Item 1. Business
NORTHEAST UTILITIES
NU, headquartered in Berlin, Connecticut, is a public utility holding company registered with the Federal Energy Regulatory Commission (FERC) under the Public Utility Holding Company Act of 2005 (PUHCA 2005). NU had been registered with the SEC as a public utility holding company under the Public Utility Holding Company Act of 1935 (PUHCA 1935) until that Act was repealed, effective February 8, 2006. NU is engaged primarily in the energy delivery business, providing franchised retail electric service to approximately 1.9 million customers in 419 cities and towns in Connecticut, New Hampshire and western Massachusetts through three of its wholly-owned subsidiaries; The Connecticut Light and Power Company (CL&P), Public Service Company of New Hampshire (PSNH), and Western Massachusetts Electric Company (WMECO), and franchised retail natural gas service to approximately 200,000 residential, commercial and industrial customers in 71 cities and towns in Connecticut, through its wholly-owned indirect subsidiary, Yankee Gas Services Company (Yankee Gas).
NU's wholly-owned subsidiary, NU Enterprises, Inc. (NU Enterprises), is in the process of exiting its competitive energy and related businesses and, as of December 31, 2006, had exited substantially all of these businesses.
For information regarding each of the NU system's reportable segments, see Footnote 16, "Segment Information" contained within NU's 2006 Annual Report to Shareholders, which is incorporated into this Form 10-K by reference.
References in this Form 10-K to the "Company," "NU," "we," "our," and "us" refer to Northeast Utilities and its consolidated subsidiaries.
REGULATED ELECTRIC DISTRIBUTION
NU's subsidiaries, CL&P, PSNH and WMECO, are engaged in the distribution of electricity in Connecticut, New Hampshire and western Massachusetts. The following table shows the sources of 2006 electric franchise retail revenues for CL&P, PSNH and WMECO, collectively, based on categories of customers:
Total
NU Operating
Companies
Residential
48%
Commercial
39%
Industrial
12%
Other
1%
Total
100%
The actual changes in retail kilowatt-hour (kWh) sales for the last two years and the forecasted retail sales growth estimates for the five-year period 2007 through 2011 for CL&P, PSNH and WMECO, collectively, are set forth below:
over
over
Forecast
2007-2011
Compound
Annual Growth
Rate
NU System
-4.0%
2.6%
1.3%
THE CONNECTICUT LIGHT AND POWER COMPANY (CL&P)
Distribution and Sales
CL&P is engaged in the purchase, transmission, delivery and sale of electricity to its residential, commercial and industrial customers. At December 31, 2006, CL&P furnished retail franchise electric service to approximately 1.2 million customers in 149 towns in Connecticut. CL&P sold all of its generating assets in 2000-2001 as required by state electric industry restructuring legislation, and no longer generates any electricity.
The following table shows the sources of 2006 electric franchise retail revenues for CL&P based on categories of customers:
CL&P
Residential
48%
Commercial
40%
Industrial
11%
Other
1%
Total
100%
The actual changes in retail kWh sales for the last two years and the forecasted retail sales growth estimates for the five-year period 2007 through 2011 for CL&P are set forth below:
over
over
Forecast
2007-2011
Compound
Annual Growth
Rate
CL&P
-4.9%
3.0%
1.1%
Rates
CL&P's retail rates are subject to regulation by the Connecticut Department of Public Utility Control (DPUC). CL&P's present general rate structure consists of various rate and service classifications covering residential, commercial and industrial services. Connecticut utilities are entitled under state law to charge rates that are sufficient to allow them an opportunity to cover their reasonable operation and capital costs, to attract needed capital and maintain their financial integrity, while also protecting relevant public interests.
CL&P's retail rates include delivery service, which includes distribution, transmission, conservation, renewables, competitive transition assessment and other charges that are assessed on all customers, and electric generation service, which includes the costs of power supply it purchases for customers that do not choose to be served by a competitive retail supplier.
CL&P has also received regulatory orders allowing it to recover all or substantially all of its prudently incurred "stranded" costs, which are pre-restructuring expenditures incurred, or commitments made for future expenditures, on behalf of customers with the expectation such expenditures would continue to be recoverable in the future through rates. CL&P has financed a significant portion of its stranded costs through the issuance of rate reduction certificates (securitization) and is recovering the costs of securitization through the Competitive Transition Assessment (CTA) component of its rates. As of December 31, 2006, CL&P had fully recovered all stranded costs, except those being recovered through securitization, ongoing independent power producer costs, costs associated with the ongoing decommissioning of the Maine Yankee, Connecticut Yankee and Yankee Rowe nuclear units, and annual decontamination and decommissioning costs payable under federal law.
Under state law, all of CL&P's customers are now able to choose their energy suppliers, with CL&P furnishing service to those customers who do not choose a competitive supplier. Beginning January 1, 2007, this service is termed "Standard Service" for customers that are less than 500 kW of demand and "Supplier of Last Resort Service" for customers who are not eligible for Standard Service.
Most of CL&P's customers have continued to buy their power from CL&P at these rates but CL&P is experiencing accelerating customer migration to alternative suppliers, with the movement concentrated among the larger customers. As of December 31, 2006, approximately 40,000 customers out of 1.2 million, representing approximately 9% of December load, had selected competitive energy supply.
On December 8, 2006, the DPUC approved CL&P's Standard Service rates, effective as of January 1, 2007. The new Standard Service rates reflect an increase of approximately 7.8% and are expected to remain effective until July 1, 2007 when these rates will likely be adjusted to reflect additional supplier bids received for 2007 and updated wholesale transmission costs. Supplier of Last Resort rates will vary, and total bills for those customers increased by 19% on January 1, 2007. On August 4, 2006, CL&P notified the DPUC that it intended to postpone filing a distribution rate case until mid-2007, and the case, when filed, would target new rates to be effective in early 2008.
As a result of Connecticut legislation passed in July 2005, CL&P filed for a transmission adjustment clause on August 1, 2005 with the rate tracking mechanism to be effective on July 6, 2005. On December 20, 2005, the DPUC approved the tracking mechanism, which provides for semi-annual adjustments in January and July of each year. CL&P adjusts its retail transmission rates on a regular basis, thereby recovering all of its retail transmission expenses on a timely basis.
Sources and Availability of Electric Power Supply
As noted above, CL&P owns no generation assets and purchases its energy requirements from a variety of competitive sources through periodic requests for proposals (RFPs). On June 21, 2006, the DPUC approved a plan for CL&P to issue RFPs periodically for periods of up to three years to layer Standard Service full requirements supply contracts in order to mitigate market volatility for its residential and lower use commercial and industrial customers. Additionally, the DPUC approved the issuance of RFPs for Supplier of Last Resort service for larger commercial and industrial customers every six months. Previously, all of CL&P's residential, commercial and industrial requirements, regardless of customer size, were bid together. The DPUC's decision also provides for enhanced access to the RFP materials, bids and other data during and after the RFP process.
In September of 2006, CL&P received bids and awarded contracts for a portion of Standard Service loads for 2007 and 2008. CL&P also received bids and awarded contracts for a portion of Standard Service loads for 2007 through 2009 in October of 2006. CL&P will receive bids in 2007 for Standard Service for remaining 2007 load requirements and for some load requirements in 2008 and 2009. CL&P also received bids and awarded contracts in September of 2006 for its Supplier of Last Resort Service for its larger commercial and industrial customers for January through June of 2007. None of CL&P's suppliers for 2007 and beyond are affiliated with CL&P. CL&P is fully recovering all of the payments it is making to those suppliers through DPUC-approved rates billed to customers, and has financial assurances from each supplier or from a parent or affiliate of each supplier to protect CL&P from loss in the event any of the suppliers encounters financial difficulties.
PUBLIC SERVICE COMPANY OF NEW HAMPSHIRE (PSNH)
Distribution and Sales
PSNH is primarily engaged in the generation, purchase, transmission, delivery and sale of electricity to its residential, commercial and industrial customers. At December 31, 2006, PSNH furnished retail franchise electric service to approximately 487,000 retail customers in 211 cities and towns in New Hampshire. PSNH also owns and operates approximately 1,200 megawatt (MW) of electricity generation assets, with a current claimed capability representing winter rates, of approximately 1,170 MW. Included among these generating assets is a 50 MW wood-burning generating unit in Portsmouth, New Hampshire, which was converted from a coal-burning unit and went into full operation in December, 2006.
The following table shows the sources of 2006 electric franchise retail revenues based on categories of customers:
PSNH
Residential
43%
Commercial
41%
Industrial
15%
Other
1%
Total
100%
The actual changes in retail kWh sales for the last two years and the forecasted retail sales growth estimates for the five-year period 2007 through 2011 for PSNH are set forth below:
over
over
Forecast
2007-2011
Compound
Annual Growth
Rate
PSNH
-1.3%
1.9%
2.3%
Rates
Default Energy Service (ES): PSNH's retail rates are subject to regulation by the New Hampshire Public Utilities Commission (NHPUC). PSNH files for approval of updated ES rates periodically with the NHPUC to ensure timely recovery of its costs. The ES rate recovers PSNH's generation and purchased power costs, including a return on equity (ROE) on PSNH's generation assets. PSNH defers for future recovery or refund any difference between its ES revenues and the actual costs incurred.
On December 2, 2005, the NHPUC issued a decision lowering PSNH's allowed generation ROE to 9.62% retroactive to an effective date of August 1, 2005. This decrease in allowed generation ROE lowers PSNH's net income by approximately $1.5 million annually based on the current level of generation assets.
On January 20, 2006, the NHPUC approved new ES rates of $0.0913 per kWh for the eleven month period February 1, 2006 through December 31, 2006. In its order, the NHPUC also allowed PSNH to implement deferred accounting treatment for the new accounting associated with asset retirement obligations. On June 29, 2006, the NHPUC decreased the ES rate to $0.0818 per kWh based upon updated cost information for the period July 1, 2006 through December 31, 2006.
On September 8, 2006, PSNH filed a petition with the NHPUC requesting a change in its ES rate for the 12-month period January 1, 2007 through December 31, 2007. On December 15, 2006, the NHPUC issued an order approving the filed ES 2007 rate of $0.0859 per kWh. As in previous NHPUC ES rate orders, there is a provision to update the ES rate during the 2007 rate year based upon updated actual and projected cost information.
Delivery Service (DS) Rates: On May 30, 2006, PSNH filed a petition with the NHPUC requesting a permanent increase in its delivery service (DS) rate of approximately $50 million, the approval of a transmission cost tracking mechanism, and a decrease in its stranded cost charge and energy charge to reflect the completed recovery of certain stranded costs and changes in PSNH's actual costs to provide transition energy service. On June 29, 2006, the NHPUC approved a temporary DS rate increase of $24.5 million, effective on July 1, 2006. This temporary rate increase will be reconciled to the allowed permanent rate increase effective back to the July 1, 2006 date. On November 17, 2006, PSNH updated its permanent DS rate filing, increasing the request to $60 million, due primarily to updated rate base projections and higher reliability spending.
On February 26, 2007, PSNH filed a settlement agreement it reached with the NHPUC staff and the Office of Consumer Advocate related to its rate case filing. The settlement agreement includes, among other things, a transmission cost tracking mechanism, effective on July 1, 2006, to be reset annually, and an allowed ROE of 9.67 percent. The allowed generation ROE of 9.62 percent was unaffected. The settlement provides for a $37.7 million estimated annualized increase ($26.5 million for distribution and $11.2 million estimated for transmission) beginning July 1, 2007 in addition to the $24.5 million temporary increase that was effective on July 1, 2006. An additional delivery revenue increase of approximately $3 million would take effect on January 1, 2008, with a final estimated rate decrease of approximately $9 million scheduled for July 1, 2008. The increased revenues will enable PSNH to fund a $10 million annual Reliability Enhancement Program and more accurately fund its Major Storm Cost Reserve. The increased revenues also include approximately $9 million related to additional revenues for the period July 1, 2006 through June 30, 2007 that will be recovered over one year. The NHPUC has scheduled hearings on the proposed settlement beginning in March 2007, with a final decision expected by late spring of 2007.
Stranded Cost Recovery Charge (SCRC): Under New Hampshire law, the SCRC allows PSNH to recover its stranded costs. PSNH has financed a significant portion of its stranded costs through securitization by issuing rate reduction bonds. It recovers the securitization costs, which are known as Part 1 costs, through the SCRC rate.
On an annual basis, PSNH files with the NHPUC a SCRC/ES reconciliation filing for the preceding calendar year. This filing includes the reconciliation of SCRC revenues and costs and the ES revenues and costs. The NHPUC reviews the filing, including a prudence review of the operations within PSNH's generation business segment. On October 25, 2006, PSNH, the NHPUC Staff and the Office of Consumer Advocate filed a settlement agreement with the NHPUC which resolved all outstanding issues associated with PSNH's 2005 reconciliation. After hearings, the NHPUC issued its order approving the settlement agreement. The terms of the settlement had virtually no impact on PSNH's financial position.
In accordance with the "Agreement to Settle PSNH Restructuring", PSNH is required to periodically recalculate its SCRC once its non-securitized (Part 3) costs are fully recovered. PSNH fully recovered its remaining Part 3 costs in June 2006, and an initial reduction of the SCRC from $0.0355 per kWh to $0.0155 per kWh was approved by the NHPUC on June 29, 2006 and effective July 1, 2006.
On September 22, 2006, PSNH filed a petition with the NHPUC requesting a decrease in its SCRC for the period January 1, 2007 through December 31, 2007 based upon market conditions and the NHPUC's decision regarding the duration of certain independent power producer agreements. On November 17, 2006, PSNH filed a revised petition with the NHPUC on the SCRC rate which was approved by the NHPUC on December 15, 2006 and resulted in a reduction in the SCRC rate to $0.0130 per kWh, effective in 2007.
Although PSNH's customers are able to choose competitive energy suppliers, PSNH has experienced almost no customer migration to date.
Coal Procurement Docket: During the second quarter of 2006, the NHPUC opened a docket to review PSNH's coal procurement and coal transportation policies and procedures. PSNH responded to data requests from the NHPUC's outside consultant. While management believes PSNH's coal procurement and transportation policies and procedures are prudent and consistent with industry practice, it is unable to determine the impact, if any, of the NHPUC's review on PSNH's earnings or financial position.
Sources and Availability of Electric Power Supply
During 2006, about 75% of PSNH load was met through owned generation and long-term power supply contracts. The remaining 25% of PSNH's load was met by short-term (less than one year) purchases and spot purchases from the New England Independent System Operator (ISO-NE) wholesale market. For 2007, PSNH expects to meet its load in a similar manner to 2006.
WESTERN MASSACHUSETTS ELECTRIC COMPANY (WMECO)
Distribution and Sales
WMECO is engaged in the purchase, transmission, delivery and sale of electricity to residential, commercial and industrial customers. At December 31, 2006, WMECO furnished retail franchise electric service to approximately 210,000 retail customers in 59 cities and towns in Massachusetts. WMECO sold all of its generating assets in 2000-2001 as required by state electric industry restructuring legislation, and no longer generates any electricity.
The following table shows the sources of 2006 electric franchise retail revenues based on categories of customers:
WMECO
Residential
56%
Commercial
32%
Industrial
11%
Other
1%
Total
100%
The actual changes in retail kWh sales for the last two years and the forecasted retail sales growth estimates for the five-year period 2007 through 2011 for WMECO are set forth below:
over
over
Forecast
2007-2011
Compound
Annual Growth
Rate
WMECO
-4.2%
1.4%
0.1%
Rates
Under state law, all of WMECO's customers are now able to choose their energy suppliers, with WMECO furnishing "basic service" to those customers who do not choose a competitive supplier. Most of WMECO's residential and smaller customers have continued to buy their power from WMECO at these rates. A greater proportion of larger commercial and business customers have opted for a competitive retail supplier. As of December 31, 2006, approximately 11,000 out of nearly 210,000 customers have elected this option, representing about 43% of the energy delivered by WMECO.
WMECO's retail rates are subject to regulation by the Massachusetts Department of Telecommunications and Energy (DTE). WMECO's present general rate structure 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 cover their reasonable operation and capital costs, to attract needed capital and maintain their financial integrity, while also protecting relevant public interests.
WMECO collects its transmission costs through a transmission adjustment clause. The DTE approved the tracking mechanism in January 2002, which provides for annual adjustments, thereby allowing WMECO to recover all of its retail transmission expenses on a timely basis.
WMECO has also received regulatory orders allowing it to recover all or substantially all of its prudently incurred "stranded" costs. WMECO has financed a portion of its stranded costs through securitization by issuing rate reduction certificates and is recovering the costs of securitization through rates.
Rate Case Settlement: On December 14, 2006, the DTE approved a rate settlement agreement (the Settlement) between WMECO, the Attorney General of the Commonwealth of Massachusetts, the Low-income Energy Affordability Network, and the Associated Industries of Massachusetts which was filed with the DTE in lieu of a base rate proceeding. The Settlement provides a $1.0 million increase in WMECO's distribution rates effective January 1, 2007 and an additional increase in distribution rate of $3.0 million effective January 1, 2008. Also included in the Settlement are cost tracking mechanisms for pension and other postretirement benefit costs, uncollectible amounts related to energy costs, and recovery of certain capital improvements and related expenses needed for system reliability. The Settlement includes an earnings sharing mechanism that will equally share with customers any earnings in excess of an actual ROE of 12% and any shortfall below an actual ROE of 8% during the two-year settlement period. The determination of any excess or shortfall would be done annually, with any such excess being recorded as a regulatory liability and any such shortfall being recorded as a regulatory asset.
Annual Rate Change Filing: On November 30, 2006, WMECO made its 2006 annual rate change filing. Because the timing of this filing coincided with WMECO's rate case settlement decision described above, the DTE combined WMECO's annual rate change filing with its rate case settlement compliance filing. The combined filing implements the $1 million distribution rate increase and associated cost tracking mechanisms as allowed under its rate case settlement agreement and reflects rate increases for 2007 default service supply. On average, total rates increased 17.8 %. On December 29, 2006, the DTE approved the rates effective January 1, 2007.
Sources and Availability of Electric Power Supply
As noted above, WMECO owns no generation assets and purchases its energy requirements from a variety of competitive sources through periodic RFPs. For basic service power supply, WMECO makes periodic market solicitations consistent with DTE regulations. During 2006, WMECO entered into power purchase agreements to meet its entire basic service supply obligation, other than to its largest customers, for the period January 1, 2007 through June 30, 2007 and for 50% of its obligation, other than to these large customers, for the second-half of 2007. WMECO has entered into short-term power purchase agreements to meet its entire basic service supply obligation for large customers for the period January 1, 2007 through March 2007 and April 1 through June 30, 2007. An RFP will be issued quarterly in 2007 for the remainder of the obligation for large customers and semi-annually for non-large customers. For 2006, WMECO entered into agreements for either three or twelve-month periods.
LICAP AND FCM DEVELOPMENT
On March 6, 2006, ISO-NE and a broad cross-section of critical stakeholders from around the region, including CL&P and PSNH, filed a comprehensive settlement agreement at the FERC proposing a forward capacity market (FCM) in place of the previously proposed locational installed capacity (LICAP), an administratively determined electric generation capacity pricing mechanism. The settlement agreement provided for a fixed level of compensation to generators from December 1, 2006 through May 31, 2010 without regard to location in New England, and annual forward capacity auctions, beginning in 2008, for the 1-year period ending on May 31, 2011, and annually thereafter. According to preliminary estimates, FCM would require our utility subsidiaries to pay approximately the following amounts from December 1, 2006 through December 31, 2009: CL&P - $470 million; PSNH - $80 million; and WMECO - $100 million. CL&P, PSNH and WMECO expect to recover these costs from their ratepayers. On June 16, 2006, the FERC accepted the settlement agreement. Several parties sought rehearing of this issue by the FERC, which was denied on October 31, 2006. On December 1, 2006 the Settlement Agreement was implemented and the payment of fixed compensation to generators began.
For more information regarding CL&P, WMECO and PSNH state regulatory matters, see "Utility Group Regulatory Issues and Rate Matters" under Item 7, "Management's Discussion and Analysis of Financial Condition and Results of Operations" contained within NU's and CL&P's Annual Reports to Shareholders, which is incorporated into this Form 10-K by reference.
REGULATED ELECTRIC TRANSMISSION
General
CL&P, PSNH and WMECO and most other New England utilities, generation owners and marketers are parties to a series of agreements that provide for coordinated planning and operation of the region's generation and transmission facilities and the market rules by which these parties participate in the wholesale markets and acquire transmission services. Under these arrangements, ISO New England Inc. (ISO-NE), a non-profit corporation whose board of directors and staff are independent from all market participants, has served as the Regional Transmission Operator (RTO) since February 1, 2005. ISO-NE ensures the reliability of the New England transmission system, administers the independent system operator tariff, subject to FERC approval, and oversees the efficient and competitive functioning of the regional wholesale power market.
Rates
Most of NU's wholesale transmission revenues are collected through a combination of ISO-NE FERC Electric Tariff No. 3, Open Access Transmission Tariff (RNS), and Schedule 21 - NU (LNS) to that tariff. The RNS (or regional network service) tariff is administered by ISO-NE and is billed to all New England transmission users. RNS recovers the revenue requirements associated with facilities that are deemed to provide a regional benefit, or pool transmission facilities. The RNS rate is reset on June 1st of each year and NU collects approximately 75 percent of its wholesale transmission revenues under its RNS tariff. NU's LNS (or local network service) rate is reset on January 1st and June 1st of each year and provides for a true-up to actual costs, which ensures that NU's transmission business recovers its total transmission revenue requirements, including the allowed ROE.
FERC ROE Decision
On October 31, 2006, the FERC issued its decision on the specific ROE and incentives for New England transmission owners. The FERC set the base ROE (before incentives) at 10.2% for the historical locked-in period of February 1, 2005 (when the New England RTO was activated) to October 31, 2006. Effective November 1, 2006, the FERC also added a 70 basis point adjustment to reflect upward pressure on the 10-year treasury rate, bringing the going forward base ROE to 10.9%. In addition, the FERC approved a 50 basis point adder for joining an RTO and approved a 100 basis point adder for all new transmission investment where the projects have been identified as necessary by the ISO-NE regional planning process. Both ROE adders for certain projects are retroactive to February 1, 2005.
On a going forward basis, our transmission capital program is largely comprised of regional infrastructure that is included within the regional planning process. Over 90% of our projected $2.5 billion capital program for 2007 through 2011 is expected to be in this category, and therefore is expected to earn at the RNS rate's 12.4% ROE.
The following is a summary of the ROEs for the applicable periods and tariffs:
LNS
RNS
New ISO-NE Approved
RTO - February 1, 2005 to October 31, 2006
10.2% (base)
10.7% (10.2% plus 0.5% for RTO membership)
11.7% (10.7% plus 1.0% adder)
RTO - November 1, 2006 - forward
10.9% (10.2% base plus 0.7% adjustment)
11.4% (10.9% plus 0.5% for RTO membership)
12.4% (11.4% plus 1.0% adder)
On November 30, 2006, the New England Transmission Owners jointly filed a rehearing request for an additional 30 basis points for the base ROE to correct what appears to be an error in the FERC's base ROE calculation. Additionally, several New England Public Utilities Commissions, Consumer Counsels and Municipals have filed a rehearing request challenging the 70 basis point Treasury rate adder and the 100 basis point adder for new regional transmission investment.
On December 29, 2006, FERC issued a tolling order stating that it accepted the various rehearing requests and intends to act on them. This order allows the regional transmission owners to collect tariffs per the ROE order subject to refund. The order did not include an action date and until FERC takes some action on the rehearing requests, parties cannot bring an appeal to court.
Other Rate Matters
Effective on February 1, 2006, NU began including 50% of construction work in progress (CWIP) for its four major southwest Connecticut transmission projects in its LNS rate for transmission service. The new rates allow NU to collect 50% of the construction financing expenses while these projects are under construction.
On July 20, 2006, the FERC issued final rules promoting transmission investment through pricing reform that included up to 100% of CWIP in rate base, accelerated book depreciation, and higher ROEs for belonging to an RTO, among others. The final rule identifies specific incentives the FERC will allow when justified in the context of specific rate applications. The burden remains on the applicant to illustrate through its filing that the incentives requested are just and reasonable and the project involved increases reliability or decreases congestion costs. The FERC reaffirmed these incentives in its order on rehearing issued on December 22, 2006.
On July 28, 2006, the FERC approved CL&P's proposal to allocate costs associated with the Bethel to Norwalk transmission project that are determined to be localized costs to all customers in Connecticut, as all of Connecticut will benefit from the reduction in congestion charges associated with the project. There are three load serving entities in Connecticut: CL&P, United Illuminating (UI) and the Connecticut Municipal Electrical Energy Cooperative. These customers would pay their allocated shares of the localized costs on a projected basis commencing on June 1, 2006, subject to true-up based on actual costs. On December 26, 2006, FERC rejected a request by UI for rehearing of this decision. On February 23, 2007, UI appealed the FERC's orders to the D.C. Circuit Court of Appeals.
On September 22, 2006, ISO-NE issued its determination letter with regard to CL&P's February 3, 2006 revised transmission cost allocation application for the Bethel to Norwalk transmission project. The decision found that $239.8 million of the total estimated cost of $357.2 million qualifies as pool-supported pool transmission facilities costs, indicating $117.4 million of total estimated costs that are localized. CL&P has decided not to challenge ISO-NE's cost allocation decision.
Transmission Projects
Our capital expenditures, including cost of removal, the allowance for funds used in construction, and the capitalized portion of pension expense or income, on transmission projects in 2006 totaled approximately $465.5 million, most of it at CL&P. For 2006, CL&P's transmission capital expenditures totaled $415.6 million, PSNH's transmission capital expenditures totaled $36.1 million and WMECO's transmission capital expenditures totaled $13.0 million.
CL&P's transmission capital expenditures were primarily on four major transmission projects in southwest Connecticut: 1) the completed Bethel to Norwalk project, 2) a 69-mile Middletown to Norwalk 115kV/345kV transmission project, 3) a related two-cable 115 kV underground project between Norwalk and Stamford, Connecticut (Glenbrook Cables), and 4) the replacement of the existing 138 kV cable between Connecticut and Long Island. Each of these projects has received approval from the Connecticut Siting Council (CSC) and ISO-NE.
The Bethel to Norwalk project, a 21-mile, 345 kV project between Bethel, Connecticut and Norwalk, Connecticut, was completed in the fourth quarter of 2006 at a cost of approximately $340 million, approximately $10 million below budget, and was fully energized and placed into service on October 12, 2006.
CL&P has commenced site work on the 69-mile 345 kV transmission line from Middletown to Norwalk, to be jointly built by UI and CL&P. The project still requires some CSC review of certain detailed construction plans. Although this project is currently expected to be completed by the end of 2009, opportunities to optimize schedule performance may result in an earlier completion date. This project is currently 16 percent complete and CL&P's portion of this project is estimated to cost approximately $1.05 billion. At December 31, 2006, CL&P has capitalized $186.4 million associated with this project.
Construction has begun on the Glenbrook Cables Project, two 9-mile 115 kV underground transmission lines between Norwalk and Stamford, which is expected to cost approximately $183 million. This project is currently approximately 20% complete and on schedule for a December 2008 in-service date. As of December 31, 2006, CL&P had capitalized $40.9 million associated with this project.
Design and engineering work on the CL&P and the Long Island Power Authority (LIPA) plans to replace a 138 kV undersea electric transmission line between Norwalk, Connecticut and Northport - Long Island, New York, is complete, and cable manufacturing commenced in mid-January, 2007. CL&P and LIPA each own approximately 50% of the line. CL&P's portion of the project is estimated to cost $72 million. Final permits are expected by mid-2007 with marine construction activities commencing in October, 2007. The projected in service date remains in 2008. Through December 31, 2006, CL&P had capitalized $16.9 million associated with this project.
In December 2006, CL&P completed construction and commenced commercial operation of a new substation in Killingly, Connecticut which will improve CL&P's 345 kV and 115 kV transmission systems in northeast Connecticut. As of December 31, 2006 CL&P had capitalized $25.9 million associated with this project, and estimates the final cost to be approximately $29 million, slightly below the budget of $32 million.
As part of a larger regional system plan, NU, ISO-NE and National Grid have begun planning upgrades to the transmission system connecting Massachusetts, Rhode Island and Connecticut in a comprehensive study called the Southern New England Transmission Reinforcement (SNETR) Project. That study has led to the identification of three interdependent NU projects that work together to address the region's transmission needs -- the Greater Springfield Reliability Project, the Central Connecticut Reliability Project, and the Interstate Reliability Project. Together, these three projects, along with National Grid's Rhode Island Reliability project, are referred to as the New England East-West Solution (NEEWS). NU and National Grid have not yet completed a detailed estimate of the total cost for these upgrades, but NU estimates that its share of these projects may range from $1.1 billion to $1.4 billion of which approximately $710 million is included in its $2.5 billion 2007 through 2011 capital budget. NU and National Grid have entered into a formal agreement to plan and permit these projects.
