divided by average Common Shareholders' Equity. | | |
| | | | | | | | | | | | | | |
(h) | The closing market price divided by the book value per share. | | | | | |
| | | | | | | | | | | | | | |
See theCombined Notes to Consolidated Financial Statements in this Annual Report on Form 10-K for a description of any accounting changes materially affecting the comparability of the information reflected in the tables above. | See theCombined Notes to Consolidated Financial Statements in this Annual Report on Form 10-K for a description of any accounting changes materially affecting the comparability of the information reflected in the tables above. | | See theCombined Notes to Consolidated Financial Statements in this Annual Report on Form 10-K for a description of any accounting changes materially affecting the comparability of the information reflected in the tables above. |
3026
|
NU Selected Consolidated Sales Statistics | | | | | | | | | | |
| | 2013 | | | 2012(a) | | | 2011 | | | 2010 | | | 2009 |
Eversource Selected Consolidated Sales Statistics | | | | | | | | |
| | | | | | | | | | | | 2015 | | | 2014 | | | 2013 | | | 2012(a) | | | 2011 |
Revenues: (Thousands) | | | | | | | | | | | | | | | | | | | | |
Residential | $ | 3,073,181 | | $ | 2,731,951 | | $ | 2,091,270 | | $ | 2,336,078 | | $ | 2,569,278 | $ | 3,608,155 | | $ | 3,288,313 | | $ | 3,073,181 | | $ | 2,731,951 | | $ | 2,091,270 |
Commercial | | 2,387,535 | | 1,604,661 | | 1,236,374 | | 1,346,228 | | 1,495,821 | | 2,476,686 | | 2,471,440 | | 2,387,535 | | 1,604,661 | | 1,236,374 |
Industrial | | 339,917 | | 753,974 | | 252,878 | | 268,598 | | 297,854 | | 326,564 | | 348,698 | | 339,917 | | 753,974 | | 252,878 |
Wholesale | | 486,515 | | 357,223 | | 350,413 | | 506,475 | | 445,261 | | 411,749 | | 447,899 | | 486,515 | | 357,223 | | 350,413 |
Miscellaneous and Eliminations | | 56,547 | | | 130,137 | | | 47,485 | | | (29,878) | | | 128,118 |
Other and Eliminations | | 110,013 | | | 97,090 | | | 56,547 | | | 130,137 | | | 47,485 |
Total Electric | | 6,343,695 | | 5,577,946 | | 3,978,420 | | 4,427,501 | | 4,936,332 | | 6,933,167 | | 6,653,440 | | 6,343,695 | | 5,577,946 | | 3,978,420 |
Natural Gas | | 855,601 | | | 572,857 | | | 430,799 | | | 434,277 | | | 449,571 | | 993,662 | | | 1,002,880 | | | 855,601 | | | 572,857 | | | 430,799 |
Total - Regulated Companies | | 7,199,296 | | 6,150,803 | | 4,409,219 | | 4,861,778 | | 5,385,903 | | 7,926,829 | | 7,656,320 | | 7,199,296 | | 6,150,803 | | 4,409,219 |
Other and Eliminations | | 101,908 | | | 122,984 | | | 56,438 | | | 36,389 | | | 53,527 | | 27,998 | | | 85,536 | | | 101,908 | | | 122,984 | | | 56,438 |
Total | $ | 7,301,204 | | $ | 6,273,787 | | $ | 4,465,657 | | $ | 4,898,167 | | $ | 5,439,430 | $ | 7,954,827 | | $ | 7,741,856 | | $ | 7,301,204 | | $ | 6,273,787 | | $ | 4,465,657 |
| | | | | | | | | | | | | | | | | | | | |
Regulated Companies - Sales: (GWh) | | | | | | | | | | |
Regulated Companies - Sales Volumes: | | | | | | | | | | |
Electric (GWh) | | | | | | | | | | |
Residential | | 21,896 | | 19,719 | | 14,766 | | 14,913 | | 14,412 | | 21,441 | | 21,317 | | 21,896 | | 19,719 | | 14,766 |
Commercial | | 27,787 | | 24,537 | | 14,628 | | 14,836 | | 14,810 | | 27,598 | | 27,449 | | 27,787 | | 24,537 | | 14,628 |
Industrial | | 5,648 | | 5,462 | | 4,418 | | 4,481 | | 4,423 | | 5,577 | | 5,676 | | 5,648 | | 5,462 | | 4,418 |
Wholesale | | 855 | | | 2,154 | | | 1,020 | | | 3,423 | | | 4,183 | | 3,215 | | 3,018 | | 855 | | 2,154 | | 1,020 |
Total | | 56,186 | | | 51,872 | | | 34,832 | | | 37,653 | | | 37,828 |
Total Electric | | 57,831 | | 57,460 | | 56,186 | | 51,872 | | 34,832 |
Natural Gas(million cubic feet) | | 102,999 | | 104,191 | | 98,258 | | 69,894 | | 46,880 |
| | | | | | | | | | | | | | | | | | | | |
Regulated Companies - Customers: (Average) | | | | | | | | | | | | | | | | | | | | |
Residential | | 2,718,727 | | 2,711,407 | | 1,710,342 | | 1,704,197 | | 1,696,756 | | 2,747,679 | | 2,734,047 | | 2,718,727 | | 2,711,407 | | 1,710,342 |
Commercial | | 371,897 | | 370,389 | | 199,240 | | 198,558 | | 196,813 | | 374,552 | | 373,511 | | 371,897 | | 370,389 | | 199,240 |
Industrial | | 8,109 | | 8,279 | | 7,083 | | 7,150 | | 7,207 | | 7,868 | | 8,016 | | 8,109 | | 8,279 | | 7,083 |
Total Electric | | 3,098,733 | | 3,090,075 | | 1,916,665 | | 1,909,905 | | 1,900,776 | | 3,130,099 | | 3,115,574 | | 3,098,733 | | 3,090,075 | | 1,916,665 |
Natural Gas | | 493,563 | | | 483,770 | | | 207,753 | | | 205,885 | | | 206,438 | | 506,175 | | | 499,186 | | | 493,563 | | | 483,770 | | | 207,753 |
Total | | 3,592,296 | | | 3,573,845 | | | 2,124,418 | | | 2,115,790 | | | 2,107,214 |
Total - Regulated Companies | | 3,636,274 | | | 3,614,760 | | | 3,592,296 | | | 3,573,845 | | | 2,124,418 |
| | | | | | | | | | |
(a) The 2012 results include the operations of NSTAR beginning April 10, 2012. | | | | | | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | | | | |
(a) The 2012 results include the operations of NSTAR beginning April 10, 2012. | CL&P Selected Sales Statistics | | | | | | | | | |
| | 2015 | | | 2014 | | | 2013 | | | 2012 | | | 2011 |
Revenues: (Thousands) | | | | | | | | | | |
Residential | $ | 1,641,165 | | $ | 1,474,181 | | $ | 1,294,160 | | $ | 1,263,845 | | $ | 1,345,290 |
Commercial | | 841,093 | | 879,343 | | 780,585 | | 732,620 | | 758,145 |
Industrial | | 129,544 | | 149,220 | | 129,557 | | 126,165 | | 126,783 |
Wholesale | | 128,169 | | 146,787 | | 219,367 | | 214,807 | | 278,751 |
Other | | 62,704 | | | 43,051 | | | 18,672 | | | 70,012 | | | 39,418 |
Total | $ | 2,802,675 | | $ | 2,692,582 | | $ | 2,442,341 | | $ | 2,407,449 | | $ | 2,548,387 |
Sales Volumes: (GWh) | | | | | | | | | | |
Residential | | 10,094 | | 10,026 | | 10,314 | | 9,978 | | 10,092 |
Commercial | | 9,635 | | 9,643 | | 9,770 | | 9,705 | | 9,809 |
Industrial | | 2,342 | | 2,377 | | 2,320 | | 2,426 | | 2,414 |
Wholesale | | 712 | | | 736 | | | 851 | | | 1,155 | | | 1,592 |
Total | | 22,783 | | | 22,782 | | | 23,255 | | | 23,264 | | | 23,907 |
Customers: (Average) | | | | | | | | | | |
Residential | | 1,117,778 | | 1,111,467 | | 1,105,417 | | 1,103,397 | | 1,100,740 |
Commercial | | 109,339 | | 109,093 | | 108,735 | | 108,589 | | 108,235 |
Industrial | | 3,163 | | | 3,213 | | | 3,247 | | | 3,301 | | | 3,331 |
Total | | 1,230,280 | | | 1,223,773 | | | 1,217,399 | | | 1,215,287 | | | 1,212,306 |
| | | | | | | | | | | | | | |
CL&P Selected Sales Statistics | | | | | | | | | | | | | |
| | 2013 | | | 2012 | | | 2011 | | | 2010 | | | 2009 |
| | | | | | | | | | | | | | |
Revenues: (Thousands) | | | | | | | | | | | | | | |
Residential | $ | 1,294,160 | | $ | 1,263,845 | | $ | 1,345,290 | | $ | 1,597,754 | | $ | 1,840,750 |
Commercial | | 780,585 | | | 732,620 | | | 758,145 | | | 853,956 | | | 958,224 |
Industrial | | 129,557 | | | 126,165 | | | 126,783 | | | 144,463 | | | 151,839 |
Wholesale | | 219,367 | | | 214,807 | | | 278,751 | | | 441,660 | | | 386,034 |
Miscellaneous | | 18,672 | | | 70,012 | | | 39,418 | | | (38,731) | | | 87,691 |
Total | $ | 2,442,341 | | $ | 2,407,449 | | $ | 2,548,387 | | $ | 2,999,102 | | $ | 3,424,538 |
Sales: (GWh) | | | | | | | | | | | | | | |
Residential | | 10,314 | | | 9,978 | | | 10,092 | | | 10,196 | | | 9,848 |
Commercial | | 9,770 | | | 9,705 | | | 9,809 | | | 10,002 | | | 9,991 |
Industrial | | 2,320 | | | 2,426 | | | 2,414 | | | 2,467 | | | 2,427 |
Wholesale | | 851 | | | 1,155 | | | 1,592 | | | 3,040 | | | 3,434 |
Total | | 23,255 | | | 23,264 | | | 23,907 | | | 25,705 | | | 25,700 |
Customers: (Average) | | | | | | | | | | | | | | |
Residential | | 1,105,417 | | | 1,103,397 | | | 1,100,740 | | | 1,096,576 | | | 1,093,229 |
Commercial | | 108,735 | | | 108,589 | | | 108,235 | | | 107,532 | | | 107,121 |
Industrial | | 3,247 | | | 3,301 | | | 3,331 | | | 3,359 | | | 3,381 |
Total | | 1,217,399 | | | 1,215,287 | | | 1,212,306 | | | 1,207,467 | | | 1,203,731 |
3127
Item 7.
Management's Discussion and Analysis of Financial Condition and Results of Operations
EVERSOURCE ENERGY AND SUBSIDIARIES
The following discussion and analysis should be read in conjunction with our consolidated financial statements and related combined notes included in this combined Annual Report on Form 10-K. References in this Annual Report on Form 10-K to "NU,"Eversource," the "Company," "we," "us," and "our" refer to Northeast UtilitiesEversource Energy and its consolidated subsidiaries. All per share amounts are reported on a diluted basis. The consolidated financial statements of NU,Eversource, NSTAR Electric and PSNH and the financial statements of CL&P and WMECO are herein collectively referred to as the "financial statements."
On April 30, 2015, the Company's legal name was changed from Northeast Utilities to Eversource Energy. CL&P, NSTAR Electric, PSNH and WMECO are each doing business as Eversource Energy.
Refer to the Glossary of Terms included in this combined Annual Report on Form 10-K for abbreviations and acronyms used throughout thisManagement's Discussion and Analysis of Financial Condition and Results of Operations.
The only common equity securities that are publicly traded are common shares of NU.Eversource. The earnings and EPS of each business discussed below do not represent a direct legal interest in the assets and liabilities allocated toof such business but rather represent a direct interest in our assets and liabilities as a whole. EPS by business is a financial measure not recognized under GAAP that is calculated by dividing the Net Income Attributable to Controlling InterestCommon Shareholders of each business by the weighted average diluted NUEversource common shares outstanding for the year.period. The discussion below also includes non-GAAP financial measures referencing our 2013, 20122015, 2014 and 20112013 earnings and EPS excluding certain integration costs incurred by Eversource parent and merger costs related to NU's merger with NSTAR and a 2011 non-recurring charge at CL&P for the establishment of a reserve to provide bill credits to its residential customers and donations to charitable organizations.our Regulated companies. We use these non-GAAP financial measures to evaluate and to provide details of earnings by business and to more fully compare and explain our 2013, 20122015, 2014 and 20112013 results without including the impact of these non-recurring items. Due to the nature and significance of these items on Net Income Attributable to Controlling Interest,Common Shareholders, we believe that the non-GAAP presentation is more representative of our financial performance and provides additional and useful information to readers of this report in analyzing historical and future performance by business. These non-GAAP financial measures should not be considered as an alternative to reported Net Income Attributable to Controlling InterestCommon Shareholders or EPS determined in accordance with GAAP as an indicator of operating performance.
Reconciliations of the above non-GAAP financial measures to the most directly comparable GAAP measures of consolidated diluted EPS and Net Income Attributable to Controlling InterestCommon Shareholders are included under "Financial Condition and Business Analysis – Overview – Consolidated" and "Financial Condition and Business Analysis – Overview – Regulated Companies" inManagement's Discussion and Analysis of Financial Condition and Results of Operations, herein.
Financial Condition and Business Analysis
Merger with NSTAR:
On April 10, 2012, we completed our merger with NSTAR. Unless otherwise noted, the results of NSTAR and its subsidiaries, hereinafter referred to as "NSTAR," are included in NU’s financial position, results of operations and cash flows as of December 31, 2013 and 2012, for the full year ended December 31, 2013, and for the period beginning April 10, 2012 through December 31, 2012 throughout thisManagement's Discussion and Analysis of Financial Condition and Results of Operations.
Executive Summary
The following items in this executive summary are explained in more detail in this Annual Report:
Results:
·
We earned $786$878.5 million, or $2.49$2.76 per share, in 2013,2015, compared with $525.9$819.5 million, or $1.89$2.58 per share, in 2012.2014. Excluding after-tax integration and merger-related costs, of $13.8we earned $894.3 million, or $0.04$2.81 per share, in 20132015 and $107.6$841.6 million, or $0.39$2.65 per share, in 2012, we earned $799.8 million, or $2.53 per share, in 2013 and $633.5 million, or $2.28 per share, in 2012.2014.
·
Our electric distribution segment, which includes generation, earned $427$507.9 million, or $1.35$1.59 per share, in 2013,2015, compared with $292.3$462.4 million, or $1.04$1.45 per share, in 2012. The 2012 results include $51.1 million, or $0.19 per share, of after-tax merger settlement agreement costs.
·
2014. Our electric transmission segment earned $287$304.5 million, or $0.91$0.96 per share, in 2013,2015, compared with $249.7$295.4 million, or $0.90$0.93 per share, in 2012.
·
2014. Our natural gas distribution segment earned $60.9$72.4 million, or $0.19$0.23 per share, in 2013,2015, compared with $30.8$72.3 million, or $0.11$0.23 per share, in 2012.2014. The 20122015 electric and natural gas distribution results include $2.1exclude $0.8 million or $0.01 per share, of after-tax merger settlement agreementintegration costs.
·
NUEversource parent and other companies recorded earnings of $11.1earned $9.5 million, or $0.03 per share, in 2015, compared with $11.5 million, or $0.04 per share, in 2013, compared with net losses of $46.92014. The 2015 and 2014 results exclude $15 million, or $0.16 per share, in 2012. The 2013 and 2012 results include $13.8 million, or $0.04$0.05 per share, and $54.4$22.1 million, or $0.19$0.07 per share, respectively, of after-tax integration and merger-related costs.
Liquidity:
·
Cash flows provided by operating activities totaled $1.4 billion in 2015, compared with $1.6 billion in 2014. Investments in property, plant and equipment totaled $1.7 billion in 2015 and $1.6 billion in 2014. Cash and cash equivalents totaled $23.9 million as of December 31, 2015, compared with $38.7 million as of December 31, 2014.
·
In 2015, we issued approximately $1.23 billion of new long-term debt consisting of $450 million by Eversource parent, $350 million by CL&P, $250 million by NSTAR Electric, $100 million by NSTAR Gas, and $75 million by Yankee Gas. In 2015, we repaid $212 million of existing long-term debt consisting of $162 million by CL&P and $50 million by WMECO.
·
In 2015, we paid cash dividends on common shares of $529.8 million, compared with $475.2 million in 2014. On February 3, 2016, our Board of Trustees approved a common share dividend payment of $0.445 per share, payable on March 31, 2016 to shareholders of record as of March 2, 2016. The 2016 dividend represented an increase of 6.6 percent over the dividend paid in December 2015, and is the equivalent to dividends on common shares of approximately $565 million on an annual basis.
28
·
We project to make capital expenditures of approximately $7.6$9.2 billion from 20142016 through 2017.2019. Of the $7.6$9.2 billion, we expect to invest approximately $3.5$4.9 billion in our electric and natural gas distribution segments and $3.7$3.9 billion in our electric transmission segment. In addition, we project to invest approximately $400 million for our corporate service companies.
32
$0.4 billion in information technology and facilities upgrades and enhancements. These projections do not include capital investments related to Access Northeast or Clean Energy Connect.
Strategic, Legislative, Regulatory, Policy and Other Items:
·
In 2013, CL&P and NSTAR Electric filed a request with the PURA and DPU, respectively, seeking approval to recover storm restoration costs. On December 30, 2013,18, 2015, the DPU approved recoveryNew Hampshire Site Evaluation Committee (NH SEC) accepted NPT’s application as complete allowing the formal siting process to move forward. The project is expected to be operational in the first half of NSTAR Electric’s $34.2 million in storm restoration costs.2019. On February 3, 2014,January 28, 2016, NPT bid into the PURA issued a draft decision, approving recovery of CL&P’s $365 million in storm restoration costs.three-state Clean Energy RFP process.
·
In 2013, Connecticut enactedThe Clean Energy Connect Project is a planned transmission, wind and hydro generation project that we plan to co-develop with experienced renewable generation companies. On January 28, 2016, the Clean Energy Connect project was bid into law two significant energy bills. The first law implemented a numberthe three-state Clean Energy RFP process. Our investment, should the Clean Energy Connect Project be selected in the RFP process, is currently estimated to be at least $400 million and will consist of the recommendations proposed in the Connecticut comprehensive energy strategy (CES), including the expansionMassachusetts portion of natural gas service, and required PURA to implement decoupling for each of Connecticut’s electric and natural gas utilities in their next respective rate cases. The second law allows DEEP to conduct a process that will ultimately help Connecticut meet its Renewable Portfolio Standard by authorizing the state’s electric distribution companies to enter into long-term power purchase agreements.new 25-mile, 345 kV transmission line with a 600 MW capacity.
·
On November 22, 2013,January 28, 2016, the PURA issued a final decision approving a comprehensive jointDPU approved NSTAR Electric’s, WMECO’s, and NSTAR Gas’ three-year electric and natural gas infrastructure expansionenergy efficiency plan, (expansion plan), consistentwhich was jointly developed with the goals of the CES, that was filed in June 2013 by Yankee Gasother Massachusetts electric distribution companies (EDCs) and other Connecticut natural gas distribution companies. The expansion plan described howOn December 31, 2015, DEEP approved CL&P’s and Yankee Gas expects to add approximately 82,000 newGas’ three-year electric and natural gas heating customers overC&LM plan, which was jointly developed with other Connecticut EDCs and natural gas distribution companies. These electric and natural gas energy efficiency and C&LM plans include the next 10 years. ability to earn performance incentives as well as recover LBR for NSTAR Electric until it is operating under a decoupled rate structure.
·
On July 1, 2013, NPT filed an amendment toJanuary 7, 2015, the Department of Energy (DOE) Presidential Permit Application for a proposed improved route in the northernmost section of the project area. The DOE completed its public scoping meeting process and the majority of its seasonal field work and environmental data collection. On December 11, 2013, NPT filed an amendment to the Transmission Services Agreement (TSA) with FERC, which was accepted on January 13, 2014. On December 31, 2013, NPT received ISO-NE approval under Section I.3.9 of the ISO tariff.
·
On August 6, 2013, the FERC ALJDPU issued an initial decision regarding the September 2011 joint complaint filed with the FERC by various New England parties concerning theorder concluding that NSTAR Electric had removed energy-related bad debt costs from base ROE earned by New England transmission owners (NETOs). The initial decision found that the current base ROE is not reasonable, but leaves policy considerations and additional adjustments to the FERC, and determined that a separate base ROE of 10.6 percent and 9.7 percent should be set for the refund period (Octoberdistribution rates effective January 1, 2011 through December 31, 2012) and the prospective period (beginning when FERC issues its final decision), respectively. The FERC may adjust the prospective period base ROE in its final decision, expected in 2014, to reflect movement in the capital markets from when the case was filed in April 2013.2006. As a result of the DPU order, in 2013, we recorded a reservethe first quarter of 2015 NSTAR Electric increased its regulatory assets and recognized an after-tax charge of $14.3reduced its operations and maintenance expense by $24.2 million for energy-related bad debt costs through 2014, resulting in after-tax earnings of $14.5 million. NSTAR Electric filed for recovery of the potential financial impactenergy-related bad debt costs regulatory asset from the FERC ALJ's initial decision.
·
Oncustomers and on November 20, 2013, GSRP,2015, the first, largest and most complicated project within the NEEWS family of projects was fully energized. The project was fully energized ahead of schedule withDPU approved NSTAR Electric’s proposed rate increase to recover these costs over a final cost of $676 million, $42 million under the $718 million estimated cost.
Liquidity:
·
Cash and cash equivalents totaled $43.4 million as of December 31, 2013, compared with $45.7 million as of December 31, 2012, while investments in property, plant and equipment totaled $1.5 billion in both 2013 and 2012.
·
Cash flows provided by operating activities in 2013 totaled $1.58 billion, compared with operating cash flows of $1.05 billion in 2012 (amounts are net of RRB payments). The improved cash flows were due primarily to the addition of NSTAR, a decrease in storm restoration costs, and the absence in 2013 of customer bill credits and merger-related costs paid in 2012, partially offset by an increase in Pension Plan cash contributions.
·
In 2013, we issued $1.68 billion of new long-term debt consisting of $750 million by NU parent, $400 million by CL&P, $200 million by NSTAR Electric, $250 million by PSNH, and $80 million by WMECO. These new issuances were used primarily to repay approximately $928 million of existing long-term debt and PCRBs. On12-month period, beginning January 2, 2014, Yankee Gas issued $100 million of new long-term debt. As of December 31, 2013, approximately $502 million of NU's current liabilities relate to long-term debt that will be paid in the next 12 months.
·
On February 4, 2014, our Board of Trustees approved a common dividend payment of $0.3925 per share, payable on March 31, 2014 to shareholders of record as of March 3, 2014. The dividend represented an increase of 6.8 percent over the quarterly dividend paid in December 2013.
33
1, 2016.
Overview
Consolidated: A summary of our earnings by business, which also reconciles the non-GAAP financial measures of consolidated non-GAAP earnings and EPS, as well as EPS by business, to the most directly comparable GAAP measures of consolidated Net Income Attributable to Controlling InterestCommon Shareholders and diluted EPS, for 2013, 2012 and 2011 is as follows:
| | | | | | | | | | | | | | | | | | |
| | For the Years Ended December 31, |
(Millions of Dollars, Except Per Share Amounts) | | 2013 | | 2012(1) | | 2011 |
| | Amount | | Per Share | | Amount | | Per Share | | Amount | | Per Share |
Net Income Attributable to Controlling Interest (GAAP) | | $ | 786.0 | | $ | 2.49 | | $ | 525.9 | | $ | 1.89 | | $ | 394.7 | | $ | 2.22 |
Regulated Companies
| | $ | 774.9 | | $ | 2.45 | | $ | 626.0 | | $ | 2.25 | | $ | 438.3 | | $ | 2.46 |
NU Parent and Other Companies | | | 24.9 | | | 0.08 | | | 7.5 | | | 0.03 | | | (14.4) | | | (0.08) |
Non-GAAP Earnings | | | 799.8 | | | 2.53 | | | 633.5 | | | 2.28 | | | 423.9 | | | 2.38 |
Integration and Merger-Related Costs (after-tax) | | | (13.8) | | | (0.04) | | | (107.6) | | | (0.39) | | | (11.3) | | | (0.06) |
Storm Fund Reserve | | | - | | | - | | | - | | | - | | | (17.9) | | | (0.10) |
Net Income Attributable to Controlling Interest (GAAP) | | $ | 786.0 | | $ | 2.49 | | $ | 525.9 | | $ | 1.89 | | $ | 394.7 | | $ | 2.22 |
(1)
Results include the operations of NSTAR beginning April 10, 2012.
| | | | | | | | | | | | | | | | | | |
| | For the Years Ended December 31, |
| | 2015 | | 2014 | | 2013 |
(Millions of Dollars, Except Per Share Amounts) | | Amount | | Per Share | | Amount | | Per Share | | Amount | | Per Share |
Net Income Attributable to Common Shareholders (GAAP) | | $ | 878.5 | | $ | 2.76 | | $ | 819.5 | | $ | 2.58 | | $ | 786.0 | | $ | 2.49 |
Regulated Companies
| | $ | 884.8 | | $ | 2.78 | | $ | 830.1 | | $ | 2.61 | | $ | 774.9 | | $ | 2.45 |
Eversource Parent and Other Companies | | | 9.5 | | | 0.03 | | | 11.5 | | | 0.04 | | | 24.9 | | | 0.08 |
Non-GAAP Earnings | | | 894.3 | | | 2.81 | | | 841.6 | | | 2.65 | | | 799.8 | | | 2.53 |
Integration Costs (after-tax) | | | (15.8) | | | (0.05) | | | (22.1) | | | (0.07) | | | (13.8) | | | (0.04) |
Net Income Attributable to Common Shareholders (GAAP) | | $ | 878.5 | | $ | 2.76 | | $ | 819.5 | | $ | 2.58 | | $ | 786.0 | | $ | 2.49 |
The 2013 after-tax integration-related2015 and 2014 integration costs consisted of costs incurred for employeeare associated with our branding efforts and severance in connection with ongoing integration, and consulting and retention costs. The 2012 after-tax merger-related costs consisted of Regulated companies’ charges of $53.2 million (for further information, see theRegulated Companiesportion of this Overview section), costs of $34 million at NU parent related to investment advisory fees, attorney fees, and consulting costs, an $11.5 million charge related to change in control costs and other compensation costs at NU parent, and an $8.9 million charge at NU parent for the establishment of a fund to advance Connecticut energy goals related to the Connecticut merger settlement agreement.
Excluding the impact of the integration and merger-related costs, our 2013 earnings increased by $166.3 million, as compared to 2012, due primarily to the inclusion of NSTAR beginning April 10, 2012, lower overall operations and maintenance costs, higher retail electric and firm natural gas sales, higher transmission segment earnings as a result of increased investments in the transmission infrastructure, and the favorable impact of a lower effective tax rate in 2013 at NU parent. Partially offsetting these favorable earnings impacts were higher depreciation and property tax expense and the establishment of an after-tax reserve of $14.3 million for a potential customer refund related to an August 2013 initial decision from the FERC ALJ. For further information, see "FERC Regulatory Issues - FERC Base ROE Complaint" in thisManagement's Discussion and Analysis.
Regulated Companies: Our Regulated companies consist of the electric distribution, electric transmission, and natural gas distribution segments. Generation activities of PSNH and WMECO are included in our electric distribution segment. A summary of our segment earnings for 2013, 2012 and 2011EPS is as follows:
| | | | | | | | |
| For the Years Ended December 31, |
(Millions of Dollars) | 2013 | | 2012(1) | | 2011 |
Net Income – Regulated Companies (GAAP) | $ | 774.9 | | $ | 572.8 | | $ | 420.4 |
| | | | | | | | |
Electric Distribution | $ | 427.0 | | $ | 343.4 | | $ | 207.0 |
Transmission | | 287.0 | | | 249.7 | | | 199.6 |
Natural Gas Distribution | | 60.9 | | | 32.9 | | | 31.7 |
Net Income – Regulated Companies (Non-GAAP) | | 774.9 | | | 626.0 | | | 438.3 |
Merger-Related Costs (after-tax) (2) | | - | | | (53.2) | | | - |
Storm Fund Reserve(3) | | - | | | - | | | (17.9) |
Net Income - Regulated Companies (GAAP) | $ | 774.9 | | $ | 572.8 | | $ | 420.4 |
| | | | | | | | | | | | | | | | | | |
| | For the Years Ended December 31, |
| | 2015 | | 2014 | | 2013 |
(Millions of Dollars, Except Per Share Amounts) | | Amount | | Per Share | | Amount | | Per Share | | Amount | | Per Share |
Electric Distribution | | $ | 507.9 | | $ | 1.59 | | $ | 462.4 | | $ | 1.45 | | $ | 427.0 | | $ | 1.35 |
Electric Transmission | | | 304.5 | | | 0.96 | | | 295.4 | | | 0.93 | | | 287.0 | | | 0.91 |
Natural Gas Distribution | | | 72.4 | | | 0.23 | | | 72.3 | | | 0.23 | | | 60.9 | | | 0.19 |
Non-GAAP Earnings | | | 884.8 | | | 2.78 | | | 830.1 | | | 2.61 | | | 774.9 | | | 2.45 |
Integration Costs (after-tax) | | | (0.8) | | | - | | | - | | | - | | | - | | | - |
Net Income - Regulated Companies | | $ | 884.0 | | $ | 2.78 | | $ | 830.1 | | $ | 2.61 | | $ | 774.9 | | $ | 2.45 |
(1)The 2015 Regulated companies' integration costs include severance in connection with cost saving initiatives.
Results include the operations of NSTAR beginning April 10, 2012.
(2)
Merger-related29
Excluding integration costs, are attributable to theour electric distribution segment ($51.1 million) and the natural gas distribution segment ($2.1 million).
(3)
The storm fund reserve is attributableearnings increased $45.5 million in 2015, as compared to the electric distribution segment.
The 2012 after-tax merger-related costs consisted of $27.6 million ($46 million pre-tax) in charges at CL&P, NSTAR Electric, NSTAR Gas and WMECO for customer bill credits related2014, due primarily to the Connecticut and Massachusetts merger settlement agreements, a $23.6 million ($40 million pre-tax) charge related to the Connecticut merger settlement agreement, whereby CL&P agreed to forego recovery of previously deferred storm restoration costs associated with Tropical Storm Irene and the October 2011 snowstorm, and a $2 million charge related to change in control costs and other compensation costs.
Excluding the impact of the merger-related costs, ourelectricDecember 1, 2014 CL&P base distribution segmentrate increase, the $27.5 million favorable earnings increased in 2013, as compared to 2012, due primarilyimpact related to the inclusionresolution of NSTAR Electric’s basic service bad debt adder and the settlement with the Massachusetts Attorney General on eleven open dockets covering the CPSL program filings and the recovery of LBR related to 2009 through 2011 energy efficiency programs at NSTAR Electric, distribution business’ earnings, lower overall operations and maintenance costsan increase in the recovery of LBR at NSTAR Electric related to 2015 energy efficiency programs, and higher retail electric sales due primarily to colder weather in the firstvolumes at NSTAR Electric and fourth quarters of 2013, as compared to the same periods in 2012. The 2013 results were also favorably impacted by PSNH rate increases effective July 1, 2012 and July 1, 2013 as a result of the 2010 distribution rate case settlement.PSNH. Partially offsetting these favorable earnings impacts were a higher effective tax rate in 2015, higher property taxes, higher depreciation expense and property tax expense.
34
a $5 million contribution in 2015 to create a clean energy fund in connection with the PSNH divestiture agreement.
Our electric transmission segment earnings increased $9.1 million in 2013,2015, as compared to 2012,2014, due primarily to the inclusionresult of NSTAR Electriclower reserve charges associated with the FERC ROE complaint proceedings of $12.4 million recorded in 2015, as compared to $22.4 million recorded in 2014, and a higher transmission business’ earnings,rate base as a result of an increased investmentsinvestment in our transmission infrastructure, including GSRP,infrastructure. These favorable earnings impacts were partially offset by a higher effective tax rate in 2015.
Our natural gas distribution segment earnings increased $0.1 million in 2015, as compared to 2014. Our natural gas distribution segment earnings were favorably impacted by a decrease in operations and the favorable impact ofmaintenance costs primarily attributable to lower employee-related expenses, a lower effective tax rate in 2013, partially2015, and additional natural gas heating customers. These favorable earnings impacts were offset by a decrease in firm natural gas sales volumes driven by record warm weather in the $14.3 million after-tax reserve relatedfourth quarter of 2015, as compared to the August 2013 FERC ALJ initial decision.2014, higher depreciation expense and higher property taxes.
Eversource Parent and Other Companies: Excluding the impact of the merger-relatedintegration costs, ournatural gas distribution segmentEversource parent and other companies had earnings increasedof $9.5 million in 2013,2015, compared with earnings of $11.5 million in 2014. The earnings decrease was due primarily to a higher effective tax rate at Eversource parent in 2015, as compared to 2012, due primarily to the inclusion of NSTAR Gas’ earnings,2014, higher firm natural gas sales due primarily to colder weather in the first and fourth quarters of 2013, as compared to the same periods in 2012, as well as the addition of approximately 10,000 new natural gas heating customers in 2013, and the favorable impact related to an increase in Yankee Gas rates effective July 1, 2012interest expense at Eversource parent as a result of new debt issuances in January 2015, and reduced earnings in 2015 from Eversource's unregulated electrical contracting business, which was sold in April 2015. These unfavorable earnings impacts were partially offset by a reduction in operations and maintenance costs.
Electric and Natural Gas Sales Volumes: Weather, fluctuations in energy supply costs, conservation measures (including utility-sponsored energy efficiency programs), and economic conditions affect customer energy usage. Industrial sales volumes are less sensitive to temperature variations than residential and commercial sales volumes. In our service territories, weather impacts electric sales volumes during the Yankee Gas 2011summer and both electric and natural gas sales volumes during the winter; however, natural gas sales volumes are more sensitive to temperature variations than are electric sales volumes. Customer heating or cooling usage may not directly correlate with historical levels or with the level of degree-days that occur.
Fluctuations in retail electric sales volumes at NSTAR Electric and PSNH impact earnings ("Traditional" in the table below). For CL&P (effective December 1, 2014) and WMECO, fluctuations in retail electric sales volumes do not impact earnings due to their respective regulatory commission approved revenue decoupling mechanisms (“Decoupled” in the table below). These distribution revenues are decoupled from their customer sales volumes, which breaks the relationship between sales volumes and revenues recognized. CL&P and WMECO reconcile their annual base distribution rate case decision.recovery amounts to their respective pre-established levels of baseline distribution delivery service revenues. Any difference between the allowed level of distribution revenue and the actual amount incurred during a 12-month period is adjusted through rates in the following period.
A summary of our retail electric GWh sales volumes and percentage changes, assuming NSTAR Electric had been part of the NU electric distribution system for all periods, as well as percentage changes in CL&P, NSTAR Electric, PSNH and WMECO retail electric GWh sales, is as follows:
| | | | | |
| For the Year Ended
December 31, 2013 Compared to 2012 |
| Sales (GWh) | | |
NU - Electric | 2013 | | 2012(1) | | Percentage
Increase/
(Decrease) |
Residential | 21,896 | | 21,374 | | 2.4 % |
Commercial(2) | 27,787 | | 27,647 | | 0.5 % |
Industrial | 5,648 | | 5,787 | | (2.4)% |
Total | 55,331 | | 54,808 | | 1.0 % |
| | | | | | | |
| For the Year Ended December 31, 2013 Compared to 2012 |
| CL&P | | NSTAR
Electric | | PSNH | | WMECO |
Electric | Percentage
Increase/
(Decrease) | | Percentage
Increase/
(Decrease) | | Percentage
Increase | | Percentage
Increase/
(Decrease) |
Residential | 3.4 % | | 1.3 % | | 2.2% | | 1.7 % |
Commercial(2) | 0.7 % | | 0.4 % | | 0.6% | | (0.4)% |
Industrial | (4.4)% | | (3.0)% | | 2.1% | | (3.0)% |
Total | 1.3 % | | 0.5 % | | 1.5% | | - % |
(1)
Results include retail electric sales of NSTAR Electric from January 1, 2012 through December 31, 2012 for comparative purposes only.
(2)
Commercial retail electric GWh sales include streetlighting and railroad retail sales.
A summary of our firm natural gas sales volumes in million cubic feet and percentage changes assuming NSTAR Gas had been part of the NU natural gas distribution system for all periods, as well as percentage changes in Yankee Gas and NSTAR Gas, for 2013, as compared to 2012, is as follows:
| | | | | |
| For the Year Ended
December 31, 2013 Compared to 2012 |
| Sales (million cubic feet) | | Percentage |
NU - Firm Natural Gas | 2013 | | 2012(1) | | Increase |
Residential | 36,777 | | 30,873 | | 19.1% |
Commercial | 40,215 | | 35,662 | | 12.8% |
Industrial | 21,266 | | 20,992 | | 1.3% |
Total | 98,258 | | 87,527 | | 12.3% |
Total, Net of Special Contracts(2) | 94,083 | | 81,772 | | 15.1% |
35
|
| For the Year Ended
December 31, 2013 Compared to 2012 | For the Year Ended December 31, 2015 Compared to 2014 |
| Sales Volumes (GWh) | | Percentage |
Electric | 2015 | | 2014 | | Increase/(Decrease) |
Traditional: | | | | | |
Residential | 9,882 | | 9,798 | | 0.9% |
Commercial | 16,486 | | 16,340 | | 0.9% |
Industrial | 2,614 | | 2,673 | | (2.2)% |
Total - Traditional | 28,982 | | 28,811 | | 0.6% |
| | | | | |
Decoupled: | | | | | |
Residential | 11,559 | | 11,519 | | 0.3% |
Commercial | 11,112 | | 11,109 | | - % |
Industrial | 2,963 | | 3,003 | | (1.3)% |
Total - Decoupled | 25,634 | | 25,631 | | - % |
Total Sales Volumes | 54,616 | | 54,442 | | 0.3% |
| Sales (million cubic feet) | |
| Yankee Gas | | NSTAR Gas(3) | For the Year Ended December 31, 2015 Compared to 2014 |
| Percentage | | Percentage | Sales Volumes (million cubic feet) | | Percentage |
Firm Natural Gas | Increase/(Decrease) | | Increase | 2015 | | 2014 | | Increase/(Decrease) |
Residential | 19.0 % | | 19.2% | 38,455 | | 38,969 | | (1.3)% |
Commercial | 13.9 % | | 11.8% | 43,006 | | 42,977 | | 0.1 % |
Industrial | (1.9)% | | 10.9% | 21,538 | | 22,245 | | (3.2)% |
Total | 9.8 % | | 14.9% |
Total, Net of Special Contracts(2) | 15.3 % | | |
Total Sales Volumes | 102,999 | | 104,191 | | (1.1)% |
Total, Net of Special Contracts(1) | 98,458 | | 99,500 | | (1.0)% |
(1)
Results include firm natural gas sales of NSTAR Gas from January 1, 2012 through December 31, 2012 for comparative purposes only.
(2)
Special contracts are unique to the natural gas distribution customers who take service under such an arrangement and generally specify the amount of distribution revenue to be paid to Yankee Gas regardless of the customers’customers' usage.
(3)
NSTAR Gas’ sales data for the year ended December 31, 2013 compared to 2012 has been provided for comparative purposes only.30
Weather, fluctuations in energy supply costs, conservation measures (including company-sponsored energy efficiency programs), and economic conditions affect customer energy usage. Industrial sales are less sensitive to temperature variations than residential and commercial sales. In our service territories, weather impacts electric sales during the summer and electric and natural gas sales during the winter (natural gas sales are more sensitive to temperature variations than electric sales). Customer heating or cooling usage may not directly correlate with historical levels or with the level of degree-days that occur. In addition, our electric and natural gas businesses are susceptible to damage from major storms and other natural events and disasters that could adversely affect our ability to provide energy.
Our 2013 consolidated2015 retail electric sales volumes at our electric utilities with a traditional rate structure (NSTAR Electric and PSNH) were slightly higher, as compared to 2012,2014, due primarily to the impact of colder winter weather experienced in the first quarter of 2015 and warmer weather in the first and fourth quartersthird quarter of 2013. The 2013 retail electric sales for CL&P, NSTAR Electric and PSNH increased while they remained unchanged for WMECO, as compared to 2012, due primarily to colder2015, partially offset by milder winter weather in the first and fourth quartersquarter of 2013.2015 throughout those service territories. In 2013,2015, heating degree days were 171 percent higher in Connecticut and western Massachusetts, 16 percenthigherlower in the Boston metropolitan area, and 15 percent higher in New Hampshire, and cooling degree days were 7 percent lower in Connecticut and western Massachusetts, 2 percenthigher in the Boston metropolitan area, and 95 percent lower in New Hampshire, as compared to 2012. On a weather-normalized basis (based on 30-year average temperatures), 20132014. Cooling degree days in 2015 were 19 percent higher in the Boston metropolitan area and 57 percent higher in New Hampshire, as compared to 2014. Weather-normalized retail electric sales for CL&P and PSNH increased, while they decreased for NSTAR Electric and WMECO,volumes were relatively unchanged in 2015, as compared to 2012. The 2013 weather-normalized NU consolidated total retail electric sales remained relatively unchanged, as compared to 2012.
For WMECO, fluctuations2014. Improved economic conditions were offset by an increase in retail electric sales do not impact earnings due to the DPU-approved revenue decoupling mechanism. Under this decoupling mechanism, WMECO has an overall fixed annual level of distribution delivery service revenues of $132.4 million, comprised of customer base rate revenues of$125.4 million and a baseline low income discount recovery of $7 million. These two mechanisms effectively break the relationship between sales volume and revenues recognized.conservation efforts resulting from company-sponsored energy efficiency programs.
Our 2013 consolidated firm natural gas sales volumes are subject to many of the same influences as our retail electric sales butvolumes. In addition, they have benefittedbenefited from favorablecustomer growth in both of our natural gas prices and customer growth across all three customer classes. Our 2013distribution companies. In 2015, consolidated firm natural gas sales volumes were higher,lower, as compared to 2012, due primarily2014. The 2015 firm natural gas sales volumes were negatively impacted by record warm weather in the fourth quarter of 2015, when compared to 2014, partially offset by colder winter weather in the first and fourth quartersquarter of 2013. The 2013 weather-normalized NU2015, as compared to 2014, throughout our natural gas service territories. Weather-normalized Eversource consolidated total firm natural gas sales volumes increased 0.92.5 percent in 2015, as compared to 2012,2014, due primarily to improved economic conditions as well as residential and commercial customer growth, an increase in natural gas conversions,partially offset by customer conservation efforts resulting from company-sponsored energy efficiency programs. On October 30, 2015, the migration of interruptible customers switching to firm service rates, and the addition of gas-fired distributed generation, all of which was primarilyDPU issued its order in the YankeeNSTAR Gas service territory.distribution rate case, which included the establishment of a revenue decoupling mechanism beginning January 1, 2016.
NU Parent and Other Companies: NU parent and other companies (which includes certain subsidiariesPrior to December 1, 2014, CL&P earned LBR related to reductions in sales volume as a result of successful energy efficiency programs. LBR was recovered from retail customers through the FMCC. Effective December 1, 2014, CL&P no longer earns LBR due to its revenue decoupling mechanism. NSTAR beginning April 10, 2012, and our competitive businesses held by NU Enterprises) earned $11.1Electric recognized LBR of $60.6 million in 2013, compared with net losses of $46.92015 and $39.9 million in 2012. Excluding the impact2014. On January 28, 2016, NSTAR Electric received approval of integrationa three-year energy efficiency plan, which includes recovery of LBR until it is operating under a decoupled rate structure.
For further information, see "Regulatory Developments and merger-related costsRate Matters - Massachusetts - NSTAR Electric, WMECO and NSTAR Gas Energy Efficiency Plan" and "Regulatory Developments and Rate Matters - Massachusetts - NSTAR Gas Distribution Rates" in thisManagement's Discussion and Analysis of $13.8 million in 2013Financial Conditions and $54.4 million in 2012, NU parent and other companies earned $24.9 million in 2013, compared with $7.5 million in 2012. Improved 2013 results were due primarily to a lower effective tax rate, a decrease in interest expense at NU parent, and an increase in earnings at the unregulated businesses.Results of Operations.
Future Outlook
20142016 EPS Guidance: We currently project 20142016 earnings of between $2.60$2.90 per diluted share and $2.75$3.05 per diluted share.
Liquidity
Consolidated: Cash and cash equivalents totaled $43.4$23.9 million as of December 31, 2013,2015, compared with $45.7$38.7 million as of December 31, 2012.2014.
CL&PLong-Term Debt Issuances and Repayments: On January 15, 2015, Eversource parent issued $400$150 million of 2.5 percent 2013 Series A First and Refunding Mortgage Bonds on January 15, 2013, due to mature in 2023. The proceeds, net of issuance costs, were used to pay short-term borrowings outstanding under the CL&P credit agreement of $89 million and intercompany loans related to our commercial paper program of $305.8 million. On September 3, 2013, CL&P
36
redeemed at par $125 million of 1.25 percent Series B 2011 PCRBs, which were subject to mandatory tender for purchase, using short-term debt.
NSTAR Electric issued $200 million of three-year floating rate debentures on May 17, 2013, due to mature in 2016. The proceeds, net of issuance costs, were used to pay short-term borrowings and for general corporate purposes.
PSNH redeemed at par approximately $109 million of the 5.45 percent 2001 Series C PCRBs on May 1, 2013, which were due to mature in 2021, using short-term debt. On November 14, 2013, PSNH issued $250 million of 3.50 percent Series S First Mortgage Bonds, due to mature in 2023. On December 23, 2013, PSNH redeemed approximately $89 million of the 4.75 percent Series B PCRBs, which were due to mature in 2021, using a portion of the proceeds from the Series S First Mortgage Bonds. The remaining Series S First Mortgage Bond proceeds were used to pay short-term borrowings.
WMECO repaid at maturity $55 million of 5 percent Series A Senior Notes on September 1, 2013, using short-term debt. On November 15, 2013, WMECO issued $80 million of 3.881.60 percent Series G Senior Notes, due to mature in 2023. The proceeds, net of issuance costs, were used to pay short-term borrowings2018, and for other working capital purposes.
NU parent issued $750 million of Senior Notes on May 13, 2013, consisting of $300 million of 1.453.15 percent Series EH Senior Notes, due to mature in 2018,2025.
On May 20, 2015 and $450December 1, 2015, CL&P issued $300 million and $50 million, respectively, of 2.804.15 percent 2015 Series F Senior Notes,A First and Refunding Mortgage Bonds due to mature in 2023. 2045.
On September 10, 2015, Yankee Gas issued $75 million of 3.35 percent 2015 Series M First Mortgage Bonds due to mature in 2025.
On November 18, 2015, NSTAR Electric issued $250 million of 3.25 percent debentures, due to mature in 2025.
On December 8, 2015, NSTAR Gas issued $100 million of 4.35 percent Series O First Mortgage Bonds due to mature in 2045.
The proceeds of all debt issuances, net of issuance costs, were used to repay short-term borrowings and fund capital expenditures and working capital.
On April 1, 2015, CL&P repaid at maturity the NU parent $250$100 million 5.655.00 percent 2005 Series A First and Refunding Mortgage Bonds and also redeemed the $62 million 1996A Series 1.55 percent PCRBs that were subject to mandatory tender, using short term borrowings.
On August 3, 2015, WMECO repaid at maturity the $50 million 5.24 percent Series C Senior Notes, that matured on June 1, 2013 and the NU parent $300 million floating rate Series D Senior Notes that matured on September 20, 2013. The remaining net proceeds were used to repay commercial paper program borrowings and for working capital purposes.
Yankee Gas issued $100 million of 4.82 percent Series L First Mortgage Bonds on January 2, 2014, 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 pay $25 million inusing short-term borrowings.
Long-Term Debt Issuance Authorizations: On July 31, 2013,November 25, 2015, PURA approved Yankee Gas’ request to extend the FERC granted authorization allowing CL&P and WMECO to incur total short-term borrowingsperiod for issuance of up to a maximum of $600$125 million and $300 million, respectively, effective January 1, 2014 throughin long-term debt from December 31, 2015. On May 16, 2012, the FERC granted authorization2015 to allow NSTAR Electric to issue total short-term debt securities in an aggregate principal amount not to exceed $655 million outstanding at any one time, effective October 23, 2012 through October 23, 2014.December 31, 2016. On December 23, 2013,4, 2015, the DPU authorized NSTAR ElectricWMECO to issue up to $800$100 million in long-term debt for the two-year period endingthrough December 31, 2015.2016. On September 26, 2013,December 4, 2015, the NHPUC issued an order, effective October 8, 2013, approving PSNH'sDPU approved NSTAR Electric’s request to issueextend the authorization period for issuance of up to $315$250 million in long-term debt throughfrom December 31, 2014, and2015 to refinance approximately $89 million Series B PCRBs through its existing maturity of May 2021.December 31, 2016.
On September 6, 2013, NUCredit Agreements and Commercial Paper Programs: Eversource parent, CL&P, PSNH, WMECO, NSTAR Gas and Yankee Gas amended their jointare parties to a five-year $1.15$1.45 billion revolving credit facility. On October 26, 2015, this revolving credit facility dated July 25, 2012, by increasingwas amended and restated and the aggregate principal amount available thereunder by $300 million to $1.45 billion, extending the expirationtermination date from July 25, 2017was extended to September 6, 2018,4, 2020. Under the revolving credit facility, CL&P has a borrowing sublimit of $600 million, and increasing CL&P's borrowing sub-limit from $300 million to $600 million. PSNH and WMECO each have borrowing sub-limitssublimits of $300 million. Simultaneously, effective September 6, 2013, the CL&P $300 millionThe revolving credit facility was terminated.
On September 6, 2013, NSTAR Electric amended its five-year $450 million revolving credit facility, dated July 25, 2012, by extending the expiration date from July 25, 2017serves to September 6, 2018.
On September 6, 2013, NU parent’s $1.15backstop Eversource parent's $1.45 billion commercial paper program. The commercial paper program was increased by $300 millionallows Eversource parent to $1.45 billion.
issue commercial paper as a form of short-term debt. As of December 31, 2013, NU2015 and 2014, Eversource parent had approximately $1.01$1.1 billion in short-term borrowings outstanding on each date under itsthe
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Eversource parent commercial paper program, leaving $435.5$351.5 million and $348.9 million of available borrowing capacity.capacity as of December 31, 2015 and 2014, respectively. The weighted-average interest rate on these borrowings as of December 31, 20132015 and 2014 was 0.240.72 percent which is generally based on money market rates.and 0.43 percent, respectively. As of December 31, 2013,2015, there were intercompany loans from Eversource parent of $277.4 million to CL&P, $231.3 million to PSNH and $143.4 million to WMECO. As of December 31, 2014, there were intercompany loans from Eversource parent of $133.4 million to CL&P, $90.5 million to PSNH and $21.4 million to WMECO.
NSTAR Electric has a five-year $450 million revolving credit facility. On October 26, 2015, this revolving credit facility was amended and restated and the termination date was extended to September 4, 2020. The facility serves to backstop NSTAR Electric's $450 million commercial paper program. As of December 31, 2015 and 2014, NSTAR Electric had $103.5$62.5 million and $302 million, respectively, in short-term borrowings outstanding under its commercial paper program, leaving $346.5$387.5 million and $148 million of available borrowing capacity.capacity as of December 31, 2015 and 2014, respectively. The weighted-average interest rate on these borrowings as of December 31, 20132015 and 2014 was 0.130.40 percent which is generally based on money market rates. and 0.27 percent, respectively.
Cash Flows: Cash flows provided by operating activities totaled $1.4 billion in 2015, compared with $1.6 billion in 2014. The decrease in operating cash flows in 2015 compared to 2014 was due primarily to the $302 million payment made to fully satisfy the obligation with the DOE, as discussed below, and an increase in purchased power and congestion costs at NSTAR Electric, WMECO and CL&P that will be recovered in future periods. Also contributing to the decrease in operating cash flows were DOE Damages proceeds received from the Yankee Companies of $4.7 million in 2015, compared to $132 million in 2014. Partially offsetting these unfavorable cash flow impacts were a decrease of $49.2 million in Pension and PBOP Plan cash contributions in 2015, as compared to 2014, and lower federal income tax payments of approximately $324 million in 2015, as compared to 2014, primarily due to the extension of the accelerated depreciation deduction.
In late 2015, CL&P and WMECO made payments of $244.6 million and $57.4 million, respectively, to fully satisfy their obligations with the DOE, which were classified as long-term debt on the balance sheets as of December 31, 2014, for costs associated with the disposal of spent nuclear fuel and high-level radioactive waste for all periods prior to 1983 from their previous ownership interest in the Millstone nuclear power station. CL&P and WMECO divested their ownership interest in Millstone in 2001. These payments included accumulated interest of $178 million and $41.8 million for CL&P and WMECO, respectively. CL&P funded its payment with the issuance of debt, and WMECO liquidated its spent nuclear fuel trust to satisfy its obligation with the DOE.
On December 18, 2015, the "Protecting Americans from Tax Hikes" Act became law, which extended the accelerated deduction of depreciation to businesses from 2015 through 2019. This extended stimulus provides us with cash flow benefits in 2016 of approximately $275 million (including approximately $105 million for CL&P) due to a refund of taxes paid in 2015 and lower expected tax payments in 2016 of approximately $300 million.
In 2015, we paid cash dividends of $529.8 million, or $1.67 per common share, compared with $475.2 million, or $1.57 per share in 2014. Our quarterly common share dividend payment was $0.4175 per share, in 2015, as compared to $0.3925 per share, in 2014. On February 3, 2016, our Board of Trustees approved a common share dividend payment of $0.445 per share, payable on March 31, 2016 to shareholders of record as of March 2, 2016. The 2016 dividend represented an increase of 6.6 percent over the dividend paid in December 2015, and is equivalent to dividends on common shares of approximately $565 million on an annual basis.
In 2015, CL&P, NSTAR Electric, PSNH, and WMECO paid $196 million, $198 million, $106 million, and $37.2 million, respectively, in common stock dividends to Eversource parent.
Investments in Property, Plant and Equipment on the statements of cash flows do not include amounts incurred on capital projects but not yet paid, cost of removal, AFUDC related to equity funds, and the capitalized portions of pension expense. In 2015, investments for Eversource, CL&P, NSTAR Electric, PSNH, and WMECO were $1.7 billion, $523.8 million, $469.5 million, $308 million, and $134.6 million, respectively.
Each of NU,Eversource, CL&P, NSTAR Electric, PSNH and WMECO use its available capital resources to fund its respective construction expenditures, meet debt requirements, pay operating costs, including storm-related costs, pay dividends and fund other corporate obligations, such as pension contributions. The current growth in NU’s transmissionEversource'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’sEversource's Regulated companies recover itstheir 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 ofand debt used to finance the cost and related financing costs.investments. These factors have resulted in current liabilities exceeding current assets by approximately $1.2 billion, $398$371 million and $339$82 million at NU, CL&PEversource and NSTAR Electric,WMECO, respectively, as of December 31, 2013.2015.
As of December 31, 2013, $501.72015, a total of $200 million of NU's obligationsEversource’s long-term debt classified as current liabilities, relates to long-term debt thatall at NSTAR Electric, will be paid in the next 12 months, consistingmonths. The remaining $28.9 million of $150 million for CL&P, $301.7 million for NSTAR Electric and $50 million for PSNH. In addition, $31.7 millionEversource's long-term debt classified as current liabilities relates to the amortization of the purchase accounting fair value adjustmentadjustments from the merger that will be amortized in the next twelve months. NU,12 months and have no cash flow impact. Eversource, with its strong credit ratings, has several options available in the financial markets to repay or refinance these maturities with the issuance of new long-term debt. NU,Eversource, CL&P, NSTAR Electric, PSNH and WMECO will reduce their short-term borrowings with cash
37
received from operating cash flows or with the issuance of new long-term debt, determined by considering capital requirements and maintenance of NU'sEversource's credit rating and profile. Management expectsWe expect the future operating cash flows of NU,Eversource, CL&P, NSTAR Electric, PSNH and WMECO, along with the access to financial markets, will be sufficient to meet any future operating requirements and capital investment forecasted opportunities.
32
Credit Ratings:On March 15, 2013, NSTAR Electric made its final principalApril 23, 2015, S&P upgraded the corporate credit ratings by one level and interest payment on approximately $675 millionchanged the outlooks to stable from positive of RRBs that were issued in March 2005. On May 1, 2013, PSNH made its final principal and interest payment on approximately $525 million of RRBs that were issued in April 2001. On June 1, 2013, WMECO made its final principal and interest payment on approximately $155 million of RRBs that were issued in May 2001. As a result,Eversourceparent, CL&P, NSTAR Electric, PSNH, WMECO, Yankee Gas and NSTAR Gas. On May 19, 2015, Moody's changed the outlooks of PSNH and WMECO are no longer recovering any paymentsto positive from customers associated with these RRBs, which reduced NSTAR Electric’s, PSNH’sstable and WMECO’s cash flows provided by operating activities in 2013, compared with 2012. There was no impact on operating cash flows netaffirmed their corporate credit ratings. On June 2, 2015, Fitch changed the outlooks to positive from stable of RRB payments.
Cash flows provided by operating activities totaled $1.58 billion in 2013, compared with $1.05 billion in 2012CL&P, PSNH and $901.1 million in 2011 (all amounts are netWMECO and affirmed its corporate credit ratings of RRB payments, which are included in financing activities on the accompanying statements of cash flows). The improved operating cash flows were due primarily to the addition of NSTAR, which contributed $138.1 million of operating cash flows (net of RRB payments) in the first quarter of 2013, a decrease of approximately $100 millionin cash disbursements for storm restoration costs associated primarily with the February 2013 blizzard, as compared to 2012 cash disbursements for storm restoration costs associated primarily with Tropical Storm Irene and the October 2011 snowstorm, the absence in 2013 of $73 million in 2012 cash disbursements atEversourceparent, CL&P, NSTAR Electric, PSNH, WMECO and NSTAR Gas and WMECO related to customer bill credits, and the absence in 2013 of $35 million ofmerger-related cash payments made in 2012. In addition, operating cash flows benefited from an increase in amortization of regulatory deferrals primarily attributable to tracking mechanisms where such revenues exceeded costs resulting in a favorable cash flow impact. Partially offsetting these favorable cash flow impacts was a $62.3 million increase in Pension Plan cash contributions, increases in coal and fuel inventories, and changes in traditional working capital amounts due primarily to the timing of accounts receivable and accounts payable. The improved operating cash flows in 2012, compared with 2011, were due primarily to the addition of NSTAR, partially offset by an increase in storm restoration costs, pension plan cash contributions, customer bill credits, and merger-related costs.Gas.
A summary of our corporate credit ratings and outlooks by Moody's, S&P and Fitch is as follows:
| | | | | | | | | | | | |
| | Moody's | | S&P | | Fitch |
| | Current | | Outlook | | Current | | Outlook | | Current | | Outlook |
NUEversource Parent
| | Baa1 | | Stable | | A-A
| | Stable | | BBB+ | | Stable |
CL&P | | Baa1 | | Stable | | A-A
| | Stable | | BBB+ | | StablePositive
|
NSTAR Electric | | A2 | | Stable | | A-A
| | Stable | | A | | Stable |
PSNH | | Baa1 | | StablePositive
| | A-A
| | Stable | | BBB+ | | StablePositive
|
WMECO | | A3 | | StablePositive
| | A-A
| | Stable | | BBB+ | | StablePositive
|
A summary of the current credit ratings and outlooks by Moody's, S&P and Fitch for senior unsecured debt of NUEversource 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 |
NUEversource Parent
| | Baa1 | | Stable | | BBB+A-
| | Stable | | BBB+ | | Stable |
CL&P | | A2 | | Stable | | AA+
| | Stable | | A | | StablePositive
|
NSTAR Electric | | A2 | | Stable | | A-A
| | Stable | | A+ | | Stable |
PSNH | | A2 | | Positive | | A+ | | Stable | | A | | Positive |
WMECO | | A3 | | Positive | | A | | Stable | | A
| | Stable
|
WMECO
| | A3
| | Stable
| | A- | | Stable
| | A-
| | StablePositive
|
On February 14, 2013, S&P revised its criteria for rating utility first mortgage bonds, resulting in one-level upgrades of CL&P and PSNH first mortgage bonds by S&P. 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.
We paid common dividends of $462.7 million in 2013, compared with $375 million in 2012. The increase was due primarily to the issuance of approximately 136 million of NU common shares to the NSTAR shareholders on April 10, 2012 as a result of the merger, and an increase of approximately 7.1 percent in our common dividend paid beginning in March 2013. On February 4, 2014, our Board of Trustees approved a common dividend payment of $0.3925 per share, payable on March 31, 2014 to shareholders of record as of March 3, 2014. The dividend represented an increase of 6.8 percent over the dividend paid in December 2013.
CL&P, NSTAR Electric, PSNH, and WMECO paid $152 million, $56 million, $68 million, and $40 million, respectively, in common dividends to their respective parent company in 2013.
Investments in Property, Plant and Equipment on the accompanying statements of cash flows do not include amounts incurred on capital projects but not yet paid, cost of removal, AFUDC related to equity funds, and, for certain subsidiaries, the capitalized portions of pension expense. In 2013, investments for NU, CL&P, NSTAR Electric, PSNH, and WMECO were $1.5 billion, $434.9 million, $476.6 million, $186 million, and $128.8 million, respectively.
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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 $1.9 billion in 2015, $1.7 billion in 2014, and $1.6 billion in 2013, $1.5 billion in 2012, and $1.2 billion in 2011.2013. These amounts included $102 million in 2015, $58.3 million in 2014, and $44.7 million in 2013 $43.1 million in 2012, and $51.9 million in 2011, related to our corporate service companies, NUSCOinformation technology and RRR.facilities upgrades and enhancements, primarily at Eversource Service and The Rocky River Realty Company.
Natural Gas Transmission Business:
Access Northeast: Access Northeast is a natural gas pipeline and storage project (the "Project") being developed jointly by Eversource, Spectra Energy Corp and National Grid. Access Northeast will enhance the Algonquin and Maritimes & Northeast pipeline systems using existing routes and will include two new LNG storage tanks and liquefaction and vaporization facilities in Acushnet, Massachusetts that will be connected to the Algonquin gas pipeline. The Project is expected to be capable of delivering approximately 900 million cubic feet of additional natural gas per day to New England on peak demand days. Eversource and Spectra Energy Corp each own a 40 percent interest in the Project, with the remaining 20 percent interest owned by National Grid. The total projected cost for both the pipeline and the LNG storage is expected to be approximately $3 billion with anticipated in-service dates commencing in November 2018. The Project is subject to FERC and other federal and state regulatory approvals. On November 17, 2015, the FERC accepted the Project’s request to initiate the pre-filing review process. Upon completion of the pre-filing review, a certificate application will be filed with the FERC. In late 2015, the Project bid into the New England Natural Gas Pipeline Capacity RFP conducted by certain EDCs in Massachusetts and Rhode Island, including NSTAR Electric and WMECO in Massachusetts, and in December 2015 and January 2016, those Massachusetts EDCs filed with the DPU seeking approval of the contracts for pipeline and storage capacity with the Project. We expect the Rhode Island EDC to file its selected contracts with the Rhode Island regulatory agencies in the first half of 2016. In February 2016, PSNH filed for approval with the NHPUC, its proposed contract for natural gas pipeline capacity and storage with the Project. For further information on the RFP process, see "Regulatory Developments and Rate Matters – General – New England Natural Gas Pipeline Capacity" in thisManagement's Discussion and Analysis of Financial Conditions and Results of Operations.
Electric Transmission Business: Overall,Our consolidated electric transmission business capital expenditures increased by $10.5$106 million in 2013,2015, as compared with 2012, due primarily to the addition of NSTAR Electric's capital expenditures, partially offset by the completion of the WMECO portion of GSRP.2014. A summary of electric transmission capital expenditures by company in 2013, 2012 and 2011 is as follows:
|
| | For the Years Ended December 31, | | For the Years Ended December 31, |
(Millions of Dollars) | | 2013 | | 2012(1) | | 2011 | | 2015 | | 2014 | | 2013 |
CL&P | | $ | 211.9 | | $ | 182.5 | | $ | 128.6 | | $ | 252.9 | | $ | 259.2 | | $ | 211.9 |
NSTAR Electric | | | 220.8 | | | 160.7 | | | N/A | | | 238.2 | | | 223.8 | | | 220.8 |
PSNH | | | 99.7 | | | 55.7 | | | 68.1 | | | 161.2 | | | 120.8 | | | 99.7 |
WMECO | | | 87.2 | | | 214.7 | | | 236.8 | | | 116.0 | | | 68.5 | | | 87.2 |
NPT | | | 39.9 | | | 35.4 | | | 25.9 | | | 38.3 | | | 28.3 | | | 39.9 |
Total Transmission Segment | | $ | 659.5 | | $ | 649.0 | | $ | 459.4 |
Total Electric Transmission Segment | | $ | 806.6 | | $ | 700.6 | | $ | 659.5 |
(1)
Results include the transmission capital expenditures of NSTAR Electric beginning April 10, 2012. 33
NEEWS: GSRP,The Interstate Reliability Project (IRP), the first, largest and most complicatedsecond project within the NEEWS family of projects, was fully energized on November 20, 2013.December 18, 2015. The project involved the construction of 115 kV and 345 kV overhead lines by CL&P and WMECO from Ludlow, Massachusetts to Bloomfield, Connecticut. This transmission upgrade ensures the reliable flow of power in and around the southern New England area and enables access to less expensive generation, further reducing the risk of congestion costs impacting New England customers. The project was fully energized ahead of schedule with a final cost of $676 million, $42 million under the $718 million estimated cost. As of December 31, 2013, CL&P and WMECO have placed $628.2 million in service.
The Interstate Reliability Project, which includes CL&P’s&P's construction of an approximately 40-mile, 345 kV345-kV overhead line from Lebanon, Connecticut to the Connecticut-Rhode Island border in Thompson, Connecticut where it will connectconnects to transmission enhancements being constructed by National Grid is the second major NEEWS project. All siting applications have been filed by CL&P and National Grid. The Connecticut andin Rhode Island portions of the project have been approved and a siting approval decision in Massachusetts is expected in early 2014. On February 12, 2014, the Army Corps of Engineers issued its permit enabling construction on the Connecticut portion of the project. This is the final permit for the Connecticut portion of the project. NU’s portion of the cost is estimated to be $218 million and the project is expected to beIsland. IRP was placed in service in late 2015.
The Greater Hartford Central Connecticut Study (GHCC), which includes the reassessmentDecember 2015 at a final cost to CL&P of the Central Connecticut Reliability Project, continues to make progress. The final need results, which were presented to the ISO-NE Planning Advisory Committee in November 2013, showed existing and worsening severe regional and local thermal overloads and voltage violations within and across each of the four study areas. ISO-NE is expected to confirm the preferred transmission solutions in the first half of 2014, which are likely to include many 115 kV upgrades. We continue to expect that the specific future projects being identified to address these reliability concerns will cost approximately $300 million and that the project will be placed in service in 2017.
Included as part of NEEWS are associated reliability related projects, $90.8 million of which have been placed in service. As of December 31, 2013, the remaining construction on the associated reliability related projects totaled $2.8 million, which is scheduled to be completed by mid-2014.
$192.6 million. Through December 31, 2013,2015, CL&P and WMECO capitalized $252.8$377.9 million and $567$570.6 million, respectively, in costs associated with NEEWS, of which $40.8 million and $48.9 million, respectively, were capitalized in 2013.NEEWS.
Cape Cod Reliability Projects:GHCC: TransmissionThe Greater Hartford Central Connecticut (GHCC) solutions are comprised of 27 projects serving Cape Codand are expected to cost approximately $350 million and be placed in service from 2016 through 2018. ISO-NE posted the Southeastern Massachusetts (SEMA) reliability region consistfinal Solutions Study for GHCC in late February 2015 and approved our Proposed Plan Applications on April 16, 2015. Through December 31, 2015, we have filed siting applications for five projects all of an expansionwhich have been approved by the Connecticut Siting Council. During 2016, fifteen projects are expected to be in active construction, and upgrade of NSTAR Electric's existing transmission infrastructure including construction of a new 345 kV transmission line that crosses the Cape Cod Canal and associated 115 kV upgrades in the center of Cape Cod (Lower SEMA Project) and related 115 kVthree additional siting applications are expected to be filed. All GHCC projects (Mid-Cape Project). The Lower SEMA Project line work was completed and placed into service in 2013. The Mid-Cape Project is scheduledare expected to be completed in 2017. The aggregate estimated construction cost for the Cape Cod projects is expected to be approximately $150 million. Throughby late 2018. As of December 31, 2013, NSTAR Electric has invested $962015, CL&P had capitalized $50.6 million in costs associated with the Cape Cod Reliability Projects, of which $61 million was capitalized in 2013.GHCC.
Northern Pass: Northern Pass is NPT'sEversource's planned HVDC transmission line from the Québec-New Hampshire border to Franklin, New Hampshire and an associated alternating current radial transmission line between Franklin and Deerfield, New Hampshire. Northern Pass will interconnect at the Québec-New Hampshire border with a planned HQ HVDC transmission line. TheOn July 21, 2015, the DOE issued the draft Environmental Impact Statement (EIS) for Northern Pass representing a key milestone in the permitting process. On August 18, 2015, a revised route was announced with an additional 52 miles of the route underground in and around the White Mountain National Forest region. As a result, the NPT project cost estimate increased from $1.4 billion projectto $1.6 billion. Concurrently, NPT announced the Forward NH Plan, which is subjecta commitment to comprehensive federalallocate $200 million to projects associated with economic development, community betterment, and clean energy innovations to benefit the state public permitting processes andof New Hampshire. This commitment is contingent upon the Northern Pass transmission line going into commercial operation.
On October 19, 2015, NPT filed its NH SEC application, which was accepted as complete by the NH SEC on December 18, 2015, allowing the formal siting process to move forward. In response to requests by the New Hampshire congressional delegation, the DOE announced that it would issue a supplement to the draft EIS. Public hearings on the draft EIS will be held in March 2016. The DOE has asked for comments by April 4, 2016. The project is expected to be operational by mid-2017. On July 1, 2013, NPT filed an amendment to the DOE Presidential Permit Application for a proposed improved route in the northernmost sectionfirst half of 2019. On January 28, 2016, NPT bid into the project area. Asthree-state Clean Energy RFP process. For further information on the RFP process, see "Regulatory Developments and Rate Matters – General – Clean Energy RFP" in thisManagement's Discussion and Analysis of December 31, 2013, the DOE had completed its public scoping meeting processFinancial Conditions and the majorityResults of its seasonal field work and environmental data collection. NPT expects to file its state permit application in the fourth quarter of 2014 after the DOE’s draft Environmental Impact Statement (EIS) is received.
39Operations.
NPT filed an amendmentClean Energy Connect: The Clean Energy Connect project is a planned transmission, wind and hydro generation project that we plan to co-develop with experienced renewable generation companies. On January 28, 2016, the Transmission Services Agreement (TSA) with FERC on December 11, 2013, whichClean Energy Connect project was accepted bybid into the FERC on January 13, 2014. The TSA amendment that went into effect on February 14, 2014 extended certain deadlines to provide project flexibility and eliminated a penalty payment for termination ofthree-state Clean Energy RFP process. Our investment, should the projectClean Energy Connect Project be selected in the future.
On December 31, 2013, NPT received ISO-NE approval under Section I.3.9RFP process, is currently estimated to be at least $400 million, and would involve the construction of the ISO tariff. By approving the project’s Section I.3.9 application, ISO-NE determined that Northern Pass can reliably interconnecta new 25-mile, 345kV transmission line with thea 600 MW capacity from western Massachusetts to eastern New England grid with no significant, adverse effect on the reliability or operating characteristics of the regional energy grid and its participants. York.
Greater Boston Reliability Solutions: In February 2015, ISO-NE selected Eversource's and National Grid's proposed Greater Boston Network Improvements: Asand New Hampshire Solution (Solution) to satisfy the requirements identified in the Greater Boston study. The Solution consists of a resultportfolio of continued analysiselectric transmission upgrades straddling southern New Hampshire and northern Massachusetts in the Merrimack Valley and continuing into the greater Boston metropolitan area. We are pursuing the necessary regulatory approvals and have filed several siting applications in Massachusetts and New Hampshire. We estimate our portion of the transmission needs to enhance system reliability and improve capacityinvestment in eastern Massachusetts, NSTAR Electric expects to implement a series of new transmission initiatives over the next five years. We expect projected costs toSolution will be approximately $440 million on these new initiatives. $544 million.
34
Distribution Business: A summary of distribution capital expenditures by company for 2013, 2012 and 2011 is as follows:
|
| For the Years Ended December 31, | For the Years Ended December 31, |
(Millions of Dollars) | 2013 | | 2012(1) | | 2011 | 2015 | | 2014 | | 2013 |
CL&P: | | | | | | | | | | | | | | | | |
Basic Business | $ | 60.9 | | $ | 69.2 | | $ | 166.6 | $ | 141.1 | | $ | 120.2 | | $ | 60.9 |
Aging Infrastructure | | 160.7 | | | 177.8 | | | 112.3 | | 151.0 | | | 118.0 | | | 160.7 |
Load Growth | | 76.9 | | | 65.8 | | | 59.6 | | 42.2 | | | 66.3 | | | 76.9 |
Total CL&P | | 298.5 | | | 312.8 | | | 338.5 | | 334.3 | | | 304.5 | | | 298.5 |
NSTAR Electric: | | | | | | | | | | | | | | | | |
Basic Business | | 98.5 | | | 47.3 | | | N/A | | 108.7 | | | 99.0 | | | 98.5 |
Aging Infrastructure | | 110.6 | | | 111.5 | | | N/A | | 103.1 | | | 104.2 | | | 110.6 |
Load Growth | | 53.6 | | | 17.4 | | | N/A | | 51.9 | | | 43.1 | | | 53.6 |
Total NSTAR Electric | | 262.7 | | | 176.2 | | | N/A | | 263.7 | | | 246.3 | | | 262.7 |
PSNH: | | | | | | | | | | | | | | | | |
Basic Business | | 22.7 | | | 25.3 | | | 47.7 | | 59.2 | | | 62.1 | | | 22.7 |
Aging Infrastructure | | 50.5 | | | 50.2 | | | 25.3 | | 57.3 | | | 45.3 | | | 50.5 |
Load Growth | | 29.3 | | | 20.2 | | | 25.8 | | 25.5 | | | 27.1 | | | 29.3 |
Total PSNH | | 102.5 | | | 95.7 | | | 98.8 | | 142.0 | | | 134.5 | | | 102.5 |
WMECO: | | | | | | | | | | | | | | | | |
Basic Business | | 7.9 | | | 12.7 | | | 24.2 | | 18.2 | | | 19.0 | | | 7.9 |
Aging Infrastructure | | 24.6 | | | 18.5 | | | 11.5 | | 18.5 | | | 16.1 | | | 24.6 |
Load Growth | | 9.2 | | | 6.5 | | | 6.1 | | 6.6 | | | 6.1 | | | 9.2 |
Total WMECO | | 41.7 | | | 37.7 | | | 41.8 | | 43.3 | | | 41.2 | | | 41.7 |
Total - Electric Distribution (excluding Generation) | | 705.4 | | | 622.4 | | | 479.1 | | 783.3 | | | 726.5 | | | 705.4 |
Total - Natural Gas | | 175.2 | | | 162.9 | | | 102.8 |
Other Distribution | | 0.7 | | | 0.1 | | | 1.0 | | - | | | - | | | 0.7 |
Total Electric and Natural Gas | | 881.3 | | | 785.4 | | | 582.9 |
PSNH Generation: | | | | | | | | |
Clean Air Project | | - | | | 22.0 | | | 101.1 |
Other | | 9.7 | | | 7.9 | | | 23.7 |
Total PSNH Generation | | 9.7 | | | 29.9 | | | 124.8 |
PSNH Generation | | 33.3 | | | 13.1 | | | 9.7 |
WMECO Generation | | 4.5 | | | 0.7 | | | 11.7 | | - | | | 7.6 | | | 4.5 |
Total Distribution Segment | $ | 895.5 | | $ | 816.0 | | $ | 719.4 |
Natural Gas | | 212.6 | | | 193.7 | | | 175.2 |
Total Electric and Natural Gas Distribution Segment | $ | 1,029.2 | | $ | 940.9 | | $ | 895.5 |
(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, distributionplant substations, underground cable replacement, and equipment failures. Load growth includes requests for new business and capacity additions on distribution lines and substation additions and expansions.
CL&P System Resiliency Plan:Natural Gas Distribution Business Expansion and Enhancement: In 2013, in accordance with the PURA-approved System Resiliency Plan, CL&P will spend approximately $300 million to improve the resiliency of its electric distribution system, which includes vegetation management. CL&P expects to complete the plan in five years in two separate phases. Costs of Phase 1 of the plan, which is primarily focused on vegetation management, totaled approximately $32 million in 2013 and is estimated to cost $53 million in 2014. Phase 2 of the plan is estimated to cost approximately $215 million over the period from 2015 through 2017.
WMECO Solar Project: On September 4, 2013, the DPU approved WMECO's proposal to build a third solar generation facility and expand its solar energy portfolio from 6 MW to 8 MW. On October 22, 2013, WMECO announced it would install a 3.9 MW solar generation facility on a site in East Springfield, Massachusetts. The facility is expected to be completed in mid-2014 at an estimated cost of approximately $15 million.
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Yankee Gas Expansion Plan: In accordance with 2013 Connecticut law and regulation, on June 14, 2013, Yankee Gas and other Connecticut natural gas distribution companies filedregulations, PURA approved a comprehensive joint natural gas infrastructure expansion plan (expansion plan) with DEEPfiled by Yankee Gas and PURA.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.a 10-year period. Yankee Gas estimatesestimated that its portion of the plan willwould cost approximately $700 million over 10 years. For further information onIn January 2015, the PURA approved a joint settlement agreement proposed by Yankee Gas and other Connecticut natural gas distribution companies and regulatory agencies that clarified the procedures and oversight criteria applicable to the expansion plan, see "Regulatory Developments and Rate Matters - Connecticut -plan. On March 20, 2015, Yankee Gas Naturalfiled its initial System Expansion (SE) Rate reconciliation for 2014. The proposed SE rate was approved by the PURA for implementation as of April 1, 2015, pending final PURA approval following a contested hearing.