We project total transmission capital expenditures for the period 2007-2011 to be approximately $2.5 billion. Of that amount, we project that CL&P will spend approximately $2 billion, PSNH will spend approximately $246 million, and WMECO will spend approximately $200 million.
Transmission Rate Base
Under NU's FERC-approved tariffs, transmission projects enter rate base once they enter commercial operation. Additionally, 50 percent of NU's capital expenditures on its four major transmission projects in southwest Connecticut enter rate base during the construction period with the remainder entering rate base once the projects are complete. At the end of 2006, NU's estimated transmission rate base was $1.1 billion, including approximately $840 million at CL&P, $140 million at PSNH and $75 million at WMECO. NU's total transmission rate base was approximately $600 million at the end of 2005. The company forecasts that its total transmission rate base will grow to approximately $1.4 billion at the end of 2007, $1.9 billion at the end of 2008, $2.6 billion at the end of 2009, $2.8 billion at the end of 2010, and $3 billion at the end of 2011. This increase in transmission rate base is driven by the need to improve the capacity and reliability of NU's regulated transmission system.
A summary of projected year end transmission rate base by Utility Group company is as follows (millions of dollars):
Company
CL&P
$1,173
$1,512
$2,117
$2,218
$2,461
PSNH
WMECO
Totals
$1,428
$1,920
$2,572
$2,761
$3,025
For more information regarding Regulated Transmission matters, see "Transmission Rate Matters and FERC Regulatory Issues" under Item 7, "Management's Discussion and Analysis of Financial Condition and Results of Operations" contained within NU's and CL&P's Annual Reports to Shareholders, which is incorporated into this Form 10-K by reference.
REGULATED GAS OPERATIONS
Yankee Energy System, Inc. (Yankee) is the holding company of Yankee Gas and two active non-utility subsidiaries, NorConn Properties, Inc., which holds certain minor properties and facilities of Yankee and its subsidiaries, and Yankee Energy Financial Services Company, which was in the business of providing Yankee Gas customers and other energy end-users with financing primarily for energy equipment installations, but which is in the process of winding up its business operations.
Yankee Gas operates the largest natural gas distribution system in Connecticut as measured by number of customers (approximately 200,000), and size of service territory (2,088 sq. miles). Total throughput (sales and transportation) for 2006 was 45.2 BcF. Yankee Gas provides firm gas sales service to customers who require a continuous gas supply throughout the year, such as residential customers who rely on gas for their heating, hot water and cooking needs. Yankee Gas also offers firm transportation service to its commercial and industrial customers as well as interruptible transportation and interruptible gas sales service to those certain commercial and industrial customers that have the capability to switch from natural gas to an alternative fuel on short notice. Yankee Gas can interrupt service to these customers during peak demand periods or at any other time to maintain distribution system integrity. Yankee Gas offers firm and interruptible transportation services to customers who purchase gas from sources other than Yankee Gas. In addition, Yankee Gas performs gas sales, gas exchanges and capacity releases to other market participants to reduce its overall gas expense.
Yankee Gas earned $11.9 million on total gas operating revenues of approximately $454 million for the full-year 2006, compared with earnings of $17.3 million for full-year 2005. Yankee Gas earnings were lower due primarily to an 11.2 percent decline in firm natural gas sales in 2006, compared with 2005, largely the result of milder weather in 2006. The following table shows the sources of 2006 total gas operating revenues:
Yankee Gas
Residential
47%
Commercial
28%
Industrial
23%
Other
2%
Total
100%
For more information regarding Yankee Gas' financial results, see Item 7, "Management's Discussion and Analysis of Financial Condition and Results of Operations," and Item 8, "Financial Statements and Supplementary Data," which includes Note 16, "Segment Information," within the notes to the consolidated financial statements, contained within NU's Annual Report to Shareholders, which is incorporated into this Form 10-K by reference.
Although Yankee Gas is not subject to the FERC's jurisdiction, the FERC does have limited oversight over certain intrastate gas transportation that Yankee Gas provides. In addition, the FERC regulates the interstate pipelines serving Yankee Gas' service territory.
Yankee Gas is subject to regulation by the DPUC, which, among other things, has jurisdiction over rates, accounting procedures, certain dispositions of property and plant, mergers and consolidations, issuances of securities, standards of service, management efficiency and construction and operation of distribution, production and storage facilities.
On December 29, 2006, Yankee Gas filed a request with the DPUC for a rate increase of approximately $67.8 million effective July 1, 2007. The request proposes to recover the costs of constructing the liquefied natural gas (LNG) storage facility (described below) and the increased costs of providing distribution and delivery service. Yankee Gas expects that this increase will be offset by savings in commodity and pipeline-related savings for a net revenue increase of approximately $37.2 million or 8.4% above current rates.
On September 9, 2005, the DPUC issued a draft decision regarding Yankee Gas Purchased Gas Adjustment (PGA) clause charges for the period of September 1, 2003 through August 31, 2004. The draft decision disallowed approximately $9 million in previously recovered PGA revenues associated with two separate Yankee Gas unbilled sales and revenue adjustments. At the request of Yankee Gas, the DPUC reopened the PGA hearings on September 20, 2005 and requested that Yankee Gas file supplemental information regarding the two adjustments. Yankee Gas complied with this request. The DPUC issued a new decision on April 20, 2006 requiring an audit of Yankee Gas' previously recovered PGA costs and deferred any conclusion on the approximately $9 million of previously recovered revenues until the completion of the audit. In a recent draft decision regarding Yankee Gas PGA charges for the period September 1, 2004 through August 31, 2005, an additional $2 million related to previously recovered revenues was also identified, bringing the total maximum amount at issue with regard to PGA clause charges under audit to $11 million.
The DPUC has hired a consulting firm which has begun an audit of Yankee Gas' previously recovered PGA costs. Yankee Gas expects that the audit will be completed in the first half of 2007. Management believes the unbilled sales and revenue adjustments and resultant charges to customers through the PGA clause for both periods were appropriate. Based on the facts of the case and the supplemental
information provided to the DPUC, Yankee Gas believes the appropriateness of the PGA charges to customers for the time period under review will be approved, and has not reserved for any loss.
Yankee Gas is constructing an LNG facility in Waterbury, Connecticut capable of storing the equivalent of 1.2 billion cubic feet of natural gas. It is expected to be put into service by mid-2007 in time for the 2007-2008 heating season at a total cost of approximately $108 million. At December 31, 2006, the project was approximately 89% complete and Yankee Gas had capitalized $95.3 million related to this project. In 2006, Yankee Gas also capitalized $41 million related to reliability improvements, new customer connections and other initiatives.
CONSTRUCTION AND CAPITAL IMPROVEMENT PROGRAM
Our capital expenditures for 2006, including cost of removal, allowance for funds used during construction and the capitalized portion of pension expense or income, totaled approximately $946 million, of which approximately $908 million was expended by CL&P, PSNH, WMECO and Yankee Gas. Approximately $466 million was spent by CL&P, PSNH and WMECO on transmission projects. The capital expenditures of these companies in 2007 are estimated to total approximately $1.2 billion. Of such total amount, approximately $860 million is expected to be expended by CL&P, $211 million by PSNH, $50 million by WMECO and $62 million by Yankee Gas. This construction program data includes all anticipated costs necessary for committed projects and for those reasonably expected to become committed projects in 2007, regardless of whether the need for the project arises from environmental compliance, reliability requirements or other causes. The construction program's main focus is maintaining, upgrading and expanding the existing electric transmission and distribution system and natural gas distribution system, including the construction of Yankee Gas' LNG facility. We expect to evaluate our needs beyond 2007 in light of future developments, such as restructuring, industry consolidation, performance and other events. If current plans are implemented on schedule, we would likely require additional external financing at the subsidiary level to construct these projects.
In 2006, CL&P's transmission capital expenditures totaled $416 million. In 2007, CL&P projects transmission capital expenditures of approximately $590 million. During the period 2007 through 2011, CL&P plans to invest approximately $2 billion in transmission projects, including $860 million to construct the Middletown to Norwalk transmission line, and $142 million for the Glenbrook Cables Project. Approximately $55 million will be invested during this period to pay for CL&P's share of replacing the 138 kV transmission line beneath Long Island Sound jointly owned by CL&P and LIPA. If all of the transmission projects are built as proposed, our investment in electric transmission would increase from approximately $1.1 billion at the end of 2006 to nearly $3.0 billion by the end of 2011.
In addition to its transmission projects, CL&P plans to make distribution capital expenditures intended to improve the reliability of its distribution system and to meet growth requirements on the distribution system. In 2006, CL&P's distribution capital expenditures totaled $210.3 million. In 2007, as a result of significant peak load growth in recent years, CL&P projects increasing distribution capital expenditures to approximately $270 million. CL&P plans to spend approximately $1.4 billion on distribution projects during the period 2007-2011.
In December, 2006, PSNH completed final testing and began commercial operation of its new wood-burning generation plant (Northern Wood Power Project), which replaced one of the three 50 MW boiler units at the coal-fired Schiller Station. As of December 31, 2006, PSNH had capitalized approximately $74 million related to this project.
In 2006, PSNH's transmission capital expenditures totaled $36 million and its distribution capital expenditures totaled $77.5 million. PSNH's generation capital expenditures totaled $32.1 million in 2006. In 2007, PSNH's transmission capital expenditures are projected to be approximately $83 million, its distribution capital expenditures are expected to be approximately $91 million and its generation capital expenditures approximately $37 million. The increase in distribution capital expenditures is due to additional reliability spending. The decline in generation capital expenditures is due to the completion in 2006 of the Northern Wood Power Project. During the period 2007-2011, PSNH plans to spend approximately $246 million on transmission projects and approximately $650 million on distribution and generation projects.
In 2006, WMECO's transmission capital expenditures totaled $13 million and its distribution capital expenditures totaled $30 million. In 2007, WMECO projects transmission capital expenditures to be approximately $16 million and its distribution capital expenditures to be approximately $34 million. During the period 2007-2011, WMECO plans on spending approximately $200 million on transmission projects and approximately $159 million on distribution projects.
In 2006, Yankee Gas' capital expenditures totaled $89.9 million, approximately 54% of which was for the construction of the LNG facility. The facility is expected to be put into service in mid-2007 in time for the 2007/ 2008 heating season at a cost of approximately $108 million. In 2006, Yankee Gas also spent $20.3 million on its reliability improvement program, $13.8 million on connecting new customers, and $6.9 million on other initiatives, including meters and information technology systems. In 2007, Yankee Gas projects total capital expenditures of approximately $62 million. The decline from 2006 is attributable to the expected completion of the LNG facility. During the period 2007-2011, Yankee Gas plans on making approximately $227 million of capital expenditures.
For more information regarding NU and its subsidiaries' construction and capital improvement program, see "Business Development and Capital Expenditures" under Item 7, "Management's Discussion and Analysis of Financial Condition and Results of Operations" contained within NU's and CL&P's Annual Reports to Shareholders, which is incorporated into this Form 10-K by reference.
STATUS OF EXIT FROM COMPETITIVE ENERGY BUSINESSES
Since we announced in March 2005 that we intended to exit from the wholesale energy marketing and energy services businesses of our subsidiary NU Enterprises, and our announcement in November 2005 that we would exit from the retail energy marketing and competitive generation businesses of NU Enterprises as well, we have made substantial progress towards our goal of exiting such businesses and focusing exclusively on our regulated business. An overview of this progress follows:
Competitive Generation. On November 1, 2006, we closed on the sale of NU Enterprises' 100% ownership in Northeast Generation Company (NGC), and of Holyoke Water Power Company's (HWP) 146 MW Mt. Tom coal-fired plant for an aggregate amount of $1.34 billion, which included the assumption of $320 million of NGC debt. We now own no competitive or merchant generation assets.
Wholesale Marketing Business: In 2005, Select Energy, Inc. (Select Energy) completed the divestiture of its New England wholesale sales contracts. Select Energy continues to serve its remaining PJM and New York wholesale sales contract obligations. As of December 31, 2006, the remaining sales obligations were approximately 7.5 million megawatt-hours (MWh), down from approximately 22 million MWh as of March of 2005 when we announced we were exiting the wholesale marketing business. Select Energy has also taken steps to reduce the volatility of these obligations by hedging a portion of them.
Retail Marketing Business: On June 1, 2006, Select Energy sold its retail marketing business, including its retail sales obligations and related supply contracts. Under the terms of the agreement, Select Energy paid the buyer approximately $11.5 million at closing and approximately $12.9 million in December of 2006, and will pay approximately $15 million by the end of 2007.
Energy Services Businesses: Woods Network, Inc. and the New Hampshire operations of Select Energy Contracting, Inc. (SECI), including Reeds Ferry, Inc., were sold in November of 2005. In January of 2006, the Massachusetts service division of SECI was sold. In April of 2006, NU Enterprises sold the services division of NGS Acquisition, Inc. (formerly Woods Electrical Co., Inc.), and in May of 2006, NU Enterprises sold its 100% ownership of Select Energy Services, Inc. (SESI).
Competitive Energy Business Assets Retained: Assets that have not yet either been sold or placed under contract to be sold by NU Enterprises are as follows:
-
Select Energy's wholesale contracts (five PJM sales contracts, four of which expire in 2007 and one of which expires in 2008, one NYMPA sales contract that expires in 2013 and three power purchase contracts, two of which expire in 2007);
-
Remaining assets, liabilities and contingencies associated with previously divested businesses or companies, including a contract to complete a cogeneration facility;
-
Contracts associated with the wind-down of the remaining operations of Northeast Generation Services Company, SECI and NGS Acquisition, Inc., (formerly Woods Electrical Co., Inc.); and
-
E.S. Boulos Company.
In addition, provisions of the SESI purchase and sale agreement require NU to indemnify the buyer for estimated costs to complete or modify specific construction projects above specified levels. Provisions of the purchase and sale agreements related to the other divested businesses contain indemnifications and/or guarantees by NU. See Note 8H "Guarantees and Indemnifications," for further information regarding these guarantees and indemnifications.
For more information regarding the exit of the competitive businesses, see "NU Enterprises Exit" under Item 7, "Management's Discussion and Analysis of Financial Condition and Results of Operations" contained within NU's Annual Report to Shareholders, which is incorporated into this Form 10-K by reference.
FINANCING
NU paid common dividends totaling $112.7 million in 2006, compared to $87.6 million paid in 2005, reflecting an increase in the number of outstanding common shares of NU as a result of its share offering in December 2005, and increases in the quarterly dividend rate that were effective in the third quarters of 2005 and 2006.
Total debt of NU and its subsidiaries, including short-term debt, capitalized lease obligations and prior spent nuclear fuel liabilities, but not including rate reduction bonds or certificates, was approximately $3.0 billion as of December 31, 2006.
At December 31, 2006, NU maintained a parent company revolving credit facility of $500 million, and CL&P, PSNH, WMECO and Yankee Gas maintained a joint revolving credit facility of $400 million, both of which expire on November 6, 2010. At December 31, 2006, NU had no borrowings on that credit line, but approximately $67.5 million of letters of credit issued in connection with Select Energy's business were secured by that line. Neither CL&P, PSNH, WMECO nor Yankee Gas had any borrowings outstanding under their credit facility at December 31, 2006.
In addition, CL&P has access to funds under an arrangement with its subsidiary, CL&P Receivables Corporation (CRC). CRC has an agreement with CL&P to purchase up to $100 million of an undivided interest in CL&P's accounts receivables and unbilled revenues, which CRC sells to a highly rated financial institution on a limited recourse basis. CL&P's continuing involvement with the receivables that are sold to CRC and the financial institution is limited to the servicing of those receivables. At December 31, 2006, CL&P had no borrowings under this facility.
Financial Covenants in Credit Facilities
Under their revolving credit facility agreement, CL&P, WMECO, PSNH and Yankee Gas must each maintain a ratio of debt to total capitalization of no more than 65%. At December 31, 2006, CL&P, WMECO, PSNH, and Yankee Gas ratios were, and are expected to, remain in compliance with these ratios.
Under its revolving credit agreement, NU must maintain a ratio of debt to total capitalization of no more 67.5% through March 31, 2006 and 65.0% thereafter. At December 31, 2006, NU was, and expects to, remain in compliance with this ratio.
For more information regarding NU and its subsidiaries' financing, see "Notes to Consolidated Financial Statements" in NU's financial statements, the footnotes related to long-term debt, short-term debt, leases and the sale of accounts receivables, as applicable, in the notes to NU's, CL&P's, PSNH's, and WMECO's financial statements, and "Liquidity" under Item 7, "Management's Discussion and Analysis of Financial Condition and Results of Operations" contained within NU's and CL&P's Annual Reports to Shareholders, which are incorporated into this Form 10-K by reference.
STATUS OF NUCLEAR DECOMMISSIONING
General
CL&P, PSNH, WMECO and other New England electric utilities are the stockholders in three regional nuclear companies (the Yankee Companies). Each Yankee Company owns a single nuclear generating unit -the Connecticut Yankee nuclear unit (CY), the Maine Yankee nuclear unit (MY), and the Yankee Rowe nuclear unit (YA). YA, CY and MY have been permanently removed from service and are being decontaminated and decommissioned. The stockholder-sponsors of each Yankee Company are responsible for proportional shares of the operating and decommissioning costs of each respective Yankee Company. CL&P's, PSNH's and WMECO's stock ownership percentages in the Yankee Companies are set forth below:
CL&P
PSNH
WMECO
NU
System
Connecticut Yankee Atomic Power Company (CYAPC)
34.5%
5.0%
9.5%
49.0%
Maine Yankee Atomic Power Company (MYAPC)
12.0%
5.0%
3.0%
20.0%
Yankee Atomic Electric Company (YAEC)
24.5%
7.0%
7.0%
38.5%
The Nuclear Regulatory Commission (NRC) has broad jurisdiction over the decommissioning activities at the Yankee Companies.
Decommissioning
CL&P, PSNH and WMECO each have significant decommissioning and plant closure cost obligations to CYAPC, YAEC and MYAPC. Each Yankee Company collects these costs through wholesale FERC-approved rates charged under power purchase agreements with CL&P, PSNH and WMECO. These companies in turn pass these costs on to their customers through state regulatory commission-approved retail rates.
On June 10, 2004, the DPUC and the Connecticut Office of Consumer Counsel (OCC) filed a petition with the FERC seeking a declaratory order that CYAPC be allowed to recover all decommissioning costs from its wholesale purchasers, including CL&P, PSNH and WMECO, but that such purchasers should not be allowed to recover in their retail rates any costs that the FERC might determine to
have been imprudently incurred. The FERC rejected the DPUC's and OCC's petition, whereupon the DPUC filed an appeal of the FERC's decision with the D.C. Circuit Court of Appeals (Court of Appeals).
On November 16, 2006, FERC approved a settlement agreement between CYAPC, the DPUC, the OCC and Maine state regulators. The settlement agreement, which provides a revised decommissioning estimate of $642.9 million (in 2006 dollars), taking into account actual spending through 2005 and the current estimate for completing decommissioning and long-term storage of spent fuel, a gross domestic product escalator of 2.5% for costs incurred after 2006, and a 10% contingency factor for all decommissioning cost, disposes of the pending litigation at the FERC and the Court of Appeals, among other issues.
Spent Nuclear Fuel Litigation
YAEC, MYAPC, and CYAPC commenced litigation in 1998 against the United States Department of Energy (DOE) charging that the federal government breached contracts it entered into with each Yankee Company in 1983 under the Nuclear Waste Policy Act of 1982 to begin removing spent nuclear fuel from the respective nuclear plants no later than January 31, 1998 in return for payments by each Yankee Company into the Nuclear Waste Fund. The funds for those payments were collected from regional electric customers. The Yankee Companies initially claimed damages for incremental spent nuclear fuel storage, security, construction and other costs through 2010.
In a ruling released on October 4, 2006, the Court of Federal Claims held that the DOE was liable for damages to CYAPC for $34.2 million through 2001, YAEC for $32.9 million through 2001 and MYAPC for $75.8 million through 2002. The Yankee Companies had claimed actual damages for the same period as follows: CYAPC: $37.7 million; YAEC: $60.8 million; and MYAPC: $78.1 million. The Yankee Companies believe they will have the opportunity in future lawsuits to seek recovery of actual damages incurred in the years following 2001-2002. The refund to CL&P, PSNH and WMECO of any damages that may be recovered from the DOE is established in the Yankee Companies' FERC-approved rate settlement agreement, although implementation will be subject to final determination of FERC. CL&P, PSNH and WMECO expect to pass any recovery onto its customers therefore no earnings are expected to result. The DOE appealed this decision in December 2006.
For more information regarding Nuclear matters, see "Notes to Consolidated Financial Statements" in NU's financial statements, the footnotes related to Spent Nuclear Fuel Disposal Costs, in the notes to NU's, CL&P's, PSNH's, and WMECO's financial statements and "Deferred Contractual Obligations" under Item 7, "Management's Discussion and Analysis of Financial Condition and Results of Operations" contained within NU's and CL&P's Annual Reports to Shareholders, which is incorporated into this Form 10-K by reference.
OTHER REGULATORY AND ENVIRONMENTAL MATTERS
General
We are regulated in virtually all aspects of our business by various federal and state agencies, including the SEC, the FERC, the NRC 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 DPUC having jurisdiction over CL&P and Yankee Gas, the NHPUC having jurisdiction over PSNH, and the DTE having jurisdiction over WMECO. Pursuant to the Energy Policy Act of 2005 (EPAct), PUHCA 1935, which provided the SEC with jurisdiction over various aspects of our operations, was repealed on February 8, 2006, and jurisdiction over a number of areas covered by PUHCA 1935 was assumed by the FERC under the PUHCA 2005 provisions of EPAct.
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, our 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. Compliance with increasingly stringent environmental laws and regulations, particularly air and water pollution control requirements, may limit operations or require substantial investments in new equipment at existing facilities.
Water Quality Requirements
The federal 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 United States Environmental Protection Agency or state environmental agency specifying the allowable quantity and characteristics of its effluent. States may also require additional permits for discharges into state waters. Our facilities are in the process of obtaining or renewing all required NPDES or state discharge permits in effect. Compliance with NPDES and state discharge permits has necessitated substantial expenditures and may require further significant expenditures, which are difficult to estimate, because of additional requirements or restrictions that could be imposed in the future, including requirements related to Sections 316(a) and 316(b) of the Clean Water Act for facilities owned by PSNH.
Air Quality Requirements
The Clean Air Act Amendments of 1990 (CAAA), as well as state laws in Connecticut, Massachusetts and New Hampshire, impose stringent requirements on emissions of sulfur dioxide (SO2) and nitrogen oxide (NOX) for the purpose of controlling acid rain and ground level ozone. In addition, the CAAA address the control of toxic air pollutants. Installation of continuous emissions monitors and expanded permitting provisions also are included.
In New Hampshire, the Multiple Pollutant Reduction Program was signed into law in May 2002. Under this law, NOX, SO2 and Carbon Dioxide (CO2) emission are capped for current compliance beginning in 2007. A law was passed during the 2006 legislative session requiring reductions in emissions of mercury from PSNH's coal-fired plants. The law requires PSNH to install a wet flue gas desulphurization system, known as "scrubber" technology, to reduce mercury emissions (with the co-benefit of reductions in SO2 emissions as well) at Merrimack Station no later than July 1, 2013. PSNH currently anticipates the cost to comply with this law to be $250 million, but this amount has the potential to increase materially as the project is undertaken, primarily as a result of changes in commodity prices and labor costs.
The Regional Greenhouse Gas Initiative (RGGI) is a cooperative effort by nine northeastern states, including New Hampshire and Connecticut, to develop a regional program for stabilizing and reducing CO2 emissions from fossil-fired electric generators. This initiative proposes to stabilize CO2 emissions at current levels and require a ten percent reduction by 2020. The RGGI agreement (MOU) was signed on December 20, 2005 by the states of Connecticut, Delaware, Maine, New Jersey, New Hampshire, New York and Vermont. On January 18, 2007, Massachusetts also committed to the MOU. Each signatory state committed to propose for approval legislative and/or regulatory mechanisms to implement the program. RGGI may impact PSNH's Merrimack, Newington and Schiller stations. At this time, we cannot quantify the impact of the MOU on our companies. A model set of regulations was promulgated by the RGGI States in August 2006 to implement the program. Individual RGGI States are now initiating legislative and/or regulatory processes to implement their individual programs.
Hazardous Materials Regulations
Prior to the last quarter of the 20th century when environmental best practices and laws were implemented, we, like most industrial companies, disposed of residues from operations by depositing or burying such materials on-site or disposing of them at off-site landfills or facilities. Typical materials disposed of include coal gasification waste, fuel oils, ash, gasoline and other hazardous materials that might contain polychlorinated biphenyls. It has since been determined that deposited or buried wastes, under certain circumstances, could cause groundwater contamination or create other environmental risks. We have recorded a liability for what we believe is, based upon currently available information, our estimated environmental investigation and/or remediation costs for waste disposal sites for which we expect to bear legal liability, and continue to evaluate the environmental impact of our former disposal practices. Under federal and state law, government agencies and private parties can attempt to impose liability on us for such past disposal. At December 31, 2006, the liability recorded by us for our estimated environmental remediation costs for known sites needing investigation and/or remediation, exclusive of recoveries from insurance or from third parties, was approximately $26.8 million, representing 51 sites. All cost estimates were made in accordance with generally accepted accounting principles where investigation and/or remediation costs are probable and reasonably estimable. These costs could be significantly higher if additional remedial actions become necessary.
The greatest liabilities currently relate to former manufactured gas plant (MGP) facilities which represent the largest share of future clean up costs. These facilities were owned and operated by predecessor companies to us 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 28 former MGP sites. Of our total recorded liabilities of $26.8 million, a reserve of approximately $24.8 million has been established to address future investigation and/or remediation costs at MGP sites. In addition, remediation has been conducted at a coal tar contaminated river site in Massachusetts that is the responsibility of HWP. The cost to clean up that contamination may be more significant than currently estimated, but the level and extent of contamination is not yet known. Any and all exposure related to this site is not subject to ratepayer recovery. An increase to the environmental reserve for this site would be recorded in earnings for future periods and may be material.
In the past, we or our subsidiaries have received other claims from government agencies and third parties for the cost of remediating sites not currently owned by us but affected by our past disposal activities and may receive more such claims in the future. We expect that the costs of resolving claims for remediating sites about which we have been notified will not be material, but we cannot estimate the costs with respect to sites about which we have not been notified.
For further information on environmental liabilities, see Footnote 8B, "Commitments and Contingencies - Environmental Matters" contained within NU's 2006 Annual Report to Shareholders, which is incorporated into this Form 10-K by reference.
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 to date, agree that current information does not support the conclusion that EMF affects human health.
We have closely monitored research and government policy developments for many years and will continue to do so. In accordance with recommendations of various regulatory bodies and public health organizations, NU reduces 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.
FERC Hydroelectric Project Licensing
New 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, or (ii) the United States may take over the project or 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 owns nine hydroelectric generating stations with an aggregate of approximately 66.3 MW of capacity, with a current claimed capability representing winter rates, of approximately 69.5 MW. Of these nine plants, eight are licensed by the FERC under long-term licenses that expire on varying dates from 2009 through 2036 As a licensee under the FPA, PSNH and its licensed hydroelectric projects are subject to conditions set forth in the FPA 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.
FERC hydroelectric project licenses expire periodically and the generating facilities must be relicensed at such times. PSNH's Merrimack River Hydroelectric Project and Canaan Hydroelectric Project are currently in FERC relicensing proceedings. The FERC license for the Merrimack River Hydroelectric Project, which consists of the Amoskeag, Hooksett and Garvins Falls generating stations, expired on December 31, 2005. This project is currently operating under an annual FERC license, and the issuance of a new long-term license for the Merrimack River Hydroelectric Project is anticipated during the first half of 2007. The license for the Canaan Hydroelectric Project expires in 2009, and the issuance of a new license for the Canaan Hydroelectric Project is not anticipated for several years.
Licensed operating hydroelectric projects are not generally subject to decommissioning during the license term in the absence of a specific license provision which expressly permits the FERC to order decommissioning during the license term. However, the FERC has taken the position that under appropriate circumstances it may order decommissioning of hydroelectric projects at relicensing or may require the establishment of decommissioning trust funds as a condition of relicensing. The FERC may also require project decommissioning during a license term if a hydroelectric project is abandoned, the project license is surrendered or the license is revoked.
At this time, it appears unlikely that the FERC will order decommissioning of PSNH's hydroelectric projects at relicensing or that the projects will be abandoned, surrendered or the project licenses revoked. However, it is impossible to predict the outcome of the FERC relicensing proceedings with certainty, or to determine the impact of future regulatory actions on project economics. Until such time as a project is ordered to be decommissioned and the terms and conditions of a decommissioning order are known, any estimates of the cost of project decommissioning are preliminary and subject to change as new information becomes available.