In October 2014, pursuant to new legislation, NSTAR Gas Expansion Plan"filed the Gas System Enhancement Program (GSEP) with the DPU. NSTAR Gas' program accelerates the replacement of certain natural gas distribution facilities in thisManagement’s Discussion and Analysis. For further informationthe system to within 25 years. The GSEP includes a new tariff effective January 1, 2016 that provides NSTAR Gas an opportunity to collect the costs for the program on an annual basis through a newly designed reconciling factor. On April 30, 2015, the Connecticut law, see "Legislative and Policy Matters - Connecticut" in thisManagement’s Discussion and Analysis.DPU approved the GSEP. We expect capital expenditures of approximately $255 million for the period 2016 through 2019 for the GSEP.
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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 20142016 through 2017,2019, including our corporate service companies' capital expendituresinformation technology and facilities upgrades and enhancements on behalf of the Regulated companies, is as follows:
|
| Year | Years |
(Millions of Dollars) | 2014 | | 2015 | | 2016 | | 2017 | | 2014-2017
Total | 2016 | | 2017 | | 2018 | | 2019 | | 2016-2019
Total |
CL&P Transmission | $ | 247 | | $ | 199 | | $ | 178 | | $ | 165 | | $ | 789 | $ | 351 | | $ | 250 | | $ | 215 | | $ | 157 | | $ | 973 |
NSTAR Electric Transmission | | 191 | | | 250 | | | 285 | | | 202 | | | 928 | | 302 | | | 216 | | | 238 | | | 149 | | | 905 |
PSNH Transmission | | 106 | | | 124 | | | 123 | | | 42 | | | 395 | | 112 | | | 65 | | | 38 | | | 56 | | | 271 |
WMECO Transmission | | 73 | | | 85 | | | 49 | | | 2 | | | 209 | | 115 | | | 78 | | | 22 | | | 40 | | | 255 |
NPT | | 47 | | | 222 | | | 610 | | | 487 | | | 1,366 | | 31 | | | 684 | | | 636 | | | 149 | | | 1,500 |
Total Transmission | $ | 664 | | $ | 880 | | $ | 1,245 | | $ | 898 | | $ | 3,687 |
Total Electric Transmission | $ | 911 | | $ | 1,293 | | $ | 1,149 | | $ | 551 | | $ | 3,904 |
Electric Distribution | $ | 679 | | $ | 647 | | $ | 647 | | $ | 619 | | $ | 2,592 | $ | 892 | | $ | 963 | | $ | 888 | | $ | 840 | | $ | 3,583 |
Generation | | 24 | | | 34 | | | 20 | | | 15 | | | 93 | | 20 | | | - | | | - | | | - | | | 20 |
Natural Gas | | 189 | | | 219 | | | 201 | | | 227 | | | 836 | | 284 | | | 318 | | | 339 | | | 357 | | | 1,298 |
Total Distribution | $ | 892 | | $ | 900 | | $ | 868 | | $ | 861 | | $ | 3,521 | $ | 1,196 | | $ | 1,281 | | $ | 1,227 | | $ | 1,197 | | $ | 4,901 |
Corporate Service Companies | $ | 117 | | $ | 93 | | $ | 76 | | $ | 76 | | $ | 362 |
Information Technology and All Other | $ | 105 | | $ | 88 | | $ | 82 | | $ | 87 | | $ | 362 |
Total | $ | 1,673 | | $ | 1,873 | | $ | 2,189 | | $ | 1,835 | | $ | 7,570 | $ | 2,212 | | $ | 2,662 | | $ | 2,458 | | $ | 1,835 | | $ | 9,167 |
The projections do not include capital investments related to Access Northeast or Clean Energy Connect. Actual capital expenditures could vary from the projected amounts for the companies and years above.
FERC Regulatory Issues
FERC Base ROE Complaint: Complaints:On September 30, 2011, several Three separate complaints have been filed at FERC by combinations of New England state attorneys general, state regulatory commissions, consumer advocates, consumer groups, municipal parties and other parties filed a joint complaint with(the "Complainants"). In these three separate complaints, the FERC under Sections 206 and 306 ofComplainants challenged the Federal Power Act alleging that the base ROE used in calculating formula rates for transmission service under the ISO-NE Open Access Transmission Tariff by NETOs, including CL&P, NSTAR Electric, PSNH and WMECO, is unjust and unreasonable. The complainants asserted that the current 11.14 percent rate, which became effective in 2006, is excessive due to changes in the capital markets and are seeking an order to reduce the rate, which would be effective October 1, 2011. In response, the NETOs filed testimony and analysis based on standard FERC methodology and precedent demonstrating that theNETOs' base ROE of 11.14 percent remained justthat had been utilized since 2006 and reasonable. The FERC set the case for trial before a FERC ALJ after settlement negotiations were unsuccessful in August 2012.
Hearings before the FERC ALJ were held in May 2013, followed by the filing of briefs by the complainants, the Massachusetts municipal electric utilities (late intervenerssought an order to the case), the FERC trial staff and the NETOs. The NETOs recommended that the current base ROE of 11.14 percent should remain in effect for the refund period (October 1, 2011 through December 31, 2012) and the prospective period (beginning when FERC issues its final decision). The complainants, the Massachusetts municipal electric utilities, and the FERC trial staff each recommended a base ROE of 9 percent or below.
On August 6, 2013, the FERC ALJ issued an initial decision, finding that the base ROE in effectreduce it prospectively from October 2011 through December 2012 was not reasonable under the standard application of FERC methodology, but leaving policy considerations and additional adjustments to the FERC. Using the established FERC methodology, the FERC ALJ determined that separate base ROEs should be set for the refund period and the prospective period. The FERC ALJ found those base ROEs to be 10.6 percent and 9.7 percent, respectively. The FERC may adjust the prospective period base ROE in its final decision to reflect movement in 10-year Treasury bond rates from the date that the case was filed (April 2013) to the date of the final decision.FERC order and for the 15-month complaint refund periods stipulated in the separate complaints. In 2014, the FERC ordered a 10.57 percent base ROE for the first complaint refund period and prospectively from October 16, 2014, and that a utility's total or maximum ROE shall not exceed the top of the new zone of reasonableness, which was set at 11.74 percent. The parties filed briefs on this decision withNETOs and the Complainants sought rehearing from FERC. In late 2014, the NETOs made a compliance filing and the Company began issuing refunds to customers from the first complaint period.
As a result of the actions taken by the FERC and a decision fromother developments in the FERC is expected in 2014. Though NU cannot predict the ultimate outcome of this proceeding, in 2013first complaint matter, the Company recorded a series of reserves at its electric subsidiaries in 2015, 2014 and 2013. In 2015, Eversource recognized an after-tax charge to recognize the potential financial impact from the FERC ALJ's initial decision for the refund period. earnings (excluding interest) of $12.4 million, of which $7.9 million was recorded at CL&P, $1.4 million at NSTAR Electric, $0.6 million at PSNH, and $2.5 million at WMECO. The net aggregate after-tax charge to earnings (excluding interest) in 2014 totaled $22.4 million, of which $12.4 million was recorded at CL&P, $4.9 million at NSTAR Electric, $1.7 million at PSNH and $3.4 million at WMECO. The aggregate after-tax charge to earnings (excluding interest) in 2013 totaled $14.3 million, at NU,of which represents reserves of $7.7 million was recorded at CL&P, $3.4 million at NSTAR Electric, $1.4 million at PSNH and $1.8 million at WMECO. The NETOs and Complainants have filed appeals to the D.C. Circuit Court of Appeals. A court decision is expected in late 2016.
On December 27, 2012, several additionalFor the second and third complaints, the state parties, filed a separate complaint concerningmunicipal utilities and FERC trial staff each believe that the NETOs' base ROE withshould be reduced to an amount lower than 10.57 percent. The NETOs believe that the FERC. This complaint seeks to reduceComplainants' positions are without merit, and the NETOs’existing base ROE effective January 1, 2013, effectively extending the refund period for an additional 15 months,of 10.57 percent is just and to consolidate this complaint with the joint complaint filed on September 30, 2011. The NETOs have asked the FERC to reject this complaint.reasonable and should be maintained. The FERC has not yet acted on this complaint, and managementALJ’s initial recommendation is unable to predict the ultimate outcomeexpected by March 31, 2016. A final FERC order is expected in late 2016 or estimate the impacts of this complaint on the financial position, results of operations or cash flows.early 2017.
As of December 31, 2013, the2015, CL&P, NSTAR Electric, PSNH, and WMECO had approximately $2.7 billion of aggregate shareholder equity invested in their transmission facilities was approximately $2.3 billion.facilities. As a result, each 10 basis point change in the prospective period authorized base ROE would change annual consolidated earnings by an approximate $2.3$2.7 million. Although we are uncertain on the final outcome of the second and third complaints regarding the ROE, we believe the current reserves established are appropriate to reflect probable and reasonably estimable refunds.
FERC Order No. 1000: On August 15, 2014, the D.C. Circuit Court of Appeals upheld the FERC's authority to order major changes to transmission planning and cost allocation in FERC Order No. 1000 and Order No. 1000-A, including transmission planning for public policy needs, and the requirement that utilities remove from their transmission tariffs their rights of first refusal to build transmission. On March 19, 2015, the FERC acted on all rehearing requests filed by the NETOs, including CL&P, NSTAR Electric, PSNH and WMECO, and other parties and accepted the November 2013 compliance filing made by ISO-NE and the NETOs, subject to further compliance. The FERC accepted our proposal that the new competitive transmission planning process will not apply to certain projects, which have been declared as the preferred solution by ISO-NE, unless ISO-NE later decides a solution must be re-evaluated. The FERC determined on rehearing that we can restore provisions that recognize the NETOs’ rights to retain use and control of their existing rights of ways. Final compliance was filed by the NETOs in November 2015 and was accepted by the FERC on December 14, 2015.
Additionally, the FERC affirmed that it can eliminate our right of first refusal to build transmission in New England even though the FERC previously approved and granted special protections to these rights. The NETOs filed an appeal to the D.C. Circuit Court of Appeals, challenging this FERC ruling. State regulators also filed an appeal, challenging FERC’s determination that ISO-NE should select public policy transmission projects after a competitive process. The Court is expected to resolve the appeals in 2016.
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Regulatory Developments and Rate Matters
General:
Clean Energy RFP: In February 2015, pursuant to clean energy goals established in three New England states (Connecticut, Massachusetts and Rhode Island), CL&P, NSTAR Electric, WMECO, other EDCs, and state agencies in the three states jointly developed and issued a draft request for proposal (RFP) for clean energy resources (including Class I renewable generation and large hydroelectric generation). The draft RFP solicits offers for clean energy and the transmission to deliver that energy to the three states. The procurement will allow the states to identify large-scale projects that may offer the potential to meet their clean energy goals in a cost-effective manner when entered into jointly, while complying with the clean energy statutes within the three states.
The DPU and the Rhode Island Public Utilities Commission (PUC) approved the draft RFP that was jointly submitted by certain EDCs. The draft RFP encompassed the timetable and method for the solicitation and execution of any associated long-term contracts. On August 31, 2015, the DEEP issued a notice of proceeding on the Connecticut portion of the draft RFP and accepted public comment through September 30, 2015. On November 12, 2015, the DEEP and the Massachusetts and Rhode Island EDCs issuedthe RFP to a wide range of potentially interested bidders. In late January 2016, bidders submitted project proposals, among which were the Northern Pass and Clean Energy Connect projects, selection of which will take place between April and July 2016. The expected timeframe within which EDCs will execute contracts and submit them for regulatory commission approval from the respective state regulators is from June through October 2016 with approval expected in late 2016.
New England Natural Gas Pipeline Capacity: In 2014, the six New England states began to explore ways to address and mitigate winter natural gas price volatility and the associated impact on electric power supply costs attributable to winter pipeline capacity constraints. Five states are currently pursuing natural gas capacity expansion efforts. In 2014, Rhode Island approved legislation authorizing the Rhode Island Division of Public Utilities and Carriers and the Office of Energy Resources to participate in the RFP process and file proposals with the PUC. In late 2015, Access Northeast bid on the natural gas pipeline and storage RFP issued by the Rhode Island EDC. We expect the EDC will file their selected contracts with the PUC in the first half of 2016. The Massachusetts DPU determined that it has the authority to allow EDCs to contract for natural gas pipeline capacity and in late 2015, certain Massachusetts EDCs, including NSTAR Electric and WMECO, issued a natural gas pipeline capacity RFP. In December 2015 and January 2016, those Massachusetts EDCs filed with the DPU seeking approval of the contracts for pipeline and storage capacity, including Access Northeast. On January 19, 2016, the NHPUC issued an order accepting a staff report that concluded that the NHPUC could approve contracts between pipelines and EDCs if they were shown to reduce electricity costs and be in the public interest. In February 2016, PSNH filed for approval with the NHPUC, its proposed contract for natural gas pipeline capacity and storage with Access Northeast. The Connecticut DEEP expects to provide an opportunity for public comment on a natural gas pipeline capacity RFP in the first quarter of 2016.
Electric and Natural Gas Base Distribution Rates:
Each NUEversource utility subsidiary is subject to the regulatory jurisdiction of the state in which it operates: CL&P and Yankee Gas operate in Connecticut and are subject to PURA regulation; NSTAR Electric, WMECO and NSTAR Gas operate in Massachusetts and are subject to DPU regulation; and PSNH operates in New Hampshire and is subject to NHPUC regulation. The Regulated companies' distribution rates are set by their respective state regulatory commissions, and their tariffs include mechanisms for periodically adjusting their rates for the recovery of specific incurred costs.
In Connecticut, pursuant to the April 2012 PURA-approved Connecticut merger settlement agreement, CL&P is subject todistribution rates were established in a base distribution2014 PURA approved rate freeze until December 1, 2014.case. Yankee Gas distribution rates were established in a 2011 PURA approved rate case. SeeConnecticut - Yankee Gas Distribution Rate Case in thisRegulatory Developments and Rate Matters section for further information.
In Massachusetts, "An Act Relative to Competitively Priced Electricity in the Commonwealth" (Energy Act), which was enacted in 2012, requires 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 limits 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 and WMECO and NSTAR Gas arewere subject to a base distribution rate freeze through December 31, 2015.
NSTAR Gas distribution rates effective January 1, 2016 were established in an October 30, 2015 DPU distribution rate order. SeeMassachusetts – NSTAR Gas Distribution Rates in thisRegulatory Developments and Rate Matters section for further information. In New Hampshire, PSNH is currently operating underdistribution rates were established in a settlement approved by the 2010NHPUC in 2010. Prior to the expiration of that settlement, the 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 costscontinuation, and step increases on an annual basis.increased funding via rates, of PSNH’s reliability enhancement program. SeeNew Hampshire - Distribution Rates in thisRegulatory Developments and Rate Matters section for further information.
As a result of the PURA-approved Connecticut merger settlement agreement, we expect to file a CL&P base distribution rate proceeding in mid-2014 with base distribution rates effective December 1, 2014. The exact timing of the base distribution rate proceedings for our other utility subsidiaries has not yet been determined.
Major Storms:
2013, 2012Electric and 2011 Major Storms:Natural Gas Retail Rates:Over the past three years, CL&P, NSTAR Electric, PSNH and WMECO each experienced significant storms, including Tropical Storm Irene, the October 2011 snowstorm, Storm Sandy, and the February 2013 blizzard. As a result of these storms, each electric utility company suffered damage to its distribution and transmission systems, which caused customer outages and required the incurrence of costs to repair significant damage and restore customer service.
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 our response to each of these storms was prudent and therefore we believe it is probable that CL&P, NSTAR Electric, PSNH and WMECO will be allowed to recover the deferred storm restoration costs. Each electric utility company is seeking recovery of its deferred storm restoration costs through its applicable regulatory recovery process.
CL&P 2013 Storm Filing: In March 2013, CL&P filed a request with PURA for approval to recover storm restoration costs associated with five major storms, all of which occurred in 2011 and 2012. CL&P's deferred storm restoration costs associated with these major storms totaled $462 million. Of that amount, approximately $414 million is subject to recovery in rates after giving effect to CL&P’s agreement to forego the recovery of $40 million of previously deferred storm restoration costs as well as an existing storm reserve fund balance of approximately $8 million. During the second half of 2013, the PURA proceeded with the storm recovery review issuing discovery, holding hearings and ultimately on February 3, 2014, issuing a draft decision on the level of storm costs recovery.
In its draft decision, the PURA approved recovery of $365 million of deferred storm restoration costs and ordered CL&P to capitalize approximately $18 million of the deferred storm restoration costs as utility plant, which will be included in depreciation expense in future rate proceedings. PURA will allow recovery of the $365 million with carrying charges in CL&P’s distribution rates over a six-year period beginning December 1, 2014. The remaining costs were either disallowed or are probable of recovery in future rates and did not have a material impact on CL&P’s financial position, results of operations or cash flows.The final decision is expected from PURA in the first quarter of 2014.
NSTAR Electric 2013 Storm Filing: On December 30, 2013, the DPU approved NSTAR Electric’s request to recover storm restoration costs, plus carrying costs, related to Tropical Storm Irene and the October 2011 snowstorm. The DPU approved recovery of $34.2 million of the $38 million requested costs. NSTAR Electric will recover these costs, plus carrying costs, in its distribution rates over a five-year period that commenced on January 1, 2014.
PSNH Major Storm Cost Reserve: On June 27, 2013, the NHPUC approved an increase to PSNH’s distribution rates effective July 1, 2013 that included a $5 million increase to the current level of funding for the major storm cost reserve.
WMECO SRRCA Mechanism:WMECO has an established Storm Reserve Recovery Cost Adjustment (SRRCA) mechanism to recover the restoration costs associated with its major storms. Effective January 1, 2012, WMECO began recovering the restoration costs of Tropical Storm Irene and other storms that took place prior to August 2011. On August 30, 2013, WMECO submitted its 2013 Annual SRRCA filing to begin recovering the restoration costs associated with the October 2011 snowstorm and Storm Sandy. On
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December 20, 2013, the DPU approved the 2013 Annual SRRCA filing for effect on January 1, 2014, subject to further review and reconciliation.
2013, 2012 and 2011 Major Storm Deferrals:As of December 31, 2013, the storm restoration costs deferred for recovery from customers for major storms that occurred during 2013, 2012 and 2011 at CL&P, NSTAR Electric, PSNH, and WMECO were as follows:
| | | | | | |
(Millions of Dollars) | | 2012
and 2011 | | 2013 | | Total |
CL&P | | $ 365.0 | | $ 28.8 | | $ 393.8 |
NSTAR Electric | | 61.3 | | 63.6 | | 124.9 |
PSNH | | 33.7 | | 5.3 | | 39.0 |
WMECO | | 35.3 | | - | | 35.3 |
Total | | $ 495.3 | | $ 97.7 | | $ 593.0 |
DPU Storm Penalties:Under Massachusetts law and regulation, the DPU has established standards of performance for emergency preparation and restoration of service for electric companies, including required annual ERP filings with the DPU for review and approval. As a remedy to violations of those standards, the DPU is authorized to levy a penalty not to exceed $250,000 for each violation for each day that the violation persists up to a maximum penalty of $20 million for any related series of violations. In December 2012, in separate orders issued by the DPU, NSTAR Electric and WMECO each received penalties related to the electric utilities’ responses to Tropical Storm Irene and the October 2011 snowstorm. The DPU ordered penalties of $4.1 million and $2 million for NSTAR Electric and WMECO, respectively, which 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. NSTAR Electric and WMECO filed initial briefs on November 5, 2013. Oral arguments are scheduled for March 2014.
Emergency Response Plans: Under Connecticut law and regulation, the PURA has established performance standards that electric and natural gas companies incorporated into their ERPs and operations in 2013. CL&P and Yankee Gas will be subject to penalties levied by PURA of up to 2.5 percent of annual distribution revenues for failure to meet performance standards. In 2013, CL&P and Yankee Gas met the established performance standards.
Connecticut:
CL&P Standard Service and Last Resort Service Rates:CL&P's residential and small commercial customers who do not choose competitive suppliers are served under SS rates, and large commercial and industrial customers who do not choose competitive suppliers are served under LRS rates. Effective January 1, 2014, the PURA approved an increase to CL&P’s energy supply portion of the total average SS rate from 7.638 cents per kWh to 9.152 cents per kWh and the energy supply portion of the total average LRS rate from 6.698 cents per kWh to 10.762 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: On January 22, 2014, PURA approved CL&P’s 2012 CTA and SBC reconciliation as filed on April 1, 2013, which compared CTA and SBC billed revenues to revenue requirements, as required by PURA. The 2012 CTA was over recovered by $21.3 million, resulting in a cumulative net under recovered balance of $8.9 million as of December 31, 2012. The 2012 SBC was over recovered by $19.4 million, resulting in a cumulative net under recovery of $19.7 million as of December 31, 2012.
CL&P FMCC Filing:Semi-annually,CL&P files with PURA its FMCC filing, which reconciles actual FMCC revenues and charges and GSC revenues and expenses, for the six-month period under consideration. The filing identifies a total net over or under recovery, which includes the remaining uncollected or non-refunded portions from previous filings. On August 1, 2013, CL&P filed with PURA its semi-annual FMCC filing for the period January 1, 2013 through June 30, 2013. This filing also included the June 30, 2013 through December 31, 2013 projected amounts for informational purposes only. The filing identified a total net under recovery of $2.7 million for the period. On February 19, 2014, PURA approved CL&P’s FMCC filing.
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 those already collected through the statutory charge and the revenues lost because of the expanded energy efficiency programs. On September 11, 2013, DEEP approved CL&P’s expanded 2014 conservation spending budget of $144.6 million. 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 Long-Term Wind Contracts: On September 19, 2013, CL&P, along with another Connecticut utility, signed long-term commitments, as required by regulation, to purchase approximately 250 MW of wind power from a Maine wind farm and 20 MW of solar power from sites in Connecticut, at a combined average price of less than 8 cents per kWh. On October 23, 2013, PURA issued a final decision accepting the contracts. The projects are expected to be operational by the end of 2016. For further information, see "Legislative and Policy Matters - Connecticut" in thisManagement’s Discussion and Analysis.
CL&P System Resiliency Plan: On January 16, 2013, PURA approved the $300 million plan CL&P filed to improve the resiliency of its electric distribution system. For further information, see "Business Development and Capital Expenditures - Distribution Business - CL&P System Resiliency Plan" in thisManagement’s Discussion and Analysis.
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Yankee Gas Distribution Rate Case: On June 29, 2011, PURA issued a final decision in the Yankee Gas rate proceeding, which it subsequently amended on September 28, 2011. The final decision, as amended, approved a regulatory ROE of 8.83 percent, based on a capital structure of 52.2 percent common equity and 47.8 percent debt, approved Yankee Gas’ WWL Project, and allowed for an increase for bare steel and cast iron pipe annual replacement funding, as requested by Yankee Gas. The changes were effective July 20, 2011 and had the effect of decreasing revenues by $0.2 million for the twelve months ended June 30, 2012 and increasing revenues by $6.9 million for the twelve months ended June 30, 2013.
Yankee Gas Natural Gas Expansion Plan:On June 14, 2013, Yankee Gas and other Connecticut natural gas distribution companies filed an expansion plan with DEEP and PURA in response to the Connecticut CES and the recently enacted Connecticut Public Act 13-298, "An Act Concerning Implementation of Connecticut’s Comprehensive Energy Strategy and Various Revisions to the Energy Statutes." The expansion plan describes how the natural gas distribution companies expect to add approximately 280,000 new natural gas heating customers over the next 10 years. Yankee Gas will serve approximately 82,000 of those customers.
The expansion plan outlines a set of comprehensive recommendations, several of which are already incorporated into Public Act 13-298. Key recommendations include providing more flexibility in the process of adding new customers, establishing new regulatory tools to help fund conversion costs over time, providing for mechanisms for timely recovery of capital investments made by natural gas distribution companies and allowing utilities to secure additional pipeline capacity into Connecticut.
On July 16, 2013, DEEP issued a determination letter finding the expansion plan was consistent with the CES and requesting certain modifications to be made. On July 26, 2013, the natural gas distribution companies submitted their responses to DEEP and PURA. On November 22, 2013, PURA issued a final decision approving the expansion plan consistent with the goals of the CES. For further information on the Connecticut law, see "Legislative and Policy Matters - Connecticut" in thisManagement’s Discussion and Analysis.
Massachusetts:
Basic Service Rates:Electric distribution companies in Massachusetts are required toEversource EDCs 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 ServiceThe natural gas distribution companies procure natural gas for firm and seasonal customers. These energy supply procurement costs are recovered from customers in energy supply rates that are approved by the respective state regulatory commission. The rates are reset every six months (every three months for large commercialperiodically and industrial customers). NSTAR Electricare fully reconciled to their costs. Each electric and WMECOnatural gas distribution company fully recover theirrecovers its energy supply costs through DPU-approvedapproved regulatory rate mechanisms.mechanisms and, therefore, such costs have no impact on earnings.
2014 Annual Reconciliation Filing:On November 1, 2013, NSTAR ElectricThe electric and WMECO filed separately their respective 2014 annualnatural gas distribution companies also recover certain costs on a fully reconciling basis through regulatory commission-approved cost recoverytracking mechanisms including theand, therefore, such costs have no impact on earnings. Costs recovered through costs tracking mechanisms to collect the costs to provide retail transmission, energy supply andinclude energy efficiency services to its customers as well as theprogram costs, related to pensionelectric transmission charges, electric federally mandated congestion charges, system resiliency costs, certain uncollectible hardship bad debt expenses, and other post-retirement employee benefit costs.restructuring and stranded costs resulting from deregulation. The reconciliation filings comparedcompare the total revenuesactual costs allowed to revenue requirements related to these services.services and the difference between the costs incurred (or the rate recovery allowed) and the actual costs allowed is deferred and included, to be either recovered or refunded, in future customer rates.
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Connecticut:
CL&P Distribution Rates: In December 2014, the PURA granted a re-opener request to CL&P’s base distribution rate application for further review of the appropriate balance of ADIT utilized in the calculation of rate base. On July 2, 2015, the PURA issued a final order that approved a settlement agreement filed on May 19, 2015 between CL&P and the PURA Prosecutorial Staff. The order allows for an increase to rate base of approximately $163 million associated with ADIT, including a regulatory asset to recover the incremental revenue requirement for the period December 1, 2014 through November 30, 2015 over a subsequent 24-month period. The rate base increase provided an increase to total allowed annual revenue requirements of $18.4 million beginning December 1, 2014. As part of the settlement agreement, the $18.4 million for the period December 1, 2014 through November 30, 2015 was recorded as a regulatory asset with a corresponding increase in Operating Revenues, and is being collected from customers in rates over a 24-month period beginning December 1, 2015.
CL&P and Yankee Gas Conservation and Load Management Plan: On December 31, 2013,2015, DEEP approved the three-year electric and natural gas C&LM plan filed by CL&P and Yankee Gas, which was jointly developed with the Connecticut EDCs and natural gas distribution companies. The C&LM plan, which covers the years 2016 through 2018, was built upon the continued success and momentum of the previous C&LM plans and includes performance incentives totaling $24 million over the three-year period related to proposed savings goals for CL&P and Yankee Gas.
Yankee Gas Settlement Agreement: On April 29, 2015, the PURA approved a settlement agreement entered into among Yankee Gas, the Connecticut Office of Consumer Counsel, and the PURA Staff, which eliminated the requirement to file a base distribution rate case in 2015. Under the terms of the settlement agreement, Yankee Gas provided a $1.5 million rate credit to firm customers beginning in December 2015 and continued through February 2016, and established an earnings sharing mechanism whereby Yankee Gas and its customers will share equally in any earnings exceeding a 9.5 percent ROE in a twelve month period commencing with the period from April 1, 2015 through March 31, 2016. Additionally, Yankee Gas shall forgo its right to file a rate case for an increase in its base distribution rates prior to January 1, 2017. This does not impact the rates charged under the Connecticut comprehensive energy strategy (CES) program. The settlement agreement also resolved two pending regulatory proceedings before the PURA pertaining to a review of Yankee Gas’ overearnings. In 2015, Yankee Gas recorded the $1.5 million expected refund to customers as a reduction to operating revenues.
Massachusetts:
NSTAR Electric and NSTAR Gas Comprehensive Settlement Agreement: On March 2, 2015, the DPU approved the comprehensive settlement agreement between NSTAR Electric, NSTAR Gas and the Massachusetts Attorney General (the"Settlement") as filed with the DPU on December 31, 2014. The Settlement resolved the outstanding NSTAR Electric CPSL program filings for 2006 through 2011, the NSTAR Electric and NSTAR Gas PAM and energy efficiency-related customer billing adjustments reported in 2012, and the recovery of LBR related to NSTAR Electric's energy efficiency programs for 2009 through 2011 (11 dockets in total). In the first quarter of 2015, as a result of the DPU order, NSTAR Electric and NSTAR Gas commenced refunding a combined $44.7 million to customers, which was recorded as a regulatory liability. Refunds to customers will continue through December 2016. As a result of the Settlement, NSTAR Electric increased its operating revenues and decreased its amortization expense in 2015, resulting in the recognition of a $13 million after-tax benefit.
NSTAR Electric Basic Service Bad Debt Adder: On January 7, 2015, the DPU issued an order concluding that NSTAR Electric had removed energy-related bad debt costs from base distribution rates effective January 1, 2006. As a final decision approvingresult of the rates asDPU order, in the first quarter of 2015, NSTAR Electric increased its regulatory assets and reduced its operations and maintenance expense by an under recovered amount of $24.2 million for energy-related bad debt costs through 2014, resulting in after-tax earnings of $14.5 million. NSTAR Electric filed subject to future review and reconciliation. Asfor recovery of December 31, 2013, we had cumulative deferred netthe energy-related bad debt costs regulatory asset balances relatedfrom customers and on November 20, 2015, the DPU approved NSTAR Electric’s proposed rate increase to recover these services of $142.1 million and $9.9 million for costs over a 12-month period, beginning January 1, 2016.
NSTAR Electric and WMECO respectively.Grid Modernization Plan: As part of the DPU’s investigation into the modernization of the electric grid, in August 2015, NSTAR Electric and WMECO filed a comprehensive ten-year plan with the DPU. The plan focuses on technologies and investments that modernize the grid with proposed investments in equipment that reduces the frequency and duration of power outages, optimizes and manages electrical demand, integrates distributed energy resources, and improves workforce and asset management. The plan includes incremental spending of approximately $430 million over the first five years, which would be recovered from customers in rates, and is pending DPU review and approval. There is currently no timeline for the DPU to take any action on this plan.
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, WMECO and NSTAR Gas Energy Efficiency Plan: The Massachusetts EDCs and approved bynatural gas distribution companies have increased their energy efficiency savings achievements significantly since the enactment of the Green Communities Act in 2008, with electric savings almost tripling between 2008 and 2014. On January 28, 2016, the DPU in 2010 coveringissued an order approving NSTAR Electric’s, WMECO’s, and NSTAR Gas’ three-year electric and natural gas energy efficiency plan, which was jointly developed with other Massachusetts EDCs and natural gas distribution companies. As part of this plan, which covers the period 2010years 2016 through 2012. The2018, NSTAR Electric, WMECO, and NSTAR Gas will maintain aggressive savings goals. The plan includes the ability to earn performance incentives related to these aggressive savings goals totaling $58 million over the three-year 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 and NSTAR Gas, include Lost Base Revenue (LBR) rate adjustment mechanisms in order to offset reduced distribution rate revenues as a result of successful energy efficiency programs. For the year ended December 31, 2013,for NSTAR Electric, WMECO and NSTAR Gas, incurred recoverable Energy Efficiency program expensesas well as recovery of $167.2LBR of approximately $50 million $38.9 million, and $31 million, respectively.
Long-Term Wind Contracts:on an annual basis for NSTAR Electric and WMECO, along with two other Massachusetts utilities, signeduntil it is operating under a long-term commitment, as required by regulation, to purchase wind power from six wind farms in Maine and New Hampshire for a combined estimated generating capacity of approximately 565 MW. On September 20, 2013, these contracts were filed jointly with the DPU. On November 21, 2013, the utility companies provided a supplemental filing to the DPU to reflect the termination of three of the six wind farms. Initial briefs were filed on December 23, 2013 and reply briefs were filed on January 8, 2014. Over the 15-year life of the remaining contracts, the utilities will pay an average price of less than 8 cents per kWh. The projects are in various stages of permitting or development and are expected to begin operation in 2015 and 2016.
On November 26, 2012, the DPU approved NSTAR Electric’s 15-year renewable energy contract with Cape Wind Associates, LLC. Under this contract, NSTAR Electric would purchase 129 MW of renewable energy from an offshore wind energy facility, which is currently expected to achieve commercial operation by May 2016.decoupled rate structure.
NSTAR Electric DPU Safety and Reliability Programs (CPSL): Since 2006,The safety and reliability programs allowed NSTAR Electric has been recovering incremental coststo recover $15 million per year, through December 31, 2015, related to DPU approved safety and reliability programs, which are designed to mitigate stray voltage and repair and replace portions of the DPU-approved Safetysystem to increase and Reliability Programs. From 2006 through 2011, cumulative costs associated with the CPSL program resulted in an incremental revenue requirement to customers of approximately $83 million. These amounts included incremental operations and maintenance costs and the related revenue requirement for specific capital investments relative to the CPSL programs.enhance customer safety.
NSTAR Gas Distribution Rates: On May 28, 2010,October 30, 2015, the DPU issued its order in the NSTAR Gas distribution rate case, which approved an order on NSTAR Electric’s 2006 CPSL costannualized base rate increase of $15.8 million, plus other increases of approximately $11.5 million, mostly relating to recovery filing (the May 2010 Order).of pension and PBOP expenses and the Hopkinton Gas Service Agreement (GSA), effective January 1, 2016. In October 2010, NSTAR Electric filed a reconciliation of the cumulative CPSL program activity for the periods 2006 through 2009 withorder, the DPU in order to determine a proposed rate adjustment. The DPU allowed the proposed rates to go into effect January 1, 2011, subject to finalalso approved an authorized regulatory
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reconciliationROE of CPSL program9.8 percent, the establishment of a revenue decoupling mechanism, the recovery of certain bad debt expenses, and a 52.1 percent equity component of its capital structure. On November 19, 2015, NSTAR Gas filed a motion for reconsideration of the order with the DPU seeking the correction of mathematical errors and other plant and cost of service items.
As a result of this order, Eversource recorded regulatory deferrals for costs throughthat have been approved for recovery or are expected to be approved for recovery in future rate proceedings, which resulted in the recognition of a future DPU proceeding. In February 2013,$10.3 million after-tax benefit in 2015. Included in this amount is a $6.3 million after-tax benefit recorded at NSTAR Electric updated the October 2010 filing with final activity through 2011. NSTAR Electric recorded its 2006 through 2011 revenues under the CPSL programs based on the May 2010 Order.
NSTAR Electric cannot predict the timing of a final DPU order related to its CPSL filings for the period 2006 through 2011. While we do not believe that any subsequent DPU order would result in revenuescertain uncollectible hardship accounts receivable that are materially different thanexpected to be recovered in future rates given the amounts already recognized, it is reasonably possible that an order could have a material impact onallowed recoveries of uncollectible hardship accounts receivable by WMECO and NSTAR Electric’s results of operations, financial position and cash flows.
The April 4, 2012 DPU-approved comprehensive merger settlement agreement with the Massachusetts Attorney General stipulates that NSTAR Electric must incur a revenue requirement of at least $15 million per year for 2012 through 2015 related to these programs. CPSL revenues will end once NSTAR Electric has recovered its 2015-related CPSL costs. Realization of these revenues is subject to maintaining certain performance metrics over the four-year period and DPU approval. As of December 31, 2013, NSTAR Electric was in compliance with the performance metrics and has recognized the entire $15 million revenue requirement during 2013 and 2012.Gas.
BasicNSTAR Gas - Gas Service Bad Debt AdderAgreement:: In accordance with a generic On April 29, 2015, the DPU approved the GSA, subject to DPU modifications, between NSTAR Gas and Hopkinton LNG Corp. (HOPCO), an indirect, wholly-owned subsidiary of Eversource. On October 30, 2015, the DPU issued its order electric utilities in Massachusetts recover the energy-related portion of bad debt costs in their Basic Service rates. In 2007, NSTAR ElectricGas distribution rate case that required minor changes to the GSA. On May 22, 2015 and November 17, 2015, we filed its 2006 Basic Service reconciliationrevised GSAs with the DPU proposing an adjustment relatedreflecting these modifications. The GSA effectively replaces the former gas services agreement in place between NSTAR Gas and HOPCO, maintains NSTAR Gas Company's entitlement to 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 nature100 percent of the Basic Service bad debt adder.
In 2010, NSTAR Electric filed an appealcurrent capacity of the DPU’s order withHOPCO facilities, and provides for the SJC. In 2012, the SJC vacated the DPU order and remanded the matter to the DPU for further review. The DPU has not taken any action on the remand.
NSTAR Electric deferred approximately $34 millionrecovery of costs associated with energy-related bad debt as a regulatory asset through 2011 as NSTAR Electric had concluded that it was probable that these costs would ultimatelyplanned capital expenditures at the HOPCO facilities. We currently estimate the HOPCO facilities’ capital expenditures to be recovered from customers. Due to delaysapproximately $200 million, most of which will be invested and placed into service in the durationfirst five years of the proceedings, NSTAR Electric concluded that while an ultimate outcomeGSA. The GSA has a 30-year term commencing on the matter in its favor remained "more likely than not," it could no longer be deemed "probable." As a result, NSTAR Electric recognized a reserve related to the regulatory asset in 2012. NSTAR Electric will continue to maintain the reserve until the proceeding has been concluded with the DPU.January 1, 2016.
New Hampshire:
Distribution Rates: PSNH distribution rates were established in a settlement approved by the NHPUC in 2010. Rates established therein will continue until changed by the NHPUC in a subsequent distribution rate proceeding. In 2013,June 2015, PSNH filedsought and obtained approval for a distribution rate step increase in accordance withto fund continuation of the reliability enhancement program beyond the end of the PSNH's 2010 NHPUC approved distribution rate case settlement. On June 27, 2013, the NHPUC approved an increase to rates of $12.6 million,effective July 1, 2013. The increase consists primarily of $7.7 million related to net plant additions and a $5 million increase to the current level of funding for the Major Storm Cost reserve.
ESGeneration Divestiture:
On June 10, 2015, Eversource and SCRC Rates:On December 12, 2013, PSNH entered into the 2015 Public Service Company of New Hampshire Restructuring and Rate Stabilization Agreement (the Agreement) with the New Hampshire Office of Energy and Planning, certain members of the NHPUC staff, the Office of Consumer Advocate, two State Senators, and several other parties. The Agreement was filed a request with the NHPUC on the same day. Under the terms of the Agreement, PSNH has agreed to adjustdivest its ESgeneration assets upon NHPUC approval. The Agreement is designed to provide a resolution of issues pertaining to PSNH's generation assets in pending regulatory proceedings before the NHPUC. The Agreement provided for the Clean Air Project prudence proceeding to be resolved and SCRCall remaining Clean Air Project costs to be included in rates effective January 1, 2014. PSNH’s request proposed2016. As part of the Agreement, PSNH has agreed to forego recovery of $25 million of the deferred equity return related to the Clean Air Project. In addition, PSNH will not seek a general distribution rate increase effective before July 1, 2017 and will contribute $5 million to create a clean energy fund, which will not be recoverable from its customers. In 2015, PSNH recorded the current ES$5 million contribution as a long-term liability and SCRC billingan increase to Operations and Maintenance expense on the statements of income.
Upon completion of the divestiture process, all remaining stranded costs will be recovered via bonds that will be secured by a non-bypassable charge or through other recoveries in rates billed to reflect projected costs for 2014. PSNH's customers. For further information on the securitization legislation that was signed into law on July 9, 2015, see "Legislative and Policy Matters – New Hampshire" in thisManagement's Discussion and Analysis of Financial Conditions and Results of Operations.
On December 27, 2013,January 26, 2016, Advisory Staff of the NHPUC approvedand the request. The approved energy supply portionparties to the Agreement filed a stipulation with the NHPUC agreeing that near-term divestiture of PSNH’s generation was in the public interest and that the Agreement should be approved. Implementation of the 2014 rateAgreement is 9.23 cents per kWhsubject to NHPUC approval, which is expected in early 2016.
We believe that full recovery of PSNH's generation assets is probable through a combination of cash flows during the remaining operating period, sales proceeds upon divestiture, and the SCRC rate for 2014 is 0.35 cents per kWh.recovery of stranded costs in future rates.
Clean Air Project Prudence ProceedingProceeding::The Clean Air Project, which involved the installation of wet scrubber technology at PSNH’sPSNH'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 will remain open
Pursuant to conductthe Agreement, on December 22, 2015, the NHPUC approved PSNH’s request to increase its default energy service rate for full recovery of costs (including a comprehensive prudence review ofreturn) related to the Clean Air Project, as well as a deferred equity return, effective January 1, 2016. The approved energy supply portion of the 2016 rate is 9.99 cents per kWh (including all Clean Energy Project-related costs), and the establishmentSCRC rate for 2016 is a credit to customers 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 has issued a series of orders ruling on the scope of its Clean Air Project inquiry and discovery issues. On December 23, 2013, the NHPUC Staff and other intervenors filed testimony discussing the prudency of the Clean Air Project, which cost $421 million. Discovery is currently ongoing with hearings likely in late 2014. We continue to believe that we were prudent in the undertaking and completion of the Clean Air Project. While we cannot predict with certainty the outcome of the Clean Air Project prudence review, we believe all costs were incurred appropriately and are probable of recovery.
PSNH Generation:On January 18, 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. On July 15, 2013, 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.
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On September 18, 2013, the NHPUC issued a Request for Proposal to hire a valuation expert to determine the value of PSNH's generation assets and entitlements. On October 16, 2013, 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. On November 1, 2013, 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. A valuation expert has been hired and the investigation is currently ongoing. At this time, we cannot predict the outcome of this review. Our current PSNH generation rate base totals approximately $760 million. We continue to believe all costs and generation investments are probable of recovery.
Federal:
EPA Proposed NPDES Permit:PSNH maintains a NPDES permit consistent with requirements of the Clean Water Act for Merrimack Station. In 1997, PSNH filed in a timely manner for a renewal of this permit. As a result, the existing permit was administratively continued. On September 29, 2011, the EPA issued a draft renewal NPDES permit for PSNH's Merrimack Station for public review and comment. The proposed permit contains many significant conditions to future operation. The proposed permit would require PSNH to install a closed-cycle cooling system (including cooling towers) at the station. The EPA estimated that the net present value cost to install this system and operate it over a 20-year period would be approximately $112 million.
On October 27, 2011, the EPA extended the initial 60-day period for public review and comment on the draft permit for an additional 90 days until February 28, 2012. PSNH and other electric utility groups filed thousands of pages of comments contesting EPA’s draft permit requirements. PSNH stated that the data and studies supplied to the EPA demonstrate the fact that a closed-cycle cooling system is not warranted. The EPA does not have a set deadline to consider comments and to issue a final permit. Merrimack Station is permitted to continue to operate under its present permit pending issuance of the final permit and subsequent resolution of matters appealed by PSNH and other parties. Due to the site specific characteristics of PSNH's other fossil generating stations, we believe that closed-cycle cooling systems are not warranted. 0.017 cents per kWh.
Legislative and Policy Matters
Federal:
On January 2, 2013,December 18, 2015, the "American Taxpayer Relief"Protecting Americans from Tax Hikes" Act of 2012" became law, which extended the accelerated deduction of depreciation to businesses from 2015 through 2013.2019. This extended stimulus provided NUprovides us with cash flow benefits of approximately $275 million (including approximately $105 million for CL&P) due to a refund of taxes paid in 2015 and lower expected tax payments in 2016 of approximately $300 million (approximately $95 million at CL&P, $85 million at NSTAR Electric, $35 million at PSNH, and $50 million at WMECO).million.
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New Hampshire: On September 13, 2013,July 9, 2015, the Internal Revenue Service issued final Tangible Property regulationsGovernor of New Hampshire signed"An Act Relative to Electric Rate Reduction Financing" (the Act) permitting the NHPUC to issue finance orders that are meant to simplify, clarify and make more administrable previously issued guidance. Inauthorize the third quarterissuance of 2013, CL&P recorded an after-tax valuation allowance of $10.5 million against its deferred tax assets as a result of these regulations. NU israte reduction bonds in complianceaccordance with the new regulations, but continues to evaluate several new potential elections. Therefore, a change toPSNH divestiture agreement and the valuation allowance at CL&P could result once NU completes the reviewexpected NHPUC divestiture order, regarding cost recovery of the impactClean Air project and divestiture of the final regulations.PSNH’s remaining generation plants.
Connecticut:
In 2013,2015, the state of Connecticut enacted into law two significant energy bills. The first law, Public Act 13-298, implementedseveral changes to its corporate tax laws. Among the changes, commencing as of January 1, 2015, is the reduction in the amount of tax credits that corporations can utilize against its tax liability in a numberyear and a continuation of the recommendations proposed in the CES. Public Act 13-298 authorized the filing of a plan to expand natural gas service to Connecticut residents that currently do not have access to natural gas. For further information on Yankee Gas’ filing, see "Regulatory Developments and Rate Matters - Connecticut - Yankee Gas Natural Gas Expansion Plan" in thisManagement's Discussion and Analysis. The law also required PURA to implement decoupling for each of Connecticut’s electric and natural gas utilities in their next respective rate cases. Finally, the law allows electric distribution companies to recover their costs as well as lost revenues from various state energy policy initiatives, including expanded energy efficiency programs.
The second law, Public Act 13-303, "An Act Concerning Connecticut’s Clean Energy Goals," allows DEEP to conduct a process to procure from renewable energy generators, under long-term contracts with the electric distribution companies, additional renewable generation to help Connecticut meet its Renewable Portfolio Standard (RPS). Large scale hydropower facilities located in the New England Power Pool Generation Information System (NEPOOL GIS) geographic eligibility area or an area abutting the northern boundary of the NEPOOL GIS geographic eligibility area are eligible to bid into DEEP's process. If Connecticut experiences a material shortfall in reaching its RPS goals, such hydropower, under certain conditions, can be used to alleviate such shortfall, up to five percent of RPS requirements in 2020.
The law also requires DEEP to develop a schedule to assign a gradually reducing renewable energy credit value for all Class I biomass or landfill generation facilities. Such reduced credit values will not apply to biogas or anaerobic digestion facilities, or to facilities that have a long-term contract in place. The commissioner of DEEP may adjust such changes to the values of renewable energy credits, if such adjustment is appropriate given the availability of other Class I renewable energy sources.
On September 26, 2013, DEEP issued a final determination that authorized the state’s electric distribution companies to enter into long-term power purchase agreements for a total of 270 MW of Class I renewable generation from two projects. On October 23, 2013, PURA issued a final decision accepting the contracts presented by the electric distribution companies. On October 21, 2013, DEEP
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issued a Request for Proposal seeking proposals for energy and RECs from private developers for up to 4 percent of the state’s electric distribution companies’ load (estimated to be between 100 MW to 150 MW) of Class I renewable energy resources for biomass, landfill gas and run off river hydropower projects from new or existing facilities.
Massachusetts:
On July 24, 2013, Massachusetts enacted a law that changed thecorporate income tax surcharge through 2018, which effectively increases the state corporate tax rate applicable to utility companies9 percent for the years 2016 and 2017 and 8.25 percent for 2018. Also, effective January 1, 2014, from 6.5 percent2016, all Connecticut companies have a mandatory unitary tax filing requirement. We continue to 8 percent. Thereview the tax law change required NU to remeasure its accumulated deferred income taxeschanges and resulted in NU increasing its deferredtheir impact on the effective tax liability with an offsetting regulatory assetrates of approximately $61 million at its utility companies.Eversource and CL&P.
Critical Accounting Policies
The preparation of financial statements in conformity with GAAP requires management to make estimates, assumptions and, at times, difficult, subjective or complex judgments. Changes in these estimates, assumptions and judgments, in and of themselves, could materially impact our financial position, results of operations or cash flows. Our management 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:Accounting The: Our Regulated companies are subject to rate-regulation that is based on cost recovery and meets the criteria for application of accounting policiesguidance for rate-regulated operations, which considers the effect of regulation on the timing of the recognition of certain revenues and expenses. The Regulated companies conform to GAAP applicable to rate-regulated enterprises andcompanies' financial statements reflect the effects of the rate-making process.
The application of accounting guidance for rate-regulated enterprises results in recording regulatory assets and liabilities. Regulatory assets represent the deferral of incurred costs that are probable of future recovery in customer ratesrates. Regulatory assets are amortized as the incurred costs are recovered through customer rates. In some cases, we record regulatory assets before approval for recovery has been received from the applicable regulatory commission. We must use judgment to conclude that costs deferred as regulatory assets are probable of future recovery. We base our conclusion on certain factors, including, but not limited to, regulatory precedent. Regulatory liabilities represent revenues received from customers to fund expected costs that have not yet been incurred or probable future refunds to customers.
We use our best judgment when recording regulatory assets and liabilities; however, regulatory commissions can reach different conclusions about the recovery of costs, and those conclusions could have a material impact on our financial statements. We believe it is probable that each of the Regulated companies will recover the regulatory assets that have been recorded. If we determineddetermine that we couldcan no longer apply the accounting guidance applicable to rate-regulated enterprises to our operations, or that we could notcannot conclude that it is probable that costs wouldwill be recovered from customers in future rates, the costs would be charged to earnings in the period in which the determination is made.
For further information, see Note 3, "Regulatory Accounting," to the financial statements.
Unbilled Revenues: The determination of retail energy sales to residential, commercial and industrial customers is based on the reading of meters, which occurs regularly throughout the month. Billed revenues are based on these meter readings, and the majority of our recorded annual revenues is based on actual billings. Because customers are billed throughout the month based on pre-determined cycles rather than on a calendar month basis, an estimate of electricity or natural gas delivered to customers for which the customers have not yet been billed is calculated as of the balance sheet date.
Unbilled revenues represent an estimate of electricity or natural gas delivered to customers but not yet billed. Unbilled revenues are included in Operating Revenues on the statement of income and are assets on the balance sheet that are reclassified to Accounts Receivable in the following month as customers are billed. Such estimates are subject to adjustment when actual meter readings become available or when there is a change in estimates and under other circumstances.our estimates.
The Regulated companies estimate unbilled sales monthly using the daily load cycle method. The daily load cycle method allocates billed sales to the current calendar month based on the daily load for each billing cycle. The billed sales are subtracted from total month load, net of delivery losses, to estimate unbilled sales. Unbilled revenues are estimated by first allocating unbilled sales to the respective customer classes, then applying an estimated rate by customer class to those sales. The estimate of unbilled revenues is sensitive to numerous factors such as energy demands,demand, weather and changes in the composition of customer classes that can significantly impact the amount of revenues recorded.
For further information, see Note 1K, "Summaryrecorded at NSTAR Electric and PSNH because they do not have a revenue decoupling mechanism. CL&P and WMECO record a regulatory deferral to reflect the actual allowed amount of Significant Accounting Policies - Revenues,"revenue for decoupling, and unbilled revenues estimation is not critical to the financial statements. CL&P and WMECO.
Pension and PBOP: NUSCO sponsorsWe sponsor Pension and PBOP Plans to provide retirement benefits to our employees. Effective January 1, 2015, the NUSCOtwo Pension Plans were merged into one Pension Plan, sponsored by Eversource Service, and NSTAR Electric acts as plan sponsor for the NSTAR Pensionour PBOP Plans were merged into one PBOP Plan, both of which cover certain of our employees. In addition, our service company sponsors the NUSCO and NSTAR PBOP plans to provide certain health care benefits, primarily medical and dental, and life insurance benefits to retired employees. sponsored by Eversource Service.For each of these plans, several significant assumptions are used to determine the development of theprojected 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 is based on several significant assumptions.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.
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Pre-tax net periodic benefit expense (excluding SERP) for the Pension PlansPlan (excluding the SERP Plans) was $236.3$124.2 million, $234.9$118.4 million and $127.7$236.3 million for the years ended December 31, 2013, 20122015, 2014 and 2011,2013, respectively. The pre-tax net periodic benefit expense for the PBOP PlansPlan was $32.6$2.4 million, $72.3$8.1 million and $43.6$32.6 million for the years ended December 31, 2015, 2014 and 2013, 2012 and 2011, respectively. NSTAR pension and PBOP expense was included in NU beginning April 10, 2012.
We develop key assumptions for purposes of measuring liabilities as of December 31st and expenses for the subsequent year. These assumptions include the expected long-term rate of return on plan assets, discount rate, compensation/progression rate, and health care cost trend rates and are discussed below.
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Expected Long-Term Rate of Return on Plan Assets: In developing this assumption, we consider historical and expected returns andas well as input from our consultants. Our expected long-term rate of return on assets is based on assumptions regarding target asset allocations and corresponding expected rates of return for each asset class. We routinely review the actual asset allocations and periodically rebalance the investments to the targeted asset allocations when appropriate. For the year ended December 31, 2013,2015, our aggregate expected long-term rate of return assumption of 8.25 percent was used to determine our pension and PBOP expense. For the forecasted 20142016 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 within both the NUSCO and NSTAR Pension and PBOP Plans.allocations.
Discount Rate: Payment obligations related to the Pension Plans and PBOP Plans are discounted at interest rates applicable to the expected timing of each plan’splan's cash flows. The discount rate that iswas utilized in determining the 2015 pension and PBOP obligations iswas based on a yield-curve approach. This approach is based onutilizes a population of bonds with an average rating of AA based on bond ratings by Moody’s,Moody's, S&P and Fitch, and uses bonds with above median yields within that population. TheAs of December 31, 2015, the discount rates determined on this basisused to determine the funded status were 5.034.6 percent for the NUSCO Pension Plan 4.85and 4.62 percent for the NSTAR Pension Plan, 4.78PBOP Plan. As of December 31, 2014, the discount rates used were 4.2 percent for the NUSCO PBOPPension Plans and 5.104.22 percent for the NSTAR PBOP PlanPlans. The increase in the discount rate used to calculate the funded status resulted in a decrease on the Pension and PBOP Plan's liability of approximately $267 million and $60 million, respectively, as of December 31, 2013.2015.
Compensation/Progression Rate: This assumption reflects the expected long-term salary growth rate, which impacts the estimated benefits that pension plan participants receive in the future. As of December 31, 2013 and 2012, we used a compensation/progression rate of 3.5 percent for the NUSCO Pension Plan and 4 percent for the NSTAR Pension Plan, which reflects our current expectation of future salary increases, including consideration of the levels of increases built into collective bargaining agreements. agreements, and impacts the estimated benefits that Pension Plan participants receive in the future. As of both December 31, 2015 and 2014, the compensation/progression rate used to determine the funded status was 3.5 percent.
Mortality Assumptions: Assumptions as to mortality of the participants in our Pension and PBOP Plans are a key estimate in measuring the expected payments a participant may receive over their lifetime and the corresponding plan liability we need to record. During 2014, the Society of Actuaries released a series of updated mortality tables resulting from studies that measured mortality rates for various groups of individuals. The updated mortality tables released in 2014 increased the life expectancy of plan participants by three to five years and had the effect of increasing the estimated benefits to be provided to plan participants. The impact of adopting the updated mortality tables on Eversource's liability as of December 31, 2014 was an increase of approximately $340 million and $82 million for the Pension and PBOP Plans, respectively. In 2015, a revised scale for the mortality table was released having the effect of decreasing the estimate of benefits to be provided to plan participants. The impact of the adoption of the new mortality scale resulted in a decrease of $48 million and $23 million for the Pension and PBOP Plans' liability, respectively, as of December 31, 2015.
Actuarial Determination of Expense: Pension and PBOP expense is determined by our actuaries and consists of service cost and prior service cost, interest cost based on the discounting of the obligations, and amortization of actuarial gains and losses, 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.
We determine theThe expected return on plan assets for the NUSCO Pension and PBOP Plansis determined by applying ourthe assumed long-term rate of return to a four-year rolling average of planthe Pension and PBOP Plan asset fair values, which reduces year-to-year volatility.balances. This calculation recognizes investment gains or losses over a four-year period from the years in which they occur. Investment gains or losses for this purpose are the difference between the calculated expected return andis compared to the actual return or loss based on the change in the fair value of assets during the year. As of December 31, 2013, investment gains and losses that remain to be reflected in the calculation of plan assets over the next four years were losses of $41.8 million and gains of $27.6 million for the NUSCO Pension Plan and PBOPPlans, respectively. As investment gains and losses are reflected in the average plan asset fair values, they are subject to amortization with other unrecognized actuarial gains or losses. The plans currently amortize unrecognized actuarial gains or losses as a component of pension and PBOP expense over the average future employee service period. As of December 31, 2013, the net unrecognized actuarial losses on the NUSCO Pension and PBOP Plan liabilities were $628.8 million and $111 million, respectively. For the NSTAR Pension and PBOP Plans, the entire difference between the actual and expected return on plan assets asat the end of December 31, 2013 is immediately reflected as a component of unrecognized actuarialeach year to determine the investment gains or losses to be amortized over the estimated average future service period of the employees. As of December 31, 2013, the netimmediately reflected in unrecognized actuarial losses on the NSTAR Pensiongains and PBOP Plan liabilities were approximately $498 million and $12.1 million, respectively.losses.
Forecasted Expenses and Expected Contributions: Based upon the assumptions and methodologies discussed above, weWe estimate that the combined expense for the Pension Plan (excluding the SERP Plans) will be approximately $65 million and income for the PBOP Plan will be approximately $7.7 million, respectively, in 2016. Effective January 1, 2016, we elected to transition the discount rate to the spot rate methodology from the yield-curve approach for the service and interest cost components of Pension and PBOP expense because it provides a more precise measurement by matching projected cash flows to the corresponding spot rates on the yield curve. Historically, these components were estimated using the same weighted-average discount rate as for the funded status. The discount rates used to estimate the 2016 service costs are 4.91 percent and 5.14 percent for the Pension and PBOP Plans, will be $132 millionrespectively. The discount rates used to estimate the 2016 interest costs are 3.80 percent and $9.1 million, respectively, in 2014.3.72 percent for the Pension and PBOP Plans, respectively. Pension and PBOP expense for subsequent years will depend on future investment performance, changes in future discount rates and other assumptions, and various other factors related to the populations participating in the plans. Pension and PBOP expense charged to earnings is net of the amounts capitalized.
We expect to continue our policy to contribute to the NUSCO PBOP Plans at the amount of PBOP expense excluding any curtailments and the NSTAR PBOP Plan at an amount that approximates benefit payments. We contributed $57.6 million to the PBOP Plans in 2013 and expect to contribute $39.7 million in 2014. NU'sOur policy is to annually fund the Pension Plans annuallyPlan in an amount at least equal to anthe amount that will satisfy theall federal funding requirements. NU made contributions to the NUSCO Pension Plan totaling $202.7 million in 2013, of which $108.3 million wasWe contributed by PSNH. NSTAR Electric contributed $82 million to the NSTAR Pension Plan in 2013. Our Pension Plan funded ratio (the value of plan assets divided by the funding target in accordance with the requirements and guidelines of the PPA) was 94.6 percent and 96 percent as of January 1, 2013 for the NUSCO Pension Plan and NSTAR Pension Plan, respectively. We currently estimate that aggregate contributions of $71.6$154.6 million to the Pension Plans will be madePlan in 2014. Fluctuations in the average discount rate used to calculate expected2015. We currently estimate approximately $146 million of contributions to the Pension Plans can have a significant impact on the amounts.Plan in 2016.
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For the PBOP Plan, it is our policy to annually fund the PBOP Plan though tax deductible contributions to external trusts. We contributed $7.9 million to the PBOP Plan in 2015. We currently estimate approximately $9.5 million in contributions to the PBOP Plan in 2016.
Sensitivity Analysis: The following represents the hypothetical increase to the Pension Plans’Plan's (excluding SERP)the SERP Plans) and PBOP Plans’Plan's reported annual cost as a result of a change in the following assumptions by 50 basis points:
| | | | | | | | | | | | |
| | Pension Plan Cost | | PBOP Plan Cost |
(Millions of Dollars) | | As of December 31, |
Assumption Change | | | 2013 | | | 2012 | | 2013 | | 2012 |
NU | | | | | | | | | | | | |
Lower long-term rate of return | | $ | 17.2 | | $ | 15.0 | | $ | 3.4 | | $ | 3.1 |
Lower discount rate | | $ | 22.3 | | $ | 22.0 | | $ | 6.8 | | $ | 6.7 |
Higher compensation increase | | $ | 12.4 | | $ | 10.4 | | | N/A | | | N/A |
| | | | | | | | | | | | |
NSTAR Plans | | | | | | | | | | | | |
Lower long-term rate of return | | $ | 5.6 | | $ | 4.8 | | $ | 1.8 | | $ | 1.7 |
Lower discount rate | | $ | 5.4 | | $ | 6.8 | | $ | 3.4 | | $ | 4.1 |
Higher compensation increase | | $ | 3.8 | | $ | 3.6 | | | N/A | | | N/A |
| | | | | | | | | | | | |
(Millions of Dollars) | | Increase in Pension Plan Cost | | Increase in PBOP Plan Cost |
Assumption Change | | As of December 31, |
Eversource | | | 2015 | | | 2014 | | 2015 | | 2014 |
Lower expected long-term rate of return | | $ | 20.6 | | $ | 19.3 | | $ | 4.2 | | $ | 4.0 |
| | | | | | | | | | | | |
Lower discount rate | | $ | 26.3 | | $ | 19.1 | | $ | 6.2 | | $ | 2.2 |
| | | | | | | | | | | | |
Higher compensation rate | | $ | 12.4 | | $ | 10.2 | | | N/A | | | N/A |
Changes in pension and PBOP costs would not impact net income for the NSTAR Plans as their expenses are fully recovered in rates, which reconcile each year relative to the change in costs.
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Health Care Cost: The health care cost trend rate assumption used to calculate the 2013 PBOP expense amounts was 7 percent for the NUSCO PBOP Plan, subsequently decreasing by 50 basis points per year to an ultimate rate of 5 percent in 2017, and 7.10 percent for the NSTAR PBOP Plan, subsequently decreasing to an ultimate rate of 4.5 percent in 2024. As of December 31, 2013,2015, the health care cost trend rate assumption used to determine the NUSCO and NSTAR PBOP Plans’Plan's year end funded status is 7was 6.25 percent, subsequently decreasing to an ultimate rate of 4.5 percent in 2024.2023. 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 $7.1million$8.5 million in 2013, with2015, and a $85.8$115.3 million impact on the postretirement benefit obligation. See Note 10A, "Employee Benefits - Pension Benefits and Postretirement Benefits Other Than Pensions,"increase to the financial statements for more information.PBOP obligation.
Goodwill: We have recorded approximately $3.5 billion of goodwill associated with the previous mergers and acquisitions. NU hasWe have identified itsour 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, 2013,2015, goodwill was allocated to the reporting units as follows: $2.5 billion to Electric Distribution, $0.6 billion to Electric Transmission, and $0.4 billion to Natural Gas Distribution.
We are required to test goodwill balances for impairment at least annually by considering the fair valuevalues 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’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, 20132015 for the Electric Distribution, Electric Transmission and Natural Gas Distribution reporting units. This evaluation required the testconsideration of several factors that impact the fair value of the reporting units, including conditions and assumptions that affect the future cash flows of the reporting units. Key considerations include discount rates, utility sector market performance and merger transaction multiples, and internal estimates of future cash flows and net income.
The 20132015 goodwill impairment test resulted in a conclusion that goodwill is not impaired and none of theno reporting unitsunit is at risk of a goodwill impairment.
Income Taxes: Income tax expense is estimated annually for each of the jurisdictions in which we operate.operate and is recorded each quarter using an estimated annualized effective tax rate. This process to record income tax expense involves estimating current and deferred income tax expense or benefit and the impact of temporary differences resulting from differing treatment of items for financial reporting and income tax return reporting purposes. Such differences are the result of timing of the deduction for expenses, as well as any impact of permanent differences, non-tax deductible expenses, or other items including items that directly impact ourincome tax returnexpense 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.
A reconciliation of expected tax expense at the statutory federal income tax rate to actual tax expense recorded is included in Note 11, "Income Taxes," to the financial statements.
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. We follow generally accepted accounting principles to address the methodology to be used in recognizing, measuring and classifying the amounts associated with tax positions that are deemed to be uncertain, including related interest and penalties. The determination of whether a tax position meets the recognition threshold under thisapplicable 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
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(including (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 significantan adverse impact on earnings. We estimate these liabilities based on findings through various phases of the assessment, considering the most likely action plan from a variety of available remediation options (ranging from no action required to full site remediation and long-term monitoring), current site information from our site assessments, remediation estimates from third party engineering and remediation contractors, and our prior experience in remediating contaminated sites. If a most likely action plan cannot yet be determined, we estimate the liability based on the low end of a range of possible action plans. A significant portion of our environmental sites and reserve amounts relate to former MGP sites that were operated several decades ago and manufactured gas from coal and other processes, which resulted in certain by-products remaining in the environment that may pose a potential risk to human health and the environment. As assessments on these sites are performed, we may receive new information to be considered in our estimates related to the extent and nature of the contamination and the costs of required remediation.
Our estimates also incorporate currently enacted state and federal environmental laws and regulations and data released by the EPA and other organizations. The estimates associated with each possible action plan are judgmental in nature partly because there are usually several different remediation options from which to choose. Our estimates are subject to revision in future periods based on actual costs or new information from other sources, including the level of contamination at the site, the extent of our responsibility or the extent of remediation required, recently enacted laws and regulations or a change in cost estimates due to certain economic factors.
For further information, see Note 12A, "Commitments and Contingencies - Environmental Matters," to the financial statements.
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 recorded at fair value,not elected or designated as "normal purchases or normal sales" (normal), to marketable securities held in NU’s supplemental benefit trust and WMECO’s spent nuclear fuel trust, the marketable securities held in CYAPC's and YAEC's nuclear decommissioning trusts, to our valuations of investments in our Pension and PBOP plans,Plans, and nonrecurring fair value measurements ofto nonfinancial assets such as goodwill and AROs. This guidance was also applied in estimating the fair value of preferred stock and long-term debt.
Changes in fair value of the regulatedRegulated company derivative contracts are recorded as Regulatory Assets or Liabilities, as we expect to recover the costs of these contracts in rates.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.
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We use quoted market prices when available to determine the fair valuesvalue 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 future contract quantities under full requirements and supplemental sales 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.
For further information on derivative contracts and marketable securities, see Note 1I, "Summary of Significant Accounting Policies - Derivative Accounting," Note 5, "Derivative Instruments," and Note 6, "Marketable Securities," to the financial statements.
Other Matters
Accounting Standards Recently Adopted: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, 20132015 is summarized annually through 20182020 and thereafter as follows:
| | | | | | | | | | | | | | | | | | | | | |
NU | |
(Millions of Dollars) | | 2014 | | 2015 | | 2016 | | 2017 | | 2018 | | Thereafter | | Total |
Long-term debt maturities(a) | | $ | 576.7 | | $ | 216.7 | | $ | 200.0 | | $ | 745.0 | | $ | 810.0 | | $ | 5,031.6 | | $ | 7,580.0 |
Estimated interest payments on existing debt(b) | | | 329.1 | | | 309.9 | | | 304.1 | | | 299.6 | | | 247.3 | | | 2,124.6 | | | 3,614.6 |
Capital leases(c) | | | 2.6 | | | 2.4 | | | 2.2 | | | 2.1 | | | 2.1 | | | 5.4 | | | 16.8 |
Operating leases(d) | | | 20.1 | | | 18.1 | | | 15.4 | | | 12.4 | | | 8.5 | | | 22.3 | | | 96.8 |
Funding of pension obligations(d) (h) | | | 71.6 | | | 188.4 | | | 173.7 | | | 127.9 | | | 36.3 | | | - | | | 597.9 |
Funding of other postretirement benefit obligations(d) | | | 39.7 | | | 37.2 | | | 18.0 | | | 15.2 | | | 14.4 | | | - | | | 124.5 |
Estimated future annual long-term contractual costs (e) | | | 705.4 | | | 615.6 | | | 538.1 | | | 428.7 | | | 368.1 | | | 2,385.6 | | | 5,041.5 |
Other purchase commitments(d) (g) | | | 1,550.7 | | | - | | | - | | | - | | | - | | | - | | | 1,550.7 |
Total(f) (i) | | $ | 3,295.9 | | $ | 1,388.3 | | $ | 1,251.5 | | $ | 1,630.9 | | $ | 1,486.7 | | $ | 9,569.5 | | $ | 18,622.8 |
|
Eversource | | | | | | | | | | | | | | | | | | | | |
(Millions of Dollars) | | 2016 | | | 2017 | | | 2018 | | | 2019 | | | 2020 | | | Thereafter | | | Total |
Long-term debt maturities(a) | $ | 200.0 | | $ | 745.0 | | $ | 960.0 | | $ | 800.0 | | $ | 295.0 | | $ | 5,736.6 | | $ | 8,736.6 |
Estimated interest payments on existing debt(b) | | 371.2 | | | 366.6 | | | 313.1 | | | 284.2 | | | 245.8 | | | 2,849.6 | | | 4,430.5 |
Capital leases(c) | | 2.2 | | | 2.1 | | | 2.1 | | | 2.0 | | | 2.0 | | | 1.4 | | | 11.8 |
Operating leases(d) | | 16.4 | | | 13.8 | | | 10.4 | | | 8.5 | | | 6.8 | | | 15.4 | | | 71.3 |
Funding of pension obligations(d) (e) | | 146.0 | | | 167.5 | | | 114.5 | | | 70.6 | | | 20.2 | | | - | | | 518.8 |
Funding of PBOP obligations(d) | | 9.5 | | | 9.2 | | | 9.4 | | | 9.6 | | | - | | | - | | | 37.7 |
Estimated future annual long-term contractual costs(e)(f) | | 684.5 | | | 590.6 | | | 442.3 | | | 376.2 | | | 344.9 | | | 2,371.7 | | | 4,810.2 |
Total(g) | $ | 1,429.8 | | $ | 1,894.8 | | $ | 1,851.8 | | $ | 1,551.1 | | $ | 914.7 | | $ | 10,974.7 | | $ | 18,616.9 |
| | | | | | | | | | | | | | | | | | | |
CL&P | | | | | | | | | | | | | | | | | | | | | |
(Millions of Dollars) | | 2014 | | 2015 | | 2016 | | 2017 | | 2018 | | Thereafter | | Total | | 2016 | | | 2017 | | | 2018 | | | 2019 | | | 2020 | | | Thereafter | | | Total |
Long-term debt maturities(a) | | $ | 150.0 | | $ | 162.0 | | $ | - | | $ | 250.0 | | $ | 300.0 | | $ | 1,640.3 | | $ | 2,502.3 | $ | - | | $ | 250.0 | | $ | 300.0 | | $ | 250.0 | | $ | - | | $ | 1,990.3 | | $ | 2,790.3 |
Estimated interest payments on existing debt (b) | | | 127.9 | | 118.2 | | 115.7 | | 111.7 | | 93.4 | | 953.7 | | 1,520.6 | | 140.0 | | | 136.0 | | | 117.8 | | | 102.4 | | | 95.5 | | | 1,402.7 | | | 1,994.4 |
Capital leases(c) | | | 2.1 | | 2.0 | | 1.9 | | 2.0 | | 2.0 | | 5.4 | | 15.4 | | 1.9 | | | 1.9 | | | 2.0 | | | 2.0 | | | 2.0 | | | 1.4 | | | 11.2 |
Operating leases(d) | | | 4.0 | | 3.6 | | 2.9 | | 1.7 | | 1.2 | | 4.7 | | 18.1 | | 2.9 | | | 2.0 | | | 1.3 | | | 1.0 | | | 0.7 | | | 1.7 | | | 9.6 |
Funding of pension obligations(d) (h) | | | - | | - | | 0.5 | | 10.2 | | 5.4 | | - | | 16.1 |
Funding of other postretirement benefit obligations(d) | | | 4.2 | | 3.4 | | 1.9 | | 0.6 | | 0.6 | | 0.5 | | 11.2 |
Estimated future annual long-term contractual costs(e)(f) | | | 256.1 | | 249.9 | | 247.2 | | 191.1 | | 176.8 | | 872.6 | | 1,993.7 |
Other purchase commitments(d) (g) | | | 678.9 | | | - | | | - | | | - | | | - | | | - | | | 678.9 |
Total(f) (i) | | $ | 1,223.2 | | $ | 539.1 | | $ | 370.1 | | $ | 567.3 | | $ | 579.4 | | $ | 3,477.2 | | $ | 6,756.3 |
Funding of pension obligations(d) (e) | | 0.4 | | | 15.5 | | | 26.3 | | | 21.1 | | | 6.1 | | | - | | | 69.4 |
Estimated future annual long-term contractual costs(f) | | 279.4 | | | 207.9 | | | 159.5 | | | 126.9 | | | 114.5 | | | 711.6 | | | 1,599.8 |
Total(g) | $ | 424.6 | | $ | 613.3 | | $ | 606.9 | | $ | 503.4 | | $ | 218.8 | | $ | 4,107.7 | | $ | 6,474.7 |
(a)
Long-term debt maturities exclude fees and interest due forthe CYAPC pre-1983 spent nuclear fuel disposal costs,obligation, net unamortized premiums, discounts and discounts,debt issuance costs, and other fair value adjustments.
(b)
Estimated interest payments on fixed-rate debt are calculated by multiplying the coupon rate on the debt by its scheduled notional amount outstanding for the period of measurement. Estimated interest payments on floating-rate debt are calculated by multiplying the averageend of the 20132015 floating-rate resetsreset 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 imputed interest.
(d)
Amounts are not included on our balance sheets.
(e)
Other than the net mark-to-market changes on derivative contracts held by the Regulated companies, these obligations are not included on our balance sheets.
(f)
Does not include unrecognized tax benefits as of December 31, 2013, as we cannot make reasonable estimates of the periods or the potential amounts of cash settlement with the respective taxing authorities. Also does not include an NU contingent commitment of approximately $38.1 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.
(g)
Amount represents open purchase orders, excluding those obligations that are included in the capital leases, operating leases and estimated future annual long-term contractual costs. These payments are subject to change as certain purchase orders include estimates based on projected quantities of material and/or services that are provided on demand, the timing of which cannot be determined. Because payment timing cannot be determined, we include all open purchase order amounts in 2014.
(h)
These amounts represent NU'sEversource's estimated minimum pension contributions to its qualified Pension Plans required under federal legislation.Plan. Contributions in 20152017 through 20182020 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.
(i)(f)
ExcludesOther 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 including the unrecognized tax benefits described above, deferred contractual obligations,recorded on our balance sheet, such as environmental reserves, employee medical insurance, and other reserves ($26.7 million at NU and $13.5 million at CL&P), workers compensation and long-term disability insurance reserves, ($43.3 million at NUARO liability reserves and $21.5 million at CL&P) and the ARO liabilityother reserves, as we cannot make reasonable estimates of the timing of payments. Also does not include amounts not included on our balance sheets for future funding of the Access Northeast project or for a contingent commitment of approximately $20 million to an energy investment fund, which would be invested under certain conditions, as we cannot make reasonable estimates of the periods or the investment contributions.
For further information regarding our contractual obligations and commercial commitments, see Note 8,6, "Asset Retirement Obligations," Note 7, "Short-Term Debt," Note 9,8, "Long-Term Debt," Note 10A,9A, "Employee Benefits - Pension Benefits and Postretirement Benefits Other Than Pensions," Note 12B,11, "Commitments and Contingencies, - Long-Term Contractual Arrangements," and Note 13,12, "Leases," to the financial statements.
5143
RESULTS OF OPERATIONS – NORTHEAST UTILITIESEVERSOURCE ENERGY AND SUBSIDIARIES
The following provides the amounts and variances in operating revenues and expense line items forin the consolidated statements of income for NUEversource for the years ended December 31, 2015, 2014, and 2013 included in this Annual Report on Form 10-K for the years ended December 31, 2013, 2012, and 2011. The year ended December 31, 2012 amounts include the operations of NSTAR beginning April 10, 2012:10-K.