EMPLOYEES
As of December 31, 2006, the NU system companies had 5,869 employees on their payrolls, excluding temporary employees, of which 1,812 were employed by CL&P, 1,286 by PSNH, 336 by WMECO, and 395 by Yankee Gas.
Approximately 2,200 employees of CL&P, PSNH, WMECO and Yankee Gas are covered by 11 union agreements. During 2005 and 2006, 11 contracts under negotiation have been ratified.
INTERNET INFORMATION
Our Web site address is http://www.nu.com. We make available through our Web site a link to the SEC's EDGAR site, at which site NU's, CL&P's, WMECO's and PSNH'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. Printed copies of these reports may be obtained free of charge by writing to our Investor Relations Department at Northeast Utilities, 107 Selden Street, Berlin, Connecticut 06037.
Item 1A.
Item 1A.
Risk Factors
We are subject to a variety of significant risks in addition to the matters set forth under "Safe Harbor Statement Under the Private Securities Litigation Reform Act of 1995" in Item 1, "Business," above. 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.
The Infrastructure Of Our Transmission And Distribution System May Not Operate As Expected, And Could Require Additional Unplanned Expense Which Would Adversely Affect Our Earnings.
Our ability to manage operational risk with respect to our transmission and distribution systems is critical to the financial performance of our business. Our transmission and distribution businesses face several operational risks, including the breakdown or failure of or damage to equipment or processes (especially due to age), accidents and labor disputes. The failure of our transmission and distributions systems to operate as planned may result in increased capital investments, reduced earnings or unplanned increases in expenses, including higher maintenance costs.
Volatility in Electric and Gas Prices May Adversely Impact Sales
The nation's economy has been affected by the recent significant increases in energy prices, particularly fossil fuels. The impact of these increases has led to a decline in electricity and gas sales in our service territories and may result in further declines. Such declines without an adjustment in rates would reduce our revenues and limit future growth prospects.
Changes in Regulatory Policy May Adversely Affect Our Transmission Franchise Rights or Facilitate Competition for Construction of Large-Scale Transmission Projects, Which Could Adversely Affect Our Earnings
Primarily through our subsidiary CL&P, we have undertaken a substantial transmission capital investment program and expect to invest approximately $2.5 billion in regulated electric transmission infrastructure from 2007 through 2011.
Although our public utility subsidiaries have exclusive franchise rights for transmission facilities in our service area, the demand for improved transmission reliability could result in changes in federal or state regulatory or legislative policy that could cause us to lose the exclusivity of our franchises or allow other companies to compete with us for transmission construction opportunities. Such a change in policy could result in reduced transmission capital investments, reduce earnings, and limit future growth prospects.
Changes in Regulatory or Legislative Policy Could Jeopardize Our Full Recovery of Costs Incurred By Our Distribution Companies
Under state law, our utility companies are entitled to charge rates that are sufficient to allow them an opportunity to recover their reasonable operation 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 state regulatory commissions for review and approval. There is no assurance that these state commissions will approve the recovery of all costs prudently incurred by the utility companies, such as for operation and maintenance, construction, as well as a return on investment on their respective regulated assets. Increases in these costs, coupled with increases in fuel and energy prices could lead to consumer or regulatory resistance to the timely recovery of such prudently incurred costs, thereby adversely affecting our business and results of operations.
In addition, CL&P and WMECO procure energy for a substantial portion of their customers via requests for proposal on an annual, semi-annual or quarterly basis. CL&P and WMECO receive approvals of recovery of these contract prices from the DPUC and DTE, respectively. While both regulators have consistently approved solicitation processes, results and recovery of costs, management cannot predict the outcome of future solicitation efforts or the regulatory proceedings related thereto.
The energy requirements for PSNH are currently met primarily through PSNH's generation resources or fixed-price forward purchase contracts. The remaining energy needs are met through spot market or bilateral energy purchases. Unplanned forced outages of its generating plants could increase the level of energy purchases needed by PSNH and therefore increase the market risk associated with
procuring the necessary amount of energy to meet requirements. PSNH recovers these costs through its SCRC, subject to a prudence review by the NHPUC. Management cannot predict the outcome of future regulatory proceedings related to recovery of these costs.
Changes In Regulatory And/Or Legislative Policy Could Negatively Impact Regional Transmission Cost Allocation Rules.
The existing New England Transmission tariff allocates the costs of transmission investment that provide regional benefits to all customers in New England. As new investment in regional transmission infrastructure occurs in any one state, there is a sharing of these regional costs across all of New England. This regional cost allocation is contractually agreed to remain in place until 2010 by the Transmission Operations Agreement signed by all of the New England transmission owning utilities but can be changed with the approval of a majority of the transmission owning utilities thereafter. Post 2010, certain changes to the terms of the Transmission Operations Agreement could have adverse effects on our distribution companies' local rates. Management is working to retain the existing regional cost allocation treatment but cannot predict the actions of the states or utilities in the region.
The Loss of Key Personnel or the Inability to Hire and Retain Qualified Employees Could Have an Adverse Effect on our Business, Financial Condition 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 NU 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 are developing strategic workforce plans to identify key functions and proactively implement plans to assure a ready and qualified workforce.
Grid Disturbances, Severe Weather, or Acts of War or Terrorism Could Negatively Impact our Business.
Because our generation and transmission systems are part of an interconnected regional grid, we face the risk of possible loss of business continuity due to a disruption or black-out caused by an event (severe storm, generator or transmission facility outage, or terrorist action) on an interconnected system or the actions of another utility. In addition, we are subject to the risk that acts of war or terrorism could negatively impact the operation of our system. Any such disruption could result in a significant decrease in revenues and significant additional costs to repair assets, which could have a material adverse impact on our financial condition and results of operations.
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 are generally not insured and 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. The effect of the failure of our facilities to operate as planned would be particularly burdensome during a peak demand period, such as during the hot summer months.
Changes in Regulatory or Legislative Policy May Delay Completion of Our Transmission Projects or Adversely Affect Our Ability to Recover Our Investments or Result in Lower than Expected Rates of Return
The successful implementation of our transmission construction plans is subject to the risk that new legislation, regulations or judicial or regulatory interpretations of applicable law or regulations could impact our ability to meet our construction schedule and/or require us to incur additional expenses, and may adversely affect our ability to achieve forecast levels of revenues.
The regulatory approval process for our planned transmission projects encompasses an extensive permitting, design and technical approval process. Various factors could result in increased cost estimates and delayed construction. Recoverability of all such investments in rates may be subject to prudence review at the FERC at the time such projects are placed in service. While we believe that all such expenses have been and will be prudently incurred, we cannot predict the outcome of future reviews should they occur.
The currently planned transmission projects are expected to help alleviate identified reliability issues in southwest Connecticut and to help reduce customers' costs in all of Connecticut. However, if, due to further regulatory or other delays, the projected in-service date for one or more of these projects is delayed, there may be increased risk of failures in the existing electricity transmission system in southwestern Connecticut and supply interruptions or blackouts may occur which could have an adverse effect on our earnings.
FERC has followed a policy of providing incentives designed to encourage the construction of new transmission facilities, including higher returns on equity and allowing facilities under construction to be placed in rate base before completion. Our projected earnings and growth could be adversely affected were FERC to reduce these incentives in the future below the level presently anticipated.
A Negative Change In NU's Credit Ratings Could Require NU To Post Cash Collateral And Affect our Ability To Obtain Financing
NU's senior unsecured debt ratings by Moody's Investors Service, Standard & Poor's, Inc. and Fitch Ratings are currently Baa2, BBB- and BBB, respectively, with stable outlooks. Were any of these ratings to decline to non-investment grade level, Select Energy could be asked to provide, as of December 31, 2006, approximately $136.8 million of collateral or letters of credit to unaffiliated counterparties and $52.4 million to several independent system operators and unaffiliated local distribution companies (LDCs) under agreements largely guaranteed by NU. While NU's credit facilities are in amounts that would be adequate to meet calls at that level, our ability to meet any future calls would depend on our liquidity and access to bank lines and the capital markets at such time.
We expect to obtain the liquidity needed for our capital programs through bank borrowings and the issuance of long-term debt at the subsidiary level. While we are reasonably confident these funds will be available on a timely basis and on reasonable terms, failure to obtain such financing could constrain our ability to finance regulated capital projects. In addition, any ratings downgrade of our securities or those of our subsidiaries could negatively impact the cost or availability of capital.
Changes in Forecasted Wholesale Electric Sales Could Require Select Energy to Acquire or Sell Additional Electricity on Unfavorable Terms
Select Energy's remaining wholesale sales contracts are to provide electricity to requirements customers, who are primarily regulated LDCs and municipal electric companies. Under the terms of its remaining requirements contracts, Select Energy is required to provide a portion of the customer's electricity requirements at all times. The volumes sold under these contracts vary based on the usage of the underlying retail electric customers, and usage is dependent upon factors outside of Select Energy's control, such as unanticipated migration or inflow of customers, and weather. As a result, the varying sales volumes could be different than the supply volumes that Select Energy expected to utilize from electricity purchase contracts acquired to serve the requirements contracts. Differences between actual sales volumes and supply volumes could require Select Energy to purchase additional electricity or sell excess electricity, both of which are subject to market conditions which change due to weather, plant availability, transmission congestion, and input fuel costs. The purchase of additional electricity at high prices or sale of excess electricity at low prices can impact Select Energy's cost to serve its remaining wholesale sales customers.
We Are Subject To Litigation Which Could Result In Large Cash Judgments against us
We are engaged in litigation that could result in the imposition of large cash judgments against us. This litigation includes a civil lawsuit between Consolidated Edison, Inc. (Con Edison) and NU relating to the parties' October 13, 1999 Agreement and Plan of Merger.
We may also be subject to future litigation based on asserted or unasserted claims and cannot predict the outcome of any of these proceedings. Adverse outcomes in existing or future litigation could result in the imposition of substantial cash damage awards against us.
Further information regarding these legal proceedings, as well as other matters, is set forth in Item 3, "Legal Proceedings."
Costs of Compliance with Environmental Regulations 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 which regulate, among other things, air emissions, water discharges and the management of hazardous and solid waste. In particular, more stringent regulations of carbon dioxide and mercury emissions have been proposed in various New England states. 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 these legal requirements may increase in the future. An increase in such costs, unless promptly recovered, could have an adverse impact on our business and results of operations, financial position and cash flows. For further information, see Item 1, "Business - Other Regulatory and Environmental Matters - Environmental Regulation."
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 for regulated generation. The cost impact of any such legislation would be dependent upon the specific requirements adopted and cannot be determined at this time.
Item 1B.
Item 1B. Unresolved Staff Comments
NU does not have any unresolved SEC staff comments.
Item 2.
Item 2. Properties
Transmission and Distribution System
At December 31, 2006, the electric operating subsidiaries of NU owned 196 transmission and 271 distribution substations that had an aggregate transformer capacity of 27,445,016 kilovoltamperes (kVa) and 2,255,770 kVa, respectively; 3,091 circuit miles of overhead transmission lines ranging from 69 kilovolt (KV) to 345 KV, and 242 cable miles of underground transmission lines ranging from 69 KV to 345 KV; 34,637 pole miles of overhead and 2,726 conduit bank miles of underground distribution lines; and 464,898 line transformers in service with an aggregate capacity of 21,202,617 kVa.
Electric Generating Plants
As of December 31, 2006, PSNH owned the following electric generating plants:
Name of Plant (Location)
Type
Year
Installed
Claimed
Capability*
(kilowatts)
Total - Fossil-Steam Plants
(7 units)
1952-78
999,554
Total - Hydro-Conventional
(20 units)
1917-83
69,510
Total - Internal Combustion
(5 units)
1968-70
101,461
Total PSNH Generating Plant
(32 units)
1,170,525
*Claimed capability represents winter ratings as of December 31, 2006. The nameplate capacity of the generating plants is approximately 1,200 MW.
Neither CL&P nor WMECO owned any electric generating plants during 2006.
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 in Title 16 of the Connecticut General Statutes 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. Title 16 of the Connecticut General Statutes was amended by Public Act 03-135, "An Act Concerning Revisions to the Electric Restructuring Legislation," to prohibit an electric distribution company from owning or operating generation assets. However, Public Act 05-01, "An Act Concerning Energy Independence," allows CL&P to own up to 200 MW of peaking facilities if the DPUC determines that such facilities will be more cost effective than other options for mitigating FMCCs and LICAP costs. CL&P has divested all of its generation assets and is now acting as a transmission and distribution company.
PSNH - The NHPUC, pursuant to statutory requirement, 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. The franchises of PSNH include the power of eminent domain.
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 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 DTE was required to define service territories for each distribution company, including WMECO. The DTE 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.
HWP and Holyoke Power and Electric Company (HP&E) - HWP, and its wholly owned subsidiary HP&E, are authorized by their charters to conduct their businesses in the territories served by them. HWP's electric business is subject to the restriction that sales be made by written contract in amounts of not less than 100 horsepower to purchasers who use the electricity in their own business in the counties of Hampden or Hampshire, Massachusetts and cities and towns in these counties, and customers who occupy property in which HWP has a financial interest, by ownership or purchase money mortgage. In connection with the sale of certain of HWP's and HP&E's assets to the city of Holyoke Gas and Electric Department (HG&E) effective December 2001, HWP agreed not to distribute electricity at retail in Holyoke and surrounding towns unless other sellers can legally compete with HG&E and to amend the charters of HWP & HP&E to reflect that limitation.
The two companies have locations in the public highways for their 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. HP&E has no retail service territory area and sells electric power exclusively at wholesale.
Yankee Gas - Yankee Gas directly and from its predecessors in interest holds valid franchises to sell gas in the areas in which Yankee Gas supplies gas service. 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 gas utility under a valid franchise of its own or are not subject to an exclusive franchise of another 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 DPUC 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 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.
Item 3. Legal Proceedings
1.
Consolidated Edison, Inc. v. NU - Merger Litigation
On March 5, 2001, Con Edison advised NU that it was unwilling to close its merger with NU on the terms set forth in the parties' 1999 merger agreement (the Merger Agreement). On March 12, 2001, NU filed suit against Con Edison seeking damages in excess of $1 billion.
On May 11, 2001, Con Edison filed an amended complaint seeking damages for breach of contract, fraudulent inducement and negligent misrepresentation.
On October 12, 2005, the United State Court of Appeals for the Second Circuit issued a decision concluding that NU shareholders had no right to sue Con Edison for its alleged breach of the Merger Agreement. As a result, the Second Circuit did not reach the second issue presented for review which was whether the right to pursue recovery of the $1 billion merger premium belongs to NU shareholders who held shares at the time of the breach or those who hold shares if and when a judgment is rendered against Con Edison. NU filed for rehearing and suggested an en banc review on October 26, 2005. By order dated January 3, 2006, NU's request for rehearing was denied. The ruling leaves intact the remaining claims between NU and Con Edison for breach of contract, which include NU's claim for recovery
of costs and expenses of approximately $32 million, and Con Edison's claim for "at least $314 million" in damages. NU opted not to seek review of this ruling by the United States Supreme Court.
On April 7, 2006, NU filed its motion for partial summary judgment on Con Edison's damage claim. NU's motion asserts that NU is entitled to judgment in its favor with respect to this claim based on the undisputed material facts and applicable law. The matter is fully briefed and awaiting a decision.
It is not possible to predict either the outcome of this matter or its ultimate effect on NU.
2.
Constellation Power Source, Inc. (Constellation) v. Select Energy, Inc.
This case involves a dispute between Select Energy and Constellation over responsibility for socialized congestion charges imposed by ISO-NE prior to the implementation of Standard Market Design (SMD) on March 1, 2003, and responsibility for congestion charges and losses following implementation of SMD. Constellation filed a complaint in the U.S. District Court for the District of Connecticut against Select Energy claiming that Select Energy was responsible for pre- and post-SMD congestion and losses amounting to approximately $9.7 million. Select Energy filed a counterclaim seeking to recover the $2.5 million in pre-SMD charges that Constellation had refused to pay.
The case was tried to the Court in August 2006. On November 14, 2006, the court issued its Memorandum of Decision and found in favor of Select Energy, with respect to its counterclaim for recovery of pre-SMD congestion and losses. The court also awarded Constellation its "pro rata share of the LMP Differential that Select Energy received from CL&P in connection with the settlement of the FERC proceeding, plus prejudgment interest as provided in the parties' agreement." Pursuant to an order of the Court, the parties made their respective damages filings with the Court on December 13, 2006. On January 23, 2007, the Court issued its final decision and order addressing the issue of damages. The net effect of the Court's ruling is that Select Energy will have to pay Constellation approximately $1.7 million as of the date entered, with interest accruing at a net rate of approximately $500 per day until the judgment is paid. The parties have reached a settlement pursuant to which Select Energy agreed to pay Constellation $2 million, thereby ending the litigation.
3.
NRG Bankruptcy
On May 14, 2003, NRG and certain of its affiliates filed for Chapter 11 protection in the United States Bankruptcy Court for the Southern District of New York (Bankruptcy Court). The filing affects relationships between various NU companies and the NRG companies, as follows:
A. Station Service
NRG has disputed its responsibility to pay for the provision of station service by CL&P to NRG's Connecticut generating plants (approximately $26 million, including late charges). The FERC issued a decision on December 20, 2002 that NRG had agreed that station service from CL&P would be subject to CL&P's applicable retail rates, and that states (i.e., the DPUC) have jurisdiction over the delivery of power to end users even where power is not delivered via distribution facilities. NRG refused CL&P's subsequent demand for payment, and on April 3, 2003, CL&P petitioned the DPUC for a declaratory order enforcing the FERC's December 20, 2002 decision. Prior to the issuance of a decision by the DPUC, NRG filed a petition under Chapter 11 of the U.S. Bankruptcy Code, staying any further action by the DPUC.
On September 18, 2003, the Bankruptcy Court approved the parties' stipulation to submit the station service issue to arbitration for a determination of liability and damages which will fix CL&P's claim in bankruptcy. The parties are currently pursuing arbitration of the issues in dispute with hearing dates scheduled for the fall of 2007. On December 17, 2003, the DPUC issued a decision in CL&P's rate case that addressed the issue that CL&P had first raised to the DPUC in its April 3, 2003 filing. The DPUC affirmatively stated that CL&P has been appropriately administering its station service rates. Subsequently, however, in unrelated proceedings, the FERC issued a series of orders with conflicting policy direction, which call into question its December 20, 2002 NRG order (See Dominion Nuclear litigation below).
B. Yankee Gas
On October 9, 2002, NRG informed Yankee Gas that its affiliate, Meriden Gas Turbines, LLC (MGT), was permanently shutting down or abandoning its Meriden power plant project, and requested that Yankee Gas cease its construction activities and begin an orderly wind down of its work relating to the project. Based on NRG's statement that it expected that Yankee Gas would draw on a $16 million letter of credit (LOC), Yankee Gas drew down the full amount of the LOC. On November 12, 2002, MGT filed suit against Yankee Gas in Meriden Superior Court, claiming that Yankee Gas breached the agreement with MGT (MGT Agreement), and seeking a declaratory ruling from the court that Yankee Gas wrongfully drew down the $16 million LOC. In April 2003, Yankee Gas filed its answer to MGT's complaint and asserted a counterclaim to recover its losses arising out of MGT's termination of the MGT Agreement. The parties
subsequently reached a settlement in principle of their claims; however, MGT has since requested the court to place the case back on the trial calendar. Yankee Gas filed a motion to enforce the settlement and the parties are again engaged in court-ordered settlement discussions. No trial date is currently scheduled
C. Congestion Charges
On August 5, 2002, CL&P withheld the past due congestion charges from its payment to NRG pursuant to contractual provisions allowing the withholding of disputed sums. CL&P continued to withhold congestion charges from its monthly payments to NRG, through March 1, 2003, and at present is withholding approximately $28 million. On November 28, 2001, CL&P filed a complaint against NRG in Connecticut Superior Court alleging breach of contract arising from the failure of NRG to pay approximately $29.6 million of socialized congestion charges. The case was removed to U.S. District Court for the District of Connecticut. NRG filed a counterclaim seeking recovery of all amounts CL&P has withheld. Discovery is complete and CL&P's motion for summary judgment is pending. No trial date is currently scheduled.
4.
CYAPC/FERC Proceeding
On July 1, 2004, CYAPC filed with the FERC to increase its decommissioning collections from $16.7 million per year (in 2000 dollars) to $93 million per year (in 2003 dollars) for the six-year period beginning January 1, 2005. The 2003 estimate projects an increase of $395.6 million in 2003 dollars and a total cost to complete decommissioning of $831.3 million in 2003 dollars.
On August 30, 2004, the FERC issued an order accepting the CYAPC rate filing, suspending collections for five months and establishing hearing procedures.
The FERC administrative law judge conducted hearings on the reasonableness of the decommissioning rates in the spring of 2005. The DPUC argued that CYAPC's actions were imprudent and recommended a disallowance in the range of approximately $225 to $234 million. The FERC trial staff argued that CYAPC should have used a lower gross domestic product (GDP) escalation rate in calculating the level of decommissioning charges and that use of such rate would reduce charges by $36 million. In post trial briefs, the FERC trial staff also claimed that CYAPC's actions were imprudent and increases in decommissioning charges should be disallowed.
In an initial decision rendered on November 22, 2005, the FERC trial judge found no imprudence on CYAPC's part, and thus there was no basis for a rate disallowance. However, the trial judge agreed with the FERC trial staff's lower GDP escalator for calculating the decommissioning rate increase.
On November 16, 2006, FERC approved a settlement among CYAPC, the DPUC, the OCC, the Maine Public Utilities Commission and the Maine Public Advocate that disposes of the pending decommissioning litigation at FERC and at the D.C. Circuit. The settlement also resolves the dispute over the incentive mechanism contained in the 2000 settlement between the parties, the disposition of the net proceeds from CY's settlement with Bechtel, CY's recovery of the costs of completing decommissioning, and CY's payment of dividends and return of equity capital to its shareholders.
Under the terms of the settlement, the parties have agreed to a revised decommissioning estimate of $642.9 million (in 2006 dollars), taking into account actual spending through 2005 and the current estimate for completing decommissioning and long-term storage of spent fuel, a GDP escalator of 2.5% for costs incurred post 2006, and a 10% contingency factor for all decommissioning costs.
NU's electric operating subsidiaries collectively own 49.0 % of CYAPC, as follows: CL&P - 34.5 %, PSNH - 5.0 %and WMECO - 9.5%.
5.
YAEC- Decommissioning
On November 23, 2005, YAEC filed a request with FERC to revise the level of its decommissioning collections, based on an increased cost estimate. A 2003 settlement had provided for annual charges of $55.6 million through 2005 and $14 million from 2006 through 2010, with certain adjustments. YAEC's proposal is to increase 2006 collections to $54.9 million and increase 2007 through 2010 collections to $23.5 million. YAEC has asked FERC for an effective date of February 1, 2006. On January 31, 2006, FERC accepted the rate increase with a February 1, 2006 effective date, subject to refund, and set the case for settlement proceedings.
On May 1, 2006, YAEC filed with FERC a proposed settlement with the Connecticut DPUC, the Massachusetts Attorney General and the Vermont Department of Public Service. The settlement reduces decommissioning charges to YAEC's wholesale utility customers by, among other items, revising the decommissioning estimate, including contingency and projected escalation, extending the collection period for charges through December 2014, reduces certain expenses, reconciling certain decontamination and dismantlement expenses, and adjusting charges based on the decommissioning trust fund's actual investment earnings. The settlement proposes a new estimate of decommissioning charges of $212.6 million, reflecting a $28.2 million reduction compared to the 2005 decommissioning cost of estimate.
The settlement became effective upon FERC's approval in December, 2006, but did not affect the level of 2006 charges. Charges from 2007 through 2014 will drop to approximately $11.7 million per year, subject to certain adjustments.
NU's electric operating subsidiaries collectively own 38.5 % of YAEC, as follows: CL&P - 24.5%, PSNH - 7.0 % and WMECO - 7.0%.
6.
Yankee Companies v. U.S. Department of Energy
A. Spent Nuclear Fuel Litigation
YAEC, MYAPC, and CYAPC commenced litigation in 1998 against the DOE charging that the federal government breached contracts it entered into with each company in 1983 under the Nuclear Waste Policy Act of 1982 to begin removing spent nuclear fuel from the respective nuclear plants no later than January 31, 1998 in return for payments by each company into the Nuclear Waste Fund. The funds for those payments were collected from regional electric customers. The Yankee Companies initially claimed damages for incremental spent nuclear fuel storage, security, construction and other costs through 2010.
In a ruling released on October 4, 2006, the Court of Federal Claims held that the DOE was liable for damages to CYAPC for $34.2 million through 2001, YAEC for $32.9 million through 2001 and MYAPC for $75.8 million through 2002. The Yankee Companies had claimed actual damages for the same period as follows: CYAPC: $37.7 million; YAEC: $60.8 million; and MYAPC: $78.1 million. The refund to CL&P, PSNH and WMECO of any damages that may be recovered from the DOE is established in the Yankee Companies' FERC-approved rate settlement agreement, although implementation will be subject to final determination of FERC. CL&P, PSNH and WMECO expect to pass any recovery onto its customers therefore no earnings are expected to result.
The Court of Federal Claims, following precedent set in another case, did not award the Yankee Companies future damages covering the period beyond the 2001/2002 damages award dates. The Yankee Companies believe they will have the opportunity in future lawsuits to seek recovery of actual damages incurred in the years following 2001/2002. The DOE appealed the decision and the Yankee Companies filed cross-appeals. The application of any damages which are ultimately recovered to benefit customers is established in the Yankee Companies' FERC-approved rate settlement agreements, although implementation will be subject to the final determination of the FERC.
B. Uranium Enrichment Litigation
In 2001, Northeast Utilities Service Company (NUSCO) asserted claims against the DOE in the Court of Federal Claims for overcharges for purchases of uranium enrichment separative work units (SWUs) for CYAPC's nuclear unit and the nuclear units located at Millstone Power Station in Waterford, Connecticut between 1986 and 1993 (D&D Claims). The NUSCO case was stayed by the Court of Federal Claims while other D&D Claims cases were being litigated. Beginning in 2005, NUSCO joined a number of other utilities in a consortium in an attempt to negotiate a settlement agreement with the DOE. In late-2006, a settlement was reached between the consortium and the DOE. The distribution of proceeds under the settlement agreement totals approximately $0.8 million for CYAPC and approximately $1.4 million related to the Millstone units. This distribution is based on the total number of SWUs purchased for CYAPC's unit and the Millstone units during the applicable period covered by the litigation. We believe it is likely that the net proceeds from the settlement will be credited to ratepayers. CL&P, PSNH and WMECO collectively own 49% of CYAPC. Prior to March 31, 2001, CL&P, PSNH and WMECO collectively owned 100% of Millstone 1 and 2 and 68.02 % of Millstone 3.
7.
Enron Bankruptcy Claim
CL&P filed a proof of claim in the sum of $42.9 million against Enron Power Marketing, Inc. (EPMI) in the U. S. Bankruptcy Court for the Southern District of New York. The claim is for damages resulting from the rejection of the December 22, 2000 electricity purchase agreement between EPMI and CL&P, which was related to an agreement the Connecticut Resource Recovery Authority had entered into with Enron. EPMI, through the Enron bankruptcy estate, objected to the CL&P claim, CL&P filed a response, and litigation ensued in the bankruptcy court. CL&P and Enron have now agreed to settle the matter by agreeing that the CL&P's claim will have a face value of $19.75 million. CL&P cannot estimate what percentage of the claim will be paid once the agreement is approved, but the proceeds from the liquidation of the claim will be credited to ratepayers. The settlement requires DPUC and bankruptcy court approval and the parties anticipate that a motion to approve the settlement will be filed in the second quarter of 2007.
8.
Connecticut MGP Cost Recovery
On August 5, 2004, Yankee Gas and CL&P (NU Companies) demanded contribution from UGI Utilities, Inc. (UGI) of Pennsylvania for past and future remediation costs related to historic MGP operations on thirteen sites currently or formerly owned by the NU Companies (Yankee Gas is responsible for ten of the sites, CL&P for two of the sites, and both companies share responsibility for one site) in a number of different locations throughout the State of Connecticut. The NU Companies alleged that UGI controlled operations of the
plants at various times throughout the period 1883 to 1941, when UGI was forced to divest its interests. Investigations and remediation costs at the sites to date total over $20 million against reserves, and projected potential remediation costs for all sites--based on litigation modeling assumptions--could total as much as $228 million. At this point, the costs are not estimable and probable from an accounting standpoint.
In September 2006, the NU Companies filed a complaint against UGI in the U.S. District Court for the District of Connecticut seeking a fair and equitable contribution for the actual and anticipated remediation costs related to the former MGP operations. On November 6, UGI answered the complaint, denying the material allegations asserted against it. The case is now in the discovery phase.