Comparison of 20132015 to 20122014:
| | | | | | | | | | | | | |
| | | For the Years Ended December 31, | |
| | | | | | | | | Increase/ | | | |
(Millions of Dollars) | 2015 | 2014 | (Decrease) | Percent | |
Operating Revenues | $ | 7,954.8 | | $ | 7,741.9 | | $ | 212.9 | | 2.7 | % |
Operating Expenses: | | | | | | | | | | | |
| Purchased Power, Fuel and Transmission | | 3,086.9 | | | 3,021.6 | | | 65.3 | | 2.2 | |
| Operations and Maintenance | | 1,329.3 | | | 1,427.6 | | | (98.3) | | (6.9) | |
| Depreciation | | 665.9 | | | 614.7 | | | 51.2 | | 8.3 | |
| Amortization of Regulatory Assets, Net | | 22.3 | | | 10.7 | | | 11.6 | | (a) | |
| Energy Efficiency Programs | | 495.7 | | | 473.1 | | | 22.6 | | 4.8 | |
| Taxes Other Than Income Taxes | | 590.5 | | | 561.4 | | | 29.1 | | 5.2 | |
| | Total Operating Expenses | | 6,190.6 | | | 6,109.1 | | | 81.5 | | 1.3 | |
Operating Income | | 1,764.2 | | | 1,632.8 | | | 131.4 | | 8.0 | |
Interest Expense | | 372.4 | | | 362.1 | | | 10.3 | | 2.8 | |
Other Income, Net | | 34.2 | | | 24.6 | | | 9.6 | | 39.0 | |
Income Before Income Tax Expense | | 1,426.0 | | | 1,295.3 | | | 130.7 | | 10.1 | |
Income Tax Expense | | 540.0 | | | 468.3 | | | 71.7 | | 15.3 | |
Net Income | | 886.0 | | | 827.0 | | | 59.0 | | 7.1 | |
Net Income Attributable to Noncontrolling Interests | | 7.5 | | | 7.5 | | | - | | - | |
Net Income Attributable to Common Shareholders | $ | 878.5 | | $ | 819.5 | | $ | 59.0 | | 7.2 | % |
| | | | | | | | | | | | | |
(a) Percent greater than 100 percent not shown as it is not meaningful. |
| | | | | | | | | | | | | |
Operating Revenues | | |
| | | For the Years Ended December 31, | |
| | | | | | | | | Increase / | | | |
(Millions of Dollars) | 2015 | 2014 | (Decrease) | Percent | |
Electric Distribution | $ | 5,903.6 | | $ | 5,663.4 | | $ | 240.2 | | 4.2 | % |
Natural Gas Distribution | | 995.5 | | | 1,007.3 | | | (11.8) | | (1.2) | |
Electric Transmission | | 1,069.1 | | | 1,018.2 | | | 50.9 | | 5.0 | |
Other and Eliminations | | (13.4) | | | 53.0 | | | (66.4) | | (a) | |
Total Operating Revenues | $ | 7,954.8 | | $ | 7,741.9 | | $ | 212.9 | | 2.7 | % |
| | | | | | | | | | | | | |
(a) Percent greater than 100 percent not shown as it is not meaningful. |
| | | | | | | | | | | | | |
A summary of our retail electric sales volumes and firm natural gas sales volumes were as follows: |
| | | | | | | | | | | | | |
| | | For the Years Ended December 31, | |
| | | | | | | | | Increase/ | | | |
| 2015 | 2014 | (Decrease) | Percent | |
Electric Sales Volumes in GWh: | | | | | | | | | | | |
| Traditional | | 28,982 | | | 28,811 | | | 171 | | 0.6 | % |
| Decoupled | | 25,634 | | | 25,631 | | | 3 | | - | |
Total Electric Sales Volumes in GWh | | 54,616 | | | 54,442 | | | 174 | | 0.3 | % |
| | | | | | | | | | | | | |
Firm Natural Gas Sales Volumes in Million Cubic Feet | | 102,999 | | | 104,191 | | | (1,192) | | (1.1) | % |
Operating Revenues, which primarily consist of base electric and natural gas distribution revenues and tracked revenues further described below, increased by $212.9 million in the aggregate in 2015 compared to 2014.
| | | | | | | | | | | | | | |
| | | 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. |
OurBase electric and natural gas distribution revenues: Base electric distribution segment revenues increased $150.9 million due primarily to CL&P’s base distribution rate increase, effective December 1, 2014 ($136.3 million) and higher retail sales volumes driven by weather impacts at our non-decoupled operating companies (traditional). In addition, Operating Revenues increased in 2013, as$19.9 million at CL&P due to the PURA-approved settlement agreement regarding ADIT, $11 million for the Comprehensive Settlement Agreement associated with the recovery of LBR related to 2009 through 2011 energy efficiency programs at NSTAR Electric, and $20.7 million increase of 2015 LBR recognition at NSTAR Electric compared to 2012, due primarily to2014 LBR amounts. The $19.9 million represents CL&P's revenue requirement from the additionsettlement agreement's rate increase through December 31, 2015, and is being collected from customers in rates over a 24-month period beginning December 1, 2015. The impact of NSTAR's operations. Duringcolder winter weather experienced in 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 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 decision2015and warmer weather in the third quarter of 2013.
·
A $34.3 million2015, partially offset by milder winter weather in the fourth quarter of 2015, all as compared to the same periods in 2014, were the primary drivers of the increase in 2015 retail electric sales volumes of 0.6 percent and base electric distribution revenues net of applicable eliminations, reflecting an increase of approximatelyat NSTAR Electric and PSNH.
For CL&P (effective December 1, percent2014) and WMECO, fluctuations in retail electric sales.sales volumes do not impact earnings due to their respective regulatory commission approved revenue decoupling mechanisms. The increaserevenue decoupling mechanisms permit recovery of a base amount of distribution revenues and break the relationship between sales volumes and revenues recognized. Revenue decoupling mechanisms result in the
44
recovery of our approved base distribution revenue requirements. Therefore, changes in sales volumes had no impact on the level of base distribution revenue realized at our decoupled companies.
Firm natural gas base distribution segment revenues decreased $4.9 million due primarily to a 1.1 percent decrease in firm natural gas sales volumes in 2015, as compared to 2014. This was driven primarilydue to record warm weather in the fourth quarter of 2015 when compared to 2014, partially offset by the colder winter weather experienced throughout our service territories in earlythe first quarter of 2015 compared to 2014. Weather-normalized firm natural gas sales volumes (based on 30-year average temperatures) increased 2.5 percent in 2015 compared to 2014, due primarily to improved economic conditions as well as residential and 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 werecommercial customer growth, partially offset by the impact of ourcustomer conservation efforts resulting from company-sponsored energy efficiency programs.
52
·
A $28.8 millionincreaseTracked distribution revenues:Tracked revenues consist of certain costs that are recovered from customers in firmrates through regulatory commission-approved cost tracking mechanisms and therefore have no impact on earnings. Costs recovered through cost tracking mechanisms include energy supply procurement costs and other energy-related costs for our electric and natural gas customers, retail transmission charges, energy efficiency program costs, and restructuring and stranded cost recovery revenues. Tracked electric distribution revenues. This increase wassegment revenues increased primarily as a result of increases in energy supply costs ($176.4 million), driven by increased average retail rates, and increases in energy efficiency program revenues ($18.3 million). These increases were partially offset by a decrease in retail electric transmission charges ($77.5 million) and a decrease in the colder winter weatherfederally mandated congestion charge primarily driven by refunds in early and late 2013, residential customer growth, an increase in2015 for a prior year overrecovery ($103.9 million). Tracked natural gas conversions, the migrationsupply revenues decreased $20.1 million as a result of interruptible customers switching to firm servicea decrease in average rates and the addition of gas-fired distributed generation.
·
The remaining increase was due primarily to higher revenues from our tracker mechanisms related to the recovery of energynatural gas supply retailcosts.
Electric transmission revenues: The electric transmission segment revenues increased by $50.9 million due primarily to the result of lower reserves associated with the FERC ROE complaint proceedings in 2015 compared to 2014 and company-sponsored energy efficiency programs. Revenues relatedhigher revenue requirements associated with ongoing investments in our transmission infrastructure.
Other: Other revenues decreased due primarily to cost recovery mechanisms vary from period to period basedthe sale of Eversource's unregulated contracting business on the timing of collections of the costs incurred. These revenues had no material impact on earnings. April 13, 2015 ($55 million).
Purchased Power, Fuel and Transmission expense includes costs associated with purchasing electricity and natural gas on behalf of our customers. These energy supply costs are recovered from customers in rates through reconciling cost tracking mechanisms, which have no impact on earnings (tracked costs). Purchased Power, Fuel and Transmission increased in 2013,2015, as compared to 2012, due primarily to the following:
| | | |
| | 2013 Increase/(Decrease)
|
(Millions of Dollars)
| Compared to 2012
|
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 Maintenancedecreased in 2013, as compared to 2012,2014, due primarily to the following:
| | |
(Millions of Dollars) | Increase/(Decrease) |
The addition of NSTAR’s operationsElectric Distribution
| $ | 123.674.8
|
Partially offset by:Natural Gas Distribution
| | (1.6) |
Electric Transmission | | 2.8 |
Other and Eliminations | | (10.7) |
Total Purchased Power, Fuel and Transmission | $ | 65.3 |
The increase in purchased power costs at the electric distribution business was driven by higher prices associated with the procurement of energy supply in 2015, as compared to 2014. The decrease in purchased power costs at the natural gas distribution business was due to lower average natural gas prices in 2015, as compared to 2014.
Operations and Maintenanceexpense includes tracked costs and costs that are part of base electric and natural gas distribution rates with changes impacting earnings (non-tracked costs). Operations and Maintenance decreased in 2015, as compared to 2014, due primarily to the following:
| | |
| |
(Millions of Dollars) | Increase/(Decrease) |
Base Electric Distribution: | | |
Resolution of basic service bad debt adder mechanism at NSTAR Electric | $ | (24.2) |
Contribution to create clean energy fund in connection with the generation
divestiture agreement at PSNH | | 5.0 |
Increase in employee-related expenses, including labor and benefits | | 1.8 |
Other operations and maintenance | | 7.0 |
Total Base Electric Distribution | | (10.4) |
Total Base Natural Gas Distribution | | (1.5) |
Total Tracked costs (Transmission and Electric and Natural Gas Distribution) | | (9.3) |
Total Distribution and Transmission | | (21.2) |
Other and eliminations: | | |
Integration merger and settlement agreement costs | | (150.3)(8.4)
|
NU’sAbsence of Eversource's unregulated electrical contracting business costsdue to sale
in April 2015, net | | (17.4)(45.7)
|
General and administrativeMerger-related costs allowed for recovery | | (12.9)(7.0)
|
Transmission segment costsES Parent and Other Companies | | (5.2)(16.0)
|
Natural gas segment costs
| | 10.5
|
Electric distribution segment costs
| | 1.3
|
All other items
| | (17.7)
|
Total Operations and Maintenance | $ | (68.1)(98.3)
|
Depreciationincreased in 2013,2015, 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 increased2014, due primarily to higher utility plant in service balances resulting from completed construction projects placed into service.service and an increase in depreciation rates at CL&P as a result of the distribution rate case effective December 1, 2014.
45
Amortization of Regulatory Assets, Net,which are tracked costs, include certain regulatory-approved tracking mechanisms. Fluctuations in these costs are recovered from customers in rates and have no impact on earnings. Amortization of Regulatory Assets, Net, increased in 2013,2015, as compared to 2012,2014, due primarily to the following:
| | |
(Millions of Dollars) | Increase/(Decrease) |
CL&P: | | |
Amortization increase (including storm cost recovery) approved and included in
base distribution rates | $ | 61.0 |
Energy and energy-related supply costs tracking mechanism | | (108.0) |
NSTAR Electric (primarily the recognition of the Comprehensive Settlement
Agreement, partially offset by transition costs tracking mechanism) | | (6.7) |
PSNH (primarily default energy service charge tracking mechanism) | | 45.9 |
WMECO (primarily the absence of the refund of DOE proceeds to customers in 2014
and energy and energy-related cost tracking mechanisms) | | 20.7 |
Other | | (1.3) |
Total Amortization of Regulatory Assets, Net | $ | 11.6 |
The increase in CL&P's amortization was due primarily to an increase in storm cost recovery, which was approved and included in distribution rates effective December 1, 2014. In connection with the Comprehensive Settlement Agreement associated with the CPSL program filings, NSTAR Electric recognized an $11.7 million benefit in the first quarter of 2015, which was recorded as a reduction to amortization expense.
The remaining fluctuations in amortization expense are driven by the deferral of energy supply and energy-related costs, which can fluctuate from period to period based on the timing of costs incurred and related rate changes to recover these costs. Fluctuations in energy supply and energy-related costs, which are the primary drivers in amortization, are recovered from customers in rates and have no impact on earnings.
Energy Efficiency Programs, which are tracked costs, increased in 2015, as compared to 2014, due primarily to an increase in energy efficiency costs in accordance with the three-year program guidelines established by the DPU at NSTAR Electric.
Taxes Other Than Income Taxes increased in 2015, as compared to 2014, due primarily to an increase in property taxes as a result of both an increase in utility plant balances and property tax rates.
Interest Expenseincreased in 2015, as compared to 2014, due primarily to an increase in interest on long-term debt ($9.3 million) as a result of new debt issuances in 2015 and an increase in interest on notes payable ($1.9 million).
Other Income, Netincreased in 2015, as compared to 2014, due primarily to higher equity AFUDC amounts ($5.1 million) and an increase in interest income related to the deferred compensation plans ($4.3 million), partially offset by the absence in 2015 of a gain on the sale of land recorded in 2014 at CL&P ($4.5 million).
Income Tax Expense increased in 2015, as compared to 2014, due primarily to higher pre-tax earnings ($45.7 million), higher state taxes, the impact of adjusting our estimated tax expense to what was filed on our tax return (provision to return), the lower tax benefit in 2015 compared to 2014 from a change in tax reserves ($19.8 million), and higher items that impact our tax rate as a result of regulatory treatment (flow-through items) ($6.2 million).
46
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.
47
CL&P and NSTAR Electric recognized lost base revenue (LBR) related to reductions in sales volume as a result of energy efficiency. LBR is recovered from retail distribution customers. Including the impact from the recognition of LBR, base distribution revenues increased in 2014, as compared to 2013. We recognized $45.2 million of LBR in 2014, compared to $20.3 million in 2013. Effective December 1, 2014, CL&P no longer recognizes LBR due to its revenue decoupling mechanism, which, similar to WMECO's revenue decoupling mechanism, provides a base amount of distribution revenues ($1.059 billion on an annual basis) that effectively breaks the relationship between revenues and customer electricity usage. The revenue decoupling mechanism is designed to allow each of CL&P and WMECO to encourage energy efficiency for its customers without negatively impacting its revenues.
Transmission revenues increased $39.5 million in 2014, as compared to 2013, due primarily to the recovery of higher revenue requirements associated with ongoing investments in our transmission infrastructure. This increase was partially offset by the impact of the $37 million net reserve recorded in 2014 as a result of the 2014 FERC ROE orders, compared to the $23.7 million reserve recorded in 2013 for the FERC ALJ initial decision in the FERC base ROE complaints.
Purchased Power, Fuel and Transmission expense includes costs associated with purchasing electricity and natural gas on behalf of our customers. These energy supply costs are recovered from customers in rates through reconciling cost tracking mechanisms, which have no impact on earnings (tracked costs). Purchased Power, Fuel and Transmission increased in 2014, as compared to 2013, due primarily to the following:
| | |
(Millions of Dollars) | Increase/(Decrease) |
The addition of NSTAR’s operationsElectric Distribution
| $ | 45.8458.2
|
Recovery of transition costs at NSTAR ElectricNatural Gas Distribution
| | 91.9104.1
|
Amortization related to CL&P’s SBC and CTATransmission
| | (6.8)(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 Maintenanceexpense 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) |
Depreciationincreased 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 | | (4.4)(1.4)
|
Total Amortization of Regulatory Assets, Net | $ | 126.5 (195.6)
|
Amortization of Rate Reduction Bonds decreased in 2013,2014, as compared to 2012,2013, due primarily to the maturity in 2013 of RRBs of NSTAR Electric's, PSNH's,Electric, PSNH and WMECO's RRBs in 2013, partially offset by the addition of NSTAR Electric’s amortization ($15.1 million).WMECO.
48
Energy Efficiency Programs, which are tracked costs, increased in 2013,2014, as compared to 2012,2013, due primarily to the additionexpanded energy conservation programs at CL&P in 2014 as a result of NSTAR's operations ($68.6 million), as well as2013 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. AllWMECO, partially offset by a decrease in the amortization of previously deferred costs are fully recovered through DPU-approved tracking mechanisms and therefore do not impact earnings.at NSTAR Electric.
Taxes Other Than Income Taxes increased in 2013,2014, as compared to 2012,2013, 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 both an increase in Property, Plantutility plant balances 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.rates.
Interest Expenseincreased $8.8 million in 2013,2014, as compared to 2012,2013, due primarily to the addition of NSTAR’s operations ($22 million) and lower interest income onrelated to a decrease in the recovery of previously deferred transition costs ($10.69.9 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, Netdecreased 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 decreasenet gain on the sale of land ($4.5 million).
Income Tax Expenseincreased in Other Interest2014, as compared to 2013, due primarily to higher pre-tax earnings ($26.1 million), and higher state taxes and various other impacts ($15.3 million). The higher state taxes include a net reduction in the valuation allowance for state tax positions, which is based on the most recent available data.
EARNINGS SUMMARY
Excluding the impact of integration costs, our 2014 earnings increased by $41.8 million, as compared to 2013. The increase was due primarily to lower operations and maintenance costs that impact earnings, which were primarily driven by lower labor and other employee-related costs, including approximately $30 million of non-tracked pension costs, and lower storm restoration costs, as well as higher firm natural gas sales volumes as a result of the colder weather in the first quarter of 2014, as compared to the first quarter of 2013. Partially offsetting this increase was the absence in 2014 of a favorable impact from the resolution of a state income tax audit in the first quarter of 2013, lower interest on short-term debt ($8.8 million)higher property taxes, higher depreciation expense at our regulated companies, and lower interest on RRBs ($6.1 million).
53
Other Income, Netincreased $10.2 millionretail electric sales volumes as a result of cooler summer weather in 2013,2014, as compared to 2012, due primarily to higher gains on the NU supplemental benefit trust ($6 million) and an increasesame period in 2013. Earnings were also unfavorably impacted by the 2014 after-tax net reserve of $22.4 million 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 2013,2014 FERC ROE orders, as compared to 2012, due primarilythe 2013 after-tax reserve of $14.3 million related to higher pre-tax earnings ($81 million), the absence2013 FERC ALJ initial decision 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).the FERC base ROE complaints.
Comparison of 2012 to 2011:
| | | | | | | | | | | | | | |
| | | Operating Revenues and Expenses | | |
| For the Years Ended December 31, | |
(Millions of Dollars) | 2012(a) | | 2011 | | Increase/ | | Percent | | |
(Decrease) | |
Operating Revenues | $ | 6,273.8 | | $ | 4,465.7 | | $ | 1,808.1 | | 40.5 | % | |
Operating Expenses: | | | | | | | | | | | | |
| Purchased Power, Fuel and Transmission | | 2,084.4 | | | 1,657.9 | | | 426.5 | | 25.7 | | |
| Operations and Maintenance | | 1,583.1 | | | 1,095.4 | | | 487.7 | | 44.5 | | |
| Depreciation | | 519.0 | | | 302.2 | | | 216.8 | | 71.7 | | |
| Amortization of Regulatory Assets, Net | | 79.8 | | | 91.1 | | | (11.3) | | (12.4) | | |
| Amortization of Rate Reduction Bonds | | 142.0 | | | 69.9 | | | 72.1 | | (b) | | |
| Energy Efficiency Programs | | 313.1 | | | 131.4 | | | 181.7 | | (b) | | |
| Taxes Other Than Income Taxes | | 434.2 | | | 323.6 | | | 110.6 | | 34.2 | | |
| | Total Operating Expenses | | 5,155.6 | | | 3,671.5 | | | 1,484.1 | | 40.4 | | |
Operating Income | $ | 1,118.2 | | $ | 794.2 | | $ | 324.0 | | 40.8 | % | |
| | | | | | | | | | | | | | |
(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) | 2012(a) | | 2011 | | Increase | | Percent | |
Electric Distribution | $ | 4,716.5 | | $ | 3,343.1 | | $ | 1,373.4 | | 41.1 | % |
Natural Gas Distribution | | 572.9 | | | 430.8 | | | 142.1 | | 33.0 | |
| Total Distribution | | 5,289.4 | | | 3,773.9 | | | 1,515.5 | | 40.2 | |
Transmission | | 861.5 | | | 635.4 | | | 226.1 | | 35.6 | |
| Total Regulated Companies | | 6,150.9 | | | 4,409.3 | | | 1,741.6 | | 39.5 | |
Other and Eliminations | | 122.9 | | | 56.4 | | | 66.5 | | (b) | |
Total Operating Revenues | $ | 6,273.8 | | $ | 4,465.7 | | $ | 1,808.1 | | 40.5 | % |
| | | | | | | | | | | | |
(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. |
| | | | | | | | | |
A summary of our retail electric sales and firm natural gas sales were as follows: |
| | | | | | | | | |
| | For the Years Ended December 31, | |
| | 2012(a) | | 2011 | | Increase | | Percent | |
Retail Electric Sales in GWh | 49,718 | | 33,812 | | 15,906 | | 47.0 | % |
Firm Natural Gas Sales in Million Cubic Feet | 69,894 | | 46,880 | | 23,014 | | 49.1 | % |
| | | | | | | | | |
(a) Includes the retail electric and firm natural gas sales of NSTAR beginning April 10, 2012. |
Our Operating RevenuesOurelectric distribution segment earnings increased $35.4 million in 2012,2014, as compared to 2011, due primarily to the addition of NSTAR, which included electric distribution revenues of approximately $1.7 billion, transmission revenues of approximately $50 million, natural gas revenues of approximately $200 million and other revenues of approximately $15 million, and the consolidation of CYAPC and YAEC revenues of approximately $40 million. Excluding the impact of NSTAR's operations and the consolidation of CYAPC and YAEC, our Operating Revenues decreased due to the following:
·
Lower electric distribution segment revenues related to the portions that are included in regulatory commission approved tracking mechanisms that recover certain incurred costs and do not impact earnings. The tracking mechanisms allow for rates to be changed periodically with overcollections refunded to customers or undercollections recovered from customers in future
54
periods. The tracked electric distribution revenues decreased2013, due primarily to lower energyoperations and supply-relatedmaintenance costs ($241.8 million),that impact earnings, which were primarily driven by lower CL&P CTA revenues ($46.3 million),labor and other employee-related costs, including pension costs, and lower wholesale revenues ($44.4 million), lower retail transmission revenues ($17.8 million), partially offset by higher CL&P FMCC delivery-related revenues ($82.4 million), higher SCRC revenues at PSNH ($34.2 million) and higher CL&P retail SBC revenues ($22.5 million).
·
A decrease in natural gas segment revenues due primarily to a 4.3 percent decrease in Yankee Gas' sales volume related to the warmer than normal weather in the heating season of 2012,storm restoration costs. Partially offsetting these favorable earnings impacts, as compared to the heating season of 2011. In addition, there was a decrease in the cost of natural gas, which is fully recovered in revenues from sales to our customers.
Partially offset by:
·
Improved transmission segment revenues resulting from a higher level of investment in transmission infrastructure and the recovery of higher overall expenses, which are tracked and result in a related increase in revenues. The increase in expenses is directly related to the increase in transmission plant, primarily at WMECO, including costs associated with2013, were higher property taxes and depreciation and operation and maintenance expenses.
·
An increase at PSNH related to the sale of oil to a third party ($20.8 million) in the second quarter of 2012, resulting in a benefit to customers throughexpense, lower ES rates that does not impact earnings.
·
The portion of electric distribution segment revenues that impacts earnings increased $8.8 million due primarily to CL&P regulatory incentives of $11.5 million and C&LM incentives of $6.2 million at CL&P, partially offset by a decrease in retail electric sales related to the warmer than normal winter weather in 2012, as compared to the winter of 2011.
Purchased Power, Fuel and Transmission increased in 2012, as compared to 2011, due primarily to the following:
| | | |
| | 2012 Increase/(Decrease)
|
(Millions of Dollars)
| Compared to 2011
|
The addition of NSTAR's operations
| $
| 640.0
|
Lower GSC supply costs, partially offset by higher CfD costs at CL&P
| | (124.3)
|
Lower natural gas costs and lower sales at Yankee Gas
| | (45.4)
|
Lower purchased transmission costs and lower Basic Service costs at WMECO
| | (25.4)
|
Lower purchased power costs, partially offset by higher transmission costs at PSNH
| | (8.6)
|
All other items
| | (9.8)
|
| | $
| 426.5
|
Operations and Maintenanceincreased in 2012, as compared to 2011, due primarily to the addition of NSTAR's operations, which included operating expenses of $320.8 million and maintenance expense of $50.4 million. Excluding the impact of NSTAR's operations, Operations and Maintenance increased due primarily to:
·
Higher NU parent and other companies' expenses ($70.1 million) that were due primarily to the increase in costs related to the completion of NU’s merger with NSTAR ($55.9 million) and higher costs at NU’s unregulated contracting business related to an increased level of work in 2012 ($16.3 million).
·
The establishment of a reserve related to major storm restoration costs ($40 million) at CL&P and bill credits to customers at CL&P and WMECO ($25 million and $3 million, respectively)volumes as a result of the Connecticutcooler summer weather in 2014, and Massachusetts settlement agreements. In addition, there were higher electric distribution business expenses ($31.6 million) mainly as a result of general and administrative expenses primarily related to higher pension costs.
Partially offsetting these increases was the absence in 20122014 of the storm fund reserve establishedregulatory interest income on stranded cost deferrals in 2011 to provide bill credits to residential customers as a result of the October 2011 snowstorm and to provide contributions to certain Connecticut charitable organizations ($30 million) at CL&P, a decrease in the amortization of the regulatory deferral allowed in the 2010 rate case decision ($21.4 million) at CL&P and lower maintenance costs at PSNH’s generation business due to less planned outage maintenance in 2012 ($17.8 million).2013.
DepreciationOur transmission segment earnings increased $8.4 million in 2012,2014, as compared to 2011, due primarily to the addition of NSTAR's utility plant balances ($148.4 million) and an increase as a result of the consolidation of CYAPC and YAEC ($40.3 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 decreased in 2012, as compared to 2011,2013, due primarily to a decrease in EStransmission segment state income tax expense and TCAM amortization at PSNH ($46.9 million and $20.2 million, respectively), anda higher CTA transition costs ($21.5 million) and lower CTA revenues ($46.3 million) at CL&P. Partially offsetting these decreases was an increase related to the addition of NSTAR's operations ($87.5 million), lower SBC costs ($7.6 million) and higher retail SBC revenues ($22.5 million) at CL&P, and an increase in SCRC amortization at PSNH ($13.5 million).
Amortization of RRBs increased in 2012, as compared to 2011, due primarily to the addition of NSTAR Electric’s amortization ($67.7 million).
55
Energy Efficiency Programs increased in 2012, as compared to 2011, due primarily to the addition of NSTAR's operations ($169.4 million). In addition, there was an increase in expenses at WMECO attributable to an increase in spending in accordance with DPU approved energy efficiency programs. The increase in energy efficiency spending is recovered in rates and therefore does not impact earnings.
Taxes Other Than Income Taxes increased in 2012, as compared to 2011, due primarily to the addition of NSTAR's operations ($96.4 million). In addition, there was an increase in property taxestransmission rate base as a result of an increaseincreased investment in Property, Plant and Equipmentour transmission infrastructure. These favorable impacts were partially offset by the after-tax net reserve of $22.4 million related to our regulated capital programs and an increase in the property tax rates.
| | | | | | | | | | | | |
Interest Expense | | | | | | | | | | | |
| | For the Years Ended December 31, | |
| | | | | | | | Increase/ | | | |
(Millions of Dollars) | 2012(a) | | 2011 | | (Decrease) | | Percent | |
Interest on Long-Term Debt | $ | 316.9 | | $ | 231.6 | | $ | 85.3 | | 36.8 | % |
Interest on RRBs | | 6.2 | | | 8.6 | | | (2.4) | | (27.9) | |
Other Interest | | 6.8 | | | 10.2 | | | (3.4) | | (33.3) | |
| | $ | 329.9 | | $ | 250.4 | | $ | 79.5 | | 31.7 | % |
(a) The 2012 results include the operations of NSTAR beginning April 10, 2012.
Interest Expense increased in 2012,2014 FERC ROE orders, as compared to 2011, due primarilythe $14.3 million after-tax reserve related to the addition of NSTAR's operations ($70.6 million). The additional increase2013 FERC ALJ initial decision in Interest on Long-Term Debt was a result of the $260FERC base ROE complaints.
Our natural gas distribution segment earnings increased $11.4 million in new long-term debt issuances in September 2011 and higher short-term borrowings resulting in higher interest expense.
Other Income, Net decreased in 2012,2014, as compared to 2011, due primarily to lower AFUDC related to equity funds at PSNH as the Clean Air Project was placed into service in September 2011, partially offset by net gains on the NU supplemental benefit trust in 2012, compared to net losses in 2011.
| | | | | | | | | | | | |
Income Tax Expense | | | | | | | | | | | |
| | For the Years Ended December 31, | |
(Millions of Dollars) | 2012(a) | | 2011 | | Increase | | Percent | |
Income Tax Expense | $ | 274.9 | | $ | 171.0 | | $ | 103.9 | | 60.8 | % |
(a) The 2012 results include the operations of NSTAR beginning April 10, 2012.
Income Tax Expense increased in 2012, as compared to 2011,2013, due primarily to higher pre-taxfirm natural gas sales volumes and peak demand revenues resulting from colder weather in the first quarter of 2014 and additional natural gas heating customers.
ES parent and other companies, which include our unregulated businesses, had a net loss of $10.6 million in 2014, compared with earnings ($141.4 million), lessof $11.1 million in 2013. Excluding the impact of integration costs, ES parent and other companies earned $11.5 million in 2014, compared with $24.9 million in 2013. The earnings decrease in 2014 was due primarily to a higher effective tax rate.
LIQUIDITY
Cash flows provided by operating activities totaled $1.64 billion in 2014, compared with $1.66 billion in 2013. The 2014 operating cash flows were favorably impacted by approximately $132 million in DOE Damages proceeds resulting from the spent nuclear fuel litigation received by CL&P, NSTAR Electric, PSNH and WMECO from the Yankee Companies, the absence of 2013 cash disbursements for major storm restoration costs, the decrease of approximately $130 million in Pension and PBOP Plan cash contributions and changes in the timing of working capital items. These favorable adjustments for prior year’s taxes ($21.3 million) and lower items that directly impact our tax return as a result of regulatory actions (flow-through items) ($3.4 million), partiallyimpacts were more than offset by Connecticuthigher income tax payments in 2014 and Massachusetts settlement agreement impacts ($41 million)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 merger impacts ($19.9 million).Contingencies – Contractual Obligations – Yankee Companies," in this combined Annual Report on Form 10-K.
5649
RESULTS OF OPERATIONS – THE CONNECTICUT LIGHT AND POWER COMPANY
The following provides the amounts and variances in operating revenues and expense line items forin the statements of income for CL&P for the years ended December 31, 2015, 2014, and 2013 included in this Annual Report on Form 10-K for the years ended December 31, 2013, 2012, and 2011:10-K:
Comparison of 20132015 to 20122014:
| | | | | | | | | | | | | |
| | | 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 | % |
| | | | | | | | | | | | | |
| | | For the Years Ended December 31, | |
| | | | | | | | | Increase/ | | | |
(Millions of Dollars) | 2015 | 2014 | (Decrease) | Percent | |
Operating Revenues | $ | 2,802.7 | | $ | 2,692.6 | | $ | 110.1 | | 4.1 | % |
Operating Expenses: | | | | | | | | | | | |
| Purchased Power and Transmission | | 1,054.3 | | | 982.9 | | | 71.4 | | 7.3 | |
| Operations and Maintenance | | 487.3 | | | 494.6 | | | (7.3) | | (1.5) | |
| Depreciation | | 215.3 | | | 188.8 | | | 26.5 | | 14.0 | |
| Amortization of Regulatory Assets, Net | | 12.3 | | | 59.3 | | | (47.0) | | (79.3) | |
| Energy Efficiency Programs | | 153.7 | | | 156.3 | | | (2.6) | | (1.7) | |
| Taxes Other Than Income Taxes | | 268.7 | | | 255.4 | | | 13.3 | | 5.2 | |
| | Total Operating Expenses | | 2,191.6 | | | 2,137.3 | | | 54.3 | | 2.5 | |
Operating Income | | 611.1 | | | 555.3 | | | 55.8 | | 10.0 | |
Interest Expense | | 145.8 | | | 147.4 | | | (1.6) | | (1.1) | |
Other Income, Net | | 11.5 | | | 13.4 | | | (1.9) | | (14.2) | |
Income Before Income Tax Expense | | 476.8 | | | 421.3 | | | 55.5 | | 13.2 | |
Income Tax Expense | | 177.4 | | | 133.5 | | | 43.9 | | 32.9 | |
Net Income | $ | 299.4 | | $ | 287.8 | | $ | 11.6 | | 4.0 | % |
| | | | | | | | | | | | | |
Operating Revenues | | | | | | | | | | | |
CL&P's retail sales volumes were as follows: | | | | | | | | | | | |
| | | For the Years Ended December 31, | |
| 2015 | | 2014 | | Increase | | Percent | |
Retail Sales Volumes in GWh | | 22,071 | | | 22,046 | | | 25 | | 0.1 | % |
Operating Revenues
CL&P’s&P's Operating Revenues, which consist of base distribution revenues and tracked revenues further described below, increased by $110.1 million in 2013, asthe aggregate in 2015 compared to 2012, due primarily to:2014.
·Base distribution revenues: Base distribution revenues increased $136.3 million due to a base distribution rate increase effective December 1, 2014. In addition, CL&P recognized $19.9 million in Operating Revenues due to the PURA-approved settlement agreement regarding ADIT. The $19.9 million represents the revenue requirement from the settlement agreement's rate increase through December 31, 2015, and is being collected from customers in rates over a 24-month period beginning December 1, 2015.
A $15.8 million increase in transmission
Effective December 1, 2014, CL&P’s distribution revenues reflectingwere decoupled from its sales volumes. As a result, CL&P no longer earns LBR related to its energy efficiency programs. The revenue decoupling mechanism permits recovery of highera base amount of distribution revenues ($1.059 billion annually effective December 1, 2014) and breaks the relationship between sales volumes and revenues recognized. Revenue decoupling mechanisms result in the recovery of our approved base distribution revenue requirements. Therefore, changes in sales volumes had no impact on the level of base distribution revenue realized in 2015 and prospectively.
Tracked revenues: Tracked revenues consist of certain costs that are recovered from customers in rates through PURA-approved cost tracking mechanisms and therefore have no impact on earnings. Costs recovered through cost tracking mechanisms include energy supply procurement and other energy-related costs, retail transmission expensescharges, energy efficiency program costs and continuing transmission infrastructure investments. The increase wasrestructuring and stranded cost recovery revenues. Tracked distribution revenues decreased primarily as a result of a decrease in the federally mandated congestion charge primarily driven by refunds in 2015 for a prior year overrecovery ($103.9 million) and a decrease in competitive transition assessment charges ($17 million), partially offset by the establishment of a reserve related to the FERC ALJ initial decision in the third quarter of 2013.
·
A $13.5 millionan increase in base distribution revenues reflecting a 1.3 percentenergy supply costs ($51.1 million) driven by increased average retail rates, and an increase in retail sales. This increase wastransmission charges ($22.7 million).
Transmission revenues increased $5.8 million due primarily to the colder winter weather experiencedresult of lower reserves associated with the FERC ROE complaint proceedings recorded in early2015 as compared to 2014, and late 2013.
·
The remaining $5.6 million increase was due primarily to higher collections of costs through reconciling cost mechanisms. These revenues are fully reconciled to the related costs. Therefore this increaserevenue requirements associated with ongoing investments in revenues had no impact on earnings. our transmission infrastructure.
Purchased Power and Transmission expense includes costs associated with purchasing electricity on behalf of CL&P's customers. These energy supply costs are recovered from customers in PURA-approved cost tracking mechanisms, which have no impact on earnings (tracked costs). Purchased Power and Transmission increased in 2013,2015, as compared to 2012,2014, due primarily to the following:
| | |
| 2013 Increase/(Decrease)
|
(Millions of Dollars) | Compared to 2012Increase/(Decrease)
|
Purchased Power Costs | $ | 54.6 |
Transmission Costs | $
| 45.8
|
Deferred Fuel Costs
| | 28.7
|
GSC Supply Costs
| | (44.2)
|
Purchased Power Contracts
| | (12.1)
|
CfD Costs
| | (7.3)17.8
|
Other | | 3.7 (1.0)
|
Total Purchased Power and Transmission | $ | 14.671.4
|
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
50
suppliers. The increase in purchased power was due primarily to higher prices associated with the procurement of energy supply related to standard offer from third party suppliers. The increase in transmission costs was primarily the result of an increasehigher Local Network Service (LNS) expenses, which are included 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.cost deferral.
Operations and Maintenanceexpense includes tracked costs and costs that are part of base distribution rates with changes impacting earnings (non-tracked costs). Operations and Maintenance decreased in 2013,2015, as compared to 2012, due2014, driven by an $11.1 million decrease in non-tracked costs, which was primarily attributable 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 wereemployee-related expenses, partially offset by an increase in distribution routine maintenance and storm-relatedcosts ($7.4 million).
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higher bad debt expense. Tracked costs, which have no earnings impact, increased $3.8 million, which was primarily attributable to higher tracked bad debt expense, partially offset by lower employee-related expenses.
Depreciation increased in 2013,2015, as compared to 2012,2014, due primarily to an increase in depreciation rates as a result of the distribution rate case decision that was effective December 1, 2014 and higher utility plant balances resulting from completed construction projects placed into service.in service balances.
Amortization of Regulatory Assets, Netdecreased in 2013,2015, as compared to 2012,2014, due primarily to a lower net SBCdecrease in the deferral of energy supply and energy-related costs that can fluctuate from period to period based on the timing of costs incurred and related rate changes to recover these costs ($108 million decrease in 2015 compared to 2014), partially offset by a higher net CTA deferral. SBC revenues were $23an increase in storm cost recovery and other cost recovery approved and included in distribution rates effective December 1, 2014 ($61 million lowerincrease in 2013,2015 compared to 2014). Fluctuations in energy supply and energy-related costs, which are the primary drivers in amortization, are recovered from customers in rates and have no impact on earnings.
Energy Efficiency Programs, which are tracked costs,decreased in 2015, as compared to 2012, partially offset by higher hardship program2014, due primarily to a decrease in the deferral, which reflects the actual costs of $6.6 million in 2013. CTA revenues were $13.9 million higher in 2013, asenergy efficiency programs compared to 2012,estimated amounts billed to customers. CL&P is allowed to recover its costs for various state energy policy initiatives 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.expanded energy efficiency programs.
Taxes Other Than Income Taxesincreased in 2013,2015, as compared to 2012,2014, due primarily to an increase in property taxes as a result of both an increase in Property, Plantutility plant balances and Equipment and an increase in the property tax ratesrates.
Other Income, Netdecreased in 2015, as compared to 2014, due primarily to the absence in 2015 of a gain on the sale of land recorded in 2014 ($11.54.5 million). In addition, there was an increase in the Connecticut gross earnings tax attributable to an increase in gross earnings, partially offset by higher equity AFUDC amounts ($7.62.3 million).
InterestIncome Tax Expenseincreased $0.5 million in 2013,2015, 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 Incomeincreased $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 2012,2014, due primarily to higher pre-tax earnings ($17.119.4 million), the absence in 2013 ofhigher state income taxes, the impact of costs recognizedadjusting estimated tax expense to what was filed on our tax return (provision to return), the lower tax benefit in 2015 compared to 2014 from a change in tax reserves ($17.3 million), and higher items that impact our tax rate as a result of the Connecticut merger settlement agreementregulatory treatment (flow-through items) ($26.6 million), and higher state taxes ($5.7 million), partially offset by various other items ($2.17.2 million).
58
Comparison of 2012 to 2011:
| | | | | | | | | | | | | | | |
| | | Operating Revenues and Expenses | |
| For the Years Ended December 31, | |
| | | | | Increase/ | | | |
(Millions of Dollars) | 2012 | | 2011 | | (Decrease) | | Percent | |
Operating Revenues | $ | 2,407.4 | | $ | 2,548.4 | | $ | (141.0) | | (5.5) | % |
Operating Expenses: | | | | | | | | | | | |
| Purchased Power and Transmission | | 858.2 | | | 982.5 | | | (124.3) | | (12.7) | |
| Operations and Maintenance | | 635.7 | | | 580.7 | | | 55.0 | | 9.5 | |
| Depreciation | | 166.9 | | | 157.8 | | | 9.1 | | 5.8 | |
| Amortization of Regulatory Assets, Net | | 14.4 | | | 61.0 | | | (46.6) | | (76.4) | |
| Energy Efficiency Programs | | 89.3 | | | 90.3 | | | (1.0) | | (1.1) | |
| Taxes Other Than Income Taxes | | 215.9 | | | 212.9 | | | 3.0 | | 1.4 | |
| | Total Operating Expenses | | 1,980.4 | | | 2,085.2 | | | (104.8) | | (5.0) | |
Operating Income | $ | 427.0 | | $ | 463.2 | | $ | (36.2) | | (7.8) | % |
| | | | | | | | | |
Operating Revenues | | | | | | | | |
CL&P's retail sales were as follows: |
| | For the Years Ended December 31, | |
| | 2012 | | 2011 | | Decrease | | Percent | |
Retail Sales in GWh | 22,109 | | 22,315 | | (206) | | (0.9) | % |
CL&P's Operating Revenues decreased in 2012, as compared to 2011, due primarily to:
·
A $133.6 million decrease in distribution revenues related to the portions that are included in PURA approved tracking mechanisms that recover certain incurred costs and do not impact earnings. The tracking mechanisms allow for rates to be changed periodically with overcollections refunded to customers or undercollections recovered from customers in future periods. The tracked distribution revenues decreased due primarily to lower GSC and FMCC supply-related revenues ($150.8 million), lower CTA revenues ($46.3 million), lower wholesale revenues ($33.5 million), and lower retail transmission revenues ($4.3 million). The lower GSC and FMCC supply-related revenues were due primarily to lower customer rates resulting from lower average supply prices and lower sales related to additional customer migration to third party electric suppliers in 2012. Partially offsetting these decreases were higher FMCC delivery-related revenues ($82.4 million) and higher retail SBC revenues ($22.5 million).
Partially offset by:
·
A $7.6 million increase in the portion of distribution revenues that impacts earnings in 2012, compared to 2011, due primarily toregulatory incentives of $11.5 million and C&LM incentives of$6.2 million, partially offset by lower sales volume related to warmer than normal winter weather in 2012, as compared to the winter of 2011.
·
A $7.2 million increase in transmission revenues resulting from an increased level of investment in transmission infrastructure and the recovery of higher overall expenses, which are subject to tracking mechanisms or processes (tracked) and result in a related increase in revenues. The increase in expenses is directly related to the increase in transmission plant, including costs associated with higher property taxes, depreciation and operation and maintenance expenses.
Purchased Power and Transmission decreased in 2012, as compared to 2011, due primarily to the following:
| | |
| 2012 Increase/(Decrease)
|
(Millions of Dollars)
| Compared to 2011
|
GSC Supply Costs
| $
| (112.0)
|
Deferred Fuel Costs
| | (33.4)
|
Transmission Costs
| | (26.8)
|
Purchased Power Contracts
| | (19.4)
|
CfD Costs
| | 70.7
|
Other
| | (3.4)
|
| $
| (124.3)
|
The decrease in GSC supply costs was due to lower average supply prices and lower sales. The lower sales were due primarily to additional customer migration to third party electric suppliers. These GSC supply costs 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 increased in 2012, as compared to 2011, due primarily to the establishment of a reserve related to major storm restoration costs ($40 million) and a bill credit to customers ($25 million) in the second quarter of 2012 as a result of the Connecticut settlement agreement. In addition, there were higher distribution business expenses as a result of higher general and administrative expenses primarily related to an increase in pension costs($20.2 million) and higher routine distribution maintenance ($19.4 million). There were also higher distribution costs related to customer Energy Independence Act incentives, which are tracked
59
and fully recoverable through tracking mechanisms ($6.5 million). Partially offsetting these increases was the absence in 2012 of the storm fund reserve established in 2011 to provide bill credits to residential customers as a result of the October 2011 snowstorm ($30 million) and a decrease in the amortization of the regulatory deferral allowed in the 2010 rate case decision ($21.4 million).
Depreciation increased in 2012, as compared to 2011, due primarily to higher utility plant balances resulting from completed construction projects placed into service.
Amortization of Regulatory Assets, Net decreased in 2012, as compared to 2011, due primarily to higher CTA transition costs ($21.5 million) and lower CTA revenues ($46.3 million). Partially offsetting these impacts were lower SBC costs ($7.6 million) and higher retail SBC revenues ($22.5 million).
| | | | | | | | | | | | |
Interest Expense | | | | | | | | | | | |
| | For the Years Ended December 31, | |
| | | | | | | | Increase/ | | | |
(Millions of Dollars) | 2012 | | 2011 | | (Decrease) | | Percent | |
Interest on Long-Term Debt | $ | 124.9 | | $ | 131.9 | | $ | (7.0) | | (5.3) | % |
Other Interest | | 8.2 | | | 0.8 | | | 7.4 | | (a) | |
| | $ | 133.1 | | $ | 132.7 | | $ | 0.4 | | 0.3 | % |
(a) Percent greater than 100 percent not shown since it is not meaningful.
Interest on Long-Term Debt decreased in 2012, as compared to 2011, due primarily to the refinancing of the PCRBs at a lower interest rate in October 2011. Other Interest increased in 2012, as compared to 2011, due primarily to the absence of tax-related benefits recognized in 2011 and an increase in short-term borrowings resulting in higher interest expense.
Income Tax Expense
| | | | | | | | | | | |
| For the Years Ended December 31, | |
(Millions of Dollars) | 2012 | | 2011 | | Increase | | Percent | |
Income Tax Expense | $ | 94.4 | | $ | 90.0 | | $ | 4.4 | | 4.9 | % |
Income Tax Expense increased in 2012, as compared to 2011, due primarily to less favorable adjustments for prior year’s taxes ($22.4 million), an increase to pre-tax earnings ($13.8 million), partially offset by Connecticut settlement agreement impacts ($26.6 million), and lower state tax and other impacts ($5.2 million).
EARNINGS SUMMARY
| | | | | | |
| For the Years Ended December 31, |
(Millions of Dollars) | | 2013 | | | 2012 |
Income Before Merger-Related Costs | $ | 279.4 | | $ | 248.1 |
Merger-Related Costs (after-tax)(1) | | - | | | (38.4) |
Net Income | $ | 279.4 | | $ | 209.7 |
(1)
The 2012 after-tax merger-related costs consisted of charges relatedCL&P's earnings increased $11.6 million in 2015, as compared to the Connecticut merger settlement agreement, including $14.8 million ($25 million pre-tax) for customer bill credits and $23.6 million ($40 million pre-tax) whereby CL&P agreed2014, driven by higher distribution revenues due primarily to forego recovery of deferred storm costs associated with Tropical Storm Irene and the October 2011 snowstorm.
Excluding the impact of merger-related costs, CL&P’sthe December 1, 2014 base distribution rate increase and the PURA-approved settlement agreement. In addition, earnings increased $31.3 million in 2013, as compareddue to 2012, due primarily to lower overall operations and maintenance costs, which were primarily attributable to lower employee-related expenses, and higher retail electric sales due primarilylower reserves associated with the FERC ROE complaint proceedings recorded in 2015 compared to colder weather in the first and fourth quarters of 2013. Partially offsetting these2014. These favorable earnings impacts waswere partially offset by higher income tax expense as a result of lower tax benefits available for utilization in 2015, higher property taxes and the establishmentabsence of a $7.7 million after-tax reserve related togain on the August 2013 FERC ALJ initial decision, higher depreciation and property tax expense.sale of land recorded in 2014.
LIQUIDITY
In 2015, CL&P had cash flows provided by operating activities of $495.3$298.3 million, compared with $612.4 million in 2013, compared with $211.9 million2014. The decrease 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 benefitted 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.
CL&P had cash flows provided by operating activities of $211.9 million in 2012, compared with cash flows provided by operating activities of $513.3 million in 2011. The reduced cash flows werewas due primarily to the $223.1approximate $245 million in payments made to fully satisfy the pre-1983 spent nuclear fuel obligation with the DOE. Also contributing to the decrease in operating cash flows were DOE Damages proceeds received from the Yankee Companies of cash disbursements for storm restoration costs primarily associated with Tropical Storm Irene, the October 2011 snowstorm, and Hurricane Sandy made$2.3 million in 2012, as2015, compared to approximately $132$68.6 million in 2011, the $27 million in bill credits provided to residential customers in February 2012
602014.
relatedIn late 2015, CL&P made a payment of $244.6 million to fully satisfy its obligation with the October 2011 snowstorm,DOE, which was classified as long-term debt on the $25 million in bill credits to customersbalance sheet as of December 31, 2014, for costs associated with the Connecticut merger settlement agreement,disposal of spent nuclear fuel and changeshigh-level radioactive waste for all periods prior to 1983 from its previous ownership interest in traditional working capital amounts principallythe Millstone nuclear power station. CL&P divested its ownership interest in Millstone in 2001. This payment included accumulated interest of $178 million. CL&P funded its payment with the issuance of debt.
On December 18, 2015, the "Protecting Americans from Tax Hikes" Act became law, which extended the accelerated deduction of depreciation to businesses from 2015 through 2019. This extended stimulus provides CL&P with cash flow benefits in 2016 of approximately $105 million due to the changesa refund of taxes paid in the timing of2015 and lower expected tax payments of accounts payable and accrued liabilities. In addition, CL&P had lower recovery of its deferred operation and maintenance costs of $23.1 million in 2012, as compared to 2011, a negative cash flow impact of $38.9 million resulting from changes in reserves for transmission refunds in 2012, as compared to 2011, and a decrease in income tax refunds of $14.6 million in 2012, as compared to 2011.2016.
Investments in Property, Plant and Equipment on the accompanying statements of cash flows do not include amounts incurred on capital projects but not yet paid, cost of removal, AFUDC related to equity funds, and the capitalized portions of pension expense. CL&P’s&P's investments totaled $434.9$523.8 million in 2013,2015, compared with $449.1$515.7 million in 2012.2014.
On January 15, 2013,October 26, 2015, ES parent and certain of its subsidiaries, including CL&P, amended and restated their joint $1.45 billion revolving credit facility and the termination date was extended to September 4, 2020. The revolving credit facility serves to backstop ES parent's $1.45 billion commercial paper program. The commercial paper program allows ES parent to issue commercial paper as a form of short-term debt with
51
intercompany loans to certain subsidiaries, including CL&P. As of December 31, 2015 and 2014, there were intercompany loans from ES parent of $277.4 million and $133.4 million, respectively, to CL&P.
On May 20, 2015 and December 1, 2015, CL&P issued $400$300 million and $50 million, respectively, of 2.54.15 percent 20132015 Series A First and Refunding Mortgage Bonds due to mature in 2023.2045. The proceeds, net of issuance costs, were used to payrepay short-term borrowings.
On April 1, 2015, CL&P repaid at maturity the $100 million 5.00 percent 2005 Series A First and Refunding Mortgage Bonds using short-term borrowings outstanding underand also redeemed the CL&P credit agreement of $89$62 million and intercompany loans related to our commercial paper program of $305.8 million. On September 3, 2013, CL&P redeemed at par $125 million of 1.251996A Series 1.55 percent Series B 2011 PCRBs whichthat were subject to mandatory tender, for purchase, using short-term debt. short term borrowings.
On July 31, 2013, the FERC granted authorization allowing CL&P to incur total short-term borrowings up to a maximum of $600 million, effective January 1, 2014 through December 31, 2015.
On September 6, 2013, NU parent and certain of its subsidiaries, including CL&P, amended their joint five-year $1.15 billion revolving credit facility, dated July 25, 2012, by increasing the aggregate principal amount available thereunder by $300 million to $1.45 billion, extending the expiration date from July 25, 2017 to September 6, 2018, and increasing CL&P's borrowing sub-limit from $300 million to $600 million. Simultaneously, effective September 6, 2013, the CL&P $300 million revolving credit facility was terminated. The revolving credit facility is to be used primarily to backstop the commercial paper program at NU. 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, 2013, CL&P had an intercompany loan payable to NU parent of $287.3 million related to our commercial paper program.
Other financingFinancing activities in 20132015 included $152$196 million in common stock dividends paid to NU parent and a $40 million capital contribution from NUES parent.
CL&P uses its available capital resourcesComparison of 2014 to fund its construction expenditures, meet debt requirements, pay operating costs, including storm-related costs, pay dividends and fund other corporate obligations. The current growth in CL&P’s transmission construction expenditures utilizes a significant amount of cash for projects that have a long-term return on investment and recovery period. In addition, CL&P recovers its distribution construction expenditures as the related project costs are depreciated over the life of the assets. As well, the future recovery of its deferred major storm costs will take place over an extended period of time. 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 $398 million as of December 31, 2013.2013:
As of December 31, 2013, $150 million of CL&P's obligations classified as current liabilities relates to long-term debt that will be paid in the next 12 months. CL&P, 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. CL&P will reduce its 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 CL&P’s credit rating and profile. Management expects the future operating cash flows of CL&P, along with the access to financial markets, will be sufficient to meet any future operating requirements and capital investment forecasted opportunities.
61
| | | | | | | | | | | | | | |
| | | 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) | % |
RESULTS OF OPERATIONS – NSTAR ELECTRIC COMPANY AND SUBSIDIARY
The following table provides the amounts and variances in operating revenues and expense line items for the consolidated statements of income for NSTAR Electric included in this Annual Report on Form 10-K for the years ended December 31, 2013 and 2012:
| | | | | | | | | | | | | |
| | | Operating Revenues and Expenses | |
| For the Years Ended December 31, | |
(Millions of Dollars) | 2013 | | 2012 | | Increase/ | | Percent | |
(Decrease) | |
Operating Revenues | $ | 2,493.5 | | $ | 2,301.0 | | $ | 192.5 | | 8.4 | % |
Operating Expenses: | | | | | | | | | | | |
| Purchased Power and Transmission | | 849.1 | | | 788.3 | | | 60.8 | | 7.7 | |
| Operations and Maintenance | | 376.4 | | | 431.8 | | | (55.4) | | (12.8) | |
| Depreciation | | 180.3 | | | 171.1 | | | 9.2 | | 5.4 | |
| Amortization of Regulatory Assets, Net | | 230.1 | | | 117.7 | | | 112.4 | | 95.5 | |
| Amortization of Rate Reduction Bonds | | 15.1 | | | 90.3 | | | (75.2) | | (83.3) | |
| Energy Efficiency Programs | | 206.5 | | | 201.2 | | | 5.3 | | 2.6 | |
| Taxes Other Than Income Taxes | | 127.8 | | | 119.2 | | | 8.6 | | 7.2 | |
| | Total Operating Expenses | | 1,985.3 | | | 1,919.6 | | | 65.7 | | 3.4 | |
Operating Income | $ | 508.2 | | $ | 381.4 | | $ | 126.8 | | 33.2 | % |
| | | | | | | | | | | | |
Operating Revenues | |
NSTAR Electric's retail sales were as follows: | | | | | | | | | | | |
| | | | | | | | | | | | |
| | For the Years Ended December 31, | |
| 2013 | | 2012 | | Increase | | Percent | |
Retail Sales in GWh | | 21,306 | | | 21,209 | | | 97 | | 0.5 | % |
NSTAR Electric'sCL&P's Operating Revenues increased $250.3 million in 2013,2014 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 2012, due primarily to:
·
A $160.1the $12.8 million increase related to a higher level of collections of energy supply and company-sponsored energy efficiency programs. These revenues are fully reconciled to their respective costs. Therefore this increasereserve recorded in revenues had no material impact on earnings.
·
A $24.7 million increase in transmission revenues reflecting recovery of higher regional transmission expenses and continuing transmission infrastructure investments, offset by the establishment of a reserve related to2013 for the FERC ALJ initial decision in the third quarter of 2013.FERC base ROE complaints.
·
A $7.7Base distribution revenues increased $9.1 million increase in 2014 compared to 2013, which was primarily attributable to the impact of the December 1, 2014 base distribution revenues reflecting a 0.5 percentrate 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 retail sales. The increase2013. Through November 30, 2014, CL&P was permitted to bill customers for LBR related to reductions in sales volume was due primarily toas a greater numberresult of cooling degree days during the summer of 2013energy efficiency, and heating degree dayseffective December 1, 2014, fluctuations in early and late 2013. This favorableretail electric sales volumes do not impact was partially offset by reductionsearnings due to NSTAR Electric’sthe PURA-approved revenue decoupling mechanism as a result of CL&P's base distribution rate case. The revenue decoupling mechanism provides a base amount of distribution revenues ($1.059 billion on an annual basis) that effectively breaks the relationship between revenues and customer fundedelectricity usage. The revenue decoupling mechanism is designed to allow CL&P to encourage energy efficiency programs.for its customers without negatively impacting its revenues.
Purchased Powerand 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 2013,2014, as compared to 2012,2013, due primarily to the following:
| | |
| 2013 Increase/(Decrease)
|
(Millions of Dollars) | Compared to 2012Increase/(Decrease)
|
Purchased Power Costs | $ | 169.7 |
Transmission Costs | $
| 37.7 (50.8)
|
Basic Service CostsOther
| | 20.2 (8.8)
|
Total Purchased Power Contracts | | 9.5
|
Deferred Fuel Costs
| | (6.6)
|
and Transmission | $ | 60.8110.1
|
52
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 transmission costs was due primarily to higher RNS costs. The increase in basic service costspurchased power was due primarily to higher average energy supply prices. The increase in purchased power contracts was due primarily to higher congestion charges.prices and increased standard offer load as a result of customers returning from third party suppliers. The decrease in deferred fueltransmission costs was due primarily to higher average energy supply prices, asthe result of a decrease in the retail transmission cost deferral, which reflects the actual costs of transmission service compared to the prices projected when basic service rates were set. Purchased Power and Transmission costs are included in regulatory-approved tracking mechanisms and do not impact earnings.estimated amounts billed to customers.
Operations and Maintenanceexpense includes tracked costs and costs that are part of base distribution rates with changes impacting earnings (non-tracked costs). Operations and Maintenance decreased in 2013,2014, as compared to 2012, due primarily to the absence of several adjustments recorded in the first quarter of 2012, the majority of which were recognized for changes in accounting estimates ($46.7 million), the absence of2013, driven by a bill credit to customers ($15 million) as a result of the Massachusetts merger settlement agreement, and an overall$38.4 million reduction in other operatingnon-tracked costs, ($2.1 million). These positive factors were partially offset by higher PAM-related amortizations ($4.1 million) as well as timing of maintenance ($4.3 million).
Depreciationincreased in 2013, as compared to 2012, due primarily to higher utility plant balances resulting from completed construction projects placed into service.
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Amortization of Regulatory Assets, Net increased in 2013, as compared to 2012, due primarily to an increase in the recovery of previously deferred transition costs.
Amortization of Rate Reduction Bondsdecreased in 2013, as compared to 2012, due to the maturity of the RRBs in March 2013.
Energy Efficiency Programs increased in 2013, as compared to 2012, due primarily to an increase in energy efficiency costs in accordance with the three-year program guidelines established by the DPU. All costs are fully recovered through DPU-approved tracking mechanisms and therefore do not impact earnings.
Taxes Other Than Income Taxes increased in 2013, as compared to 2012, due to higher municipal property taxes as a result of an increase in Property, Plant and Equipment.
Interest Expense increased $0.3 million in 2013, as compared to 2012, due primarily to lower regulatory interest income primarily from deferred transition costs, partially offset by lower average long-term bond rates.
Income Tax Expense
| | | | | | | | | | | | |
| | For the Years Ended December 31, | |
(Millions of Dollars) | 2013 | | 2012 | | Increase | | Percent | |
Income Tax Expense | $ | 172.9 | | $ | 124.0 | | $ | 48.9 | | 39.4 | % |
Income Tax Expense increased in 2013, as compared to 2012, due primarily to higher pre-tax earnings ($44 million) and the absence in 2013 of the impact of costs recognized as a result of the Massachusetts merger settlement agreement ($5.9 million), partially offset by various other impacts ($1 million).
EARNINGS SUMMARY
| | | | | |
| For the Years Ended December 31, |
(Millions of Dollars) | | 2013 | | | 2012 |
Income Before Merger-Related Costs | $ | 268.5 | | $ | 201.1 |
Merger-Related Costs (after-tax)(1) | | - | | | (10.9) |
Net Income | $ | 268.5 | | $ | 190.2 |
(1)
The 2012 after-tax merger-related costs consisted of a $15 million pre-tax charge for customer bill credits related to the Massachusetts merger settlement agreement and a $2.8 million pre-tax charge related to compensation costs.
Excluding the impact of merger-related costs, NSTAR Electric’s earnings increased $67.4 million in 2013, as compared to 2012, due primarily to lower overall operations and maintenance costs and higher retail electric sales due primarily to colder weather in the first and fourth quarters in 2013. Partially offsetting these factorswhich was higher depreciation and property tax expense.
CAPITAL EXPENDITURES
A summary of capital expenditures, including amounts incurred but not paid, cost of removal, AFUDC, and the capitalized portions of pension expense, is as follows:
| | | | | | | | |
| For the Years Ended December 31, |
(Millions of Dollars) | | 2013 | | | 2012 | | | 2011 |
Transmission | $ | 220.8 | | $ | 192.1 | | $ | 162.5 |
Distribution: | | | | | | | | |
Basic Business | | 98.5 | | | 64.2 | | | 58.5 |
Aging Infrastructure | | 110.6 | | | 145.8 | | | 132.8 |
Load Growth | | 53.6 | | | 21.2 | | | 19.3 |
Total Distribution | | 262.7 | | | 231.2 | | | 210.6 |
Total | $ | 483.5 | | $ | 423.3 | | $ | 373.1 |
LIQUIDITY
NSTAR Electric had cash flows provided by operating activities of $466.9 million in 2013, compared with $506.9 million in 2012 (amounts are net of RRB payments, which are included in financing activities). The decrease in operating cash flows was due primarily to a $57 million increase in Pension Plan contributions in 2013, as compared to 2012, and a $75.3 million increase in net tax payments. Partially offsetting the negative cash flow impacts was the absence in 2013 of $15 million in bill credits provided to customers in the second quarter of 2012 in connection with the Massachusetts merger settlement agreement. In addition, operating cash flows benefitted from an increase in amortization on regulatory deferrals primarily attributable to tracking mechanisms where such revenues exceededlower labor and other employee-related costs, resulting in a favorable cash flow impact.
63
RESULTS OF OPERATIONS – PUBLIC SERVICE COMPANY OF NEW HAMPSHIRE AND SUBSIDIARY
The following table provides the amountsincluding pension costs, and variances in operating revenues and expense line items for the consolidated statements of income for PSNH included in this Annual Report on Form 10-K for the years ended December 31, 2013 and 2012:
| | | | | | | | | | | | | |
| | | Operating Revenues and Expenses | |
| For the Years Ended December 31, |
(Millions of Dollars) | 2013 | | 2012 | | Increase/ | | Percent | |
(Decrease) |
Operating Revenues | $ | 935.4 | | $ | 988.0 | | $ | (52.6) | | (5.3) | % |
Operating Expenses: | | | | | | | | | | | |
| Purchased Power, Fuel and Transmission | | 269.8 | | | 319.3 | | | (49.5) | | (15.5) | |
| Operations and Maintenance | | 267.8 | | | 263.2 | | | 4.6 | | 1.7 | |
| Depreciation | | 91.6 | | | 87.6 | | | 4.0 | | 4.6 | |
| Amortization of Regulatory Liabilities, Net | | (20.4) | | | (24.1) | | | 3.7 | | 15.4 | |
| Amortization of Rate Reduction Bonds | | 19.7 | | | 56.6 | | | (36.9) | | (65.2) | |
| Energy Efficiency Programs | | 14.5 | | | 14.2 | | | 0.3 | | 2.1 | |
| Taxes Other Than Income Taxes | | 67.2 | | | 66.1 | | | 1.1 | | 1.7 | |
| | Total Operating Expenses | | 710.2 | | | 782.9 | | | (72.7) | | (9.3) | |
Operating Income | $ | 225.2 | | $ | 205.1 | | $ | 20.1 | | 9.8 | % |
| | | | | | | | | |
Operating Revenues | | | | | | | | |
PSNH's retail sales were as follows: |
| | For the Years Ended December 31, | |
| | 2013 | | 2012 | | Increase | | Percent | |
Retail Sales in GWh | 7,938 | | 7,821 | | 117 | | 1.5 | % |
PSNH's Operating Revenues decreased in 2013, as compared to 2012, due primarily to:
·
A $73.2 million decrease related to PSNH's cost recovery mechanisms. The primary reason for this decrease was the reduction of recoveries related to PSNH’s RRBs, which were fully collected during the first half of 2013.This reduction had no impact on earnings.
Partially offset by:
·
A $17.3 million increase in base distribution revenues reflecting a 1.5 percent increase in retail sales. PSNH experienced strong sales in early and late 2013 due to colder winter weather than what was experienced in 2012. Also reflected in this revenue increase was an increase of $11.9 millionrelated to NHPUC-approved distribution rate increases effective July 1, 2012 and July 1, 2013 as a result of the 2010 distribution rate case settlement.
·
A $3.3 million increase in transmission revenues reflecting recovery of higher transmission expenses and continuing transmission infrastructure investments. The increase was mostly offset by the establishment of a reserve related to the FERC ALJ initial decision in the third quarter of 2013.
Purchased Power, Fuel and Transmission decreased in 2013, as compared to 2012, due primarily to a decrease inlower storm restoration costs, related to renewable energy and a decrease in fuel costs resulting from an increase in customer migration to third party suppliers, which resulted in a decrease in load obligation. These decreases were partially offset by an increase in transmission costs resulting from higher RNS costs. Purchased Power, Fuel and Transmission costs are includedfor the implementation of a new outage restoration program that began in regulatory-approved tracking mechanisms and do not impact earnings.
Operations and Maintenance increased in 2013, as compared to 2012, due primarily to anthe second quarter of 2014. Partially offsetting this decrease was a $9.8 million increase in routine maintenancetracked costs, which have no earnings impact, that was primarily attributable to higher tracked bad debt expense and storm-related distribution overhead line costs ($11.4 million) and an increase in routine generation maintenance costs ($4.4 million). Partially offsetting these increases was the absence in 2013 of PBOP transition obligation amortization ($2.5 million), lower distribution general and administrative costs ($3 million), a decrease in RRB charges that are included in NHPUC-approved tracking mechanisms ($2.9 million), and a decrease in routineincreased transmission maintenance ($1.4 million).expenses.
Depreciationincreased in 2013,2014, as compared to 2012,2013, due primarily to higher utility plant balances resulting from completed construction projects placed into service.
Amortization of Regulatory Liabilities,Assets, Netincreased expenses in 2013,2014, as compared to 2012,2013. 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 an increaseexpanded energy conservation programs in the ES2014 as a result of 2013 legislative action. In 2013, Connecticut enacted into law Public Act 13-298, which implemented a number of recommendations, including allowing electric distribution companies to recover their costs from various state energy policy initiatives and TCAM amortization ($23.3 million and $9.2 million, respectively), partially offset by a decrease in the SCRC amortization ($27.9 million).
Amortization of Rate Reduction Bonds decreased in 2013, as compared to 2012, due to the maturity of the RRBs in May 2013.expanded energy efficiency programs.
Taxes Other Than Income Taxes increased in 2013,2014, as compared to 2012,2013, due primarily to an increase in property taxes as a result of both an increase in utility plant balances and property tax rates.
Interest Expenseincreased 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, Netdecreased in 2014, as compared to 2013, due primarily to lower unrealized gains on the assets supporting the deferred compensation plans ($6.7 million), partially offset by a gain on the sale of land ($4.5 million).
Income Tax Expense decreased in 2014, as compared to 2013, due primarily to lower state taxes, which includes the reduction in the valuation allowance for state tax positions, and various other impacts.
EARNINGS SUMMARY
CL&P's earnings increased in 2014, as compared to 2013, due primarily to a decrease in operations and maintenance costs primarily attributable to lower employee-related costs, as well as lower income tax expense due to the net reduction in the valuation allowance for state tax positions. Partially offsetting these favorable earnings impacts were lower retail electric sales volumes, higher depreciation expense, higher property tax expense, higher interest expense and the after-tax reserve recorded for the 2014 FERC ROE orders as compared to the reserve recorded in 2013 for the FERC ALJ initial decision in the FERC base ROE complaints.
LIQUIDITY
In 2014, CL&P had cash flows provided by operating activities of $612.4 million, compared with $495.3 million in 2013. The improved operating cash flows were due primarily to $68.6 million in DOE damages proceeds received in 2014 from the Yankee Companies associated with the spent nuclear fuel litigation, the absence of cash disbursements for major storm restoration costs, and the favorable cash flow impact resulting from an increase in recoveries from customers in 2014, as compared to 2013, relating to regulatory cost recovery tracking mechanisms, partially offset by higher income tax payments in 2014, as compared to 2013, and changes in working capital items.
53
RESULTS OF OPERATIONS – NSTAR ELECTRIC COMPANY AND SUBSIDIARY
The following provides the amounts and variances in operating revenues and expense line items in the statements of income for NSTAR Electric for the years ended December 31, 2015 and 2014 included in this Annual Report on Form 10-K:
| | | | | | | | | | | | | |
| | | For the Years Ended December 31, | |
| | | | | | | | | Increase/ | | | |
(Millions of Dollars) | 2015 | 2014 | (Decrease) | Percent | |
Operating Revenues | $ | 2,681.3 | | $ | 2,536.7 | | $ | 144.6 | | 5.7 | % |
Operating Expenses: | | | | | | | | | | | |
| Purchased Power and Transmission | | 1,190.2 | | | 1,122.3 | | | 67.9 | | 6.1 | |
| Operations and Maintenance | | 306.5 | | | 327.0 | | | (20.5) | | (6.3) | |
| Depreciation | | 196.8 | | | 188.7 | | | 8.1 | | 4.3 | |
| Amortization of Regulatory Liabilities, Net | | (13.0) | | | (6.3) | | | (6.7) | | (a) | |
| Energy Efficiency Programs | | 224.8 | | | 193.5 | | | 31.3 | | 16.2 | |
| Taxes Other Than Income Taxes | | 133.2 | | | 133.0 | | | 0.2 | | 0.2 | |
| | Total Operating Expenses | | 2,038.5 | | | 1,958.2 | | | 80.3 | | 4.1 | |
Operating Income | | 642.8 | | | 578.5 | | | 64.3 | | 11.1 | |
Interest Expense | | 75.4 | | | 77.9 | | | (2.5) | | (3.2) | |
Other Income, Net | | 5.1 | | | 4.5 | | | 0.6 | | 13.3 | |
Income Before Income Tax Expense | | 572.5 | | | 505.1 | | | 67.4 | | 13.3 | |
Income Tax Expense | | 228.0 | | | 202.0 | | | 26.0 | | 12.9 | |
Net Income | $ | 344.5 | | $ | 303.1 | | $ | 41.4 | | 13.7 | % |
| | | | | | | | | | | | | |
(a) Percent greater than 100 percent not shown as it is not meaningful. | |
| | | | | | | | | | | | | |
Operating Revenues | | | | | | | | | | | |
NSTAR Electric's retail sales volumes were as follows: | | | | | | | | | | | |
| | | | | | | | | | | | | |
| | | For the Years Ended December 31, | |
| 2015 | | 2014 | | Increase | | Percent | |
Retail Sales Volumes in GWh | | 21,055 | | | 20,925 | | | 130 | | 0.6 | % |
NSTAR Electric's Operating Revenues, which consist of base distribution revenues and tracked revenues further described below, increased by $144.6 million in the aggregate in 2015 compared to 2014.
Base distribution revenues: Base distribution revenues, excluding LBR, increased $6.5 million as a result of weather impacts. The impact of colder winter weather experienced in the first quarter of 2015 and warmer weather in the third quarter of 2015, partially offset by milder winter weather in the fourth quarter of 2015, all as compared to the same periods in 2014, were the primary drivers of the increase in 2015 retail electric sales volumes of 0.6 percent. In addition, NSTAR Electric is allowed to recover LBR related to reductions in sales volumes as a result of successful energy efficiency programs. NSTAR Electric recognized $20.7 million more LBR in 2015 compared to 2014.
In connection with the Comprehensive Settlement Agreement, NSTAR Electric recognized an $11 million benefit in the first quarter of 2015 associated with the recovery of LBR related to 2009 through 2011 energy efficiency programs, which was recorded as an increase to Operating Revenues. For further information, see "Regulatory Developments and Rate Matters – Massachusetts – NSTAR Electric and NSTAR Gas Comprehensive Settlement Agreement" in thisManagement's Discussion and Analysis of Financial Condition and Results of Operations.
Tracked revenues: Tracked revenues consist of certain costs that are recovered from customers in rates through DPU-approved cost tracking mechanisms and therefore have no impact on earnings. Costs recovered through cost tracking mechanisms include energy supply costs, retail transmission charges, energy efficiency program costs, net metering for distributed generation and transition cost recovery revenues. Tracked distribution revenues increased primarily as a result of an increase in energy supply costs ($116.2 million), driven by increased average retail rates, and increased cost recovery related to energy efficiency programs ($31.1 million). These increases were partially offset by decreased retail transmission charges ($80.6 million).
Transmission revenues increased by $23.9 million due primarily to higher revenue requirements associated with ongoing investments in our transmission infrastructure and the result of lower reserves associated with the FERC ROE complaint proceedings recorded in 2015 as compared to 2014.
Purchased Power and Transmissionexpense includes costs associated with purchasing electricity on behalf of NSTAR Electric's customers. These energy supply costs are recovered from customers in DPU-approved cost tracking mechanisms, which have no impact on earnings (tracked costs). Purchased Power and Transmission increased in 2015, as compared to 2014, due primarily to the following:
| | |
(Millions of Dollars) | Increase/(Decrease) |
Purchased Power Costs | $ | 133.2 |
Transmission Costs | | (65.4) |
Other | | 0.1 |
Total Purchased Power and Transmission | $ | 67.9 |
54
Included in purchased power are the costs associated with NSTAR Electric's basic service charge and deferred energy supply costs. The basic service charge recovers energy-related costs incurred as a result of providing electric generation service supply to all customers that have not migrated to third party suppliers.The increase in purchased power costs was due primarily to higher prices associated with the procurement of energy supply. The decrease in transmission costs was primarily the result of a decrease in the retail transmission cost deferral, which reflects the actual costs of transmission service compared to estimated amounts billed to customers.
Operations and Maintenanceexpense includes tracked costs and costs that are part of base distribution rates with changes impacting earnings (non-tracked costs). Operations and Maintenance decreased in 2015, as compared to 2014, driven by a $6.8 million reduction in non-tracked costs, which was primarily attributable to the resolution of the basic service bad debt adder mechanism ($24.2 million) and lower bad debt expense, partially offset by increased employee-related expenses. Tracked costs, which have no earnings impact, decreased $13.7 million, which was primarily attributable to lower employee-related expenses. As a result of the October 30, 2015 DPU order in the NSTAR Gas distribution rate case, which allows for the recovery of certain uncollectible hardship accounts receivable, NSTAR Electric recorded regulatory deferrals for costs expected to be recovered in future rates given the allowed recoveries of uncollectible hardship accounts receivable by WMECO and NSTAR Gas, which resulted in the recognition of a $10.5 million pre-tax benefit in 2015.
Depreciationincreased in 2015, as compared to 2014, due primarily to higher utility plant in service balances.
Amortization of Regulatory Liabilities, Net,reflects an $11.7 million benefit recognized in connection with the Comprehensive Settlement Agreement associated with the CPSL program filings in the first quarter of 2015, which was recorded as a reduction to amortization expense. For further information, see "Regulatory Developments and Rate Matters – Massachusetts – NSTAR Electric and NSTAR Gas Comprehensive Settlement Agreement" in thisManagement's Discussion and Analysis of Financial Condition and Results of Operations. Partially offsetting this benefit was an increase in the recovery of previously deferred tracked transition costs, which increased amortization expense, in 2015 compared to 2014. Fluctuations in these costs are recovered from customers in rates and have no impact on earnings.
Energy Efficiency Programs, which are tracked costs, increased in 2015, as compared to 2014, due primarily to an increase in energy efficiency costs incurred in accordance with the three-year program guidelines established by the DPU.
Income Tax Expense increased in 2015, as compared to 2014, due primarily to higher pre-tax earnings ($23.6 million), and higher state taxes and the impact of adjusting estimated tax expense to what was filed on our tax return (provision to return) ($2.4 million).
EARNINGS SUMMARY
NSTAR Electric's earnings increased $41.4 million in 2015, as compared to 2014, due primarily to the resolution of the basic service bad debt adder mechanism ($14.5 million), the favorable impact associated with the Comprehensive Settlement Agreement, which resolved eleven open dockets including the CPSL program filings and the recovery of LBR related to 2009 through 2011 energy efficiency programs ($13 million), the recovery of higher LBR related to 2015 energy efficiency programs, an increase in transmission earnings due primarily to a higher transmission rate base and lower reserves associated with the FERC ROE complaint proceedings recorded in 2015 compared to 2014, and higher retail sales volumes. These favorable earnings impacts were partially offset by an increase in employee-related expenses and higher depreciation expense.
LIQUIDITY
NSTAR Electric had cash flows provided by operating activities of $657 million in 2015, compared with $533 million in 2014. The improved operating cash flows were due primarily to a $110 million decrease in Pension and PBOP Plan cash contributions in 2015 compared to 2014, the $236.9 million favorable impact of receiving net income tax refunds in 2015 compared with making net income tax payments in 2014 due to the extension of the accelerated depreciation deduction. These favorable cash flow impacts were partially offset by the impact of the timing of regulatory recoveries resulting from the increase in purchased power costs and the timing of collections and payments related to our working capital items, including affiliated company receivables, accounts receivable and accounts payable. Accounts receivable increased due primarily to an increase in basic service rates effective January 1, 2015. Also offsetting the favorable impacts were DOE Damages proceeds received from the Yankee Companies of $0.8 million in 2015, compared to $30.2 million in 2014.
NSTAR Electric has a five-year $450 million revolving credit facility. On October 26, 2015, this revolving credit facility was amended and restated and the termination date was extended to September 4, 2020. This facility serves to backstop NSTAR Electric's existing $450 million commercial paper program. As of December 31, 2015 and 2014, NSTAR Electric had $62.5 million and $302 million, respectively, in short-term borrowings outstanding under its commercial paper program, leaving $387.5 million and $148 million of available borrowing capacity as of December 31, 2015 and 2014, respectively. The weighted-average interest rate on these borrowings as of December 31, 2015 and 2014 was 0.40 percent and 0.27 percent, respectively.
55
RESULTS OF OPERATIONS – PUBLIC SERVICE COMPANY OF NEW HAMPSHIRE AND SUBSIDIARY
The following provides the amounts and variances in operating revenues and expense line items in the statements of income for PSNH for the years ended December 31, 2015 and 2014 included in this Annual Report on Form 10-K:
| | | | | | | | | | | | | |
| | | For the Years Ended December 31, | |
| | | | | | | | | Increase/ | | | |
(Millions of Dollars) | 2015 | 2014 | (Decrease) | Percent | |
Operating Revenues | $ | 972.2 | | $ | 959.5 | | $ | 12.7 | | 1.3 | % |
Operating Expenses: | | | | | | | | | | | |
| Purchased Power, Fuel and Transmission | | 247.7 | | | 313.7 | | | (66.0) | | (21.0) | |
| Operations and Maintenance | | 276.5 | | | 261.9 | | | 14.6 | | 5.6 | |
| Depreciation | | 105.4 | | | 98.4 | | | 7.0 | | 7.1 | |
| Amortization of Regulatory Assets/(Liabilities), Net | | 16.3 | | | (29.6) | | | 45.9 | | (a) | |
| Energy Efficiency Programs | | 14.3 | | | 14.3 | | | - | | - | |
| Taxes Other Than Income Taxes | | 81.8 | | | 71.4 | | | 10.4 | | 14.6 | |
| | Total Operating Expenses | | 742.0 | | | 730.1 | | | 11.9 | | 1.6 | |
Operating Income | | 230.2 | | | 229.4 | | | 0.8 | | 0.3 | |
Interest Expense | | 46.0 | | | 45.4 | | | 0.6 | | 1.3 | |
Other Income, Net | | 3.3 | | | 2.0 | | | 1.3 | | 65.0 | |
Income Before Income Tax Expense | | 187.5 | | | 186.0 | | | 1.5 | | 0.8 | |
Income Tax Expense | | 73.1 | | | 72.1 | | | 1.0 | | 1.4 | |
Net Income | $ | 114.4 | | $ | 113.9 | | $ | 0.5 | | 0.4 | % |
| | | | | | | | | | | | | |
(a) Percent greater than 100 percent not shown as it is not meaningful. |
| | | | | | | | | | | | | |
Operating Revenues | | | | | | | | | | | |
PSNH's retail sales volumes were as follows: | | | | | | | | | | | |
| | | | | | | | | | | | | |
| | | For the Years Ended December 31, | |
| 2015 | | 2014 | | Increase | | Percent | |
Retail Sales Volumes in GWh | | 7,927 | | | 7,886 | | | 41 | | 0.5 | % |
PSNH's Operating Revenues, which consist of base distribution revenues and tracked revenues further described below, increased by $12.7 million in the aggregate in 2015 compared to 2014.
Base distribution revenues: Base distribution revenues increased $8.1 million as a result of a distribution rate increase effective July 1, 2015 and higher retail sales volumes driven by weather impacts. Sales volumes increased 0.5 percent in 2015, as compared to 2014, primarily related to the impact of colder winter weather experienced in the first quarter of 2015and warmer weather in the third quarter of 2015, partially offset by milder winter weather in the fourth quarter of 2015, all as compared to the same periods in 2014.
Tracked revenues:Tracked revenues consist of certain costs that are recovered from customers in rates through NHPUC-approved cost tracking mechanisms and therefore have no impact on earnings. Costs recovered through cost tracking mechanisms include energy supply costs and costs associated with the generation of electricity for customers, retail transmission charges, energy efficiency program costs and stranded cost recovery revenues. Tracked distribution revenues decreased primarily as a result of a reduction in wholesale generation revenues, partially offset by an increase in energy supply costs in 2015, as compared to 2014 ($11.2 million).
Transmission revenues increased by $12.5 million due primarily to higher revenue requirements associated with ongoing investments in our transmission infrastructure and lower reserves associated with the FERC ROE complaint proceedings recorded in 2015 compared to 2014.
Purchased Power, Fuel and Transmissionexpense includes costs associated with PSNH's generation of electricity as well as purchasing electricity on behalf of its customers. These energy supply costs are recovered from customers in NHPUC-approved cost tracking mechanisms, which have no impact on earnings (tracked costs). Purchased Power, Fuel and Transmission decreased in 2015, as compared to 2014, due primarily to the following:
| | |
(Millions of Dollars) | Decrease |
Generation Fuel Costs | $ | (25.0) |
Purchased Power Costs | | (23.6) |
Transmission Costs | | (14.1) |
Other | | (3.3) |
Total Purchased Power, Fuel and Transmission | $ | (66.0) |
PSNH procures power through its own generation, long-term power supply contracts, and short-term purchases and spot purchases in the competitive New England wholesale power market. The decrease in generation fuel costs was due primarily to a decrease in the amount of electricity generated by PSNH facilities during 2015, as compared to 2014. The decrease in purchased power costs was due to lower power prices of short-term and spot purchases made in the wholesale power market during 2015, as compared to 2014. The decrease in transmission costs was primarily the result of a decrease in the retail transmission cost deferral, which reflects the actual costs of transmission service compared to estimated amounts billed to customers.
56
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 increased in 2015, as compared to 2014, driven by a $7.5 million increase in tracked costs, which have no earnings impact, that was primarily attributable to increased maintenance activities at PSNH's generating facilities, partially offset by lower employee-related expenses, and a $7.1 million increase in non-tracked costs, which was primarily attributable to a $5 million contribution to create a clean energy fund that was recorded in 2015 in connection with the generation divestiture agreement, which is not recoverable from customers.
Depreciationincreased in 2015, as compared to 2014, due primarily to higher utility plant in service balances.
Amortization of Regulatory Assets/(Liabilities), Net reflects an increase in the deferral to expense of energy supply costs and other amortizations for 2015, as compared to 2014. Fluctuations in these costs are recovered from customers in rates and have no impact on earnings.
Taxes Other Than Income Taxes increased in 2015, as compared to 2014, due primarily to an increase in property taxes as a result of an increase in Property, Plant and Equipment and an increase in the property tax rates.
64
Interest Expensedecreased $4.1 million in 2013, as compared to 2012, due primarily to lower interest on RRBs ($2.8 million) as a result of the maturity of the RRBs in May 2013, and a decrease in interest on long-term debt ($1.9 million) due primarily to the redemption of the 2001 Series C PCRBs in May 2013.
Income Tax Expense
| | | | | | | | | | | | |
| | For the Years Ended December 31, | |
(Millions of Dollars) | 2013 | | 2012 | | Increase | | Percent | |
Income Tax Expense | $ | 71.1 | | $ | 61.0 | | $ | 10.1 | | 16.6 | % |
Income Tax Expense increased in 2013, as compared to 2012, due primarily to higher pre-tax earnings ($8.6 million) and various other impacts ($1.5 million).utility plant balances.
EARNINGS SUMMARY
| | | | | | | | |
| For the Years Ended December 31, |
(Millions of Dollars) | 2013 | | 2012 | | Increase |
Net Income | $ | 111.4 | | $ | 96.9 | | $ | 14.5 |
PSNH’sPSNH's earnings increased $0.5 million in 2015 compared to 2014, driven by higher distribution revenues due primarily to higher generation earnings andthe impact of the distribution retail revenues. The 2013 distribution retail revenues were favorably impacted by the PSNH rate increasesincrease effective July 1, 20122015 and July 1, 2013 as a result of the 2010 distribution rate case settlementhigher retail sales volumes, and a 1.5 percentan increase in retail sales. PSNH experienced strong salestransmission earnings due primarily to a higher transmission rate base and lower reserves associated with the FERC ROE complaint proceedings recorded in early and late 2013 due2015 compared to colder winter weather than what was experienced in 2012. Partially offsetting these2014. These favorable earnings impacts were offset by a $5 million contribution to create a clean energy fund recorded in 2015 in connection with the generation divestiture agreement, which is not recoverable from customers, higher property tax expense, higher depreciation expense and property tax expense.an increase in operations and maintenance costs.
LIQUIDITY
PSNH had cash flows provided by operating activities of $158.8$274.5 million in 2013,2015, as compared with $174.2to $248 million in 2012 (amounts are net of RRB payments, which are included2014. The increase in financing activities). The decrease inoperating cash flows was due primarily to the timing of payments related to fuel, materials and supplies as well as an increase in NUSCO Pension Plan contributions of $20.6 millionrecoveries from customers in 2013, as2015, compared to 2012,2014, and an increase in coalthe timing of collections and fuel inventories in 2013 creating a negative cash flow impact of $34.6 million, as comparedpayments related to a reduction in coalour working capital items, including accounts receivable and fuel inventories in 2012 creating a positive cash flow impact of $28.1 million.accounts payable. Partially offsetting these decreasesfavorable impacts were income tax refundsDOE Damages proceeds received from the Yankee Companies of $30.1$1 million in 2013,2015, compared to income tax payments of $14.7$14.5 million in 2012, the absence of $13.7 million of 2012 cash disbursements for storm costs associated with Tropical Storm Irene and the October 2011 snowstorm and the favorable impacts related to the distribution rate increases effective July 1, 2012 and July 1, 2013 as a result of the 2010 distribution rate case settlement. 2014.
6557
RESULTS OF OPERATIONS – WESTERN MASSACHUSETTS ELECTRIC COMPANY
The following table provides the amounts and variances in operating revenues and expense line items forin the statements of income for WMECO for the years ended December 31, 2015 and 2014 included in this Annual Report on Form 10-K for the years ended December 31, 2013 and 2012:10-K:
|
| | | Operating Revenues and Expenses | | | | For the Years Ended December 31, | |
| For the Years Ended December 31, | | | | | | | | | Increase/ | | | |
(Millions of Dollars) | 2013 | | 2012 | | Increase/ | | Percent | |
(Decrease) | (Millions of Dollars) | 2015 | | 2014 | | (Decrease) | | Percent | |
Operating Revenues | Operating Revenues | $ | 472.7 | | $ | 441.2 | | $ | 31.5 | | 7.1 | % | Operating Revenues | $ | 518.1 | $ | 493.4 | $ | 24.7 | 5.0 | % |
Operating Expenses: | Operating Expenses: | | | | | | | | | | Operating Expenses: | | | | | | | | | | | |
| Purchased Power and Transmission | | 147.1 | | 136.1 | | 11.0 | | 8.1 | | Purchased Power and Transmission | | 177.2 | | | 172.9 | | | 4.3 | | 2.5 | |
| Operations and Maintenance | | 96.2 | | 97.0 | | (0.8) | | (0.8) | | Operations and Maintenance | | 86.3 | | | 89.4 | | | (3.1) | | (3.5) | |
| Depreciation | | 37.6 | | 30.0 | | 7.6 | | 25.3 | | Depreciation | | 43.4 | | | 41.9 | | | 1.5 | | 3.6 | |
| Amortization of Regulatory (Liabilities)/Assets, Net | | (3.2) | | 0.4 | | (3.6) | | (a) | | Amortization of Regulatory Assets/(Liabilities), Net | | 14.5 | | | (6.2) | | | 20.7 | | (a) | |
| Amortization of Rate Reduction Bonds | | 7.8 | | 17.6 | | (9.8) | | (55.7) | | Energy Efficiency Programs | | 42.9 | | | 42.9 | | | - | | - | |
| Energy Efficiency Programs | | 39.5 | | 27.8 | | 11.7 | | 42.1 | | Taxes Other Than Income Taxes | | 38.3 | | | 34.9 | | | 3.4 | | 9.7 | |
| Taxes Other Than Income Taxes | | 28.4 | | | 21.5 | | | 6.9 | | 32.1 | | | Total Operating Expenses | | 402.6 | | | 375.8 | | | 26.8 | | 7.1 | |
Operating Income | | 115.5 | | | 117.6 | | | (2.1) | | (1.8) | |
Interest Expense | | 24.7 | | | 24.9 | | | (0.2) | | (0.8) | |
Other Income, Net | | 2.7 | | | 2.4 | | | 0.3 | | 12.5 | |
Income Before Income Tax Expense | | 93.5 | | | 95.1 | | | (1.6) | | (1.7) | |
Income Tax Expense | | 37.0 | | | 37.3 | | | (0.3) | | (0.8) | |
Net Income | $ | 56.5 | | $ | 57.8 | | $ | (1.3) | | (2.2) | % |
| | Total Operating Expenses | | 353.4 | | | 330.4 | | | 23.0 | | 7.0 | | | | | | | | | | | | | | |
Operating Income | $ | 119.3 | | $ | 110.8 | | $ | 8.5 | | 7.7 | % |
(a) Percent greater than 100 percent not shown as it is not meaningful | |
| | | | | | | | | | | | | | | |
(a) | Percent greater than 100 percent not shown as it is not meaningful. | |
Operating Revenues | | | | | | | | | | | |
WMECO's retail sales volumes were as follows: | | | | | | | | | | | |
| | | For the Years Ended December 31, | |
| | | 2015 | | 2014 | | Decrease | | Percent | |
Retail Sales Volumes in GWh | | 3,563 | | | 3,586 | | | (23) | | (0.6) | % |
| | | | | | | | | |
Operating Revenues | | | | | | | | |
WMECO's retail sales were as follows: |
| | For the Years Ended December 31, | |
| | 2013 | | 2012 | | Change | | Percent | |
Retail Sales in GWh | 3,683 | | 3,683 | | - | | - | % |
Operating Revenues
WMECO's Operating Revenues increased by $24.7 million in 2013, as2015 compared to 2012, due primarily to:2014.
·
A $21.3 million increaseFluctuations in transmissionWMECO's sales volumes have no impact on total operating revenues reflecting recovery of higher transmission expenses and continuing transmission infrastructure investments, primarily related to the NEEWS project. The increase was partially offset by the establishment of a reserve related to the FERC ALJ initial decision in the third quarter of 2013.
·
Base distributionor earnings, as WMECO’s revenues are consistent with 2012, as they are decoupled from sales volumes.
·
The remaining increase primarily reflects a higher Fluctuations in the overall level of collectionsoperating revenues are primarily related to WMECO’stracked revenues. Tracked revenues consist of certain costs that are recovered from customers in rates through DPU-approved cost tracking mechanisms and therefore have no impact on earnings. Costs recovered through cost tracking mechanisms include energy supply and company-sponsoredcosts, transmission related costs, energy efficiency programs. Theseprograms, low income assistance programs, and restructuring and stranded costs as a result of deregulation. Tracked revenues are fully reconciled to the related costs. Therefore this increase in revenues had no material impact on earnings.
Purchased Power and Transmissionincreased in 2013, as compared to 2012, due primarily to an increase in supplier contract prices. energy supply costs ($20.3 million) driven by increased average retail rates. The increase in Operating Revenues was partially offset by a $3.9 million decrease in revenues that impacts earnings due to the absence of a 2014 wholesale billing adjustment.
Transmission revenues increased by $8.7 million due primarily to higher revenue requirements associated with ongoing investments in our transmission infrastructure and the impact of a lower FERC ROE complaint proceedings reserve recorded in 2015 as compared to 2014.
Purchased Power and Transmissionexpense includes costs associated with purchasing electricity on behalf of WMECO's customers. These energy supply costs are includedrecovered from customers in regulatory-approvedDPU-approved cost tracking mechanisms, which have no impact on earnings (tracked costs). Purchased Power and doTransmissionincreased in 2015, as compared to 2014, due primarily to the following:
| | |
(Millions of Dollars) | Increase/(Decrease) |
Purchased Power Costs | $ | 18.1 |
Transmission Costs | | (13.8) |
Total Purchased Power and Transmission | $ | 4.3 |
Included in purchased power are the costs associated with WMECO's basic service charge and deferred energy supply costs. The basic service charge recovers energy-related costs incurred as a result of providing electric generation service supply to all customers that have not impact earnings. migrated to competitive energy suppliers. The increase in purchased power costs was due primarily to higher prices associated with the procurement of energy supply. The decrease in transmission costs was as a result of a decrease in the retail transmission cost deferral, which reflects the actual costs of transmission service compared to estimated amounts billed to customers.
Operations and Maintenanceexpense includes tracked costs and costs that are part of base distribution rates with changes impacting earnings (non-tracked costs). Operations and Maintenance decreased in 2013,2015, as compared to 2012, due primarily to the absence2014, driven by $3.9 million reduction in 2013 of bill credits to customers ($3 million) made in the second quarter of 2012 as a result of the Massachusetts merger settlement agreement and the absence in 2013 of the DPU storm penalty ($2 million). In addition, there were lower general and administrative expenses ($2.5 million). Partially offsetting these decreases was an increase in Pension and PBOP Plantracked costs, ($6.6 million), which is recovered through DPU-approved tracking mechanisms and hashave no earnings impact.impact, that was primarily attributable to lower employee-related expenses, partially offset by higher tracked bad debt expense. Non-tracked costs increased $0.8 million, which was primarily attributable to higher bad debt expense, partially offset by a decrease in workers' compensation claims.
Depreciationincreased in 2013,2015, as compared to 2012,2014, due primarily to higher utility plant balances resulting from completed construction projects placed into service.in service balances.
58
Amortization of Regulatory Assets/(Liabilities)/Assets,, Netdecreased in 2013, as compared to 2012, due primarily to a decrease in amortizationreflects the absence of the transition charge deferral.
Amortization of Rate Reduction Bondsdecreased in 2013, as compared to 2012, due to the maturityrefund of the RRBsDOE proceeds to customers in June 2013.
Energy Efficiency Programsincreased2014 as well as energy and energy related costs and amortizations that can fluctuate period to period based on timing of costs incurred and related rate changes to recover these costs. Fluctuations in 2013, as compared to 2012, due primarily to an increase in expenses attributable to an increase in spending in accordance with the three-year program guidelines established by the DPU. Allenergy and energy related costs are fully recovered through DPU-approved tracking mechanismsfrom customers in rates and therefore do nothave no impact on earnings.
Taxes Other Than Income Taxes increased in 2013,2015, as compared to 2012,2014, 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.
66
Interest Expensedecreased $1.8 million in 2013, as compared to 2012, due primarily to lower interest on RRBs ($1.1 million) as a result of the maturity of the RRBs in June 2013, and lower interest on short-term debt ($0.9 million).
Income Tax Expense
| | | | | | | | | | | | |
| | For the Years Ended December 31, | |
(Millions of Dollars) | 2013 | | 2012 | | Increase | | Percent | |
Income Tax Expense | $ | 37.4 | | $ | 32.1 | | $ | 5.3 | | 16.5 | % |
Income Tax Expense increased in 2013, as compared to 2012, due primarily to higher pre-tax earnings ($2.9 million), the absence in 2013 of the impact of costs recognized as a result of the Massachusetts merger settlement agreement ($1.2 million) and various other impacts ($1.2 million). utility plant balances.
EARNINGS SUMMARY
| | | | | | |
| For the Years Ended
December 31, |
(Millions of Dollars) | | 2013 | | | 2012 |
Income Before Merger-Related Costs | $ | 60.4 | | $ | 56.3 |
Merger-Related Costs (after-tax) | | - | | | (1.8) |
Net Income | $ | 60.4 | | $ | 54.5 |
Excluding the impact of merger-related costs, WMECO’sWMECO's earnings increased $4.1decreased $1.3 million in 2015, as compared to 2012,2014, due primarily to the absence of a 2014 wholesale billing adjustment, which favorably impacted 2014 revenues and interest expense, higher property tax expense and an increase in non-tracked operations and maintenance costs. Partially offsetting these unfavorable earnings impacts was an increase in transmission earnings due primarily to a higher transmission earnings as a result of an increased level of investmentrate base and lower reserves associated with the FERC ROE complaint proceedings recorded in transmission infrastructure, primarily related2015 compared to the NEEWS project. Partially offsetting this favorable earnings impact was higher depreciation and property tax expense.2014.
LIQUIDITY
WMECO had cash flows provided by operating activities of $169.5$43 million in 2013,2015, compared with $77$153.3 million in 2012 (amounts are net of RRB payments, which are included2014. The decrease in financing activities). The improvedoperating cash flows was due primarily to the $57.4 million payment made from WMECO’s spent nuclear fuel trust to fully satisfy the pre-1983 spent nuclear fuel obligation with the DOE. Also contributing to the decrease in operating cash flows were DOE Damages proceeds received from the Yankee Companies of $0.6 million in 2015, compared to $18.9 million in 2014, the unfavorable impact of accounts receivable due primarily to an increase in basic service rates effective January 1, 2015, and the timing of regulatory recoveries resulting from the increase in purchased power costs. Partially offsetting these unfavorable cash flow impacts were lower income tax refunds of $69 millionpayments in 2013,2015 compared with income tax refunds of $8.4 million in 2012, the absence of $16.7 million in 2012 cash disbursements for storm costs in 2012 and the absence of $3 million in bill credits provided to customers in the second quarter of 2012 associated with the Massachusetts merger settlement agreement. 2014.
6759
Item 7A.
Quantitative and Qualitative Disclosures about Market Risk
Market Risk Information
Commodity Price Risk Management: Our Regulated companies enter into energy contracts to serve our customers and the economic impacts of those contracts are passed on to our customers. Accordingly, the Regulated companies have no exposure to loss of future earnings or fair values due to these market risk-sensitive instruments. NU’sEversource's Energy Supply Risk Committee, comprised of senior officers, reviews and approves all large scale energy related transactions entered into by its Regulated Companies.
The remaining unregulated wholesale marketing contracts expired on December 31, 2013 and therefore, there is no remaining market risk exposure related to these contracts.companies.
Other Risk Management Activities
We have an Enterprise Risk Management methodology(ERM) program for identifying the principal risks of the Company. Our ERM program involves the application of a well-defined, enterprise-wide methodology designed to allow our Risk Committee, comprised of our senior officers and directors of the Company, to the company, to oversee the identification, managementidentify, categorize, prioritize, and reporting ofmitigate the principal risks to the Company. The ERM program is integrated with other assurance functions throughout the Company including Compliance, Auditing, and Insurance to ensure appropriate coverage of risks that could impact the business.Company. In addition to known risks, ERM identifies emerging risks to the Company, through participation in industry groups, discussions with management and in consultation with outside advisers. Our management then analyzes risks to determine materiality, and other attributes such as likelihood and impact, and develops mitigation strategies. Management broadly considers our business model, the utility industry, the global economy and the current environment to identify risks. The Finance Committee of the Board of Trustees is responsible for oversight of the Company's ERM program and enterprise-wide risks as well as specific risks associated with insurance, credit, financing, investments, pensions and overall system security including cyber security. The findings of thisthe ERM process are periodically discussed with the Finance Committee of our Board of Trustees.Trustees, as well as with other Board Committees or the full Board of Trustees, as appropriate, including reporting on how these issues are being measured and managed. However, there can be no assurances that the Enterprise Risk Management process will identify or manage every risk or event that could impact our financial position, results of operations or cash flows.
Interest Rate Risk Management: We manage our interest rate risk exposure in accordance with our written policies and procedures by maintaining a mix of fixed and variable rate long-term debt. As of December 31, 2013,2015, approximately 9195 percent of our long-term debt, including fees and interest due for CYAPC's spent nuclear fuel disposal costs, was at a fixed interest rate. The remaining long-term debt is at variable interest rates and is subject to interest rate risk that could result in earnings volatility. Assuming a one percentage point increase in our variable interest rate,rates, annual interest expense would have increased by a pre-tax amount of $7.7$4.7 million.
Credit Risk Management: Credit risk relates to the risk of loss that we would incur as a result of non-performance by counterparties pursuant to the terms of our contractual obligations. We serve a wide variety of customers and transact with suppliers that include IPPs, industrial companies, natural gas and electric utilities, oil and gas producers, financial institutions, and other energy marketers. Margin accounts exist within this diverse group, and we realize interest receipts and payments related to balances outstanding in these margin accounts. This wide customer and supplier mix generates a need for a variety of contractual structures, products and terms that, in turn, require us to manage the portfolio of market risk inherent in those transactions in a manner consistent with the parameters established by our risk management process.
Our Regulated companies are subject to credit risk from certain long-term or high-volume supply contracts with energy marketing companies. Our Regulated companies manage the credit risk with these counterparties in accordance with established credit risk practices and monitor contracting risks, including credit risk. As of December 31, 2013,2015, our Regulated companies helddid not hold collateral (letters of credit) from counterparties related to our standard service contracts. As of December 31, 2013, NU2015, Eversource had $17.1 million of cash posted with ISO-NE related to energy purchase transactions.
For further information on cash collateral deposited and posted with counterparties, as well, see Note 1G, "Summary of Significant Accounting Policies- Restricted Cash and OtherPolicies - Deposits," and Note 5,4, "Derivative Instruments," to the consolidated financial statements.
If the respective unsecured debt ratings of NUEversource or its subsidiaries were reduced to below investment grade by either Moody’sMoody's or S&P, certain of NU’sEversource's contracts would require additional collateral in the form of cash to be provided to counterparties and independent system operators. NUEversource would have been and remains able to provide that collateral.
6860
Item 8.
Financial Statements and Supplementary Data
| | | |
| | |
NUEversource
| | |
| Company Report on Internal Controls Over Financial Reporting | |
| Report of Independent Registered Public Accounting Firm | |
| Consolidated Financial Statements | |
| | |
CL&P | | |
| Company Report on Internal Controls Over Financial Reporting | |
| Report of Independent Registered Public Accounting Firm | |
| Financial Statements | |
| | |
NSTAR Electric | | |
| Company Report on Internal Controls Over Financial Reporting | |
| ReportsReport of Independent Registered Public Accounting FirmsFirm
| |
| Consolidated Financial Statements | |
| | |
PSNH | | |
| Company Report on Internal Controls Over Financial Reporting | |
| Report of Independent Registered Public Accounting Firm | |
| Consolidated Financial Statements | |
| | |
WMECO | | |
| Company Report on Internal Controls Over Financial Reporting | |
| Report of Independent Registered Public Accounting Firm | |
| Financial Statements | |
6961
Company Report on Internal Controls Over Financial Reporting
Northeast UtilitiesEversource Energy
Management is responsible for the preparation, integrity, and fair presentation of the accompanying consolidated financial statements of Northeast UtilitiesEversource Energy and subsidiaries (NU(Eversource or the Company) and of other sections of this annual report. NU’sEversource's internal controls over financial reporting were audited by Deloitte & Touche LLP.
Management is responsible for establishing and maintaining adequate internal controls over financial reporting. The Company’sCompany's internal control framework and processes have been designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with accounting principles generally accepted accounting principles.in the United States of America. There are inherent limitations of internal controls over financial reporting that could allow material misstatements due to error or fraud to occur and not be prevented or detected on a timely basis by employees during the normal course of business. Additionally, internal controls over financial reporting may become inadequate in the future due to changes in the business environment.
Under the supervision and with the participation of the principal executive officer and principal financial officer, NUEversource conducted an evaluation of the effectiveness of internal controls over financial reporting based on criteria established inInternal Control – Integrated Framework (2013)(1992 Framework) issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO). Based on this evaluation under the framework in COSO, management concluded that internal controls over financial reporting were effective as of December 31, 2013.2015.
February 25, 201426, 2016
7062
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
To the Board of Trustees and Shareholders of Northeast Utilities:Eversource Energy:
We have audited the accompanying consolidated balance sheets of Northeast UtilitiesEversource Energy and subsidiaries (the "Company") as of December 31, 20132015 and 2012,2014, and the related consolidated statements of income, comprehensive income, common shareholders’shareholders' equity, and cash flows for each of the three years in the period ended December 31, 2013.2015. Our audits also included the financial statement schedules listed in the Index at Item 15 of Part IV. We also have audited the Company's internal control over financial reporting as of December 31, 2013,2015, based on criteria established inInternal Control — Integrated Framework (1992)(2013)issued by the Committee of Sponsoring Organizations of the Treadway Commission. The Company's management is responsible for these financial statements and financial statement schedules, for maintaining effective internal control over financial reporting, and for its assessment of the effectiveness of internal control over financial reporting, included in the accompanying Company Report on Internal Controls Over Financial Reporting. Our responsibility is to express an opinion on these financial statements and financial statement schedules and an opinion on the Company's internal control over financial reporting based on our audits.
We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement and whether effective internal control over financial reporting was maintained in all material respects. Our audits of the financial statements included examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, and evaluating the overall financial statement presentation. Our audit of internal control over financial reporting included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, testing and evaluating the design and operating effectiveness of internal control based on the assessed risk. Our audits also included performing such other procedures as we considered necessary in the circumstances. We believe that our audits provide a reasonable basis for our opinions.
A company's internal control over financial reporting is a process designed by, or under the supervision of, the company's principal executive and principal financial officers, or persons performing similar functions, and effected by the company's board of directors, management, and other personnel to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company's internal control over financial reporting includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company's assets that could have a material effect on the financial statements.
Because of the inherent limitations of internal control over financial reporting, including the possibility of collusion or improper management override of controls, material misstatements due to error or fraud may not be prevented or detected on a timely basis. Also, projections of any evaluation of the effectiveness of the internal control over financial reporting to future periods are subject to the risk that the controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.
In our opinion, the consolidated financial statements referred to above present fairly, in all material respects, the financial position of Northeast UtilitiesEversource Energy and subsidiaries as of December 31, 20132015 and 2012,2014, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2013,2015, in conformity with accounting principles generally accepted in the United States of America. Also, in our opinion, such financial statement schedules, when considered in relation to the basic consolidated financial statements taken as a whole, present fairly, in all material respects, the information set forth therein. Also, in our opinion, the Company maintained, in all material respects, effective internal control over financial reporting as of December 31, 2013,2015, based on the criteria established inInternal Control — Integrated Framework(1992)Framework (2013)issued by the Committee of Sponsoring Organizations of the Treadway Commission.
/s/ Deloitte & Touche LLP
Hartford, Connecticut
February 25, 201426, 2016
7163
| | | | | | |
NORTHEAST UTILITIES AND SUBSIDIARIES |
CONSOLIDATED BALANCE SHEETS |
|
| | | | | | |
| | As of December 31, |
(Thousands of Dollars) | 2013 | | 2012 |
| | | | | | |
ASSETS | | | | | |
| | | | | | |
Current Assets: | | | | | |
| Cash and Cash Equivalents | $ | 43,364 | | $ | 45,748 |
| Receivables, Net | | 765,391 | | | 792,822 |
| Unbilled Revenues | | 224,982 | | | 216,040 |
| Fuel, Materials and Supplies | | 303,233 | | | 267,713 |
| Regulatory Assets | | 535,791 | | | 705,025 |
| Prepayments and Other Current Assets | | 214,288 | | | 199,947 |
Total Current Assets | | 2,087,049 | | | 2,227,295 |
| | | | | | |
Property, Plant and Equipment, Net | | 17,576,186 | | | 16,605,010 |
| | | | | | |
Deferred Debits and Other Assets: | | | | | |
| Regulatory Assets | | 3,758,694 | | | 5,132,411 |
| Goodwill | | 3,519,401 | | | 3,519,401 |
| Marketable Securities | | 488,515 | | | 400,329 |
| Derivative Assets | | 74,155 | | | 90,612 |
| Other Long-Term Assets | | 291,537 | | | 327,766 |
Total Deferred Debits and Other Assets | | 8,132,302 | | | 9,470,519 |
| | | | | | |
| | | | | | |
| | | | | | |
Total Assets | $ | 27,795,537 | | $ | 28,302,824 |
| | | | | | |
| | | | | | |
| | | | | | |
The accompanying notes are an integral part of these consolidated financial statements. |
| | | | | | | | | |
EVERSOURCE ENERGY AND SUBSIDIARIES |
CONSOLIDATED BALANCE SHEETS |
|
| | | | | | | | | |
| | | | | As of December 31, |
(Thousands of Dollars) | 2015 | | 2014 |
| | | | | |
ASSETS | | | | | |
| | | | | |
Current Assets: | | | | | |
| Cash and Cash Equivalents | $ | 23,947 | | $ | 38,703 |
| Receivables, Net | | 775,480 | | | 856,346 |
| Unbilled Revenues | | 202,647 | | | 211,758 |
| Taxes Receivable | | 305,359 | | | 337,307 |
| Fuel, Materials and Supplies | | 336,476 | | | 349,664 |
| Regulatory Assets | | 845,843 | | | 672,493 |
| Prepayments and Other Current Assets | | 129,034 | | | 226,194 |
Total Current Assets | | 2,618,786 | | | 2,692,465 |
| | | | | |
Property, Plant and Equipment, Net | | 19,892,441 | | | 18,647,041 |
| | | | | |
Deferred Debits and Other Assets: | | | | | |
| Regulatory Assets | | 3,737,960 | | | 4,054,086 |
| Goodwill | | 3,519,401 | | | 3,519,401 |
| Marketable Securities | | 516,478 | | | 515,025 |
| Other Long-Term Assets | | 295,243 | | | 312,369 |
Total Deferred Debits and Other Assets | | 8,069,082 | | | 8,400,881 |
| | | | | |
Total Assets | $ | 30,580,309 | | $ | 29,740,387 |
| | | | | | | | | |
LIABILITIES AND CAPITALIZATION | | | | | |
| | | | | |
Current Liabilities: | | | | | |
| Notes Payable | $ | 1,160,953 | | $ | 956,825 |
| Long-Term Debt - Current Portion | | 228,883 | | | 245,583 |
| Accounts Payable | | 813,646 | | | 868,231 |
| Regulatory Liabilities | | 107,759 | | | 235,022 |
| Accumulated Deferred Income Taxes | | - | | | 160,288 |
| Other Current Liabilities | | 678,549 | | | 668,432 |
Total Current Liabilities | | 2,989,790 | | | 3,134,381 |
| | | | | | | | | |
Deferred Credits and Other Liabilities: | | | | | |
| Accumulated Deferred Income Taxes | | 5,147,678 | | | 4,467,473 |
| Regulatory Liabilities | | 513,595 | | | 515,144 |
| Derivative Liabilities | | 337,102 | | | 409,632 |
| Accrued Pension, SERP and PBOP | | 1,407,288 | | | 1,638,558 |
| Other Long-Term Liabilities | | 871,499 | | | 874,387 |
Total Deferred Credits and Other Liabilities | | 8,277,162 | | | 7,905,194 |
| | | | | | | | | |
Capitalization: | | | | | |
| Long-Term Debt | | 8,805,574 | | | 8,568,429 |
| | | | | |
| Noncontrolling Interest - Preferred Stock of Subsidiaries | | 155,568 | | | 155,568 |
| | | | | |
| Equity: | | | | | |
| | Common Shareholders' Equity: | | | | | |
| | | Common Shares | | 1,669,313 | | | 1,666,796 |
| | | Capital Surplus, Paid In | | 6,262,368 | | | 6,235,834 |
| | | Retained Earnings | | 2,797,355 | | | 2,448,661 |
| | | Accumulated Other Comprehensive Loss | | (66,844) | | | (74,009) |
| | | Treasury Stock | | (309,977) | | | (300,467) |
| | Common Shareholders' Equity | | 10,352,215 | | | 9,976,815 |
Total Capitalization | | 19,313,357 | | | 18,700,812 |
| | | | | |
Commitments and Contingencies (Note 11) | | | | | |
| | | | | |
Total Liabilities and Capitalization | $ | 30,580,309 | | $ | 29,740,387 |
| | | | | | | | | |
| | | | | | | | | |
| | | | | | | | | |
The accompanying notes are an integral part of these consolidated financial statements. |
7264
| | | | | | | |
NORTHEAST UTILITIES AND SUBSIDIARIES |
CONSOLIDATED BALANCE SHEETS |
|
| | | | | | | |
| | | As of December 31, |
(Thousands of Dollars) | 2013 | | 2012 |
| | | | | | | |
LIABILITIES AND CAPITALIZATION | | | | | |
| | | | | | | |
Current Liabilities: | | | | | |
Notes Payable | $ | 1,093,000 | | $ | 1,120,196 |
Long-Term Debt - Current Portion | | 533,346 | | | 763,338 |
Accounts Payable | | 742,251 | | | 764,350 |
Regulatory Liabilities | | 204,278 | | | 134,115 |
Other Current Liabilities | | 702,776 | | | 861,691 |
Total Current Liabilities | | 3,275,651 | | | 3,643,690 |
| | | | | | | |
Rate Reduction Bonds | | - | | | 82,139 |
| | | | | | | |
Deferred Credits and Other Liabilities: | | | | | |
Accumulated Deferred Income Taxes | | 4,029,026 | | | 3,463,347 |
Regulatory Liabilities | | 502,984 | | | 540,162 |
Derivative Liabilities | | 624,050 | | | 882,654 |
Accrued Pension, SERP and PBOP | | 896,844 | | | 2,130,497 |
Other Long-Term Liabilities | | 923,053 | | | 967,561 |
Total Deferred Credits and Other Liabilities | | 6,975,957 | | | 7,984,221 |
| | | | | | | |
Capitalization: | | | | | |
Long-Term Debt | | 7,776,833 | | | 7,200,156 |
| | | | | | | |
Noncontrolling Interest - Preferred Stock of Subsidiaries | | 155,568 | | | 155,568 |
| | | | | | | |
Equity: | | | | | |
| Common Shareholders' Equity: | | | | | |
| Common Shares | | 1,665,351 | | | 1,662,547 |
| Capital Surplus, Paid In | | 6,192,765 | | | 6,183,267 |
| Retained Earnings | | 2,125,980 | | | 1,802,714 |
| Accumulated Other Comprehensive Loss | | (46,031) | | | (72,854) |
| Treasury Stock | | (326,537) | | | (338,624) |
Common Shareholders' Equity | | 9,611,528 | | | 9,237,050 |
Total Capitalization | | 17,543,929 | | | 16,592,774 |
| | | | | | | |
Commitments and Contingencies (Note 12) | | | | | |
| | | | | | | |
Total Liabilities and Capitalization | $ | 27,795,537 | | $ | 28,302,824 |
| | | | | | | |
| | | | | | | |
| | | | | | | |
The accompanying notes are an integral part of these consolidated financial statements. |
| | | | | | | | | | |
EVERSOURCE ENERGY AND SUBSIDIARIES |
CONSOLIDATED STATEMENTS OF INCOME |
|
| | | | | | | | | | |
| | | For the Years Ended December 31, |
(Thousands of Dollars, Except Share Information) | 2015 | | 2014 | | 2013 |
| | | | | | | | | | |
Operating Revenues | $ | 7,954,827 | | $ | 7,741,856 | | $ | 7,301,204 |
| | | | | | | | | | |
Operating Expenses: | | | | | | | | |
| Purchased Power, Fuel and Transmission | | 3,086,905 | | | 3,021,550 | | | 2,482,954 |
| Operations and Maintenance | | 1,329,289 | | | 1,427,589 | | | 1,514,986 |
| Depreciation | | 665,856 | | | 614,657 | | | 610,777 |
| Amortization of Regulatory Assets, Net | | 22,339 | | | 10,704 | | | 206,322 |
| Amortization of Rate Reduction Bonds | | - | | | - | | | 42,581 |
| Energy Efficiency Programs | | 495,701 | | | 473,127 | | | 401,919 |
| Taxes Other Than Income Taxes | | 590,573 | | | 561,380 | | | 512,230 |
| | Total Operating Expenses | | 6,190,663 | | | 6,109,007 | | | 5,771,769 |
Operating Income | | 1,764,164 | | | 1,632,849 | | | 1,529,435 |
Interest Expense | | 372,420 | | | 362,106 | | | 338,699 |
Other Income, Net | | 34,227 | | | 24,619 | | | 29,894 |
Income Before Income Tax Expense | | 1,425,971 | | | 1,295,362 | | | 1,220,630 |
Income Tax Expense | | 539,967 | | | 468,297 | | | 426,941 |
Net Income | | 886,004 | | | 827,065 | | | 793,689 |
Net Income Attributable to Noncontrolling Interests | | 7,519 | | | 7,519 | | | 7,682 |
Net Income Attributable to Common Shareholders | $ | 878,485 | | $ | 819,546 | | $ | 786,007 |
| | | | | | | | | | |
Basic Earnings Per Common Share | $ | 2.77 | | $ | 2.59 | | $ | 2.49 |
| | | | | | | | | | |
Diluted Earnings Per Common Share | $ | 2.76 | | $ | 2.58 | | $ | 2.49 |
| | | | | | | | | | |
Weighted Average Common Shares Outstanding: | | | | | | | | |
| Basic | | 317,336,881 | | | 316,136,748 | | | 315,311,387 |
| Diluted | | 318,432,687 | | | 317,417,414 | | | 316,211,160 |
| | | | | | | | | | |
The accompanying notes are an integral part of these consolidated financial statements. |
| | | | | | | | | | |
| | | | | | | | | | |
| | | | | | | | | | |
| | | | | | | | | | |
CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME |
| | | | | | | | | | |
| | | | | | | | | | |
Net Income | $ | 886,004 | | $ | 827,065 | | $ | 793,689 |
Other Comprehensive Income/(Loss), Net of Tax: | | | | | | | | |
| Qualified Cash Flow Hedging Instruments | | 2,079 | | | 2,037 | | | 2,049 |
| Changes in Unrealized (Losses)/Gains on Marketable Securities | | (2,588) | | | 315 | | | (940) |
| Changes in Funded Status of Pension, SERP and PBOP Benefit Plans | | 7,674 | | | (30,330) | | | 25,714 |
Other Comprehensive Income/(Loss), Net of Tax | | 7,165 | | | (27,978) | | | 26,823 |
Comprehensive Income Attributable to Noncontrolling Interests | | (7,519) | | | (7,519) | | | (7,682) |
Comprehensive Income Attributable to Common Shareholders | $ | 885,650 | | $ | 791,568 | | $ | 812,830 |
| | | | | | | | | | |
The accompanying notes are an integral part of these consolidated financial statements. |
| | | | | | | | | | |
7365
| | | | | | | | | | |
NORTHEAST UTILITIES AND SUBSIDIARIES |
CONSOLIDATED STATEMENTS OF INCOME |
|
| | | | | | | | | | |
| | | For the Years Ended December 31, |
(Thousands of Dollars, Except Share Information) | 2013 | | 2012 | | 2011 |
| | | | | | | | | | |
Operating Revenues | $ | 7,301,204 | | $ | 6,273,787 | | $ | 4,465,657 |
| | | | | | | | | | |
Operating Expenses: | | | | | | | | |
| Purchased Power, Fuel and Transmission | | 2,482,954 | | | 2,084,364 | | | 1,657,914 |
| Operations and Maintenance | | 1,514,986 | | | 1,583,070 | | | 1,095,358 |
| Depreciation | | 610,777 | | | 519,010 | | | 302,192 |
| Amortization of Regulatory Assets, Net | | 206,322 | | | 79,762 | | | 91,080 |
| Amortization of Rate Reduction Bonds | | 42,581 | | | 142,019 | | | 69,912 |
| Energy Efficiency Programs | | 401,919 | | | 313,149 | | | 131,415 |
| Taxes Other Than Income Taxes | | 512,230 | | | 434,207 | | | 323,610 |
| | Total Operating Expenses | | 5,771,769 | | | 5,155,581 | | | 3,671,481 |
Operating Income | | 1,529,435 | | | 1,118,206 | | | 794,176 |
| | | | | | | | | | |
Interest Expense: | | | | | | | | |
| Interest on Long-Term Debt | | 340,970 | | | 316,987 | | | 231,630 |
| Interest on Rate Reduction Bonds | | 422 | | | 6,168 | | | 8,611 |
| Other Interest | | (2,693) | | | 6,790 | | | 10,184 |
| | Interest Expense | | 338,699 | | | 329,945 | | | 250,425 |
Other Income, Net | | 29,894 | | | 19,742 | | | 27,715 |
Income Before Income Tax Expense | | 1,220,630 | | | 808,003 | | | 571,466 |
Income Tax Expense | | 426,941 | | | 274,926 | | | 170,953 |
Net Income | | 793,689 | | | 533,077 | | | 400,513 |
Net Income Attributable to Noncontrolling Interests | | 7,682 | | | 7,132 | | | 5,820 |
Net Income Attributable to Controlling Interest | $ | 786,007 | | $ | 525,945 | | $ | 394,693 |
| | | | | | | | | | |
Basic Earnings Per Common Share | $ | 2.49 | | $ | 1.90 | | $ | 2.22 |
| | | | | | | | | | |
Diluted Earnings Per Common Share | $ | 2.49 | | $ | 1.89 | | $ | 2.22 |
| | | | | | | | | | |
Weighted Average Common Shares Outstanding: | | | | | | | | |
| Basic | | 315,311,387 | | | 277,209,819 | | | 177,410,167 |
| Diluted | | 316,211,160 | | | 277,993,631 | | | 177,804,568 |
| | | | | | | | | | |
| | | | | | | | | | |
| | | | | | | | | | |
The accompanying notes are an integral part of these consolidated financial statements. |
| | | | | | | | | |
EVERSOURCE ENERGY AND SUBSIDIARIES |
CONSOLIDATED STATEMENTS OF COMMON SHAREHOLDERS' EQUITY |
| | | | | | | | | |
| | | | | | | Accumulated | | Total |
| | | | | Capital | | Other | | Common |
| | | Common Shares | Surplus, | Retained | Comprehensive | Treasury | Shareholders' |
(Thousands of Dollars, Except Share Information) | Shares | Amount | Paid In | Earnings | Income/(Loss) | Stock | Equity |
Balance as of January 1, 2013 | 314,053,634 | $ 1,662,547 | $ 6,183,267 | $ 1,802,714 | $ (72,854) | $ (338,624) | $ 9,237,050 |
| Net Income | | | | 793,689 | | | 793,689 |
| Dividends on Common Shares - $1.47 Per Share | | | | (462,741) | | | (462,741) |
| Dividends on Preferred Stock | | | | (7,682) | | | (7,682) |
| Issuance of Common Shares, $5 Par Value | 560,848 | 2,804 | 8,274 | | | | 11,078 |
| Long-Term Incentive Plan Activity | | | (10,748) | | | | (10,748) |
| Issuance of Treasury Shares | 659,077 | | 17,381 | | | 12,087 | 29,468 |
| Other Changes in Shareholders' Equity | | | (5,409) | | | | (5,409) |
| Other Comprehensive Income | | | | | 26,823 | | 26,823 |
Balance as of December 31, 2013 | 315,273,559 | 1,665,351 | 6,192,765 | 2,125,980 | (46,031) | (326,537) | 9,611,528 |
| Net Income | | | | 827,065 | | | 827,065 |
| Dividends on Common Shares - $1.57 Per Share | | | | (496,524) | | | (496,524) |
| Dividends on Preferred Stock | | | | (7,519) | | | (7,519) |
| Issuance of Common Shares, $5 Par Value | 288,941 | 1,445 | 5,164 | | | | 6,609 |
| Long-Term Incentive Plan Activity | | | (9,569) | | | | (9,569) |
| Issuance of Treasury Shares | 1,420,837 | | 37,817 | | | 26,070 | 63,887 |
| Other Changes in Shareholders' Equity | | | 9,657 | (341) | | | 9,316 |
| Other Comprehensive Loss | | | | | (27,978) | | (27,978) |
Balance as of December 31, 2014 | 316,983,337 | 1,666,796 | 6,235,834 | 2,448,661 | (74,009) | (300,467) | 9,976,815 |
| Net Income | | | | 886,004 | | | 886,004 |
| Dividends on Common Shares - $1.67 Per Share | | | | (529,791) | | | (529,791) |
| Dividends on Preferred Stock | | | | (7,519) | | | (7,519) |
| Issuance of Common Shares, $5 Par Value | 503,443 | 2,517 | 6,951 | | | | 9,468 |
| Long-Term Incentive Plan Activity | | | (6,140) | | | | (6,140) |
| Increase in Treasury Shares | (295,531) | | 22,070 | | | (9,510) | 12,560 |
| Other Changes in Shareholders' Equity | | | 3,653 | | | | 3,653 |
| Other Comprehensive Income | | | | | 7,165 | | 7,165 |
Balance as of December 31, 2015 | 317,191,249 | $ 1,669,313 | $ 6,262,368 | $ 2,797,355 | $ (66,844) | $ (309,977) | $ 10,352,215 |
| | | | | | | | | |
| | | | | | | | | |
| | | | | | | | | |
The accompanying notes are an integral part of these consolidated financial statements. |
7466
| | | | | | | | | | | |
NORTHEAST UTILITIES AND SUBSIDIARIES |
CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME |
| | | | | | | | | | | |
| | | | For the Years Ended December 31, |
(Thousands of Dollars) | 2013 | | 2012 | | 2011 |
| | | | | | | | | | | |
Net Income | $ | 793,689 | | $ | 533,077 | | $ | 400,513 |
Other Comprehensive Income/(Loss), Net of Tax: | | | | | | | | |
| Qualified Cash Flow Hedging Instruments | | 2,049 | | | 1,971 | | | (14,177) |
| Changes in Unrealized Gains/(Losses) on Other Securities | | (940) | | | 217 | | | 506 |
| Change in Funded Status of Pension, SERP and PBOP | | | | | | | | |
| | Benefit Plans | | 25,714 | | | (4,356) | | | (13,645) |
Other Comprehensive Income/(Loss), Net of Tax | | 26,823 | | | (2,168) | | | (27,316) |
Comprehensive Income Attributable to Noncontrolling Interests | | (7,682) | | | (7,132) | | | (5,820) |
Comprehensive Income Attributable to Controlling Interest | $ | 812,830 | | $ | 523,777 | | $ | 367,377 |
| | | | | | | | | | | |
The accompanying notes are an integral part of these consolidated financial statements. |
| | | | | | | | | | |
EVERSOURCE ENERGY AND SUBSIDIARIES |
CONSOLIDATED STATEMENTS OF CASH FLOWS |
|
| | | | | | | | | | |
| | | | | | | | | | |
| | | For the Years Ended December 31, |
(Thousands of Dollars) | 2015 | | 2014 | | 2013 |
| | | | | | | | | | |
Operating Activities: | | | | | | | | |
| Net Income | $ | 886,004 | | $ | 827,065 | | $ | 793,689 |
| Adjustments to Reconcile Net Income to Net Cash Flows | | | | | | | | |
| | Provided by Operating Activities: | | | | | | | | |
| | Depreciation | | 665,856 | | | 614,657 | | | 610,777 |
| | Deferred Income Taxes | | 491,736 | | | 443,259 | | | 431,413 |
| | Pension, SERP and PBOP Expense | | 96,017 | | | 99,056 | | | 195,698 |
| | Pension and PBOP Contributions | | (162,452) | | | (211,649) | | | (342,184) |
| | Regulatory (Under)/Over Recoveries, Net | | (163,287) | | | 6,853 | | | (24,276) |
| | Amortization of Regulatory Assets, Net | | 22,339 | | | 10,704 | | | 206,322 |
| | Amortization of Rate Reduction Bonds | | - | | | - | | | 42,581 |
| | (Payments)/Refunds Related to Spent Nuclear Fuel, Net | | (297,253) | | | 132,138 | | | - |
| | Other | | (91,945) | | | 39,523 | | | 56,071 |
| Changes in Current Assets and Liabilities: | | | | | | | | |
| | Receivables and Unbilled Revenues, Net | | (39,797) | | | (122,139) | | | (163,549) |
| | Fuel, Materials and Supplies | | 34,112 | | | (41,310) | | | (14,811) |
| | Taxes Receivable/Accrued, Net | | 30,282 | | | (323,224) | | | (50,950) |
| | Accounts Payable | | (91,618) | | | 144,743 | | | (54,619) |
| | Other Current Assets and Liabilities, Net | | 44,031 | | | 15,797 | | | (22,623) |
Net Cash Flows Provided by Operating Activities | | 1,424,025 | | | 1,635,473 | | | 1,663,539 |
| | | | | | | | | | |
Investing Activities: | | | | | | | | |
| Investments in Property, Plant and Equipment | | (1,724,139) | | | (1,603,744) | | | (1,456,787) |
| Proceeds from Sales of Marketable Securities | | 799,165 | | | 488,789 | | | 627,532 |
| Purchases of Marketable Securities | | (717,114) | | | (491,220) | | | (679,784) |
| Other Investing Activities | | (17,062) | | | 14,380 | | | 67,816 |
Net Cash Flows Used in Investing Activities | | (1,659,150) | | | (1,591,795) | | | (1,441,223) |
| | | | | | | | | | |
Financing Activities: | | | | | | | | |
| Cash Dividends on Common Shares | | (529,791) | | | (475,227) | | | (462,741) |
| Cash Dividends on Preferred Stock | | (7,519) | | | (7,519) | | | (7,682) |
| (Decrease)/Increase in Short-Term Debt | | (242,122) | | | 285,075 | | | (397,000) |
| Issuance of Long-Term Debt | | 1,225,000 | | | 725,000 | | | 1,680,000 |
| Retirements of Long-Term Debt | | (216,700) | | | (576,551) | | | (929,885) |
| Retirements of Rate Reduction Bonds | | - | | | - | | | (82,139) |
| Other Financing Activities | | (8,499) | | | 883 | | | (25,253) |
Net Cash Flows Provided by/(Used in) Financing Activities | | 220,369 | | | (48,339) | | | (224,700) |
Net Decrease in Cash and Cash Equivalents | | (14,756) | | | (4,661) | | | (2,384) |
Cash and Cash Equivalents - Beginning of Year | | 38,703 | | | 43,364 | | | 45,748 |
Cash and Cash Equivalents - End of Year | $ | 23,947 | | $ | 38,703 | | $ | 43,364 |
| | | | | | | | | | |
The accompanying notes are an integral part of these consolidated financial statements. |
| | | | | | | | | | |
75
| | | | | | | | | |
NORTHEAST UTILITIES AND SUBSIDIARIES |
CONSOLIDATED STATEMENTS OF COMMON SHAREHOLDERS' EQUITY |
| | | | | | | | | |
| | | | | | | Accumulated | | Total |
| | | | | Capital | | Other | | Common |
| | | Common Shares | Surplus, | Retained | Comprehensive | Treasury | Shareholders' |
(Thousands of Dollars, Except Share Information) | Shares | Amount | Paid In | Earnings | Income/(Loss) | Stock | Equity |
Balance as of January 1, 2011 | 176,448,081 | $ 978,909 | $ 1,777,592 | $ 1,452,777 | $ (43,370) | $ (354,732) | $ 3,811,176 |
| Net Income | | | | 400,513 | | | 400,513 |
| Dividends on Common Shares - $1.10 Per Share | | | | (195,595) | | | (195,595) |
| Dividends on Preferred Stock | | | | (5,559) | | | (5,559) |
| Issuance of Common Shares, $5 Par Value | 271,030 | 1,355 | 4,496 | | | | 5,851 |
| Long-Term Incentive Plan Activity | | | 7,359 | | | | 7,359 |
| Issuance of Treasury Shares to Fund ESOP | 439,581 | | 7,048 | | | 8,065 | 15,113 |
| Other Changes in Shareholders' Equity | | | 1,389 | | | | 1,389 |
| Net Income Attributable to Noncontrolling Interests | | | | (261) | | | (261) |
| Other Comprehensive Loss | | | | | (27,316) | | (27,316) |
Balance as of December 31, 2011 | 177,158,692 | 980,264 | 1,797,884 | 1,651,875 | (70,686) | (346,667) | 4,012,670 |
| Net Income | | | | 533,077 | | | 533,077 |
| Shares Issued in Connection with NSTAR Merger | 136,048,595 | 680,243 | 4,358,027 | | | | 5,038,270 |
| Other Equity Impacts of Merger with NSTAR | | | 2,938 | 421 | | | 3,359 |
| Dividends on Common Shares - $1.32 Per Share | | | | (375,527) | | | (375,527) |
| Dividends on Preferred Stock | | | | (7,029) | | | (7,029) |
| Issuance of Common Shares, $5 Par Value | 408,018 | 2,040 | 11,287 | | | | 13,327 |
| Long-Term Incentive Plan Activity | | | (3,897) | | | | (3,897) |
| Issuance of Treasury Shares to Fund ESOP | 438,329 | | 8,454 | | | 8,043 | 16,497 |
| Other Changes in Shareholders' Equity | | | 8,574 | | | | 8,574 |
| Net Income Attributable to Noncontrolling Interests | | | | (103) | | | (103) |
| Other Comprehensive Loss | | | | | (2,168) | | (2,168) |
Balance as of December 31, 2012 | 314,053,634 | 1,662,547 | 6,183,267 | 1,802,714 | (72,854) | (338,624) | 9,237,050 |
| Net Income | | | | 793,689 | | | 793,689 |
| Dividends on Common Shares - $1.47 Per Share | | | | (462,741) | | | (462,741) |
| Dividends on Preferred Stock | | | | (7,682) | | | (7,682) |
| Issuance of Common Shares, $5 Par Value | 560,848 | 2,804 | 8,274 | | | | 11,078 |
| Long-Term Incentive Plan Activity | | | (10,748) | | | | (10,748) |
| Issuance of Treasury Shares | 659,077 | | 17,381 | | | 12,087 | 29,468 |
| Other Changes in Shareholders' Equity | | | (5,409) | | | | (5,409) |
| Other Comprehensive Income | | | | | 26,823 | | 26,823 |
Balance as of December 31, 2013 | 315,273,559 | $ 1,665,351 | $ 6,192,765 | $ 2,125,980 | $ (46,031) | $ (326,537) | $ 9,611,528 |
| | | | | | | | | |
| | | | | | | | | |
| | | | | | | | | |
The accompanying notes are an integral part of these consolidated financial statements. |
76
| | | | | | | | | | |
NORTHEAST UTILITIES AND SUBSIDIARIES |
CONSOLIDATED STATEMENTS OF CASH FLOWS |
|
| | | | | | | | | | |
| | | | | | | | | | |
| | | For the Years Ended December 31, |
(Thousands of Dollars) | 2013 | | 2012 | | 2011 |
| | | | | | | | | | |
Operating Activities: | | | | | | | | |
| Net Income | $ | 793,689 | | $ | 533,077 | | $ | 400,513 |
| Adjustments to Reconcile Net Income to Net Cash Flows | | | | | | | | |
| | Provided by Operating Activities: | | | | | | | | |
| | Depreciation | | 610,777 | | | 519,010 | | | 302,192 |
| | Deferred Income Taxes | | 431,413 | | | 292,000 | | | 196,761 |
| | Pension, SERP and PBOP Expense | | 195,698 | | | 218,540 | | | 133,000 |
| | Pension and PBOP Contributions | | (342,184) | | | (295,028) | | | (191,101) |
| | Regulatory Underrecoveries, Net | | (24,276) | | | (259,853) | | | (70,863) |
| | Amortization of Regulatory Assets, Net | | 206,322 | | | 79,762 | | | 91,080 |
| | Amortization of Rate Reduction Bonds | | 42,581 | | | 142,019 | | | 69,912 |
| | Other | | 56,071 | | | 42,852 | | | (48,772) |
| Changes in Current Assets and Liabilities: | | | | | | | | |
| | Receivables and Unbilled Revenues, Net | | (163,549) | | | (20,214) | | | 17,570 |
| | Fuel, Materials and Supplies | | (14,811) | | | 34,321 | | | (11,033) |
| | Taxes Receivable/Accrued, Net | | (50,950) | | | (5,450) | | | 49,642 |
| | Accounts Payable | | (54,619) | | | (128,339) | | | 18,916 |
| | Other Current Assets and Liabilities, Net | | (22,623) | | | 8,532 | | | 12,569 |
Net Cash Flows Provided by Operating Activities | | 1,663,539 | | | 1,161,229 | | | 970,386 |
| | | | | | | | | | |
Investing Activities: | | | | | | | | |
| Investments in Property, Plant and Equipment | | (1,456,787) | | | (1,472,272) | | | (1,076,730) |
| Proceeds from Sales of Marketable Securities | | 627,532 | | | 317,294 | | | 149,441 |
| Purchases of Marketable Securities | | (679,784) | | | (348,629) | | | (151,972) |
| Other Investing Activities | | 67,816 | | | 35,683 | | | 60,674 |
Net Cash Flows Used in Investing Activities | | (1,441,223) | | | (1,467,924) | | | (1,018,587) |
| | | | | | | | | | |
Financing Activities: | | | | | | | | |
| Cash Dividends on Common Shares | | (462,741) | | | (375,047) | | | (194,555) |
| Cash Dividends on Preferred Stock | | (7,682) | | | (7,029) | | | (5,559) |
| (Decrease)/Increase in Short-Term Debt | | (397,000) | | | 825,000 | | | 50,000 |
| Issuance of Long-Term Debt | | 1,680,000 | | | 850,000 | | | 627,500 |
| Retirements of Long-Term Debt | | (929,885) | | | (839,136) | | | (369,586) |
| Retirements of Rate Reduction Bonds | | (82,139) | | | (114,433) | | | (69,312) |
| Other Financing Activities | | (25,253) | | | 6,529 | | | (7,123) |
Net Cash Flows (Used in)/Provided by Financing Activities | | (224,700) | | | 345,884 | | | 31,365 |
Net (Decrease)/Increase in Cash and Cash Equivalents | | (2,384) | | | 39,189 | | | (16,836) |
Cash and Cash Equivalents - Beginning of Year | | 45,748 | | | 6,559 | | | 23,395 |
Cash and Cash Equivalents - End of Year | $ | 43,364 | | $ | 45,748 | | $ | 6,559 |
| | | | | | | | | | |
The accompanying notes are an integral part of these consolidated financial statements. |
| | | | | | | | | | |
7767
Company Report on Internal Controls Over Financial Reporting
The Connecticut Light and Power Company
Management is responsible for the preparation, integrity, and fair presentation of the accompanying financial statements of The Connecticut Light and Power Company (CL&P or the Company) and of other sections of this annual report.
Management is responsible for establishing and maintaining adequate internal controls over financial reporting. The Company’sCompany's internal control framework and processes have been designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with accounting principles generally accepted accounting principles.in the United States of America. There are inherent limitations of internal controls over financial reporting that could allow material misstatements due to error or fraud to occur and not be prevented or detected on a timely basis by employees during the normal course of business. Additionally, internal controls over financial reporting may become inadequate in the future due to changes in the business environment.
Under the supervision and with the participation of the principal executive officer and principal financial officer, CL&P conducted an evaluation of the effectiveness of internal controls over financial reporting based on criteria established inInternal Control – Integrated Framework (2013)(1992 Framework) issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO). Based on this evaluation under the framework in COSO, management concluded that internal controls over financial reporting were effective as of December 31, 2013.2015.
February 25, 201426, 2016
7868
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
To the Board of Directors and Stockholder of The Connecticut Light and Power Company:
We have audited the accompanying balance sheets of The Connecticut Light and Power Company (the "Company") as of December 31, 20132015 and 2012,2014, and the related statements of income, comprehensive income, common stockholder’sstockholder's equity, and cash flows for each of the three years in the period ended December 31, 2013.2015. Our audits also included the financial statement schedule listed in the Index at Item 15 of Part IV. These financial statements and financial statement schedule are the responsibility of the Company's management. Our responsibility is to express an opinion on the financial statements and financial statement schedule based on our audits.
We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. The Company is not required to have, nor were we engaged to perform, an audit of its internal control over financial reporting. Our audits included consideration of internal control over financial reporting as a basis for designing audit procedures that are appropriate in the circumstances, but not for the purpose of expressing an opinion on the effectiveness of the Company's internal control over financial reporting. Accordingly, we express no such opinion. An audit also includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.
In our opinion, such financial statements present fairly, in all material respects, the financial position of The Connecticut Light and Power Company as of December 31, 20132015 and 2012,2014, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2013,2015, in conformity with accounting principles generally accepted in the United States of America. Also, in our opinion, such financial statement schedule, when considered in relation to the basic financial statements taken as a whole, presents fairly in all material respects the information set forth therein.
/s/ Deloitte & Touche LLP
Hartford, Connecticut
February 25, 201426, 2016
7969
|
THE CONNECTICUT LIGHT AND POWER COMPANY | THE CONNECTICUT LIGHT AND POWER COMPANY | THE CONNECTICUT LIGHT AND POWER COMPANY |
BALANCE SHEETS | BALANCE SHEETS | BALANCE SHEETS |
| | |
| | | | | | | | | | | |
| | As of December 31, | | | As of December 31, |
(Thousands of Dollars) | (Thousands of Dollars) | 2013 | | 2012 | (Thousands of Dollars) | 2015 | | 2014 |
| | | | | | | | | | | |
ASSETS | ASSETS | | | | | ASSETS | | | | |
| | | | | | | | | | | |
Current Assets: | Current Assets: | | | | | Current Assets: | | | | |
| Cash | $ | 7,237 | | $ | 1 | Cash | $ | 1,057 | | $ | 2,356 |
| Receivables, Net | | 319,670 | | 284,787 | Receivables, Net | | 352,536 | | 355,140 |
| Accounts Receivable from Affiliated Companies | | 13,777 | | 6,641 | Accounts Receivable from Affiliated Companies | | 21,214 | | 16,757 |
| Unbilled Revenues | | 92,401 | | 85,353 | Unbilled Revenues | | 99,879 | | 102,137 |
| Regulatory Assets | | 150,943 | | 185,858 | Taxes Receivable | | 137,643 | | 116,148 |
| Materials and Supplies | | 54,606 | | 64,603 | Regulatory Assets | | 268,318 | | 220,344 |
| Prepayments and Other Current Assets | | 53,082 | | | 26,413 | Materials and Supplies | | 43,124 | | 46,664 |
| Prepayments and Other Current Assets | | 32,234 | | | 37,822 |
Total Current Assets | Total Current Assets | | 691,716 | | | 653,656 | Total Current Assets | | 956,005 | | | 897,368 |
| | | | | | | | | | |
Property, Plant and Equipment, Net | Property, Plant and Equipment, Net | | 6,451,259 | | | 6,152,959 | Property, Plant and Equipment, Net | | 7,156,809 | | | 6,809,664 |
| | | | | | | | | | |
Deferred Debits and Other Assets: | Deferred Debits and Other Assets: | | | | | Deferred Debits and Other Assets: | | | | |
| Regulatory Assets | | 1,663,147 | | 2,158,363 | Regulatory Assets | | 1,369,028 | | 1,475,508 |
| Derivative Assets | | 71,384 | | 90,612 | Other Long-Term Assets | | 111,115 | | | 161,860 |
Total Deferred Debits and Other Assets | | 1,480,143 | | | 1,637,368 |
| Other Long-Term Assets | | 102,996 | | | 86,498 | | | | | | |
Total Deferred Debits and Other Assets | | 1,837,527 | | | 2,335,473 |
Total Assets | $ | 9,592,957 | | $ | 9,344,400 |
| | | | | | |
LIABILITIES AND CAPITALIZATION | | | | |
| | | | | | |
Current Liabilities: | | | | |
| | | | | | Notes Payable to Eversource Parent | $ | 277,400 | | $ | 133,400 |
| | | | | | Long-Term Debt - Current Portion | | - | | 162,000 |
| | | | | | Accounts Payable | | 267,764 | | 272,971 |
Total Assets | $ | 8,980,502 | | $ | 9,142,088 |
| Accounts Payable to Affiliated Companies | | 66,456 | | 65,594 |
| Obligations to Third Party Suppliers | | 60,746 | | 73,624 |
| Regulatory Liabilities | | 61,155 | | 124,722 |
| Derivative Liabilities | | 91,820 | | 88,459 |
| Other Current Liabilities | | 110,631 | | | 153,420 |
Total Current Liabilities | | 935,972 | | | 1,074,190 |
| | | | | | |
Deferred Credits and Other Liabilities: | | | | |
| Accumulated Deferred Income Taxes | | 1,820,865 | | 1,642,805 |
| Regulatory Liabilities | | 74,830 | | 81,298 |
| Derivative Liabilities | | 336,189 | | 406,199 |
| Accrued Pension, SERP and PBOP | | 271,056 | | 273,854 |
| Other Long-Term Liabilities | | 133,446 | | | 148,844 |
Total Deferred Credits and Other Liabilities | | 2,636,386 | | | 2,553,000 |
| | | | | | |
Capitalization: | | | | |
| Long-Term Debt | | 2,763,682 | | | 2,664,243 |
| | | | | | |
Preferred Stock Not Subject to Mandatory Redemption | | 116,200 | | | 116,200 |
| | | | | | |
| Common Stockholder's Equity: | | | | |
| | Common Stock | | 60,352 | | 60,352 |
| | Capital Surplus, Paid In | | 1,910,663 | | 1,804,869 |
| | Retained Earnings | | 1,170,278 | | 1,072,477 |
| | Accumulated Other Comprehensive Loss | | (576) | | | (931) |
| Common Stockholder's Equity | | 3,140,717 | | | 2,936,767 |
Total Capitalization | | 6,020,599 | | | 5,717,210 |
| | | | | | |
Commitments and Contingencies (Note 11) | | | | |
| | | | | | |
Total Liabilities and Capitalization | $ | 9,592,957 | | $ | 9,344,400 |
| | | | | | | | | | | |
| | | | | | | | | | | |
| | | | | | | | | | | |
The accompanying notes are an integral part of these financial statements. | The accompanying notes are an integral part of these financial statements. | The accompanying notes are an integral part of these financial statements. |
8070
| | | | | | | |
THE CONNECTICUT LIGHT AND POWER COMPANY |
BALANCE SHEETS |
|
| | | | | | | |
| | | As of December 31, |
(Thousands of Dollars) | 2013 | | 2012 |
| | | | | | | |
LIABILITIES AND CAPITALIZATION | | | | | |
| | | | | | | |
Current Liabilities: | | | | | |
| Notes Payable to Affiliated Companies | $ | 287,300 | | $ | 99,296 |
| Long-Term Debt - Current Portion | | 150,000 | | | 125,000 |
| Accounts Payable | | 201,047 | | | 262,857 |
| Accounts Payable to Affiliated Companies | | 56,531 | | | 52,326 |
| Obligations to Third Party Suppliers | | 73,914 | | | 67,344 |
| Accrued Taxes | | 37,186 | | | 60,109 |
| Regulatory Liabilities | | 93,961 | | | 32,119 |
| Derivative Liabilities | | 92,233 | | | 96,931 |
| Other Current Liabilities | | 97,530 | | | 125,662 |
Total Current Liabilities | | 1,089,702 | | | 921,644 |
| | | | | | | |
Deferred Credits and Other Liabilities: | | | | | |
| Accumulated Deferred Income Taxes | | 1,510,586 | | | 1,336,105 |
| Regulatory Liabilities | | 93,757 | | | 124,319 |
| Derivative Liabilities | | 617,072 | | | 865,571 |
| Accrued Pension, SERP and PBOP | | 95,895 | | | 304,696 |
| Other Long-Term Liabilities | | 163,588 | | | 197,434 |
Total Deferred Credits and Other Liabilities | | 2,480,898 | | | 2,828,125 |
| | | | | | | |
Capitalization: | | | | | |
| Long-Term Debt | | 2,591,208 | | | 2,737,790 |
| | | | | | | |
Preferred Stock Not Subject to Mandatory Redemption | | 116,200 | | | 116,200 |
| | | | | | | |
| Common Stockholder's Equity: | | | | | |
| | Common Stock | | 60,352 | | | 60,352 |
| | Capital Surplus, Paid In | | 1,682,047 | | | 1,640,149 |
| | Retained Earnings | | 961,482 | | | 839,628 |
| | Accumulated Other Comprehensive Loss | | (1,387) | | | (1,800) |
| Common Stockholder's Equity | | 2,702,494 | | | 2,538,329 |
Total Capitalization | | 5,409,902 | | | 5,392,319 |
| | | | | | | |
Commitments and Contingencies (Note 12) | | | | | |
| | | | | | | |
Total Liabilities and Capitalization | $ | 8,980,502 | | $ | 9,142,088 |
| | | | | | | |
| | | | | | | |
| | | | | | | |
The accompanying notes are an integral part of these financial statements. |
| | | | | | | | | | |
THE CONNECTICUT LIGHT AND POWER COMPANY |
STATEMENTS OF INCOME |
|
| | | | | | | | | | |
| | | | | | | | | | |
| | | For the Years Ended December 31, |
(Thousands of Dollars) | 2015 | | 2014 | | 2013 |
| | | | | | | | | | |
Operating Revenues | $ | 2,802,675 | | $ | 2,692,582 | | $ | 2,442,341 |
| | | | | | | | | | |
Operating Expenses: | | | | | | | | |
| Purchased Power and Transmission | | 1,054,313 | | | 982,876 | | | 872,769 |
| Operations and Maintenance | | 487,281 | | | 494,578 | | | 523,247 |
| Depreciation | | 215,289 | | | 188,837 | | | 177,603 |
| Amortization of Regulatory Assets, Net | | 12,318 | | | 59,336 | | | 4,870 |
| Energy Efficiency Programs | | 153,725 | | | 156,335 | | | 89,858 |
| Taxes Other Than Income Taxes | | 268,688 | | | 255,370 | | | 234,418 |
| | Total Operating Expenses | | 2,191,614 | | | 2,137,332 | | | 1,902,765 |
Operating Income | | 611,061 | | | 555,250 | | | 539,576 |
Interest Expense | | 145,795 | | | 147,421 | | | 133,650 |
Other Income, Net | | 11,490 | | | 13,376 | | | 15,149 |
Income Before Income Tax Expense | | 476,756 | | | 421,205 | | | 421,075 |
Income Tax Expense | | 177,396 | | | 133,451 | | | 141,663 |
Net Income | $ | 299,360 | | $ | 287,754 | | $ | 279,412 |
| | | | | | | | | | |
| | | | | | | | | | |
| | | | | | | | | | |
The accompanying notes are an integral part of these financial statements. |
| | | | | | | | | | |
| | | | | | | | | | |
| | | | | | | | | | |
| | | | | | | | | | |
STATEMENTS OF COMPREHENSIVE INCOME | | | | | | |
| | | | | | | | | | |
Net Income | $ | 299,360 | | $ | 287,754 | | $ | 279,412 |
Other Comprehensive Income, Net of Tax: | | | | | | | | |
| Qualified Cash Flow Hedging Instruments | | 444 | | | 444 | | | 444 |
| Changes in Unrealized (Losses)/Gains on Marketable Securities | | (89) | | | 12 | | | (31) |
Other Comprehensive Income, Net of Tax | | 355 | | | 456 | | | 413 |
Comprehensive Income | $ | 299,715 | | $ | 288,210 | | $ | 279,825 |
| | | | | | | | | | |
| | | | | | | | | | |
| | | | | | | | | | |
The accompanying notes are an integral part of these financial statements. |
8171
| | | | | | | | | | |
THE CONNECTICUT LIGHT AND POWER COMPANY |
STATEMENTS OF INCOME |
|
| | | | | | | | | | |
| | | | | | | | | | |
| | | For the Years Ended December 31, |
(Thousands of Dollars) | 2013 | | 2012 | | 2011 |
| | | | | | | | | | |
Operating Revenues | $ | 2,442,341 | | $ | 2,407,449 | | $ | 2,548,387 |
| | | | | | | | | | |
Operating Expenses: | | | | | | | | |
| Purchased Power and Transmission | | 872,769 | | | 858,231 | | | 982,514 |
| Operations and Maintenance | | 523,247 | | | 635,733 | | | 580,736 |
| Depreciation | | 177,603 | | | 166,853 | | | 157,747 |
| Amortization of Regulatory Assets, Net | | 4,870 | | | 14,372 | | | 61,025 |
| Energy Efficiency Programs | | 89,858 | | | 89,299 | | | 90,297 |
| Taxes Other Than Income Taxes | | 234,418 | | | 215,972 | | | 212,885 |
| | Total Operating Expenses | | 1,902,765 | | | 1,980,460 | | | 2,085,204 |
Operating Income | | 539,576 | | | 426,989 | | | 463,183 |
| | | | | | | | | | |
Interest Expense: | | | | | | | | |
| Interest on Long-Term Debt | | 130,620 | | | 124,894 | | | 131,918 |
| Other Interest | | 3,030 | | | 8,233 | | | 809 |
| | Interest Expense | | 133,650 | | | 133,127 | | | 132,727 |
Other Income, Net | | 15,149 | | | 10,300 | | | 9,741 |
Income Before Income Tax Expense | | 421,075 | | | 304,162 | | | 340,197 |
Income Tax Expense | | 141,663 | | | 94,437 | | | 90,033 |
Net Income | $ | 279,412 | | $ | 209,725 | | $ | 250,164 |
| | | | | | | | | | |
| | | | | | | | | | |
| | | | | | | | | | |
The accompanying notes are an integral part of these financial statements. |
| | | | | | | | | | |
| | | | | | | | | | |
| | | | | | | | | | |
| | | | | | | | | | |
STATEMENTS OF COMPREHENSIVE INCOME | | | | | | |
| | | | | | | | | | |
Net Income | $ | 279,412 | | $ | 209,725 | | $ | 250,164 |
Other Comprehensive Income, Net of Tax: | | | | | | | | |
| Qualified Cash Flow Hedging Instruments | | 444 | | | 444 | | | 445 |
| Changes in Unrealized Gains/(Losses) on Other | | | | | | | | |
| | Securities | | (31) | | | 7 | | | 17 |
Other Comprehensive Income, Net of Tax | | 413 | | | 451 | | | 462 |
Comprehensive Income | $ | 279,825 | | $ | 210,176 | | $ | 250,626 |
| | | | | | | | | | |
| | | | | | | | | | |
| | | | | | | | | | |
The accompanying notes are an integral part of these financial statements. |
| | | | | | | | | | | | | | | | | | |
THE CONNECTICUT LIGHT AND POWER COMPANY |
STATEMENTS OF COMMON STOCKHOLDER'S EQUITY |
| | | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | Accumulated | | | Total |
| | | | | | | | | Capital | | | | | | Other | | | Common |
| | | Common Stock | | | Surplus, | | | Retained | | | Comprehensive | | | Stockholder's |
(Thousands of Dollars, Except Stock Information) | Stock | | | Amount | | | Paid In | | | Earnings | | | Income/(Loss) | | | Equity |
Balance as of January 1, 2013 | 6,035,205 | | $ | 60,352 | | $ | 1,640,149 | | $ | 839,628 | | $ | (1,800) | | $ | 2,538,329 |
| Net Income | | | | | | | | | | 279,412 | | | | | | 279,412 |
| Dividends on Preferred Stock | | | | | | | | | | (5,559) | | | | | | (5,559) |
| Dividends on Common Stock | | | | | | | | | | (151,999) | | | | | | (151,999) |
| Allocation of Benefits - ESOP | | | | | | | 1,847 | | | | | | | | | 1,847 |
| Capital Stock Expenses, Net | | | | | | | 51 | | | | | | | | | 51 |
| Capital Contributions from Eversource Parent | | | | | | | 40,000 | | | | | | | | | 40,000 |
| Other Comprehensive Income | | | | | | | | | | | | | 413 | | | 413 |
Balance as of December 31, 2013 | 6,035,205 | | | 60,352 | | | 1,682,047 | | | 961,482 | | | (1,387) | | | 2,702,494 |
| Net Income | | | | | | | | | | 287,754 | | | | | | 287,754 |
| Dividends on Preferred Stock | | | | | | | | | | (5,559) | | | | | | (5,559) |
| Dividends on Common Stock | | | | | | | | | | (171,200) | | | | | | (171,200) |
| Allocation of Benefits - ESOP | | | | | | | 2,771 | | | | | | | | | 2,771 |
| Capital Stock Expenses, Net | | | | | | | 51 | | | | | | | | | 51 |
| Capital Contributions from Eversource Parent | | | | | | | 120,000 | | | | | | | | | 120,000 |
| Other Comprehensive Income | | | | | | | | | | | | | 456 | | | 456 |
Balance as of December 31, 2014 | 6,035,205 | | | 60,352 | | | 1,804,869 | | | 1,072,477 | | | (931) | | | 2,936,767 |
| Net Income | | | | | | | | | | 299,360 | | | | | | 299,360 |
| Dividends on Preferred Stock | | | | | | | | | | (5,559) | | | | | | (5,559) |
| Dividends on Common Stock | | | | | | | | | | (196,000) | | | | | | (196,000) |
| Allocation of Benefits - ESOP | | | | | | | 743 | | | | | | | | | 743 |
| Capital Stock Expenses, Net | | | | | | | 51 | | | | | | | | | 51 |
| Capital Contributions from Eversource Parent | | | | | | | 105,000 | | | | | | | | | 105,000 |
| Other Comprehensive Income | | | | | | | | | | | | | 355 | | | 355 |
Balance as of December 31, 2015 | 6,035,205 | | $ | 60,352 | | $ | 1,910,663 | | $ | 1,170,278 | | $ | (576) | | $ | 3,140,717 |
| | | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | | |
The accompanying notes are an integral part of these financial statements. |
8272
| | | | | | | | |
THE CONNECTICUT LIGHT AND POWER COMPANY |
STATEMENTS OF COMMON STOCKHOLDER'S EQUITY |
| | | | | | | | |
| | | | | | | Accumulated | Total |
| | | | | Capital | | Other | Common |
| | | Common Stock | Surplus, | Retained | Comprehensive | Stockholder's |
(Thousands of Dollars, Except Stock Information) | Stock | Amount | Paid In | Earnings | Income/(Loss) | Equity |
Balance as of January 1, 2011 | 6,035,205 | $ 60,352 | $ 1,605,275 | $ 734,561 | $ (2,713) | $ 2,397,475 |
| Net Income | | | | 250,164 | | 250,164 |
| Dividends on Preferred Stock | | | | (5,559) | | (5,559) |
| Dividends on Common Stock | | | | (243,218) | | (243,218) |
| Allocation of Benefits - ESOP | | | 1,429 | | | 1,429 |
| Capital Stock Expenses, Net | | | 51 | | | 51 |
| Capital Contributions from NU Parent | | | 6,748 | | | 6,748 |
| Other Comprehensive Income | | | | | 462 | 462 |
Balance as of December 31, 2011 | 6,035,205 | 60,352 | 1,613,503 | 735,948 | (2,251) | 2,407,552 |
| Net Income | | | | 209,725 | | 209,725 |
| Dividends on Preferred Stock | | | | (5,559) | | (5,559) |
| Dividends on Common Stock | | | | (100,486) | | (100,486) |
| Allocation of Benefits - ESOP | | | 1,595 | | | 1,595 |
| Capital Stock Expenses, Net | | | 51 | | | 51 |
| Capital Contributions from NU Parent | | | 25,000 | | | 25,000 |
| Other Comprehensive Income | | | | | 451 | 451 |
Balance as of December 31, 2012 | 6,035,205 | 60,352 | 1,640,149 | 839,628 | (1,800) | 2,538,329 |
| Net Income | | | | 279,412 | | 279,412 |
| Dividends on Preferred Stock | | | | (5,559) | | (5,559) |
| Dividends on Common Stock | | | | (151,999) | | (151,999) |
| Allocation of Benefits - ESOP | | | 1,847 | | | 1,847 |
| Capital Stock Expenses, Net | | | 51 | | | 51 |
| Capital Contributions from NU Parent | | | 40,000 | | | 40,000 |
| Other Comprehensive Income | | | | | 413 | 413 |
Balance as of December 31, 2013 | 6,035,205 | $ 60,352 | $ 1,682,047 | $ 961,482 | $ (1,387) | $ 2,702,494 |
| | | | | | | | |
| | | | | | | | |
| | | | | | | | |
The accompanying notes are an integral part of these financial statements. |
| | | | | | | | | | |
THE CONNECTICUT LIGHT AND POWER COMPANY |
STATEMENTS OF CASH FLOWS |
|
| | | | | | | | | | |
| | | | | | | | | | |
| | | For the Years Ended December 31, |
(Thousands of Dollars) | 2015 | | 2014 | | 2013 |
| | | | | | | | | | |
Operating Activities: | | | | | | | | |
| Net Income | $ | 299,360 | | $ | 287,754 | | $ | 279,412 |
| Adjustments to Reconcile Net Income to Net Cash Flows | | | | | | | | |
| | Provided by Operating Activities: | | | | | | | | |
| | Depreciation | | 215,289 | | | 188,837 | | | 177,603 |
| | Deferred Income Taxes | | 135,994 | | | 130,949 | | | 130,038 |
| | Pension, SERP and PBOP Expense, Net of PBOP Contributions | | 14,091 | | | 14,992 | | | 24,416 |
| | Regulatory (Under)/Over Recoveries, Net | | (53,781) | | | (20,502) | | | 28,298 |
| | Amortization of Regulatory Assets, Net | | 12,318 | | | 59,336 | | | 4,870 |
| | (Payments)/Refunds Related to Spent Nuclear Fuel, Net | | (242,231) | | | 68,610 | | | - |
| | Other | | (36,385) | | | (1,342) | | | (3,478) |
| Changes in Current Assets and Liabilities: | | | | | | | | |
| | Receivables and Unbilled Revenues, Net | | (29,195) | | | (78,631) | | | (56,593) |
| | Materials and Supplies | | 22,810 | | | 13,063 | | | 9,997 |
| | Taxes Receivable/Accrued, Net | | (13,517) | | | (126,376) | | | (41,594) |
| | Accounts Payable | | (16,910) | | | 68,891 | | | (66,225) |
| | Other Current Assets and Liabilities, Net | | (9,514) | | | 6,838 | | | 8,513 |
Net Cash Flows Provided by Operating Activities | | 298,329 | | | 612,419 | | | 495,257 |
| | | | | | | | | | |
Investing Activities: | | | | | | | | |
| Investments in Property, Plant and Equipment | | (523,849) | | | (515,710) | | | (434,934) |
| Other Investing Activities | | (716) | | | 12,653 | | | 2,650 |
Net Cash Flows Used in Investing Activities | | (524,565) | | | (503,057) | | | (432,284) |
| | | | | | | | | | |
Financing Activities: | | | | | | | | |
| Cash Dividends on Common Stock | | (196,000) | | | (171,200) | | | (151,999) |
| Cash Dividends on Preferred Stock | | (5,559) | | | (5,559) | | | (5,559) |
| Decrease in Short-Term Debt | | - | | | - | | | (89,000) |
| Increase/(Decrease) in Notes Payable to Eversource Parent | | 144,000 | | | (153,900) | | | (117,800) |
| Issuance of Long-Term Debt | | 350,000 | | | 250,000 | | | 400,000 |
| Retirements of Long-Term Debt | | (162,000) | | | (150,000) | | | (125,000) |
| Capital Contributions from Eversource Parent | | 105,000 | | | 120,000 | | | 40,000 |
| Other Financing Activities | | (10,504) | | | (3,584) | | | (6,379) |
Net Cash Flows Provided by/(Used in) Financing Activities | | 224,937 | | | (114,243) | | | (55,737) |
Net (Decrease)/Increase in Cash | | (1,299) | | | (4,881) | | | 7,236 |
Cash - Beginning of Year | | 2,356 | | | 7,237 | | | 1 |
Cash - End of Year | $ | 1,057 | | $ | 2,356 | | $ | 7,237 |
| | | | | | | | | | |
The accompanying notes are an integral part of these financial statements. |
83
| | | | | | | | | | |
THE CONNECTICUT LIGHT AND POWER COMPANY |
STATEMENTS OF CASH FLOWS |
|
| | | | | | | | | | |
| | | | | | | | | | |
| | | For the Years Ended December 31, |
(Thousands of Dollars) | 2013 | | 2012 | | 2011 |
| | | | | | | | | | |
Operating Activities: | | | | | | | | |
| Net Income | $ | 279,412 | | $ | 209,725 | | $ | 250,164 |
| Adjustments to Reconcile Net Income to Net Cash Flows | | | | | | | | |
| | Provided by Operating Activities: | | | | | | | | |
| | Depreciation | | 177,603 | | | 166,853 | | | 157,747 |
| | Deferred Income Taxes | | 130,038 | | | 140,993 | | | 112,620 |
| | Pension, SERP and PBOP Expense, Net of PBOP Contributions | | 24,416 | | | 24,062 | | | 10,664 |
| | Regulatory Over/(Under) Recoveries, Net | | 28,298 | | | (100,505) | | | (82,502) |
| | Amortization of Regulatory Assets, Net | | 4,870 | | | 14,372 | | | 61,025 |
| | Other | | (3,478) | | | (28,952) | | | (33,713) |
| Changes in Current Assets and Liabilities: | | | | | | | | |
| | Receivables and Unbilled Revenues, Net | | (56,593) | | | (7,741) | | | 14,610 |
| | Materials and Supplies | | 9,997 | | | (4,573) | | | (2,206) |
| | Taxes Receivable/Accrued, Net | | (41,594) | | | 15,702 | | | 2,719 |
| | Accounts Payable | | (66,225) | | | (190,240) | | | 8,864 |
| | Other Current Assets and Liabilities, Net | | 8,513 | | | (27,803) | | | 13,291 |
Net Cash Flows Provided by Operating Activities | | 495,257 | | | 211,893 | | | 513,283 |
| | | | | | | | | | |
Investing Activities: | | | | | | | | |
| Investments in Property, Plant and Equipment | | (434,934) | | | (449,137) | | | (424,865) |
| Proceeds from Sale of Assets | | - | | | - | | | 46,841 |
| Other Investing Activities | | 2,650 | | | 32,009 | | | 16,001 |
Net Cash Flows Used in Investing Activities | | (432,284) | | | (417,128) | | | (362,023) |
| | | | | | | | | | |
Financing Activities: | | | | | | | | |
| Cash Dividends on Common Stock | | (151,999) | | | (100,486) | | | (243,218) |
| Cash Dividends on Preferred Stock | | (5,559) | | | (5,559) | | | (5,559) |
| (Decrease)/Increase in Short-Term Debt | | (89,000) | | | 58,000 | | | 31,000 |
| (Decrease)/Increase in Notes Payable to Affiliate | | (117,800) | | | 346,575 | | | 52,300 |
| Issuance of Long-Term Debt | | 400,000 | | | - | | | 245,500 |
| Retirements of Long-Term Debt | | (125,000) | | | (116,400) | | | (245,500) |
| Capital Contributions from NU Parent | | 40,000 | | | 25,000 | | | 6,748 |
| Other Financing Activities | | (6,379) | | | (1,895) | | | (2,292) |
Net Cash Flows (Used in)/Provided by Financing Activities | | (55,737) | | | 205,235 | | | (161,021) |
Net Increase/(Decrease) in Cash | | 7,236 | | | - | | | (9,761) |
Cash - Beginning of Year | | 1 | | | 1 | | | 9,762 |
Cash - End of Year | $ | 7,237 | | $ | 1 | | $ | 1 |
| | | | | | | | | | |
The accompanying notes are an integral part of these financial statements. |
8473
Company Report on Internal Controls Over Financial Reporting
NSTAR Electric Company
Management is responsible for the preparation, integrity, and fair presentation of the accompanying consolidated financial statements of NSTAR Electric Company and subsidiary (NSTAR Electric or the Company) and of other sections of this annual report.