9.
Dominion Nuclear-Station Service
On July 24, 2006, Dominion Nuclear Connecticut, Inc. (DNCI) filed a complaint at FERC, claiming that, because as of December 1, 2005, DNCI sought to "self-supply" its station service power through the ISO-NE settlement system rather than from CL&P as a Transitional Standard Service retail customer, it is not required to buy retail delivery service for that power. On August 14, 2006, CL&P answered the complaint, supported by the Connecticut DPUC, OCC and the AG.
On September 22, 2006, FERC issued an order finding that CL&P is not authorized to impose local distribution charges for station power delivery service on DNCI, and directed CL&P to cease charging DNCI retroactive to December 1, 2005. Since that date, DNCI has withheld approximately $1.7 million (including interest). CL&P sought rehearing and clarification on October 23, 2006. (See "NRG Bankruptcy - Station Service" under entry 3 of this Item 3 for a contrasting view taken by the DPUC).
10.
Other Legal Proceedings
The following sections of Item 1, "Business" discuss additional legal proceedings: See "Regulated Electric Distribution," "Regulated Electric Transmission," and "Regulated Gas Operations" for information about various state restructuring and rate proceedings, civil lawsuits related thereto, and information about proceedings relating to power, transmission and pricing issues; "Status of 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, EMF, licensing of hydroelectric projects, and other matters. In addition, see Item 1A, "Risk Factors" for general information about several significant risks.
EXECUTIVE OFFICERS OF NU
Name
Age
Business Experience During Past 5 Years
Gregory B. Butler
Senior Vice President and General Counsel of NU since December 1, 2005 and of CL&P, PSNH and WMECO since March 9, 2006, and a Director of Northeast Utilities Foundation, Inc. since December 1, 2002; previously Senior Vice President, Secretary and General Counsel of NU from August 31, 2003 to December 1, 2005; Vice President, Secretary and General Counsel of NU from May 1, 2001 through August 30, 2003.
Lawrence E. De Simone
Retired as of January 1, 2007; previously served as President-Competitive Group of NU and President of NU Enterprises, Inc., from October 25, 2004 to December 31, 2006 and Chairman, President and Chief Executive Officer of Select Energy, Inc. from February 1, 2005 to December 31, 2006; previously Executive Vice President - Regulated Business and Services of PPL Corporation from January 1, 2004 to August 31, 2004; Executive Vice President - Supply of PPL Corporation from October 2001 to December 31, 2003.
Cheryl W. Grisé (*)
Executive Vice President of NU since December 1, 2005; Chief Executive Officer of CL&P, PSNH and WMECO from September 10, 2002 to January 15, 2007, a Director of CL&P from May 1, 2001 to January 15, 2007, PSNH from May 14, 2001 to January 15, 2007 and WMECO from June 2001 to January 15, 2007, and a Director of Northeast Utilities Foundation, Inc. since September 23, 1998; previously President - Utility Group of NU from May 2001 to December 1, 2005.
David R. McHale
Senior Vice President and Chief Financial Officer of NU, CL&P, PSNH and WMECO since January 1, 2005 and a Director of PSNH and WMECO since January 1, 2005 and CL&P since January 15, 2007; previously Vice President and Treasurer of NU, WMECO and PSNH from July 1998 to December 31, 2004.
Leon J. Olivier
Executive Vice President - Operations of NU since February 13, 2007; Chief Executive Officer of CL&P, PSNH and WMECO since January 15, 2007; Director of PSNH and WMECO since January 17, 2005 and a Director of CL&P since September 2001. Previously Executive Vice President of NU from December 1, 2005 to February 13, 2007; President - Transmission Group of NU from January 17, 2005 to December 1, 2005; President and Chief Operating Officer of CL&P from September 2001 to January 2005.
Shirley M. Payne
Vice President - Accounting and Controller of NU since February 13, 2007, and CL&P, PSNH and WMECO since January 29, 2007. Previously Vice President, Corporate Accounting and Tax of TECO Energy, Inc. from July 2000 to January 26, 2007 and Tax Officer of Tampa Electric Company from April 1999 to January 26, 2007.
Charles W. Shivery
Chairman of the Board, President and Chief Executive Officer of NU since March 29, 2004; Chairman and a Director of CL&P, PSNH and WMECO since January 19, 2007. Previously, President (interim) of NU from January 1, 2004 to March 29, 2004 and a Director of Northeast Utilities Foundation since March 3, 2004; previously President - Competitive Group of NU and President and Chief Executive Officer of NU Enterprises, Inc., from June 2002 through December 2003.
(*)
Mrs. Grisé is a Director of MetLife, Inc. and Dana Corporation.
Item 4.
Item 4. Submission Of Matters To a Vote of Security Holders
No event that would be described in response to this item occurred with respect to NU or CL&P.
The information called by Item 4 is omitted for PSNH and WMECO pursuant to Instruction I (2)(c) to Form 10-K (Omission of Information by Certain Wholly Owned Subsidiaries.)
Part II
Item 5.
Item 5. Market for The Registrants' Common Equity and Related Stockholder Matters
NU. The common shares of NU 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 closing sales prices for the past two years, by quarters, are shown below.
There were no purchases made by or on behalf of NU or any "affiliated purchaser" (as defined in Rule 10b-18(a)(3) under the Securities Exchange Act of 1934), of common stock during the fourth quarter of the year ended December 31, 2006. Information with respect to the performance of NU's common shares is contained in the "Share Performance Chart" from the Proxy Statement to be dated March 20, 2007, which information is incorporated herein by reference.
As of January 31, 2007, there were 50,849 common shareholders of NU on record. As of the same date, there were a total of 175,453,290 common shares issued, including 1,483,561 unallocated Employee Stock Ownership Plan (ESOP) shares held in the ESOP trust.
On February 13, 2007, the NU Board of Trustees approved the payment of 18.75 cent per share dividend, payable on March 31, 2007, to shareholders of record as of March 1, 2007.
On November 13, 2006, the NU Board of Trustees approved the payment of 18.75 cent per share dividend, payable on December 30, 2006, to shareholders of record as of December 1, 2006.
On May 9, 2006, the NU Board of Trustees approved the payment of 18.75 cent per share dividend, payable on September 29, 2006 to shareholders of record as of September 1, 2006.
On April 11, 2006, the NU Board of Trustees approved the payment of 17.5 cent per share dividend, payable on June 30, 2006 to shareholders of record on June 1, 2006.
On February 14, 2006, the NU Board of Trustees approved the payment of 17.5 cent per share dividend, payable on March 31, 2006 to shareholders of record as of March 1, 2006.
On October 11, 2005, the NU Board of Trustees approved the payment of 17.5 cent per share dividend, payable on December 30, 2005 to shareholders of record as of December 1, 2005.
On May 10, 2005, the NU Board of Trustees approved the payment of 17.5 cent per share dividend, payable on September 30, 2005 to shareholders of record as of September 1, 2005.
On April 12, 2005, the NU Board of Trustees approved the payment of 16.25 cent per share dividend, payable on June 30, 2005 to shareholders of record as of June 1, 2005.
On January 31, 2005, the NU Board of Trustees approved the payment of 16.25 cent per share dividend, payable on March 31, 2005 to shareholders of record as of March 1, 2005.
Information with respect to dividend restrictions for NU, CL&P, 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 in the "Notes to Consolidated Financial Statements," within each company's 2006 Annual Report to Shareholders, which information is incorporated herein by reference.
CL&P, PSNH and WMECO. There is no established public trading market for the common stock of CL&P, PSNH and WMECO. The common stock of CL&P, PSNH and WMECO is held solely by NU.
During 2006 and 2005, CL&P approved and paid $63.7 million and $53.8 million, respectively, of common stock dividends to NU.
During 2006 and 2005, PSNH approved and paid $41.7 million and $42.4 million, respectively, of common stock dividends to NU.
During 2006 and 2005, WMECO approved and paid $7.9 million and $7.7 million, respectively, of common stock dividends to NU.
For information regarding securities authorized for issuance under equity compensation plans, see Item 12, "Security Ownership of Certain Beneficial Owners and Management and Related Shareholder Matters," included in this report on Form 10-K.
Item 6.
Item 6. Selected Financial Data
NU. Reference is made to information under the heading "Selected Consolidated Financial Data" contained within NU's 2006 Annual Report to Shareholders, which information is incorporated herein by reference.
CL&P. Reference is made to information under the heading "Selected Consolidated Financial Data" contained within CL&P's 2006 Annual Report, which information is incorporated herein by reference.
PSNH. Reference is made to information under the heading "Selected Consolidated Financial Data" contained within PSNH's 2006 Annual Report, which information is incorporated herein by reference.
WMECO. Reference is made to information under the heading "Selected Consolidated Financial Data" contained within WMECO's 2006 Annual Report, which information is incorporated herein by reference.
Item 7.
Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations
NU. Reference is made to information under the heading "Management's Discussion and Analysis and Results of Operations" contained within NU's 2006 Annual Report to Shareholders, which information is incorporated herein by reference.
CL&P. Reference is made to information under the heading "Management's Discussion and Analysis and Results of Operations" contained within CL&P's 2006 Annual Report, which information is incorporated herein by reference.
PSNH. With respect to PSNH's results of operations, reference is made to information under the heading "Results of Operations" contained within PSNH's 2006 Annual Report, which information is incorporated herein by reference.
WMECO. With respect to WMECO's results of operations, reference is made to information under the heading "Results of Operations" contained within WMECO's 2006 Annual Report, which information is incorporated herein by reference.
Item 7A.
Item 7A. Quantitative and Qualitative Disclosures about Market Risk
Market Risk Information
The merchant energy business utilizes the sensitivity analysis methodology to disclose quantitative information for its commodity price risks (including where applicable capacity and ancillary components). Sensitivity analysis provides a presentation of the potential loss of future earnings, fair values or cash flows from market risk-sensitive instruments over a selected time period due to one or more hypothetical changes in commodity price components, or other similar price changes. Under sensitivity analysis, the fair value of the portfolio is a function of the underlying commodity components, contract prices and market prices represented by each derivative contract. For swaps, forward contracts and options, fair value reflects management's best estimates considering over-the-counter quotations, time value and volatility factors of the underlying commitments. Exchange-traded futures and options are recorded at fair value based on closing exchange prices. As the NU Enterprises' businesses are exited, the risks associated with commodity prices are expected to be reduced.
NU Enterprises - Wholesale Portfolio: When conducting sensitivity analyses of the change in the fair value of Select Energy's wholesale portfolio, which includes a non-derivative power purchase contract, which would result from a hypothetical change in the future market price of electricity, the fair values of the contracts are determined from models that take into consideration estimated future market prices of electricity, the volatility of the market prices in each period, as well as the time value factors of the underlying commitments.
A hypothetical change in the fair value of the wholesale portfolio was determined assuming a 10 percent change in forward market prices. At December 31, 2006, Select Energy has calculated the market price resulting from a 10 percent change in forward market prices of those contracts. A 10 percent increase in prices for all products would have resulted in a pre-tax decrease in fair value of $1.2 million and a 10 percent decrease in prices for all products would not have resulted in a change in fair value. A 10 percent increase in energy prices would have resulted in a $9.4 million pre-tax decrease, and a 10 percent decrease in energy prices would have resulted in an $8.2 million pre-tax increase. A 10 percent increase/(decrease) in capacity prices would have resulted in a $2.3 million pre-tax increase/(decrease). A 10 percent increase/(decrease) in ancillary prices would have resulted in a 5.9 million pre-tax increase/(decrease).
The impact of a change in electricity and natural gas prices on Select Energy's wholesale transactions at December 31, 2006 are not necessarily representative of the results that will be realized. These transactions are accounted for at fair value, and changes in market prices impact earnings.
NU Enterprises - Generation Portfolio: In conjunction with the sale of the competitive generation business on November 1, 2006, the generation portfolio was divested or otherwise closed out by December 31, 2006.
Other Risk Management Activities
Interest Rate Risk Management: NU manages its interest rate risk exposure in accordance with its written policies and procedures by maintaining a mix of fixed and variable rate debt. At December 31, 2006, approximately 89 percent (80 percent including the debt subject to the fixed-to-floating interest rate swap of variable rate debt) of NU's long-term debt, including fees and interest due for spent nuclear fuel disposal costs, is at a fixed interest rate. The remaining long-term debt is variable-rate and is subject to interest rate risk that could result in earnings volatility. Assuming a one percentage point increase in NU's variable interest rates, including the rate on debt subject to the fixed-to-floating interest rate swap, annual interest expense would have increased by $3.2 million. At December 31, 2006, NU parent maintained a fixed-to-floating interest rate swap to manage the interest rate risk associated with its $263 million of fixed-rate debt.
Credit Risk Management: Credit risk relates to the risk of loss that NU would incur as a result of non-performance by counterparties pursuant to the terms of its contractual obligations. NU serves a wide variety of customers and suppliers that include IPPs, industrial companies, gas and electric utilities, oil and gas producers, financial institutions, and other energy marketers. Margin accounts exist within this diverse group, and NU realizes 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 which, in turn, requires NU to manage the portfolio of market risk inherent in those transactions in a manner consistent with the parameters established by NU's risk management process.
Credit risks and market risks at NU Enterprises are monitored regularly by a Risk Oversight Council. The Risk Oversight Council is generally comprised of individuals from outside of the business lines that create or actively manage these risk exposures and functions to ensure compliance with NU's stated risk management policies.
NU tracks and re-balances the risk in its portfolio in accordance with fair value and other risk management methodologies that utilize forward price curves in the energy markets to estimate the size and probability of future potential exposure.
NYMEX traded futures and option contracts cleared off the NYMEX exchange are ultimately guaranteed by NYMEX to Select Energy. Select Energy has established written credit policies with regard to its counterparties to minimize overall credit risk on all types of transactions. These policies require an evaluation of potential counterparties' financial condition (including credit ratings), collateral requirements under certain circumstances (including cash in advance, LOCs, and parent guarantees), and the use of standardized agreements, which allow for the netting of positive and negative exposures associated with a single counterparty. This evaluation results in establishing credit limits prior to Select Energy entering into energy contracts. The appropriateness of these limits is subject to continuing review. Concentrations among these counterparties may impact Select Energy's overall exposure to credit risk, either positively or negatively, in that the counterparties may be similarly affected by changes to economic, regulatory or other conditions.
At December 31, 2006 and 2005, Select Energy maintained collateral balances from counterparties of $0.2 million and $28.9 million, respectively. These amounts are included in counterparty deposits on the accompanying condensed consolidated balance sheets. Select Energy also has collateral balances deposited with counterparties of $48.5 million and $103.8 million at December 31, 2006 and 2005, respectively.
The Utility Group has a lower level of credit risk related to providing regulated electric and gas distribution service than NU Enterprises. However, the Utility Group companies are subject to credit risk from certain long-term or high-volume supply contracts with energy marketing companies. The Utility Group manages the credit risk with these counterparties in accordance with established credit risk practices and maintains an oversight group that monitors contracting risks, including credit risk.
NU has implemented an Enterprise Risk Management (ERM) methodology for identifying the principal risks of the company. ERM involves the application of a well-defined, enterprise-wide methodology that will enable NU’s Risk and Capital Committee, comprised of senior NU officers, to oversee the identification, management and reporting of the principal risks of the business. However, there can be no assurances that the ERM process will identify every risk or event that could impact the company's financial condition or results of operations. The findings of this process are periodically discussed with NU's Finance Committee of the Board of Trustees.
Additional quantitative and qualitative disclosures about market risk are set forth in Part II, Item 7, "Management's Discussion and Analysis of Financial Condition and Results of Operations," included in this combined report on Form 10-K.
Item 8.
Item 8. Financial Statements and Supplementary Data
NU. Reference is made to information under the headings "Report of Independent Registered Public Accounting Firm," "Consolidated Balance Sheets," "Consolidated Statements of Income/(Loss)," "Consolidated Statements of Comprehensive Income/(Loss)," "Consolidated Statements of Shareholders' Equity," "Consolidated Statements of Cash Flows," "Consolidated Statements of Capitalization," "Notes to Consolidated Financial Statements," and "Consolidated Statements of Quarterly Financial Data" contained within NU's 2006 Annual Report to Shareholders, which information is incorporated herein by reference.
CL&P. Reference is made to information under the headings "Report of Independent Registered Public Accounting Firm," "Consolidated Balance Sheets," "Consolidated Statements of Income," "Consolidated Statements of Comprehensive Income," "Consolidated Statements of Common Stockholder's Equity," "Consolidated Statements of Cash Flows," "Notes to Consolidated Financial Statements," and "Consolidated Quarterly Financial Data" contained within CL&P's 2006 Annual Report, which information is incorporated herein by reference.
PSNH. Reference is made to information under the headings "Report of Independent Registered Public Accounting Firm," "Consolidated Balance Sheets," "Consolidated Statements of Income," "Consolidated Statements of Comprehensive Income," "Consolidated Statements of Common Stockholder's Equity," "Consolidated Statements of Cash Flows," "Notes to Consolidated Financial Statements," and "Consolidated Quarterly Financial Data" contained within PSNH's 2006 Annual Report, which information is incorporated herein by reference.
WMECO. Reference is made to information under the headings "Report of Independent Registered Public Accounting Firm," "Consolidated Balance Sheets," "Consolidated Statements of Income," "Consolidated Statements of Comprehensive Income," "Consolidated Statements of Common Stockholder's Equity," "Consolidated Statements of Cash Flows," "Notes to Consolidated Financial Statements," and "Consolidated Quarterly Financial Data" contained within WMECO's 2006 Annual Report, which information is incorporated herein by reference.
Item 9.
Item 9. Changes in and Disagreements With Accountants on Accounting and Financial Disclosure
No events that would be described in response to this item have occurred with respect to NU, CL&P, PSNH or WMECO.
Item 9A.
Item 9A. Controls and Procedures
Management is responsible for the preparation, integrity, and fair presentation of the accompanying consolidated financial statements of Northeast Utilities and subsidiaries (NU) and of other sections of this annual report. These financial statements, which were audited by Deloitte & Touche LLP, have been prepared in conformity with accounting principles generally accepted in the United States of America using estimates and judgments, where required, and giving consideration to materiality.
Management is responsible for establishing and maintaining adequate internal controls over financial reporting. The Company'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 generally accepted accounting principles. 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 management, including our principal executive officer and principal financial officer, NU conducted an evaluation of the effectiveness of internal controls over financial reporting based on criteria established in Internal Control - Integrated 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 our internal controls over financial reporting were effective as of December 31, 2006.
Deloitte & Touche LLP has issued an attestation report on management's assessment of internal controls over financial reporting.
NU, CL&P, PSNH and WMECO undertook separate evaluations of the design and operation of their disclosure controls and procedures to determine whether they are effective in ensuring that the disclosure of required information is made timely and in accordance with the Exchange Act and the rules and forms of the SEC. This evaluation was made under the supervision and with the participation of management, including the companies' principal executive officers and principal financial officer, as of the end of the period covered by this Annual Report on Form 10-K. The principal executive officers and principal financial officer have concluded, based on their review, that the companies' disclosure controls and procedures are effective to ensure that information required to be disclosed by the companies in reports that it files under the Exchange Act i) is recorded, processed, summarized, and reported within the time periods specified in SEC rules and forms and ii) is accumulated and communicated to management including the principal executive officers and principal financial officer, as appropriate to allow timely decisions regarding required disclosure.
There have been no changes in internal controls over financial reporting for NU, CL&P, and PSNH during the quarter ended December 31, 2006 that have materially affected, or are reasonably likely to materially affect internal controls over financial reporting. There was a material change in WMECO's internal controls over financial reporting in the fourth quarter due to enhancements made to WMECO's controls related to supplier load/usage reporting to ISO New England. WMECO reports to ISO New England the suppliers' hourly loads/usage aggregated for customers on competitive supply or WMECO's default service.
Item 9B.
Item 9B. Other Information
No information is required to be disclosed under this item at December 31, 2006, as this information has been previously disclosed in applicable reports on Form 8-K during the fourth quarter of 2006.
Part III
Item 10.
Item 10. Directors, and Executive Officers and Corporate Governance
The information in Item 10 is provided as of February 13, 2007 except where otherwise indicated.
NU
In addition to the information provided below concerning the executive officers of NU, incorporated herein by reference is the information contained in the sections "Election of Trustees," "Board Committees and Responsibilities," "Selection of Trustees," and "Section 16(a) Beneficial Ownership Reporting Compliance" of the definitive proxy statement for solicitation of proxies by NU's Board of Trustees, to be dated March 20, 2007, which will be filed with the Commission pursuant to Rule 14a-6 under the Securities Exchange Act of 1934.
Name
Positions Held
Gregory B. Butler
SVP, GC
Lawrence E. De Simone (1)
P
Cheryl W. Grisé (2)
EVP
David R. McHale
SVP, CFO
Leon J. Olivier (3)
EVP
Charles W. Shivery (4)
CHB, P, CEO, T
Shirley M. Payne (5)
VP, CONT
CL&P
Name
Positions Held
Gregory B. Butler
SVP, GC
Cheryl W. Grisé (2)
OTH
David R. McHale
SVP, CFO
Raymond P. Necci
P, COO, D
Leon J. Olivier (3)
CEO, D
Charles W. Shivery (4)
C, D
Shirley M. Payne (5)
VP, CONT
PSNH
Name
Positions Held
Gregory B. Butler
SVP, GC
Cheryl W. Grisé (2)
OTH
Gary A. Long
P, COO, D
David R. McHale
SVP, CFO, D
Leon J. Olivier (3)
CEO, D
Charles W. Shivery (4)
C, D
Shirley M. Payne (5)
VP, CONT
WMECO
Name
Positions Held
Gregory B. Butler
SVP, GC
Cheryl W. Grisé (2)
OTH
David R. McHale
SVP, CFO, D
Leon J. Olivier (3)
CEO, D
Rodney O. Powell
P, COO, D
Charles W. Shivery (4)
C, D
Shirley M. Payne (5)
VP, CONT
(1)
Served as President-Competitive Group of NU until January 1, 2007, when he retired.
(2)
Serves as Executive Vice President of NU. Resigned as Chief Executive Officer and Director of CL&P, PSNH and WMECO effective January 15, 2007.
(3)
Serves as Executive Vice President - Operations of NU. Elected Chief Executive Officer of CL&P, PSNH and WMECO effective January 15, 2007.
(4)
Serves as Chairman of the Board, President and Chief Executive Officer and a Trustee of NU. Elected Chairman and a Director of CL&P, PSNH and WMECO effective January 19, 2007.
(5)
Became an executive officer of NU upon election as Vice President-Accounting and Controller, effective February 13, 2007. Became an executive officer of CL&P, PSNH and WMECO upon election as Vice President-Accounting and Controller, effective January 29, 2007.
Key:
C
-
Chairman
CONT
-
Controller
CEO
-
Chief Executive Officer
CFO
-
Chief Financial Officer
CHB
-
Chairman of the Board
COO
-
Chief Operating Officer
D
-
Director
EVP
-
Executive Vice President
GC
-
General Counsel
OTH
-
Executive Officer of Registrant because of policy-making function for NU System
P
-
President
SVP
-
Senior Vice President
T
-
Trustee
VP
-
Vice President
Name
Age
Business Experience During Past 5 Years
Gregory B. Butler
Senior Vice President and General Counsel of NU since December 1, 2005 and of CL&P, PSNH and WMECO since March 9, 2006, and a Director of Northeast Utilities Foundation, Inc. since December 1, 2002; previously Senior Vice President, Secretary and General Counsel of NU from August 31, 2003 to December 1, 2005; Vice President, Secretary and General Counsel of NU from May 1, 2001 through August 30, 2003.
Lawrence E. De Simone
Retired as of January 1, 2007; previously served as President-Competitive Group of NU and President of NU Enterprises, Inc., from October 25, 2004 to December 31, 2006 and Chairman, President and Chief Executive Officer of Select Energy, Inc. from February 1, 2005 to December 31, 2006; previously Executive Vice President - Regulated Business and Services of PPL Corporation from January 1, 2004 to August 31, 2004; Executive Vice President - Supply of PPL Corporation from October 2001 to December 31, 2003.
Cheryl W. Grisé (*)
Executive Vice President of NU since December 1, 2005; Chief Executive Officer of CL&P, PSNH and WMECO from September 10, 2002 to January 15, 2007, a Director of CL&P from May 1, 2001 to January 15, 2007, PSNH from May 14, 2001 to January 15, 2007 and WMECO from June 2001 to January 15, 2007, and a Director of Northeast Utilities Foundation, Inc. since September 23, 1998; previously President - Utility Group of NU from May 2001 to December 1, 2005.
Gary A. Long (**)
President and Chief Operating Officer and a Director of PSNH since July 1, 2000.
David R. McHale
Senior Vice President and Chief Financial Officer of NU, CL&P, PSNH and WMECO since January 1, 2005 and a Director of PSNH and WMECO since January 1, 2005 and CL&P since January 15, 2007; previously Vice President and Treasurer of NU, WMECO and PSNH from July 1998 to December 31, 2004.
Raymond P. Necci
President and Chief Operating Officer and a Director of CL&P since January 17, 2005. Previously Vice President - Utility Group Services of NUSCO from January 1, 2002 to January 16, 2005.
Leon J. Olivier
Executive Vice President-Operations of NU since February 13, 2007; Chief Executive Officer of CL&P, PSNH and WMECO since January 15, 2007; Director of PSNH and WMECO since January 17, 2005 and a Director of CL&P since September 2001. Previously Executive Vice President of NU from December 1, 2005 to February 13, 2007; President - Transmission Group of NU from January 17, 2005 to December 1, 2005; President and Chief Operating Officer of CL&P from September 2001 to January 2005.
Shirley M. Payne
Vice President - Accounting and Controller of NU since February 13, 2007, and CL&P, PSNH and WMECO since January 29, 2007. Previously Vice President, Corporate Accounting and Tax of TECO Energy, Inc. from July 2000 to January 26, 2007 and Tax Officer of Tampa Electric Company from April 1999 to January 26, 2007.
Rodney O. Powell
President and Chief Operating Officer and a Director of WMECO since January 1, 2005. Previously Vice President - Customer Relations of CL&P from January 1, 2002 to December 31, 2004.
Charles W. Shivery
Chairman of the Board, President and Chief Executive Officer of NU since March 29, 2004; Chairman and a Director of CL&P, PSNH and WMECO since January 19, 2007. Previously, President (interim) of NU from January 1, 2004 to March 29, 2004 and a Director of Northeast Utilities Foundation since March 3, 2004; previously President - Competitive Group of NU and President and Chief Executive Officer of NU Enterprises, Inc., from June 2002 through December 2003.
(*)
Mrs. Grisé is a Director of MetLife, Inc. and Dana Corporation.
(**)
Mr. Long is a Director of Citizens Bank-NH.
There are no family relationships between any director or executive officer and any other director or executive officer of NU, CL&P, PSNH or WMECO.
NU, CL&P, PSNH, WMECO
Each of the registrants has adopted a Code of Ethics for Senior Financial Officers (Chief Executive Officer, Chief Financial Officer and Controller) and a Standards of Business Conduct which is applicable to all Directors, officers, employees, contractors and agents of NU, CL&P, PSNH and WMECO. The Code of Ethics and the Standards of Business Conduct have both been posted on Northeast Utilities' web site and are available at http://www.nu.com/investors/corporate_gov/default.asp on the Internet. Information pertaining to amendments and waivers from the Code of Ethics will be posted at this site.
Printed copies of the Code of Ethics and the Standards of Business Conduct are also available to any shareholder without charge upon written request mailed to:
Ms. Kerry J. Kuhlman
Vice President and Secretary
Northeast Utilities Service Company
P.O. Box 270
Hartford, CT 06141
CL&P obtains audit services from the independent registered public accounting firm engaged by the Audit Committee of NU's Board of Trustees. CL&P does not have its own audit committee or, accordingly, an audit committee financial expert.
Certain information called for by Item 10 is omitted for PSNH and WMECO pursuant to Instruction I (2)(c) to Form 10-K (Omission of Information by Certain Wholly Owned Subsidiaries).
Item 11.
Item 11. Executive Compensation
COMPENSATION DISCUSSION AND ANALYSIS
OVERALL OBJECTIVES OF EXECUTIVE COMPENSATION PROGRAM
The fundamental objective of our Executive Compensation Program is to motivate executives and key employees to support our strategy of investing in and operating businesses to benefit customers, employees, and shareholders. As a public company, we are responsible to our shareholders to provide a fair return on their investment. As a holding company for several regulated utilities, we are also responsible to our franchise customers to provide products reliably, safely, with respect for the environment and our employees, and at a reasonable cost.