Management is responsible for establishing and maintaining adequate internal controls over financial reporting. The Company’sCompany's internal control framework and processes have been designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with accounting principles generally accepted accounting principles.in the United States of America. There are inherent limitations of internal controls over financial reporting that could allow material misstatements due to error or fraud to occur and not be prevented or detected on a timely basis by employees during the normal course of business. Additionally, internal controls over financial reporting may become inadequate in the future due to changes in the business environment.
Under the supervision and with the participation of the principal executive officer and principal financial officer, NSTAR Electric conducted an evaluation of the effectiveness of internal controls over financial reporting based on criteria established inInternal Control – Integrated Framework (2013)(1992 Framework) issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO). Based on this evaluation under the framework in COSO, management concluded that internal controls over financial reporting were effective as of December 31, 2013.2015.
February 25, 201426, 2016
8574
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
To the Board of Directors and Stockholder of NSTAR Electric Company:
We have audited the accompanying consolidated balance sheets of NSTAR Electric Company and subsidiary (the "Company") as of December 31, 20132015 and 20122014 and the related consolidated statements of income, comprehensive income, common stockholder’sstockholder's equity, and cash flows for each of the twothree years in the period ended December 31, 2013.2015. Our audits also included the financial statement schedule listed in the Index at Item 15 of Part IV. These financial statements and financial statement schedule are the responsibility of the Company's management. Our responsibility is to express an opinion on the financial statements and financial statement schedule based on our audits. The consolidated financial statements and financial statement schedule of the Company for the year ended December 31, 2011 were audited by other auditors whose report, dated February 7, 2012, expressed an unqualified opinion on those statements and included an explanatory paragraph relating to the merger agreement signed with Northeast Utilities.
We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audits to obtain reasonable assurance about whether the financial statements are free of material misstatement. The Company is not required to have, nor were we engaged to perform, an audit of its internal control over financial reporting. Our audits included consideration of internal control over financial reporting as a basis for designing audit procedures that are appropriate in the circumstances, but not for the purpose of expressing an opinion on the effectiveness of the Company's internal control over financial reporting. Accordingly, we express no such opinion. An audit also includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.
In our opinion, such consolidated financial statements present fairly, in all material respects, the financial position of NSTAR Electric Company and subsidiary as of December 31, 20132015 and 2012,2014, and the results of their operations and their cash flows for each of the twothree years in the period ended December 31, 2013,2015, in conformity with accounting principles generally accepted in the United States of America. Also, in our opinion, such 2013 and 2012 financial statement schedule, when considered in relation to the basic consolidated financial statements taken as a whole, presents fairly in all material respects the information set forth therein.
/s/ Deloitte & Touche LLP
Hartford, Connecticut
February 25, 201426, 2016
86
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
To the Directors and Shareholder of NSTAR Electric Company:
In our opinion, the consolidated statements of income, common stockholder's equity, and cash flows present fairly, in all material respects, the results of operations and cash flows of NSTAR Electric Company and its subsidiaries for the year ended December 31, 2011 in conformity with accounting principles generally accepted in the United States of America. In addition, in our opinion, the financial statement schedule for the year ended December 31, 2011 listed in the index appearing under Item 15(a)(2) presents fairly, in all material respects, the information set forth therein when read in conjunction with the related consolidated financial statements. These financial statements and financial statement schedule are the responsibility of the Company’s management. Our responsibility is to express an opinion on these financial statements and financial statement schedule based on our audit. We conducted our audit of these statements in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audits to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, and evaluating the overall financial statement presentation. We believe that our audit provides a reasonable basis for our opinion.
/s/ PricewaterhouseCoopers LLP
Boston, Massachusetts
February 7, 2012
8775
|
NSTAR ELECTRIC COMPANY AND SUBSIDIARY | NSTAR ELECTRIC COMPANY AND SUBSIDIARY | NSTAR ELECTRIC COMPANY AND SUBSIDIARY |
CONSOLIDATED BALANCE SHEETS | CONSOLIDATED BALANCE SHEETS | CONSOLIDATED BALANCE SHEETS |
| | |
| | | | | | | | | | | |
| | As of December 31, | | | As of December 31, |
(Thousands of Dollars) | (Thousands of Dollars) | 2013 | | 2012 | (Thousands of Dollars) | 2015 | | 2014 |
| | | | | | | | | | | |
ASSETS | ASSETS | | | | | ASSETS | | | | |
| | | | | | | | | | | |
Current Assets: | Current Assets: | | | | | Current Assets: | | | | |
| Cash and Cash Equivalents | $ | 8,021 | | $ | 13,695 | Cash and Cash Equivalents | $ | 3,346 | | $ | 12,773 |
| Receivables, Net | | 209,711 | | 202,025 | Receivables, Net | | 229,936 | | 234,481 |
| Accounts Receivable from Affiliated Companies | | 27,264 | | 160,176 | Accounts Receivable from Affiliated Companies | | 4,034 | | 40,353 |
| Unbilled Revenues | | 41,368 | | 41,377 | Unbilled Revenues | | 29,464 | | 29,741 |
| Materials and Supplies | | 44,236 | | 26,754 | Taxes Receivable | | 70,236 | | 144,601 |
| Regulatory Assets | | 204,144 | | 347,081 | Materials and Supplies | | 75,487 | | 74,179 |
| Prepayments and Other Current Assets | | 36,710 | | | 1,332 | Regulatory Assets | | 348,408 | | 198,710 |
| Prepayments and Other Current Assets | | 11,448 | | | 10,815 |
Total Current Assets | Total Current Assets | | 571,454 | | | 792,440 | Total Current Assets | | 772,359 | | | 745,653 |
| | | | | | | | | | | |
Property, Plant and Equipment, Net | Property, Plant and Equipment, Net | | 5,043,887 | | | 4,735,297 | Property, Plant and Equipment, Net | | 5,655,458 | | | 5,335,436 |
| | | | | | | | | | | |
Deferred Debits and Other Assets: | Deferred Debits and Other Assets: | | | | | Deferred Debits and Other Assets: | | | | |
| Regulatory Assets | | 1,235,156 | | 1,444,870 | Regulatory Assets | | 1,112,977 | | 1,179,100 |
| Other Long-Term Assets | | 60,624 | | | 87,382 | Other Long-Term Assets | | 62,467 | | | 61,880 |
Total Deferred Debits and Other Assets | Total Deferred Debits and Other Assets | | 1,295,780 | | | 1,532,252 | Total Deferred Debits and Other Assets | | 1,175,444 | | | 1,240,980 |
| | | | | | | | | | | |
Total Assets | $ | 7,603,261 | | $ | 7,322,069 |
| | | | | | | | | | | |
LIABILITIES AND CAPITALIZATION | | | | |
| | | | | | | | | | | |
Total Assets | $ | 6,911,121 | | $ | 7,059,989 |
Current Liabilities: | | | | |
| | | | | | Notes Payable | $ | 62,500 | | $ | 302,000 |
| | | | | | Long-Term Debt - Current Portion | | 200,000 | | 4,700 |
| | | | | | Accounts Payable | | 228,250 | | 217,311 |
| | | | | | Accounts Payable to Affiliated Companies | | 38,648 | | 63,517 |
| Obligations to Third Party Suppliers | | 56,718 | | 34,824 |
| Renewable Portfolio Standards Compliance Obligations | | 104,847 | | 60,750 |
| Accumulated Deferred Income Taxes | | - | | 55,136 |
| Regulatory Liabilities | | 3,281 | | 49,611 |
| Other Current Liabilities | | 72,007 | | | 90,939 |
Total Current Liabilities | | 766,251 | | | 878,788 |
| | | | | | |
Deferred Credits and Other Liabilities: | | | | |
| Accumulated Deferred Income Taxes | | 1,760,339 | | 1,527,667 |
| Regulatory Liabilities | | 264,352 | | 262,738 |
| Accrued Pension, SERP and PBOP | | 209,153 | | 235,529 |
| Other Long-Term Liabilities | | 120,939 | | | 129,279 |
Total Deferred Credits and Other Liabilities | | 2,354,783 | | | 2,155,213 |
| | | | | | |
Capitalization: | | | | |
| Long-Term Debt | | 1,829,766 | | | 1,781,541 |
| | | | | | |
Preferred Stock Not Subject to Mandatory Redemption | | 43,000 | | | 43,000 |
| | | | | | |
| Common Stockholder's Equity: | | | | |
| | Common Stock | | - | | - |
| | Capital Surplus, Paid In | | 995,378 | | 994,130 |
| | Retained Earnings | | 1,613,538 | | 1,468,955 |
| | Accumulated Other Comprehensive Income | | 545 | | | 442 |
| Common Stockholder's Equity | | 2,609,461 | | | 2,463,527 |
Total Capitalization | | 4,482,227 | | | 4,288,068 |
| | | | | | |
Commitments and Contingencies (Note 11) | | | | |
| | | | | | |
Total Liabilities and Capitalization | $ | 7,603,261 | | $ | 7,322,069 |
| | | | | | |
| | | | | | |
| | | | | | |
The accompanying notes are an integral part of these consolidated financial statements. | The accompanying notes are an integral part of these consolidated financial statements. | The accompanying notes are an integral part of these consolidated financial statements. |
8876
| | | | | | | |
NSTAR ELECTRIC COMPANY AND SUBSIDIARY |
CONSOLIDATED BALANCE SHEETS |
|
| | | | | | | |
| | | As of December 31, |
(Thousands of Dollars) | 2013 | | 2012 |
| | | | | | | |
LIABILITIES AND CAPITALIZATION | | | | | |
| | | | | | | |
Current Liabilities: | | | | | |
| Notes Payable | $ | 103,500 | | $ | 276,000 |
| Long-Term Debt - Current Portion | | 301,650 | | | 1,650 |
| Accounts Payable | | 207,559 | | | 168,611 |
| Accounts Payable to Affiliated Companies | | 75,707 | | | 247,061 |
| Accumulated Deferred Income Taxes | | 50,128 | | | 104,668 |
| Regulatory Liabilities | | 53,958 | | | 47,539 |
| Other Current Liabilities | | 118,410 | | | 144,433 |
Total Current Liabilities | | 910,912 | | | 989,962 |
| | | | | | | |
Rate Reduction Bonds | | - | | | 43,493 |
| | | | | | | |
Deferred Credits and Other Liabilities: | | | | | |
| Accumulated Deferred Income Taxes | | 1,466,835 | | | 1,321,026 |
| Regulatory Liabilities | | 253,108 | | | 244,224 |
| Accrued Pension | | 118,010 | | | 360,932 |
| Payable to Affiliated Companies | | 64,172 | | | 70,221 |
| Other Long-Term Liabilities | | 142,214 | | | 183,190 |
Total Deferred Credits and Other Liabilities | | 2,044,339 | | | 2,179,593 |
| | | | | | | |
Capitalization: | | | | | |
| Long-Term Debt | | 1,499,417 | | | 1,600,911 |
| | | | | | | |
Preferred Stock Not Subject to Mandatory Redemption | | 43,000 | | | 43,000 |
| | | | | | | |
| Common Stockholder's Equity: | | | | | |
| | Common Stock | | - | | | - |
| | Capital Surplus, Paid In | | 992,625 | | | 992,625 |
| | Retained Earnings | | 1,420,828 | | | 1,210,405 |
| Common Stockholder's Equity | | 2,413,453 | | | 2,203,030 |
Total Capitalization | | 3,955,870 | | | 3,846,941 |
| | | | | | | |
Commitments and Contingencies (Note 12) | | | | | |
| | | | | | | |
Total Liabilities and Capitalization | $ | 6,911,121 | | $ | 7,059,989 |
| | | | | | | |
| | | | | | | |
| | | | | | | |
The accompanying notes are an integral part of these consolidated financial statements. |
| | | | | | | | | | |
NSTAR ELECTRIC COMPANY AND SUBSIDIARY |
CONSOLIDATED STATEMENTS OF INCOME |
|
| | | | | | | | | | |
| | | | | | | | | | |
| | | For the Years Ended December 31, |
(Thousands of Dollars) | 2015 | | 2014 | | 2013 |
| | | | | | | | | | |
Operating Revenues | $ | 2,681,342 | | $ | 2,536,677 | | $ | 2,493,479 |
| | | | | | | | | | |
Operating Expenses: | | | | | | | | |
| Purchased Power and Transmission | | 1,190,191 | | | 1,122,298 | | | 849,149 |
| Operations and Maintenance | | 306,528 | | | 326,972 | | | 376,360 |
| Depreciation | | 196,770 | | | 188,693 | | | 180,298 |
| Amortization of Regulatory (Liabilities)/Assets, Net | | (12,989) | | | (6,330) | | | 230,148 |
| Amortization of Rate Reduction Bonds | | - | | | - | | | 15,054 |
| Energy Efficiency Programs | | 224,755 | | | 193,516 | | | 206,536 |
| Taxes Other Than Income Taxes | | 133,260 | | | 133,072 | | | 127,778 |
| | Total Operating Expenses | | 2,038,515 | | | 1,958,221 | | | 1,985,323 |
Operating Income | | 642,827 | | | 578,456 | | | 508,156 |
Interest Expense | | 75,347 | | | 77,878 | | | 70,383 |
Other Income, Net | | 5,106 | | | 4,491 | | | 3,639 |
Income Before Income Tax Expense | | 572,586 | | | 505,069 | | | 441,412 |
Income Tax Expense | | 228,044 | | | 201,981 | | | 172,866 |
Net Income | $ | 344,542 | | $ | 303,088 | | $ | 268,546 |
| | | | | | | | | | |
| | | | | | | | | | |
| | | | | | | | | | |
The accompanying notes are an integral part of these consolidated financial statements. |
| | | | | | | | | | |
| | | | | | | | | | |
| | | | | | | | | | |
| | | | | | | | | | |
CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME |
| | | | | | | | | | |
Net Income | $ | 344,542 | | $ | 303,088 | | $ | 268,546 |
Other Comprehensive Income, Net of Tax: | | | | | | | | |
| | Changes in Funded Status of SERP Benefit Plan | | 103 | | | 442 | | | - |
Other Comprehensive Income, Net of Tax | | 103 | | | 442 | | | - |
Comprehensive Income | $ | 344,645 | | $ | 303,530 | | $ | 268,546 |
| | | | | | | | | | |
| | | | | | | | | | |
| | | | | | | | | | |
The accompanying notes are an integral part of these consolidated financial statements. |
8977
| | | | | | | | | | |
NSTAR ELECTRIC COMPANY AND SUBSIDIARY |
CONSOLIDATED STATEMENTS OF INCOME |
|
| | | | | | | | | | |
| | | | | | | | | | |
| | | For the Years Ended December 31, |
(Thousands of Dollars) | 2013 | | 2012 | | 2011 |
| | | | | | | | | | |
Operating Revenues | $ | 2,493,479 | | $ | 2,300,997 | | $ | 2,403,053 |
| | | | | | | | | | |
Operating Expenses: | | | | | | | | |
| Purchased Power and Transmission | | 849,149 | | | 788,252 | | | 905,226 |
| Operations and Maintenance | | 376,360 | | | 431,802 | | | 387,533 |
| Depreciation | | 180,298 | | | 171,070 | | | 163,368 |
| Amortization of Regulatory Assets, Net | | 230,148 | | | 117,682 | | | 82,979 |
| Amortization of Rate Reduction Bonds | | 15,054 | | | 90,322 | | | 90,322 |
| Energy Efficiency Programs | | 206,536 | | | 201,234 | | | 175,747 |
| Taxes Other Than Income Taxes | | 127,778 | | | 119,219 | | | 111,705 |
| | Total Operating Expenses | | 1,985,323 | | | 1,919,581 | | | 1,916,880 |
Operating Income | | 508,156 | | | 381,416 | | | 486,173 |
| | | | | | | | | | |
Interest Expense: | | | | | | | | |
| Interest on Long-Term Debt | | 79,088 | | | 87,100 | | | 90,040 |
| Interest on Rate Reduction Bonds | | 399 | | | 3,585 | | | 7,226 |
| Other Interest | | (9,104) | | | (20,631) | | | (27,839) |
| | Interest Expense | | 70,383 | | | 70,054 | | | 69,427 |
Other Income, Net | | 3,639 | | | 2,846 | | | 1,434 |
Income Before Income Tax Expense | | 441,412 | | | 314,208 | | | 418,180 |
Income Tax Expense | | 172,866 | | | 123,966 | | | 165,686 |
Net Income | $ | 268,546 | | $ | 190,242 | | $ | 252,494 |
| | | | | | | | | | |
| | | | | | | | | | |
| | | | | | | | | | |
The accompanying notes are an integral part of these consolidated financial statements. |
| | | | | | | | | | | | | | | | | | |
NSTAR ELECTRIC COMPANY AND SUBSIDIARY |
CONSOLIDATED STATEMENTS OF COMMON STOCKHOLDER'S EQUITY |
| | | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | Accumulated | | | Total |
| | | | | | | | | Capital | | | | | | Other | | | Common |
| | | Common Stock | | | Surplus, | | | Retained | | | Comprehensive | | | Stockholder's |
(Thousands of Dollars, Except Stock Information) | Stock | | | Amount | | | Paid In | | | Earnings | | | Income | | | Equity |
Balance as of January 1, 2013 | 100 | | $ | - | | $ | 992,625 | | $ | 1,210,405 | | $ | - | | $ | 2,203,030 |
| Net Income | | | | | | | | | | 268,546 | | | | | | 268,546 |
| Dividends on Preferred Stock | | | | | | | | | | (2,123) | | | | | | (2,123) |
| Dividends on Common Stock | | | | | | | | | | (56,000) | | | | | | (56,000) |
Balance as of December 31, 2013 | 100 | | | - | | | 992,625 | | | 1,420,828 | | | - | | | 2,413,453 |
| Net Income | | | | | | | | | | 303,088 | | | | | | 303,088 |
| Dividends on Preferred Stock | | | | | | | | | | (1,961) | | | | | | (1,961) |
| Dividends on Common Stock | | | | | | | | | | (253,000) | | | | | | (253,000) |
| Other Changes in Stockholder's Equity | | | | | | | 1,505 | | | | | | | | | 1,505 |
| Accumulated Other Comprehensive Income | | | | | | | | | | | | | 442 | | | 442 |
Balance as of December 31, 2014 | 100 | | | - | | | 994,130 | | | 1,468,955 | | | 442 | | | 2,463,527 |
| Net Income | | | | | | | | | | 344,542 | | | | | | 344,542 |
| Dividends on Preferred Stock | | | | | | | | | | (1,960) | | | | | | (1,960) |
| Dividends on Common Stock | | | | | | | | | | (197,999) | | | | | | (197,999) |
| Other Changes in Stockholder's Equity | | | | | | | 1,248 | | | | | | | | | 1,248 |
| Accumulated Other Comprehensive Income | | | | | | | | | | | | | 103 | | | 103 |
Balance as of December 31, 2015 | 100 | | $ | - | | $ | 995,378 | | $ | 1,613,538 | | $ | 545 | | $ | 2,609,461 |
| | | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | | |
The accompanying notes are an integral part of these consolidated financial statements. |
9078
| | | | | | | |
NSTAR ELECTRIC COMPANY AND SUBSIDIARY |
CONSOLIDATED STATEMENTS OF COMMON STOCKHOLDER'S EQUITY |
| | | | | | | |
| | | | | | | Total |
| | | | | Capital | | Common |
| | | Common Stock | Surplus, | Retained | Stockholder's |
(Thousands of Dollars, Except Stock Information) | Stock | Amount | Paid In | Earnings | Equity |
Balance as of January 1, 2011 | 100 | $ - | $ 992,625 | $ 1,158,489 | $ 2,151,114 |
| Net Income | | | | 252,494 | 252,494 |
| Dividends on Preferred Stock | | | | (1,960) | (1,960) |
| Dividends on Common Stock | | | | (169,900) | (169,900) |
Balance as of December 31, 2011 | 100 | - | 992,625 | 1,239,123 | 2,231,748 |
| Net Income | | | | 190,242 | 190,242 |
| Dividends on Preferred Stock | | | | (1,960) | (1,960) |
| Dividends on Common Stock | | | | (217,000) | (217,000) |
Balance as of December 31, 2012 | 100 | - | 992,625 | 1,210,405 | 2,203,030 |
| Net Income | | | | 268,546 | 268,546 |
| Dividends on Preferred Stock | | | | (2,123) | (2,123) |
| Dividends on Common Stock | | | | (56,000) | (56,000) |
Balance as of December 31, 2013 | 100 | $ - | $ 992,625 | $ 1,420,828 | $ 2,413,453 |
| | | | | | | |
| | | | | | | |
| | | | | | | |
The accompanying notes are an integral part of these consolidated financial statements. |
91
|
NSTAR ELECTRIC COMPANY AND SUBSIDIARY | NSTAR ELECTRIC COMPANY AND SUBSIDIARY | NSTAR ELECTRIC COMPANY AND SUBSIDIARY |
CONSOLIDATED STATEMENTS OF CASH FLOWS | CONSOLIDATED STATEMENTS OF CASH FLOWS | CONSOLIDATED STATEMENTS OF CASH FLOWS |
| | |
| | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | |
| | | For the Years Ended December 31, | | | For the Years Ended December 31, |
(Thousands of Dollars) | (Thousands of Dollars) | 2013 | | 2012 | | 2011 | (Thousands of Dollars) | 2015 | | 2014 | | 2013 |
| | | | | | | | | | | | | | | | |
Operating Activities: | Operating Activities: | | | | | | | Operating Activities: | | | | | | |
| Net Income | $ | 344,542 | | $ | 303,088 | | $ | 268,546 |
| Net Income | $ | 268,546 | | $ | 190,242 | | $ | 252,494 | Adjustments to Reconcile Net Income to Net Cash Flows | | | | | | |
| Adjustments to Reconcile Net Income to Net Cash Flows | | | | | | | | Provided by Operating Activities: | | | | | | |
| | Provided by Operating Activities: | | | | | | | | Depreciation | | 196,770 | | 188,693 | | 180,298 |
| | Depreciation | | 180,298 | | 171,070 | | 163,368 | | Deferred Income Taxes | | 173,155 | | 108,133 | | 48,808 |
| | Deferred Income Taxes | | 48,808 | | 4,264 | | 72,006 | | Pension and PBOP Expense | | 10,786 | | 6,760 | | 35,731 |
| | Pension Expense | | 35,731 | | 66,010 | | 54,704 | | Pension and PBOP Contributions | | (9,886) | | (120,306) | | (82,000) |
| | Pension Contributions | | (82,000) | | (25,000) | | (125,000) | | Regulatory (Under)/Over Recoveries, Net | | (124,323) | | 57,696 | | (119,433) |
| | Regulatory (Under)/Over Recoveries, Net | | (119,433) | | (16,129) | | 68,353 | | Amortization of Regulatory (Liabilities)/Assets, Net | | (12,989) | | (6,330) | | 230,148 |
| | Amortization of Regulatory Assets, Net | | 230,148 | | 117,682 | | 82,979 | | Amortization of Rate Reduction Bonds | | - | | - | | 15,054 |
| | Amortization of Rate Reduction Bonds | | 15,054 | | 90,322 | | 90,322 | | Bad Debt Expense | | 14,228 | | 24,740 | | 28,108 |
| | Bad Debt Expense | | 28,108 | | 40,301 | | 22,582 | | Refunds Related to Spent Nuclear Fuel | | 783 | | 30,193 | | - |
| | Other | | 4,428 | | (32,048) | | 539 | | Other | | (56,063) | | (51,478) | | 4,428 |
| Changes in Current Assets and Liabilities: | | | | | | | Changes in Current Assets and Liabilities: | | | | | | |
| | Receivables and Unbilled Revenues, Net | | (45,405) | | (10,496) | | (26,041) | | Receivables and Unbilled Revenues, Net | | (35,525) | | (18,853) | | (45,405) |
| | Materials and Supplies | | 3,227 | | 1,813 | | (12,968) | | Materials and Supplies | | 406 | | (29,943) | | 3,227 |
| | Taxes Receivable/Accrued, Net | | (38,003) | | 29,899 | | 149,889 | | Taxes Receivable/Accrued, Net | | 77,429 | | (122,746) | | (38,003) |
| | Accounts Payable | | 31,875 | | 2,662 | | (53,939) | | Accounts Payable | | 21,961 | | 9,753 | | 31,875 |
| | Accounts Receivable from/Payable to Affiliates, Net | | (44,491) | | (61,879) | | (7,232) | | Accounts Receivable from/Payable to Affiliates, Net | | 11,450 | | 115,092 | | (44,491) |
| | Other Current Assets and Liabilities, Net | | (6,468) | | | 22,568 | | | 14,272 | | Other Current Assets and Liabilities, Net | | 44,302 | | | 38,535 | | | (6,468) |
Net Cash Flows Provided by Operating Activities | Net Cash Flows Provided by Operating Activities | | 510,423 | | | 591,281 | | | 746,328 | Net Cash Flows Provided by Operating Activities | | 657,026 | | | 533,027 | | | 510,423 |
| | | | | | | | | | | | | | | | |
Investing Activities: | Investing Activities: | | | | | | | Investing Activities: | | | | | | |
| Investments in Property, Plant and Equipment | | (476,600) | | (414,089) | | (390,427) | Investments in Property, Plant and Equipment | | (469,466) | | (465,028) | | (476,600) |
| Decrease/(Increase) in Special Deposits | | 37,604 | | 3,060 | | (2,732) | Decrease in Special Deposits | | - | | - | | 37,604 |
| Other Investing Activities | | 400 | | | 400 | | | 6,095 | Other Investing Activities | | - | | | - | | | 400 |
Net Cash Flows Used in Investing Activities | Net Cash Flows Used in Investing Activities | | (438,596) | | | (410,629) | | | (387,064) | Net Cash Flows Used in Investing Activities | | (469,466) | | | (465,028) | | | (438,596) |
| | | | | | | | | | | | | | | | |
Financing Activities: | Financing Activities: | | | | | | | Financing Activities: | | | | | | |
| Cash Dividends on Common Stock | | (56,000) | | (217,000) | | (169,900) | Cash Dividends on Common Stock | | (197,999) | | (253,000) | | (56,000) |
| Cash Dividends on Preferred Stock | | (2,123) | | (1,960) | | (1,960) | Cash Dividends on Preferred Stock | | (1,960) | | (1,961) | | (2,123) |
| (Decrease)/Increase in Short-Term Debt | | (172,500) | | 134,500 | | (86,000) | (Decrease)/Increase in Short-Term Debt | | (239,500) | | 198,500 | | (172,500) |
| Issuance of Long-Term Debt | | 200,000 | | 400,000 | | - | Issuance of Long-Term Debt | | 250,000 | | 300,000 | | 200,000 |
| Retirements of Long-Term Debt | | (1,650) | | (401,650) | | (16,650) | Retirements of Long-Term Debt | | (4,700) | | (301,650) | | (1,650) |
| Retirements of Rate Reduction Bonds | | (43,493) | | (84,367) | | (84,346) | Retirements of Rate Reduction Bonds | | - | | - | | (43,493) |
| Other Financing Activities | | (1,735) | | | (5,853) | | | - | Other Financing Activities | | (2,828) | | | (5,136) | | | (1,735) |
Net Cash Flows Used in Financing Activities | Net Cash Flows Used in Financing Activities | | (77,501) | | | (176,330) | | | (358,856) | Net Cash Flows Used in Financing Activities | | (196,987) | | | (63,247) | | | (77,501) |
Net (Decrease)/Increase in Cash and Cash Equivalents | Net (Decrease)/Increase in Cash and Cash Equivalents | | (5,674) | | 4,322 | | 408 | Net (Decrease)/Increase in Cash and Cash Equivalents | | (9,427) | | 4,752 | | (5,674) |
Cash and Cash Equivalents - Beginning of Year | Cash and Cash Equivalents - Beginning of Year | | 13,695 | | | 9,373 | | | 8,965 | Cash and Cash Equivalents - Beginning of Year | | 12,773 | | | 8,021 | | | 13,695 |
Cash and Cash Equivalents - End of Year | Cash and Cash Equivalents - End of Year | $ | 8,021 | | $ | 13,695 | | $ | 9,373 | Cash and Cash Equivalents - End of Year | $ | 3,346 | | $ | 12,773 | | $ | 8,021 |
| | | | | | | | | | | | | | | | |
The accompanying notes are an integral part of these consolidated financial statements. | The accompanying notes are an integral part of these consolidated financial statements. | The accompanying notes are an integral part of these consolidated financial statements. |
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9379
Company Report on Internal Controls Over Financial Reporting
Public Service Company of New Hampshire
Management is responsible for the preparation, integrity, and fair presentation of the accompanying consolidated financial statements of Public Service Company of New Hampshire and subsidiary (PSNH or the Company) and of other sections of this annual report.
Management is responsible for establishing and maintaining adequate internal controls over financial reporting. The Company’sCompany's internal control framework and processes have been designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with accounting principles generally accepted accounting principles.in the United States of America. There are inherent limitations of internal controls over financial reporting that could allow material misstatements due to error or fraud to occur and not be prevented or detected on a timely basis by employees during the normal course of business. Additionally, internal controls over financial reporting may become inadequate in the future due to changes in the business environment.
Under the supervision and with the participation of the principal executive officer and principal financial officer, PSNH conducted an evaluation of the effectiveness of internal controls over financial reporting based on criteria established inInternal Control - Integrated Framework (2013)(1992 Framework) issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO). Based on this evaluation under the framework in COSO, management concluded that internal controls over financial reporting were effective as of December 31, 2013.2015.
February 25, 201426, 2016
9480
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
To the Board of Directors and Stockholder of Public Service Company of New Hampshire:
We have audited the accompanying consolidated balance sheets of Public Service Company of New Hampshire and subsidiary (the "Company") as of December 31, 20132015 and 20122014 and the related consolidated statements of income, comprehensive income, common stockholder’sstockholder's equity, and cash flows for each of the three years in the period ended December 31, 2013.2015. Our audits also included the financial statement schedule listed in the Index at Item 15 of Part IV. These financial statements and financial statement schedule are the responsibility of the Company's management. Our responsibility is to express an opinion on the financial statements and financial statement schedule based on our audits.
We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. The Company is not required to have, nor were we engaged to perform, an audit of its internal control over financial reporting. Our audits included consideration of internal control over financial reporting as a basis for designing audit procedures that are appropriate in the circumstances, but not for the purpose of expressing an opinion on the effectiveness of the Company's internal control over financial reporting. Accordingly, we express no such opinion. An audit also includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.
In our opinion, such consolidated financial statements present fairly, in all material respects, the financial position of Public Service Company of New Hampshire and subsidiary as of December 31, 20132015 and 2012,2014, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2013,2015, in conformity with accounting principles generally accepted in the United States of America. Also, in our opinion, such financial statement schedule, when considered in relation to the basic consolidated financial statements taken as a whole, presents fairly in all material respects the information set forth therein.
/s/ Deloitte & Touche LLP
Hartford, Connecticut
February 25, 201426, 2016
81
| | | | | | | |
PUBLIC SERVICE COMPANY OF NEW HAMPSHIRE AND SUBSIDIARY | | | | | |
CONSOLIDATED BALANCE SHEETS | | | | | |
| | | | | | | |
| | | | | | | |
| | | As of December 31, |
(Thousands of Dollars) | 2015 | | 2014 |
| | | | | | | |
ASSETS | | | | | |
| | | | | | | |
Current Assets: | | | | | |
| Cash | $ | 1,733 | | $ | 489 |
| Receivables, Net | | 77,546 | | | 80,151 |
| Accounts Receivable from Affiliated Companies | | 2,352 | | | 3,194 |
| Unbilled Revenues | | 38,207 | | | 40,181 |
| Taxes Receivable | | 43,128 | | | 14,571 |
| Fuel, Materials and Supplies | | 156,868 | | | 148,139 |
| Regulatory Assets | | 104,971 | | | 111,705 |
| Prepayments and Other Current Assets | | 24,302 | | | 27,821 |
Total Current Assets | | 449,107 | | | 426,251 |
| | | | | | | |
Property, Plant and Equipment, Net | | 2,855,363 | | | 2,635,844 |
| | | | | | | |
Deferred Debits and Other Assets: | | | | | |
| Regulatory Assets | | 257,873 | | | 293,115 |
| Other Long-Term Assets | | 34,176 | | | 32,963 |
Total Deferred Debits and Other Assets | | 292,049 | | | 326,078 |
| | | | | | | |
Total Assets | $ | 3,596,519 | | $ | 3,388,173 |
| | | | | | | |
LIABILITIES AND CAPITALIZATION | | | | | |
| | | | | | | |
Current Liabilities: | | | | | |
| Notes Payable to Eversource Parent | $ | 231,300 | | $ | 90,500 |
| Accounts Payable | | 87,925 | | | 93,349 |
| Accounts Payable to Affiliated Companies | | 24,214 | | | 33,734 |
| Regulatory Liabilities | | 6,898 | | | 16,044 |
| Accumulated Deferred Income Taxes | | - | | | 36,164 |
| Other Current Liabilities | | 43,921 | | | 38,969 |
Total Current Liabilities | | 394,258 | | | 308,760 |
| | | | | | | |
Deferred Credits and Other Liabilities: | | | | | |
| Accumulated Deferred Income Taxes | | 705,894 | | | 587,292 |
| Regulatory Liabilities | | 47,851 | | | 51,372 |
| Accrued Pension, SERP and PBOP | | 89,579 | | | 93,243 |
| Other Long-Term Liabilities | | 50,746 | | | 50,155 |
Total Deferred Credits and Other Liabilities | | 894,070 | | | 782,062 |
| | | | | | | |
Capitalization: | | | | | |
| Long-Term Debt | | 1,071,017 | | | 1,070,021 |
| | | | | | | |
| Common Stockholder's Equity: | | | | | |
| | Common Stock | | - | | | - |
| | Capital Surplus, Paid In | | 748,634 | | | 748,240 |
| | Retained Earnings | | 494,901 | | | 486,459 |
| | Accumulated Other Comprehensive Loss | | (6,361) | | | (7,369) |
| Common Stockholder's Equity | | 1,237,174 | | | 1,227,330 |
Total Capitalization | | 2,308,191 | | | 2,297,351 |
| | | | | | | |
Commitments and Contingencies (Note 11) | | | | | |
| | | | | | | |
Total Liabilities and Capitalization | $ | 3,596,519 | | $ | 3,388,173 |
| | | | | | | |
| | | | | | | |
| | | | | | | |
The accompanying notes are an integral part of these consolidated financial statements. |
9582
| | | | | | |
PUBLIC SERVICE COMPANY OF NEW HAMPSHIRE AND SUBSIDIARY | | | | | |
CONSOLIDATED BALANCE SHEETS | | | | | |
| | | | | | |
| | | | | | |
| | As of December 31, |
(Thousands of Dollars) | 2013 | | 2012 |
| | | | | | |
ASSETS | | | | | |
| | | | | | |
Current Assets: | | | | | |
| Cash | $ | 130 | | $ | 2,493 |
| Receivables, Net | | 76,331 | | | 87,164 |
| Accounts Receivable from Affiliated Companies | | 90 | | | 723 |
| Unbilled Revenues | | 38,344 | | | 39,982 |
| Taxes Receivable | | 2,180 | | | 17,177 |
| Fuel, Materials and Supplies | | 128,736 | | | 95,345 |
| Regulatory Assets | | 92,194 | | | 62,882 |
| Prepayments and Other Current Assets | | 21,920 | | | 22,205 |
Total Current Assets | | 359,925 | | | 327,971 |
| | | | | | |
Property, Plant and Equipment, Net | | 2,467,556 | | | 2,352,515 |
| | | | | | |
Deferred Debits and Other Assets: | | | | | |
| Regulatory Assets | | 219,346 | | | 351,059 |
| Other Long-Term Assets | | 39,891 | | | 83,052 |
Total Deferred Debits and Other Assets | | 259,237 | | | 434,111 |
| | | | | | |
| | | | | | |
| | | | | | |
Total Assets | $ | 3,086,718 | | $ | 3,114,597 |
| | | | | | |
| | | | | | |
| | | | | | |
The accompanying notes are an integral part of these consolidated financial statements. | | | | | |
| | | | | | |
| | | | | | | | | | |
PUBLIC SERVICE COMPANY OF NEW HAMPSHIRE AND SUBSIDIARY | | | |
CONSOLIDATED STATEMENTS OF INCOME | | | |
| | | |
| | | | | | | | | | |
| | | For the Years Ended December 31, |
(Thousands of Dollars) | 2015 | | 2014 | | 2013 |
| | | | | | | | | | |
Operating Revenues | $ | 972,203 | | $ | 959,500 | | $ | 935,402 |
| | | | | | | | | | |
Operating Expenses: | | | | | | | | |
| Purchased Power, Fuel and Transmission | | 247,721 | | | 313,732 | | | 269,754 |
| Operations and Maintenance | | 276,554 | | | 261,848 | | | 267,797 |
| Depreciation | | 105,372 | | | 98,436 | | | 91,581 |
| Amortization of Regulatory Assets/(Liabilities), Net | | 16,276 | | | (29,602) | | | (20,387) |
| Amortization of Rate Reduction Bonds | | - | | | - | | | 19,748 |
| Energy Efficiency Programs | | 14,324 | | | 14,286 | | | 14,494 |
| Taxes Other Than Income Taxes | | 81,779 | | | 71,417 | | | 67,196 |
| | Total Operating Expenses | | 742,026 | | | 730,117 | | | 710,183 |
Operating Income | | 230,177 | | | 229,383 | | | 225,219 |
Interest Expense | | 45,990 | | | 45,349 | | | 46,176 |
Other Income, Net | | 3,315 | | | 2,045 | | | 3,455 |
Income Before Income Tax Expense | | 187,502 | | | 186,079 | | | 182,498 |
Income Tax Expense | | 73,060 | | | 72,135 | | | 71,101 |
Net Income | $ | 114,442 | | $ | 113,944 | | $ | 111,397 |
| | | | | | | | | | |
| | | | | | | | | | |
| | | | | | | | | | |
The accompanying notes are an integral part of these consolidated financial statements. | | | |
| | | | | | | | | | |
| | | | | | | | | | |
| | | | | | | | | | |
| | | | | | | | | | |
CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME |
| | | | | | | | | | |
Net Income | $ | 114,442 | | $ | 113,944 | | $ | 111,397 |
Other Comprehensive Income, Net of Tax: | | | | | | | | |
| Qualified Cash Flow Hedging Instruments | | 1,162 | | | 1,162 | | | 1,162 |
| Changes in Unrealized (Losses)/Gains on Marketable Securities | | (154) | | | 19 | | | (54) |
| Changes in Funded Status of SERP Benefit Plan | | - | | | - | | | (3) |
Other Comprehensive Income, Net of Tax | | 1,008 | | | 1,181 | | | 1,105 |
Comprehensive Income | $ | 115,450 | | $ | 115,125 | | $ | 112,502 |
| | | | | | | | | | |
| | | | | | | | | | |
| | | | | | | | | | |
The accompanying notes are an integral part of these consolidated financial statements. | | | |
9683
| | | | | | | |
PUBLIC SERVICE COMPANY OF NEW HAMPSHIRE AND SUBSIDIARY |
CONSOLIDATED BALANCE SHEETS |
|
| | | | | | | |
| | | As of December 31, |
(Thousands of Dollars) | 2013 | | 2012 |
| | | | | | | |
LIABILITIES AND CAPITALIZATION | | | | | |
| | | | | | | |
Current Liabilities: | | | | | |
| Notes Payable to Affiliated Companies | $ | 86,500 | | $ | 63,300 |
| Long-Term Debt - Current Portion | | 50,000 | | | - |
| Accounts Payable | | 82,920 | | | 62,864 |
| Accounts Payable to Affiliated Companies | | 22,040 | | | 21,337 |
| Regulatory Liabilities | | 20,643 | | | 23,002 |
| Accumulated Deferred Income Taxes | | 28,596 | | | 10,364 |
| Renewable Portfolio Standards Compliance Obligations | | 8,918 | | | 17,383 |
| Other Current Liabilities | | 42,811 | | | 40,586 |
Total Current Liabilities | | 342,428 | | | 238,836 |
| | | | | | | |
Rate Reduction Bonds | | - | | | 29,294 |
| | | | | | | |
Deferred Credits and Other Liabilities: | | | | | |
| Accumulated Deferred Income Taxes | | 500,166 | | | 441,577 |
| Regulatory Liabilities | | 51,723 | | | 52,418 |
| Accrued Pension | | - | | | 186,148 |
| Accrued SERP and PBOP | | 15,272 | | | 33,981 |
| Other Long-Term Liabilities | | 46,247 | | | 47,896 |
Total Deferred Credits and Other Liabilities | | 613,408 | | | 762,020 |
| | | | | | | |
Capitalization: | | | | | |
| Long-Term Debt | | 999,006 | | | 997,932 |
| | | | | | | |
| Common Stockholder's Equity: | | | | | |
| | Common Stock | | - | | | - |
| | Capital Surplus, Paid In | | 701,911 | | | 701,052 |
| | Retained Earnings | | 438,515 | | | 395,118 |
| | Accumulated Other Comprehensive Loss | | (8,550) | | | (9,655) |
| Common Stockholder's Equity | | 1,131,876 | | | 1,086,515 |
Total Capitalization | | 2,130,882 | | | 2,084,447 |
| | | | | | | |
Commitments and Contingencies (Note 12) | | | | | |
| | | | | | | |
Total Liabilities and Capitalization | $ | 3,086,718 | | $ | 3,114,597 |
| | | | | | | |
| | | | | | | |
| | | | | | | |
The accompanying notes are an integral part of these consolidated financial statements. |
| | | | | | | | | | | | | | | | | | |
PUBLIC SERVICE COMPANY OF NEW HAMPSHIRE AND SUBSIDIARY |
CONSOLIDATED STATEMENTS OF COMMON STOCKHOLDER'S EQUITY |
| | | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | Accumulated | | | Total |
| | | | | | | | | Capital | | | | | | Other | | | Common |
| | | Common Stock | | | Surplus, | | | Retained | | | Comprehensive | | | Stockholder's |
(Thousands of Dollars, Except Stock Information) | Stock | | | Amount | | | Paid In | | | Earnings | | | Income/(Loss) | | | Equity |
Balance as of January 1, 2013 | 301 | | $ | - | | $ | 701,052 | | $ | 395,118 | | $ | (9,655) | | $ | 1,086,515 |
| Net Income | | | | | | | | | | 111,397 | | | | | | 111,397 |
| Dividends on Common Stock | | | | | | | | | | (68,000) | | | | | | (68,000) |
| Allocation of Benefits - ESOP | | | | | | | 859 | | | | | | | | | 859 |
| Other Comprehensive Income | | | | | | | | | | | | | 1,105 | | | 1,105 |
Balance as of December 31, 2013 | 301 | | | - | | | 701,911 | | | 438,515 | | | (8,550) | | | 1,131,876 |
| Net Income | | | | | | | | | | 113,944 | | | | | | 113,944 |
| Dividends on Common Stock | | | | | | | | | | (66,000) | | | | | | (66,000) |
| Capital Contributions from Eversource Parent | | | | | | | 45,000 | | | | | | | | | 45,000 |
| Allocation of Benefits - ESOP | | | | | | | 1,329 | | | | | | | | | 1,329 |
| Other Comprehensive Income | | | | | | | | | | | | | 1,181 | | | 1,181 |
Balance as of December 31, 2014 | 301 | | | - | | | 748,240 | | | 486,459 | | | (7,369) | | | 1,227,330 |
| Net Income | | | | | | | | | | 114,442 | | | | | | 114,442 |
| Dividends on Common Stock | | | | | | | | | | (106,000) | | | | | | (106,000) |
| Allocation of Benefits – ESOP | | | | | | | 394 | | | | | | | | | 394 |
| Other Comprehensive Income | | | | | | | | | | | | | 1,008 | | | 1,008 |
Balance as of December 31, 2015 | 301 | | $ | - | | $ | 748,634 | | $ | 494,901 | | $ | (6,361) | | $ | 1,237,174 |
| | | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | | |
The accompanying notes are an integral part of these consolidated financial statements. |
9784
| | | | | | | | | | |
PUBLIC SERVICE COMPANY OF NEW HAMPSHIRE AND SUBSIDIARY | | | |
CONSOLIDATED STATEMENTS OF INCOME | | | |
| | | |
| | | | | | | | | | |
| | | For the Years Ended December 31, |
(Thousands of Dollars) | 2013 | | 2012 | | 2011 |
| | | | | | | | | | |
Operating Revenues | $ | 935,402 | | $ | 988,013 | | $ | 1,013,003 |
| | | | | | | | | | |
Operating Expenses: | | | | | | | | |
| Purchased Power, Fuel and Transmission | | 269,754 | | | 319,253 | | | 327,905 |
| Operations and Maintenance | | 267,797 | | | 263,234 | | | 278,153 |
| Depreciation | | 91,581 | | | 87,602 | | | 76,167 |
| Amortization of Regulatory Assets/(Liabilities), Net | | (20,387) | | | (24,086) | | | 25,383 |
| Amortization of Rate Reduction Bonds | | 19,748 | | | 56,645 | | | 53,389 |
| Energy Efficiency Programs | | 14,494 | | | 14,245 | | | 12,917 |
| Taxes Other Than Income Taxes | | 67,196 | | | 66,025 | | | 58,985 |
| | Total Operating Expenses | | 710,183 | | | 782,918 | | | 832,899 |
Operating Income | | 225,219 | | | 205,095 | | | 180,104 |
| | | | | | | | | | |
Interest Expense: | | | | | | | | |
| Interest on Long-Term Debt | | 44,370 | | | 46,228 | | | 36,832 |
| Interest on Rate Reduction Bonds | | (154) | | | 2,687 | | | 6,276 |
| Other Interest | | 1,960 | | | 1,313 | | | 1,039 |
| | Interest Expense | | 46,176 | | | 50,228 | | | 44,147 |
Other Income, Net | | 3,455 | | | 3,008 | | | 14,255 |
Income Before Income Tax Expense | | 182,498 | | | 157,875 | | | 150,212 |
Income Tax Expense | | 71,101 | | | 60,993 | | | 49,945 |
Net Income | $ | 111,397 | | $ | 96,882 | | $ | 100,267 |
| | | | | | | | | | |
| | | | | | | | | | |
| | | | | | | | | | |
The accompanying notes are an integral part of these consolidated financial statements. | | | |
| | | | | | | | | | |
| | | | | | | | | | |
| | | | | | | | | | |
| | | | | | | | | | |
CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME |
| | | | | | | | | | |
Net Income | $ | 111,397 | | $ | 96,882 | | $ | 100,267 |
Other Comprehensive Income/(Loss), Net of Tax: | | | | | | | | |
| Qualified Cash Flow Hedging Instruments | | 1,162 | | | 1,162 | | | (10,260) |
| Changes in Unrealized Gains/(Losses) on Other Securities | | (54) | | | 13 | | | 29 |
| Changes in Funded Status of Pension, SERP and PBOP | | | | | | | | |
| | Benefit Plans | | (3) | | | 2 | | | - |
Other Comprehensive Income/(Loss), Net of Tax | | 1,105 | | | 1,177 | | | (10,231) |
Comprehensive Income | $ | 112,502 | | $ | 98,059 | | $ | 90,036 |
| | | | | | | | | | |
| | | | | | | | | | |
| | | | | | | | | | |
The accompanying notes are an integral part of these consolidated financial statements. | | | |
| | | | | | | | | | |
PUBLIC SERVICE COMPANY OF NEW HAMPSHIRE AND SUBSIDIARY |
CONSOLIDATED STATEMENTS OF CASH FLOWS |
|
| | | | | | | | | | |
| | | | | | | | | | |
| | | For the Years Ended December 31, |
(Thousands of Dollars) | 2015 | | 2014 | | 2013 |
| | | | | | | | | | |
Operating Activities: | | | | | | | | |
| Net Income | $ | 114,442 | | $ | 113,944 | | $ | 111,397 |
| Adjustments to Reconcile Net Income to Net Cash Flows | | | | | | | | |
| | Provided by Operating Activities: | | | | | | | | |
| | Depreciation | | 105,372 | | | 98,436 | | | 91,581 |
| | Deferred Income Taxes | | 83,776 | | | 94,813 | | | 75,693 |
| | Pension, SERP and PBOP Expense | | 4,580 | | | 7,197 | | | 26,846 |
| | Pension and PBOP Contributions | | (982) | | | (2,482) | | | (112,964) |
| | Regulatory Over/(Under) Recoveries, Net | | 41 | | | (11,875) | | | (8,481) |
| | Amortization of Regulatory Assets/(Liabilities), Net | | 16,276 | | | (29,602) | | | (20,387) |
| | Amortization of Rate Reduction Bonds | | - | | | - | | | 19,748 |
| | Refunds Related to Spent Nuclear Fuel | | 979 | | | 14,453 | | | - |
| | Other | | 8,677 | | | 10,095 | | | 16,079 |
| Changes in Current Assets and Liabilities: | | | | | | | | |
| | Receivables and Unbilled Revenues, Net | | (4,750) | | | (15,576) | | | 2,412 |
| | Fuel, Materials and Supplies | | (8,729) | | | (19,403) | | | (33,391) |
| | Taxes Receivable/Accrued, Net | | (23,909) | | | (23,857) | | | 26,462 |
| | Accounts Payable | | (22,203) | | | 17,796 | | | 2,632 |
| | Other Current Assets and Liabilities, Net | | 953 | | | (5,972) | | | (9,520) |
Net Cash Flows Provided by Operating Activities | | 274,523 | | | 247,967 | | | 188,107 |
| | | | | | | | | | |
Investing Activities: | | | | | | | | |
| Investments in Property, Plant and Equipment | | (308,036) | | | (256,159) | | | (186,009) |
| (Increase)/Decrease in Special Deposits | | - | | | (1,013) | | | 22,040 |
| Other Investing Activities | | 306 | | | (139) | | | (88) |
Net Cash Flows Used in Investing Activities | | (307,730) | | | (257,311) | | | (164,057) |
| | | | | | | | | | |
Financing Activities: | | | | | | | | |
| Cash Dividends on Common Stock | | (106,000) | | | (66,000) | | | (68,000) |
| Increase in Short-Term Debt | | - | | | 4,000 | | | 23,200 |
| Issuance of Long-Term Debt | | - | | | 75,000 | | | 250,000 |
| Retirements of Long-Term Debt | | - | | | (50,000) | | | (198,235) |
| Retirements of Rate Reduction Bonds | | - | | | - | | | (29,294) |
| Increase in Notes Payable to Eversource Parent | | 140,800 | | | - | | | - |
| Capital Contributions from Eversource Parent | | - | | | 45,000 | | | - |
| Other Financing Activities | | (349) | | | 1,703 | | | (4,084) |
Net Cash Flows Provided by/(Used in) Financing Activities | | 34,451 | | | 9,703 | | | (26,413) |
Net Increase/(Decrease) in Cash | | 1,244 | | | 359 | | | (2,363) |
Cash - Beginning of Year | | 489 | | | 130 | | | 2,493 |
Cash - End of Year | $ | 1,733 | | $ | 489 | | $ | 130 |
| | | | | | | | | | |
The accompanying notes are an integral part of these consolidated financial statements. |
98
| | | | | | | | |
PUBLIC SERVICE COMPANY OF NEW HAMPSHIRE AND SUBSIDIARY |
CONSOLIDATED STATEMENTS OF COMMON STOCKHOLDER'S EQUITY |
| | | | | | | | |
| | | | | | | Accumulated | Total |
| | | | | Capital | | Other | Common |
| | | Common Stock | Surplus, | Retained | Comprehensive | Stockholder's |
(Thousands of Dollars, Except Stock Information) | Stock | Amount | Paid In | Earnings | Income/(Loss) | Equity |
Balance as of January 1, 2011 | 301 | $ - | $ 579,577 | $ 347,471 | $ (601) | $ 926,447 |
| Net Income | | | | 100,267 | | 100,267 |
| Dividends on Common Stock | | | | (58,828) | | (58,828) |
| Allocation of Benefits - ESOP | | | 678 | | | 678 |
| Capital Contributions from NU Parent | | | 120,030 | | | 120,030 |
| Other Comprehensive Loss | | | | | (10,231) | (10,231) |
Balance as of December 31, 2011 | 301 | - | 700,285 | 388,910 | (10,832) | 1,078,363 |
| Net Income | | | | 96,882 | | 96,882 |
| Dividends on Common Stock | | | | (90,674) | | (90,674) |
| Allocation of Benefits - ESOP | | | 767 | | | 767 |
| Other Comprehensive Income | | | | | 1,177 | 1,177 |
Balance as of December 31, 2012 | 301 | - | 701,052 | 395,118 | (9,655) | 1,086,515 |
| Net Income | | | | 111,397 | | 111,397 |
| Dividends on Common Stock | | | | (68,000) | | (68,000) |
| Allocation of Benefits - ESOP | | | 859 | | | 859 |
| Other Comprehensive Income | | | | | 1,105 | 1,105 |
Balance as of December 31, 2013 | 301 | $ - | $ 701,911 | $ 438,515 | $ (8,550) | $ 1,131,876 |
| | | | | | | | |
| | | | | | | | |
| | | | | | | | |
The accompanying notes are an integral part of these consolidated financial statements. |
99
| | | | | | | | | | |
PUBLIC SERVICE COMPANY OF NEW HAMPSHIRE AND SUBSIDIARY |
CONSOLIDATED STATEMENTS OF CASH FLOWS |
|
| | | | | | | | | | |
| | | | | | | | | | |
| | | For the Years Ended December 31, |
(Thousands of Dollars) | 2013 | | 2012 | | 2011 |
| | | | | | | | | | |
Operating Activities: | | | | | | | | |
| Net Income | $ | 111,397 | | $ | 96,882 | | $ | 100,267 |
| Adjustments to Reconcile Net Income to Net Cash Flows | | | | | | | | |
| | Provided by Operating Activities: | | | | | | | | |
| | Depreciation | | 91,581 | | | 87,602 | | | 76,167 |
| | Deferred Income Taxes | | 75,693 | | | 58,552 | | | 75,628 |
| | Pension, SERP and PBOP Expense | | 26,846 | | | 26,312 | | | 27,298 |
| | Pension and PBOP Contributions | | (112,964) | | | (96,880) | | | (121,178) |
| | Regulatory (Under)/Over Recoveries, Net | | (8,481) | | | (183) | | | 6,079 |
| | Amortization of Regulatory (Liabilities)/Assets, Net | | (20,387) | | | (24,086) | | | 25,383 |
| | Amortization of Rate Reduction Bonds | | 19,748 | | | 56,645 | | | 53,389 |
| | Settlements of Cash Flow Hedge Instruments | | - | | | - | | | (18,072) |
| | Other | | 16,079 | | | 11,205 | | | (13,923) |
| Changes in Current Assets and Liabilities: | | | | | | | | |
| | Receivables and Unbilled Revenues, Net | | 2,412 | | | (84) | | | 7,833 |
| | Fuel, Materials and Supplies | | (33,391) | | | 25,897 | | | (9,873) |
| | Taxes Receivable/Accrued, Net | | 26,462 | | | (9,752) | | | 5,139 |
| | Accounts Payable | | 2,632 | | | (15,248) | | | (4,517) |
| | Other Current Assets and Liabilities, Net | | (9,520) | | | 13,436 | | | (4,915) |
Net Cash Flows Provided by Operating Activities | | 188,107 | | | 230,298 | | | 204,705 |
| | | | | | | | | | |
Investing Activities: | | | | | | | | |
| Investments in Property, Plant and Equipment | | (186,009) | | | (203,902) | | | (241,772) |
| Decrease/(Increase) in Notes Receivable from Affiliate | | - | | | 55,900 | | | (55,900) |
| Decrease in Special Deposits | | 22,040 | | | 4,200 | | | 2,223 |
| Other Investing Activities | | (88) | | | (135) | | | (134) |
Net Cash Flows Used in Investing Activities | | (164,057) | | | (143,937) | | | (295,583) |
| | | | | | | | | | |
Financing Activities: | | | | | | | | |
| Cash Dividends on Common Stock | | (68,000) | | | (90,674) | | | (58,828) |
| Increase/(Decrease) in Short-Term Debt | | 23,200 | | | - | | | (30,000) |
| Issuance of Long-Term Debt | | 250,000 | | | - | | | 282,000 |
| Retirements of Long-Term Debt | | (198,235) | | | - | | | (119,800) |
| Retirements of Rate Reduction Bonds | | (29,294) | | | (56,074) | | | (52,879) |
| Increase/(Decrease) in Notes Payable to Affiliate | | - | | | 63,300 | | | (47,900) |
| Capital Contributions from NU Parent | | - | | | - | | | 120,030 |
| Other Financing Activities | | (4,084) | | | (476) | | | (4,248) |
Net Cash Flows (Used in)/Provided by Financing Activities | | (26,413) | | | (83,924) | | | 88,375 |
Net (Decrease)/Increase in Cash | | (2,363) | | | 2,437 | | | (2,503) |
Cash - Beginning of Year | | 2,493 | | | 56 | | | 2,559 |
Cash - End of Year | $ | 130 | | $ | 2,493 | | $ | 56 |
| | | | | | | | | | |
The accompanying notes are an integral part of these consolidated financial statements. |
10085
Company Report on Internal Controls Over Financial Reporting
Western Massachusetts Electric Company
Management is responsible for the preparation, integrity, and fair presentation of the accompanying financial statements of Western Massachusetts Electric Company (WMECO or the Company) and of other sections of this annual report.
Management is responsible for establishing and maintaining adequate internal controls over financial reporting. The Company’sCompany's internal control framework and processes have been designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with accounting principles generally accepted accounting principles.in the United States of America. There are inherent limitations of internal controls over financial reporting that could allow material misstatements due to error or fraud to occur and not be prevented or detected on a timely basis by employees during the normal course of business. Additionally, internal controls over financial reporting may become inadequate in the future due to changes in the business environment.
Under the supervision and with the participation of the principal executive officer and principal financial officer, WMECO conducted an evaluation of the effectiveness of internal controls over financial reporting based on criteria established inInternal Control – Integrated Framework (2013)(1992 Framework) issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO). Based on this evaluation under the framework in COSO, management concluded that internal controls over financial reporting were effective as of December 31, 2013.2015.
February 25, 201426, 2016
10186
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
To the Board of Directors and Stockholder of Western Massachusetts Electric Company:
We have audited the accompanying balance sheets of Western Massachusetts Electric Company (the "Company") as of December 31, 20132015 and 20122014 and the related statements of income, comprehensive income, common stockholder’sstockholder's equity, and cash flows for each of the three years in the period ended December 31, 2013.2015. Our audits also included the financial statement schedule listed in the Index at Item 15 of Part IV. These financial statements and financial statement schedule are the responsibility of the Company's management. Our responsibility is to express an opinion on the financial statements and financial statement schedule based on our audits.
We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. The Company is not required to have, nor were we engaged to perform, an audit of its internal control over financial reporting. Our audits included consideration of internal control over financial reporting as a basis for designing audit procedures that are appropriate in the circumstances, but not for the purpose of expressing an opinion on the effectiveness of the Company's internal control over financial reporting. Accordingly, we express no such opinion. An audit also includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.
In our opinion, such financial statements present fairly, in all material respects, the financial position of Western Massachusetts Electric Company as of December 31, 20132015 and 2012,2014, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2013,2015, in conformity with accounting principles generally accepted in the United States of America. Also, in our opinion, such financial statement schedule, when considered in relation to the basic financial statements taken as a whole, presents fairly in all material respects the information set forth therein.
/s/ Deloitte & Touche LLP
Hartford, Connecticut
February 25, 2014
26, 2016
10287
|
WESTERN MASSACHUSETTS ELECTRIC COMPANY | WESTERN MASSACHUSETTS ELECTRIC COMPANY | WESTERN MASSACHUSETTS ELECTRIC COMPANY |
BALANCE SHEETS | BALANCE SHEETS | BALANCE SHEETS |
| | |
| | | | | | | | | | | |
| | As of December 31, | | | As of December 31, |
(Thousands of Dollars) | (Thousands of Dollars) | 2013 | | 2012 | (Thousands of Dollars) | 2015 | | 2014 |
| | | | | | | | | | | |
ASSETS | ASSETS | | | | | ASSETS | | | | |
| | | | | | | | | | | |
Current Assets: | Current Assets: | | | | | Current Assets: | | | | |
| Cash | $ | - | | $ | 1 | Cash | $ | 834 | | $ | - |
| Receivables, Net | | 49,018 | | 47,297 | Receivables, Net | | 50,912 | | 51,066 |
| Accounts Receivable from Affiliated Companies | | 47,607 | | 164 | Accounts Receivable from Affiliated Companies | | 18,633 | | 7,851 |
| Unbilled Revenues | | 16,562 | | 16,192 | Unbilled Revenues | | 15,065 | | 15,146 |
| Taxes Receivable | | 432 | | 15,513 | Taxes Receivable | | 33,407 | | 18,126 |
| Regulatory Assets | | 43,024 | | 42,370 | Regulatory Assets | | 56,166 | | 51,923 |
| Marketable Securities | | 26,628 | | 27,352 | Marketable Securities | | - | | 28,658 |
| Prepayments and Other Current Assets | | 10,479 | | | 7,963 | Prepayments and Other Current Assets | | 7,882 | | | 7,607 |
Total Current Assets | Total Current Assets | | 193,750 | | | 156,852 | Total Current Assets | | 182,899 | | | 180,377 |
| | | | | | | | | | | |
Property, Plant and Equipment, Net | Property, Plant and Equipment, Net | | 1,381,060 | | | 1,290,498 | Property, Plant and Equipment, Net | | 1,575,306 | | | 1,461,321 |
| | | | | | | | | | | |
Deferred Debits and Other Assets: | Deferred Debits and Other Assets: | | | | | Deferred Debits and Other Assets: | | | | |
| Regulatory Assets | | 146,088 | | 221,752 | Regulatory Assets | | 135,010 | | 146,307 |
| Marketable Securities | | 31,243 | | 30,342 | Marketable Securities | | - | | 29,452 |
| Other Long-Term Assets | | 40,679 | | | 23,625 | Other Long-Term Assets | | 24,875 | | | 18,731 |
Total Deferred Debits and Other Assets | Total Deferred Debits and Other Assets | | 218,010 | | | 275,719 | Total Deferred Debits and Other Assets | | 159,885 | | | 194,490 |
| | | | | | | | | | | |
Total Assets | $ | 1,918,090 | | $ | 1,836,188 |
| | | | | | |
LIABILITIES AND CAPITALIZATION | | | | |
| | | | | | |
Current Liabilities: | | | | |
| | | | | | Notes Payable to Eversource Parent | $ | 143,400 | | $ | 21,400 |
| | | | | | Long-Term Debt - Current Portion | | - | | 50,000 |
Total Assets | $ | 1,792,820 | | $ | 1,723,069 |
| Accounts Payable | | 58,364 | | 53,732 |
| Accounts Payable to Affiliated Companies | | 19,896 | | 14,328 |
| Regulatory Liabilities | | 13,122 | | 22,486 |
| Accumulated Deferred Income Taxes | | - | | 18,089 |
| Other Current Liabilities | | 29,927 | | | 24,080 |
Total Current Liabilities | | 264,709 | | | 204,115 |
| | | | | | |
Deferred Credits and Other Liabilities: | | | | |
| Accumulated Deferred Income Taxes | | 470,539 | | 416,822 |
| Regulatory Liabilities | | 11,597 | | 10,835 |
| Accrued Pension, SERP and PBOP | | 19,515 | | 17,705 |
| Other Long-Term Liabilities | | 36,819 | | | 33,747 |
Total Deferred Credits and Other Liabilities | | 538,470 | | | 479,109 |
| | | | | | |
Capitalization: | | | | |
| Long-Term Debt | | 517,329 | | | 575,184 |
| | | | | | |
| Common Stockholder's Equity: | | | | |
| | Common Stock | | 10,866 | | 10,866 |
| | Capital Surplus, Paid In | | 391,398 | | 391,256 |
| | Retained Earnings | | 198,140 | | 178,834 |
| | Accumulated Other Comprehensive Loss | | (2,822) | | | (3,176) |
| Common Stockholder's Equity | | 597,582 | | | 577,780 |
Total Capitalization | | 1,114,911 | | | 1,152,964 |
| | | | | | |
Commitments and Contingencies (Note 11) | | | | |
| | | | | | |
Total Liabilities and Capitalization | $ | 1,918,090 | | $ | 1,836,188 |
| | | | | | | | | | | |
| | | | | | | | | | | |
| | | | | | | | | | | |
The accompanying notes are an integral part of these financial statements. | The accompanying notes are an integral part of these financial statements. | The accompanying notes are an integral part of these financial statements. |
10388
| | | | | | | |
WESTERN MASSACHUSETTS ELECTRIC COMPANY |
BALANCE SHEETS |
|
| | | | | | | |
| | | As of December 31, |
(Thousands of Dollars) | 2013 | | 2012 |
| | | | | | | |
LIABILITIES AND CAPITALIZATION | | | | | |
| | | | | | | |
Current Liabilities: | | | | | |
| Notes Payable to Affiliated Companies | $ | - | | $ | 31,900 |
| Long-Term Debt - Current Portion | | - | | | 55,000 |
| Accounts Payable | | 62,961 | | | 68,141 |
| Accounts Payable to Affiliated Companies | | 9,230 | | | 7,103 |
| Accrued Interest | | 7,525 | | | 8,304 |
| Regulatory Liabilities | | 19,858 | | | 21,037 |
| Accumulated Deferred Income Taxes | | 13,098 | | | 8,404 |
| Counterparty Deposits | | 7,688 | | | 751 |
| Other Current Liabilities | | 20,629 | | | 15,754 |
Total Current Liabilities | | 140,989 | | | 216,394 |
| | | | | | | |
Rate Reduction Bonds | | - | | | 9,352 |
| | | | | | | |
Deferred Credits and Other Liabilities: | | | | | |
| Accumulated Deferred Income Taxes | | 396,933 | | | 303,111 |
| Regulatory Liabilities | | 13,873 | | | 9,686 |
| Accrued Pension | | - | | | 24,215 |
| Accrued SERP and PBOP | | 3,911 | | | 11,884 |
| Other Long-Term Liabilities | | 28,619 | | | 40,148 |
Total Deferred Credits and Other Liabilities | | 443,336 | | | 389,044 |
| | | | | | | |
Capitalization: | | | | | |
| Long-Term Debt | | 629,389 | | | 550,270 |
| | | | | | | |
| Common Stockholder's Equity: | | | | | |
| | Common Stock | | 10,866 | | | 10,866 |
| | Capital Surplus, Paid In | | 390,743 | | | 390,412 |
| | Retained Earnings | | 181,014 | | | 160,577 |
| | Accumulated Other Comprehensive Loss | | (3,517) | | | (3,846) |
| Common Stockholder's Equity | | 579,106 | | | 558,009 |
Total Capitalization | | 1,208,495 | | | 1,108,279 |
| | | | | | | |
Commitments and Contingencies (Note 12) | | | | | |
| | | | | | | |
Total Liabilities and Capitalization | $ | 1,792,820 | | $ | 1,723,069 |
| | | | | | | |
| | | | | | | |
| | | | | | | |
The accompanying notes are an integral part of these financial statements. |
| | | | | | | | | | |
WESTERN MASSACHUSETTS ELECTRIC COMPANY |
STATEMENTS OF INCOME |
|
| | | | | | | | | | |
| | | | | |
| For the Years Ended December 31, |
(Thousands of Dollars) | 2015 | | 2014 | | 2013 |
| | | | | | | | | | |
Operating Revenues | $ | 518,128 | | $ | 493,423 | | $ | 472,724 |
| | | | | | | | | | |
Operating Expenses: | | | | | | | | |
| Purchased Power and Transmission | | 177,172 | | | 172,876 | | | 147,059 |
| Operations and Maintenance | | 86,360 | | | 89,406 | | | 96,194 |
| Depreciation | | 43,362 | | | 41,886 | | | 37,568 |
| Amortization of Regulatory Assets/(Liabilities), Net | | 14,545 | | | (6,228) | | | (3,206) |
| Amortization of Rate Reduction Bonds | | - | | | - | | | 7,780 |
| Energy Efficiency Programs | | 42,867 | | | 42,937 | | | 39,524 |
| Taxes Other Than Income Taxes | | 38,302 | | | 34,907 | | | 28,458 |
| | Total Operating Expenses | | 402,608 | | | 375,784 | | | 353,377 |
Operating Income | | 115,520 | | | 117,639 | | | 119,347 |
Interest Expense | | 24,792 | | | 24,931 | | | 24,851 |
Other Income, Net | | 2,748 | | | 2,379 | | | 3,310 |
Income Before Income Tax Expense | | 93,476 | | | 95,087 | | | 97,806 |
Income Tax Expense | | 36,970 | | | 37,268 | | | 37,368 |
Net Income | $ | 56,506 | | $ | 57,819 | | $ | 60,438 |
| | | | | | | | | | |
| | | | | | | | | | |
| | | | | | | | | | |
The accompanying notes are an integral part of these financial statements. | | | | | | |
| | | | | | | | | | |
| | | | | | | | | | |
| | | | | | | | | | |
| | | | | | | | | | |
STATEMENTS OF COMPREHENSIVE INCOME |
| | | | | | | | | | |
Net Income | $ | 56,506 | | $ | 57,819 | | $ | 60,438 |
Other Comprehensive Income, Net of Tax: | | | | | | | | |
| Qualified Cash Flow Hedging Instruments | | 379 | | | 338 | | | 338 |
| Changes in Unrealized (Losses)/Gains on Marketable Securities | | (25) | | | 3 | | | (9) |
Other Comprehensive Income, Net of Tax | | 354 | | | 341 | | | 329 |
Comprehensive Income | $ | 56,860 | | $ | 58,160 | | $ | 60,767 |
| | | | | | | | | | |
| | | | | | | | | | |
| | | | | | | | | | |
The accompanying notes are an integral part of these financial statements. | | | | | | |
10489
| | | | | | | | | | |
WESTERN MASSACHUSETTS ELECTRIC COMPANY |
STATEMENTS OF INCOME |
|
| | | | | | | | | | |
| | | | | |
| For the Years Ended December 31, |
(Thousands of Dollars) | 2013 | | 2012 | | 2011 |
| | | | | | | | | | |
Operating Revenues | $ | 472,724 | | $ | 441,164 | | $ | 417,315 |
| | | | | | | | | | |
Operating Expenses: | | | | | | | | |
| Purchased Power and Transmission | | 147,059 | | | 136,086 | | | 161,480 |
| Operations and Maintenance | | 96,194 | | | 97,031 | | | 80,241 |
| Depreciation | | 37,568 | | | 29,971 | | | 26,455 |
| Amortization of Regulatory Assets/(Liabilities), Net | | (3,206) | | | 410 | | | 4,492 |
| Amortization of Rate Reduction Bonds | | 7,780 | | | 17,632 | | | 16,523 |
| Energy Efficiency Programs | | 39,524 | | | 27,802 | | | 21,804 |
| Taxes Other Than Income Taxes | | 28,458 | | | 21,458 | | | 17,957 |
| | Total Operating Expenses | | 353,377 | | | 330,390 | | | 328,952 |
Operating Income | | 119,347 | | | 110,774 | | | 88,363 |
| | | | | | | | | | |
Interest Expense: | | | | | | | | |
| Interest on Long-Term Debt | | 23,625 | | | 23,462 | | | 20,023 |
| Interest on Rate Reduction Bonds | | 177 | | | 1,229 | | | 2,335 |
| Other Interest | | 1,049 | | | 1,943 | | | 1,254 |
| | Interest Expense | | 24,851 | | | 26,634 | | | 23,612 |
Other Income, Net | | 3,310 | | | 2,503 | | | 1,489 |
Income Before Income Tax Expense | | 97,806 | | | 86,643 | | | 66,240 |
Income Tax Expense | | 37,368 | | | 32,140 | | | 23,186 |
Net Income | $ | 60,438 | | $ | 54,503 | | $ | 43,054 |
| | | | | | | | | | |
| | | | | | | | | | |
| | | | | | | | | | |
The accompanying notes are an integral part of these financial statements. | | | | | | |
| | | | | | | | | | |
| | | | | | | | | | |
| | | | | | | | | | |
| | | | | | | | | | |
STATEMENTS OF COMPREHENSIVE INCOME |
| | | | | | | | | | |
Net Income | $ | 60,438 | | $ | 54,503 | | $ | 43,054 |
Other Comprehensive Income/(Loss), Net of Tax: | | | | | | | | |
| Qualified Cash Flow Hedging Instruments | | 338 | | | 338 | | | (4,108) |
| Changes in Unrealized Gains/(Losses) on Other Securities | | (9) | | | 2 | | | 5 |
Other Comprehensive Income/(Loss), Net of Tax | | 329 | | | 340 | | | (4,103) |
Comprehensive Income | $ | 60,767 | | $ | 54,843 | | $ | 38,951 |
| | | | | | | | | | |
| | | | | | | | | | |
| | | | | | | | | | |
The accompanying notes are an integral part of these financial statements. | | | | | | |
| | | | | | | | | | | | | | | | | | |
WESTERN MASSACHUSETTS ELECTRIC COMPANY |
STATEMENTS OF COMMON STOCKHOLDER'S EQUITY |
| | | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | Accumulated | | | Total |
| | | | | | | | | Capital | | | | | | Other | | | Common |
| | | Common Stock | | | Surplus, | | | Retained | | | Comprehensive | | | Stockholder's |
(Thousands of Dollars, Except Stock Information) | Stock | | | Amount | | | Paid In | | | Earnings | | | Income/(Loss) | | | Equity |
Balance as of January 1, 2013 | 434,653 | | $ | 10,866 | | $ | 390,412 | | $ | 160,577 | | $ | (3,846) | | $ | 558,009 |
| Net Income | | | | | | | | | | 60,438 | | | | | | 60,438 |
| Dividends on Common Stock | | | | | | | | | | (40,001) | | | | | | (40,001) |
| Allocation of Benefits - ESOP | | | | | | | 331 | | | | | | | | | 331 |
| Other Comprehensive Income | | | | | | | | | | | | | 329 | | | 329 |
Balance as of December 31, 2013 | 434,653 | | | 10,866 | | | 390,743 | | | 181,014 | | | (3,517) | | | 579,106 |
| Net Income | | | | | | | | | | 57,819 | | | | | | 57,819 |
| Dividends on Common Stock | | | | | | | | | | (59,999) | | | | | | (59,999) |
| Allocation of Benefits - ESOP | | | | | | | 513 | | | | | | | | | 513 |
| Other Comprehensive Income | | | | | | | | | | | | | 341 | | | 341 |
Balance as of December 31, 2014 | 434,653 | | | 10,866 | | | 391,256 | | | 178,834 | | | (3,176) | | | 577,780 |
| Net Income | | | | | | | | | | 56,506 | | | | | | 56,506 |
| Dividends on Common Stock | | | | | | | | | | (37,200) | | | | | | (37,200) |
| Allocation of Benefits - ESOP | | | | | | | 142 | | | | | | | | | 142 |
| Other Comprehensive Income | | | | | | | | | | | | | 354 | | | 354 |
Balance as of December 31, 2015 | 434,653 | | $ | 10,866 | | $ | 391,398 | | $ | 198,140 | | $ | (2,822) | | $ | 597,582 |
| | | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | | |
The accompanying notes are an integral part of these financial statements. |
10590
| | | | | | | | |
WESTERN MASSACHUSETTS ELECTRIC COMPANY |
STATEMENTS OF COMMON STOCKHOLDER'S EQUITY |
| | | | | | | | |
| | | | | | | Accumulated | Total |
| | | | | Capital | | Other | Common |
| | | Common Stock | Surplus, | Retained | Comprehensive | Stockholder's |
(Thousands of Dollars, Except Stock Information) | Stock | Amount | Paid In | Earnings | Income/(Loss) | Equity |
Balance as of January 1, 2011 | 434,653 | $ 10,866 | $ 248,044 | $ 98,757 | $ (83) | $ 357,584 |
| Net Income | | | | 43,054 | | 43,054 |
| Dividends on Common Stock | | | | (26,305) | | (26,305) |
| Allocation of Benefits - ESOP | | | 259 | | | 259 |
| Capital Contributions from NU Parent | | | 91,812 | | | 91,812 |
| Other Comprehensive Loss | | | | | (4,103) | (4,103) |
Balance as of December 31, 2011 | 434,653 | 10,866 | 340,115 | 115,506 | (4,186) | 462,301 |
| Net Income | | | | 54,503 | | 54,503 |
| Dividends on Common Stock | | | | (9,432) | | (9,432) |
| Allocation of Benefits - ESOP | | | 297 | | | 297 |
| Capital Contributions from NU Parent | | | 50,000 | | | 50,000 |
| Other Comprehensive Income | | | | | 340 | 340 |
Balance as of December 31, 2012 | 434,653 | 10,866 | 390,412 | 160,577 | (3,846) | 558,009 |
| Net Income | | | | 60,438 | | 60,438 |
| Dividends on Common Stock | | | | (40,001) | | (40,001) |
| Allocation of Benefits - ESOP | | | 331 | | | 331 |
| Other Comprehensive Income | | | | | 329 | 329 |
Balance as of December 31, 2013 | 434,653 | $ 10,866 | $ 390,743 | $ 181,014 | $ (3,517) | $ 579,106 |
| | | | | | | | |
| | | | | | | | |
| | | | | | | | |
The accompanying notes are an integral part of these financial statements. |
| | | | | | | | | | |
WESTERN MASSACHUSETTS ELECTRIC COMPANY |
STATEMENTS OF CASH FLOWS |
|
| | | | | | | | | | |
| | | | | | | | | | |
| | | For the Years Ended December 31, |
(Thousands of Dollars) | 2015 | | 2014 | | 2013 |
| | | | | | | | | | |
Operating Activities: | | | | | | | | |
| Net Income | $ | 56,506 | | $ | 57,819 | | $ | 60,438 |
| Adjustments to Reconcile Net Income to Net Cash Flows | | | | | | | | |
| | Provided by Operating Activities: | | | | | | | | |
| | Depreciation | | 43,362 | | | 41,886 | | | 37,568 |
| | Deferred Income Taxes | | 39,428 | | | 34,108 | | | 87,028 |
| | Regulatory (Under)/Over Recoveries, Net | | (17,501) | | | 1,925 | | | 8,458 |
| | Amortization of Regulatory Assets/(Liabilities), Net | | 14,545 | | | (6,228) | | | (3,206) |
| | Amortization of Rate Reduction Bonds | | - | | | - | | | 7,780 |
| | (Payments)/Refunds Related to Spent Nuclear Fuel, Net | | (56,784) | | | 18,883 | | | - |
| | Other | | (6,421) | | | (2,005) | | | 3,381 |
| Changes in Current Assets and Liabilities: | | | | | | | | |
| | Receivables and Unbilled Revenues, Net | | (17,822) | | | 39,872 | | | (53,292) |
| | Taxes Receivable/Accrued, Net | | (15,281) | | | (22,454) | | | 19,840 |
| | Accounts Payable | | (2,602) | | | 1,269 | | | 7,456 |
| | Other Current Assets and Liabilities, Net | | 5,594 | | | (11,796) | | | 3,356 |
Net Cash Flows Provided by Operating Activities | | 43,024 | | | 153,279 | | | 178,807 |
| | | | | | | | | | |
Investing Activities: | | | | | | | | |
| Investments in Property, Plant and Equipment | | (134,551) | | | (116,205) | | | (128,786) |
| Proceeds from Sales of Marketable Securities | | 186,444 | | | 73,198 | | | 70,778 |
| Purchases of Marketable Securities | | (128,861) | | | (73,888) | | | (71,390) |
| Other Investing Activities | | - | | | 3,200 | | | 7,401 |
Net Cash Flows Used in Investing Activities | | (76,968) | | | (113,695) | | | (121,997) |
| | | | | | | | | | |
Financing Activities: | | | | | | | | |
| Cash Dividends on Common Stock | | (37,200) | | | (59,999) | | | (40,001) |
| Issuance of Long-Term Debt | | - | | | - | | | 80,000 |
| Retirements of Long-Term Debt | | (50,000) | | | - | | | (55,000) |
| Increase/(Decrease) in Notes Payable to Eversource Parent | | 122,000 | | | 21,400 | | | (31,900) |
| Retirements of Rate Reduction Bonds | | - | | | - | | | (9,352) |
| Other Financing Activities | | (22) | | | (985) | | | (558) |
Net Cash Flows Provided by/(Used in) Financing Activities | | 34,778 | | | (39,584) | | | (56,811) |
Net Increase/(Decrease) in Cash | | 834 | | | - | | | (1) |
Cash - Beginning of Year | | - | | | - | | | 1 |
Cash - End of Year | $ | 834 | | $ | - | | $ | - |
| | | | | | | | | | |
The accompanying notes are an integral part of these financial statements. |
106
| | | | | | | | | | |
WESTERN MASSACHUSETTS ELECTRIC COMPANY |
STATEMENTS OF CASH FLOWS |
|
| | | | | | | | | | |
| | | | | | | | | | |
| | | For the Years Ended December 31, |
(Thousands of Dollars) | 2013 | | 2012 | | 2011 |
| | | | | | | | | | |
Operating Activities: | | | | | | | | |
| Net Income | $ | 60,438 | | $ | 54,503 | | $ | 43,054 |
| Adjustments to Reconcile Net Income to Net Cash Flows | | | | | | | | |
| | Provided by Operating Activities: | | | | | | | | |
| | Depreciation | | 37,568 | | | 29,971 | | | 26,455 |
| | Deferred Income Taxes | | 87,028 | | | 53,942 | | | 23,056 |
| | Regulatory Over/(Under) Recoveries, Net | | 8,458 | | | (19,152) | | | 3,328 |
| | Amortization of Regulatory (Liabilities)/Assets, Net | | (3,206) | | | 410 | | | 4,492 |
| | Amortization of Rate Reduction Bonds | | 7,780 | | | 17,632 | | | 16,523 |
| | Settlement of Cash Flow Hedge Instrument | | - | | | - | | | (6,859) |
| | Other | | 3,381 | | | (3,954) | | | (586) |
| Changes in Current Assets and Liabilities: | | | | | | | | |
| | Receivables and Unbilled Revenues, Net | | (53,292) | | | (8,896) | | | (7,263) |
| | Materials and Supplies | | 865 | | | (2,882) | | | 331 |
| | Taxes Receivable/Accrued, Net | | 19,840 | | | (8,311) | | | 5,084 |
| | Accounts Payable | | 7,456 | | | (19,297) | | | 12,956 |
| | Other Current Assets and Liabilities, Net | | 2,491 | | | 581 | | | 3,824 |
Net Cash Flows Provided by Operating Activities | | 178,807 | | | 94,547 | | | 124,395 |
| | | | | | | | | | |
Investing Activities: | | | | | | | | |
| Investments in Property, Plant and Equipment | | (128,786) | | | (264,175) | | | (237,996) |
| Proceeds from Sales of Marketable Securities | | 70,778 | | | 79,769 | | | 125,157 |
| Purchases of Marketable Securities | | (71,390) | | | (80,529) | | | (125,453) |
| Decrease/(Increase) in Notes Receivable from Affiliate | | - | | | 11,000 | | | (11,000) |
| Other Investing Activities | | 7,401 | | | (28) | | | (1,919) |
Net Cash Flows Used in Investing Activities | | (121,997) | | | (253,963) | | | (251,211) |
| | | | | | | | | | |
Financing Activities: | | | | | | | | |
| Cash Dividends on Common Stock | | (40,001) | | | (9,432) | | | (26,305) |
| Issuance of Long-Term Debt | | 80,000 | | | 150,000 | | | 100,000 |
| Retirements of Long-Term Debt | | (55,000) | | | (53,800) | | | - |
| (Decrease)/Increase in Notes Payable to Affiliate | | (31,900) | | | 31,900 | | | (20,400) |
| Retirements of Rate Reduction Bonds | | (9,352) | | | (17,540) | | | (16,433) |
| Capital Contributions from NU Parent | | - | | | 50,000 | | | 91,812 |
| Other Financing Activities | | (558) | | | 8,288 | | | (1,858) |
Net Cash Flows (Used in)/Provided by Financing Activities | | (56,811) | | | 159,416 | | | 126,816 |
Net Decrease in Cash | | (1) | | | - | | | - |
Cash - Beginning of Year | | 1 | | | 1 | | | 1 |
Cash - End of Year | $ | - | | $ | 1 | | $ | 1 |
| | | | | | | | | | |
The accompanying notes are an integral part of these financial statements. |
10791
NORTHEAST UTILITIESEVERSOURCE ENERGY AND SUBSIDIARIES
THE CONNECTICUT LIGHT AND POWER COMPANY
NSTAR ELECTRIC COMPANY AND SUBSIDIARY
PUBLIC SERVICE COMPANY OF NEW HAMPSHIRE AND SUBSIDIARY
WESTERN MASSACHUSETTS ELECTRIC COMPANY
COMBINED NOTES TO FINANCIAL STATEMENTS
Refer to the Glossary of Terms included in this combined Annual Report on Form 10-K for abbreviations and acronyms used throughout the combined notes to the financial statements.
1.
SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
A.
About NU,Eversource, CL&P, NSTAR Electric, PSNH and WMECO
NU Consolidated:Eversource Energy: NUEversource Energy is a public utility holding company primarily engaged, through its wholly owned regulated utility subsidiaries, in the energy delivery business. On April 10, 2012, NU acquired NSTAR and its subsidiaries. NU'sEversource Energy's wholly owned regulated utility subsidiaries consist of CL&P, NSTAR Electric, PSNH, WMECO, Yankee Gas and NSTAR Gas. NUEversource provides energy delivery service to approximately 3.6 million electric and natural gas customers through these six regulated utilities in Connecticut, Massachusetts and New Hampshire. See Note 2, "Merger of NU and NSTAR," for further information regarding the merger.
NU,On April 30, 2015, the Company's legal name was changed from Northeast Utilities to Eversource Energy. CL&P, NSTAR Electric, PSNH and WMECO are each doing business as Eversource Energy.
Eversource, CL&P, NSTAR Electric, PSNH and WMECO are reporting companies under the Securities Exchange Act of 1934. NUEversource Energy is a public utility holding company under the Public Utility Holding Company Act of 2005. Arrangements among the regulated electric companies and other NUEversource companies, outside agencies and other utilities covering interconnections, interchange of electric power and sales of utility property are subject to regulation by the FERC. The Regulated companies are subject to regulation of rates, accounting and other matters by the FERC and/or applicable state regulatory commissions (the PURA for CL&P and Yankee Gas, the DPU for NSTAR Electric, WMECO and NSTAR Gas, and the NHPUC for PSNH).
Regulated Companies: CL&P, NSTAR Electric, PSNH and WMECO furnish franchised retail electric service in Connecticut, Massachusetts and New Hampshire. Yankee Gas and NSTAR Gas isare engaged in the distribution and sale of natural gas to customers within centralConnecticut and eastern Massachusetts. Yankee Gas owns and operates Connecticut's largest natural gas distribution system.Massachusetts, respectively. CL&P, NSTAR Electric, PSNH and WMECO's results include the operations of their respective distribution and transmission businesses. PSNH and WMECO's distribution results include the operations of their respective generation businesses. NUEversource also has a regulated subsidiary, NPT, which was formed to construct, own and operate the Northern Pass line, a new HVDC transmission line from Québec to New Hampshire under development that will interconnect with a new HVDC transmission line being developed by a transmission subsidiary of HQ.
Other: NUSCO, RRR,Eversource Service, Eversource's service company, Rocky River Realty Company, a wholly-owned real estate subsidiary of Eversource, Renewable Properties, Inc., aan indirect, wholly-owned subsidiary of NUTV,Eversource, and Properties, Inc., a wholly-owned subsidiary of PSNH, provide support services to NU,Eversource, including its regulatedRegulated companies. Harbor Electric Energy Company, aEversource Gas Transmission LLC, an indirect, wholly-owned subsidiary of NSTAR Electric, provides distribution service and ongoing support to its only customer,Eversource, holds an equity interest in the Massachusetts Water Resources Authority. Hopkinton, a subsidiary of NU, provides natural gas liquefaction and storage services to NSTAR Gas. As of December 31, 2013, NU Enterprises’ primary business consisted of NGS’ operation and maintenance agreements, E.S. Boulos Company, an electrical contractor based in Maine, and NSTAR Communications, Inc., an unregulated telecommunications subsidiary. Access Northeast project.
B.
Basis of Presentation
The consolidated financial statements of NU,Eversource, NSTAR Electric and PSNH include the accounts of each of their respective subsidiaries. Intercompany transactions have been eliminated in consolidation. The accompanying consolidated financial statements of NU,Eversource, NSTAR Electric and PSNH and the financial statements of CL&P and WMECO are herein collectively referred to as the "financial statements."
The preparation of the financial statements in conformity with GAAP requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and the disclosure of contingent liabilities as of the date of the financial statements and the reported amounts of revenues and expenses during the reporting period. Actual results could differ from those estimates.
NU's consolidated financial information includes NSTAR and its subsidiaries’ results of operations beginning April 10, 2012. The information disclosed for NSTAR Electric represents its results of operations for each of the years ended December 31, 2013, 2012 and 2011 presented on a comparable basis. NU did not apply "push-down accounting" to NSTAR Electric, whereby the adjustments of assets and liabilities to fair value and the resultant goodwill would be shown on the financial statements of the acquired subsidiary.
NUEversource consolidates CYAPC and YAEC asbecause CL&P’s,&P's, NSTAR Electric’s, PSNH’sElectric's, PSNH's and WMECO’sWMECO's combined ownership interest in each of these entities is greater than 50 percent. Intercompany transactions between CL&P, NSTAR Electric, PSNH and WMECO and the CYAPC and YAEC companies have been eliminated in consolidation of the NUEversource financial statements. For CL&P, NSTAR Electric, PSNH and WMECO, the investments in CYAPC and YAEC continue to be accounted for under the equity method. See Note 1J, "Summary of Significant Accounting Policies – Equity Method Investments," for further information.
NU'sEversource's utility subsidiariessubsidiaries' distribution (including generation) and transmission businesses are subject to rate-regulation that is based on cost recovery and meets the criteria for application of accounting guidance for entities with rate-regulated operations, thatwhich considers the effect of regulation resulting fromon the differences in the timing of the recognition of certain revenues and expenses from those of other businesses and industries. NU's utility subsidiaries' energy delivery business is subject to rate-regulation that is based on cost recovery and meets the criteria for application of rate-regulated accounting. See Note 3,2, "Regulatory Accounting," for further information.
108
Certain reclassifications of prior year data were made in the accompanying balance sheets for NU, NSTAR Electric, PSNH and WMECO and thefinancial statements of cash flows for all companies presented. These reclassifications were made to conform to the current year presentation.presentation and as a result of the adoption of new accounting guidance. See Note 1C, "Summary of Significant Accounting Policies – Accounting Standards," for further information.
In accordance with accounting guidance on noncontrolling interests in consolidated financial statements, the Preferred Stock of CL&P and the Preferred Stock of NSTAR Electric, which are not owned by NUEversource or its consolidated subsidiaries and are not subject to mandatory redemption, have been presented as noncontrolling interests in the financial statements of NU.Eversource. The Preferred Stock of CL&P and the
92
Preferred Stock of NSTAR Electric are considered to be temporary equity and have been classified between liabilities and permanent shareholders' equity on the balance sheets of NU,Eversource, CL&P and NSTAR Electric due to a provision in the preferred stock agreements of both CL&P and NSTAR Electric that grant preferred stockholders the right to elect a majority of the CL&P and NSTAR Electric BoardBoards of Directors, respectively, should certain conditions exist, such as if preferred dividends are in arrears for a specified amount of time. The Net Income reported in the statements of income and cash flows represents net income prior to apportionment to noncontrolling interests, which is represented by dividends on preferred stock of CL&P and NSTAR Electric.
As of December 31, 2015 and 2014, Eversource's carrying amount of goodwill was approximately $3.5 billion. Eversource performs an assessment for possible impairment of its goodwill at least annually. Eversource completed its annual goodwill impairment test for each of its reporting units as of October 1, 2015 and determined that no impairment exists. See Note 21, "Goodwill," for further information.
C.
Accounting Standards
Recently Adopted Accounting Standards: In the first quarter of 2013, NU, CL&P, NSTAR Electric, PSNH and WMECO, adopted the following Financial Accounting Standards Board’s (FASB) final Accounting Standards Updates (ASU) relating to additional disclosure requirements:
Reporting of Amounts Reclassified Out of Accumulated Other Comprehensive Income (AOCI): The ASU does not change existing guidance on which items should be reclassified out of AOCI but requires additional disclosures about the components of AOCI and the amount of reclassification adjustments to be presented in one location in the footnotes. The ASU was effective beginning in the first quarter of 2013 and was applied prospectively. For further information, see Note 15, "Accumulated Other Comprehensive Income/(Loss)," to the financial statements. The ASU did not affect the calculation of net income, comprehensive income or EPS and did not have an impact on financial position, results of operations or cash flows.
Clarifying the Scope of Disclosures about Offsetting Assets and Liabilities: Clarifies the scope of the offsetting disclosure requirements under GAAP and applies to derivative instruments. The ASU was effective beginning in the first quarter of 2013 with retrospective application. For further information, see Note 5, "Derivative Instruments," to the financial statements. The ASU did not have an impact on financial position, results of operations or cash flows.
Accounting Standards Issued but not Yet Adopted:Effective: In July 2013,May 2014, the Financial Accounting Standards Board (FASB) issued an Accounting Standards Update (ASU) 2014-09,Revenue from Contracts with Customers, which amends existing revenue recognition guidance and is required to be applied retrospectively (either to each reporting period presented or cumulatively at the date of initial application). In August 2015, the FASB issued ASU 2015-14,Revenue from Contracts with Customers – Deferral of the Effective Date, which defers the effective date of ASU 2014-09 to the first quarter of 2018, with 2017 application permitted. The Company is reviewing the requirements of ASU 2014-09 and will implement the standard in the first quarter of 2018. The ASU is not expected to have a finalmaterial impact on the financial statements of Eversource, CL&P, NSTAR Electric, PSNH or WMECO.
In January 2016, the FASB issued ASU effective2016-01,Financial Instruments-Overall: Recognition and Measurement of Financial Assets and Liabilities, which is required to be implemented in the first quarter of 2018. The Company is reviewing the requirements of the ASU. The ASU will remove the available-for-sale designation for equity securities, whereby changes in fair value are recorded in other comprehensive income in shareholders' equity, and will require changes in fair value of all equity securities to be recorded in earnings beginning on January 1, 2014, requiring presentation2018, with the unrealized gain or loss on available-for-sale equity securities as of certain unrecognized tax benefitsthat date reclassified to retained earnings as reductionsa cumulative effect of adoption. The fair value of available-for-sale equity securities subject to deferred tax assets.this guidance as of December 31, 2015 was approximately $52 million. The remaining available-for-sale equity securities included in marketable securities on the balance sheet are held in nuclear decommissioning trusts and are subject to regulatory accounting treatment and will not be impacted by this guidance. Implementation of the ASU for other financial instruments is not expected to have a material impact on the financial statements of Eversource, CL&P, NSTAR Electric, PSNH or WMECO.
On February 25, 2016, the FASB issued ASU 2016-02,Leases, which changes existing lease accounting guidance and is required to be applied in the first quarter of 2019, with earlier application permitted. The ASU is required to be implemented prospectivelyfor leases beginning on January 1, 2014. Implementationthe date of initial application. For prior periods presented, leases are required to be recognized and measured using a modified retrospective approach. The Company is reviewing the requirements of ASU 2016-02.
Recently Adopted Accounting Standards: In April 2015, the FASB issued ASU 2015-03,Simplifying the Presentation of Debt Issuance Costs, that changed the balance sheet presentation of debt issuance costs. Under the ASU, issuance costs related to debt are presented on the balance sheet as a direct deduction from the carrying amount of the debt liability rather than as a deferred cost. The new accounting guidance is effective for interim and annual periods beginning in the first quarter of 2016 with early adoption permitted and is required to be applied retrospectively. On December 31, 2015, the Company adopted the new accounting guidance and applied it retrospectively to all prior periods presented in the financial statements. The adoption of this guidance willASU did not have an immaterial impacta material effect on the balance sheets and had no impact on the results of operations or cash flows.flows of Eversource, CL&P, NSTAR Electric, PSNH or WMECO. See Note 8, "Long-Term Debt," for the prior year amounts that have been retrospectively adjusted.
On November 20, 2015, the FASB issued ASU 2015-17,Balance Sheet Classification of Deferred Taxes, that required all deferred tax liabilities and assets, along with any related valuation allowance, be classified as noncurrent on the balance sheet. This new accounting guidance is effective for interim and annual periods beginning in the first quarter of 2017 with early adoption permitted and may be applied either prospectively or retrospectively. On December 31, 2015, the Company adopted the new accounting guidance and applied it prospectively. The adoption of this ASU did not have a material effect on the balance sheets and had no impact on the results of operations or cash flows of Eversource, CL&P, NSTAR Electric, PSNH or WMECO. The current portion of Accumulated Deferred Income Taxes as of December 31, 2014, which was included in Total Current Liabilities on the balance sheets, was $160.3 million for Eversource, $34.1 million for CL&P, $55.1 million for NSTAR Electric, $36.2 million for PSNH, and $18.1 million for WMECO.
D.
Cash and Cash Equivalents
Cash and cash equivalents include cash on hand and short-term cash investments that are highly liquid in nature and have original maturities of three months or less. At the end of each reporting period, any overdraft amounts are reclassified from Cash and Cash Equivalents to Accounts Payable on the balance sheets.
E.
Provision for Uncollectible Accounts
NU,Eversource, including CL&P, NSTAR Electric, PSNH and WMECO, presents its receivables at estimated net realizable value by maintaining a provision for uncollectible amounts.accounts. This provision is determined based upon a variety of judgments and factors, including applyingthe application of an estimated uncollectible account percentage to each receivable aging category,category. The estimate is based upon historical collection and write-off experience and management's assessment of collectibilitycollectability from individual customers. Management continuously assesses the collectibilitycollectability of receivables and if circumstances change, collectibilityadjusts collectability estimates are adjusted accordingly.based on actual experience. Receivable balances are written off against the provision for uncollectible accounts when the customer accounts are terminated and these balances are deemed to be uncollectible.
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The PURA allows CL&P and Yankee Gas to accelerate the recovery of accounts receivable balances attributable to qualified customers under financial or medical duress (uncollectible hardship accounts receivable) outstanding for greater than 180 days and 90 days.days, respectively. The DPU allows WMECO and NSTAR Gas to also recover in rates amounts associated with certain uncollectible hardship accounts receivable. AsCertain of December 31, 2013, CL&P, WMECO and Yankee Gas hadNSTAR Electric's uncollectible hardship accounts receivable reservesare expected to be recovered in the amount of $67.3 million, $5.5 millionfuture rates, similar to WMECO and $8.4 million, respectively, with the corresponding under recovery of bad debt expense recorded asNSTAR Gas. Uncollectible customer account balances, which are expected to be recovered in rates, are included in Regulatory Assets or Other Long-Term Assets as these amounts are probable of recovery. As of December 31, 2012, these amounts totaled $65.2 million, $4.7 million and $6.4 million, respectively. These amounts are reflected inon the balance sheets.
The total provision for uncollectible accounts in the table below.
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The provisionand for uncollectible hardship accounts, which is included in the total provision, are included in Receivables, Net on the balance sheets, wasand were as follows:
|
| Total Provision for Uncollectible Accounts | | Uncollectible Hardship |
| | As of December 31, | | As of December 31, | | As of December 31, |
(Millions of Dollars) | (Millions of Dollars) | 2013 | | 2012 | (Millions of Dollars) | 2015 | | 2014 | | 2015 | | 2014 |
NU | $ | 171.3 | | $ | 165.5 |
Eversource | $ | 190.7 | | $ | 175.3 | | $ | 118.5 | | $ | 91.5 |
CL&P | CL&P | | 82.0 | | 77.6 | CL&P | | 79.5 | | 84.3 | | | 68.1 | | 74.0 |
NSTAR Electric | NSTAR Electric | | 41.7 | | 44.1 | NSTAR Electric | | 52.6 | | 40.7 | | | 25.3 | | - |
PSNH | PSNH | | 7.4 | | 6.8 | PSNH | | 8.7 | | 7.7 | | | - | | - |
WMECO | WMECO | | 10.0 | | 8.5 | WMECO | | 14.0 | | 9.9 | | | 7.4 | | 6.2 |
F.
Fuel, Materials and Supplies and Allowance Inventory
Fuel, Materials and Supplies include natural gas, coal, biomass and oil inventories as well as materials purchased primarily for construction or operation and maintenance purposes. Natural gas, coal, biomass and oil inventories are valued at their respective weighted average cost. Materials and supplies are valued at the lower of average cost or market.
AsFuel, Materials and Supplies also include Renewable Energy Certificates (RECs), which are purchased from suppliers of December 31, 2013, NU had $139.5 million ($74.2 million at PSNH)renewable sources of fuel and $163.7 million ($54.5 million at PSNH) of materials and supplies. As of December 31, 2012, NU had $109 million ($39.6 million at PSNH) of fuel and $158.7 million ($55.7 million at PSNH) of materials and supplies.generation. RECs are used to meet state mandated Renewable Portfolio Standards requirements.
PSNH is subject to federal and state laws and regulations that regulate emissions of air pollutants, including SO2, CO2, and NOx related to its regulated generation units, and uses SO2, CO2, and NOx emissions allowances. At the end of each compliance period, PSNH is required to relinquish SO2, CO2, and NOx emissions allowances corresponding to the actual respective emissions emitted by its generating units over the compliance period. SO2 and NOx emissions allowances are obtained through an annual allocation from the federal and state regulators that are granted at no cost and through purchases from third parties. CO2 emissions allowances are obtained through an annual allocation from the state regulator that are granted at no cost and are acquired through auctions and through purchases from third parties.
SO2, CO2, and NOxemissions allowances are recorded within Fuel, Materials and Supplies and are classified on the balance sheet as short-term or long-term depending on the period in which they are expected to be utilized against actual emissions. As of December 31, 2013 and 2012, PSNH had $0.2 million and $0.4 million, respectively, of short-term SO2, CO2, and NOxemissions allowances classified as Fuel, Materials and Supplies and $19.4 million and $19.4 million, respectively, of long-term SO2 and CO2emissions allowances classified as Other Long-Term Assets on the balance sheets.
SO2, CO2, and NOx emissions allowances are charged to expense based on their weighted average cost as they are utilized against emissions volumes at PSNH's generating units. PSNHSO2, CO2, and NOxemissions allowances are recorded expenses of $0.3 million, $0.4 millionwithin Fuel, Materials and $5.1 million for the years ended December 31, 2013, 2012, and 2011, respectively, which were included in Purchased Power, Fuel and TransmissionSupplies on the statementsbalance sheet and are classified as short-term or long-term depending on the period in which they are expected to be utilized against actual emissions. Current SO2 and CO2emissions allowances were classified as Fuel, Materials and Supplies on the balance sheets and long-term SO2 and CO2emissions allowances were classified as Other Long-Term Assets on the balance sheets.
The carrying amount of income. These costs or benefits are recovered from or refunded to customers through energy supply revenues. For the year ended December 31, 2013, PSNH received $6.8 million in proceeds from the auction offuel, materials and supplies, RECs, and emission allowances resulting in a net benefit of $6.5 million. were as follows:
| | | | | | | | | | | | | | | | | | |
| | As of December 31, |
| | 2015 | | 2014 |
| | | | | NSTAR | | | | | | | NSTAR | | |
(Millions of Dollars) | Eversource | | Electric | | PSNH | | Eversource | | Electric | | PSNH |
Current: | | | | | | | | | | | | | | | | | |
Fuel | $ | 152.5 | | $ | - | | $ | 103.4 | | $ | 164.3 | | $ | - | | $ | 95.1 |
Materials and Supplies | | 131.2 | | | 32.2 | | | 44.6 | | | 159.5 | | | 49.1 | | | 52.2 |
RECs | | 50.9 | | | 43.3 | | | 7.0 | | | 25.8 | | | 25.1 | | | 0.7 |
Emission Allowances | | 1.9 | | | - | | | 1.9 | | | 0.1 | | | - | | | 0.1 |
| | | | | | | | | | | | | | | | | | |
Long-Term: | | | | | | | | | | | | | | | | | |
Emission Allowances | | 17.5 | | | - | | | 17.5 | | | 20.1 | | | - | | | 20.1 |
G.
Restricted Cash and Other Deposits
As of December 31, 2013, NU2015, Eversource, CL&P, NSTAR Electric and CL&PPSNH had $1.7$17.1 million, $0.7 million, $8.5 million and $1.4$1.5 million, respectively, of restricted cash relatingcollateral posted not subject to amounts held in escrow,master netting agreements, with ISO-NE related to energy purchase transactions, which werewas included in Prepayments and Other Current Assets on the balance sheets. As of December 31, 2012,2014, these amounts were $3.3$9.9 million, $1.3$1.2 million and $1.7$2.5 million for NU,Eversource, CL&P and PSNH, respectively.
As of December 31, 2013 and 2012, NU had $17.9 million ($9 million of which related to NSTAR Electric) and $14.6 million, respectively, of cash collateral posted not subject to master netting agreements, primarily with ISO-NE, which were included in Prepayments and Other Current Assets on the balance sheets.
As of December 31, 2012, NU, NSTAR Electric, PSNH and WMECO had $69.4 million, $42.2 million, $22 million and $5.1 million, respectively, on deposit related to subsidiaries used for the payment of RRBs. As of December 31, 2013, there were no deposits related to these RRB subsidiaries as NSTAR Electric, PSNH and WMECO made their final payments in the first half of 2013 and these deposit balances were fully utilized.
H.
Fair Value Measurements
Fair value measurement guidance is applied to derivative contracts that are not elected or designated as "normal purchases or normal sales" (normal) and to the marketable securities held in trusts. Fair value measurement guidance is also applied to investment valuations of the investments used to calculate the funded status of pension and PBOP plans, andthe nonrecurring fair value measurements of nonfinancial assets such as goodwill and AROs. AROs, and the estimated fair value of preferred stock and long-term debt.
Fair Value Hierarchy: In measuring fair value, NUEversource uses observable market data when available and minimizesin order to minimize the use of unobservable inputs. Inputs used in fair value measurements are categorized into three fair value hierarchy levels for disclosure purposes. The entire fair value measurement is categorized based on the lowest level of input that is significant to the fair value measurement. NUEversource evaluates the
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classification of assets and liabilities measured at fair value on a quarterly basis, and NU'sEversource's policy is to recognize transfers between levels of the fair value hierarchy as of the end of the reporting period. The three levels of the fair value hierarchy are described below:
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Level 1 - Inputs are quoted prices (unadjusted) in active markets for identical assets or liabilities as of the reporting date. Active markets are those in which transactions for the asset or liability occur in sufficient frequency and volume to provide pricing information on an ongoing basis.
Level 2 - Inputs are quoted prices for similar instruments in active markets, quoted prices for identical or similar instruments in markets that are not active, and model-derived valuations in which all significant inputs are observable.
Level 3 - Quoted market prices are not available. Fair value is derived from valuation techniques in which one or more significant inputs or assumptions are unobservable. Where possible, valuation techniques incorporate observable market inputs that can be validated to external sources such as industry exchanges, including prices of energy and energy-related products.
Determination of Fair Value: The valuation techniques and inputs used in NU'sEversource's fair value measurements are described in Note 2, "Merger of NU and NSTAR," Note 5,4, "Derivative Instruments," Note 6,5, "Marketable Securities," Note 7,6, "Asset Retirement Obligations," Note 9A, "Employee Benefits – Pension Benefits and Postretirement Benefits Other Than Pensions," and Note 14,13, "Fair Value of Financial Instruments,"Instruments" to the financial statements.
I.
Derivative Accounting
Many of the Regulated companies' contracts for the purchase and sale of energy or energy-related products are derivatives. The accounting treatment for energy contracts entered into varies and depends on the intended use of the particular contract and on whether or not the contract is a derivative. For the Regulated companies, regulatory assets or regulatory liabilities are recorded to offset the fair values of derivative contracts, as costscontract settlements are recovered from, or refunded to, customers in future rates.
The application of derivative accounting is complex and requires management judgment in the following respects: identification of derivatives and embedded derivatives, election and designation of thea contract as normal, exception, and determination of the fair value of derivative contracts. All of these judgments can have a significant impact on the financial statements.
The judgment applied in the election of thea contract as normal exception (and resulting accrual accounting) includes the conclusion that it is probable at the inception of the contract and throughout its term that it will result in physical delivery of the underlying product and that the quantities will be used or sold by the business in the normal course of business. If facts and circumstances change and management can no longer support this conclusion, then thea contract cannot be considered normal exception and accrual accounting is terminated, and fair value accounting is applied prospectively.
The fair value of derivative contracts is based upon the contract terms and conditions and the underlying market price or fair value per unit. When quantities are not specified in the contract, the Company determines whether the contract has a determinable quantity by using amounts referenced in default provisions and other relevant sections of the contract. The fair value of derivative assets and liabilities with the same counterparty are offset and recorded as a net derivative asset or liability on the balance sheets. Changes
All changes in the fair value of derivative contracts are recorded as regulatory assets or liabilities and do not impact net income.
For further information regarding derivative contracts, see Note 5,4, "Derivative Instruments," to the financial statements.
J.
Equity Method Investments
Equity investments are included in Other Long-Term Assets on the balance sheets and net earnings related to these equity investments are included in Other Income, Net on the statements of income.
Regional Decommissioned Nuclear Companies: CL&P, NSTAR Electric, PSNH and WMECO own common stock in three regional nuclear generation companies (CYAPC, YAEC and MYAPC, collectively referred to as the Yankee Companies), each of which owned a single nuclear generating facility that has been decommissioned. Upon consummation of the merger with NSTAR, NSTAR Electric's ownership interests in CYAPC and YAEC combined with CL&P's, PSNH's and WMECO's respective ownership interests in CYAPC and YAEC totaled greater than 50 percent, requiring NU to consolidate CYAPC and YAEC beginning April 10, 2012. The investments in CYAPC and YAEC had previously been accounted for under the equity method of accounting by NU. For CL&P, NSTAR Electric, PSNH and WMECO, the investmentrespective investments in CYAPC, YAEC and YAEC, as well as MYAPC continues to beare accounted for under the equity method. At the NU consolidated level, intercompanyEversource consolidates CYAPC and YAEC because CL&P's, NSTAR Electric's, PSNH's and WMECO's combined ownership interest in each of these entities is greater than 50 percent. Intercompany transactions between CL&P, NSTAR Electric, PSNH and WMECO and the CYAPC and YAEC companies have been eliminated in consolidation.consolidation of the Eversource financial statements.
Ownership interests in the Yankee Companies as of December 31, 2013 and 2012 were as follows:
| | | | | | | | |
(Percent) | CYAPC | | | YAEC | | | MYAPC | |
CL&P | 34.5 | | | 24.5 | | | 12.0 | |
NSTAR Electric | 14.0 | | | 14.0 | | | 4.0 | |
PSNH | 5.0 | | | 7.0 | | | 5.0 | |
WMECO | 9.5 | | | 7.0 | | | 3.0 | |
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The total carrying values of CL&P's, NSTAR Electric's, PSNH's and WMECO's ownership interests in CYAPC, YAECthe Yankee Companies and MYAPC,the total carrying values, which arewere included in Other Long-Term Assets on their respective balance sheets, were as follows:
|
| As of December 31, | Ownership Interests (percent) | | Carrying Amount (in millions) |
(Millions of Dollars) | 2013 | | 2012 |
| As of December 31, 2015 and 2014 | | As of December 31, |
| CYAPC | | YAEC | | MYAPC | | 2015 | | 2014 |
CL&P | $ | 1.2 | | $ | 1.4 | 34.5 | % | | 24.5 | % | | 12.0 | % | | $ | 1.2 | | $ | 1.2 |
NSTAR Electric | | 0.5 | | 0.6 | 14.0 | | | 14.0 | | | 4.0 | | | | 0.5 | | | 0.5 |
PSNH | | 0.3 | | 0.3 | 5.0 | | | 7.0 | | | 5.0 | | | | 0.3 | | | 0.3 |
WMECO | | 0.3 | | 0.4 | 9.5 | | | 7.0 | | | 3.0 | | | | 0.3 | | | 0.3 |
For further information on the Yankee Companies, see Note 12C,11C, "Commitments and Contingencies - Contractual Obligations - Yankee Companies," to the financial statements.
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Infrastructure and Other Investments: As of December 31, 20132015 and 2012, NU2014, Eversource had a 37.2 percent (14.5 percent of which related to NSTAR Electric)an equity ownership interest in two companies that transmit electricity imported from the Hydro-Québec system in Canada. These investments are accounted for under the equity methodan energy investment fund of accounting. NU’s investment totaled $5.1$30.3 million and $6$17.8 million, respectively. Eversource had a 40 percent equity ownership interest in the Algonquin Gas Transmission, LLC (legal entity that owns Access Northeast assets) of $10.7 million as of December 31, 2013 and 2012, respectively, and NSTAR Electric's investment totaled $2 million and $2.3 million as of December 31, 2013 and 2012, respectively. As of December 31, 2013 and 2012,NU also had an equity ownership interest of $9.8 million and $6.8 million in an energy investment fund, respectively.
Equity investments are included in Other Long-Term Assets on the balance sheets and net earnings related to these equity investments are included in Other Income, Net on the statements of income. 2015.
K.
Revenues
Regulated Companies:Companies' Retail Revenues: The Regulated companies' retail revenues are based on rates approved by their respective state regulatory commissions. In general, rates can only be changed through formal proceedings with the state regulatory commissions. The Regulated companies' rates are designed to recover the costs to provide service to their customers, includingand include a return on investment. The Regulated companies also utilize regulatory commission-approved tracking mechanisms to recover certain costs on a fully-reconciling basis. These tracking mechanisms require rates to be changed periodically with overcollections refunded to customers or undercollections collected from customers in future periods.ensure recovery of actual costs incurred.
CL&P (effective December 1, 2014), WMECO, hasand NSTAR Gas (effective January 1, 2016), each have a regulatory commission approved revenue decoupling mechanismmechanism. Distribution revenues are decoupled from customer sales volumes, which breaks the relationship between sales volumes and revenues recognized. CL&P and WMECO reconcile their annual base distribution rate recovery to recover a pre-established levellevels of baseline distribution delivery service revenues per year, independentrevenues. Any difference between the allowed level of distribution revenue and the actual customer usage. Such decoupling mechanisms effectively breakamount incurred during a 12-month period is adjusted through rates in the relationship between kWhs consumed by customers and revenues recognized.following period.
A significant portion of the Regulated companies' retail revenues relate to the recovery of costs incurred for the sale of electricity and natural gas purchased on behalf of customers. These energy supply costs are recovered from customers in rates through cost tracking mechanisms. Energy purchases are recorded in Purchased Power, Fuel and Transmission, and the sales of energy associated with these purchases are recorded in Operating Revenues.
Regulated Companies' Unbilled Revenues: 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 are included in Operating Revenues on the statements of income and are assetsin Current Assets on the balance sheets. Actual amounts billed to customers when meter readings become available may vary from the estimated amount.
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 can significantly impact the amount of revenues recorded at NSTAR Electric and PSNH because they do not have a revenue decoupling mechanism. CL&P and WMECO record a regulatory deferral to reflect the actual allowed amount of revenue for decoupling.
Regulated Companies' Transmission Revenues - Wholesale Rates: Wholesale transmission revenues are recovered through FERC approved formula rates. Wholesale transmission revenues for CL&P, NSTAR Electric, PSNH, and WMECO are collected through a combination of regional and local rates, both of which are under the ISO New England Inc. Transmission, Markets and Services Tariff (ISO-NE Tariff). The ISO-NE Tariff includes Regional Network Service (RNS) and, Schedule 21 - NU– ES rate schedules, thatwhich recover the costs of transmission and other transmission-related services for CL&P, PSNH and WMECO, and Schedule 21 - NSTAR rate schedules, thatwhich recover costs of transmission and other transmission-related services for NSTAR Electric. The RNS rate, administered by ISO-NE and billed to all New England transmission load, including CL&P, NSTAR Electric, PSNH and WMECO's distribution businesses, is reset on June 1st of each year and recovers the revenue requirements associated with transmission facilitiesPool Transmission Facilities (PTF) that benefit the entire New England region. The Schedule 21 - NU– ES rate and Schedule 21 - NSTAR rates,rate are administered by NU, recoversEversource and recover any PTF costs not recovered under RNS rates, as well as the remaindercost of transmission facilities associated with the transmission revenue requirements.respective utility's local system. The Schedule 21 - NUES rate is reset on January 1st1st and June 1st1st of each year, while the Schedule 21 - NSTAR rate is reset on June 1st1st of each year. The Schedule 21 - NU– ES rate and Schedule 21 - NSTAR rate calculations recover total transmission revenue requirements net of revenues received from other sources (i.e., RNS, rentals, etc.), thereby ensuring that NUEversource recovers all of CL&P's, NSTAR Electric’s, PSNH's and WMECO's regional and local transmission revenue requirements in accordance with the ISO-NE Tariff. The RNS, Schedule 21 - NU– ES rate and Schedule 21 - NSTAR ratesrate provide for the annual reconciliation and recovery or refund of estimated costs to actual costs. The financial impacts of differences between actual and estimated costs are deferred for future recovery from, or refunded to, transmission customers. See Note 11E, "Commitments and Contingencies – FERC ROE Complaints," for complaints filed at the FERC relating to Eversource's ROE.
Regulated Companies' Transmission Revenues - Retail Rates: A significant portion of the NUEversource transmission segment revenue comes from ISO-NE charges to the distribution businesses of CL&P, NSTAR Electric, PSNH and WMECO, each of which recovers these costs through rates charged to their retail customers. CL&P, NSTAR Electric, PSNH and WMECO each have a retail transmission cost
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tracking mechanism as part of their rates, which allows the electric distribution companies to charge their retail customers for transmission costs on a timely basis.
L.
Operating Expenses
Costs related to fuel and natural gas included in Purchased Power, Fuel and Transmission on the statements of income were as follows:
|
| For the Years Ended December 31, | | | For the Years Ended December 31, |
(Millions of Dollars) | 2013 | | 2012 | | 2011 | | | 2015 | | 2014 | | 2013 |
NU -Natural Gas and Fuel (1) | $ | 466.5 | | $ | 346.8 | | $ | 307.9 | | |
Eversource - Natural Gas and Fuel | $ | 516.7 | | $ | 599.4 | | $ | 466.5 |
PSNH - Fuel | | 104.8 | | 103.4 | | 115.9 | | | | 85.4 | | 113.4 | | 104.8 |
| | | | | | | | |
(1) NSTAR Gas natural gas costs were included in NU beginning April 10, 2012. |
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M.
Allowance for Funds Used During Construction
AFUDC represents the cost of borrowed and equity funds used to finance construction and is included in the cost of the Regulated companies' utility plant.plant on the balance sheet. The portion of AFUDC attributable to borrowed funds is recorded as a reduction of Other Interest Expense, and the AFUDC related to equity funds is recorded as Other Income, Net on the statements of income. AFUDC costs are recovered from customers over the service life of the related plant in the form of increased revenue collected as a result of higher depreciation expense.
| | | | | | | | | |
NU | For the Years Ended December 31, |
(Millions of Dollars, except percentages) | 2013 | | 2012(1) | | 2011 |
AFUDC: | | | | | | | | |
| Borrowed Funds | $ | 4.1 | | $ | 5.3 | | $ | 11.8 |
| Equity Funds | | 7.1 | | | 6.8 | | | 22.5 |
Total | $ | 11.2 | | $ | 12.1 | | $ | 34.3 |
Average AFUDC Rate | | 2.7% | | | 3.7% | | | 7.3% |
| | | | | | | | | |
(1) NSTAR amounts were included in NU beginning April 10, 2012. | |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | For the Years Ended December 31, |
| | 2013 | | 2012 | | 2011 |
(Millions of Dollars, | | | | NSTAR | | | | | | | | | | NSTAR | | | | | | | | | | | NSTAR | | | | | | |
except percentages) | CL&P | | Electric | | PSNH | | WMECO | | CL&P | | Electric | | PSNH | | WMECO | | CL&P | | Electric | | PSNH | | WMECO |
AFUDC: | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Borrowed Funds | $ | 2.2 | | $ | 0.5 | | $ | 0.5 | | $ | 0.5 | | $ | 2.5 | | $ | 0.3 | | $ | 1.6 | | $ | 0.5 | | $ | 3.3 | | $ | 0.2 | | $ | 7.1 | | $ | 0.5 |
| Equity Funds | | 2.9 | | | - | | | 0.2 | | | 1.0 | | | 1.9 | | | - | | | 1.9 | | | 1.0 | | | 6.0 | | | - | | | 13.2 | | | 1.0 |
Total | $ | 5.1 | | $ | 0.5 | | $ | 0.7 | | $ | 1.5 | | $ | 4.4 | | $ | 0.3 | | $ | 3.5 | | $ | 1.5 | | $ | 9.3 | | $ | 0.2 | | $ | 20.3 | | $ | 1.5 |
Average AFUDC Rate | | 3.7% | | | 0.5% | | | 1.1% | | | 6.1% | | | 3.6% | | | 0.4% | | | 5.9% | | | 6.8% | | | 8.3% | | | 0.3% | | | 7.1% | | | 7.4% |
The Regulated companies' average AFUDC rate is based on a FERC-prescribed formula using the cost of a company's short-term financings as well as a company'sand capitalization (preferred stock, long-term debt and common equity)., as appropriate. The average rate is applied to average eligible CWIP amounts to calculate AFUDC.
AFUDC costs and the weighted-average AFUDC rates were as follows:
| | | | | | | | |
Eversource | For the Years Ended December 31, |
(Millions of Dollars, except percentages) | 2015 | | 2014 | | 2013 |
Borrowed Funds | $ | 7.2 | | $ | 5.8 | | $ | 4.1 |
Equity Funds | | 18.8 | | | 13.7 | | | 7.1 |
Total AFUDC | $ | 26.0 | | $ | 19.5 | | $ | 11.2 |
Average AFUDC Rate | | 3.9% | | | 3.4% | | | 2.7% |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | For the Years Ended December 31, |
| | 2015 | | 2014 | | 2013 |
(Millions of Dollars, | | | | NSTAR | | | | | | | | | | NSTAR | | | | | | | | | | | NSTAR | | | | | | |
except percentages) | CL&P | | Electric | | PSNH | | WMECO | | CL&P | | Electric | | PSNH | | WMECO | | CL&P | | Electric | | PSNH | | WMECO |
Borrowed Funds | $ | 2.6 | | $ | 2.0 | | $ | 1.0 | | $ | 1.0 | | $ | 1.9 | | $ | 2.0 | | $ | 0.6 | | $ | 0.9 | | $ | 2.2 | | $ | 0.5 | | $ | 0.5 | | $ | 0.5 |
Equity Funds | | 5.2 | | | 4.3 | | | 1.2 | | | 1.7 | | | 2.9 | | | 3.8 | | | 0.6 | | | 1.7 | | | 2.9 | | | - | | | 0.2 | | | 1.0 |
Total AFUDC | $ | 7.8 | | $ | 6.3 | | $ | 2.2 | | $ | 2.7 | | $ | 4.8 | | $ | 5.8 | | $ | 1.2 | | $ | 2.6 | | $ | 5.1 | | $ | 0.5 | | $ | 0.7 | | $ | 1.5 |
Average AFUDC Rate | | 5.5% | | | 3.2% | | | 1.8% | | | 4.4% | | | 3.4% | | | 2.5% | | | 1.8% | | | 5.6% | | | 3.7% | | | 0.5% | | | 1.1% | | | 6.1% |
N.
Other Income, Net
Items included within Other Income, Net on the statements of income primarily consist of investment income/(loss), interest income, AFUDC related to equity funds, and equity in earnings.earnings of equity method investees. Investment income/(loss) primarily relatedrelates to the NU supplemental benefitdebt and equity securities held in trust. For further information, see Note 6,5, "Marketable Securities," to the financial statements. For further information on AFUDC related to equity funds, see Note 1M, "Summary of Significant Accounting Policies – Allowance for Funds Used During Construction," to the financial statements. For further information on equity in earnings, see Note 1J, "Summary of Significant Accounting Policies – Equity Method Investments," to the financial statements.
O.
Other Taxes
Gross receipts taxes levied by the state of Connecticut are collected by CL&P and Yankee Gas from their respective customers. These gross receipts taxes are shown on a gross basisseparately with collections in Operating Revenues and with payments in Taxes Other Than Income Taxes on the statements of income as follows:
|
| For the Years Ended December 31, | For the Years Ended December 31, |
(Millions of Dollars) | 2013 | | 2012 | | 2011 | 2015 | | 2014 | | 2013 |
NU | $ | 144.1 | | $ | 135.0 | | $ | 137.8 |
Eversource | $ | 147.2 | | $ | 148.2 | | $ | 144.1 |
CL&P | | 128.2 | | 120.7 | | 121.6 | | 128.5 | | 127.9 | | 128.2 |
Certain sales taxes are also collected by NU'sAs agents for state and local governments, Eversource's companies that serve customers in Connecticut and Massachusetts as agents for state and local governments andcollect certain sales taxes that are recorded on a net basis with no impact on the statements of income.
| | | | | | | | | | | |
P. | Supplemental Cash Flow Information |
| | | | | | | | | | | |
Eversource | As of and For the Years Ended December 31, |
(Millions of Dollars) | 2015 | | 2014 | | 2013 |
Cash Paid During the Year for: | | | | | | | | |
| Interest, Net of Amounts Capitalized | $ | 365.9 | | $ | 349.6 | | $ | 343.3 |
| Income Taxes | | 10.3 | | | 334.2 | | | 50.0 |
Non-Cash Investing Activities: | | | | | | | | |
| Plant Additions Included in Accounts Payable (As of) | | 216.6 | | | 181.9 | | | 193.1 |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | As of and For the Years Ended December 31, |
| | 2015 | | 2014 | | 2013 |
| | | | | NSTAR | | | | | | | | | | | NSTAR | | | | | | | | | | | NSTAR | | | | | | |
(Millions of Dollars) | CL&P | | Electric | | PSNH | | WMECO | | CL&P | | Electric | | PSNH | | WMECO | | CL&P | | Electric | | PSNH | | WMECO |
Cash Paid/(Received) During the Year for: | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Interest, Net of Amounts Capitalized | $ | 144.4 | | $ | 75.7 | | $ | 42.3 | | $ | 26.7 | | $ | 144.1 | | $ | 75.3 | | $ | 41.1 | | $ | 25.9 | | $ | 131.6 | | $ | 75.8 | | $ | 43.3 | | $ | 25.8 |
| Income Taxes | | 55.2 | | | (19.8) | | | 14.4 | | | 14.7 | | | 135.4 | | | 217.1 | | | 2.3 | | | 25.1 | | | 55.0 | | | 163.4 | | | (30.1) | | | (69.0) |
Non-Cash Investing Activities: | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Plant Additions Included in
Accounts Payable (As of) | | 76.0 | | | 23.5 | | | 46.5 | | | 27.0 | | | 63.5 | | | 34.6 | | | 39.3 | | | 14.2 | | | 51.4 | | | 57.0 | | | 34.9 | | | 19.5 |
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97
The 2015 cash paid for interest excludes interest payments made by CL&P and WMECO in connection with the full satisfaction of their respective obligations to the DOE for the disposal of spent nuclear fuel and high-level radioactive waste. For further information, see Note 8, "Long-Term Debt," to the financial statements.
| | | | | | | | | | | |
P. Supplemental Cash Flow Information |
| | | | | | | | | | | |
NU | As of and For the Years Ended December 31, |
(Millions of Dollars) | 2013 | | 2012(1) | | 2011 |
Cash Paid/(Received) During the Year for: | | | | | | | | |
| Interest, Net of Amounts Capitalized | $ | 343.3 | | $ | 356.5 | | $ | 256.3 |
| Income Taxes | | 50.0 | | | (12.8) | | | (76.6) |
Non-Cash Investing Activities: | | | | | | | | |
| Plant Additions Included in Accounts Payable (As of) | | 193.1 | | | 160.6 | | | 168.5 |
| | | | | | | | | | | |
(1) NSTAR amounts were included in NU beginning April 10, 2012. |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | As of and For the Years Ended December 31, |
| | 2013 | | 2012 | | 2011 |
| | | | | NSTAR | | | | | | | | | | | NSTAR | | | | | | | | | | | NSTAR | | | | | | |
(Millions of Dollars) | CL&P | | Electric | | PSNH | | WMECO | | CL&P | | Electric | | PSNH | | WMECO | | CL&P | | Electric | | PSNH | | WMECO |
Cash Paid/(Received) During | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| the Year for: | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Interest, Net of Amounts | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Capitalized | $ | 131.6 | | $ | 75.8 | | $ | 43.3 | | $ | 25.8 | | $ | 129.4 | | $ | 94.6 | | $ | 49.8 | | $ | 25.8 | | $ | 136.6 | | $ | 96.1 | | $ | 49.3 | | $ | 22.1 |
| Income Taxes | | 55.0 | | | 163.4 | | | (30.1) | | | (69.0) | | | (42.0) | | | 88.1 | | | 14.7 | | | (8.4) | | | (27.5) | | | (62.2) | | | (29.0) | | | (4.9) |
Non-Cash Investing Activities: | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Plant Additions Included in | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Accounts Payable (As of) | | 51.4 | | | 57.0 | | | 34.9 | | | 19.5 | | | 42.8 | | | 50.0 | | | 16.8 | | | 30.0 | | | 32.7 | | | 34.3 | | | 51.1 | | | 61.3 |
The mergerIn 2014, as a result of NU with NSTAR on April 10, 2012 represented a significant non-cash transaction. Referdamages awarded to the Yankee Companies for spent nuclear fuel lawsuits against the DOE described in Note 2, "Merger11C, "Commitments and Contingencies - Contractual Obligations - Yankee Companies," Eversource received total proceeds of NU$132.1 million, which were net of $80.6 million in proceeds CYAPC and NSTAR," for further information on the purchase price of NSTAR.YAEC returned to non-affiliated member companies.
Q.
Related Parties
NUSCO, NU'sEversource Service, Eversource's service company, provides centralized accounting, administrative, engineering, financial, information technology, legal, operational, planning, purchasing, and other services to NU'sEversource's companies. RRR,The Rocky River Realty Company, Renewable Properties, Inc. and Properties, Inc., three other NUEversource subsidiaries, construct, acquire or lease some of the property and facilities used by NU'sEversource's companies.
As of both December 31, 20132015 and 2012,2014, CL&P, PSNH and WMECO had long-term receivables from NUSCOEversource Service in the amounts of $25 million, $3.8 million and $5.5 million, respectively, which were included in Other Long-Term Assets on the balance sheets.These amounts related to the funding of investments held in trust by NUSCOEversource Service in connection with certain postretirement benefits for CL&P, PSNH and WMECO employees and have been eliminated in consolidation on the NUEversource financial statements.
NSTAR Electric’s balance sheets included $64.2 million and $70.2 million in Payable to Affiliated Companies as of December 31, 2013 and 2012, respectively. These amounts related to payments received from affiliates as a result of NSTAR Electric’s role as the acting sponsor of the NSTAR Pension Plan.
Included in the CL&P, NSTAR Electric, PSNH and WMECO balance sheets as of December 31, 20132015 and 20122014 were Accounts Receivable from Affiliated Companies and Accounts Payable to Affiliated Companies relating to transactions between CL&P, NSTAR Electric, PSNH and WMECO and other subsidiaries that are wholly ownedwholly-owned by NU.Eversource. These amounts have been eliminated in consolidation on the NUEversource financial statements.
R.
Severance Benefits
DuringFor the years ended December 31, 2015, 2014 and 2013, NUEversource recorded severance benefit expensesexpense of $4.7 million, $15 million and $9.7 million, respectively, in connection with organizational and cost saving initiatives, and, in 2014, the partial outsourcing of information technology functions made as part of ongoing post-merger integration.functions. As of December 31, 2013,2015 and 2014, the severance accrual totaled $14.7$9.3 million and $10.4 million, respectively, and was included in Other Current Liabilities on the balance sheet. sheets.
2.
MERGER OF NU AND NSTAR
On April 10, 2012, NU acquired 100 percent of the outstanding common shares of NSTAR. Pursuant to the terms and conditions of the Agreement and Plan of Merger, as amended, (the "Merger Agreement,") NSTAR and its subsidiaries became wholly-owned subsidiaries of NU.
NSTAR was a holding company engaged through its subsidiaries in the energy delivery business serving electric and natural gas distribution customers in Massachusetts. As part of the merger, NSTAR shareholders received 1.312 NU common shares for each NSTAR common share owned (the "exchange ratio") as of the acquisition date. The exchange ratio was structured to result in a no-premium merger based on the average closing share price of each company's common shares for the 20 trading days preceding the announcement of the merger in October 2010. NU issued approximately 136 million common shares to the NSTAR shareholders as a result of the merger.
114
Purchase Price: Pursuant to the merger, all of the NSTAR common shares were exchanged at the fixed exchange ratio of 1.312 NU common shares for each NSTAR common share. The total consideration transferred in the merger was based on the closing price of NU common shares on April 9, 2012, the day prior to the date the merger was completed, and was calculated as follows:
| | | |
NSTAR common shares outstanding as of April 9, 2012 (in thousands)*
| | 103,696
|
Exchange ratio
| | 1.312
|
NU common shares issued for NSTAR common shares outstanding (in thousands)
| | 136,049
|
Closing price of NU common shares on April 9, 2012
| $
| 36.79
|
Value of common shares issued (in millions)
| $
| 5,005
|
Fair value of NU replacement stock-based compensation awards related to
| | |
| pre-merger service (in millions)
| | 33
|
Total purchase price (in millions)
| $
| 5,038
|
*
Included 109 thousand shares related to NSTAR stock-based compensation awards that vested immediately prior to the merger.
Certain of NSTAR’s stock-based compensation awards, including deferred shares, performance shares and all outstanding stock options, were replaced with NU awards using the exchange ratio upon consummation of the merger. In accordance with accounting guidance for business combinations, the portion of the fair value of these awards attributable to service provided prior to the merger was included in the purchase price as it represented consideration transferred in the merger. See Note 10D, "Employee Benefits – Share-Based Payments," for further information.
Purchase Price Allocation: The allocation of the total purchase price to the estimated fair values of the assets acquired and liabilities assumed was determined based on the accounting guidance for fair value measurements, which defines fair value as the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date. The allocation of the total purchase price included adjustments to record the fair value of NSTAR’s unregulated telecommunications business, regulatory assets not earning a return, lease agreements, long-term debt and the preferred stock of NSTAR Electric. The fair values of NSTAR's assets and liabilities were determined based on significant estimates and assumptions, including Level 3 inputs, that were judgmental in nature. These estimates and assumptions included the timing and amounts of projected future cash flows and discount rates reflecting risk inherent in future cash flows.
In accordance with accounting guidance for business combinations, the excess of the purchase price over the estimated fair values of the assets acquired and liabilities assumed was recognized as goodwill. The allocation of the purchase price was as follows:
| | |
(Millions of Dollars)
| | |
Current Assets
| $
| 739
|
Property Plant and Equipment, Net
| | 5,155
|
Goodwill
| | 3,232
|
Other Long-Term Assets, excluding Goodwill
| | 2,103
|
Current Liabilities
| | (1,330)
|
Long-Term Liabilities
| | (2,723)
|
Long-Term Debt and Other Long-Term Obligations
| | (2,099)
|
Noncontrolling Interest
| | (39)
|
Total Purchase Price
| $
| 5,038
|
The goodwill from the merger with NSTAR of $3.2 billion was allocated to NU's reporting units based on their estimated fair values. NU's reporting units consist of Electric Distribution, Electric Transmission and Natural Gas Distribution. See the "Goodwill" section below for the allocation of goodwill to each reporting unit.
Pro Forma Financial Information: The following unaudited pro forma financial information reflects the pro forma combined results of operations of NU and NSTAR and reflects the amortization of purchase price adjustments assuming the merger had taken place on January 1, 2011. The unaudited pro forma financial information has been presented for illustrative purposes only and is not necessarily indicative of the consolidated results of operations that would have been achieved or the future consolidated results of operations of NU.
| | | | | |
| For the Years Ended December 31, |
(Pro forma amounts in millions, except per share amounts) | 2012 | | 2011 |
Operating Revenues | $ | 7,004 | | $ | 7,361 |
Net Income Attributable to Controlling Interest | | 630 | | | 689 |
Basic EPS | | 2.00 | | | 2.20 |
Diluted EPS | | 1.99 | | | 2.19 |
115
Pro forma net income does not include potential cost savings associated with the merger. Pro forma net income also excludes certain non-recurring merger costs and costs related to the Connecticut and Massachusetts merger settlement agreements described below, with the following aggregate after-tax impacts:
| | | | | | |
| | For the Years Ended December 31, |
(Millions of Dollars) | 2012 | | 2011 |
Transaction and Other Costs | $ | 32 | | $ | 19 |
Settlement Agreement Impacts | | 60 | | | - |
Total After-Tax Non-Recurring Costs Excluded from | | | | | |
| Pro Forma Net Income Attributable to Controlling Interest | $ | 92 | | $ | 19 |
Regulatory Approvals: On February 15, 2012, NU and NSTAR reached comprehensive merger settlement agreements with the Massachusetts Attorney General and the DOER. The Attorney General settlement agreement covered a variety of rate-making and rate design issues, including a base distribution rate freeze through 2015 for NSTAR Electric, NSTAR Gas and WMECO and $15 million, $3 million and $3 million in the form of rate credits to their respective customers. The settlement agreement reached with the DOER covered the same rate-making and rate design issues as the Attorney General's settlement agreement, as well as a variety of matters impacting the advancement of Massachusetts clean energy policy established by the Green Communities Act and Global Warming Solutions Act. On April 4, 2012, the DPU approved the settlement agreements and the merger of NU and NSTAR.
On March 13, 2012, NU and NSTAR reached a comprehensive merger settlement agreement with both the Connecticut Attorney General and the Connecticut Office of Consumer Counsel. The settlement agreement covered a variety of matters, including a $25 million rate credit to CL&P customers, a CL&P base distribution rate freeze until December 1, 2014, and the establishment of a $15 million fund for energy efficiency and other initiatives to be disbursed at the direction of the DEEP. In the agreement, CL&P agreed to forego rate recovery of $40 million of the deferred storm restoration costs associated with restoration activities following Tropical Storm Irene and the October 2011 snowstorm. On April 2, 2012, the PURA approved the settlement agreement and the merger of NU and NSTAR.
The pre-tax financial impacts of the Connecticut and Massachusetts merger settlement agreements that were recognized in 2012 by NU, CL&P, NSTAR Electric, and WMECO are summarized as follows:
| | | | | | | | | | | |
(Millions of Dollars) | NU | | CL&P | | NSTAR Electric | | WMECO |
Customer Rate Credits | $ | 46 | | $ | 25 | | $ | 15 | | $ | 3 |
Storm Costs Deferral Reduction | | 40 | | | 40 | | | - | | | - |
Establishment of Energy Efficiency Fund | | 15 | | | - | | | - | | | - |
Total Pre-Tax Settlement Agreement Impacts | $ | 101 | | $ | 65 | | $ | 15 | | $ | 3 |
Goodwill: In accordance with the accounting standards, goodwill is not subject to amortization. However, goodwill is subject to fair value-based rules for measuring impairment, and resulting write-downs, if any, are charged to Operating Expenses. These accounting standards require that goodwill be reviewed at least annually for impairment and whenever facts or circumstances indicate that there may be an impairment. NU uses October 1st as the annual goodwill impairment testing date.
On April 10, 2012, upon consummation of the merger with NSTAR, NU recorded approximately $3.2 billion of goodwill. With the completion of the merger, NU reviewed its management structure and determined that the reporting units for the purpose of testing goodwill for impairment are Electric Distribution, Electric Transmission and Natural Gas Distribution. NU's reporting units are consistent with the operating segments underlying the reportable segments identified in Note 21, "Segment Information," to the financial statements. Accordingly, the goodwill resulting from the merger was allocated to the Electric Distribution, Electric Transmission and Natural Gas Distribution reporting units based on the estimated fair values of the reporting units as of the merger date.
Prior to the merger with NSTAR, the only reporting unit that maintained goodwill was the Natural Gas Distribution reportable segment related to the acquisition of the parent of Yankee Gas in 2000. This goodwill was recorded at Yankee Gas. The goodwill balance at Yankee Gas as of December 31, 2013 and 2012 was $0.3 billion.
NU completed its annual goodwill impairment test for each of its reporting units as of October 1, 2013 and determined that no impairment exists. There were no events subsequent to October 1, 2013 that indicated impairment of goodwill.
The allocation of goodwill to NU's reporting units was as follows:
| | | | | | | | | | | | | | |
(Billions of Dollars) | | Electric | | Electric | | Natural Gas | | | | |
| | | Distribution | | Transmission | | Distribution | | Total | |
Balance as of December 31, 2011 | | $ | - | | $ | - | | $ | 0.3 | | $ | 0.3 | |
| Merger with NSTAR | | | 2.5 | | | 0.6 | | | 0.1 | | | 3.2 | |
Balance as of December 31, 2012 | | $ | 2.5 | | $ | 0.6 | | $ | 0.4 | | $ | 3.5 | |
| | | | | | | | | | | | | | |
There were no changes to the goodwill balance or the allocation of goodwill for the year ended December 31, 2013. |
116
3.
REGULATORY ACCOUNTING
Eversource's Regulated companies are subject to rate-regulation that is based on cost recovery and meets the criteria for application of accounting guidance for rate-regulated operations, which considers the effect of regulation on the timing of the recognition of certain revenues and expenses. The Regulated companies' financial statements reflect the effects of the rate-making process. The rates charged to the customers of NU'sEversource's Regulated companies are designed to collect each company's costs to provide service, including a return on investment. Therefore, the accounting policies of the Regulated companies reflect the application of accounting guidance for entities with rate-regulated operations and reflect the effects of the rate-making process.
Management believes it is probable that each of the Regulated companies will recover their respective investments in long-lived assets, including regulatory assets. If management were to determine that it could no longer apply the accounting guidance applicable to rate-regulated enterprises to any of the Regulated companies' operations, or thatif management could not conclude it is probable that costs would be recovered from customers in future rates, the costs would be charged to net income in the period in which the determination is made.
Regulatory Assets: The components of regulatory assets arewere as follows:
| | | | | |
NU | As of December 31, |
(Millions of Dollars) | 2013 | | 2012 |
Benefit Costs | $ | 1,240.2 | | $ | 2,452.1 |
Derivative Liabilities | | 638.0 | | | 885.6 |
Goodwill | | 525.9 | | | 537.6 |
Storm Restoration Costs | | 589.6 | | | 547.7 |
Income Taxes, Net | | 626.2 | | | 516.2 |
Securitized Assets | | - | | | 232.6 |
Contractual Obligations - Yankee Companies | | 154.2 | | | 217.6 |
Buy Out Agreements for Power Contracts | | 70.2 | | | 92.9 |
Regulatory Tracker Mechanisms | | 323.4 | | | 190.1 |
Other Regulatory Assets | | 126.8 | | | 165.0 |
Total Regulatory Assets | | 4,294.5 | | | 5,837.4 |
Less: Current Portion | | 535.8 | | | 705.0 |
Total Long-Term Regulatory Assets | $ | 3,758.7 | | $ | 5,132.4 |
| | | | | | | | | | | | | | | | | | | | | | | | |
| | As of December 31, |
| | 2013 | | 2012 |
| | | | | NSTAR | | | | | | | | | | | NSTAR | | | | | | |
(Millions of Dollars) | CL&P | | Electric | | PSNH | | WMECO | | CL&P | | Electric | | PSNH | | WMECO |
Benefit Costs | $ | 297.7 | | $ | 496.7 | | $ | 100.6 | | $ | 57.3 | | $ | 563.2 | | $ | 781.2 | | $ | 223.7 | | $ | 116.0 |
Derivative Liabilities | | 630.4 | | | 7.7 | | | - | | | - | | | 866.2 | | | 14.9 | | | - | | | 3.0 |
Goodwill | | - | | | 451.5 | | | - | | | - | | | - | | | 461.5 | | | - | | | - |
Storm Restoration Costs | | 397.8 | | | 109.3 | | | 43.7 | | | 38.8 | | | 413.9 | | | 55.8 | | | 34.5 | | | 43.5 |
Income Taxes, Net | | 415.5 | | | 84.0 | | | 40.3 | | | 43.7 | | | 367.5 | | | 47.1 | | | 36.2 | | | 31.0 |
Securitized Assets | | - | | | - | | | - | | | - | | | - | | | 205.1 | | | 19.7 | | | 7.8 |
Contractual Obligations - | | | | | | | | | | | | | | | | | | | | | | | |
| Yankee Companies | | 19.8 | | | 6.2 | | | - | | | 4.5 | | | 64.0 | | | 22.8 | | | - | | | 14.9 |
Buy Out Agreements for Power Contracts | | - | | | 64.7 | | | 5.5 | | | - | | | - | | | 85.9 | | | 7.0 | | | - |
Regulatory Tracker Mechanisms | | 8.0 | | | 169.5 | | | 83.3 | | | 32.6 | | | 12.2 | | | 71.4 | | | 49.3 | | | 31.9 |
Other Regulatory Assets | | 44.8 | | | 49.7 | | | 38.1 | | | 12.2 | | | 57.3 | | | 46.3 | | | 43.6 | | | 16.1 |
Total Regulatory Assets | | 1,814.0 | | | 1,439.3 | | | 311.5 | | | 189.1 | | | 2,344.3 | | | 1,792.0 | | | 414.0 | | | 264.2 |
Less: Current Portion | | 150.9 | | | 204.1 | | | 92.2 | | | 43.0 | | | 185.9 | | | 347.1 | | | 62.9 | | | 42.4 |
Total Long-Term Regulatory Assets | $ | 1,663.1 | | $ | 1,235.2 | | $ | 219.3 | | $ | 146.1 | | $ | 2,158.4 | | $ | 1,444.9 | | $ | 351.1 | | $ | 221.8 |
Regulatory Costs in Other Long-Term Assets: The Regulated companies had $65.1 million ($7.3 million for CL&P, $33.4 million for NSTAR Electric, and $10.1 million for WMECO) and $69.9 million ($3.9 million for CL&P, $25.4 million for NSTAR Electric, $35.7 million for PSNH, and $1.4 million for WMECO) of additional regulatory costs as of December 31, 2013 and 2012, respectively, that were included in Other Long-Term Assets on the balance sheets. These amounts represent incurred costs for which recovery has not yet been specifically approved by the applicable regulatory agency. However, based on regulatory policies or past precedent on similar costs, management believes it is probable that these costs will ultimately be approved and recovered from customers in rates.