The Executive Compensation Program supports its fundamental objective through the following design principles:
·
Attract and retain key executives by providing total compensation competitive with that of other executives employed by companies of similar size and complexity. The program benchmarks peer companies to ensure that compensation opportunities are competitive and capable of attracting and retaining executives with the experience and talent required to achieve our strategic objectives. As we continue to grow and improve our transmission, distribution, and regulated generation systems, having the right talent will be critical.
·
Establish performance-based compensation that balances rewards for short-term and long-term business results. The program motivates executives to run the business well in the short term, while executing the long-term business plan to benefit both our customers and shareholders. The program aims to strike a balance between the short- and long-term programs so that they work in tandem. It also ensures that long-term objectives are not sacrificed to achieve short-term goals or vice versa.
Incentive plan performance criteria are based on a combination of financial, operational, stewardship, and strategic goals that are essential to the achievement of our business strategies. This linkage to critical goals helps to align executives with our key stakeholders-customers, employees, and shareholders. The long-term program also compares performance relative to a group of comparable utility companies.
·
Reward corporate and individual performance. Overall compensation has many metrics based on corporate performance but is also highly differentiated based on individual performance. The annual incentive program rewards both team performance (measured by adjusted net income) and individual performance (including individualized financial, operational and strategic metrics). Long-term incentives (LTI) are comprised of a Performance Cash Program and restricted share units (RSUs). The Performance Cash Program pays out based on the achievement of corporate goals (cumulative net income, average return on equity, average credit rating and relative total shareholder return). The ultimate value of RSUs is based on corporate total shareholder return, but the size of RSU grants reflects individual performance and contribution.
·
Encourage long-term commitment to the Company. Utility companies provide a public service and have a long-term commitment to ensure that customers receive reliable service day after day. Meeting this commitment requires specialized skills and institutional knowledge that are learned over time through local industry experience. These skills include familiarity with the regions and communities that we serve, government regulations, and long-term energy policies. In addition, utility companies rely on long-term capital investments to serve their customers.
As a result, public utilities benefit from long-service employees. We have structured our executive compensation programs to build long-term commitment as well as shareholder alignment. Providing competitive compensation opportunities and offering programs such as RSUs and supplemental retirement benefits that vest and build value over time encourage long-term retention. Executive share ownership guidelines are another program component intended to build long-term shareholder alignment and commitment.
ELEMENTS OF 2006 COMPENSATION
The Executive Compensation Program is composed of base salary, an annual incentive program, long-term incentives (consisting of RSUs and a performance cash program), nonqualified deferred compensation, a supplemental executive retirement plan, officer perquisites, and employment agreements that specify payments and benefits upon involuntary termination and termination resulting from a change in control.
A description and the objective of each element of the Executive Compensation Program are summarized below.
Supplemental Executive Retirement Plan (Supplemental Plan)
Non-qualified pension plan, providing additional retirement income to officers beyond what is provided in our standard defined benefit retirement plan. These include:
·
A defined benefit "make-whole" plan.
·
A supplemental "target" benefit (senior vice presidents and above only)
Note: Above benefits are not available to non-union employees, including executives, hired after 2005
Compensate for IRS limits on qualified plans
Aid in retention of executives and build long-term commitment to the Company
Other Nonqualified Deferred Compensation
Opportunity to defer base salary and annual incentives, using the same investment vehicles as the NU qualified plan, and receive matching contributions otherwise capped by Internal Revenue Code limits on qualified plans
Each year's match vests after 3 years or at retirement
For executives hired after 2005, the Company makes contributions of 2.5%, 4.5% and 6.5%, as applicable based on the relevant bracket for the sum of the officer's age and service with the Company on cash compensation that would otherwise be capped by Internal Revenue Code limits on qualified plans
Aid executives in tax planning by allowing them to defer taxes on certain compensation
Compensate for IRS limits on qualified plans
Provide a competitive benefit
Aid in retention and build long-term commitment to the Company
Perquisites
Financial planning and tax preparation reimbursement benefit
Executive physical examination reimbursement plan
(Financial planning) Encourage use of a professional to maximize ultimate value of compensation and help executives better prepare tax returns
(Physical exam) Encourage executives to undergo regular health checks (minimize the risk of losing critical employees)
Severance/Change-in-Control (CIC) Agreements
All named executive officers have employment agreements specifying benefits and payments upon involuntary termination and termination following a change in control
Mr. Olivier also participates in a "Special Severance Program" that specifies other benefits and payments upon termination resulting from a CIC
Meet competitive expectation of employment
Help focus executive on shareholder interests
Provide income protection in the event of involuntary loss of employment
MIX OF COMPENSATION ELEMENTS
We strive to provide base compensation opportunities at or above the competitive median over time for fully proficient executives (see Benchmarking discussion for how market median is established). Accordingly, our annual and long-term incentive target percentages approximate competitive median incentives for the Chief Executive Officer (CEO) and the other executive officers listed in the Summary Compensation Table below, who we refer to together as "Named Executive Officers" or "NEOs."
As officers move up in the organization, a greater proportion of their total compensation is based on performance with a long-term focus. Historically, LTI has been weighted more significantly than short-term incentives at target, reflecting the longer-term nature of our business plans (1). Accordingly, the NEOs' target LTI opportunities, as a percent of base salary, are slightly higher than the survey data (2) that is used to benchmark executive compensation (see the Benchmarking section below for further discussion). Short-term compensation is commensurately lower.
Target annual incentive and LTI opportunities for the CEO are 100% and 300% of base salary, respectively. For the remaining NEOs, target percentages are 65% and 125 to 155%, respectively. All of the incentive compensation elements are at risk. The result is:
BENCHMARKING
The Compensation Committee determines executive officer TDC levels through two steps: Step one is external comparisons; step two interprets the data based on internal considerations. First, the Committee identifies the "market" values of total compensation and individual components of pay (e.g., base salaries, annual incentives and long-term incentives).
We changed our business model in 2005 from a mix of competitive and regulated businesses to a solely regulated business. Accordingly, the Committee adjusted the set of companies selected for executive pay comparisons. For market comparisons, we consider the following sources:
·
Utility and general industry survey data (primary market comparison). We use this data as the primary market data for determining pay levels and incentive opportunities since these surveys include a diverse group of companies representative of our market for talent. Survey data is adjusted to reflect companies and business units of similar size. Utility-specific positions (i.e., EVP-NU, Utility Group and EVP-NU, Transmission Group) are compared to utility market values only. General industry comparisons are blended on a 50/50 basis with utility industry comparisons only for positions that have counterparts in general industry (our Chairman of the Board, President and CEO; SVP and CFO; and SVP and General Counsel).
·
Customized peer group data (secondary reference only). We evaluate the pay opportunities provided by a customized group of utility peers of similar size, and complexity. Data are provided to the Committee for those positions only where there is a title match (i.e., the CEO, CFO, and General Counsel). For 2006, this group included the following 17 companies: Allegheny Energy Inc., Alliant Energy, Ameren Corp., Centerpoint Energy Inc., Consolidated Edison Inc., DTE Energy, Energy East, KeySpan
(1)
In 2006, Mr. Olivier's and Mrs. Grisé's long-term incentive targets were exceptions and vary from the 150% of base salary target typically provided at their level. Mrs. Grisé had a long-term incentive target of 155% of salary, which was grandfathered from an older agreement, and Mr. Olivier accepted a 125% target because of his special retirement benefit.
(2)
Survey data long-term opportunity is based on the present value (e.g. Black-Scholes methodology for options) of actual LTI grants.
(3)
RSUs are granted based on annual performance, but vest over time based on continued service.
Energy, NiSource, Inc., NSTAR, Pepco Holdings Inc., Pinnacle West Capital Corp., Puget Energy, Inc., SCANA Corp., Sierra Pacific Resources, Wisconsin Energy Corp., and Xcel Energy Inc. The Committee uses this group for insights into peer incentive design practices and as a secondary reference regarding specific peer company pay levels. In 2006, the Committee also used this group for performance comparisons under the Performance Cash Plan (as described below in the Long-Term Incentive Program section).
For 2007, the Compensation Committee's consultant further refined the customized peer group to reflect: 1) utility companies that are mostly regulated with revenues between $2.5 and $12 billion (median for the group is $5.6 billion), and 2) less regulated utility companies closer in size to NU, with revenues between $3 billion and $7 billion. The less-regulated companies represent potential sources of talent, even if they are not direct performance peers. As a result, we added seven companies to the peer group, including CMS Energy, Great Plains Energy, OGE Energy, PG&E, PPL Corporation, Progress Energy, and TECO Energy. We removed Keyspan from the group since it is being acquired. We also removed DTE because of its concentration of unregulated businesses.
The changes in the peer group's composition did not result in any significant differences in competitive pay opportunities, nor did it lead the Compensation Committee to make any changes in our compensation structure. However, the group is now more inclusive of all the companies that fit the size and business mix criteria defined above. While the peer group has been refined for pay comparison purposes, we will continue to use the 2006 peer group (minus Keyspan and DTE) for comparison of performance since we believe that the best yardstick for performance results are mostly-regulated utilities.
Once the market values have been determined, we interpret the market data in the context of the strategic importance of different positions and internal equity considerations. The Committee periodically adjusts the target percentages of short-term and long-term incentives to keep them representative of market median levels. Targeted levels are adjusted over time, and care is taken to avoid sudden, drastic moves.
Supplemental benefits are also targeted to provide market-based opportunities to the executive. We provide perquisites to the extent they serve business purposes. We conduct periodic reviews of market benefits and perquisites using utility and general industry surveys (and at times, information from that year's customized peer group). Benefits are occasionally adjusted to maintain market parity. We last reviewed our supplemental retirement practices in 2005 and 2006, as described in more detail in the Supplemental Benefits section below. When the market indicates a reduction in benefits as a prevalent practice (e.g., elimination of defined benefit pension plans), such reductions have been applied to new officers only.
BASE COMPENSATION
The Compensation Committee reviews and approves executive officers' salaries annually, setting salaries for each executive officer at levels considered to be reasonable and fair and reflective of the strategic importance of the position, level of responsibility, skills and experience of the incumbent, and individual performance.
In adjusting salaries, the Committee considers the following:
·
Annual individual performance appraisals
·
Market pay movement (as gleaned from the benchmarking exercise described above)
·
Market pay positioning (as extracted from position-specific survey and proxy data)
·
Incumbent experience and time-in-position at the Company
·
Shifts in corporate focus with respect to strategic importance of a position
·
Internal equity
Individuals who are performing well in highly strategic positions are likely to have their base salaries increased more quickly than individuals in other roles. From time-to-time, weak corporate performance has prompted salary increases to be postponed, but the Committee prefers to reflect subpar corporate performance through the variable pay components.
Based on these considerations, the Compensation Committee approved base salary increases of 3.5% in 2006 for Ms. Grisé, Mr. Olivier, and Mr. Butler. The Compensation Committee approved larger increases of 11.9% and 36.4%, respectively, for Messrs. Shivery and McHale because, as newer executive officers, they had salaries below median, and the Compensation Committee wanted to move their salaries closer to median after they demonstrated strong performance in their roles.
INCENTIVE COMPENSATION
Our incentive plan includes both the annual and LTI programs. Our shareholders approved the incentive plan in 1998 and 2003. The plan preserves the tax-deductibility offered under Section 162(m) of the Internal Revenue Code (Code), which allows companies to deduct compensation for the CEO and certain other executives above $1 million only if it qualifies as "performance based."
Incentive awards are subject to objective financial performance goals established by the Compensation Committee with the advice of the Finance Committee. Metrics are adjusted from year to year depending on our business focus for the period. Metrics have been adjusted more in recent years as we have been transforming ourselves back into a mostly regulated utility. Consistent with the requirements of Section 162(m), the Compensation Committee reports to the Board of Trustees each year the extent to which the performance objectives have been achieved.
The Committee approves individual awards based on performance achieved. Incentive award payments are made only to the extent that those objective financial performance goals are met. As discussed in more detail below relative to the annual program, the Committee may exercise discretion around performance against individual goals, as long as overall financial performance has been met. At the time of RSU grants, the Committee exercises discretion regarding the size of grants based on the previous year's performance.
Annual Incentive Program
Target incentive opportunities under the annual incentive program are established for the CEO and the other NEOs as a group as described in the Mix of Compensation Elements section above. Annual incentive awards may equal up to two times target when superior financial and operational results are achieved, but do not pay out when performance is below threshold levels. The opportunity to earn up to two times target reflects the Compensation Committee's belief that officers have a significant ability to affect performance outcomes.
Goals include a team goal and individual goals, as described below.
Team Goal
For Mr. Shivery and the other NEOs, the team goal is based on corporate Adjusted Net Income (ANI), defined as net income excluding the effect of certain nonrecurring income and expenses. ANI was selected because it serves as an indicator of ongoing operating performance. The nonrecurring income and expenses that were excluded included items generally outside the control of management and/or related to a decision by the Compensation Committee not to penalize executives for making correct strategic business decisions (e.g., the divestiture of the competitive business).
For 2006, there were two sets of excludable items. Items in the first set were completely excluded and included the following:
Items in the second set were excluded at 85% of their value because the Committee believed they had a disproportionate effect on 2006 net income relative to management's influence over their outcome:
The Compensation Committee approved all final exclusions. The final ANI value was calculated by taking reported net income with adjustments for the dollar value of the exclusions noted above. The number of exclusions reflects the complexity of our business as we transition from mixed competitive and regulated business to a mostly regulated utility. In the event NU's earnings were restated as a result of noncompliance with accounting rules caused by fraud or misconduct, the Sarbanes-Oxley Act of 2002 requires the chief executive officer and chief financial officer to reimburse the Company for certain incentive compensation they had received. NU's Amended Incentive Plan contains a similar but broader provision requiring all employees to reimburse or forfeit their incentive compensation to the extent the Board determined their misconduct or fraud caused such a restatement, which would be invoked to the extent the Sarbanes provision were not applicable. To date, there have been no instances in which either the Sarbanes provision or the new provision in the Amended Incentive Plan would apply
Individual Goals
Individual goals include a combination of key financial, operational, stewardship, and strategic metrics that are drivers of overall corporate performance. Individual goal categories for the NEOs are detailed in the goal weightings table below. Individual goals do not result in payment of an award if a threshold level of ANI is not achieved. For 2006, the ANI threshold was based on NU corporate ANI for the CEO, CFO, and General Counsel and on Utility Group and Transmission Group ANI for Ms. Grisé and Mr. Olivier, respectively. The threshold is defined as 25% below target ANI performance. (This threshold complies with section 162(m) of the Code).
Full incentive plan funding occurs once we achieve the ANI threshold. Actual payouts are determined with reference to attainment of individual goals and corporate goals exercising discretion in a manner which comports with Internal Revenue Code rules under Code Section 162(m) (that is, to assure that the incentive is "qualified performance based compensation" therefore avoiding the $1 million deductibility cap). In no case may an officer receive more than two times target for the individual portion of the incentive award. The Compensation Committee recommends to the Board of Trustees the amount of any award for the CEO. For the remaining NEOs, the CEO recommends awards to the Compensation Committee for its approval.
Goal Weightings for 2006
The table below provides the weighting of team and individual goals for the NEOs for 2006. These weightings communicate the Compensation Committee's intention of balancing the need for teamwork across the organization with individual accountability. During 2006, Mr. De Simone had a unique role as the head of a business unit (the competitive business) that NU was in the process of exiting. Considering this unusual role and his responsibility in transitioning out of the competitive business, Mr. De Simone's entire incentive award was based on individual goals to keep focus on the factors that would help lead to a successful strategic transition. Individual goal weightings more typically range from 40% to 60%, as is the case for all other NEOs.
In 2006, the annual incentive thresholds were designed to reward performance on a more "localized" level. They were intended to recognize the distinctions among, and individual performance of, the distribution, transmission, and competitive business groups at a time when the organization was going through a restructuring, and we needed each unit to avoid distraction and maximize its own business results. As a result, Ms. Grisé and Mr. Olivier had thresholds based on their own businesses' performance.
2006 Financial Thresholds and Goals
Annual goals for 2006 were based on the first year of the multi-year business plan adopted by the Board. As shown in the table below, maximum and minimum performance levels were set at 15% above and below the target performance level, respectively. As mentioned above, the individual goal threshold was set 25% below target. At this threshold, the individual goal portion of the incentive may be paid.
The Compensation Committee determines appropriate stretch around the targets based on the following factors:
·
An assessment of the potential volatility in results
·
The degree of difficulty in achieving target
·
Minimum, and maximum goals
·
The minimum acceptable ANI.
Annual incentive program financial thresholds and goals for 2006 are shown below.
2006 Results
Each NEO was awarded annual incentives for the 2006 program based on the achievement of the corporate ANI goal and individual goals. The corporate ANI goal result was near maximum. The Utility Group and Transmission Group ANI results exceeded the threshold levels; consequently, all NEOs received a payment for individual goals. The CEO's performance against individual goals was assessed at 175% of target, reflecting the successful execution of the Company's strategic plan, including the exit from its competitive business, notably the sale of its generation plants, and significant progress in building the expanded transmission infrastructure. In combination with the corporate ANI goal results, the CEO's overall incentive payment was set at 185% of target. Performance measured against individual goals for each of the other NEOs was above target in aggregate, which, when combined with corporate ANI performance for all but Mr. De Simone, resulted in incentive payments from 129% to 172% of target. As stated in Goal Weightings for 2006, Mr. De Simone's incentive payment was determined solely on the basis of individual goals focused on the competitive business.
2007 Design Changes
For 2007, the Compensation Committee changed three aspects of the annual incentive program in recognition that our transition to a mostly regulated utility is largely complete. These changes, which are described below, also simplify the program.
1.
Individual goal thresholds for all NEOs will be based on Corporate (as compared to Business Unit) ANI. This change encourages teamwork by emphasizing performance of the overall Company rather than separate business groups.
2.
The number of ANI adjustment categories will be modified and reduced to include adjustments for only:
o
Accounting or tax law changes
o
Unusual IRS or regulatory issues
o
Unexpected costs related to nuclear decommissioning
o
Unexpected costs related to environmental remediation at the Holyoke Water Power Company
o
Divesture or discontinuance of a segment or component of the Company's business
o
ConEd settlement or court decision
o
NUEI mark-to-market impacts
o
Unbudgeted charitable contributions
o
Impairments on goodwill booked more than five years before the incentive program's performance period began.
3.
The payout range will be narrowed to 10% above and below the target goal, and the payout at minimum goal point will change to 50% of target. The narrower performance range is now appropriate due to the change in risk profile resulting from the exit from the NUEI businesses. Similarly, the threshold performance level for individual goal payout was changed to 20% below target ANI.
Long-Term Incentive Program
Target incentive opportunities under this program are established for the CEO and the other NEOs as a group as described in the Mix of Compensation Elements section above. The target opportunity for each participant is stated as a percentage of base pay at the time of the grant. One-half of the target LTI value is awarded in restricted share units (RSUs), and one-half is granted as Performance Cash (see discussion of each element below). This mix balances internal financial performance with total shareholder return. The Compensation Committee chose RSUs as the equity incentive vehicle because utilities create value for shareholders not only through stock price appreciation, but also through dividends.
The LTI program rewards aggregate financial and total shareholder return performance over time; the annual incentive program reflects critical annual operating plans. The two programs work in tandem, such that achievement of annual goals moves the Company towards attainment of our long-term financial goals.
Restricted Share Units (RSUs)
Each RSU is equal to the value of one share of our common stock. In 2006, NU granted RSUs that vest equally over three years. Participants earn dividend equivalents on the RSUs that have been granted, but these dividend equivalents are calculated as reinvested shares of Company stock until the related RSUs vest.
The Compensation Committee establishes a pool for RSU grants annually at the beginning of each year based on performance for the prior year. The pool concept adds a performance component to the RSU program. At the Compensation Committee's discretion, the RSU pool is adjusted up or down from the target level based on three factors: 1) Company performance in the prior year, 2) the contribution by the executives to NU's longer-term strategic direction, and 3) the need to motivate future performance. Each executive officer receives an RSU grant from the RSU pool reflecting his or her individual performance and contribution. Adjustments to the RSU pool, and therefore to individual grants, will have the effect of raising or lowering NU's positioning versus peer companies' pay opportunities.
In 2005, at the Compensation Committee's March 1 meeting, the RSU pool was reduced to 76% of target based on disappointing 2004 results in the competitive businesses. The CEO received a grant at 75% of target, and the other NEOs received grants between 65% and 85% of target. In 2006, at the Committee's February 14 meeting, the CEO and CFO were granted RSUs at 125% of target. These awards recognized their efforts to reposition the Company and a successful large equity offering in the fourth quarter of 2005. The other NEOs were granted RSUs at target.
As to the timing of grants:
·
All grants are approved by the Committee.
·
All grants are made on date of the Committee meeting at which they were approved.
·
Grants are not timed to take advantage of material, non-public information.
2006 Results/2007 Pool
The 2007 RSU pool for executives was set at 147% of target. This upward adjustment to the pool reflects the Company's superior financial performance in 2006 as well as the significant progress in its transformation to an entirely regulated business. In recognition of their significant contributions, the CEO received a grant at 175% of target, and Messrs. Butler, McHale, and Olivier received grants of between 130% and 150% of target. Neither Mrs. Grisé nor Mr. De Simone received RSU grants because of their retirements.
2007 Design Changes: Share Ownership Guidelines
Except for the CEO, payment of half of any vested RSUs, prior to, and through 2006, was deferred an additional four years beyond vesting. For the CEO, payment of all of the vested units was deferred until after retirement. This deferral feature was intended to foster executive share ownership.
Beginning in 2007, the Compensation Committee simplified the RSU program to eliminate the deferral feature and introduce share ownership guidelines instead. The share ownership guidelines reinforce the importance of building NU share ownership among senior executives in a way that more actively involves the executives. Executives will be able to receive all RSU shares upon vesting, rather than deferring half for an additional four years. As a consequence, executives will be taxed upon vesting on all shares versus receiving the benefit of tax deferral on a portion of their awards for an additional four years.
The following share ownership guidelines for NEOs took effect January 1, 2007. The guidelines are equivalent to approximately six-times base salary for the CEO and three-times base salary for the other NEOs:
Executives have five years to attain these levels, although most NEOs currently are at, or close to, these ownership levels. RSUs, shares held in individual 401(k) accounts, and shares owned outright count toward the ownership guidelines. Stock options do not count toward the ownership guidelines.
As of the last trading day in 2006, the CEO's ownership requirement will place his ownership above the prevalent proxy peer standard for CEOs of five-times base salary. In order to allow NU to preserve the tax deduction on his RSU grants under Section 162(m), Mr. Shivery has elected to continue to defer all of his RSUs until one year after retirement, as long as it is beneficial to the Company (see Tax and Accounting Considerations section, below).
Performance Cash Program
The Performance Cash Program is a three-year performance program, with a new performance cycle beginning every year.
2004-2006 Cycle
Performance Cash Program goals are set based on NU's three-year strategic operating plan at the beginning of each cycle.
In the 2004 to 2006 cycle, the Performance Cash Program was based exclusively on Cumulative Net Income (excluding pension income or expense). Significant losses in the competitive business in 2004 and 2005 resulted in no payouts for the 2004-2006 Performance Cash Program. NU began exiting the competitive businesses during this performance cycle, which exacerbated losses when divestiture accounting rules were applied.
Program Changes Beginning with the 2005-2007 Cycle
Beginning with the 2005 to 2007 performance cycle, the Compensation Committee changed two aspects of the Performance Cash Program to better reflect the Company's strategic redirection to a mostly regulated utility.
·
First, the Cumulative Net Income definition was adjusted to specifically exclude certain net income effects of the competitive businesses (4). This change was designed to motivate executives working to reposition NU in the new strategic direction as a mostly regulated company.
·
Second, the metrics were expanded to include three additional objectives:
(4)
In addition, pension income or expense was excluded for the 2005 to 2007 performance cycle.
1.
Average ROE, defined as the average of the annual Return on Equity for the three years during the Performance Period. Average ROE is adjusted on the same basis as Cumulative Net Income.
2.
Average credit rating, defined as the time-weighted average daily credit rating by S&P, Moody's, and Fitch (Average Credit Rating). This objective has the additional provision that the Moody's and S&P ratings must remain above investment grade.
3.
Relative total shareholder return versus the 2006 proxy peers described in the Benchmarking discussion above.
Cumulative Net income, Average ROE, and Average Credit Rating are directly related to NU's multi-year business plan for 2006 to 2008. The relative total shareholder return metric reinforces the importance of delivering total shareholder return performance at or above the industry median.
All four metrics are weighted equally, communicating that all of these outcomes are important to investors and critical enablers of NU's ability to execute its transmission build-out and distribution system upgrade. The three internal financial metrics are supplemented by the total shareholder return metric, which is intended to focus executives on delivering results that are ultimately recognized by shareholders as industry-leading. A minimum level of performance must be met for each metric before that portion of the grant will pay out. The minimum performance level results in a payout equal to half of the target award. The plan pays a maximum value of 150% of target when maximum performance goals are achieved. The maximum pay opportunity is set at 150% of target to correspond to typical market practices.
Program Changes for the 2007-2009 Cycle
For the 2007-2009 cycle, cumulative net income will be adjusted to have the same exclusions as in the annual incentive plan beginning in 2007, as described above in 2007 Design Changes. This change will maintain consistency in goals across compensation programs and facilitate simplified performance tracking by program participants going forward.
SUPPLEMENTAL BENEFITS
We provide a range of basic and supplemental benefits that are designed to assist us in attracting and retaining executives critical to our success and to reflect the competitive practices. The Compensation Committee endeavors to adhere to a high level of propriety in managing executive benefits and perquisites. Permanent lodging or personal entertainment is not provided for any executive officer or employee, and our health care and benefit programs offer substantially the same benefits to all full-time employees as they do to executive officers.
Retirement Benefits
We provide retirement income benefits from the Northeast Utilities Service Company Retirement Plan (Retirement Plan) and, for system officers, the Supplemental Executive Retirement Plan for Officers of Northeast Utilities System Companies (Supplemental Plan). Each plan is a defined benefit pension plan, which determines retirement benefits based on Company service, age at retirement, and "plan compensation". Plan compensation for the Retirement Plan, which is a "qualified" plan under the Code, includes primarily base pay and nonofficer annual incentives up to the IRS limits for qualified plans.
The Supplemental Plan adds base pay over the IRS limits, deferred compensation, awards under the executive annual incentive program and, for certain participants, LTI program awards to plan compensation as explained in the narrative accompanying the Pension Benefits Table.
The Supplemental Plan has two parts, as explained below:
The first part is the "make-whole" benefit. This benefit makes up for benefits lost through the application of certain tax code limitations on the benefits that may be provided under the Retirement Plan. For certain participants, it also adds LTI program awards to plan compensation.
The second part is the "target benefit," which is available to all of the NEOs except Mr. Olivier. This benefit supplements the Retirement Plan and make-whole benefits under the Supplemental Plan so that, upon achieving at least 25 years of service, total retirement benefits from these plans equal a target percentage of the annual average of the participant's highest consecutive 36 months of plan compensation (Final Average Compensation). To receive this benefit, a participant must remain in the employ of NU companies until at least age 60 (unless the Board of Trustees sets an earlier age).
The value of the target benefit was reduced in 2005 to reflect changes in competitive practices, which showed a general reduction in the prevalence of defined benefit plans and in the value of special retirement benefits to senior executives. The target benefit for officers who became eligible for the target benefit before February 2005 uses a 60% target formula. For officers who become eligible after January 2005, the benefit uses a 50% target formula. Messrs. Shivery and Butler and Ms. Grisé all have 60% target benefits. Mr. McHale has a 50% target benefit.
Mr. Olivier has separate retirement provisions in lieu of the Supplemental Plan benefits described above for the other NEOs. His retirement provisions were included in his employment agreement to provide a benefit similar to that provided by his previous employer. Based on his agreement, Mr. Olivier will receive a targeted pension value if he meets certain eligibility requirements (see the Pension Benefits Table and accompanying narrative for more details of this arrangement). As noted in the Mix of Compensation Elements discussion above, because of these additional retirement benefits, Mr. Olivier's LTI target and termination benefits are less generous than those provided to other similarly situated officers.
In addition, Mr. Shivery's employment agreement provides for a special total retirement benefit determined with the Supplemental Plan target benefit formula, but with the addition of three years of company service. The benefit is reduced by two percent for each year Mr. Shivery retires before age 65. Mr. Shivery is also eligible upon retirement for the cash value of retirement health benefits (see the Pension Benefits Table and accompanying narrative for more details of these arrangements).
Savings Plan
We also provide an opportunity for employees to save on a tax-favored basis through the Northeast Utilities Service Company 401k Plan (Savings Plan). The Savings Plan is a defined contribution plan. Participants who have six months of service receive matching contributions, not to exceed 3% of base compensation, one-third of which is in the form of cash available for investment in various mutual fund investments and two-thirds of which is in the form of NU common shares (ESOP shares).
Employees hired before 2006 continue to participate in the Savings Plan as well as the defined benefit retirement plans described above. Beginning in 2006, newly-hired non-union employees, including new NU System Officers, also participate in an enhanced defined contribution retirement plan (the K-Vantage benefit) instead of the defined benefit retirement plans. The K-Vantage benefit provides for Company contributions to the Savings Plan of between 2.5% and 6.5% of plan compensation based on age and service. These contributions are in addition to employer matching contributions. Officers hired after 2005 will, likewise, participate only in the K-Vantage benefit as well as a companion nonqualified benefit, described below, that provides defined contribution benefits above the Code limits on qualified plans.
Nonqualified Deferred Compensation Plan
The primary purpose of this plan (Deferral Plan) is to provide employee deferral and Company contributions not available in the Company's 401(k) plan because of the Code limits on qualified plans. Executive officers can defer up to 100% of base salary and annual incentive awards. The Company matches employee deferrals equal to three percent of base pay above the Code limits on qualified plans. The match is "invested" in Company shares and vests at the end of the third year after the calendar year in which the match was earned, or at retirement. Participants can "invest" their deferred amounts in the same investments as are available in the Savings Plan. The Company also makes contributions to this plan equal to the K-Vantage benefit that would have been provided under the Savings Plan but for the Code limits on qualified plans. This nonqualified plan is unfunded. Please see the Nonqualified Deferred Compensation Table and the accompanying notes for more plan details.
Perquisites
It is NU's philosophy that perquisites should be provided to executives as needed for business reasons, and not simply in reaction to prevalent market practice.
Most senior executives, including all NEOs, are eligible for financial planning and tax preparation. This benefit helps ensure that executives seek competent tax advice, better prepare complex tax returns, and leverage the value of the Company's compensation programs. The benefit is $1,500 per year for tax form preparation and $4,000 every two years for financial planning services.
All executives qualify for a special annual physical examination benefit to help ensure serious health issues are detected early. The benefit is a reimbursement of up to $500 for fees incurred beyond those covered by the Company's medical plan.
As required when hiring a new executive, the Company may reimburse executives for certain temporary living and relocation expenses, or provide a lump sum payment in lieu of specific reimbursement. Such expenses are grossed-up for taxes.
When required for a valid business purpose, an executive will be asked that a spouse accompany him or her, in which case spousal travel expenses are reimbursed and grossed-up for taxes.
Tax gross-ups are provided only as described above because of the direct benefit to the corporation when the executive incurs such expense. The impact to the Company of the gross-ups is immaterial.
CONTRACTUAL AGREEMENTS
Each NEO has an employment agreement that specifies details of pay and benefits on an ongoing basis and under certain termination events. These agreements were put in place to foster executive attraction and retention. Involuntary and change in control termination benefits are specified in the agreements in recognition of the higher exposure executives have. The benefits also help ensure executives' continued dedication and objectivity at a time when they might otherwise be concerned about their future employment. In the event of a change in control, the agreement provides for enhanced cash severance benefits upon termination without "cause," as defined in each agreement, or for good reason (constructive termination (5). The Compensation Committee believes that constructive termination is conceptually the same as actual termination without "cause," and potential acquirers would otherwise have an incentive to constructively terminate NEOs to avoid paying severance. Under the NU Incentive Plan rules in place when stock options were granted to NEOS, NEOs who are involuntarily terminated or who terminate for good reason also receive an extension on the expiration date of their vested stock options. The extension of 36 months after termination allows executives to benefit from the shareholder value created by any transaction.
While an NEO must terminate in the event of a change in control in order to receive enhanced cash severance (i.e., a double trigger), the provisions of the incentive plan provide for full vesting of RSUs and full vesting and immediate payout at target for performance cash units whether or not the NEO is terminated, unless the Committee determines otherwise. In addition, the deferred compensation plan provides for immediate vesting of any Company matches, although these matches will be paid according to the schedule defined by the executive's original election.
As part of the change in control severance benefits provided for in their agreements, all NEOs other than Mr. Olivier, will be reimbursed the full amount of any excise taxes imposed on their severance payments and any other payments under Section 4999 of the Code. This "gross-up" is intended to make the executives whole for any adverse tax consequences they may become subject to under the tax law. It also preserves the level of change in control severance protection provided through the employment agreements and other compensation plans. The mechanics and impact of the termination arrangements in the NEOs' agreements are described in more detail in the Potential Payments Upon Termination or Change of Control Tables, appearing further below. Mr. Olivier's severance payments will be cut back to avoid excise taxes.
To help protect the Company after an executive's termination, the employment agreements include non-competition and non-solicitation covenants. The NEOs have agreed not to compete with the Company or solicit talent for a period of two years (one year for Mr. Olivier) after termination.
As discussed in the Supplemental Benefits section above, Mr. Shivery's and Mr. Olivier's contracts also include enhancements to their retirement benefits that were negotiated when they were recruited to the Company.
Mrs. Grisé has announced her plans to retire from the Company on July 1, 2007. In determining the date of her retirement, the Company entered into an agreement in principle with Mrs. Grisé to assure that she would remain with the Company until at least July 1, 2007 in order to ensure an orderly transition of her responsibilities. As part of the agreement in principle, Mrs. Grisé affirmed the commitments previously made under her employment agreement, including an agreement that, for two years following her retirement, she generally may not engage in activities on behalf of certain competitors, solicit certain employees or interfere with the Company's business relationships. In consideration of these factors and the other terms of the agreement in principle, the Company will provide Mrs. Grisé with a special retirement benefit which, when combined with her annual benefit under the Retirement Plan and the Supplemental Plan, will provide an approximate annual benefit of $644,000. Under the agreement in principle, Mrs. Grisé will also be eligible for a lump sum cash payment of roughly $120,000 in lieu of receiving a grant of RSUs or Performance Cash under the 2007-2009 long-term incentive program. The agreement in principle also contains a standard general release of all claims against the Company in connection with Mrs. Grisé's employment.
(5)
Constructive termination is a termination of employment initiated by the executive upon any failure of the Company materially to comply with and satisfy any of the terms of his or her agreement, or to transfer the executive, without his or her consent, to a location that is more than 50 miles from the executive's principal place of business immediately preceding shareholder approval or consummation of a Change of Control.
TAX AND ACCOUNTING CONSIDERATIONS
Tax Considerations. All executive compensation for 2006 was fully deductible to the Company for federal income tax purposes, except for less than $250,000 in RSU gains for Mr. Shivery.
Section 162(m) of the Code limits the tax deduction for compensation paid to a company's CEO and certain other executives. An exception is provided for "performance-based" compensation. The Company's annual incentives and Performance Cash Plan qualify as performance-based compensation under the Code. RSUs do not qualify as performance-based.
Currently, Mr. Shivery is the only NEO to exceed the 162(m) limit. To avoid a lost tax deduction for the Company, he has agreed, for as long as it is beneficial to the Company, to defer receipt of all RSUs until the calendar year following termination of employment, at which time Section 162(m) will no longer be applicable for him. The less than $250,000 in 2006 RSU gains for Mr. Shivery noted above related to RSU grants made before Mr. Shivery began this practice.
Section 409A of the Code provides that amounts deferred under nonqualified deferred compensation plans are includable in an employee's income when vested unless certain requirements are met. If these requirements are not met, employees are also subject to an additional income tax and interest penalties. All of the Company's supplemental retirement plans, severance arrangements, and other nonqualified deferred compensation plans currently meet, or will be amended to meet, these requirements. As a result, employees will be taxed when the deferred compensation is actually paid to them. The Company will be entitled to a tax deduction at that time.
Section 280G of the Code disallows a company's tax deduction for what are defined as "excess parachute payments," and Section 4999 of the Code imposes a 20% excise tax on any person who receives excess parachute payments. As discussed above, NEOs are entitled to certain payments upon termination of their employment, including termination following a change in control of the Company. Under the terms of their contracts, all NEOs other than Mr. Olivier are entitled to tax gross ups in the event of any payment that would be an excess parachute payment. Accordingly, the Company's tax deduction would be disallowed under Section 280G for all excess parachute payments as well as tax gross-ups. Not all of the payments to which NEOs are entitled are excess parachute payments. The amounts of the payments that constitute excess parachute payments are set forth in the tables found in the Potential Payments at Termination or Change of Control section that follows.
NU's share awards are currently structured to accelerate in the event of a change in control, even if the executive remains employed by the Company. Depending on the share price on the date of the change in control and the time remaining until the awards would otherwise have vested, this acceleration could contribute significantly to potential excess parachute payments.
Accounting Considerations. RSUs as disclosed in the Grants of Plan-Based Awards Table are accounted for based on their grant date fair value, as determined under Statement of Financial Accounting Standards No. 123(R), which is recognized over the service period, which is the three-year vesting period applicable to the RSUs. Assumptions used in the calculation of this amount are included in the Management's Discussion and Analysis and Results of Operations section of our annual report to shareholders for the fiscal year ended December 31, 2006 as incorporated by reference in this Form 10-K. Forfeitures are estimated, and the compensation cost of the awards will be reversed if the employee does not remain employed by the Company throughout the three-year vesting period. Performance Cash Program payments are accounted for on a variable basis based on the most likely payment outcome.
COMPENSATION COMMITTEE REPORT
The Compensation Committee of the Northeast Utilities Board of Trustees ("Compensation Committee" and "Board of Trustees," respectively) has reviewed and discussed the Compensation Discussion and Analysis required by Item 402(b) of Regulation S-K with Northeast Utilities management. Based on this review and discussion the Compensation Committee has recommended to the Board of Trustees that the Compensation Discussion and Analysis be included in this annual report for each registrant.
The Compensation Committee
E. Gail de Planque, Chair
Sanford Cloud, Jr.
Robert E. Patricelli, Vice Chair
James F. Cordes
Richard R. Booth
Elizabeth T. Kennan
Dated: February 20, 2007
SUMMARY COMPENSATION TABLE
The table below summarizes the total compensation paid or earned by our President/Chief Executive Officer, Chief Financial Officer and four most highly compensated executive officers other than the Chief Executive Officer and Chief Financial Officer (collectively, the "named executive officers"). As explained in the footnotes below, the amounts reflect the economic benefit to each named executive officer of the compensation item paid or accrued on his or her behalf for the fiscal year ended December 31, 2006.
(1) Amounts reported in the Salary column include amounts deferred by Messrs. Shivery and Olivier and Mrs. Grisé under the Deferral Plan, as set forth in the Executive Contributions in the Last Fiscal Year column of the Non-Qualified Deferred Compensation Plans Table.
(2) No discretionary bonus awards were made to any of the named executive officers in the fiscal year ended December 31, 2006.
(3) Amounts reported in the Stock Awards column reflect the dollar amount recognized for financial statement reporting purposes for the fiscal year ended December 31, 2006, in accordance with the treatment of time-based RSU and restricted share grants under generally accepted accounting principles. The amounts therefore reflect the accounting expense of awards granted in and prior to 2006. Assumptions used in the calculation of this amount are set forth in section 6D of the Management's Discussion and Analysis and Results of Operations section of our annual report to shareholders for the fiscal year ended December 31, 2006 as incorporated by reference in this 2006 Form 10-K. In 2005 and 2006, all named executive officers were awarded RSUs as long-term incentive compensation, which vest over three years, with 50 percent payable at vesting and 50 percent payable four years after vesting, with the exception of RSUs awarded to Mr. Shivery, which vest over three years and are payable after retirement. Dividends on RSUs are reinvested, and additional shares added as a result of reinvestment are vested and paid on the same schedule as the related restricted share units. In 2004, Messrs. Shivery, McHale, Olivier and Butler and Mrs. Grisé were awarded RSUs as long-term incentive compensation, which vest over four years, with 50 percent payable at vesting and 50 percent payable four years after vesting. In 2004 Mr. Shivery and Mrs. Grisé received RSU grants vesting over three years, in partial payment of their awards under the 2003 Annual Incentive Program. In addition, Mr. Shivery was awarded 25,000 restricted shares in 2004, upon his appointment as Chairman, President and Chief Executive Officer; these shares vest over four years, and dividends are paid out during the vesting period. In 2003 Messrs. Shivery, McHale, Olivier and Butler and Mrs. Grisé were awarded restricted shares as long-term incentive compensation, which vest over four years; dividends on these restricted shares are paid out during the vesting period. Mr. De Simone's RSUs were vested on a prorated basis for time worked in 2006 in connection with his retirement on January 1, 2007. Additional information regarding Mr. De Simone's retirement is available in the Post-Employment Compensation Table prepared for Mr. De Simone.
(4) No option awards were made to any of the named executive officers in the fiscal year ended December 31, 2006.
(5) Amounts reported in the Non-Equity Incentive Plan Compensation column represent the payment to the named executive officers of short-term incentives under the 2006 Annual Incentive Program. Under the 2006 Annual Incentive Program, performance goals were communicated during the first 90 days of 2006 to each officer by the CEO or, in the case of the CEO, by the Chairman of the Compensation Committee. Satisfaction of these performance goals was determined by the Compensation Committee (based on input from the CEO, in the case of officers other than the CEO) in February 2007 with reference to minimum, target and maximum goal achievement.
(6) Amounts reported in the Change in Pension Value and Non-Qualified Deferred Compensation Earnings column include the actuarial increase in the present value from December 31, 2005 to December 31, 2006 of the named executive officer's accumulated benefits under all pension plans established by the Company determined using interest rate and mortality rate assumptions as set forth in section 6 of the Management's Discussion and Analysis and Results of Operations section of our annual report to shareholders for the fiscal year ended December 31, 2006 as incorporated by reference in this 2006 Form 10-K. The named executive officer may not be fully vested in such amount. More information on this topic is set forth in the notes to the Pension Benefits Table, appearing further below. There were no above-market earnings on deferrals that were required to be reported in this column.
According to the terms of Mr. De Simone's employment agreement, accruals for Mr. De Simone under the Supplemental Plan accelerated upon his January 1, 2007 retirement to provide for the benefit due under the agreement. The change in pension accrual in 2006 for Mr. De Simone reported in this column represents the remainder required to be accrued in the fiscal year ended December 31, 2006 to provide this benefit.
(7) Amounts reported in the All Other Compensation column include matching contributions ($6,600 for each officer) allocated by the Company to the account of each of the named executive officers under the Savings Plan, and Company matching contributions under the Deferral Plan for the named executive officers who deferred part of their salary in the fiscal ended December 31, 2005 (Mr. Shivery-$19,249, Mrs. Grisé-$9,334, and Mr. Olivier-$5,758) and tax gross-up (Mr. Shivery- $3,614, Mrs. Grisé-$463, Mr. De Simone-$557, Mr. Olivier-$1,335, and Mr. Butler-$477). Except for Mr. Shivery, whose total also includes spousal travel and a cell phone allowance, the aggregate of perquisites received by any named executive officer was less than $10,000, and therefore was not reportable.
(8) Mrs. Grisé served as Chief Executive Officer of CL&P, PSNH and WMECO until January 15, 2007.
(9) In connection with Mr. De Simone's January 1, 2007 retirement, he is entitled to receive various payments pursuant to the terms of his employment agreement, such payments to be delayed until July 1, 2007, with interest accruing from January 1, 2007 through June 30, 2007, as follows: (i) a lump sum payment of $19,946 representing the present value of eighteen months of Company health care contributions; (ii) a one-time severance payment of $811,162 in consideration for a general release, and (iii) a one-time payment of
$811,162 in return for his covenant not to compete for a period of two years. Additional information is set forth in the Post-Employment Compensation Table prepared for Mr. De Simone.
(10) Mr. Olivier has served as Executive Vice President - Operations of NU since February 13, 2007 and has served as Executive Vice President since December 1, 2005. He was elected Chief Executive Officer of CL&P, PSNH and WMECO on January 15, 2007.
GRANTS OF PLAN-BASED AWARDS DURING 2006
The Grants of Plan-Based Awards Table provides information on the range of potential payouts under all incentive plan awards during the fiscal year ended December 31, 2006. The table also discloses the underlying stock awards and the grant date for equity-based awards. No option awards were made to any of the named executive officers in the fiscal year ended December 31, 2006.
(1) Amounts reflect the range of potential payouts established for 2006 performance under the 2006 Annual Incentive Program for each named executive officer, as described in the Compensation Discussion and Analysis. The 2007 payment for 2006 performance is set forth in the Non-Equity Incentive Plan Compensation column of the Summary Compensation Table.
(2) Amounts in the Estimated Future Payouts Under Non-Equity Incentive Plan Awards columns show the range of potential payouts under non-equity long-term incentive plan awards, as described in the Compensation Discussion and Analysis. Grants of three-year performance cash units were made to officers during 2006 under the 2006-2008 Long-Term Incentive Program. Any payments due will be made in cash following the close of the performance period. Payments at the threshold, target, and maximum levels will be determined based on cumulative net income, average return on equity, average credit rating, and total shareholder return relative to sixteen utility companies over the performance period. The Target award for each officer is stated as a percentage of base rate of pay at the time of grant, and ultimate payout, if any, varies from 50 percent of target for achievement of minimum performance goals to 150 percent of target for achievement of maximum performance goals. Performance Cash will be fully vested at the end of the Performance Period and paid to the officer within 2½ months after the end of the Performance Period.
(3) The amounts shown in the All Other Stock Awards: Number of Shares of Stock or Units column reflect the number of RSUs granted to each of the named executive officers on February 14, 2006 under the 2006-2008 Long-Term Incentive Program. The RSUs will vest by one-third on the 25th of February in each of the first three years following the calendar year of award. Except for Mr. Shivery, half of the vested RSUs shall be paid out four years after their respective vesting dates; the other half of the vested RSUs shall be paid out immediately upon vesting. For Mr. Shivery, the vested RSUs shall be paid out in three approximately equal annual installments beginning the later of six months after his separation from the Company and January of the calendar year following the year he separates from the Company. Payouts will be in cash of an amount sufficient to pay tax withholding, plus whole common shares of Northeast Utilities. Until RSUs are paid out, the value of dividends that would have been paid to the recipient had the RSUs been actual Northeast Utilities common shares will be deemed to be invested in additional RSUs and paid out at the same time the related RSUs are paid.
(4) Amounts in this column reflect the grant-date fair value of RSUs granted to the named executive officers on February 14, 2006, under the 2006-2008 Long-Term Incentive Program. Amounts are reported as determined pursuant to generally accepted accounting principles.
(5) The amount reported for Mr. De Simone in the All Other Stock Awards: Number of Shares of Stock or Units column represents the full grant of RSUs made by the Board of Trustees to Mr. De Simone on February 14, 2006. This grant and other outstanding unvested RSUs held by Mr. De Simone on his January 1, 2007 retirement date were prorated for time worked in 2006. Additional information is set forth in the Post-Employment Compensation Table prepared for Mr. De Simone.
EQUITY GRANTS OUTSTANDING AT DECEMBER 31, 2006
The following table sets forth option, restricted share and RSU grants outstanding at the end of our fiscal year ended December 31, 2006 for each of the named executive officers. All option grants were fully vested as of December 31, 2006.
(1) There have been no new grants of stock options made since the fiscal year ended December 31, 2002.
(2) The market value of the restricted share units is determined by multiplying the number of shares by $28.16, the closing price of NU common shares on December 29, 2006, the last trading day of the fiscal year.
OPTIONS EXERCISED AND STOCK VESTED IN 2006
The following table reports amounts realized on equity compensation during the fiscal year ended December 31, 2006. In 2006 Messrs. McHale and Butler exercised options. The Stock Awards columns report the vesting of restricted share and RSU grants to officers in February 2006.
(1) The amounts shown represent the amounts realized on the option exercises, which is the difference between the option exercise price and the market price on the date of exercise.
(2) The amounts vested include long-term incentive grants as follows: one-fourth of the restricted shares granted in 2003; one-fourth of the RSUs granted in 2004, half of which were immediately paid and half of which were deferred; and one-third of the RSUs granted in 2005, half of which were immediately paid and half of which were deferred, except for Mr. Shivery whose entire 2005 grant year award was deferred until retirement. Amounts vested also include one-third of a special grant of RSUs in 2004 to Mr. Shivery and Mrs. Grisé in connection with their 2003 Annual Incentive Program award, and one-fourth of the restricted shares granted to Mr. Shivery on his appointment as Chairman, CEO and President of NU. In all cases, payment is made in cash sufficient to satisfy applicable tax withholding and the remainder in NU common shares. Included in the value realized are values associated with deferred RSUs, which are also reported in the Registrant Contributions in Last Fiscal Year column of the Non-Qualified Deferred Compensation Table.
(3) Value realized is based on the $19.64 closing market price of NU common shares on February 24, 2006. This value includes the value of vested, deferred RSUs.
PENSION BENEFITS IN 2006
The Pension Benefits Table sets forth the estimated present value of accumulated retirement benefits that would be payable to each named executive officer upon his or her retirement as of the date upon which he or she can first obtain an unreduced pension benefit (see below). The table separates the benefits into those available through the Retirement Plan, the Supplemental Plan and any additional benefits made available through the respective officer's employment agreement. The Supplemental Plan provides a make whole benefit that takes into account compensation received by the officer not permitted to be recognized under a tax-qualified plan and provides a target benefit if the eligible officer continues service until age 60. The Supplemental Plan also takes into account elements of compensation that are not taken into account for officers under the Retirement Plan. This includes compensation equal to (i) deferred compensation, and (ii) the value of awards under the annual incentive program for officers and, for Mrs. Grisé as to her target benefit and Messrs. McHale and Butler as to their make whole benefit, long-term incentives, the value of which is frozen at the 2001 target grant level.
The present value of accumulated benefits shown in the Pension Benefits Table is calculated as of December 31, 2006. The present value is calculated assuming benefits would be paid in the form of a 50% contingent annuitant option (normal form of payment for the Target Benefit). For Mr. McHale, benefits are expressed in a single life annuity form. For Mr. Olivier, who has a special retirement arrangement, it was assumed that his special retirement benefit would be paid as a lump sum, and his Retirement Plan benefit would be paid in the form of a 33.33% contingent annuitant option (normal form for the Retirement Plan). For this table, it was assumed that none of Mr. Olivier's benefit is provided under the Supplemental Plan. In addition, the present value of accrued benefits for any named executive officer assumes that benefits commence at the earliest age at which the participant could retire and receive unreduced benefits. Except for Mr. Olivier, unreduced benefits are available at the earlier of (a) attainment of age 65 or (b) attainment of at least age 60 when age plus service equals 85 or more years. Mr. Olivier's unreduced benefit is available at age 60 according to his employment agreement. The following chart summarizes the unreduced retirement ages for each of the named executive officers:
Shivery
Butler
McHale
Grisé
Olivier
De Simone
Mr. De Simone announced his retirement effective January 1, 2007, and his accrued benefit, consequently, is equal to the amount immediately payable.
The limitations applicable to the Retirement Plan under the Code as of December 31, 2006 were used to determine the benefits under each plan. The accrued benefits reflect actual compensation (both base and incentives) earned during 2006. Under the terms of the Supplemental Plan, annual incentives earned for services provided in a plan year are deemed paid ratably over that plan year. For example, the 2006 annual incentive payment made in February 2007 was reflected in the 2006 plan compensation. The present value of the benefit at retirement age was determined by using the discount rate under Statement of Financial Accounting Standards No. 87 for 2006 fiscal year end measurement (as of December 31, 2006) of 5.90%. This present value assumes no preretirement mortality, turnover or disability. However, for the postretirement period beginning at the retirement age, the 1994 Uninsured Pension Mortality Table was used (same table used for financial reporting under FAS 87). Additional assumptions are as set forth in section 6 of the Management's Discussion and Analysis and Results of Operations section of our annual report to shareholders for the fiscal year ended December 31, 2006 as incorporated by reference in this 2006 Form 10-K.
(1) Mr. Shivery's actual service with the NU System is 4.6 years as of December 31, 2006; however, Mr. Shivery's employment agreement provides for a special retirement benefit consisting of an amount equal to the difference between: (i) the equivalent of fully-vested benefits under the Retirement Plan and the Supplemental Plan calculated by adding three additional years to his actual service and using an early retirement commencement reduction factor of two percent per year for each year Mr. Shivery's age at retirement commencement is under age 65, if better than the factors then in use under the Retirement Plan, and (ii) benefits otherwise payable from the Retirement Plan and the Supplemental Plan. The value of the additional three years of service on December 31, 2006 is $1,141,516.
(2) Mr. De Simone retired effective January 1, 2007 without a vested benefit in the Retirement Plan.
(3) Mr. Olivier was employed with Northeast Nuclear Energy Company, a subsidiary of NU, from October of 1998 through March of 2001. In connection with this employment, he was granted a special retirement benefit that provided credit for service with his previous employer in calculating his defined benefit pension value, which was offset by the pension benefit provided by the previous employer. The benefit, which commenced upon Mr. Olivier's 55th birthday, provides an annuity of $105,966 per year in a form that provides no contingent annuitant benefit. The present value of future payments is calculated using the actuarial assumptions that are in use for the Retirement Plan. Mr. Olivier was rehired by the NU System in September of 2001. The terms of Mr. Olivier's current employment agreement provide for certain supplemental pension benefits in lieu of benefits under the Supplemental Plan if certain eligibility requirements are met, in order to provide a benefit similar to that provided by his previous employer. Under this arrangement, if Mr. Olivier remains in continuous employment with the Company until September 10, 2011 (or separates from the Company earlier with the Company's permission), he will be eligible for a special benefit, subject to reduction for termination prior to age 65, of three percent of final average compensation for each of his first 15 years of service since September 10, 2001, plus one percent of final average compensation for each of the second 15 years of service. Alternatively, if Mr Olivier voluntarily terminates his employment with the Company after his 60th birthday, or is earlier terminated by the Company for any reason other than "cause", he may receive upon retirement a lump sum payment of $2,050,000 in lieu of benefits under the Supplemental Plan and the benefit described in the preceding sentence. These supplemental pension benefits will be offset by the value of any benefits he receives from the Retirement Plan. If the conditions described above are not met, then Mr. Olivier would be eligible for the make whole benefit under the Supplemental Plan. Amounts reported in the table assume his separation at age 60 and payment of the lump sum benefit of $2,050,000, as offset by Retirement Plan benefits.
NONQUALIFIED DEFERRED COMPENSATION IN 2006
The table below sets forth values associated with the deferral of vested RSUs related to the 2004 and 2005 grants reported in the Outstanding Equity at Fiscal Year End Table. In addition, the table below sets forth the value of elective contributions, Company matching contributions and earnings pursuant to the Deferral Plan. More information about the Deferral Plan is available in the Compensation Discussion and Analysis. Only Messrs. Shivery and Olivier and Mrs. Grisé elected to participate in the Deferral Plan in 2006. Mr. Butler holds a balance in the Deferral Plan relating to participation prior to 2006, and Messrs. McHale and De Simone have never participated.
Earnings on deferred RSUs are in the form of reinvested dividend equivalents that track actual dividends on NU common shares.
Deferrals of base salary and incentive compensation into the Deferral Plan are made pursuant to advance elections made by the executive officer in compliance with Section 409A of the Internal Revenue Code, providing for distribution after a stated number of years or after termination of employment in lump sum or installments, as specified under the election. The deferrals are deemed to be invested in phantom funds, at the direction of the executive, which mirror, with some exceptions, the investments offered to all eligible employees through the Savings Plan. The Savings Plan offers participants investment in various mutual funds offered by Fidelity Investments and a managed balanced fund.
No distributions of deferred RSUs or Deferral Plan balances were made in 2006.
(1) The amounts in this column represent base salary deferrals by the named executive officers under the terms of the Deferral Plan for the fiscal year ended December 31, 2006.
(2) The amounts in this column include Company matching contributions made to the Deferral Plan posted January 31, 2006 in notional common shares of Northeast Utilities with respect to contributions by the named executive officers in the fiscal year ended December 31, 2005 as reported in the All Other Compensation column of the Summary Compensation Table (Mr. Shivery-$19,249, Mrs. Grisé-$9,334, and Mr. Olivier-$5,758); all other amounts relate to the value of vested restricted share units automatically deferred under the terms of the respective Long-Term Incentive Program as of the February 27, 2006 vesting date (at a share price of $19.64). For more information, reference the notes to the Options Exercised and Stock Vested Table.
(3) The amounts in this column represent the total market value at December 31, 2006 of Deferral Plan balances plus the value of all deferred RSUs.
POTENTIAL PAYMENTS UPON TERMINATION OR CHANGE OF CONTROL
The discussion and tables below reflect the amount of compensation that would be payable to each of the named executive officers of the Company (except for Mr. De Simone, whose payments upon retirement are set forth in a separate table) in the event of termination of such executive's employment upon his or her (I) termination for cause, (II) voluntary termination, (III) involuntary not-for-cause termination, (IV) termination in the event of disability, (VI) death, and (VII) termination following a change of control. The amounts shown assume that each termination was effective as of December 29, 2006, the last business day of the fiscal year as required under SEC reporting requirements. Because payouts under the annual incentive program require employment through the end of the performance year, amounts reflected do not include incentive payments unless, according to program documents, such payment would have been made as a result of the officer's retirement, death or disability on December 29. The actual amounts to be paid out would be determined at the time of such executive's separation from the Company.