The PSNH balance as of December 31, 2012 primarily related to storm restoration costs incurred for Tropical Storm Irene, the October 2011 snowstorm and Storm Sandy that met the NHPUC criteria for cost deferral and recovery. Refer to the "Storm Restoration Costs" section in this Note for further discussion. The NSTAR Electric balance as of December 31, 2013 and 2012 primarily related to costs deferred in connection with the basic service bad debt adder. See Note 12G, "Commitments and Contingencies – Basic Service Bad Debt Adder," for further information.
Equity Return on Regulatory Assets: For rate-making purposes, the Regulated companies recover the carrying cost related to their regulatory assets. For certain regulatory assets, the carrying cost recovered includes an equity return component. This equity return, which is not recorded on the balance sheets, totaled $1.9 million and $2.5 million for CL&P and $33.1 million and $21.8 million for PSNH as of December 31, 2013 and 2012, respectively. These carrying costs will be recovered from customers in future rates.
| | | | | |
Eversource | As of December 31, |
(Millions of Dollars) | 2015 | | 2014 |
Benefit Costs | $ | 1,828.2 | | $ | 2,016.0 |
Derivative Liabilities | | 388.0 | | | 425.5 |
Income Taxes, Net | | 650.9 | | | 635.3 |
Storm Restoration Costs | | 436.9 | | | 502.8 |
Goodwill-related | | 484.9 | | | 505.4 |
Regulatory Tracker Mechanisms | | 526.5 | | | 350.5 |
Contractual Obligations - Yankee Companies | | 134.4 | | | 123.8 |
Other Regulatory Assets | | 134.0 | | | 167.3 |
Total Regulatory Assets | | 4,583.8 | | | 4,726.6 |
Less: Current Portion | | 845.8 | | | 672.5 |
Total Long-Term Regulatory Assets | $ | 3,738.0 | | $ | 4,054.1 |
11798
Regulatory Assets - The following provides further information about regulatory assets:
| | | | | | | | | | | | | | | | | | | | | | | | |
| | As of December 31, |
| | 2015 | | 2014 |
| | | | | NSTAR | | | | | | | | | | | NSTAR | | | | | | |
(Millions of Dollars) | CL&P | | Electric | | PSNH | | WMECO | | CL&P | | Electric | | PSNH | | WMECO |
Benefit Costs | $ | 413.6 | | $ | 479.9 | | $ | 164.2 | | $ | 84.9 | | $ | 445.4 | | $ | 515.9 | | $ | 174.3 | | $ | 85.0 |
Derivative Liabilities | | 380.8 | | | 1.3 | | | - | | | - | | | 410.9 | | | 4.5 | | | - | | | - |
Income Taxes, Net | | 444.4 | | | 85.7 | | | 34.5 | | | 31.8 | | | 437.7 | | | 83.7 | | | 38.0 | | | 35.5 |
Storm Restoration Costs | | 271.4 | | | 110.9 | | | 31.5 | | | 23.1 | | | 319.6 | | | 103.7 | | | 47.7 | | | 31.8 |
Goodwill-related | | - | | | 416.3 | | | - | | | - | | | - | | | 433.9 | | | - | | | - |
Regulatory Tracker Mechanisms | | 45.1 | | | 311.0 | | | 101.2 | | | 40.1 | | | 16.1 | | | 141.4 | | | 103.5 | | | 33.0 |
Other Regulatory Assets | | 82.0 | | | 56.3 | | | 31.5 | | | 11.3 | | | 66.1 | | | 94.7 | | | 41.3 | | | 12.9 |
Total Regulatory Assets | | 1,637.3 | | | 1,461.4 | | | 362.9 | | | 191.2 | | | 1,695.8 | | | 1,377.8 | | | 404.8 | | | 198.2 |
Less: Current Portion | | 268.3 | | | 348.4 | | | 105.0 | | | 56.2 | | | 220.3 | | | 198.7 | | | 111.7 | | | 51.9 |
Total Long-Term Regulatory Assets | $ | 1,369.0 | | $ | 1,113.0 | | $ | 257.9 | | $ | 135.0 | | $ | 1,475.5 | | $ | 1,179.1 | | $ | 293.1 | | $ | 146.3 |
Benefit Costs: NU's Eversource's Pension, SERP and PBOP Plans are accounted for in accordance with accounting guidance on defined benefit pension and other postretirementPBOP plans. BecauseThe liability recorded by the Regulated companies recoverto recognize the funded status of their retiree benefit costs from customers through rates,plans is offset by a regulatory assets are recordedasset in lieu of a charge to Accumulated Other Comprehensive Income/(Loss), reflecting ultimate recovery from customers through rates. The regulatory asset is amortized as the actuarial gains and losses and prior service cost are amortized to reflect the liability that is recognizednet periodic benefit cost for the funded status of the pension and other postretirement plans and isPBOP plans. All amounts are remeasured annually. Regulatory accounting wasis also applied to the portions of NU'sEversource's service company costs that support the Regulated companies, as these amounts are also recoverable. CL&P, NSTAR Electric, PSNH and WMECOAs these regulatory assets do not collectrepresent a cash outlay for the Regulated companies, no carrying charges on these benefit costs regulatory assets. charge is recovered from customers.
CL&P, NSTAR Electric, PSNH and WMECO recover benefit costs related to their distribution and transmission operations from customers in rates as allowed by their applicable regulatory commissions. NSTAR Electric and WMECO each recover their qualified pension and postretirementPBOP expenses related to distribution operations through rate reconciling mechanisms that fully track the change in net pension and postretirementPBOP expenses each year. NSTAR Electric earns a carrying charge on the excess cumulative benefit plan trust fund contributions it has made over what it has cumulatively recognized as net periodic benefit expense, net of deferred income taxes. As of December 31, 2013 and 2012, these balances were $379.9 million and $366.8 million of the total benefit costs regulatory asset, respectively.
Derivative Liabilities: Regulatory assets are recorded as an offset to derivative liabilities and relate to the fair value of contracts used to purchase energy and energy-related products that will be recovered from customers in future rates. See Note 5, "Derivative Instruments," to the financial statements for further information. These assets are excluded from rate base and are being recovered as the actual settlements occur over the duration of the contracts. See Note 4, "Derivative Instruments," to the financial statements for further information on these contracts.
Goodwill: The goodwill regulatory asset originated from the transaction that created NSTAR in 1999. This regulatory asset is currently being amortized and recovered from customers in rates without a carrying charge over a 40-year period (as of December 31, 2013, there were 26 years of amortization remaining).
Storm Restoration Costs: The storm restoration cost deferrals relate to costs incurred at CL&P, NSTAR Electric, PSNH and WMECO that each company expects to recover from customers. A storm must meet certain criteria to be declared a major storm with the criteria specific to each state jurisdiction and utility company as follows:
·
Connecticut - qualifying storm restoration costs must exceed $5 million for a storm to be declared a major storm;
·
Massachusetts - qualifying storm restoration costs must exceed $1 million for NSTAR Electric and $300,000 for WMECO and an emergency response plan must be initiated for a storm to be declared a major storm; and
·
New Hampshire - For a storm to be declared a major storm: (1) at least 10 percent of customers must be without power with at least 200 concurrent locations requiring repairs (trouble spots), or (2) at least 300 concurrent trouble spots must be reported.
Once a storm is declared major, all qualifying expenses prudently incurred during storm restoration efforts are deferred and recovered from customers.
In addition to storm restoration costs, PSNH is allowed recovery of prudently incurred storm pre-staging costs in accordance with NHPUC regulation.
In 2013, 2012 and 2011, CL&P, NSTAR Electric, PSNH and WMECO experienced significant storms, including Tropical Storm Irene, the October 2011 snowstorm, Storm Sandy, 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, which required the incurrence of costs to repair damage and restore customer service. The storm restoration cost regulatory asset balance at CL&P, NSTAR Electric, PSNH and WMECO reflects costs incurred for major storm events. Management believes the storm restoration costs were prudent and meet the criteria for specific cost recovery in Connecticut, Massachusetts and New Hampshire and as a result, are probable of recovery.
Storm Filings: Each electric utility is seeking recovery of its deferred storm restoration costs through its applicable regulatory recovery process.
On February 3, 2014, the PURA issued a draft decision on CL&P’s request to recover storm restoration costs associated with five major storms, all of which occurred in 2011 and 2012. In its draft decision, the PURA approved recovery of $365 million of deferred storm restoration costs and ordered CL&P to capitalize approximately $18 million of the deferred storm restoration costs as utility plant, which will be included in depreciation expense in future rate proceedings. PURA will allow recovery of the $365 million with carrying charges in CL&P’s distribution rates over a six-year period beginning December 1, 2014. The remaining costs were either disallowed or are probable of recovery in future rates and did not have a material impact on CL&P’s financial position, results of operations or cash flows.
On December 30, 2013, the DPU approved NSTAR Electric’s request to recover storm restoration costs, plus carrying costs, related to Tropical Storm Irene and the October 2011 snowstorm. The DPU approved recovery of $34.2 million of the $38 million requested costs. NSTAR Electric will recover these costs, plus carrying costs, in its distribution rates over a five-year period beginning on January 1, 2014.
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On June 27, 2013, the NHPUC approved an increase to PSNH’s distribution rates effective July 1, 2013, which included a $5 million increase to the current level of funding for the major storm cost reserve. The major storm cost reserve is used to offset the storm restoration cost regulatory asset.
On August 30, 2013, WMECO submitted its 2013 Annual Storm Reserve Recovery Cost Adjustment (SRRCA) filing to begin recovering the restoration costs associated with the October 2011 snowstorm and Storm Sandy. On December 20, 2013, the DPU approved the 2013 Annual SRRCA filing for effect on January 1, 2014, subject to further review and reconciliation.
Income Taxes, Net: The tax effect of temporary book-tax differences (differences between the periods in which transactions affect income in the financial statements and the periods in which they affect the determination of taxable income, including those differences relating to uncertain tax positions) is accounted for in accordance with the rate-making treatment of the applicable regulatory commissions and accounting guidance for income taxes. Differences in income taxes between the accounting guidance and the rate-making treatment of the applicable regulatory commissions are recorded as regulatory assets. As these assets are offset by deferred income tax liabilities, no carrying charge is collected. The amortization period of these assets varies depending on the nature and/or remaining life of the underlying assets and liabilities. For further information regarding income taxes, see Note 11,10, "Income Taxes," to the financial statements.
Storm Restoration Costs:Securitized Assets: NSTAR Electric's securitized regulatory asset balance primarily includedThe storm restoration cost deferrals relate to costs related to purchase power contract divestitures and certain costs related to NSTAR Electric’s former generation business that were recovered with a return through the transition charge and amounted to $186.1 million as of December 31, 2012. These costs were fully recovered from customers in 2013.
The securitized regulatory asset balance as of December 31, 2012 also included proceeds received from the issuance of RRBsincurred for major storm events at CL&P, NSTAR Electric, PSNH and WMECO that each company expects to recover from customers. A storm must meet certain criteria to qualify as a major storm with the criteria specific to each state jurisdiction and utility company. Once a storm qualifies as a major storm, all qualifying expenses incurred during storm restoration efforts are deferred and recovered from customers. In addition to storm restoration costs, CL&P and PSNH are each allowed to recover pre-staging storm costs. Of the total deferred storm restoration costs, $197 million is pending regulatory approval (including $106 million at NSTAR Electric, $61 million at PSNH, and $30 million at WMECO). Management believes the storm restoration costs were usedprudent 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. Each electric utility company earns a return on its deferred storm restoration cost regulatory asset balance.
Goodwill-related: The goodwill regulatory asset originated from a 1999 merger transaction and the DPU allowed its recovery in NSTAR Electric and NSTAR Gas rates. This regulatory asset is currently being amortized and recovered from customers in rates without a carrying charge over a 40-year period, and, as of December 31, 2015, there were 24 years of amortization remaining.
Regulatory Tracker Mechanisms:The Regulated companies’ approved rates are designed to buy out or buy down purchase power contracts.recover their costs incurred to provide service to customers. The collateralized amounts reflectedRegulated companies recover certain of their costs on a fully-reconciling basis through regulatory commission-approved tracking mechanisms. The differences between the costs incurred (or the rate recovery allowed) and the actual revenues are recorded as securitized regulatory assets for(for undercollections) or as regulatory liabilities (for overcollections) to be included in future customer rates each year. Carrying charges are recorded on all material regulatory tracker mechanisms.
CL&P, NSTAR Electric, PSNH and WMECO each recover, on a fully reconciling basis, the costs associated with the procurement of energy, transmission related costs from FERC-approved transmission tariffs, energy efficiency programs (including LBR at NSTAR Electric), low income assistance programs, certain uncollectible accounts receivable for hardship customers, and restructuring and stranded costs as a result of December 31, 2012 were $14.1 million, $19.7 millionderegulation. Energy procurement costs at PSNH include the costs related to its generating stations and $7.8 million, respectively. As of December 31, 2013, NSTAR Electric's, PSNH's and WMECO's RRBs were fully redeemed andat WMECO include the costs related regulatory assets were fully recovered from customers.to its solar generation.
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CL&P (effective December 1, 2014) and WMECO each have a regulatory commission approved revenue decoupling mechanism. Distribution revenues are decoupled from customer sales volumes, which breaks the relationship between sales volumes and revenues recognized. 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 received during a 12-month period is adjusted through rates in the following period. CL&P and WMECO's revenue decoupling mechanisms permit recovery of an annual base amount of distribution revenues of $1.059 billion and $132.4 million, respectively.
Contractual Obligations - Yankee Companies: CL&P, NSTAR Electric, PSNH and WMECO are responsible for their proportionate share of the remaining costs of the CYAPC, YAEC and MYAPC nuclear facilities, including decommissioning.nuclear fuel storage. A portion of these amountscosts was recorded as a regulatory asset. Amounts for CL&P are earning a return and are being recovered through the CTA. Amounts for NSTAR Electric and WMECO are being recovered without a return through the transition charge. Amounts for PSNH were fully recovered in 2006. As a result of NU'sEversource's consolidation of CYAPC and YAEC, NU'sEversource's regulatory asset balance also includes the regulatory assets of CYAPC and YAEC, which totalled $129.8totaled $110.9 million and $214$97.8 million as of December 31, 20132015 and 2012,2014, respectively. At the NU consolidated level, intercompanyIntercompany transactions between CL&P, NSTAR Electric, PSNH and WMECO and the CYAPC and YAEC companies have been eliminated in consolidation.consolidation of the Eversource financial statements.
Buy Out Agreements for Power Contracts: NSTAR Electric's balance represents the contract termination liability related to certain purchase power contract buy out agreements that were executed in 2004. The contracts’ termination payments occur through September 2016 and are collected from customers through NSTAR Electric’s transition charge over the same period. Therefore, NSTAR Electric does not earn a return on this regulatory asset. PSNH's balance represents payments associated with the termination of various power purchase contracts that were recorded as regulatory assets and are amortized over the remaining life of the contracts.
Regulatory Tracker Mechanisms: The Regulated companies’ approved rates are designed to recover their incurred costs to provide service to customers. The Regulated companies are permitted to recover certain of their costs on a fully-reconciling basis through regulatory commission-approved tracking mechanisms. The difference between the costs incurred (or the rate recovery allowed) and the actual revenues is recorded as regulatory assets (for undercollections) or regulatory liabilities (for overcollections) to be included in future customer rates each year. Carrying charges are recorded on all material regulatory tracker mechanisms.
CL&P, NSTAR Electric, PSNH and WMECO each recover the costs associated with the procurement of energy, transmission related costs from FERC-approved transmission tariffs, energy efficiency programs, low income assistance programs, and restructuring and stranded costs as a result of deregulation, on a fully reconciling basis. Energy procurement costs at PSNH include the costs related to its generating stations.
WMECO’s distribution revenue is decoupled from its customer sales volume. WMECO reconciles its annual base distribution rate recovery to a pre-established level of baseline distribution delivery service revenue. 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.
Other Regulatory Assets: Other Regulatory Assets primarily include asset retirement obligations, environmental remediation costs, losses associated with the reacquisition or redemption of long-term debt, purchase power contract termination costs and various other items, partially offsetitems.
Regulatory Costs in Other Long-Term Assets: The Regulated companies had $75.3 million (including $3.1 million for CL&P, $35.4 million for NSTAR Electric, $4.8 million for PSNH and $16.7 million for WMECO) and $60.5 million (including $1.3 million for CL&P, $33.2 million for NSTAR Electric, $0.9 million for PSNH, and $11 million for WMECO) of additional regulatory costs as of December 31, 2015 and 2014, respectively, that were included in Other Long-Term Assets on the balance sheets. These amounts represent incurred costs for which recovery has not yet been specifically approved by purchase price adjustments recordedthe applicable regulatory agency. However, based on regulatory policies or past precedent on similar costs, management believes it is probable that these costs will ultimately be approved and recovered from customers in rates. The NSTAR Electric balance as of December 31, 2015 and 2014 primarily related to the deferral of certain bad debt costs expected to be recovered in future rates.
Equity Return on Regulatory Assets in connection with the merger with NSTAR. The ARO costs associated with the depreciation ofAssets: For rate-making purposes, the Regulated companies' ARO assets and accretion ofcompanies recover the ARO liabilities are recorded ascarrying costs related to their regulatory assets. For CL&P, NSTAR Electric and WMECO, ARO assets,certain regulatory assets, the carrying cost recovered includes an equity return component. This equity return, which is not recorded on the balance sheets, totaled $1.5 million and liabilities offset$1.7 million for CL&P as of December 31, 2015 and are excluded2014, respectively. These carrying costs will be recovered from rate base. PSNH's ARO assets, regulatory assets and liabilities are includedcustomers in rate base; these costs are being recovered over the life of the underlying property, plant and equipment.future rates.
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As of December 31, 2015 and 2014, this equity return, which is not recorded on the balance sheets, totaled $48.3 million and $43.3 million, respectively, for PSNH. These amounts include $25 million of equity return on the Clean Air Project costs that PSNH has agreed not to bill customers pending NHPUC approval of a generation divestiture settlement agreement. For further information on the divestiture, see Note 11H, "Commitments and Contingencies – PSNH Generation Restructuring."
Regulatory Liabilities: The components of regulatory liabilities arewere as follows:
|
NU | As of December 31, |
Eversource | As of December 31, |
(Millions of Dollars) | 2013 | | 2012 | 2015 | | 2014 |
Cost of Removal | $ | 435.1 | | $ | 440.8 | $ | 437.1 | | $ | 439.9 |
Regulatory Tracker Mechanisms | | 151.2 | | 95.1 | | 99.7 | | 192.3 |
AFUDC – Transmission | | 68.1 | | 70.0 |
AFUDC - Transmission | | 66.1 | | 67.1 |
Other Regulatory Liabilities | | 52.9 | | | 68.4 | | 18.5 | | | 50.8 |
Total Regulatory Liabilities | | 707.3 | | 674.3 | | 621.4 | | 750.1 |
Less: Current Portion | | 204.3 | | | 134.1 | | 107.8 | | | 235.0 |
Total Long-Term Regulatory Liabilities | $ | 503.0 | | $ | 540.2 | $ | 513.6 | | $ | 515.1 |
|
| | As of December 31, | | As of December 31, |
| | 2013 | | 2012 | | 2015 | | 2014 |
| | | | NSTAR | | | | | | | | NSTAR | | | | | | | | NSTAR | | | | | | | | NSTAR | | | | |
(Millions of Dollars) | (Millions of Dollars) | CL&P | | Electric | | PSNH | | WMECO | | CL&P | | Electric | | PSNH | | WMECO | (Millions of Dollars) | CL&P | | Electric | | PSNH | | WMECO | | CL&P | | Electric | | PSNH | | WMECO |
Cost of Removal | Cost of Removal | $ | 29.1 | | $ | 250.0 | | $ | 49.7 | | $ | - | | $ | 44.2 | | $ | 240.3 | | $ | 51.2 | | $ | - | Cost of Removal | $ | 24.1 | | $ | 257.4 | | $ | 47.2 | | $ | 2.8 | | $ | 19.7 | | $ | 258.3 | | $ | 50.3 | | $ | 1.1 |
Regulatory Tracker Mechanisms | Regulatory Tracker Mechanisms | | 95.6 | | | 21.9 | | | 21.6 | | | 21.1 | | | 39.1 | | | 14.4 | | | 20.4 | | | 19.0 | Regulatory Tracker Mechanisms | | 56.2 | | | 3.3 | | | 3.4 | | | 12.9 | | | 122.6 | | | 20.7 | | | 14.2 | | | 22.3 |
AFUDC – Transmission | | 54.7 | | | 4.1 | | | - | | | 9.3 | | | 56.6 | | | 4.1 | | | - | | | 9.3 |
AFUDC - Transmission | | 51.5 | | | 5.7 | | | - | | | 8.9 | | | 53.6 | | | 4.4 | | | - | | | 9.1 |
Other Regulatory Liabilities | Other Regulatory Liabilities | | 8.4 | | | 31.1 | | | 1.0 | | | 3.4 | | | 16.5 | | | 32.9 | | | 3.8 | | | 2.4 | Other Regulatory Liabilities | | 4.2 | | | 1.3 | | | 4.2 | | | 0.1 | | | 10.1 | | | 28.9 | | | 2.9 | | | 0.8 |
Total Regulatory Liabilities | Total Regulatory Liabilities | | 187.8 | | | 307.1 | | | 72.3 | | | 33.8 | | | 156.4 | | | 291.7 | | | 75.4 | | | 30.7 | Total Regulatory Liabilities | | 136.0 | | | 267.7 | | | 54.8 | | | 24.7 | | | 206.0 | | | 312.3 | | | 67.4 | | | 33.3 |
Less: Current Portion | Less: Current Portion | | 94.0 | | | 54.0 | | | 20.6 | | | 19.9 | | | 32.1 | | | 47.5 | | | 23.0 | | | 21.0 | Less: Current Portion | | 61.2 | | | 3.3 | | | 6.9 | | | 13.1 | | | 124.7 | | | 49.6 | | | 16.0 | | | 22.5 |
Total Long-Term Regulatory Liabilities | Total Long-Term Regulatory Liabilities | $ | 93.8 | | $ | 253.1 | | $ | 51.7 | | $ | 13.9 | | $ | 124.3 | | $ | 244.2 | | $ | 52.4 | | $ | 9.7 | Total Long-Term Regulatory Liabilities | $ | 74.8 | | $ | 264.4 | | $ | 47.9 | | $ | 11.6 | | $ | 81.3 | | $ | 262.7 | | $ | 51.4 | | $ | 10.8 |
Cost of Removal: NU's Eversource's Regulated companies currently recover amounts in rates for future costs of removal of plant assets over the lives of the assets. The estimated cost to remove utility assets from service is recognized as a component of depreciation expense and the cumulative amountsamount collected from customers but not yet expended is recognized as a regulatory liability. Expended costs that exceed amounts collected from customers are recognized as regulatory assets, as they are probable of recovery in future rates.
AFUDC - Transmission: AFUDC was Regulatory liabilities were recorded by CL&P and WMECO for their NEEWSAFUDC accrued on certain reliability-related transmission projects to reflect local rate base recovery as a result of a FERC-approved transmission tariff. A regulatory liability was recorded by NSTAR Electric for AFUDC accrued on certain reliability-related transmission projects through MayDecember 31, 2011, all2015 to reflect local rate base recovery. These regulatory liabilities for CL&P, NSTAR Electric and WMECO will be amortized over the depreciable life of the related transmission assets.
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2015 Regulatory Developments:
FERC ROE Complaints: As a result of the actions taken by the FERC and other developments in the pending ROE complaint proceedings described in Note 11E, "Commitments and Contingencies – FERC ROE Complaints," Eversource recorded reserves for the first and second ROE complaints, which was reservedwere recorded as a regulatory liability and as a reduction to reflect rate baseoperating revenues. The cumulative pre-tax reserves (excluding interest) as of December 31, 2015, which include the impact of refunds given to customers, totaled $39.1 million for Eversource (including $21.4 million for CL&P, $8.5 million for NSTAR Electric, $3.1 million for PSNH, and $6.1 million for WMECO).
NSTAR Electric and NSTAR Gas Comprehensive Settlement Agreement: On March 2, 2015, the DPU approved the comprehensive settlement agreement between NSTAR Electric, NSTAR Gas and the Massachusetts Attorney General (the "Settlement") as filed with the DPU on December 31, 2014. The Settlement resolved the outstanding NSTAR Electric CPSL program filings for 2006 through 2011, the NSTAR Electric and NSTAR Gas PAM and energy efficiency-related customer billing adjustments reported in 2012, and the recovery of LBR related to NSTAR Electric's energy efficiency programs for 100 percent of the CWIP2009 through 2011 (11 dockets in total). In 2015, as a result of FERC-approved transmission incentives. Effective June 1, 2011, FERC approved changes to the ISO-NE Tariff inDPU order, to include 100 percent of the NEEWS CWIP in regional rate base. As a result, CL&P and WMECO no longer record AFUDC on NEEWS CWIP. NSTAR Electric recorded AFUDC on reliability-related projects over $5and NSTAR Gas commenced refunding a combined $44.7 million through December 31, 2013, 50 percent ofto customers, which was recorded as a regulatory liabilityliability. Refunds to reflect rate base recovery for 50 percent of the CWIP ascustomers will continue through December 2016. As a result of FERC-approved transmission incentives.the Settlement, NSTAR Electric increased its operating revenues and decreased its amortization expense in 2015, resulting in the recognition of a $21.7 million pre-tax benefit in 2015.
Other Regulatory Liabilities: Other Regulatory Liabilities primarily includes amountsNSTAR Electric Basic Service Bad Debt Adder: On January 7, 2015, the DPU issued an order concluding that NSTAR Electric had removed energy-related bad debt costs from base distribution rates effective January 1, 2006. As a result of the DPU order, in the first quarter of 2015, NSTAR Electric increased its regulatory assets and reduced its operations and maintenance expense by an under recovered amount of $24.2 million for energy-related bad debt costs through 2014, resulting in a pre-tax benefit in 2015. NSTAR Electric filed for recovery of the energy-related bad debt costs regulatory asset from customers and on November 20, 2015 the DPU approved NSTAR Electric's proposed rate increase to recover these costs over a 12-month period, effective January 1, 2016.
CL&P Distribution Rates: On July 2, 2015, PURA issued a final order that approved a settlement agreement filed on May 19, 2015, which allows for an increase to rate base of approximately $163 million associated with ADIT, including a regulatory asset to recover the incremental revenue requirement for the period December 1, 2014 through November 30, 2015 over a subsequent 24-month period. The rate base increase provided an increase to total allowed annual revenue requirements of $18.4 million beginning December 1, 2014. As part of the settlement agreement, the $18.4 million for the period December 1, 2014 through November 30, 2015 was recorded as a regulatory asset with a corresponding increase in Operating Revenues, and is being collected from customers in rates over a 24-month period beginning December 1, 2015.
NSTAR Gas Distribution Rates: On October 30, 2015, the DPU issued its order in the NSTAR Gas distribution rate case, which approved an annualized base rate increase of $15.8 million, plus other increases of approximately $11.5 million, mostly relating to recovery of pension and PBOP expenses and the Hopkinton GSA, effective January 1, 2016. In the order, the DPU also approved an authorized regulatory ROE of 9.8 percent, the establishment of a revenue decoupling mechanism, the recovery of certain bad debt expenses, and a 52.1 percent equity component of its capital structure. On November 19, 2015, NSTAR Gas filed a motion for reconsideration of the order with the DPU seeking the correction of mathematical errors and other plant and cost of service items.
As a result of this order, Eversource recorded regulatory deferrals for costs that have been approved for recovery or are expected to be approved for recovery in future rate proceedings, which resulted in the recognition of a $17.2 million pre-tax benefit in 2015. Included in this amount is a $10.5 million pre-tax benefit recorded at NSTAR Electric for certain uncollectible hardship accounts receivable that are subjectexpected to various rate reconciling mechanisms that, asbe recovered in future rates given the allowed recoveries of each period end date, would result in refunds to customers.uncollectible hardship accounts receivable by WMECO and NSTAR Gas.
4.3.
PROPERTY, PLANT AND EQUIPMENT AND ACCUMULATED DEPRECIATION
Utility property, plant and equipment is recorded at original cost. Original cost includes materials, labor, construction overhead and AFUDC for regulated property. The cost of repairs and maintenance, including planned major maintenance activities, is charged to Operating Expenses as incurred.
The following tables summarize the investments in utility property, plant and equipment by asset category:
|
NU | As of December 31, |
Eversource | As of December 31, |
(Millions of Dollars) | (Millions of Dollars) | 2013 | | 2012 | (Millions of Dollars) | 2015 | | 2014 |
Distribution - Electric | Distribution - Electric | $ | 11,950.2 | | $ | 11,438.2 | Distribution - Electric | $ | 13,054.8 | | $ | 12,495.2 |
Distribution - Natural Gas | Distribution - Natural Gas | | 2,425.9 | | 2,274.2 | Distribution - Natural Gas | | 2,727.2 | | 2,595.4 |
Transmission | | 6,412.5 | | 5,541.1 |
Transmission - Electric | | 7,691.9 | | 6,930.7 |
Generation | Generation | | 1,152.3 | | | 1,146.6 | Generation | | 1,194.1 | | | 1,170.9 |
Electric and Natural Gas Utility | Electric and Natural Gas Utility | | 21,940.9 | | 20,400.1 | Electric and Natural Gas Utility | | 24,668.0 | | 23,192.2 |
Other (1) | Other (1) | | 508.7 | | | 429.3 | Other (1) | | 558.6 | | | 551.3 |
Property, Plant and Equipment, Gross | Property, Plant and Equipment, Gross | | 22,449.6 | | 20,829.4 | Property, Plant and Equipment, Gross | | 25,226.6 | | 23,743.5 |
Less: Accumulated Depreciation | Less: Accumulated Depreciation | | | | | Less: Accumulated Depreciation | | | | |
| Electric and Natural Gas Utility | | (5,387.0) | | (5,065.1) | Electric and Natural Gas Utility | | (6,141.1) | | (5,777.8) |
| Other | | (196.2) | | | (171.5) | Other | | (255.6) | | | (231.8) |
Total Accumulated Depreciation | Total Accumulated Depreciation | | (5,583.2) | | | (5,236.6) | Total Accumulated Depreciation | | (6,396.7) | | | (6,009.6) |
Property, Plant and Equipment, Net | Property, Plant and Equipment, Net | | 16,866.4 | | 15,592.8 | Property, Plant and Equipment, Net | | 18,829.9 | | 17,733.9 |
Construction Work in Progress | Construction Work in Progress | | 709.8 | | | 1,012.2 | Construction Work in Progress | | 1,062.5 | | | 913.1 |
Total Property, Plant and Equipment, Net | Total Property, Plant and Equipment, Net | $ | 17,576.2 | | $ | 16,605.0 | Total Property, Plant and Equipment, Net | $ | 19,892.4 | | $ | 18,647.0 |
(1)
These assets represent unregulated property and are primarily comprised of building improvements, at RRR,computer software, hardware and equipment at NUSCO and telecommunications assets at NSTAR Communications, Inc.
Eversource Service.
120101
| | | | | | | | | | | | | | | | | | | | | | | |
| As of December 31, |
| 2015 | | 2014 |
| | | | NSTAR | | | | | | | | | | | NSTAR | | | | | | |
(Millions of Dollars) | CL&P | | Electric | | PSNH | | WMECO | | CL&P | | Electric | | PSNH | | WMECO |
Distribution | $ | 5,377.2 | | $ | 5,100.5 | | $ | 1,804.8 | | $ | 812.3 | | $ | 5,158.8 | | $ | 4,895.5 | | $ | 1,696.7 | | $ | 784.2 |
Transmission | | 3,618.0 | | | 2,131.3 | | | 928.2 | | | 964.9 | | | 3,274.0 | | | 1,928.5 | | | 789.7 | | | 891.0 |
Generation | | - | | | - | | | 1,158.1 | | | 36.0 | | | - | | | - | | | 1,136.5 | | | 34.4 |
Property, Plant and
Equipment, Gross | | 8,995.2 | | | 7,231.8 | | | 3,891.1 | | | 1,813.2 | | | 8,432.8 | | | 6,824.0 | | | 3,622.9 | | | 1,709.6 |
Less: Accumulated Depreciation | | (2,041.9) | | | (1,886.8) | | | (1,171.0) | | | (307.0) | | | (1,928.0) | | | (1,761.4) | | | (1,090.0) | | | (297.4) |
Property, Plant and Equipment, Net | | 6,953.3 | | | 5,345.0 | | | 2,720.1 | | | 1,506.2 | | | 6,504.8 | | | 5,062.6 | | | 2,532.9 | | | 1,412.2 |
Construction Work in Progress | | 203.5 | | | 310.5 | | | 135.3 | | | 69.1 | | | 304.9 | | | 272.8 | | | 102.9 | | | 49.1 |
Total Property, Plant and
Equipment, Net | $ | 7,156.8 | | $ | 5,655.5 | | $ | 2,855.4 | | $ | 1,575.3 | | $ | 6,809.7 | | $ | 5,335.4 | | $ | 2,635.8 | | $ | 1,461.3 |
| | | | | | | | | | | | | | | | | | | | | | | |
| As of December 31, |
| 2013 | | 2012 |
| | | | NSTAR | | | | | | | | | | | NSTAR | | | | | | |
(Millions of Dollars) | CL&P | | Electric | | PSNH | | WMECO | | CL&P | | Electric | | PSNH | | WMECO |
Distribution | $ | 4,930.7 | | $ | 4,694.7 | | $ | 1,608.2 | | $ | 756.6 | | $ | 4,691.3 | | $ | 4,539.9 | | $ | 1,520.1 | | $ | 724.2 |
Transmission | | 3,071.9 | | | 1,772.3 | | | 695.7 | | | 826.4 | | | 2,796.1 | | | 1,529.7 | | | 599.2 | | | 583.7 |
Generation | | - | | | - | | | 1,131.2 | | | 21.1 | | | - | | | - | | | 1,125.5 | | | 21.1 |
Property, Plant and | | | | | | | | | | | | | | | | | | | | | | | |
Equipment, Gross | | 8,002.6 | | | 6,467.0 | | | 3,435.1 | | | 1,604.1 | | | 7,487.4 | | | 6,069.6 | | | 3,244.8 | | | 1,329.0 |
Less: Accumulated Depreciation | | (1,804.1) | | | (1,631.3) | | | (1,021.8) | | | (271.5) | | | (1,698.1) | | | (1,540.1) | | | (954.0) | | | (252.1) |
Property, Plant and Equipment, Net | | 6,198.5 | | | 4,835.7 | | | 2,413.3 | | | 1,332.6 | | | 5,789.3 | | | 4,529.5 | | | 2,290.8 | | | 1,076.9 |
Construction Work in Progress | | 252.8 | | | 208.2 | | | 54.3 | | | 48.5 | | | 363.7 | | | 205.8 | | | 61.7 | | | 213.6 |
Total Property, Plant and | | | | | | | | | | | | | | | | | | | | | | | |
Equipment, Net | $ | 6,451.3 | | $ | 5,043.9 | | $ | 2,467.6 | | $ | 1,381.1 | | $ | 6,153.0 | | $ | 4,735.3 | | $ | 2,352.5 | | $ | 1,290.5 |
As of December 31, 2015, PSNH had $1.2 billion in gross generation utility plant assets and related Accumulated Depreciation of $522.4 million. These generation assets are the subject of a divestiture agreement entered into on June 10, 2015 between Eversource, PSNH and key New Hampshire officials whereby, among other resolutions, PSNH has agreed to divest these generation assets upon NHPUC approval. Upon completion of the divestiture process, remaining costs not recovered by the sale of these assets (stranded costs) will be recovered via bonds that will be secured by a non-bypassable charge or other recovery mechanisms in rates billed to PSNH’s customers. See Note 11H, “Commitments and Contingencies – PSNH Generation Restructuring,” for further information.
Depreciation of utility assets is calculated on a straight-line basis using composite rates based on the estimated remaining useful lives of the various classes of property (estimated useful life for PSNH distribution). The composite rates, which are subject to approval by the appropriate state regulatory agency. The composite ratesagency, include a cost of removal component (other than PSNH Generation), which is collected from customers over the lives of the plant assets and is recognized as a regulatory liability. Depreciation rates are applied to property from the time it is placed in service.
Upon retirement from service, the cost of the utility asset is charged to the accumulated provision for depreciation. The actual incurred removal costs are applied against the related regulatory liability.
The depreciation rates for the various classes of utility property, plant and equipment aggregate to composite rates as follows:
|
(Percent) | 2013 | | 2012 | | 2011 | | 2015 | | | 2014 | | | 2013 | |
NU | | 2.8 | | 2.5 | | 2.6 |
Eversource | | 2.9 | % | | 3.0 | % | | 2.8 | % |
CL&P | | 2.5 | | 2.5 | | 2.4 | | 2.7 | % | | 2.7 | % | | 2.5 | % |
NSTAR Electric | | 2.9 | | 2.8 | | 3.0 | | 3.0 | % | | 3.0 | % | | 2.9 | % |
PSNH | | 3.0 | | 3.0 | | 2.9 | | 3.2 | % | | 3.0 | % | | 3.0 | % |
WMECO | | 2.9 | | 3.3 | | 2.9 | | 2.7 | % | | 3.3 | % | | 2.9 | % |
|
The following table summarizes average useful lives of depreciable assets: | The following table summarizes average remaining useful lives of depreciable assets: | | | | | | | | | | | | | | | | | | | | | | | |
| | Average Depreciable Life | | As of December 31, 2015 |
(Years) | (Years) | NU | | CL&P | | NSTAR Electric | | PSNH | | WMECO | (Years) | Eversource | | CL&P | | NSTAR Electric | | PSNH | | WMECO |
Distribution | Distribution | | 36.1 | | 42.0 | | 32.9 | | 32.7 | | 29.8 | Distribution | | 34.8 | | 37.3 | | 31.9 | | 31.3 | | 30.5 |
Transmission | Transmission | | 43.0 | | 39.6 | | 47.2 | | 42.3 | | 49.5 | Transmission | | 41.6 | | 38.7 | | 43.8 | | 41.6 | | 50.0 |
Generation | Generation | | 32.2 | | - | | - | | 32.4 | | 25.0 | Generation | | 30.7 | | - | | - | | 30.9 | | 25.0 |
Other | Other | | 14.6 | | - | | - | | - | | - | Other | | 14.1 | | - | | - | | - | | - |
5.4.
DERIVATIVE INSTRUMENTS
The Regulated companies purchase and procure energy and energy-related products, for their customers, which are subject to price volatility.volatility, for their customers. The costs associated with supplying energy to customers are recoverable through customerfrom customers in future rates. The Regulated companies manage the risks associated with the price volatility of energy and energy-related products through the use of derivative and nonderivative contracts.
Many of the derivative contracts meet the definition of, and are designated as, normal and qualify for accrual accounting under the applicable accounting guidance. The costs and benefits of derivative contracts that meet the definition of normal are recognized in Operating Expenses or Operating Revenues on the statements of income, as applicable, as electricity or natural gas is delivered.
Derivative contracts that are not designated as normal are recorded at fair value as current or long-term Derivative Assets or Derivative Liabilities on the balance sheets. For the Regulated companies, regulatory assets or regulatory liabilities are recorded to offset the fair values of derivatives, as costscontract settlement amounts are recovered from, or refunded to, customers in their respective energy supply rates. For NU's unregulated wholesale marketing contracts that expired on December 31, 2013, changes in fair values of derivatives were included in Net Income.
121102
The gross fair values of derivative assets and liabilities with the same counterparty are offset and reported as net Derivative Assets or Derivative Liabilities, with current and long-term portions, on the balance sheets. Cash collateral posted or collected under master netting agreements is recorded as an offset to the derivative asset or liability. The following tables presenttable presents the gross fair values of contracts, categorized by risk type, and the net amountamounts recorded as current or long-term derivative assetassets or liability:liabilities:
| | | | | | | | | |
| | As of December 31, 2013 |
| | Commodity Supply and | | | | Net Amount Recorded as |
(Millions of Dollars) | Price Risk Management | | Netting (1) | | Derivative Asset/(Liability) |
Current Derivative Assets: | | | | | | | | |
Level 2: | | | | | | | | |
| Other (1) | $ | 1.9 | | $ | (0.3) | | $ | 1.6 |
Level 3: | | | | | | | | |
| CL&P (1) | | 17.1 | | | (9.8) | | | 7.3 |
| NSTAR Electric | | 1.2 | | | - | | | 1.2 |
| WMECO | | 0.1 | | | - | | | 0.1 |
Total Current Derivative Assets | $ | 20.3 | | $ | (10.1) | | $ | 10.2 |
| | | | | | | | | |
Long-Term Derivative Assets: | | | | | | | | |
Level 2: | | | | | | | | |
| Other | $ | 0.2 | | $ | - | | $ | 0.2 |
Level 3: | | | | | | | | |
| CL&P (1) | | 113.6 | | | (42.2) | | | 71.4 |
| WMECO | | 2.6 | | | - | | | 2.6 |
Total Long-Term Derivative Assets | $ | 116.4 | | $ | (42.2) | | $ | 74.2 |
| | | | | | | | | |
Current Derivative Liabilities: | | | | | | | | |
Level 3: | | | | | | | | |
| CL&P | $ | (92.2) | | $ | - | | $ | (92.2) |
| NSTAR Electric | | (1.5) | | | - | | | (1.5) |
Total Current Derivative Liabilities | $ | (93.7) | | $ | - | | $ | (93.7) |
| | | | | | | | | |
Long-Term Derivative Liabilities: | | | | | | | | |
Level 3: | | | | | | | | |
| CL&P | $ | (617.1) | | $ | - | | $ | (617.1) |
| NSTAR Electric | | (7.0) | | | - | | | (7.0) |
Total Long-Term Derivative Liabilities | $ | (624.1) | | $ | - | | $ | (624.1) |
|
| | As of December 31, |
| 2015 | | 2014 |
| | As of December 31, 2012 | | Commodity Supply | | | | Net Amount | | Commodity Supply | | | | Net Amount |
| | Commodity Supply and | | | | Net Amount Recorded as | | and Price Risk | | | | | Recorded as | | and Price Risk | | | | | | Recorded as |
(Millions of Dollars) | (Millions of Dollars) | Price Risk Management | | Netting (1) | | Derivative Asset/(Liability) | (Millions of Dollars) | Management | | Netting(1) | | a Derivative | | Management | | Netting(1) | | a Derivative |
Current Derivative Assets: | Current Derivative Assets: | | | | | | | | | Current Derivative Assets: | | | | | | | | | | | | | | | | | |
Level 3: | | | | | | | | | | | | | | | | | |
| Eversource | $ | 16.7 | | $ | (10.9) | | $ | 5.8 | | $ | 16.2 | | $ | (6.6) | | $ | 9.6 |
| CL&P | | 16.7 | | | (10.9) | | | 5.8 | | | 16.1 | | | (6.6) | | | 9.5 |
| NSTAR Electric | | - | | | - | | | - | | | 0.1 | | | - | | | 0.1 |
| | | | | | | | | | | | | | | | | | |
Long-Term Derivative Assets: | | | | | | | | | | | | | | | | | |
Level 2: | Level 2: | | | | | | | | | Level 2: | | | | | | | | | | | | | | | | | |
| Other | $ | 0.2 | | $ | - | | $ | 0.2 | Eversource | $ | 0.1 | | $ | - | | $ | 0.1 | | $ | - | | $ | - | | $ | - |
Level 3: | Level 3: | | | | | | | | | Level 3: | | | | | | | | | | | | | | | | | |
| CL&P(1) | | 17.7 | | | (12.0) | | | 5.7 | Eversource | | 62.0 | | | (19.3) | | | 42.7 | | | 93.5 | | | (19.2) | | | 74.3 |
| Other | | 5.5 | | | - | | | 5.5 | CL&P | | 60.7 | | | (19.3) | | | 41.4 | | | 93.5 | | | (19.2) | | | 74.3 |
Total Current Derivative Assets | $ | 23.4 | | $ | (12.0) | | $ | 11.4 |
| | | | | | | | | | NSTAR Electric | | 1.3 | | | - | | | 1.3 | | | - | | | - | | | - |
Long-Term Derivative Assets: | | | | | | | | |
Level 3: | | | | | | | | |
| CL&P(1) | $ | 159.7 | | $ | (69.1) | | $ | 90.6 |
Total Long-Term Derivative Assets | $ | 159.7 | | $ | (69.1) | | $ | 90.6 |
| | | | | | | | | | | | | | | | | | | | | | | | | | | |
Current Derivative Liabilities: | Current Derivative Liabilities: | | | | | | | | | Current Derivative Liabilities: | | | | | | | | | | | | | | | | | |
Level 2: | Level 2: | | | | | | | | | Level 2: | | | | | | | | | | | | | | | | | |
| Other(1) (2) | $ | (19.9) | | $ | 0.6 | | $ | (19.3) | Eversource | $ | (5.8) | | $ | - | | $ | (5.8) | | $ | (9.8) | | $ | - | | $ | (9.8) |
Level 3: | Level 3: | | | | | | | | | Level 3: | | | | | | | | | | | | | | | | | |
| CL&P | | (96.9) | | | - | | | (96.9) | Eversource | | (92.3) | | | - | | | (92.3) | | | (90.0) | | | - | | | (90.0) |
| NSTAR Electric | | (1.0) | | | - | | | (1.0) | CL&P | | (91.8) | | | - | | | (91.8) | | | (88.5) | | | - | | | (88.5) |
Total Current Derivative Liabilities | $ | (117.8) | | $ | 0.6 | | $ | (117.2) |
| | | | | | | | | | NSTAR Electric | | (0.5) | | | - | | | (0.5) | | | (1.5) | | | - | | | (1.5) |
Long-Term Derivative Liabilities: | | | | | | | | |
| | | | | | | | | | | | | | | | | | |
Long-Term Derivative Liabilities: | Level 2: | Level 2: | | | | | | | | | Level 2: | | | | | | | | | | | | | | | | | |
| Other | $ | (0.2) | | $ | - | | $ | (0.2) | Eversource | $ | - | | $ | - | | $ | - | | $ | (0.3) | | $ | - | | $ | (0.3) |
Level 3: | Level 3: | | | | | | | | | Level 3: | | | | | | | | | | | | | | | | | |
| CL&P | | (865.6) | | | - | | | (865.6) | Eversource | | (337.1) | | | - | | | (337.1) | | | (409.3) | | | - | | | (409.3) |
| NSTAR Electric | | (13.9) | | | - | | | (13.9) | CL&P | | (336.2) | | | - | | | (336.2) | | | (406.2) | | | - | | | (406.2) |
| WMECO | | (3.0) | | | - | | | (3.0) | NSTAR Electric | | (0.9) | | | - | | | (0.9) | | | (3.1) | | | - | | | (3.1) |
Total Long-Term Derivative Liabilities | $ | (882.7) | | $ | - | | $ | (882.7) |
(1)
Amounts represent derivative assets and liabilities that NUEversource elected to record net on the balance sheets. These amounts are subject to master netting agreements or similar agreements for which the right of offset exists.
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(2)
As of December 31, 2012, NU had $4.1 million of cash posted related to these contracts, which was not offset against the derivative liability and is recorded as Prepayments and Other Current Assets on the balance sheets.
The business activities that result in the recognition of derivative assets also create exposure to various counterparties. As of December 31, 2013, NU2015, Eversource’s and CL&P's derivative assets were exposed to counterparty credit risk. Of the totalEversource's and CL&P's derivative assets, $80approximately $47 million and $79 million, respectively, werewas contracted with investment grade entities.
For further information on the fair value of derivative contracts, see Note 1H, "Summary of Significant Accounting Policies - Fair Value Measurements," and Note 1I, "Summary of Significant Accounting Policies - Derivative Accounting," to the financial statements.
Derivatives Not Designated as HedgesDerivative Contracts At Fair Value with Offsetting Regulatory Amounts
Commodity Supply and Price Risk Management: As required by regulation, CL&P, along with UI, has capacity-related contracts with generation facilities. These contracts and similar UI contracts have an expected capacity of 787 MW. CL&P has a sharing agreement with UI, with 80 percent of the costs or benefits of each contract borne by or allocated to CL&P and 20 percent borne by or allocated to UI. The combined capacity of these contracts is 787 MW. The capacity contracts extend through 2026 and obligate both CL&P and UI to make or receive payments on a monthly basis to or from the generation facilities based on the difference between a set capacity price and the forward capacity market price received in the ISO-NE capacity markets. In addition, CL&P has a contract to purchase 0.1 million MWh of energy per year through 2020.
NSTAR Electric has a renewable energy contract to purchase 0.1 million MWh of energy per year through 2018 and a capacity relatedcapacity-related contract to purchase up to 35 MW per year through 2019.
WMECO has a renewable energy contract to purchase 0.1 million MWh of energy per year through 2029 with a facility that has not yet achieved commercial operation.
As of December 31, 20132015 and 2012, NU2014, Eversource had NYMEX futurefinancial contracts for natural gas futures in order to reduce variability associated with the purchase price of approximately 9.1 million and 11.58.8 million MMBtu of natural gas, respectively.
As ofFor the years ended December 31, 2012, NU had approximately 24 thousand MWh2015, 2014 and 2013, there were losses of supply volumes remaining in its unregulated wholesale portfolio when expected sales were compared with supply contracts. These contracts expired on December 31, 2013.
The following table presents$60.2 million and gains of $134.4 million and $160.6 million, respectively, deferred as regulatory costs, which reflect the current change in fair value primarily recovered through rates from customers, associated with NU’sEversource's derivative contracts not designated as hedges:contracts.
| | | | | | | | | | | |
Location of Amounts | | | Amounts Recognized on Derivatives |
Recognized on Derivatives | | | For the Years Ended December 31, |
(Millions of Dollars) | | | 2013 | | 2012 | | 2011 |
NU | | | | | | | | | | |
Balance Sheet: | | | | | | | | | | |
| Regulatory Assets and Liabilities | | | $ | 160.6 | | $ | (29.0) | | $ | (162.0) |
Statement of Income: | | | | | | | | | | |
| Purchased Power, Fuel and Transmission | | | | 1.0 | | | (0.7) | | | 0.5 |
Credit Risk
Certain of NU’sEversource's derivative contracts contain credit risk contingent features.provisions. These featuresprovisions require NUEversource to maintain investment grade credit ratings from the major rating agencies and to post collateral for contracts in a net liability position over specified credit limits. As of December 31, 2013, there were no derivative contracts in a net liability position that were subject to credit risk contingent features. As of December 31, 2012, NU2015 and 2014, Eversource had $15.3$5.8 million and $10 million, respectively, of derivative contracts in a net liability position that were
103
subject to credit risk contingent featuresprovisions and would have been required to post additional collateral of $17.4$5.8 million and $10 million, respectively, if NU parent’sEversource parent's unsecured debt credit ratings had been downgraded to below investment grade.
Fair Value Measurements of Derivative Instruments
Valuation of Derivative Instruments:Derivative contracts classified as Level 2 in the fair value hierarchy relate to the financial contracts for natural gas futures and forward contracts to purchase energy.futures. Prices are obtained from broker quotes and are based on actual market activity. The contracts are valued using the mid-point of the bid-ask spread.NYMEX natural gas prices. Valuations of these contracts also incorporate discount rates using the yield curve approach.
The fair value of derivative contracts classified as Level 3 utilizes significant unobservable inputs. The fair value is modeled using income techniques, such as discounted cash flow valuations adjusted for assumptions relating to exit price. Significant observable inputs for valuations of these contracts include energy and energy-related product prices in future years for which quoted prices in an active market exist. Fair value measurements categorized in Level 3 of the fair value hierarchy are prepared by individuals with expertise in valuation techniques, pricing of energy and energy-related products, and accounting requirements. The future power and capacity prices for periods that are not quoted in an active market or established at auction are based on available market data and are escalated based on estimates of inflation in order to address the full time period of the contract.
Valuations of derivative contracts using a discounted cash flow methodology include assumptions regarding the timing and likelihood of scheduled payments and also reflect non-performance risk, including credit, using the default probability approach based on the counterparty's credit rating for assets and the Company's credit rating for liabilities. Valuations incorporate estimates of premiums or
123
discounts that would be required by a market participant to arrive at an exit price, using historical market transactions adjusted for the terms of the contract.
The following is a summary of NU’s,Eversource's, including CL&P’s,&P's and NSTAR Electric’s and WMECO’s,Electric's, Level 3 derivative contracts and the range of the significant unobservable inputs utilized in thetheir respective valuations over the duration of the contracts:
| | | | | | | | | | | | | | | | | |
| As of December 31, 2013
| | As of December 31, 2012
|
| | Range
| | Period Covered
| | | Range
| | Period Covered
|
Energy Prices:
| | | | | | | | | | | | | | | | | |
NU
| $49 - 77 per MWh
| | 2018-2029
| | $43 - 90 per MWh
| | 2018 - 2028
|
CL&P
| $56 - 58 per MWh
| | 2018-2029
| | $50 - 55 per MWh
| | 2018 - 2020
|
WMECO
| $49 - 77 per MWh
| | 2018-2029
| | $43 - 90 per MWh
| | 2018 - 2028
|
| | | | | | | | | | | | | | | | | |
Capacity Prices:
| | | | | | | | | | | | | | | | | |
NU
| $5.07 - 11.82 per kW-Month
| | 2017-2029
| | $1.40 -10.53 per kW-Month
| | 2016 - 2028
|
CL&P
| $5.07 - 10.42 per kW-Month
| | 2017-2026
| | $1.40 - 9.83 per kW-Month
| | 2016 - 2026
|
NSTAR Electric
| $5.07 - 7.38 per kW-Month
| | 2017-2019
| | $1.40 - 3.39 per kW-Month
| | 2016 - 2019
|
WMECO
| $5.07 - 11.82 per kW-Month
| | 2017-2029
| | $1.40 - 10.53 per kW-Month
| | 2016 - 2028
|
| | | | | | | | | | | | | | | | | |
Forward Reserve:
| | | | | | | | | | | | | | | | | |
NU, CL&P
| $3.30 per kW-Month
| | 2014-2024
| | $0.35 - 0.90 per kW-Month
| | 2013 - 2024
|
| | | | | | | | | | | | | | | | | |
REC Prices:
| | | | | | | | | | | | | | | | | |
NU
| $36 - 87 per REC
| | 2014-2029
| | $25 - 85 per REC
| | 2013 - 2028
|
NSTAR Electric
| $36 - 70 per REC
| | 2014-2018
| | $25 - 71 per REC
| | 2013 - 2018
|
WMECO
| $36 - 87 per REC
| | 2014-2029
| | $25 - 85 per REC
| | 2013 - 2028
|
| | | | | | | | | | | | | | | | | |
| As of December 31, |
| 2015 | | 2014 |
| | Range | | Period Covered | | | Range | | Period Covered |
Capacity Prices: | | | | | | | | | | | | | | | | | |
Eversource | $ | 10.81 | - | 15.82 | per kW-Month | | 2016 - 2026 | | $ | 5.30 | - | 12.98 | per kW-Month | | 2016 - 2026 |
CL&P | $ | 10.81 | - | 12.60 | per kW-Month | | 2019 - 2026 | | $ | 11.08 | - | 12.98 | per kW-Month | | 2018 - 2026 |
NSTAR Electric | $ | 10.81 | - | 15.82 | per kW-Month | | 2016 - 2019 | | $ | 5.30 | - | 11.10 | per kW-Month | | 2016 - 2019 |
| | | | | | | | | | | | | | | | | |
Forward Reserve: | | | | | | | | | | | | | | | | | |
Eversource, CL&P | $ | 2.00 | per kW-Month | | 2016 - 2024 | | $ | 5.80 | - | 9.50 | per kW-Month | | 2015 - 2024 |
| | | | | | | | | | | | | | | | | |
REC Prices: | | | | | | | | | | | | | | | | | |
Eversource, NSTAR Electric | $ | 45 | - | 51 | | per REC | | 2016 - 2018 | | $ | 38 | - | 56 | | per REC | 2015 - 2018 |
Exit price premiums of 105 percent through 32to 22 percent are also applied on these contracts and reflect the uncertainty and illiquidity premiums that would be required based on the most recent market activity available for similar type contracts.
Significant increases or decreases in future energy or capacity prices in isolation would decrease or increase, respectively, the fair value of the derivative liability. Any increases in the risk premiums would increase the fair value of the derivative liabilities. Changes in these fair values are recorded as a regulatory asset or liability and would not impact net income.
Valuations using significant unobservable inputs: The following tables presenttable presents changes for the years ended December 31, 2013 and 2012 in the Level 3 category of derivative assets and derivative liabilities measured at fair value on a recurring basis. The derivative assets and liabilities are presented on a net basis. The fair value
| | | | | | | | |
(Millions of Dollars) | Eversource | | CL&P | | NSTAR Electric |
Derivatives, Net: | | | | | | | | |
Fair Value as of January 1, 2014 | $ | (635.2) | | $ | (630.6) | | $ | (7.3) |
Net Realized/Unrealized Gains Included in Regulatory Assets and Liabilities | | 141.3 | | | 139.7 | | | 4.3 |
Settlements | | 78.5 | | | 80.0 | | | (1.5) |
Fair Value as of December 31, 2014 | $ | (415.4) | | $ | (410.9) | | $ | (4.5) |
Net Realized/Unrealized Losses Included in Regulatory Assets and Liabilities | | (52.1) | | | (51.3) | | | (0.8) |
Settlements | | 86.6 | | | 81.4 | | | 5.2 |
Fair Value as of December 31, 2015 | $ | (380.9) | | $ | (380.8) | | $ | (0.1) |
Significant increases or decreases in 2012 reflects a transfer of remaining unregulated wholesale marketing sourcing contracts that had previously been presented as a portfolio along with the unregulated wholesale marketing sales contract as Level 3 under the highest and best use valuation premise. These contracts, which expired on December 31, 2013, were classified within Level 2 offuture energy or capacity prices in isolation would decrease or increase, respectively, the fair value hierarchy as of December 31, 2012.
| | | | | | | | | | | | |
(Millions of Dollars) | NU(1) | | CL&P | | NSTAR Electric | | WMECO |
Derivatives, Net: | | | | | | | | | | | |
Fair Value as of January 1, 2012 | $ | (962.2) | | $ | (931.6) | | $ | (3.4) | | $ | (7.3) |
Liabilities Assumed due to Merger with NSTAR | | (5.4) | | | - | | | - | | | - |
Transfer to Level 2 | | 32.2 | | | - | | | - | | | - |
Net Realized/Unrealized Gains/(Losses) Included in: | | | | | | | | | | | |
| Net Income(2) | | 10.9 | | | - | | | - | | | - |
| Regulatory Assets and Liabilities | | (29.2) | | | (21.6) | | | (15.2) | | | 4.3 |
Settlements | | 75.1 | | | 87.0 | | | 3.7 | | | - |
Fair Value as of December 31, 2012 | $ | (878.6) | | $ | (866.2) | | $ | (14.9) | | $ | (3.0) |
Net Realized/Unrealized Gains/(Losses) Included in: | | | | | | | | | | | |
| Net Income(2) | | 10.9 | | | - | | | - | | | - |
| Regulatory Assets and Liabilities | | 158.3 | | | 148.9 | | | 3.5 | | | 5.7 |
Settlements | | 74.2 | | | 86.7 | | | 4.1 | | | - |
Fair Value as of December 31, 2013 | $ | (635.2) | | $ | (630.6) | | $ | (7.3) | | $ | 2.7 |
(1)
NSTAR Electric amounts were includedthe derivative liability. Any increases in NU beginning April 10, 2012.
(2)
The Net Income impact for the years ended December 31, 2013 and 2012 related to the unregulated wholesale marketing sales contract that was offset by the gains/(losses) on the unregulated sourcing contracts classified as Level 2 inrisk premiums would increase the fair value hierarchy, resultingof the derivative liability. Changes in these fair values are recorded as a totalregulatory asset or liability and do not impact net gain of $1 million and net loss of $0.7 million, respectively.income.
6.5.
MARKETABLE SECURITIES
NUEversource maintains a supplemental benefit trusttrusts that hold marketable securities to fund certain non-qualified executive retirement benefit obligations and WMECO maintains a spent nuclear fuel trust to fund WMECO’s prior period spent nuclear fuel liability, each of which hold marketable securities. benefits.These trusts are not subject to regulatory oversight by state or federal agencies. In addition, CYAPC and YAEC maintain legally restricted trusts, each of which holds marketable securities, for settlingto fund the decommissioning and spent nuclear fuel removal obligations of their nuclear power plants. fuel storage facilities.
WMECO maintained a spent nuclear fuel trust to fund WMECO's pre-1983 spent nuclear fuel obligation. In late 2015, this trust was liquidated to satisfy the spent nuclear fuel obligation with the DOE. For further information, see Note 8, "Long-Term Debt."
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The Company electsTrading Securities: Eversource has elected to record mutual funds purchased bycertain equity securities as trading securities, with the NU supplemental benefit trust at fair value. As such, any changechanges in fair valuevalues recorded in Other Income, Net on the statements of income. As of December 31, 2015 and 2014, these mutual funds is reflected in Net Income. These mutual funds,securities were classified as Level 1 in the fair value hierarchy and totaled $57.2$14.2 million and $47$85.1 million, as ofrespectively. For the years ended December 31, 2015, 2014 and 2013, and 2012, respectively, and were included in Prepayments and Other Current Assets on the accompanying balance sheets. Netnet gains on these securities of $10.2$2 million, $1.9 million and $5.9$10.2 million, and net losses of $1.1 million for the years ended December 31, 2013, 2012 and 2011, respectively, were recorded in Other Income, Net on the statements of income. Dividend income is recorded in Other Income, Net on the statements of income when dividends are declared. All other marketableIn 2015, certain of the securities are accounted forclassified as available-for-sale.trading securities were sold and the proceeds were re-invested in equity securities designated as available-for-sale securities.
Available-for-Sale Securities: The following is a summary of NU's available-for-sale securities, held in the NU supplemental benefit trust, WMECO's spent nuclear fuel trust and CYAPC’s and YAEC's nuclear decommissioning trusts. These securitieswhich are recorded at fair value and are included in current and long-term Marketable Securities on the balance sheets.
|
| | As of December 31, 2013 |
| | | | | Pre-Tax | | Pre-Tax | | |
| | Amortized | | Unrealized | | Unrealized | | |
(Millions of Dollars) | Cost | | Gains(1) | | Losses(1) | | Fair Value |
NU | | | | | | | | |
| Debt Securities (2) | $ | 299.2 | | $ | 2.5 | | $ | (2.1) | | $ | 299.6 |
| Equity Securities (2) | | 163.6 | | 60.5 | | - | | 224.1 |
| | | | | | | | | |
WMECO | | | | | | | | |
| Debt Securities | | 57.9 | | - | | - | | 57.9 |
| | | | | | | | | | | As of December 31, |
| | As of December 31, 2012 | | 2015 | | 2014 |
| | | | | Pre-Tax | | Pre-Tax | | | | | | | Pre-Tax | | Pre-Tax | | | | | | | Pre-Tax | | Pre-Tax | | |
| | Amortized | | Unrealized | | Unrealized | | | | Amortized | | Unrealized | | Unrealized | | | | Amortized | | Unrealized | | Unrealized | | |
(Millions of Dollars) | (Millions of Dollars) | Cost | | Gains(1) | | Losses(1) | | Fair Value | (Millions of Dollars) | Cost | | Gains | | Losses | | Fair Value | | Cost | | Gains | | Losses | | Fair Value |
NU | | | | | | | | |
| Debt Securities (2) | $ | 266.6 | | $ | 13.3 | | $ | (0.1) | | $ | 279.8 |
Eversource | | | | | | | | | | | | | | | | | |
| Equity Securities (2) | | 145.5 | | 20.0 | | - | | 165.5 | Debt Securities (1) (2) | $ | 256.5 | | $ | 4.5 | | $ | (0.6) | | $ | 260.4 | | $ | 313.0 | | $ | 7.5 | | $ | (0.3) | | $ | 320.2 |
| | | | | | | | | | Equity Securities (1) | | 215.3 | | 59.2 | | (3.4) | | 271.1 | | | 160.6 | | 73.3 | | - | | 233.9 |
WMECO | WMECO | | | | | | | | | WMECO | | | | | | | | | | | | | | | | | |
| Debt Securities | | 57.7 | | 0.1 | | (0.1) | | 57.7 | Debt Securities (2) | | - | | - | | - | | - | | | 58.2 | | - | | (0.1) | | 58.1 |
(1)
Unrealized gains and losses on debt securities for the NU supplemental benefit trust and WMECO spent nuclear fuel trust are recorded in AOCI and Other Long-Term Assets, respectively, on the balance sheets.
(2)
NU's amountsAmounts include CYAPC's and YAEC's marketable securities held in nuclear decommissioning trusts of $424$436.9 million and $340.4$450.8 million as of December 31, 20132015 and 2012, respectively, the majority of which are legally restricted and can only be used for the decommissioning of the nuclear power plants owned by these companies. In the first quarter of 2013, CYAPC and YAEC received cash from the DOE related to the litigation of storage costs for spent nuclear fuel, which was invested in the nuclear decommissioning trusts.2014, respectively. Unrealized gains and losses for the nuclear decommissioning trusts are recorded in Marketable Securities with the corresponding offset into Other Long-Term Liabilities on the balance sheets, with no impact on the statementstatements of income. All of
(2)
Unrealized gains and losses on debt securities held by WMECO were recorded in Marketable Securities with the equity securities accounted for as available-for-sale securities are held in these trusts.corresponding offset to Other Long-Term Assets on the balance sheets.
Unrealized Losses and Other-than-Temporary Impairment: There have been no significant unrealized losses, other-than-temporary impairments or credit losses for the NU supplemental benefit trust, the WMECO spent nuclear fuel trust, and the trusts held by CYAPC and YAEC.Factorsin 2015 or 2014.Factors considered in determining whether a credit loss exists include the duration and severity of the impairment, adverse conditions specifically affecting the issuer, and the payment history, ratings and rating changes of the security. For asset-backed debt securities, underlying collateral and expected future cash flows are also evaluated.
Realized Gains and Losses: Realized gains and losses on available-for-sale securities are recorded in Other Income, Net for the NU supplementalEversource's benefit trust Other Long-Term Assets for the WMECO spent nuclear fuel trust, and are offset in Other Long-Term Liabilities for CYAPC and YAEC. NUEversource utilizes the specific identification basis method for the NU supplementalEversource benefit trust securities and the average cost basis method for the WMECO spent nuclear fuel trust and the CYAPC and YAEC nuclear decommissioning trusts to compute the realized gains and losses on the sale of available-for-sale securities.
Contractual Maturities: As of December 31, 2013,2015, the contractual maturities of available-for-sale debt securities arewere as follows:
|
| | | | | | | | | |
| | NU | | WMECO |
| | Amortized | | | | Amortized | | |
Eversource | Amortized | | Fair |
(Millions of Dollars) | (Millions of Dollars) | Cost | | Fair Value | | Cost | | Fair Value | Cost | | Value |
Less than one year (1) | Less than one year (1) | $ | 72.4 | | $ | 72.3 | | $ | 26.5 | | $ | 26.6 | $ | 33.3 | | $ | 33.2 |
One to five years | One to five years | | 62.1 | | 62.7 | | 25.6 | | 25.5 | | 50.2 | | 50.7 |
Six to ten years | Six to ten years | | 59.4 | | 59.3 | | 1.7 | | 1.7 | | 56.6 | | 57.2 |
Greater than ten years | Greater than ten years | | 105.3 | | | 105.3 | | | 4.1 | | | 4.1 | | 116.4 | | | 119.3 |
Total Debt Securities | Total Debt Securities | $ | 299.2 | | $ | 299.6 | | $ | 57.9 | | $ | 57.9 | $ | 256.5 | | $ | 260.4 |
(1)
Amounts in the Less than one year NU category include securities in the CYAPC and YAEC nuclear decommissioning trusts, which are restricted and are classified in long-term Marketable Securities on the balance sheets.
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Fair Value Measurements: The following table presents the marketable securities recorded at fair value on a recurring basis by the level in which they are classified within the fair value hierarchy:
|
| | | NU | | WMECO |
| | | As of December 31, | | As of December 31, |
Eversource | As of December 31, |
(Millions of Dollars) | (Millions of Dollars) | 2013 | | 2012 | | 2013 | | 2012 | (Millions of Dollars) | 2015 | | 2014 |
Level 1: | Level 1: | | | | | | | | | Level 1: | | | | |
| Mutual Funds and Equities | $ | 281.3 | | $ | 212.5 | | $ | - | | $ | - | Mutual Funds and Equities | $ | 285.3 | | $ | 319.0 |
| Money Market Funds | | 32.9 | | | 40.2 | | | 10.9 | | | 5.2 | Money Market Funds | | 26.9 | | | 24.9 |
Total Level 1 | Total Level 1 | $ | 314.2 | | $ | 252.7 | | $ | 10.9 | | $ | 5.2 | Total Level 1 | $ | 312.2 | | $ | 343.9 |
Level 2: | Level 2: | | | | | | | | | Level 2: | | | | |
| U.S. Government Issued Debt Securities | | | | | | | | | U.S. Government Issued Debt Securities
(Agency and Treasury) | $ | 46.6 | | $ | 51.3 |
| | (Agency and Treasury) | $ | 61.4 | | $ | 69.9 | | $ | 6.8 | | $ | 18.7 | Corporate Debt Securities | | 43.9 | | 49.1 |
| Corporate Debt Securities | | 53.6 | | 33.0 | | 15.1 | | 7.0 | Asset-Backed Debt Securities | | 20.0 | | 54.1 |
| Asset-Backed Debt Securities | | 30.4 | | 28.5 | | 9.0 | | 10.9 | Municipal Bonds | | 111.4 | | 116.3 |
| Municipal Bonds | | 105.5 | | 93.8 | | 11.2 | | 11.6 | Other Fixed Income Securities | | 11.6 | | | 24.5 |
| Other Fixed Income Securities | | 15.8 | | | 14.4 | | | 4.9 | | | 4.3 |
Total Level 2 | Total Level 2 | $ | 266.7 | | $ | 239.6 | | $ | 47.0 | | $ | 52.5 | Total Level 2 | $ | 233.5 | | $ | 295.3 |
Total Marketable Securities | Total Marketable Securities | $ | 580.9 | | $ | 492.3 | | $ | 57.9 | | $ | 57.7 | Total Marketable Securities | $ | 545.7 | | $ | 639.2 |
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As of December 31, 2014, the WMECO spent nuclear fuel trust included investments in money market funds of $4.3 million classified as Level 1 in the fair value hierarchy, and $14.7 million of corporate debt securities, $14.5 million of asset-backed debt securities, $13 million of municipal bonds and $11.6 million of other fixed income securities classified as Level 2 in the fair value hierarchy. The trust was liquidated in late 2015.
U.S. government issued debt securities are valued using market approaches that incorporate transactions for the same or similar bonds and adjustments for yields and maturity dates. Corporate debt securities are valued using a market approach, utilizing recent trades of the same or similar instrument and also incorporating yield curves, credit spreads and specific bond terms and conditions. Asset-backed debt securities include collateralized mortgage obligations, commercial mortgage backed securities, and securities collateralized by auto loans, credit card loans or receivables. Asset-backed debt securities are valued using recent trades of similar instruments, prepayment assumptions, yield curves, issuance and maturity dates, and tranche information. Municipal bonds are valued using a market approach that incorporates reported trades and benchmark yields. Other fixed income securities are valued using pricing models, quoted prices of securities with similar characteristics, and discounted cash flows.
7.6.
ASSET RETIREMENT OBLIGATIONS
In accordance with accounting guidance for conditional AROs, NU,Eversource, including CL&P, NSTAR Electric, PSNH and WMECO, recognizes a liability for the fair value of an ARO on the obligation date if the liability's fair value can be reasonably estimated and is conditional on a future event. Settlement dates and future costs are reasonably estimated when sufficient information becomes available. Management has identified various categories of AROs, primarily certain assets containing asbestos and hazardous contamination, and has performed fair value calculations reflecting expected probabilities for settlement scenarios.
The fair value of an ARO is recorded as a liability in Other Long-Term Liabilities with a corresponding amount included in Property, Plant and Equipment, Net on the balance sheets. As the Regulated companies are rate-regulated on a cost-of-service basis, these companies apply regulatory accounting guidance and the costs associated with the Regulated companies' AROs are included in Regulatory Assets. The ARO assets are depreciated, and the ARO liabilities are accreted over the estimated life of the obligation with corresponding credits recorded as accumulated depreciation and ARO liabilities, respectively. BothAs the Regulated companies are rate-regulated on a cost-of-service basis, these companies apply regulatory accounting guidance and both the depreciation and accretion werecosts associated with the Regulated companies' AROs are recorded as increases to Regulatory Assets on the balance sheets. For further information, see Note 3, "Regulatory Accounting," to the financial statements.
A reconciliation of the beginning and ending carrying amounts of ARO liabilities are as follows:
|
NU | | | | | | As of December 31, |
Eversource | | | As of December 31, |
(Millions of Dollars) | (Millions of Dollars) | 2013 | | 2012 | (Millions of Dollars) | 2015 | | 2014 |
Balance as of Beginning of Year | Balance as of Beginning of Year | $ | 412.2 | | $ | 56.2 | Balance as of Beginning of Year | $ | 426.3 | | $ | 424.9 |
Liability Assumed Upon Consolidation of CYAPC and YAEC | | - | | 284.2 |
Liability Assumed Upon Merger With NSTAR | | - | | 35.9 |
Liabilities Incurred During the Year | Liabilities Incurred During the Year | | 0.1 | | 1.5 | Liabilities Incurred During the Year | | 6.6 | | 1.3 |
Liabilities Settled During the Year | Liabilities Settled During the Year | | (13.8) | | (7.2) | Liabilities Settled During the Year | | (18.2) | | (19.5) |
Accretion | Accretion | | 23.8 | | 20.2 | Accretion | | 26.5 | | 25.1 |
Revisions in Estimated Cash Flows | Revisions in Estimated Cash Flows | | 2.6 | | | 21.4 | Revisions in Estimated Cash Flows | | (11.1) | | | (5.5) |
Balance as of End of Year | Balance as of End of Year | $ | 424.9 | | $ | 412.2 | Balance as of End of Year | $ | 430.1 | | $ | 426.3 |
|
| | | | | As of December 31, | | | | As of December 31, |
| | | | | 2013 | | 2012 | | | | 2015 | | 2014 |
| | | | | NSTAR | | | | | | | | NSTAR | | | | | | | | NSTAR | | | | | | | | NSTAR | | | | |
(Millions of Dollars) | (Millions of Dollars) | | CL&P | | Electric | | PSNH | | WMECO | | CL&P | | Electric | | PSNH | | WMECO | (Millions of Dollars) | CL&P | | Electric | | PSNH | | WMECO | | CL&P | | Electric | | PSNH | | WMECO |
Balance as of Beginning of Year | Balance as of Beginning of Year | | $ | 33.6 | | $ | 31.4 | | $ | 18.4 | | $ | 4.3 | | $ | 32.2 | | $ | 27.5 | | $ | 17.0 | | $ | 4.0 | Balance as of Beginning of Year | $ | 35.3 | | $ | 34.3 | | $ | 20.6 | | $ | 5.9 | | $ | 35.0 | | $ | 32.8 | | $ | 19.5 | | $ | 4.5 |
Liabilities Incurred During the Year | Liabilities Incurred During the Year | | - | | - | | - | | - | | - | | - | | 0.3 | | - | Liabilities Incurred During the Year | | - | | 6.2 | | 0.4 | | - | | - | | - | | - | | 1.1 |
Liabilities Settled During the Year | Liabilities Settled During the Year | | (0.7) | | (0.1) | | - | | - | | (0.9) | | (1.0) | | - | | - | Liabilities Settled During the Year | | - | | (1.5) | | - | | (0.1) | | (1.1) | | - | | - | | - |
Accretion | Accretion | | 2.2 | | 1.5 | | 1.2 | | 0.3 | | 2.0 | | 1.5 | | 1.1 | | 0.3 | Accretion | | 2.2 | | 1.8 | | 1.3 | | 0.4 | | 1.9 | | 1.5 | | 1.1 | | 0.3 |
Revisions in Estimated Cash Flows | Revisions in Estimated Cash Flows | | | (0.1) | | | - | | | (0.1) | | | (0.1) | | | 0.3 | | | 3.4 | | | - | | | - | Revisions in Estimated Cash Flows | | (3.7) | | | (5.5) | | | (0.7) | | | (0.5) | | | (0.5) | | | - | | | - | | | - |
Balance as of End of Year | Balance as of End of Year | | $ | 35.0 | | $ | 32.8 | | $ | 19.5 | | $ | 4.5 | | $ | 33.6 | | $ | 31.4 | | $ | 18.4 | | $ | 4.3 | Balance as of End of Year | $ | 33.8 | | $ | 35.3 | | $ | 21.6 | | $ | 5.7 | | $ | 35.3 | | $ | 34.3 | | $ | 20.6 | | $ | 5.9 |
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The Liability Assumed Upon Consolidation ofEversource's amounts include CYAPC and YAEC represents the CYAPCYAEC's AROs of $319.1 million and YAEC ARO fair value$317.3 million as of the merger date.December 31, 2015 and 2014, respectively. The fair value of the ARO for CYAPC and YAEC includes uncertainties of the fuel off-load dates related to the DOE’s timing of performance regarding its obligation to dispose of the spent nuclear fuel and high level waste. The incremental asset recorded as an offset to the ARO liability was fully depreciated since the plants have no remaining useful life. Any changes in the assumptions used to calculate the fair value of the ARO liability are recorded as anwith a corresponding offset to the related regulatory asset. The assets held in the CYAPC and YAEC nuclear decommissioning trusttrusts are restricted for settling the asset retirement obligationARO and all other decommissioning obligations. For further information on the assets held in trust to support this obligation,the nuclear decommissioning trusts, see Note 6,5, "Marketable Securities," to the financial statements.
8.
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7.
SHORT-TERM DEBT
Short-Term Borrowing Limits: The amount of short-term borrowings that may be incurred by CL&P, NSTAR Electric and WMECO is subject to periodic approval by the FERC. As a result of the NHPUC having jurisdiction over PSNH's short-term debt, PSNH is not currently required to obtain FERC approval for its short-term borrowings. On July 31, 2013,June 16, 2015, the FERC granted authorization to allowthat allows CL&P and WMECO to incur total short-term borrowings up to a maximum of $600 million and $300 million, respectively, effective January 1, 20142016 through December 31, 2015.2017. On May 16, 2012,June 11, 2014, the FERC granted authorization to allow NSTAR Electric to issue total short-term debt securities in an aggregate principal amount not to exceed $655 million outstanding at any one time, effective October 23, 201224, 2014 through October 23, 2014. As a result of the NHPUC having jurisdiction over PSNH's short-term debt, PSNH is not currently required to obtain FERC approval for its short-term borrowings.2016.