Payments Made Upon Termination
Regardless of the manner in which a named executive officer terminates, he or she is entitled to receive certain amounts earned during his or her term of employment. Such amounts include:
·
vested restricted shares and RSUs;
·
amounts contributed under the Deferral Plan;
·
vested matching contributions under the Deferral Plan;
·
pay for unused vacation; and
·
amounts accrued and vested through the Retirement Plan, the Savings Plan and the Supplemental Plan.
(1) The assumed termination date for purposes of these tables is December 29, 2006. The 2006 Annual Incentive Program and all current Long-Term Performance Cash programs provide for no payout in the event that a participant's employment terminates for any reason other than retirement, death or disability before December 31, 2006. Only those RSUs that were previously vested but not yet paid would be payable upon a termination for cause.
(2) Only vested benefits under the Retirement Plan and the make whole benefit under the Supplemental Plan would be available in the event of a termination for cause. Mr. Shivery has not yet accumulated five years of credited service and is not yet eligible to receive a benefit under the Retirement Plan. None of the named executive officers has satisfied the minimum requirements (at least age 55 with at least 10 years of service) to be eligible to receive a make whole benefit under the Supplemental Plan on account of a termination for cause.
(3) The amounts in this row represent vested balances in the Deferral Plan at December 31, 2006, which would be payable in accordance with previous distribution elections following separation for any reason.
(1) The 2006 Annual Incentive Program and all current Long-Term Performance Cash programs provide for no payout in the event that a participant's employment terminates for any reason other than retirement, death or disability before December 31, 2006. "Retirement" is defined as eligibility to immediately commence a post-employment benefit under the Retirement Plan, Supplemental Plan or other employment agreement with an NU System company. Both Mr. Shivery and Mr. Olivier meet these criteria and would, therefore, receive payouts under the 2006 Annual Incentive Program and prorated payouts of the 2005-2007 and 2006-2008 Performance Cash awards, which would be based on final results and paid in the first quarter of 2008 and 2009, respectively. The amounts reflected in the table are projections assuming target performance under Performance Cash Programs. For the RSUs granted under the 2004, 2005 and 2006 Long-Term Incentive programs, both Mr. Shivery and Mr. Olivier would receive a prorated payout of unvested RSUs for time worked in the vesting period that would otherwise be completed on February 25, 2007. All named executive officers would receive full payment for all previously vested but not yet paid RSUs.
(2) Pension amounts are present values at the end of 2006 of life annuities payable to each named executive officer at age 65 (age 60 for Mr. Olivier). All assumptions used to calculate these pension values are the same as those described in the notes attached to the Pension Benefits Table.
(3) The deferred compensation values are vested balances for all named executive officers. Mr. Shivery and Mr. Olivier are eligible for accelerated vesting of the employer match for 2003 through 2005 because of their retirement eligibility. Mrs. Grisé and Mr. Butler would forfeit this unvested match upon voluntary separation.
(4) Mr. Shivery's employment agreement provides for immediate eligibility for retiree health or the cash equivalent regardless of his actual age and years of service. Outside of this agreement, he would not otherwise qualify for these benefits. The amount shown is the lump sum cash value of Company contributions for these benefits grossed up for applicable withholding taxes.
(1) Messrs. Shivery and Olivier would satisfy the criteria for retirement treatment under Annual and Long -Term Incentive Programs as described in the Voluntary Termination Table. Mrs. Grisé would be eligible for retirement treatment under a provision of the Retirement Plan that allows for immediate commencement of retirement benefits if a participant is involuntarily terminated without cause between age 50 and 55 with at least 65 years of age and service. Mr. Shivery's employment agreement calls for full vesting and payout of all restricted shares and RSUs upon involuntary termination without cause. All named executive officers would receive full payment for all previously vested but not yet paid RSUs.
(2) Employment agreements for all but Mr. Olivier provide for an addition of two years of age and service in the calculation of pension benefits available upon an involuntary termination without cause. For Mr. Shivery, this two years of added age and service is in addition to the three years of added service upon a voluntary termination. Pension amounts reflected above are present values at the end of 2006 of benefits payable to each NEO at the earliest unreduced benefit age (Mr. Shivery - age 63, Mr. McHale - age 63, Mrs. Grisé - age 63, Mr. Olivier - age 58, and Mr. Butler - age 63). All but the benefit payable to Mr. Olivier are annuities that are calculated using the same assumptions as detailed in the notes to the Pension Benefits Table. Under the terms of his employment agreement, if Mr. Olivier is terminated for any reason other than "cause," he is made immediately eligible for a special retirement benefit paid as a lump sum of $2,050,000 as offset by benefits from the Retirement Plan.
(3) The deferred compensation values are vested balances for all NEOs. Messrs. Shivery and Olivier and Mrs. Grisé are eligible for accelerated vesting of the employer match for 2003 through 2005 because of their retirement eligibility. Mr. Butler would forfeit his unvested match upon involuntary termination.
(4) Employment agreements for all but Mr. Olivier provide for the payment of two years of active benefits value and retirement benefits if adding the "two" years of age and service would have made the officer eligible under the retiree health plan. Mr. Shivery's employment agreement provides for automatic eligibility for retiree health benefits, and Mr. Olivier's employment agreement provides for retiree health benefits if he is terminated without cause. Mrs. Grisé would be eligible for retiree health benefits under the retiree health plan. Six months of Company-paid COBRA benefits are generally made available to all employees who are involuntarily terminated without cause. Thus, the amounts reported in the table are the cash value of 18 months of Company contributions for all but Mr. Olivier plus retiree benefits for Mr. Shivery and Mr. Olivier, who would not otherwise be eligible for retiree health benefits except as provided under their employment agreements. These amounts would be paid as a single lump sum and grossed up for applicable withholding taxes. All except Mr. Olivier are also eligible to receive two years of reimbursement of financial planning and tax preparation services.
(5) Employment agreements for all but Mr. Olivier provide for a severance payment equal to two times the base salary plus annual incentives at target, one multiple of which is associated with the signing of a non-compete agreement.
(1) The 2006 Annual Incentive Program and all current Long-Term Performance Cash programs provide for payout in the event that a participant's employment terminates for reason of disability. While actual values are reported for the 2006 Annual Incentive amounts, amounts shown for the Performance Cash Program for 2004-2006, 2005-2007 and 2006-2008 are based on target performance in accordance with program rules and prorated for time worked in the performance period. For RSUs, a disabled participant would receive payout of unvested RSUs prorated for time worked in the vesting period that would otherwise be completed on February 25, 2007 plus payment for all previously vested but not yet paid RSUs.
(2) Under the Company's Long-Term Disability (LTD) program, disabled participants in the Retirement Plan are allowed to continue to accrue service in the Retirement Plan during the period when they are receiving disability payments. Disability payments stop when the LTD participant elects to commence pension payments, but not later than age 65. We have assumed similar treatment in the development of the pension amounts reported in this table. For purposes of valuing the pension benefits, we have assumed that each named executive officer would remain on LTD until his or her first unreduced make whole or target pension benefit age (Mr. Shivery - 65, Mr. McHale - 55, Mrs. Grisé - 57, Mr. Olivier - 60, and Mr. Butler - age 62). All but the benefit payable to Mr. Olivier are life annuities that are calculated using the same assumptions as detailed in the notes to the Pension Benefits Table. Mr. Olivier's benefit would be paid as a lump sum of $2,050,000 as offset by benefits from the Retirement Plan.
(3) The deferred compensation values are vested balances for all named executive officers since all unvested employer match would become vested upon disability.
(4) Mr. Olivier's employment agreement provides for retiree health benefits if he is terminated without cause even if he would not otherwise qualify for such benefits. The amount reported is the value of Company contributions for these benefits paid as a single lump sum grossed up for applicable withholding taxes.
(1) The 2006 Annual Incentive Program and 2004-2006, 2005-2007 and 2006-2008 Performance Cash programs provide for payout in the event that a participant's employment terminates for reason of death. All such payments would be prorated for time worked in each performance period and paid at target. For RSUs, a deceased participant's beneficiary would receive prorated payout of unvested RSUs for time worked in the vesting period that would otherwise be completed on February 25, 2007 plus payment for all previously vested but not yet paid RSUs.
(2) Represents the lump sum present value of pension payments to the surviving beneficiary of each named executive officer.
(3) The deferred compensation values are vested balances for all named executive officers since all unvested employer matches would become vested on account of death.
(4) Messrs. Shivery and Olivier's employment agreements provide, upon their death, for retiree health benefits for their respective spouses if Messrs. Shivery and Olivier would not otherwise qualify for such benefits. The amount reported is the value of Company contributions for these benefits paid as a single lump sum grossed up for applicable withholding taxes.
Payments Made Upon a Change of Control
The Company has entered into employment agreements with Messrs. Shivery, McHale, Olivier and Butler and Mrs. Grisé. In addition, Mr. Olivier participates in the Special Severance Program for Officers of Northeast Utilities System Companies (the "SSP") providing for benefits upon termination connected with a Change of Control, while other named executive officers have Change of Control benefits pursuant to the terms of their employment agreements. Also, the agreements and the SSP are binding on Northeast Utilities and, except for Mr. Shivery's agreement, on certain majority-owned subsidiaries of Northeast Utilities. The terms of the various employment agreements (the "Agreements") are substantially similar except as applied to Mr. Olivier, whose Agreement references the change of control provisions of the SSP. Pursuant to the Agreements and under the terms of the SSP, if the executive's employment terminates following a Change of Control (other than termination for "cause" or by reason of death or disability) or if the executive terminates his or her employment in certain circumstances defined in the Agreements as constituting "good reason," then in addition to the benefits listed above, the named executive officer will receive, upon signing a release of all legal actions against the Company:
·
a lump sum severance payment (except for Mr. Olivier) of two-times the sum of the executive's base salary and all annual awards that would be payable for the relevant year determined at target ("Base Compensation");
·
in consideration for a non-competition and non-solicitation covenant, a lump sum payment of one-times Base Compensation (two-times Base Compensation for Mr. Olivier under the terms of the SSP);
·
active health continuation coverage for three years (two years, for Mr. Olivier), or the cash equivalent;
·
benefits under the Supplemental Plan (except for Mr. Olivier, whose benefits are further described below) without regard to satisfaction of eligibility for the Target Benefit with favorable actuarial reductions and imputation of 36 months to the executive's age and service over that provided for upon voluntary termination of employment;
·
all restricted shares and RSUs held by the executive will automatically vest and be paid, and
·
an amount equal to the excise tax (except for Mr. Olivier) charged to the executive under the Code as a result of the receipt of any change of control payments, plus tax gross-up.
The descriptions of the various Agreements set forth above are for purpose of disclosure in accordance with the annual report and other disclosure rules of the SEC and shall not be controlling on any party; the actual terms of the agreements themselves determine the rights and obligations of the parties.
(1) All named executive officers meet the criteria for retirement treatment under the Annual Incentive Program and would receive a payout under the 2006 Annual Incentives Program based on actual results. Under the terms of the 2004-2006, 2005-2007 and 2006-2008 Performance Cash Programs, participants who are terminated upon a Change of Control become eligible for immediate payout of a target award, and under the terms of the outstanding grants of restricted shares and RSUs, all unvested shares and share units held by participants terminated upon a Change of Control would be immediately vested and paid.
(2) Employment agreements for all but Mr. Olivier provide for the addition of three years of age and service in the calculation of pension benefits available upon termination following a Change of Control. For Mr. Shivery, this three years of added age and service are in addition to the three years of added service provided upon his voluntary termination. Pension amounts reflected in the table are present values at the end of 2006 of benefits payable to each NEO at the earliest unreduced benefit age (Mr. Shivery - age 62, Mr. McHale - age 62, Mrs. Grisé - age 62, Mr. Olivier - age 58, and Mr. Butler - age 62). All but the benefit payable to Mr. Olivier are annuities that are
calculated using the assumptions detailed in the notes to the Pension Benefits Table. Mr. Olivier's benefit would be paid as a lump sum of $2,050,000 as offset by benefits from the Retirement Plan.
(3) The deferred compensation values are vested balances for all named executive officers since all unvested matches would become fully vested upon the occurrence of a change of control.
(4) Employment agreements for all but Mr. Olivier provide for the payment of three years of active health benefits value and retiree health benefits if adding the three years of age and service would have made the executive eligible under the Retirement Plan. Mr. Olivier is a participant in the SSP and, as such, is eligible for two years of active health benefits continuation. Mrs. Grisé would be eligible for retiree health benefits under the Retirement Plan. Six months of company-paid COBRA benefits are generally made available to all employees who are involuntarily terminated without cause, so the amounts reported in the table are the cash value of 30 months of Company contributions for all but Mr. Olivier, whose benefit would be the cash value of 18 months of Company contributions. In addition to continuation of active health benefits, retiree health benefits for Messrs. Shivery and Olivier, which are provided for in their employment agreements regardless of eligibility, would be paid as a single lump sum and grossed up for applicable withholding taxes. All named executive officers are also eligible to receive three years of reimbursement of financial planning and tax preparation services.
(5) Excise Tax gross-up: Upon a Change of Control, employees may be subject to certain excise taxes under Section 280G of the Code. Employment agreements for all but Mr. Olivier provide for a grossed-up reimbursement of these excise taxes. The amounts in the table are based on a 280G excise tax rate of 20%, a statutory federal income tax withholding rate of 25%, a Connecticut state income tax rate of 5%, and a Medicare tax rate of 1.45%. Mr. Olivier's benefit through the SSP does not provide for this payment. Severance Payments: Employment agreements for all but Mr. Olivier provide for a severance payment equal to three-times the officer's base salary plus annual incentives at target, one multiple of which is associated with the signing of a non-compete agreement. Mr. Olivier's benefit under the SSP would be a payment of two-times his base salary plus target annual incentives, all of which is associated with the signing of a non-compete agreement.
Lawrence E. De Simone
The following table sets forth the payments to be received by Lawrence De Simone, President- Competitive Group of Northeast Utilities following his retirement from the Company on January 1, 2007. Pursuant to the terms of Mr. De Simone's employment agreement, Mr. De Simone became entitled to the enumerated separation benefits if his responsibilities were significantly reduced as the result of the sale or other disposition of NU Enterprises, Inc. unrelated to a Change of Control of NU, as occurred in 2006, and he elected to terminate his employment. Because Mr. De Simone retired, he is also entitled to receive payment under the 2006 Annual Award Program. In addition, as set forth in the notes to the Grants of Plan-Based Awards Table, Mr. De Simone is eligible for distributions in the first quarter of 2008 under the 2005-2007 Performance Cash Program based on goal achievement, prorated to reflect that Mr. De Simone performed services for two years out of the three-year period, and an award under the 2006-2008 Performance Cash Program based on goal achievement, prorated to reflect that Mr. De Simone performed services for one year out of the three-year period ending December 31, 2008. Mr. De Simone vested in RSUs granted on February 14, 2006 and in prior years based on a proration of service during 2006 during which the grant was outstanding. Mr. De Simone was not eligible for a vested benefit under the Retirement Plan.
(1) Upon his retirement, Mr. De Simone is eligible to receive a payout under the 2006 Annual Incentive Program. He is also eligible to receive a prorated payout of the 2005-2007 and 2006-2008 Performance Cash programs, which will be paid in 2008 and 2009, respectively, based on final performance. Amounts reflected in the table are estimated payouts based on target performance. Upon Mr. De Simone's retirement on January 1, 2007, his unvested RSUs were vested on a prorated basis for time worked, and the remaining unvested RSUs were forfeited. Payout of the vested RSUs will be made in July of 2007, with the six-month delay that is required for deferred compensation paid to "key employees" under Code Section 409A. A total of 12,943 RSUs were outstanding following proration, and 19,809 RSUs have been forfeited.
(2) Pension values are the total accrued pension benefit payable as an annuity that pays 50% to his surviving spouse. Assumptions used in the calculation of this benefit are further discussed in the notes to the Pension Benefits table.
(3) Mr. De Simone's employment agreement provides for the payment of the value of two years of active health benefits upon his separation. Six months of Company-paid COBRA benefits are generally made available to all employees who are involuntarily terminated without cause, so the amounts reported in the table are the cash value of 18 months of Company contributions paid as a single lump sum and grossed up for applicable tax withholding. Payment will be made in January 2007 in accordance with Code Section 409A.
(4) Mr. De Simone's employment agreement provides for a severance payment equal to two times base pay plus annual incentives, one multiple of which is associated with his signing a non-compete agreement.
Incorporated herein by reference is the information contained in the section "Board Committees and Responsibilities," of the definitive proxy statement for solicitation of proxies by NU's Board of Trustees, to be dated March 20, 2007, which will be filed with the Commission pursuant to Rule 14a-6 under the Securities Exchange Act of 1934.
TRUSTEE AND DIRECTOR COMPENSATION
Incorporated herein by reference is the information contained in the section "Trustee Compensation" of the definitive proxy statement for solicitation of proxies by NU's Board of Trustees, to be dated March 20, 2007, which will be filed with the Commission pursuant to Rule 14a-6 under the Securities Exchange Act of 1934.
Directors of CL&P did not receive any compensation relating to their duties as directors during 2006.
Certain information required by Item 11 is omitted for PSNH and WMECO pursuant to Instruction I(2)(c) to Form 10-K (Omission of Certain Information by Certain Wholly Owned Subsidiaries).
Item 12.
Item 12. Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters
NU
Incorporated herein by reference is the information contained in the sections "Common Stock Ownership of Certain Beneficial Owners," "Common Stock Ownership of Trustees and Management," and "Securities Authorized for Issuance Under Equity Compensation Plans" of the definitive proxy statement for solicitation of proxies by NU's Board of Trustees, to be dated March 20, 2007, which will be filed with the Commission pursuant to Rule 14a-6 under the Securities Exchange Act of 1934.
CL&P, PSNH and WMECO
NU owns 100 percent of the outstanding common stock of registrants CL&P, PSNH, and WMECO. The following table sets forth, as of February 13, 2007, the beneficial ownership of the equity securities of NU by (i) the Chief Executive Officer of each of CL&P, PSNH and WMECO and the Executive Officers of CL&P, PSNH, and WMECO listed on the Summary Compensation Table in Item 11 and (ii) all of the current Executive Officers and directors of each of CL&P, PSNH and WMECO, as a group. No equity securities of CL&P, PSNH, or WMECO are owned by the Directors and Executive Officers of CL&P, PSNH, and WMECO. Unless otherwise noted, each Director and Executive Officer of CL&P, PSNH, and WMECO has sole voting and investment power with respect to the listed shares.
Amount beneficially owned by Directors and Executive Officers as a group:
Notes:
(1)
As of February 13, 2007, the Directors and Executive Officers of CL&P, PSNH, or WMECO individually and as a group, owned less than one percent of the shares outstanding.
(2)
Includes 29,024 shares that could be acquired by Mr. Shivery pursuant to currently exercisable options, 1,500 shares which Mr. Shivery owns jointly with his wife with whom he shares voting and dispositive power, and 16,390 shares as to which Mr. Shivery has sole voting and no dispositive power.
(3) Includes 7,500 shares that could have been acquired by Mr. McHale pursuant to currently exercisable options and 1,130 shares as to which Mr. McHale has sole voting and no dispositive power.
(4)
Includes 171,228 shares that could be acquired by Mrs. Grisé pursuant to currently exercisable options, 5,746 shares as to which Mrs. Grisé has sole voting and no dispositive power, and 265 shares held by Mrs. Grisé's husband as custodian for her children, with whom she shares voting and dispositive power.
(5)
Includes 19,900 shares that could be acquired by Mr. Olivier pursuant to currently exercisable options and 1,388 shares as to which Mr. Olivier has sole voting and no dispositive power.
(6)
Includes 12,680 shares held jointly by Mr. Butler with his wife, with whom he shares voting and dispositive power, and 1,945 shares as to which Mr. Butler has sole voting but no dispositive power.
(7)
Includes 14,850 shares that could be acquired by Mr. Long pursuant to currently exercisable options, and 1,150 shares as to which Mr. Long has sole voting and no dispositive power.
(8)
Includes 23,500 shares that could be acquired by Mr. Necci pursuant to currently exercisable options, and 1,185 shares as to which Mr. Necci has sole voting and no dispositive power.
(9)
Includes 4,500 shares that could be acquired by Mr. Powell pursuant to currently exercisable options, and 467 shares as to which Mr. Powell has sole voting and no dispositive power .
SECURITIES AUTHORIZED FOR ISSUANCE UNDER EQUITY COMPENSATION PLANS
The following table sets forth the number of common shares of Northeast Utilities issuable under the equity compensation plans of the Northeast Utilities System, as well as their weighted exercise price, in accordance with the rules of the Securities and Exchange Commission:
Plan Category
Number of securities to be issued upon exercise of outstanding options, warrants and rights
Weighted-average exercise price of outstanding options, warrants and rights
Number of securities remaining available for future issuance under equity compensation plans (excluding securities reflected in column (a))
(a)
(b)
(c)
Equity compensation plans approved by security holders
784,104
$ 18.55
See Note 1
Equity compensation plans not approved by security holders
None
Total
784,104
$ 18.55
See Note 1
Note:
(1)
Under the Northeast Utilities 1998 Incentive Plan, 7,730,755 shares were available for issuance as of December 31, 2006. In addition, an amount equal to one percent of the outstanding shares as of the end of each year becomes available for issuance under the Incentive Plan the following year. No more than 400,000 shares will be granted from this pool from January 1, 2007 through the 2007 Annual Meeting, when an amendment to the 1998 Incentive Plan will be presented to shareholders for approval. Upon adoption of this amendment, all remaining shares under the 1998 Incentive Plan will be cancelled. All future awards will be granted from shares approved by shareholders at the 2007 Annual Meeting under the terms of the Amended and Restated Incentive Plan. Under the Northeast Utilities Employee Share Purchase Plan II, 6,506,110 additional shares are available for issuance.
Item 13.
Item 13. Certain Relationships and Related Transactions, and Trustee Independence
Incorporated herein by reference is the information contained in the sections "Trustee Independence" and "Certain Relationships and Related Transactions" of the definitive proxy statement for solicitation of proxies by NU's Board of Trustees, to be dated March 20, 2007, which will be filed with the Commission pursuant to Rule 14a-6 under the Securities Exchange Act of 1934.
The Directors of CL&P are employees of CL&P and/or other NU system companies and thus are not considered independent under the NYSE guidelines discussed under "Trustee Independence" of NU's definitive proxy statement, to be dated March 20, 2007.
Certain information called for by this Item 13 is omitted for PSNH and WMECO pursuant to Instruction I(2)(c) to Form 10-K (Omission of Information by Certain Wholly Owned Subsidiaries).
Item 14.
Item 14. Principal Accountant Fees and Services
NU
Incorporated herein by reference is the information contained in the section "Relationship with Independent Auditors " of the definitive proxy statement for solicitation of proxies by NU's Board of Trustees, to be dated March 20, 2007, which will be filed with the Commission pursuant to Rule 14a-6 under the Securities Exchange Act of 1934.
CL&P, PSNH, WMECO
None of CL&P, PSNH and WMECO is subject to the audit committee requirements of the Securities and Exchange Commission, the national securities exchanges or the national securities associations. CL&P, PSNH and WMECO obtain audit services from the independent auditor engaged by the Audit Committee of NU's Board of Trustees. The NU Audit Committee has established policies and procedures regarding the pre-approval of services provided by the principal auditors. Those policies and procedures delegate pre-approval of services to the NU Audit Committee Chair and/or Vice Chair provided that such offices are held by NU Trustees who are "independent" within the meaning of the Sarbanes-Oxley Act of 2002 (SOX) and that all such pre-approvals are presented to the Audit Committee at the next regularly scheduled meeting of the Committee. The following relates to fees and services for the entire Northeast Utilities System, including CL&P, PSNH, and WMECO:
Fees Paid to Principal Auditor
The Company's principal auditor was paid fees aggregating $3,134,359 and $3,535,700 for the years ended December 31, 2006 and 2005, respectively, comprised of the following:
1.
Audit Fees
The aggregate fees billed to NU and its subsidiaries by Deloitte & Touche LLP, the member firms of Deloitte Touche Tohmatsu and their respective affiliates (collectively, the "Deloitte Entities") for audit services rendered for the years ended December 31, 2006 and 2005 totaled $2,938,255 and $3,309,000, respectively. The audit fees were incurred for audits of the annual consolidated financial statements of NU and its subsidiaries, reviews of financial statements included in quarterly reports on Form 10-Q of NU and its subsidiaries, comfort letters, consents and other costs related to registration statements and financings. The fees also included audits of internal controls over financial reporting as of December 31, 2006 and 2005.
Audit Related Fees
The aggregate fees billed to NU and its subsidiaries by the Deloitte Entities for audit related services rendered for the years ended December 31, 2006 and 2005 totaled $150,000 and $148,000, respectively, primarily related to the examination of management's assertions of CL&P's, PSNH's and WMECO's securitization subsidiaries and the Company's 401k Plan.
3.
Tax Fees
The aggregate fees billed to NU and its subsidiaries by the Deloitte Entities for tax services for the years ended December 31, 2006 and 2005 totaled $44,604 and $55,000, respectively. These services related solely to reviews of tax returns. There were no services related to tax advice or tax planning.
4.
All Other Fees
The aggregate fees billed to NU and its subsidiaries by the Deloitte Entities for the years ended December 31, 2006 and 2005 for services other than the services described above totaled $1,500 and $23,700, respectively, primarily related to access to an accounting research database (in 2006) and tax return software licensing (in 2005).
The Audit Committee pre-approves all auditing services and permitted non-audit services (including the fees and terms thereof) to be performed for the Company by its independent auditors, subject to the de minimis exceptions for non-audit services described in Section 10A(i)(1)(B) of the Securities Exchange Act of 1934, which are approved by the Audit Committee prior to the completion of the audit. The Audit Committee may form and delegate authority to subcommittees consisting of one or more members when appropriate, including the authority to grant pre-approvals of audit and permitted non-audit services, provided that decisions of such subcommittee to grant pre-approvals are presented to the full Audit Committee at its next scheduled meeting. No services were provided which were not pre-approved.
The NU Audit Committee has considered whether the provision by the Deloitte Entities of the non-audit services described above was allowed under Rule 2-01(c)(4) of Regulation S-X and was compatible with maintaining auditor independence and has concluded that the Deloitte Entities were and are independent of the Company in all respects.
Part IV
Item 15.
Item 15. Exhibits and Financial Statement Schedules
(a)
1.
Financial Statements:
The Reports of the Independent Registered Public Accounting Firm and financial statements of CL&P, PSNH and WMECO are hereby incorporated by reference and made a part of this report (see "Item 8. Financial Statements and Supplementary Data").
Report of Independent Registered Public Accounting Firm
S-1
2.
Schedules:
Financial Statement Schedules for NU (Parent), NU and Subsidiaries, CL&P
and Subsidiaries, PSNH and Subsidiaries, and WMECO and Subsidiary
are listed in the Index to Financial Statement Schedules
S-2
3.
Exhibits Index
E-1
NORTHEAST UTILITIES
SIGNATURES
Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the Registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.
NORTHEAST UTILITIES
(Registrant)
Date: February 26, 2007
By
/s/
Charles W. Shivery
Charles W. Shivery
Chairman of the Board,
President and Chief Executive Officer
(Principal Executive Officer)
Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the Registrant and in the capacities and on the dates indicated.
Date
Title
Signature
February 26, 2007
Chairman of the Board, President and Chief Executive Officer, and a Trustee
/s/
Charles W. Shivery
Charles W. Shivery
(Principal Executive Officer)
February 26, 2007
Senior Vice President and
Chief Financial Officer
(Principal Financial Officer)
/s/
David R. McHale
David R. McHale
February 26, 2007
Vice President - Accounting and
/s/
Shirley M. Payne
Controller
Shirley M. Payne
February 26, 2007
Trustee
/s/
Richard H. Booth
Richard H. Booth
February 26, 2007
Trustee
/s/
Cotton M. Cleveland
Cotton M. Cleveland
February 26, 2007
Trustee
/s/
Sanford Cloud, Jr.
Sanford Cloud, Jr.
February 26, 2007
Trustee
/s/
James F. Cordes
James F. Cordes
February 26, 2007
Trustee
/s/
E. Gail de Planque
E. Gail de Planque
February 26, 2007
Trustee
/s/
John G. Graham
John G. Graham
February 26, 2007
Trustee
/s/
Elizabeth T. Kennan
Elizabeth T. Kennan
February 26, 2007
Trustee
/s/ Kenneth R. Leibler
Kenneth R. Leibler
February 26, 2007
Trustee
/s/ Robert E. Patricelli
Robert E. Patricelli
February 26, 2007
Trustee
/s/ John F. Swope
John F. Swope
THE CONNECTICUT LIGHT AND POWER COMPANY
SIGNATURES
Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the Registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.