PSNH is authorized by regulation of the NHPUC to incur short-term borrowings up to 10 percent of net fixed plant plus an additional $60 million until further ordered by the NHPUC. As of December 31, 2013,2015, PSNH's short-term debt authorization under the 10 percent of net fixed plant test plus $60 million totaled approximately $293$325 million.
CL&P's certificate of incorporation contains preferred stock provisions restricting the amount of unsecured debt that CL&P may incur, including limiting unsecured indebtedness with a maturity of less than 10 years to 10 percent of total capitalization. In November 2003, CL&P obtained from its preferred stockholders a waiver of such 10 percent limit for a ten-year period expiring in March 2014, provided that all unsecured indebtedness does not exceed 20 percent of total capitalization. As of December 31, 2013,2015, CL&P had $776.9$327.3 million of unsecured debt capacity available under this authorization.
Yankee Gas and NSTAR Gas are not required to obtain approval from any state or federal authority to incur short-term debt.
Credit Agreements and Commercial Paper Programs: NUEversource parent, CL&P, PSNH, WMECO, NSTAR Gas and Yankee Gas are parties to a five-year $1.45 billion revolving credit facility. On October 26, 2015, this revolving credit facility was amended and restated and the termination date was extended to September 4, 2020. Under the revolving credit facility, CL&P has a borrowing sublimit of $600 million, and PSNH and WMECO each have borrowing sublimits of $300 million. The revolving credit facility is to be used primarilyserves to backstop theEversource parent's $1.45 billion commercial paper program at NU, which commenced July 25, 2012.program. The commercial paper program allows NUEversource parent to issue commercial paper as a form of short-term debt. On September 6, 2013,As of December 31, 2015 and 2014, Eversource parent had approximately $1.1 billion in short-term borrowings outstanding on each date under the $1.15 billion revolving credit facility dated July 25, 2012 was amended to increase the aggregate principal amount available thereunder by $300 million to $1.45 billion, to extend the expiration date from July 25, 2017 to September 6, 2018, and to increase CL&P's borrowing sublimit from $300 million to $600 million. PSNH and WMECO each have borrowing sublimits of $300 million. On September 6, 2013, NU parent’s $1.15 billionEversource parent commercial paper program, leaving $351.5 million and $348.9 million of available borrowing capacity as of December 31, 2015 and 2014, respectively. The weighted-average interest rate on these borrowings as of December 31, 2015 and 2014 was increased by $3000.72 percent and 0.43 percent, respectively. As of December 31, 2015, there were intercompany loans from Eversource parent of $277.4 million to $1.45 billion. CL&P, $231.3 million to PSNH and $143.4 million to WMECO. As of December 31, 2014, there were intercompany loans from Eversource parent of $133.4 million to CL&P, $90.5 million to PSNH and $21.4 million to WMECO.
NSTAR Electric has a five-year $450 million revolving credit facility. ThisOn October 26, 2015, this revolving credit facility was amended and restated and the termination date was extended to September 4, 2020. The facility serves to backstop NSTAR Electric’s existingElectric's $450 million commercial paper program. On September 6, 2013, NSTAR Electric amended its revolving credit facility dated July 25, 2012 to extend the expiration date from July 25, 2017 to September 6, 2018.
On September 6, 2013, the CL&P five-year $300 million revolving credit facility was terminated. As of December 31, 2012, CL&P had $89 million in borrowings outstanding under this credit agreement with a weighted average interest rate of 3.325 percent.
As of December 31, 20132015 and 2012, NU had approximately $1.01 billion and $1.15 billion, respectively, in short-term borrowings outstanding under the commercial paper program, leaving $435.5 million of available borrowing capacity as of December 31, 2013. The weighted-average interest rate on these borrowings as of December 31, 2013 and 2012 was 0.24 percent and 0.46 percent, respectively, which is generally based on money market rates. As of December 31, 2013 and 2012,2014, NSTAR Electric had $103.5$62.5 million and $276$302 million, respectively, in short-term borrowings outstanding under its commercial paper program, leaving $346.5$387.5 million and $174$148 million of available borrowing capacity as of December 31, 20132015 and 2012,2014, respectively. The weighted-average interest rate on these borrowings as of December 31, 20132015 and 20122014 was 0.130.40 percent and 0.310.27 percent, respectively, which is generally based on money market rates.respectively.
AmountsExcept as described below, amounts outstanding under the commercial paper programs for NU and NSTAR Electric are generally included in Notes Payable for Eversource and NSTAR Electric and are classified in current liabilities on the balance sheets as all borrowings are outstanding for no more than 364 days at one time. On January 2, 2014, Yankee Gas issued $100 million of Series L First Mortgage Bonds. A portion of the proceeds was used to pay short-term borrowings outstanding under the NU commercial paper program. As a result and in accordance with applicable accounting guidance, $25 million of the NU commercial paper program borrowings have been classified as Long-Term Debt as of December 31, 2013.
As of December 31, 2013 and 2012, there were intercompany loans from NU of $287.3 million and $405.1 million to CL&P, $86.5 million and $63.3 million to PSNH, and zero and $31.9 million to WMECO, respectively. Intercompany loans from NUEversource parent to CL&P, PSNH and WMECO are included in Notes Payable to Affiliated CompaniesEversource Parent and generallyare classified in current liabilities on thetheir respective balance sheets. Intercompany loans from Eversource to CL&P, PSNH and WMECO are eliminated in consolidation on Eversource's balance sheets.
On January 15, 2013, CL&P2015, Eversource parent issued $400$150 million of 1.60 percent Series A FirstG Senior Notes due to mature in 2018 and Refunding Mortgage Bonds.$300 million of 3.15 percent Series H Senior Notes, due to mature in 2025. The proceeds, net of issuance costs, were used to payrepay short-term borrowings outstanding under the CL&P credit agreement of $89 million
127
and the NUEversource parent commercial paper programprogram. As the debt proceeds, net of $305.8 million. As a result and in accordance with applicable accounting guidance, these amounts wereissuance costs, refinanced short-term debt, the short-term debt was classified as Long-Term Debt on the balance sheet as of December 31, 2012.
Intercompany loans from NU to CL&P, PSNH and WMECO are eliminated in consolidation in NU's balance sheets.2014. See Note 8, "Long-Term Debt," for further information on these debt issuances.
Under the credit facilities NUdescribed above, Eversource and its subsidiaries must comply with certain financial and non-financial covenants, including a consolidated debt to total capitalization ratio. As of December 31, 20132015 and 2012, NU2014, Eversource and its subsidiaries were in compliance with these covenants. If NUEversource or its subsidiaries were not in compliance with these covenants, an event of default would occur requiring all outstanding borrowings by such borrower to be repaid and additional borrowings by such borrower would not be permitted under its respective credit facility.
Working Capital: 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 transmission construction expenditures utilizes a significant amount of cash for projects that have a long-term return on investment and recovery period. In addition, NU’s Regulated companies recover its 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 $1.2 billion, $398 million and $339 million at NU, CL&P and NSTAR Electric, respectively, as of December 31, 2013.
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As of December 31, 2013, $501.7 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 $150 million for CL&P, $301.7 million for NSTAR Electric and $50 million for PSNH. In addition, $31.7 million relates to the amortization of the purchase accounting fair value adjustment that will be amortized in the next twelve months. NU, with its strong credit ratings, has several options available in the financial markets to repay or refinance these maturities with the issuance of new long-term debt. NU, CL&P, NSTAR Electric, PSNH and WMECO will reduce their short-term borrowings with cash received from operating cash flows or with the issuance of new long-term debt, determined considering capital requirements and maintenance of NU's credit rating and profile. Management expects the future operating cash flows of NU, CL&P, NSTAR Electric, PSNH and WMECO, along with the access to financial markets, will be sufficient to meet any future operating requirements and capital investment forecasted opportunities.
9.8.
LONG-TERM DEBT
Details of long-term debt outstanding are as follows:
| | | | | | | |
| CL&P | As of December 31, |
| (Millions of Dollars) | 2013 | | 2012 |
| First Mortgage Bonds: | | | | | |
| | 7.875% 1994 Series D due 2024 | $ | 139.8 | | $ | 139.8 |
| | 4.800% 2004 Series A due 2014 | | 150.0 | | | 150.0 |
| | 5.750% 2004 Series B due 2034 | | 130.0 | | | 130.0 |
| | 5.000% 2005 Series A due 2015 | | 100.0 | | | 100.0 |
| | 5.625% 2005 Series B due 2035 | | 100.0 | | | 100.0 |
| | 6.350% 2006 Series A due 2036 | | 250.0 | | | 250.0 |
| | 5.375% 2007 Series A due 2017 | | 150.0 | | | 150.0 |
| | 5.750% 2007 Series B due 2037 | | 150.0 | | | 150.0 |
| | 5.750% 2007 Series C due 2017 | | 100.0 | | | 100.0 |
| | 6.375% 2007 Series D due 2037 | | 100.0 | | | 100.0 |
| | 5.650% 2008 Series A due 2018 | | 300.0 | | | 300.0 |
| | 5.500% 2009 Series A due 2019 | | 250.0 | | | 250.0 |
| | 2.500% 2013 Series A due 2023(1) | | 400.0 | | | - |
| Total First Mortgage Bonds | | 2,319.8 | | | 1,919.8 |
| Pollution Control Notes: | | | | | |
| | 4.375% Fixed Rate Tax Exempt due 2028 | | 120.5 | | | 120.5 |
| | 1.25% Fixed Rate Tax Exempt due 2028(2) | | - | | | 125.0 |
| | 1.55% Fixed Rate Tax Exempt due 2031(2) | | 62.0 | | | 62.0 |
| Total Pollution Control Notes | | 182.5 | | | 307.5 |
| Total First Mortgage Bonds and Pollution Control Notes | | 2,502.3 | | | 2,227.3 |
| Fees and Interest due for Spent Nuclear Fuel Disposal Costs | | 244.4 | | | 244.3 |
| CL&P Commercial Paper and Revolver Borrowings(1) | | - | | | 394.8 |
| Less Amounts due Within One Year | | (150.0) | | | (125.0) |
| Unamortized Premiums and Discounts, Net | | (5.5) | | | (3.6) |
| CL&P Long-Term Debt | $ | 2,591.2 | | $ | 2,737.8 |
| | | | | | |
CL&P | As of December 31, |
(Millions of Dollars) | 2015 | | 2014 |
First Mortgage Bonds: | | | | | |
| 7.875% 1994 Series D due 2024 | $ | 139.8 | | $ | 139.8 |
| 5.750% 2004 Series B due 2034 | | 130.0 | | | 130.0 |
| 5.000% 2005 Series A due 2015 | | - | | | 100.0 |
| 5.625% 2005 Series B due 2035 | | 100.0 | | | 100.0 |
| 6.350% 2006 Series A due 2036 | | 250.0 | | | 250.0 |
| 5.375% 2007 Series A due 2017 | | 150.0 | | | 150.0 |
| 5.750% 2007 Series B due 2037 | | 150.0 | | | 150.0 |
| 5.750% 2007 Series C due 2017 | | 100.0 | | | 100.0 |
| 6.375% 2007 Series D due 2037 | | 100.0 | | | 100.0 |
| 5.650% 2008 Series A due 2018 | | 300.0 | | | 300.0 |
| 5.500% 2009 Series A due 2019 | | 250.0 | | | 250.0 |
| 2.500% 2013 Series A due 2023 | | 400.0 | | | 400.0 |
| 4.300% 2014 Series A due 2044 | | 250.0 | | | 250.0 |
| 4.150% 2015 Series A due 2045 | | 350.0 | | | - |
Total First Mortgage Bonds | | 2,669.8 | | | 2,419.8 |
Pollution Control Revenue Bonds: | | | | | |
| 4.375% Fixed Rate Tax Exempt due 2028 | | 120.5 | | | 120.5 |
| 1.550% Fixed Rate Tax Exempt due 2031 | | - | | | 62.0 |
Total Pollution Control Revenue Bonds | | 120.5 | | | 182.5 |
Pre-1983 Spent Nuclear Fuel Obligation | | - | | | 244.5 |
Less Amounts due Within One Year | | - | | | (162.0) |
Unamortized Premiums and Discounts, Net | | (10.7) | | | (4.8) |
Unamortized Debt Issuance Costs(1) | | (15.9) | | | (15.8) |
CL&P Long-Term Debt(1) | $ | 2,763.7 | | $ | 2,664.2 |
| | | | | | |
NSTAR Electric | As of December 31, |
(Millions of Dollars) | 2015 | | 2014 |
Debentures: | | | | | |
| 5.750% due 2036 | $ | 200.0 | | $ | 200.0 |
| 5.625% due 2017 | | 400.0 | | | 400.0 |
| 5.500% due 2040 | | 300.0 | | | 300.0 |
| 2.375% due 2022 | | 400.0 | | | 400.0 |
| Variable Rate due 2016 (0.6036% and 0.4721% as of December 31, 2015 and 2014) | | 200.0 | | | 200.0 |
| 4.400% due 2044 | | 300.0 | | | 300.0 |
| 3.250% due 2025 | | 250.0 | | | - |
Total Debentures | | 2,050.0 | | | 1,800.0 |
Bonds: | | | | | |
| 7.375% Tax Exempt Sewage Facility Revenue Bonds, due 2015 | | - | | | 4.7 |
Less Amounts due Within One Year | | (200.0) | | | (4.7) |
Unamortized Premiums and Discounts, Net | | (8.5) | | | (7.3) |
Unamortized Debt Issuance Costs(1) | | (11.7) | | | (11.2) |
NSTAR Electric Long-Term Debt(1) | $ | 1,829.8 | | $ | 1,781.5 |
| | | | | | |
PSNH | As of December 31, |
(Millions of Dollars) | 2015 | | 2014 |
First Mortgage Bonds: | | | | | |
| 5.60% Series M due 2035 | $ | 50.0 | | $ | 50.0 |
| 6.15% Series N due 2017 | | 70.0 | | | 70.0 |
| 6.00% Series O due 2018 | | 110.0 | | | 110.0 |
| 4.50% Series P due 2019 | | 150.0 | | | 150.0 |
| 4.05% Series Q due 2021 | | 122.0 | | | 122.0 |
| 3.20% Series R due 2021 | | 160.0 | | | 160.0 |
| 3.50% Series S due 2023 | | 325.0 | | | 325.0 |
Total First Mortgage Bonds | | 987.0 | | | 987.0 |
Pollution Control Revenue Bonds: | | | | | |
| Adjustable Rate Tax Exempt Series A due 2021 (0.193% and 0.175% as of December 31, 2015 and 2014) | | 89.3 | | | 89.3 |
Unamortized Premiums and Discounts, Net | | 0.1 | | | - |
Unamortized Debt Issuance Costs(1) | | (5.4) | | | (6.3) |
PSNH Long-Term Debt(1) | $ | 1,071.0 | | $ | 1,070.0 |
128108
| | | | | | | |
| NSTAR Electric | As of December 31, |
| (Millions of Dollars) | 2013 | | 2012 |
| Debentures: | | | | | |
| | 4.875% due 2014 | $ | 300.0 | | $ | 300.0 |
| | 5.75% due 2036 | | 200.0 | | | 200.0 |
| | 5.625% due 2017 | | 400.0 | | | 400.0 |
| | 5.50% due 2040 | | 300.0 | | | 300.0 |
| | 2.375% due 2022 | | 400.0 | | | 400.0 |
| | Variable Rate due 2016(3) | | 200.0 | | | - |
| Total Debentures | | 1,800.0 | | | 1,600.0 |
| Bonds: | | | | | |
| | 7.375% Tax Exempt Sewage Facility Revenue Bonds, due 2015 | | 6.4 | | | 8.0 |
| Less Amounts due Within One Year | | (301.7) | | | (1.7) |
| Unamortized Premiums and Discounts, Net | | (5.3) | | | (5.4) |
| NSTAR Electric Long-Term Debt | $ | 1,499.4 | | $ | 1,600.9 |
| | | | | | | |
| | | | | | | |
| PSNH | As of December 31, |
| (Millions of Dollars) | 2013 | | 2012 |
| First Mortgage Bonds: | | | | | |
| | 5.25% 2004 Series L due 2014 | $ | 50.0 | | $ | 50.0 |
| | 5.60% 2005 Series M due 2035 | | 50.0 | | | 50.0 |
| | 6.15% 2007 Series N due 2017 | | 70.0 | | | 70.0 |
| | 6.00% 2008 Series O due 2018 | | 110.0 | | | 110.0 |
| | 4.50% 2009 Series P due 2019 | | 150.0 | | | 150.0 |
| | 4.05% 2011 Series Q due 2021 | | 122.0 | | | 122.0 |
| | 3.20% 2011 Series R due 2021 | | 160.0 | | | 160.0 |
| | 3.50% 2013 Series S due 2023(4) | | 250.0 | | | - |
| Total First Mortgage Bonds | | 962.0 | | | 712.0 |
| Pollution Control Revenue Bonds: | | | | | |
| | 4.75% - 5.45% Tax Exempt Series B and C due 2021(4) | | - | | | 198.2 |
| | Adjustable Rate Series A due 2021 | | 89.3 | | | 89.3 |
| Total Pollution Control Revenue Bonds | | 89.3 | | | 287.5 |
| Less Amounts due Within One Year | | (50.0) | | | - |
| Unamortized Premiums and Discounts, Net | | (2.3) | | | (1.6) |
| PSNH Long-Term Debt | $ | 999.0 | | $ | 997.9 |
| | | | | | | |
| WMECO | As of December 31, |
| (Millions of Dollars) | 2013 | | 2012 |
| Other Notes: | | | | | |
| | 5.00% Senior Notes Series A, due 2013 (5) | $ | - | | $ | 55.0 |
| | 5.90% Senior Notes Series B, due 2034 | | 50.0 | | | 50.0 |
| | 5.24% Senior Notes Series C, due 2015 | | 50.0 | | | 50.0 |
| | 6.70% Senior Notes Series D, due 2037 | | 40.0 | | | 40.0 |
| | 5.10% Senior Notes Series E, due 2020 | | 95.0 | | | 95.0 |
| | 3.50% Senior Notes Series F, due 2021 | | 250.0 | | | 250.0 |
| | 3.88% Senior Notes Series G, due 2023 (5) | | 80.0 | | | - |
| Total Other Notes | | 565.0 | | | 540.0 |
| Fees and Interest due for Spent Nuclear Fuel Disposal Costs | | 57.3 | | | 57.3 |
| Less Amounts due Within One Year (5) | | - | | | (55.0) |
| Unamortized Premiums and Discounts, Net | | 7.1 | | | 8.0 |
| WMECO Long-Term Debt | $ | 629.4 | | $ | 550.3 |
| | | | | | | |
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| | | | | | | |
| OTHER | As of December 31, |
| (Millions of Dollars) | 2013 | | | 2012 |
| Yankee Gas - First Mortgage Bonds: | | | | | |
| | 8.48% Series B due 2022 | $ | 20.0 | | $ | 20.0 |
| | 4.80% Series G due 2014 (6) | | 75.0 | | | 75.0 |
| | 5.26% Series H due 2019 | | 50.0 | | | 50.0 |
| | 5.35% Series I due 2035 | | 50.0 | | | 50.0 |
| | 6.90% Series J due 2018 | | 100.0 | | | 100.0 |
| | 4.87% Series K due 2020 | | 50.0 | | | 50.0 |
| Total First Mortgage Bonds | | 345.0 | | | 345.0 |
| Unamortized Premium | | 0.7 | | | 0.8 |
| Yankee Gas Long-Term Debt | | 345.7 | | | 345.8 |
| | | | | | | |
| NSTAR Gas - First Mortgage Bonds: | | | | | |
| | 9.95% Series J due 2020 | | 25.0 | | | 25.0 |
| | 7.11% Series K due 2033 | | 35.0 | | | 35.0 |
| | 7.04% Series M due 2017 | | 25.0 | | | 25.0 |
| | 4.46% Series N due 2020 | | 125.0 | | | 125.0 |
| NSTAR Gas Long-Term Debt | | 210.0 | | | 210.0 |
| | | | | | | |
| Other - Notes and Debentures: | | | | | |
| | 5.65% Senior Notes Series C due 2013 (NU Parent) (7) | | - | | | 250.0 |
| | Variable Rate Senior Notes Series D due 2013 (NU Parent) (7) | | - | | | 300.0 |
| | 1.45% Senior Notes Series E due 2018 (NU Parent)(7) | | 300.0 | | | - |
| | 2.80% Senior Notes Series F due 2023 (NU Parent)(7) | | 450.0 | | | - |
| | 4.50% Debentures due 2019 (NU Parent) | | 350.0 | | | 350.0 |
| | NU Commercial Paper Borrowings (6) | | 25.0 | | | - |
| | Spent Nuclear Fuel Obligation (CYAPC) | | 179.4 | | | 179.3 |
| Total Other Long-Term Debt | | 1,304.4 | | | 1,079.3 |
| Fair Value Adjustment(8) | | 230.7 | | | 259.9 |
| Less Amounts due Within One Year | | - | | | (550.0) |
| Less Fair Value Adjustment - Current Portion(8) | | (31.7) | | | (31.7) |
| Unamortized Premiums and Discounts, Net | | (1.3) | | | - |
| Total NU Long-Term Debt | $ | 7,776.8 | | $ | 7,200.2 |
| | | | | | |
WMECO | As of December 31, |
(Millions of Dollars) | 2015 | | 2014 |
Notes: | | | | | |
| 5.90% Senior Notes Series B, due 2034 | $ | 50.0 | | $ | 50.0 |
| 5.24% Senior Notes Series C, due 2015 | | - | | | 50.0 |
| 6.70% Senior Notes Series D, due 2037 | | 40.0 | | | 40.0 |
| 5.10% Senior Notes Series E, due 2020 | | 95.0 | | | 95.0 |
| 3.50% Senior Notes Series F, due 2021 | | 250.0 | | | 250.0 |
| 3.88% Senior Notes Series G, due 2023 | | 80.0 | | | 80.0 |
Total Notes | | 515.0 | | | 565.0 |
Pre-1983 Spent Nuclear Fuel Obligation | | - | | | 57.4 |
Less Amounts due Within One Year | | - | | | (50.0) |
Unamortized Premiums and Discounts, Net | | 5.2 | | | 6.1 |
Unamortized Debt Issuance Costs (1) | | (2.9) | | | (3.3) |
WMECO Long-Term Debt (1) | $ | 517.3 | | $ | 575.2 |
| | | | | | |
OTHER | As of December 31, |
(Millions of Dollars) | 2015 | | | 2014 |
Yankee Gas - First Mortgage Bonds: | | | | | |
| 8.48% Series B due 2022 | $ | 20.0 | | $ | 20.0 |
| 5.26% Series H due 2019 | | 50.0 | | | 50.0 |
| 5.35% Series I due 2035 | | 50.0 | | | 50.0 |
| 6.90% Series J due 2018 | | 100.0 | | | 100.0 |
| 4.87% Series K due 2020 | | 50.0 | | | 50.0 |
| 4.82% Series L due 2044 | | 100.0 | | | 100.0 |
| 3.35% Series M due 2025 | | 75.0 | | | - |
Total First Mortgage Bonds | | 445.0 | | | 370.0 |
Unamortized Premium | | 0.4 | | | 0.6 |
Unamortized Debt Issuance Costs (1) | | (1.7) | | | (1.5) |
Yankee Gas Long-Term Debt (1) | | 443.7 | | | 369.1 |
| | | | | | |
NSTAR Gas - First Mortgage Bonds: | | | | | |
| 9.95% Series J due 2020 | | 25.0 | | | 25.0 |
| 7.11% Series K due 2033 | | 35.0 | | | 35.0 |
| 7.04% Series M due 2017 | | 25.0 | | | 25.0 |
| 4.46% Series N due 2020 | | 125.0 | | | 125.0 |
| 4.35% Series O due 2045 | | 100.0 | | | - |
Total First Mortgage Bonds | | 310.0 | | | 210.0 |
Unamortized Debt Issuance Costs (1) | | (0.8) | | | (0.6) |
NSTAR Gas Long-Term Debt (1) | | 309.2 | | | 209.4 |
| | | | | | |
Eversource Parent - Notes and Debentures: | | | | | |
| 4.50% Debentures due 2019 | | 350.0 | | | 350.0 |
| 1.45% Senior Notes Series E due 2018 | | 300.0 | | | 300.0 |
| 2.80% Senior Notes Series F due 2023 | | 450.0 | | | 450.0 |
| 1.60% Senior Notes Series G due 2018 | | 150.0 | | | - |
| 3.15% Senior Notes Series H due 2025 | | 300.0 | | | - |
| Eversource Parent Commercial Paper Borrowings | | - | | | 446.3 |
Total Eversource Parent Notes and Debentures | | 1,550.0 | | | 1,546.3 |
Pre-1983 Spent Nuclear Fuel Obligation (CYAPC) | | 179.5 | | | 179.4 |
Fair Value Adjustment(2) | | 173.5 | | | 202.3 |
Less Fair Value Adjustment - Current Portion(2) | | (28.9) | | | (28.9) |
Unamortized Premiums and Discounts, Net | | (1.3) | | | (1.2) |
Unamortized Debt Issuance Costs (1) | | (1.9) | | | 1.1 |
Total Other Long-Term Debt (1) | $ | 2,623.8 | | $ | 2,477.5 |
| | | | | | |
Total Eversource Long-Term Debt (1) | $ | 8,805.6 | | $ | 8,568.4 |
(1)
On January 15, 2013, CL&P issued $400 millionEffective December 31, 2015, the carrying amount of 2.50 percent Series A First and Refunding Mortgage Bonds with a maturity date of January 15, 2023. The proceeds, net ofLong-Term Debt includes unamortized debt issuance costs were used to pay short-term borrowings outstanding underpresented as a direct reduction from the CL&P credit agreementcarrying amount of $89 million and the NU commercial paper program of $305.8 million. As a result anddebt liability, in accordance with applicablenew accounting guidance, these amounts were classified asguidance. The December 31, 2014 carrying amount of Long-Term Debt onwas retrospectively adjusted to conform to the balance sheet ascurrent year presentation. See Note 1C, "Summary of December 31, 2012.Significant Accounting Policies – Accounting Standards," for further information.
(2)
In April 2012, CL&P remarketed $62 million of tax-exempt PCRBs for a three-year period. The PCRBs, which mature on May 1, 2031, carry a coupon rate of 1.55 percent during the current three-year fixed rate period and are subject to mandatory tender for purchase on April 1, 2015. On September 3, 2013, CL&P redeemed at par $125 million of 1.25 percent Series B 2011 PCRBs, which were subject to mandatory tender for purchase, using short-term debt.
(3)
On May 17, 2013, NSTAR Electric issued $200 million of three-year floating rate debentures due in May 2016. The proceeds, net of issuance costs, were used to repay commercial paper borrowings and for general corporate purposes. The debentures have a coupon rate reset quarterly based on 3-month LIBOR plus a credit spread of 0.24 percent. The interest rate as of December 31, 2013 was 0.478 percent.
(4)
On May 1, 2013, PSNH redeemed at par approximately $109 million of the 2001 Series C PCRBs that were due to mature in 2021 using short-term debt. On November 14, 2013, PSNH issued $250 million of 3.50 percent Series S First Mortgage Bonds due in 2023. On December 23, 2013, PSNH redeemed approximately $89 million of the Series B PCRBs that were due to mature in 2021. The proceeds of the Series S issuance were used to repay the short term debt used to redeem the $109 million 2001 Series C PCRBs and to redeem the $89 million Series B PCRBs and pay the associated call premium. The remaining proceeds of the offering were used to refinance short-term debt.
(5)
On September 1, 2013, WMECO repaid at maturity the $55 million Series A Senior Notes using short-term debt. On November 15, 2013, WMECO issued $80 million of 3.88 percent Series G Senior Notes due in 2023. The proceeds, net of issuance costs, were used to pay short-term borrowings and for other working capital purposes.
(6)
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 Series G $75 million First Mortgage Bonds that matured on January 1, 2014 and to pay $25 million in short-term borrowings. As a result and in accordance with applicable accounting guidance, these amounts were classified as Long-Term Debt on NU’s balance sheet as of December 31, 2013.
(7)
On May 13, 2013, NU parent issued $750 million of Senior Notes, consisting of $300 million of 1.45 percent Series E Senior Notes due to mature in 2018 and $450 million of 2.80 percent Series F Senior Notes due to mature in 2023. The proceeds, net of issuance costs, were used to repay the NU parent $250 million Series C Senior Notes at a coupon rate of 5.65 percent that matured on June 1, 2013 and the NU parent $300 million floating rate Series D Senior Notes that matured on
130
September 20, 2013. The remaining net proceeds were used to repay commercial paper program borrowings and for working capital purposes.
(8)
Amount relates tofair value adjustment amount is the purchase price adjustment, net of amortization, required to record the NSTAR long-term debt at fair value on the date of the merger.
Long-term debt maturities, mandatory tender payments and cash sinking fund requirements on debt outstanding for the years 2014 throughLong-Term Debt Issuances: On January 15, 2015, Eversource parent issued $150 million of 1.60 percent Series G Senior Notes, due to mature in 2018, and thereafter are shown below. These amounts exclude fees and interest$300 million of 3.15 percent Series H Senior Notes, due for spent nuclear fuel disposalto mature in 2025. As the debt proceeds, net of issuance costs, net unamortized premiums and discounts, and other fair value adjustmentsrefinanced short-term debt, the short-term debt was classified as Long-Term Debt as of December 31, 2013:2014. On May 20, 2015 and December 1, 2015, CL&P issued $300 million and $50 million, respectively, of 4.15 percent 2015 Series A First and Refunding Mortgage Bonds due to mature in 2045.On September 10, 2015, Yankee Gas issued $75 million of 3.35 percent 2015 Series M First Mortgage Bonds due to mature in 2025. On November 18, 2015, NSTAR Electric issued $250 million of 3.25 percent debentures, due to mature in 2025. On December 8, 2015, NSTAR Gas issued $100
109
| | | | | | | | | | | | | | |
(Millions of Dollars) | NU | | CL&P | | NSTAR Electric | | PSNH | | WMECO |
2014 | $ | 576.7 | | $ | 150.0 | | $ | 301.7 | | $ | 50.0 | | $ | - |
2015 | | 216.7 | | | 162.0 | | | 4.7 | | | - | | | 50.0 |
2016 | | 200.0 | | | - | | | 200.0 | | | - | | | - |
2017 | | 745.0 | | | 250.0 | | | 400.0 | | | 70.0 | | | - |
2018 | | 810.0 | | | 300.0 | | | - | | | 110.0 | | | - |
Thereafter | | 5,031.6 | | | 1,640.3 | | | 900.0 | | | 821.3 | | | 515.0 |
Total | $ | 7,580.0 | | $ | 2,502.3 | | $ | 1,806.4 | | $ | 1,051.3 | | $ | 565.0 |
million of 4.35 percent Series O First Mortgage Bonds due to mature in 2045. The proceeds of all debt issuances, net of issuance costs, were used to repay short-term borrowings and fund capital expenditures and working capital.
Long-Term Debt Repayments: On April 1, 2015, CL&P repaid at maturity the $100 million 5.00 percent 2005 Series A First and Refunding Mortgage Bonds and also redeemed the $62 million 1996A Series 1.55 percent PCRBs that were subject to mandatory tender using short-term borrowings. On August 3, 2015, WMECO repaid at maturity the $50 million 5.24 percent Series C Senior Notes, using short-term borrowings.
Long-Term Debt Issuance Authorizations: On November 25, 2015, PURA approved Yankee Gas’ request to extend the authorization period for issuance of up to $125 million in long-term debt from December 31, 2015 to December 31, 2016. On December 4, 2015, the DPU authorized WMECO to issue up to $100 million in long-term debt for the period through December 31, 2016. On December 4, 2015, the DPU approved NSTAR Electric’s request to extend the authorization period for issuance of up to $250 million in long-term debt from December 31, 2015 to December 31, 2016.
Long-Term Debt Provisions: The utility plant of CL&P, PSNH, Yankee Gas and NSTAR Gas is subject to the lien of each company's respective first mortgage bond indenture. The Eversource parent, NSTAR Electric WMECO and NU parentWMECO debt is unsecured. Additionally, the long-term debt agreements provide that Eversource and certain of its subsidiaries must comply with certain covenants as are customarily included in such agreements, including a minimum equity requirement for NSTAR Gas. Under the minimum equity requirement, the outstanding long-term debt of NSTAR Gas must not exceed equity.
CL&P’s&P's obligation to repay each series ofthe PCRBs is secured by first mortgage bonds. Each such series ofThe first mortgage bonds containscontain similar terms and provisions as the applicable series of PCRBs. If CL&P fails to meet its obligations under the first mortgage bonds, then the holder of the first mortgage bonds (the issuer of the PCRBs) would have rights under the first mortgage bonds. CL&P’s $62 million tax-exempt PCRBs, which is subject to mandatory tender for purchase on April 1, 2015, cannot be redeemed prior to its tender date. CL&P’s&P's $120.5 million tax-exempt PCRBs will be subject to redemption at par on or after September 1, 2021. All other long-term debt securities are subject to make-whole provisions.
PSNH's obligation to repay the PCRBs is secured by first mortgage bonds and bond insurance. The first mortgage bonds contain similar terms and provisions as the PCRBs. If PSNH fails to meet its obligations under the first mortgage bonds, then the holder of the first mortgage bonds (the issuer of the PCRBs) would have rights under the first mortgage bonds. The PSNH Series A tax-exempt PCRBs are currently callable at 100 percent of par. The PCRBs bear interest at a rate that is periodically set pursuant to auctions. PSNH is not obligated to purchase these PCRBs, which mature in 2021, from the remarketing agent. The interest rate as of December 31, 2013 was 0.088 percent.
The long-term debt agreements provide that NU and certain of its subsidiaries must comply with certain covenants as are customarily included in such agreements, including a minimum equity requirement for NSTAR Gas. Under the minimum equity requirement, the outstanding long-term debt of NSTAR Gas must not exceed equity.
Yankee Gas has certain long-term debt agreements that contain cross-default provisions applicable to all of Yankee Gas’ outstanding first mortgage bond series. The cross-default provisions on Yankee Gas’ Series B Bonds would be triggered if Yankee Gas were to default on a payment due on indebtedness in excess of $2 million. The cross-default provisions on all other series of Yankee Gas’ first mortgage bonds would be triggered if Yankee Gas were to default in a payment due on indebtedness in excess of $10 million.provisions. No other debt issuances contain cross-default provisions as of December 31, 2013.2015.
Pre-1983 Spent Nuclear Fuel Obligation: Under the Nuclear Waste Policy Act of 1982, CL&P and WMECO mustwere obligated to pay the DOE for the costs of disposal of pre-1983 spent nuclear fuel and high-level radioactive waste for the period prior to the sale of their ownership shares in the Millstone nuclear power stations.
stations, which were sold in March 2001. The DOE is responsible for the selection and development of repositories for, and the disposal of, spent nuclear fuel and high-level radioactive waste. For nuclear fuel used to generate electricity prior to April 7, 1983 (Prior Period Spent Nuclear Fuel) for CL&P and WMECO, an accrual has been recorded for the full liability, and payment must be made by CL&P and WMECO to the DOE prior to the first delivery of spent fuel to the DOE. After the sale of the Millstone nuclear power stations in March 2001, CL&P and WMECO remained responsible for their share of the disposal costs associated with the Prior Periodfor nuclear fuel used to generate electricity prior to April 7, 1983 (pre-1983 Spent Nuclear Fuel. Until such paymentFuel) and recorded an accrual for the full liability thereof to the DOE is made, the outstandingDOE. This liability will continue to accrueaccrued interest costs at the 3-month Treasury bill yield rate. As of December 31, 2014, CL&P and WMECO's pre-1983 Spent Nuclear Fuel obligation was $244.5 million and $57.4 million, respectively, which included accumulated interest costs of $178 million for CL&P and $41.8 million for WMECO.
In late 2015, CL&P and WMECO made payments of $244.6 million and $57.4 million, respectively, to fully satisfy their pre-1983 Spent Nuclear Fuel obligations to the DOE, which included accumulated interest of $178 million and $41.8 million, respectively. CL&P issued debt to fund its payment while WMECO liquidated its spent nuclear fuel trust.
In addition, as a result of consolidating CYAPC, NUEversource has consolidated $179.5 million and $179.4 million, respectively, in additional pre-1983 spent nuclear fuel obligations including interest, as of December 31, 2013. Fees due to the DOE, for the disposal of CL&P's and WMECO's Prior Period Spent Nuclear Fuel and CYAPC's spent nuclear fuel obligationwhich include accumulated interest costs of $350.3$130.7 million and $350$130.6 million ($177.9 million and $177.8 million for CL&P and $41.7 million and $41.7 million for WMECO) as of December 31, 20132015 and 2012,2014, respectively.
WMECO and CYAPC maintain trustsmaintains a trust to fund amounts due to the DOE for the disposal of pre-1983 spent nuclear fuel. For further information, on these trusts, see Note 6,5, "Marketable Securities," to the financial statements.
Long-Term Debt Maturities: Long-term debt maturities on debt outstanding for the years 2016 through 2020 and thereafter are shown below. These amounts exclude the CYAPC pre-1983 spent nuclear fuel obligation, net unamortized premiums, discounts and debt issuance costs, and other fair value adjustments as of December 31, 2015:
| | | | | | | | | | | | | | |
(Millions of Dollars) | Eversource | | CL&P | | NSTAR Electric | | PSNH | | WMECO |
2016 | $ | 200.0 | | $ | - | | $ | 200.0 | | $ | - | | $ | - |
2017 | | 745.0 | | | 250.0 | | | 400.0 | | | 70.0 | | | - |
2018 | | 960.0 | | | 300.0 | | | - | | | 110.0 | | | - |
2019 | | 800.0 | | | 250.0 | | | - | | | 150.0 | | | - |
2020 | | 295.0 | | | - | | | - | | | - | | | 95.0 |
Thereafter | | 5,736.6 | | | 1,990.3 | | | 1,450.0 | | | 746.3 | | | 420.0 |
Total | $ | 8,736.6 | | $ | 2,790.3 | | $ | 2,050.0 | | $ | 1,076.3 | | $ | 515.0 |
131110
10.9.
EMPLOYEE BENEFITS
A.
Pension Benefits and Postretirement Benefits Other Than Pensions
NUSCO sponsors aAs of December 31, 2014, Eversource Service sponsored two defined benefit retirement planplans that covers mostcovered eligible employees, including, among others, employees of CL&P, NSTAR Electric, PSNH and WMECO employees, hired before 2006 (or as negotiated, for bargaining unit employees), referred to as the NUSCOWMECO. Effective January 1, 2015, these two pension plans were merged into one plan, sponsored by Eversource Service (Pension Plan). The Pension Plan. NSTAR Electric acts as plan sponsor for a defined benefit retirement plan that covers most employees of NSTAR Electric and certain affiliates, hired before October 1, 2012, or as negotiated by bargaining unit employees, referred to as the NSTAR Pension Plan. Both plans arePlan is subject to the provisions of ERISA, as amended by the PPA of 2006. NUSCO alsoEversource’s policy is to annually fund the Pension Plan in an amount at least equal to an amount that will satisfy all federal funding requirements. In addition to the Pension Plan, Eversource maintains non-qualified defined benefit retirement plans sponsored by Eversource Service (herein collectively referred to as the SERP Plans), which provide benefits in excess of Internal Revenue Code limitations to eligible current and retired participants.
NUSCOAs of December 31, 2014, Eversource Service also sponsorssponsored defined benefit postretirement plans that provideprovided certain retiree health care benefits, primarily medical, and dental and life insurance, benefits to retiringretired employees that meetmet certain age and service eligibility requirements, (NUSCO PBOP Plansincluding, among others, employees of CL&P, NSTAR Electric, PSNH and NSTAR PBOPWMECO. Effective January 1, 2015, these postretirement plans were merged into one plan, sponsored by Eversource Service (PBOP Plan).Under certain circumstances, eligible retirees are required to contribute to the costs of postretirement benefits. The benefits provided under the NUSCO and NSTAR PBOP PlansPlan are not vested and the Company has the right to modify any benefit provision subject to applicable laws at that time. Eversource annually funds postretirement costs through tax deductible contributions to external trusts.
The funded status of the Pension, SERP and PBOP Plans is calculated based on the difference between the benefit obligation and the fair value of plan assets and is recorded on the balance sheets as an asset or a liability. Because the Regulated companies recover the retiree benefit costs from customers through rates, regulatory assets are recorded in lieu of recording an adjustment to Accumulated Other Comprehensive Income/(Loss). for the funded status of the Pension, SERP and PBOP Plans. Regulatory accounting wasis also applied to the portions of the NUSCOEversource Service costs that support the Regulated companies, as these costs are also recovered from customers. Adjustments to the Pension and PBOP Plans funded status for the unregulated companies are recorded on an after-tax basis to Accumulated Other Comprehensive Income/(Loss). For further information, see Note 3,2, "Regulatory Accounting," and Note 15,14, "Accumulated Other Comprehensive Income/(Loss)," to the financial statements. The SERP Plans do not have plan assets.
For the NUSCO Pension and PBOP Plans,year ended December 31, 2015, the expected return on plan assets is calculated by applying the assumed rate of return to a four-year rolling average of plan asset fair values, which reduces year-to-year volatility. This calculation recognizes investment gains or losses over a four-year period from the years in which they occur. Investment gains or losses for this purpose are the difference between the calculated expected return and the actual return. As investment gains and losses are reflected in the average plan asset fair values, they are subject to amortization with other unrecognized actuarial gains or losses. For the NSTAR Pension and PBOP Plans, the entire difference between the actual return and calculated expected return on plan assets isfor the Pension and PBOP Plans are reflected as a component of unrecognized actuarial gaingains or loss.losses, which are recorded in Regulatory Assets or Accumulated Other Comprehensive Income/(Loss). Unrecognized actuarial gains or losses are amortized as a component of Pensionpension and PBOP expense over the estimated average future employee service period.
Pension and SERP Plans: The funded statusOn January 1, 2014, NSTAR Electric & Gas was merged into Eversource Service (service company merger) and, concurrently, all employees were transferred to the company they predominantly provide services for: Eversource Service, NSTAR Electric or NSTAR Gas. As a result of eachthese employee transfers, the pension and SERP assets and liabilities of NSTAR Electric & Gas were attributed by participant and transferred to the plans is recordedapplicable operating company's balance sheets. This change had no impact on the respective acting sponsor's balance sheet: NUSCO (NUSCO Pension, NUSCO SERP and NSTAR SERP) andincome statement or net assets of NSTAR Electric (NSTAR Pension). or Eversource.
The NUSCO plansPension and SERP Plans are accounted for under the multiple-employer approach, while the NSTAR plans are accounted for under the multi-employer approach. Accordingly, thewith each operating company's balance sheet reflecting its share of NSTAR Electric reflects the full funded status of the NSTAR Pension Plan.
plans. Although Eversource maintains marketable securities in a benefit trust, the SERP Plans do not contain any assets. For further information, see Note 5, "Marketable Securities," to the financial statements. The following tables provide information on the Pension and SERP Plan benefit obligations, fair values of Pension Plan assets, and funded status:
|
| | Pension and SERP | | Pension and SERP |
NU | As of December 31, |
Eversource | As of December 31, |
(Millions of Dollars) | (Millions of Dollars) | 2013 | | 2012(1) | (Millions of Dollars) | 2015 | | 2014 |
Change in Benefit Obligation | Change in Benefit Obligation | | | | | Change in Benefit Obligation | | | | |
Benefit Obligation as of Beginning of Year | Benefit Obligation as of Beginning of Year | $ | (5,022.8) | | $ | (3,098.9) | Benefit Obligation as of Beginning of Year | $ | (5,486.2) | | $ | (4,676.5) |
Liabilities Assumed from Merger with NSTAR | | - | | (1,409.7) |
Service Cost | Service Cost | | (102.3) | | (84.3) | Service Cost | | (91.4) | | (79.9) |
Interest Cost | Interest Cost | | (206.7) | | (198.3) | Interest Cost | | (227.0) | | (225.7) |
Actuarial Gain/(Loss) | Actuarial Gain/(Loss) | | 433.6 | | (429.7) | Actuarial Gain/(Loss) | | 331.5 | | (739.6) |
Benefits Paid – Pension | | 216.6 | | 187.7 |
Benefits Paid – SERP | | 5.1 | | 4.2 |
SERP Curtailment | | - | | | 6.2 |
Benefits Paid - Pension | | 238.5 | | 230.3 |
Benefits Paid - Lump Sum | | 149.5 | | - |
Benefits Paid - SERP | | 5.0 | | | 5.2 |
Benefit Obligation as of End of Year | Benefit Obligation as of End of Year | $ | (4,676.5) | | $ | (5,022.8) | Benefit Obligation as of End of Year | $ | (5,080.1) | | $ | (5,486.2) |
Change in Pension Plan Assets | Change in Pension Plan Assets | | | | | Change in Pension Plan Assets | | | | |
Fair Value of Plan Assets as of Beginning of Year | $ | 3,411.3 | | $ | 2,005.9 |
Assets Assumed from Merger with NSTAR | | - | | 984.7 |
Fair Value of Pension Plan Assets as of Beginning of Year | $ | 4,126.5 | | $ | 3,985.9 |
Employer Contributions | Employer Contributions | | 284.7 | | 222.4 | Employer Contributions | | 154.6 | | 171.6 |
Actual Return on Plan Assets | | 506.5 | | 386.0 |
Actual Return on Pension Plan Assets | | 12.3 | | 199.3 |
Benefits Paid | Benefits Paid | | (216.6) | | (187.7) | Benefits Paid | | (238.5) | | (230.3) |
Fair Value of Plan Assets as of End of Year | $ | 3,985.9 | | $ | 3,411.3 |
Benefits Paid - Lump Sum | | (149.5) | | | - |
Fair Value of Pension Plan Assets as of End of Year | $ | 3,905.4 | | $ | 4,126.5 |
Funded Status as of December 31st | Funded Status as of December 31st | $ | (690.6) | | $ | (1,611.5) | Funded Status as of December 31st | $ | (1,174.7) | | $ | (1,359.7) |
132111
|
| | Pension and SERP | | Pension and SERP |
| | As of December 31, 2013 | | As of December 31, 2012 | | As of December 31, 2015 | | As of December 31, 2014 |
| | | | | NSTAR | | | | | | | | | | | NSTAR | | | | | | | | | | | NSTAR | | | | | | | | | | | NSTAR | | | | | | |
(Millions of Dollars) | (Millions of Dollars) | CL&P | | Electric(2) | | PSNH | | WMECO | | CL&P | | Electric(2) | | PSNH | | WMECO | (Millions of Dollars) | CL&P | | Electric | | PSNH | | WMECO | | CL&P | | Electric | | PSNH | | WMECO |
Change in Benefit Obligation | Change in Benefit Obligation | | | | | | | | | | | | | | | | | | | | | | | | Change in Benefit Obligation | | | | | | | | | | | | | | | | | | | | | | | |
Benefit Obligation as of Beginning of Year | Benefit Obligation as of Beginning of Year | $ | (1,178.0) | | $ | (1,430.0) | | $ | (576.0) | | $ | (243.1) | | $ | (1,043.8) | | $ | (1,346.2) | | $ | (497.9) | | $ | (215.8) | Benefit Obligation as of Beginning of Year | $ | (1,230.1) | | $ | (982.6) | | $ | (580.7) | | $ | (249.4) | | $ | (1,083.4) | | $ | (1,353.3) | | $ | (529.0) | | $ | (223.9) |
Change due to transfer of employees | | (4.6) | | | 6.2 | | | (1.9) | | | (1.3) | | | 26.4 | | | 479.9 | | | 32.2 | | | 6.2 |
Service Cost | Service Cost | | (24.9) | | | (33.1) | | | (13.1) | | | (4.7) | | | (21.8) | | | (30.3) | | | (11.8) | | | (4.1) | Service Cost | | (24.7) | | | (14.9) | | | (12.1) | | | (4.3) | | | (20.2) | | | (13.6) | | | (9.7) | | | (3.5) |
Interest Cost | Interest Cost | | (48.3) | | | (58.0) | | | (23.6) | | | (10.0) | | | (51.2) | | | (58.9) | | | (24.4) | | | (10.5) | Interest Cost | | (51.1) | | | (40.2) | | | (24.3) | | | (10.4) | | | (50.5) | | | (41.3) | | | (23.8) | | | (10.3) |
Actuarial Gain/(Loss) | Actuarial Gain/(Loss) | | 110.7 | | | 96.6 | | | 62.4 | | | 22.4 | | | (117.4) | | | (63.6) | | | (61.3) | | | (24.0) | Actuarial Gain/(Loss) | | 77.8 | | | 34.1 | | | 38.9 | | | 12.6 | | | (161.0) | | | (107.0) | | | (73.3) | | | (29.8) |
Benefits Paid - Pension | Benefits Paid - Pension | | 56.6 | | | 71.2 | | | 21.1 | | | 11.5 | | | 55.9 | | | 69.0 | | | 19.7 | | | 11.3 | Benefits Paid - Pension | | 60.2 | | | 47.6 | | | 23.2 | | | 12.7 | | | 58.3 | | | 52.4 | | | 22.8 | | | 11.9 |
Benefits Paid - Lump Sum | | 14.5 | | | - | | | 9.1 | | | 2.5 | | | - | | | - | | | - | | | - |
Benefits Paid - SERP | Benefits Paid - SERP | | 0.5 | | | - | | | 0.2 | | | - | | | 0.3 | | | - | | | - | | | - | Benefits Paid - SERP | | 0.4 | | | 0.1 | | | 0.2 | | | - | | | 0.3 | | | 0.3 | | | 0.1 | | | - |
SERP Curtailment | | - | | | - | | | - | | | - | | | - | | | - | | | (0.3) | | | - |
Benefit Obligation as of End of Year | Benefit Obligation as of End of Year | $ | (1,083.4) | | $ | (1,353.3) | | $ | (529.0) | | $ | (223.9) | | $ | (1,178.0) | | $ | (1,430.0) | | $ | (576.0) | | $ | (243.1) | Benefit Obligation as of End of Year | $ | (1,157.6) | | $ | (949.7) | | $ | (547.6) | | $ | (237.6) | | $ | (1,230.1) | | $ | (982.6) | | $ | (580.7) | | $ | (249.4) |
Change in Pension Plan Assets | Change in Pension Plan Assets | | | | | | | | | | | | | | | | | | | | | | | | Change in Pension Plan Assets | | | | | | | | | | | | | | | | | | | | | | | |
Fair Value of Plan Assets as of Beginning of Year | $ | 937.6 | | $ | 1,069.1 | | $ | 386.6 | | $ | 218.5 | | $ | 869.6 | | $ | 988.5 | | $ | 279.7 | | $ | 202.0 |
Fair Value of Pension Plan Assets as of Beginning of Year | $ | 980.8 | | $ | 879.0 | | $ | 498.4 | | $ | 234.0 | | $ | 1,016.3 | | $ | 1,235.3 | | $ | 528.6 | | $ | 240.4 |
Change due to transfer of employees | | 4.6 | | | (6.2) | | | 1.9 | | | 1.3 | | | (26.4) | | | (441.4) | | | (32.2) | | | (6.2) |
Employer Contributions | Employer Contributions | | - | | | 82.0 | | | 108.3 | | | - | | | - | | | 25.0 | | | 87.7 | | | - | Employer Contributions | | - | | | 5.0 | | | 1.0 | | | - | | | - | | | 101.0 | | | - | | | - |
Actual Return on Plan Assets | | 135.3 | | | 155.4 | | | 54.8 | | | 33.4 | | | 123.9 | | | 124.6 | | | 38.9 | | | 27.8 |
Actual Return on Pension Plan Assets | | 2.8 | | | 2.7 | | | 1.5 | | | 0.7 | | | 49.2 | | | 36.5 | | | 24.8 | | | 11.7 |
Benefits Paid | Benefits Paid | | (56.6) | | | (71.2) | | | (21.1) | | | (11.5) | | | (55.9) | | | (69.0) | | | (19.7) | | | (11.3) | Benefits Paid | | (60.2) | | | (47.6) | | | (23.2) | | | (12.7) | | | (58.3) | | | (52.4) | | | (22.8) | | | (11.9) |
Fair Value of Plan Assets as of End of Year | $ | 1,016.3 | | $ | 1,235.3 | | $ | 528.6 | | $ | 240.4 | | $ | 937.6 | | $ | 1,069.1 | | $ | 386.6 | | $ | 218.5 |
Benefits Paid - Lump Sum | | (14.5) | | | - | | | (9.1) | | | (2.5) | | | - | | | - | | | - | | | - |
Fair Value of Pension Plan Assets as of End of Year | $ | 913.5 | | $ | 832.9 | | $ | 470.5 | | $ | 220.8 | | $ | 980.8 | | $ | 879.0 | | $ | 498.4 | | $ | 234.0 |
Funded Status as of December 31st | Funded Status as of December 31st | $ | (67.1) | | $ | (118.0) | | $ | (0.4) | | $ | 16.5 | | $ | (240.4) | | $ | (360.9) | | $ | (189.4) | | $ | (24.6) | Funded Status as of December 31st | $ | (244.1) | | $ | (116.8) | | $ | (77.1) | | $ | (16.8) | | $ | (249.3) | | $ | (103.6) | | $ | (82.3) | | $ | (15.4) |
| | | | | | | | | | | | | | | | | | | | | | | | |
(1) NSTAR amounts were included in NU beginning April 10, 2012. | |
| | | | | | | | | | | | | | | | | | | | | | | | |
(2) NSTAR Electric amounts do not include benefit obligations of the NSTAR SERP Plan. | |
AsIn August 2015, Eversource made a total lump-sum payout of $149.5 million, which reduced the projected benefit obligation and Pension Plan assets by a corresponding amount. Therefore, the lump-sum payment had no impact on the net Accrued Pension Liability reflected on the Eversource, CL&P, PSNH and WMECO balance sheets as of December 31, 2013, prepaid2015.
During 2014, the Society of Actuaries released a series of updated mortality tables resulting from studies that measured mortality rates for various groups of individuals. The updated mortality tables released in 2014 increased the life expectancy of plan participants by three to five years and had the effect of increasing the estimated benefits to be provided to plan participants.The impact of adopting the updated mortality tables on Eversource's liability as of December 31, 2014 was an increase of approximately $340 million. In 2015, a revised scale for the mortality table was released having the effect of decreasing the estimate of benefits to be provided to plan participants. The impact of the adoption of the new mortality scale resulted in a decrease of $48 million on Eversource's liability as of December 31, 2015.
The increase in the discount rate used to calculate the funded status resulted in a decrease on Eversource's liability of approximately $267 million as of December 31, 2015. Decreases in the discount rates resulted in an increase on Eversource's liability of approximately $530 million as of December 31, 2014.
The pension assets of $3 million and $17 million for PSNH and WMECO, respectively, were included in Other Long-Term Assets on their accompanying balance sheets. Pension and SERP benefitsPlans' funded status includes the current portion of the SERP liability, which is included in Other Current Liabilities on the accompanying balance sheets.
Although NU maintains marketable securities in a supplemental benefit trust, the plan itself does not contain any assets. See Note 6, "Marketable Securities," to the financial statements.
| | | | | | | | | | | | | | | | |
As of December 31, 2015 and 2014, the accumulated benefit obligation for the Pension and SERP Plans is as follows: |
| | | | | | | | | | | | | | | | |
(Millions of Dollars) | Eversource | | CL&P | | NSTAR Electric | | PSNH | | WMECO | |
2015 | $ | 4,733.2 | | $ | 1,062.7 | | $ | 888.8 | | $ | 506.4 | | $ | 222.3 | |
2014 | | 5,000.1 | | | 1,101.4 | | | 910.4 | | | 524.5 | | | 226.4 | |
| | | | | | | | | | | | | | | | |
The following actuarial assumptions were used in calculating the Pension and SERP Plans' year end funded status: |
|
The accumulated benefit obligation for the Pension and SERP Plans is as follows:
|
| | | | | | |
| | Pension and SERP |
| | As of December 31, |
(Millions of Dollars) | 2013 | | 2012 |
NU | $ | 4,538.8 | | $ | 4,622.1 |
CL&P | | 1,058.0 | | | 1,061.8 |
NSTAR Electric(1) | | 1,280.6 | | | 1,353.1 |
PSNH | | 520.1 | | | 515.9 |
WMECO | | 220.6 | | | 221.3 |
| | | | | | |
|
(1)
NSTAR Electric amounts do not include the accumulated benefit obligation for the SERP Plan.
|
The following actuarial assumptions were used in calculating the Pension and SERP Plans' year end funded status:
|
|
| | Pension and SERP | | | Pension and SERP | | | | |
| | As of December 31, | | | As of December 31, | | | | |
| | 2013 | | 2012 | | | 2015 | | | 2014 | | | | | |
NUSCO Pension and SERP Plans | | | | | | |
Discount Rate | Discount Rate | 5.03 | % | | 4.24 | % | | Discount Rate | 4.21 | % | - | 4.60 | % | | 4.20 | % | | | | |
Compensation/Progression Rate | Compensation/Progression Rate | 3.50 | % | | 3.50 | % | | Compensation/Progression Rate | 3.50% | | 3.50 | % | | | | |
| | | | | | | |
NSTAR Pension and SERP Plans | | | | | | |
Discount Rate | 4.85 | % | | 4.13 | % | |
Compensation/Progression Rate | 4.00 | % | | 4.00 | % | |
Pension and SERP Expense: For the NUSCO Plans, NU allocatesEversource charges net periodic pension expense to its subsidiaries based on the actual participant demographic data for each subsidiary's participants. Benefit paymentsThe actual investment return in the trust is allocated to each of the subsidiaries annually in proportion to the investment return expected to be earned during the year. For the year ended December 31, 2013 (prior to the service company merger), the net periodic pension expense recorded at NSTAR Electric represented the full cost of the plan with a portion of the costs allocated to affiliated companies based on participant demographic data.
112
The components of net periodic benefit expense for the Pension and SERP Plans are shown below. The net periodic benefit expense and the intercompany allocations less the capitalized portion of pension and SERP amounts are included in Operations and Maintenance expense on the statements of income. Capitalized pension amounts relate to employees working on capital projects and are included in Property, Plant and Equipment, Net on the balance sheets. Pension and SERP expense reflected in the statements of cash flows for CL&P, NSTAR Electric, PSNH and WMECO does not include the intercompany allocations or the corresponding capitalized portion, as these amounts are cash settled on a short-term basis.
| | | | | | | | | | | | | | | |
| Pension and SERP |
| | For the Year Ended December 31, 2015 |
| | | | | | | | NSTAR | | | | | | |
(Millions of Dollars) | Eversource(1) | | CL&P | | Electric | | PSNH(1) | | WMECO |
Service Cost | $ | 91.4 | | $ | 24.7 | | $ | 14.9 | | $ | 12.1 | | $ | 4.3 |
Interest Cost | | 227.0 | | | 51.1 | | | 40.2 | | | 24.3 | | | 10.4 |
Expected Return on Pension Plan Assets | | (335.9) | | | (78.9) | | | (70.0) | | | (40.4) | | | (18.9) |
Actuarial Loss | | 148.5 | | | 32.2 | | | 35.8 | | | 11.6 | | | 6.4 |
Prior Service Cost/(Credit) | | 3.7 | | | 1.5 | | | (0.1) | | | 0.5 | | | 0.3 |
Total Net Periodic Benefit Expense | $ | 134.7 | | $ | 30.6 | | $ | 20.8 | | $ | 8.1 | | $ | 2.5 |
Intercompany Allocations | | N/A | | $ | 22.5 | | $ | 13.6 | | $ | 6.7 | | $ | 4.4 |
Capitalized Pension Expense | $ | 41.0 | | $ | 18.8 | | $ | 11.4 | | $ | 3.5 | | $ | 1.9 |
| | | | | | | | | | | | | | | |
| Pension and SERP |
| | For the Year Ended December 31, 2014 |
| | | | | | | | NSTAR | | | | | | |
(Millions of Dollars) | Eversource | | CL&P | | Electric | | PSNH | | WMECO |
Service Cost | $ | 79.9 | | $ | 20.2 | | $ | 13.6 | | $ | 9.7 | | $ | 3.5 |
Interest Cost | | 225.7 | | | 50.5 | | | 41.3 | | | 23.8 | | | 10.3 |
Expected Return on Pension Plan Assets | | (310.8) | | | (75.4) | | | (63.0) | | | (38.1) | | | (17.9) |
Actuarial Loss | | 128.4 | | | 33.7 | | | 23.5 | | | 11.6 | | | 6.9 |
Prior Service Cost | | 4.4 | | | 1.8 | | | - | | | 0.7 | | | 0.4 |
Total Net Periodic Benefit Expense | $ | 127.6 | | $ | 30.8 | | $ | 15.4 | | $ | 7.7 | | $ | 3.2 |
Intercompany Allocations | | N/A | | $ | 26.7 | | $ | 10.4 | | $ | 7.6 | | $ | 5.1 |
Capitalized Pension Expense | $ | 35.2 | | $ | 17.6 | | $ | 7.9 | | $ | 3.0 | | $ | 2.4 |
| | | | | | | | | | | | | | | |
| | Pension and SERP |
| | For the Year Ended December 31, 2013 |
| | | | | | | | NSTAR | | | | | | |
(Millions of Dollars) | Eversource | | CL&P | | Electric (2) | | PSNH | | WMECO |
Service Cost | $ | 102.3 | | $ | 24.9 | | $ | 33.1 | | $ | 13.1 | | $ | 4.7 |
Interest Cost | | 206.7 | | | 48.3 | | | 58.0 | | | 23.6 | | | 10.0 |
Expected Return on Pension Plan Assets | | (278.1) | | | (73.8) | | | (84.4) | | | (35.4) | | | (17.4) |
Actuarial Loss | | 210.5 | | | 55.9 | | | 58.1 | | | 21.6 | | | 11.8 |
Prior Service Cost/(Credit) | | 4.0 | | | 1.8 | | | (0.3) | | | 0.7 | | | 0.4 |
Total Net Periodic Benefit Expense | $ | 245.4 | | $ | 57.1 | | $ | 64.5 | | $ | 23.6 | | $ | 9.5 |
Intercompany Allocations | | N/A | | $ | 44.9 | | $ | (8.4) | | $ | 10.5 | | $ | 8.0 |
Capitalized Pension Expense | $ | 73.2 | | $ | 28.0 | | $ | 28.9 | | $ | 7.3 | | $ | 5.2 |
(1)
Amounts exclude $3.2 million for the year ended December 31, 2015 that represent amounts included in other deferred debits.
(2)
NSTAR Electric's allocated expense associated with the NSTAR SERP was $3.2 million for the year ended December 31, 2013 and was not included in the NSTAR Electric amounts in the table above. For the years ended December 31, 2015 and 2014, the SERP amount is now allocated to NSTAR Electric due to the service company merger.
| | | | | | | | | | | | | | | | | | |
The following actuarial assumptions were used to calculate Pension and SERP expense amounts: | |
| | | | | | | | | | | | | | | | | | |
| | Pension and SERP |
| | For the Years Ended December 31, |
| 2015 | | 2014 | | | 2013 |
Discount Rate | 4.20% | | 4.85 | % | - | 5.03 | % | | 4.13 | % | - | 4.24 | % |
Expected Long-Term Rate of Return | 8.25 % | | 8.25 % | | 8.25% |
Compensation/Progression Rate | 3.50 % | | 3.50 | % | - | 4.00 | % | | 3.50 | % | - | 4.00 | % |
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|
The following is a summary of the changes in plan assets and benefit obligations recognized in Regulatory Assets and Other Comprehensive Income (OCI) as well as amounts in Regulatory Assets and OCI that were reclassified as net periodic benefit expense during the years presented: |
| | | | | | | | | | | | |
| Regulatory Assets | | OCI |
| | For the Years Ended December 31, |
(Millions of Dollars) | 2015 | | 2014 | | 2015 | | 2014 |
Actuarial (Gains)/Losses Arising During the Year | $ | (2.0) | | $ | 797.3 | | $ | (6.2) | | $ | 55.9 |
Actuarial Losses Reclassified as Net Periodic Benefit Expense | | (142.3) | | | (122.8) | | | (6.2) | | | (5.6) |
Prior Service Cost Reclassified as Net Periodic Benefit Expense | (3.5) | | | (4.2) | | | (0.2) | | | (0.2) |
|
The following is a summary of the remaining Regulatory Assets and Accumulated Other Comprehensive Loss amounts that have not been recognized as components of net periodic benefit expense as of December 31, 2015 and 2014, as well as the amounts that are expected to be recognized as components in 2016: |
| | | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | | |
| Regulatory Assets as of | | Expected | | AOCI as of | | Expected |
| | December 31, | | 2016 | | December 31, | | 2016 |
(Millions of Dollars) | 2015 | | 2014 | | Expense | | 2015 | | 2014 | | Expense |
Actuarial Loss | $ | 1,667.6 | | $ | 1,811.9 | | $ | 120.6 | | $ | 81.1 | | $ | 93.5 | | $ | 5.4 |
Prior Service Cost | | 9.7 | | | 13.2 | | | 3.4 | | | 0.6 | | | 0.8 | | | 0.2 |
PBOP Plan:On January 1, 2014, concurrent with the service company merger, the PBOP assets and liabilities of NSTAR Electric & Gas were attributed by participant and transferred to the applicable operating company's balance sheets. This change had no impact on the income statements or net assets of NSTAR Electric or Eversource. The PBOP Plan is accounted for under the multiple-employer approach, with each operating company's balance sheet reflecting its share of the funded status of the plan. The following tables provide information on the PBOP Plan benefit obligations, fair values of plan assets, and funded status:
| | | | | | |
| | PBOP |
Eversource | As of December 31, |
(Millions of Dollars) | 2015 | | 2014 |
Change in Benefit Obligation | | | | | |
Benefit Obligation as of Beginning of Year | $ | (1,147.9) | | $ | (1,038.0) |
Service Cost | | (16.3) | | | (12.5) |
Interest Cost | | (47.2) | | | (49.5) |
Actuarial Gain/(Loss) | | 106.0 | | | (95.5) |
Benefits Paid | | 54.0 | | | 47.6 |
Benefit Obligation as of End of Year | $ | (1,051.4) | | $ | (1,147.9) |
Change in Plan Assets | | | | | |
Fair Value of Plan Assets as of Beginning of Year | $ | 862.6 | | $ | 826.5 |
Actual Return on Plan Assets | | (4.3) | | | 43.7 |
Employer Contributions | | 7.9 | | | 40.0 |
Benefits Paid | | (54.0) | | | (47.6) |
Fair Value of Plan Assets as of End of Year | $ | 812.2 | | $ | 862.6 |
Funded Status as of December 31st | $ | (239.2) | | $ | (285.3) |
| | | | | | | | | | | | | | | | | | | | | | | | |
| | PBOP |
| | As of December 31, |
| | 2015 | | 2014 |
| | | | | NSTAR | | | | | | | | | | | NSTAR | | | | | | |
(Millions of Dollars) | CL&P | | Electric | | PSNH | | WMECO | | CL&P | | Electric | | PSNH | | WMECO |
Change in Benefit Obligation | | | | | | | | | | | | | | | | | | | | | | | |
Benefit Obligation as of Beginning of Year | $ | (173.9) | | $ | (468.7) | | $ | (91.8) | | $ | (36.6) | | $ | (180.4) | | $ | - | | $ | (93.5) | | $ | (38.7) |
Change due to transfer of employees | | 0.1 | | | 2.3 | | | (0.3) | | | - | | | 3.7 | | | (395.5) | | | 4.3 | | | 1.0 |
Service Cost | | (2.1) | | | (5.4) | | | (1.4) | | | (0.4) | | | (2.2) | | | (3.1) | | | (1.3) | | | (0.4) |
Interest Cost | | (7.2) | | | (19.0) | | | (3.9) | | | (1.5) | | | (8.1) | | | (19.4) | | | (4.3) | | | (1.7) |
Actuarial Gain/(Loss) | | 7.2 | | | 59.1 | | | 3.6 | | | 1.5 | | | 3.5 | | | (68.6) | | | (1.1) | | | 1.3 |
Benefits Paid | | 11.9 | | | 18.9 | | | 5.3 | | | 2.6 | | | 9.6 | | | 17.9 | | | 4.1 | | | 1.9 |
Benefit Obligation as of End of Year | $ | (164.0) | | $ | (412.8) | | $ | (88.5) | | $ | (34.4) | | $ | (173.9) | | $ | (468.7) | | $ | (91.8) | | $ | (36.6) |
Change in Plan Assets | | | | | | | | | | | | | | | | | | | | | | | |
Fair Value of Plan Assets as of Beginning of Year | $ | 149.0 | | $ | 336.5 | | $ | 80.9 | | $ | 34.4 | | $ | 151.3 | | $ | - | | $ | 81.8 | | $ | 35.3 |
Change due to transfer of employees | | - | | | 0.6 | | | 0.2 | | | - | | | (3.2) | | | 316.7 | | | (3.1) | | | (1.0) |
Actual Return on Plan Assets | | (0.4) | | | (2.8) | | | - | | | (0.1) | | | 6.3 | | | 18.4 | | | 3.8 | | | 1.6 |
Employer Contributions | | - | | | 4.9 | | | - | | | - | | | 4.2 | | | 19.3 | | | 2.5 | | | 0.4 |
Benefits Paid | | (11.9) | | | (18.9) | | | (5.3) | | | (2.6) | | | (9.6) | | | (17.9) | | | (4.1) | | | (1.9) |
Fair Value of Plan Assets as of End of Year | $ | 136.7 | | $ | 320.3 | | $ | 75.8 | | $ | 31.7 | | $ | 149.0 | | $ | 336.5 | | $ | 80.9 | | $ | 34.4 |
Funded Status as of December 31st | $ | (27.3) | | $ | (92.5) | | $ | (12.7) | | $ | (2.7) | | $ | (24.9) | | $ | (132.2) | | $ | (10.9) | | $ | (2.2) |
During 2014, the Society of Actuaries released a series of updated mortality tables resulting from studies that measured mortality rates for various groups of individuals. The updated mortality tables released in 2014 increased the life expectancy of plan participants by three to five years and contributions are also trackedhad the effect of increasing the estimated benefits to be provided to plan participants.The impact of adopting the updated mortality tables on Eversource's liability as of December 31, 2014 was an increase of approximately $82 million. In 2015, a revised scale for the mortality table was released having the effect of decreasing the estimate of benefits to be provided to plan participants. The impact of the adoption of the new mortality scale resulted in a decrease of $23 million on Eversource's liability as of December 31, 2015.
114
The increase in the discount rate used to calculate the funded status resulted in a decrease on Eversource's liability of approximately $60 million as of December 31, 2015. Decreases in the discount rates resulted in an increase on Eversource's liability of approximately $110 million as of December 31, 2014.
| | | | | | | |
The following actuarial assumptions were used in calculating the PBOP Plan's year end funded status: |
| | | | | | | |
| | PBOP | |
| | As of December 31, | |
| 2015 | | 2014 | | |
Discount Rate | 4.62 | % | | 4.22 | % | |
Health Care Cost Trend Rate | 6.25 | % | | 6.50 | % | |
PBOP Expense: Eversource charges net periodic postretirement benefits expense to its subsidiaries based on the actual participant demographic data for each subsidiary.subsidiary's participants. The actual investment return in the trust each year is allocated to each of the subsidiaries annually in proportion to the investment return expected to be earned during the year. For the NSTAR Pension Plan,year ended December 31, 2013 (prior to the service company merger), the net periodic pensionpostretirement expense recorded atof the NSTAR PBOP Plan allocated to NSTAR Electric represents the full cost of the plan and then a portion of the costs are allocated to affiliated companies based on participant demographic data.
133
was $4.6 million.
The components of net periodic benefit expense for which the totalPBOP Plan are shown below. The net periodic benefit expense and the intercompany allocations less the capitalized amounts isportion of PBOP are included in Operations and Maintenance on the statements of income, the portion of pensionincome. Capitalized PBOP amounts capitalized relatedrelate to employees working on capital projects which isand are included in Property, Plant and Equipment, Net on the balance sheets,sheets. PBOP expense reflected in the statements of cash flows for CL&P, NSTAR Electric, PSNH and WMECO does not include the intercompany allocations not included inor the net periodic benefit expensecorresponding capitalized portion, as these amounts for the Pension and SERP Plans are as follows:cash settled on a short-term basis.
|
| | Pension and SERP | | | | PBOP |
| | For the Year Ended December 31, 2013 | | | For the Year Ended December 31, 2015 |
| | | | | | | NSTAR | | | | | | | | | | | | | NSTAR | | | | | | |
(Millions of Dollars) | (Millions of Dollars) | NU | | CL&P | | Electric (2) | | PSNH | | WMECO | | (Millions of Dollars) | Eversource | | CL&P | | Electric | | PSNH | | WMECO |
Service Cost | Service Cost | $ | 102.3 | | $ | 24.9 | | $ | 33.1 | | $ | 13.1 | | $ | 4.7 | | Service Cost | $ | 16.3 | | $ | 2.1 | | $ | 5.4 | | $ | 1.4 | | $ | 0.4 |
Interest Cost | Interest Cost | | 206.7 | | 48.3 | | 58.0 | | 23.6 | | 10.0 | | Interest Cost | | 47.2 | | | 7.2 | | | 19.0 | | | 3.9 | | | 1.5 |
Expected Return on Plan Assets | Expected Return on Plan Assets | | (278.1) | | (73.8) | | (84.4) | | (35.4) | | (17.4) | | Expected Return on Plan Assets | | (67.4) | | | (11.1) | | | (27.3) | | | (6.0) | | | (2.5) |
Actuarial Loss | Actuarial Loss | | 210.5 | | 55.9 | | 58.1 | | 21.6 | | 11.8 | | Actuarial Loss | | 6.8 | | | 0.7 | | | 2.3 | | | 0.5 | | | - |
Prior Service Cost/(Credit) | | 4.0 | | | 1.8 | | | (0.3) | | | 0.7 | | | 0.4 | |
Prior Service Credit | | (0.5) | | | - | | | (0.2) | | | - | | | - |
Total Net Periodic Benefit Expense/(Income) | $ | 2.4 | | $ | (1.1) | | $ | (0.8) | | $ | (0.2) | | $ | (0.6) |
Intercompany Allocations | | N/A | | $ | 1.9 | | $ | 0.8 | | $ | 0.4 | | $ | 0.3 |
Capitalized PBOP Expense/(Income) | $ | 0.1 | | $ | (0.2) | | $ | (0.2) | | $ | 0.2 | | $ | (0.2) |
| | | | | | | | | | | | | | | |
| PBOP |
| | For the Year Ended December 31, 2014 |
| | | | | | | | NSTAR | | | | | | |
(Millions of Dollars) | Eversource | | CL&P | | Electric | | PSNH | | WMECO |
Service Cost | $ | 12.5 | | $ | 2.2 | | $ | 3.1 | | $ | 1.3 | | $ | 0.4 |
Interest Cost | | 49.5 | | | 8.1 | | | 19.4 | | | 4.3 | | | 1.7 |
Expected Return on Plan Assets | | (63.3) | | | (10.5) | | | (25.9) | | | (5.4) | | | (2.3) |
Actuarial Loss/(Gain) | | 12.2 | | | 4.2 | | | (0.5) | | | 2.2 | | | 0.5 |
Prior Service Credit | | (2.8) | | | - | | | (1.9) | | | - | | | - |
Total Net Periodic Benefit Expense/(Income) | $ | 8.1 | | $ | 4.0 | | $ | (5.8) | | $ | 2.4 | | $ | 0.3 |
Intercompany Allocations | | N/A | | $ | 3.8 | | $ | 0.8 | | $ | 1.0 | | $ | 0.7 |
Capitalized PBOP Expense/(Income) | $ | 1.4 | | $ | 1.8 | | $ | (2.3) | | $ | 0.8 | | $ | 0.2 |
| | | | | | | | | | | | | | | |
| PBOP | | | |
| | For the Year Ended December 31, 2013 | | | |
(Millions of Dollars) | Eversource | | CL&P | | PSNH | | WMECO | | | |
Service Cost | $ | 16.9 | | $ | 3.4 | | $ | 2.3 | | $ | 0.7 | | | |
Interest Cost | | 47.2 | | | 7.9 | | | 4.0 | | | 1.7 | | | |
Expected Return on Plan Assets | | (55.4) | | | (10.1) | | | (5.2) | | | (2.3) | | | |
Actuarial Loss | | 26.0 | | | 7.4 | | | 3.6 | | | 1.1 | | | |
Prior Service Credit | | (2.1) | | | - | | | - | | | - | | | |
Total Net Periodic Benefit Expense | Total Net Periodic Benefit Expense | $ | 245.4 | | $ | 57.1 | | $ | 64.5 | | $ | 23.6 | | $ | 9.5 | | Total Net Periodic Benefit Expense | $ | 32.6 | | $ | 8.6 | | $ | 4.7 | | $ | 1.2 | | | |
Related Intercompany Allocations | | N/A | | $ | 44.9 | | $ | (8.4) | | $ | 10.5 | | $ | 8.0 | |
Capitalized Pension Expense | $ | 73.2 | | $ | 28.0 | | $ | 28.9 | | $ | 7.3 | | $ | 5.2 | |
Intercompany Allocations | | N/A | | $ | 7.1 | | $ | 1.6 | | $ | 1.3 | | | |
Capitalized PBOP Expense | $ | 8.8 | | $ | 3.9 | | $ | 1.3 | | $ | 0.6 | | | |
| | | | | | | | | | | | | | | | | | | | | | | | | | | |
B.
Share-based compensation awards are recorded using a fair-value-based method at the date of grant. NU,Eversource, CL&P, NSTAR Electric, PSNH and WMECO record compensation expense related to these awards, as applicable, for shares issued or sold to their respective employees and officers, as well as for the allocation of costs associated with shares issued or sold to NU'sEversource's service company employees and officers that support CL&P, NSTAR Electric, PSNH and WMECO.
ESPP Shares - For shares sold under the ESPP, no compensation expense was recorded as the ESPP qualifiesqualified as a non-compensatory plan. The ESPP ended as of February 1, 2016.
An income tax rate of 40 percent is used to estimate the tax effect on total share-based payments determined under the fair value-based method for all awards. The Company generally settles stock option exercises and fully vested RSUs and performance shares with either the issuance of new common shares or the issuance of common shares purchased in the open market.