THE CONNECTICUT LIGHT AND POWER COMPANY
(Registrant)
Date: February 26, 2007
By
/s/
Leon J. Olivier
Leon J. Olivier
Chief Executive Officer
(Principal Executive Officer)
Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the Registrant and in the capacities and on the dates indicated.
Date
Title
Signature
February 26, 2007
Chairman and a Director
/s/
Charles W. Shivery
Charles W. Shivery
February 26, 2007
Chief Executive Officer and a Director
/s/
Leon J. Olivier
(Principal Executive Officer)
Leon J. Olivier
February 26, 2007
President and Chief Operating Officer and a Director
/s/
Raymond P. Necci
Raymond P. Necci
February 26, 2007
Senior Vice President and Chief Financial Officer and a Director
/s/
David R. McHale
David R. McHale
(Principal Financial Officer)
February 26, 2007
Vice President - Accounting and
/s/
Shirley M. Payne
Controller
Shirley M. Payne
PUBLIC SERVICE COMPANY OF NEW HAMPSHIRE
SIGNATURES
Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the Registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.
PUBLIC SERVICE COMPANY OF NEW HAMPSHIRE
(Registrant)
Date: February 26, 2007
By
/s/
Leon J. Olivier
Leon J. Olivier
Chief Executive Officer
(Principal Executive Officer)
Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the Registrant and in the capacities and on the dates indicated.
Date
Title
Signature
February 26, 2007
Chairman and a Director
/s/
Charles W. Shivery
Charles W. Shivery
February 26, 2007
Chief Executive Officer and a Director
(Principal Executive Officer)
/s/
Leon J. Olivier
Leon J. Olivier
February 26, 2007
President and Chief Operating Officer and a Director
/s/
Gary A. Long
Gary A. Long
February 26, 2007
Senior Vice President and Chief Financial Officer and a Director
/s/
David R. McHale
David R. McHale
(Principal Financial Officer)
February 26, 2007
Vice President - Accounting and
/s/
Shirley M. Payne
Controller
Shirley M. Payne
WESTERN MASSACHUSETTS ELECTRIC COMPANY
SIGNATURES
Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the Registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.
WESTERN MASSACHUSETTS ELECTRIC COMPANY
(Registrant)
Date: February 26, 2007
By
/s/
Leon J. Olivier
Leon J. Olivier
Chief Executive Officer
(Principal Executive Officer)
Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the Registrant and in the capacities and on the dates indicated.
Date
Title
Signature
February 26, 2007
Chairman and a Director
/s/
Charles W. Shivery
Charles W. Shivery
February 26, 2007
Chief Executive Officer and a Director
(Principal Executive Officer)
/s/
Leon J. Olivier
Leon J. Olivier
February 26, 2007
President and Chief Operating Officer and a Director
/s/
Rodney O. Powell
Rodney O. Powell
February 26, 2007
Senior Vice President and Chief Financial Officer and a Director
/s/
David R. McHale
David R. McHale
(Principal Financial Officer)
February 26, 2007
Vice President - Accounting and
/s/
Shirley M. Payne
Controller
Shirley M. Payne
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
To the Board of Directors and Shareholders of Northeast Utilities and the Boards of Directors of The Connecticut Light and Power Company, Public Service Company of New Hampshire and Western Massachusetts Electric Company:
We have audited the consolidated financial statements of Northeast Utilities and subsidiaries (the "Company"), as of December 31, 2006 and 2005, and for each of the three years in the period ended December 31, 2006, management's assessment of the effectiveness of the Company's internal control over financial reporting as of December 31, 2006, and the effectiveness of the Company's internal control over financial reporting as of December 31, 2006, and have issued our report thereon dated February 28, 2007 (which report expresses an unqualified opinion and includes an explanatory paragraph regarding Northeast Utilities' ongoing divestiture activities, a reduction to income tax expense, and the adoption of Statement of Financial Accounting Standard No. 158, Employers' Accounting for Defined Benefit Pension and Other Postretirement Plans); such consolidated financial statements and report are included in Northeast Utilities' 2006 Annual Report to Shareholders and are incorporated herein by reference.
We have also audited the consolidated financial statements of The Connecticut Light and Power Company ("CL&P") as of December 31, 2006 and 2005, and for each of the three years in the period ended December 31, 2006, and have issued our report thereon dated February 28, 2007 (which report expresses an unqualified opinion and includes an explanatory paragraph regarding a reduction in income tax expense and the adoption of Statement of Financial Accounting Standard No. 158, Employers' Accounting for Defined Benefit Pension and Other Postretirement Plans); such consolidated financial statements and report are included in CL&P's 2006 Annual Report and are incorporated herein by reference.
We have also audited the consolidated financial statements of Public Service Company of New Hampshire ("PSNH") and Western Massachusetts Electric Company ("WMECO") as of December 31, 2006 and 2005, and for each of the three years in the period ended December 31, 2006, and have issued our reports thereon dated February 28, 2007 (which reports express an unqualified opinion and include explanatory paragraphs regarding the adoption of Statement of Financial Accounting Standard No. 158, Employers' Accounting for Defined Benefit Pension and Other Postretirement Plans); such consolidated financial statements and reports are included in PSNH's and WMECO's 2006 Annual Reports and are incorporated herein by reference.
Our audits also included the consolidated financial statement schedules of the Company, CL&P, PSNH and WMECO, listed in Item 15. These consolidated financial statement schedules are the responsibility of the managements of the Company, CL&P, PSNH and WMECO. Our responsibility is to express an opinion based on our audits. In our opinion, such consolidated financial statement schedules, when considered in relation to the basic consolidated financial statements for each company taken as a whole, present fairly, in all material respects, the information set forth therein.
/s/
Deloitte & Touche LLP
Deloitte & Touche LLP
Hartford, Connecticut
February 26, 2007
INDEX TO FINANCIAL STATEMENT SCHEDULES
Schedule
I.
Financial Information of Registrant:
Northeast Utilities (Parent) Balance Sheets at December 31, 2006 and 2005
S-3
Northeast Utilities (Parent) Statements of Income/(Loss) for the Years Ended
December 31, 2006, 2005, and 2004
S-4
Northeast Utilities (Parent) Statements of Cash Flows for the Years Ended
December 31, 2006, 2005, and 2004
S-5
II.
Valuation and Qualifying Accounts and Reserves for 2006, 2005, and 2004:
Northeast Utilities and Subsidiaries
S-6 - S-8
The Connecticut Light and Power Company
S-9 - S11
Public Service Company of New Hampshire
S-12 - S14
Western Massachusetts Electric Company
S-15 - S-17
All other schedules of the companies' for which provision is made in the applicable regulations of the SEC are not required under the related instructions or are not applicable, and therefore have been omitted.
SCHEDULE I
NORTHEAST UTILITIES (PARENT)
FINANCIAL INFORMATION OF REGISTRANT
BALANCE SHEETS
AT DECEMBER 31, 2006 AND 2005
(Thousands of Dollars)
ASSETS
Current Assets:
Cash
$ 1,791
$ 390
Notes receivable from affiliated companies
915,900
352,700
Notes and accounts receivable
Accounts receivable from affiliated companies
3,540
7,642
Prepayments
922,049
361,747
Deferred Debits and Other Assets:
Investments in subsidiary companies, at equity
2,520,144
2,531,536
Accumulated deferred income taxes
-
9,965
Other
19,547
11,604
2,539,691
2,553,105
Total Assets
$ 3,461,740
$ 2,914,852
LIABILITIES AND CAPITALIZATION
Current Liabilities:
Notes payable to banks
$ -
$ 32,000
Long-term debt - current portion
-
21,000
Accounts payable
Accounts payable to affiliated companies
Accrued taxes
240,466
12,103
Accrued interest
5,179
5,357
Other
246,839
71,705
Deferred Credits and Other Liabilities:
Accumulated deferred income taxes
1,685
-
Derivative liabilities - long-term
6,483
5,211
Other
2,136
1,072
10,304
6,283
Capitalization:
Long-Term Debt
406,418
407,620
Common shares, $5 par value - authorized
225,000,000 shares; 175,420,239 shares issued
and 154,233,141 shares outstanding in 2006 and
174,897,704 shares issued and 153,225,892 shares
outstanding in 2005
877,101
874,489
Capital surplus, paid in
1,449,586
1,437,561
Deferred contribution plan - employee
stock ownership plan
(34,766)
(46,884)
Retained earnings
862,660
504,301
Accumulated other comprehensive income
4,498
19,987
Treasury stock, 19,684,249 shares in 2006
and 19,645,511 shares in 2005
(360,900)
(360,210)
Common Shareholders' Equity
2,798,179
2,429,244
Total Capitalization
3,204,597
2,836,864
Total Liabilities and Capitalization
$ 3,461,740
$ 2,914,852
SCHEDULE I
NORTHEAST UTILITIES (PARENT)
FINANCIAL INFORMATION OF REGISTRANT
STATEMENTS OF INCOME/(LOSS)
FOR THE YEARS ENDED DECEMBER 31, 2006, 2005 AND 2004
(Thousands of Dollars, Except Share Information)
Operating Revenues
$ -
$ -
$ -
Operating Expenses:
Other
4,063
7,955
8,430
Operating Loss
(4,063)
(7,955)
(8,430)
Interest Expense
32,945
33,068
24,868
Other Income:
Equity in earnings/(losses) of subsidiaries
473,279
(240,179)
131,127
Other, net
29,493
17,218
13,551
Other Income/(Loss), Net
502,772
(222,961)
144,678
Income/(Loss) Before Income Tax Benefit
465,764
(263,984)
111,380
Income Tax Benefit
(4,814)
(10,496)
(5,208)
Earnings/(Loss) for Common Shares
$ 470,578
$ (253,488)
$ 116,588
Basic Earnings/(Loss) Per Common Share
$ 3.06
$ (1.93)
$ 0.91
Fully Diluted Earnings/(Loss) Per Common Share
$ 3.05
$ (1.93)
$ 0.91
Basic Common Shares Outstanding (weighted average)
153,767,527
131,638,953
128,245,860
Fully Diluted Common Shares Outstanding (weighted average)
154,146,669
131,638,953
128,396,076
Schedule II
Northeast Utilities and Subsidiaries
Valuation and Qualifying Accounts and Reserves
Year Ended December 31, 2006
(Thousands of Dollars)
(a)
Amount relates to uncollectible amounts reserved for that relate to receivables other than those of customers.
(b)
Amounts written off, net of recoveries.
(c)
Principally payments for environmental remediation, various injuries and damages, employee medical expenses, and expenses in connection therewith. This amount also includes a reduction to environmental reserves related to Mt. Tom property that was sold to ECP in 2006.
(d)
Amounts include activity related to accounts that are classified as assets held for sale and discontinued operations.
Schedule II
Northeast Utilities and Subsidiaries
Valuation and Qualifying Accounts and Reserves
Year Ended December 31, 2005
(Thousands of Dollars)
(a)
Amount relates to uncollectible amounts reserved for that relate to receivables other than those of customers.
(b)
Amounts written off, net of recoveries.
(c)
Principally payments for environmental remediation, various injuries and damages, employee medical expenses, and expenses in connection therewith. This amount also includes a reduction to environmental reserves related to land that was sold in 2005.
(d)
Amounts include activity related to accounts that are classified as assets held for sale and discontinued operations.
Schedule II
Northeast Utilities and Subsidiaries
Valuation and Qualifying Accounts and Reserves
Year Ended December 31, 2004
(Thousands of Dollars)
(a)
Amounts written off, net of recoveries and other adjustments.
(b)
Principally payments for environmental remediation, various injuries and damages, employee medical expenses, inventory reserves and expenses in connection therewith.
Schedule II
The Connecticut Light and Power Company and Subsidiaries
Valuation and Qualifying Accounts and Reserves
Year Ended December 31, 2006
(Thousands of Dollars)
(a) Amount relates to uncollectible amounts reserved for that relate to receivables other than those of customers.
(b) Amounts written off, net of recoveries and other adjustments.
(c)
Principally payments for environmental remediation, various injuries and damages, employee medical expenses, and expenses in connection therewith.
Schedule II
The Connecticut Light and Power Company and Subsidiaries
Valuation and Qualifying Accounts and Reserves
Year Ended December 31, 2005
(Thousands of Dollars)
(a) Amount relates to uncollectible amounts reserved for that relate to receivables other than those of customers.
(b) Amounts written off, net of recoveries and other adjustments.
(c)
Principally payments for environmental remediation, various injuries and damages, employee medical expenses, and expenses in connection therewith. This amount also includes a reduction to environmental reserves related to land that was sold in 2005.
Schedule II
The Connecticut Light and Power Company and Subsidiaries
Valuation and Qualifying Accounts and Reserves
Year Ended December 31, 2004
(Thousands of Dollars)
(a)
Amounts written off, net of recoveries and other adjustments.
(b)
Principally payments for environmental remediation, various injuries and damages, employee medical expenses, inventory reserves and expenses in connection therewith.
Schedule II
Public Service Company of New Hampshire and Subsidiaries
Valuation and Qualifying Accounts and Reserves
Year Ended December 31, 2006
(Thousands of Dollars)
(a)
Amount relates to uncollectible amounts reserved for that relate to receivables other than those of customers.
(b) Amounts written off, net of recoveries.
(c)
Principally payments for environmental remediation, various injuries and damages, employee medical expenses, inventory reserves and expenses in connection therewith.
Schedule II
Public Service Company of New Hampshire and Subsidiaries
Valuation and Qualifying Accounts and Reserves
Year Ended December 31, 2005
(Thousands of Dollars)
(a)
Amount relates to uncollectible amounts reserved for that relate to receivables other than those of customers.
(b) Amounts written off, net of recoveries.
(c)
Principally payments for environmental remediation, various injuries and damages, employee medical expenses, inventory reserves and expenses in connection therewith.
Schedule II
Public Service Company of New Hampshire and Subsidiaries
Valuation and Qualifying Accounts and Reserves
Year Ended December 31, 2004
(Thousands of Dollars)
(a)
Amount relates to uncollectible amounts reserved for that relate to receivables other than those of customers and New Hampshire's low-income assistance program.
(b)
Amounts written off, net of recoveries.
(c)
Principally payments for environmental remediation, various injuries and damages, employee medical expenses, inventory reserves and expenses in connection therewith.
Schedule II
Western Massachusetts Electric Company and Subsidiary
Valuation and Qualifying Accounts and Reserves
Year Ended December 31, 2006
(Thousands of Dollars)
(a)
Amount relates to uncollectible amounts reserved for that relate to receivables other than those of customers.
(b)
Amounts written off, net of recoveries.
(c)
Principally payments for environmental remediation, various injuries and damages, employee medical expenses, inventory reserves and expenses in connection therewith.
Schedule II
Western Massachusetts Electric Company and Subsidiary
Valuation and Qualifying Accounts and Reserves
Year Ended December 31, 2005
(Thousands of Dollars)
(a)
Amount relates to uncollectible amounts reserved for that relate to receivables other than those of customers.
(b)
Amounts written off, net of recoveries.
(c)
Principally payments for environmental remediation, various injuries and damages, employee medical expenses, inventory reserves and expenses in connection therewith.
Schedule II
Western Massachusetts Electric Company and Subsidiary
Valuation and Qualifying Accounts and Reserves
Year Ended December 31, 2004
(Thousands of Dollars)
(a)
Amounts written off, net of recoveries.
(b)
Principally payments for environmental remediation, various injuries and damages, employee medical expenses, inventory reserves and expenses in connection therewith.
EXHIBIT INDEX
Each document described below is incorporated by reference by the registrant(s) listed to the files identified, unless designated with a (*), which exhibits are filed herewith.
Exhibit
Number
Description
Plan of acquisition, reorganization, arrangement, liquidation or succession
(A)
NU
2.1
Amended and Restated Agreement and Plan of Merger (Exhibit 1 to NU Form 8-K dated December 2, 1999, File No. 1-5324)
Articles of Incorporation and By-Laws
(A)
Northeast Utilities
3.1
Declaration of Trust of NU, as amended through May 10, 2005 (Exhibit A.1, NU Form U-1 dated June 23, 2005, File No. 70-10315)
(B)
The Connecticut Light and Power Company
3.1
Certificate of Incorporation of CL&P, restated to March 22, 1994. (Exhibit 3.2.1, 1993 NU Form 10-K, File No. 1-5324)
3.1.2
Certificate of Amendment to Certificate of Incorporation of CL&P, dated December 26, 1996. (Exhibit 3.2.2, 1996 NU Form 10-K, File No. 1-5324)
3.1.3
Certificate of Amendment to Certificate of Incorporation of CL&P, dated April 27, 1998. (Exhibit 3.2.3, 1998 NU Form 10-K, File No. 1-5324)
3.2
By-laws of CL&P, as amended to January 1, 1997. (Exhibit 3.2.3, 1996 NU Form 10-K, File No. 1-5324)
(C)
Public Service Company of New Hampshire
3.1
Articles of Incorporation, as amended to May 16, 1991. (Exhibit 3.3.1, 1993 NU Form 10-K, File No. 1-5324)
3.2
By Laws of PSNH, as in effect June 30, 2005 (Exhibit 3.2, NU Form 10-Q for the Quarter Ended June 30, 2005, File No. 1-5324)
(D)
Western Massachusetts Electric Company
3.1
Articles of Organization of WMECO, restated to February 23, 1995. (Exhibit 3.4.1, 1994 NU Form 10-K, File No. 1-5324)
3.2
By-laws of WMECO, as amended to April 1, 1999. (Exhibit 3.1, NU Form 10-Q for the Quarter Ended June 30, 1999, File No. 1-5324)
3.2.1
By-laws of WMECO, as further amended to May 1, 2000. (Exhibit 3.1, NU Form 10-Q for the Quarter Ended June 30, 2000, File No. 1-5324)
Instruments defining the rights of security holders, including indentures
(A)
Northeast Utilities
4.1
Rights Agreement dated as of February 23, 1999, between Northeast Utilities and Northeast Utilities Service Company, as Rights Agent. (Exhibit 1 to NU's Registration Statement on Form 8-A, filed on April 12, 1999, File No. 001-05324)
4.1.1
Amendment to Rights Agreement. (Exhibit 3 to NU Form 8-K dated October 13, 1999, File No. 1-5324)
4.1.2
Second Amendment to Rights Agreement. (Exhibit B-3 to NU 35-CERT, dated February 1, 2002, File No. 070-09463)
4.2
Indenture dated as of April 1, 2002, between NU and the Bank of New York as Trustee. (Exhibit A-3 to NU 35-CERT filed April 9, 2002, File No. 70-9535)
4.2.1
First Supplemental Indenture dated as of April 1, 2002, between NU and the Bank of New York as Trustee, relating to $263M of Senior Notes, Series A, due 2012. (Exhibit A-4 to NU 35-CERT filed April 9, 2002, File No. 70-9535)
4.2.2
Second Supplemental Indenture dated as of June 1, 2003, between NU and the Bank of New York as Trustee, relating to $150M of Senior Notes, Series B, due 2008. (Exhibit A-1.3 to NU 35-CERT filed June 6, 2003, File No. 70-10051)
4.3
Credit Agreement dated as of November 2, 2005 among Northeast Utilities, the Banks Named Therein, the Lenders party thereto and Barclays Bank PLC as Administrative Agent and Fronting Bank (Exhibit B-1 to NU 35-CERT filed November 10, 2005, File No. 70-10315)
4.4
Amended and Restated Credit Agreement dated December 9, 2005 between NU, the Banks Named Therein, Union Bank of California, N.A. as Administrative Agent, and Barclays Bank, PLC, JPMorgan Chase Bank, N.A. and Union Bank of California, N.A., as Fronting Banks (Exhibit 99.1, NU Form 8-K dated December 9, 2005, File No. 1-5324)
(B)
The Connecticut Light and Power Company
4.1
Indenture of Mortgage and Deed of Trust between CL&P and Bankers Trust Company, Trustee, dated as of May 1, 1921. (Composite including all twenty-four amendments to May 1, 1967.) (Exhibit 4.1.1, 1989 CL&P Form 10-K, File No. 0-00404)
4.1.1
Supplemental Indentures to the Composite May 1, 1921 Indenture of Mortgage and Deed of Trust between CL&P and Bankers Trust Company, dated as of October 1, 1994. (Exhibit 4.2.16, 1994 CL&P Form 10-K, File No. 1-11419)
4.1.2
Series A Supplemental Indenture between CL&P and Deutsche Bank Trust Company Americas, as Trustee, dated as of September 1, 2004 (Exhibit 99.2 to CL&P Form 8-K filed September 22, 2004, File No. 0-00404)
4.1.3
Series B Supplemental Indenture between CL&P and Deutsche Bank Trust Company Americas, as Trustee dated as of September 1, 2004 (Exhibit 99.5 to CL&P Form 8-K filed September 22, 2004, File No. 0-00404)
*4.2
Composite Indenture of Mortgage and Deed of Trust between CL&P and Deutsche Bank Trust Company Americas f/k/a Bankers Trust Company , dated as of May 1, 1921, as amended and supplemented by seventy-three supplemental mortgages to and including Supplemental Mortgage dated as of April 1, 2005.
4.2.1
Supplemental Indenture (2005 Series A Bonds and 2005 Series B Bonds) between CL&P and Deutsche Bank Trust Company Americas, as Trustee dated as of April 1, 2005 (Exhibit 99.2 to CL&P Form 8-K filed April 13, 2005, File No. 0-00404)
4.2.2
Supplemental Indenture (2006 Series A Bonds) between CL&P and Deutsche Bank Trust Company Americas, as Trustee dated as of June 1, 2006 (“Supplemental Indenture”) (Exhibit 99.2 to CL&P Form 8-K filed June 7, 2006, File No. 0-00404)
4.3
Financing Agreement between Industrial Development Authority of the State of New Hampshire and CL&P (Pollution Control Bonds, 1986 Series) dated as of December 1, 1986. (Exhibit C.1.47, 1986 NU Form U5S, File No. 30-246)
4.4
Financing Agreement between Industrial Development Authority of the State of New Hampshire and CL&P (Pollution Control Bonds, 1988 Series) dated as of October 1, 1988. (Exhibit C.1.55, 1988 NU Form U5S, File No. 30-246)
4.5
Loan and Trust Agreement among Business Finance Authority of the State of New Hampshire, CL&P and the Trustee (Pollution Control Bonds, 1992 Series A) dated as of December 1, 1992. (Exhibit C.2.33, 1992 NU Form U5S, File No. 30-246)
4.6
Loan Agreement between Connecticut Development Authority and CL&P (Pollution Control Bonds - Series A, Tax Exempt Refunding) dated as of September 1, 1993. (Exhibit 4.2.21, 1993 CL&P Form 10-K, File No. 0-00404)
4.7
Loan Agreement between Connecticut Development Authority and CL&P (Pollution Control Bonds - Series B, Tax Exempt Refunding) dated as of September 1, 1993. (Exhibit 4.2.22, 1993 CL&P Form 10-K, File No. 0-00404)
4.8
Amended and Restated Loan Agreement between Connecticut Development Authority and CL&P (Pollution Control Revenue Bond - 1996A Series) dated as of May 1, 1996 and Amended and Restated as of January 1, 1997. (Exhibit 4.2.24, 1996 CL&P Form 10-K, File No. 0-00404)
4.9
Amended and Restated Indenture of Trust between Connecticut Development Authority and the Trustee (CL&P Pollution Control Revenue Bond-1996A Series), dated as of May 1, 1996 and Amended and Restated as of January 1, 1997. (Exhibit 4.2.24.1, 1996 CL&P Form 10-K, File No. 0-00404)
4.10
AMBAC Municipal Bond Insurance Policy issued by the Connecticut Development Authority (CL&P Pollution Control Revenue Bond-1996A Series), effective January 23, 1997.(Exhibit 4.2.24.3, 1996 CL&P Form 10-K, File No. 1-11419)
4.11
Compensation and Multiannual Mode Agreement among the Connecticut Development Authority and BNY Capital Markets, Inc. dated September 23, 2003 (Exhibit 4.2.7.5, CL&P Form 10-Q for the Quarter Ended September 30, 2003, File No. 0-00404)
4.12
Amended and Restated Receivables Purchase and Sale Agreement among CL&P and CL&P Receivables Corporation (“CRC”) Corporate Asset Funding Company. Inc. (“CAFCO”), Citibank, N. A. (“Citibank”) and Citicorp North America, Inc. (“CNAI”), dated as of March 30, 2001. (Exhibit 10.1, CL&P Form 10-Q for the Quarter Ended September 30, 2001, File No. 0-00404)
4.12.1
Amendment No. 2 to the Amended and Restated Receivables Purchase and Sale Agreement among CL&P, CRC, CAFCO., Citibank, and CNAI, dated as of July 10, 2002 (Exhibit 4.2.8.1, 2002 CL&P Form 10-K, File No. 0-00404)
4.12.2
Amendment No. 3 to the Amended and Restated Receivables Purchase and Sales Agreement among CL&P, CRC, CAFCO., Citibank, and CNAI, dated as of July 9, 2003 (Exhibit 4.2.8.2, CL&P Form 10-Q for the Quarter Ended September 30, 2003, File No. 0-00404)
4.12.3
Amendment No. 4 to the Amended and Restated Receivables Purchase and Sales Agreement among CL&P, CRC, CAFCO., Citibank, and CNAI, dated as of July 7, 2004 (Exhibit 4.12.3 to CL&P Form 10-Q for the Quarter Ended June 30, 2005, File No. 0-00404)
4.12.4
Amendment No. 5 to the Amended and Restated Receivables Purchase and Sales Agreement among CL&P, CRC, CAFCO., Citibank, and CNAI, dated as of July 7, 2005 (Exhibit 4.12.4 to CL&P Form 10-Q for the Quarter Ended June 30, 2005, File No. 0-00404)
4.12.5
Amendment No. 6 to the Amended and Restated Receivables Purchase and Sales Agreement among CL&P, CRC, CAFCO., Citibank, and CNAI, dated as of July 5, 2006 (Exhibit 4.12.5 to CL&P Form 10-Q for the Quarter Ended June 30, 2006 File No. 0-00404)
4.12.6
Letter Amendment dated July 21, 2006 to Amended and Restated Receivables Purchase and Sales Agreement among CL&P, CRC, CAFCO., Citibank, and CNAI, dated as of July 5, 2006 (Exhibit 4.12.6 to CL&P Form 10-Q for the Quarter Ended September 30, 2006 File No. 0-00404)
4.13
Purchase and Contribution Agreement between CL&P and CRC, dated as of September 30, 1997 (Exhibit 10.49.1, 1997 NU Form 10-K, File No. 1-5324)
4.13.1
Amendment No. 1 to the Purchase and Contribution Agreement between CL&P and CRC dated as of March 30, 2001 (Exhibit 4.2.9 of 2002 CL&P Form 10-K, File No. 0-00404)
*4.13.2
Amendment No. 3 to the Purchase and Contribution Agreement between CL&P and CRC dated as of July 7, 2004.
4.14
Amended and Restated Credit Agreement dated December 9, 2005 between CL&P, WMECO, Yankee Gas and PSNH, the Banks Named Therein, and Citicorp USA, Inc., as Administrative Agent (Exhibit 99.2, CL&P Form 8-K dated December 9, 2005, File No. 0-00404)
(C)
Public Service Company of New Hampshire
4.1
First Mortgage Indenture dated as of August 15, 1978 between PSNH and First Fidelity Bank, National Association, New Jersey, now First Union National Bank, Trustee, (Composite including all amendments to May 16, 1991). (Exhibit 4.4.1, 1992 PSNH Form 10-K, File No. 1-6392)
4.1.1
Tenth Supplemental Indenture dated as of May 1, 1991 between PSNH and First Fidelity Bank, National Association, now First Union National Bank. (Exhibit 4.1, PSNH Form 8-K dated February 10, 1992, File No. 1-6392)
4.1.2
Twelfth Supplemental Indenture dated as of December 1, 2001 between PSNH and First Union National Bank. (Exhibit 4.3.1.2, 2001 PSNH Form 10-K, File No. 1-6392)
4.1.3
Thirteenth Supplemental Indenture, dated as of July 1, 2004, between PSNH and Wachovia Bank, National Association, successor to First Union National Bank, as successor to First Fidelity Bank, National Association, as Trustee (Exhibit 99.2 to PSNH Form 8-K filed October 5, 2004, File No. 1-6392)
4.1.4
Fourteenth Supplemental Indenture, dated as of October 1, 2005, between PSNH and Wachovia Bank, National Association successor to First Union National Bank, as successor to First Fidelity Bank, National Association, as Trustee (Exhibit 99.2 to PSNH Form 8-K filed October 6, 2005, File No. 1-6392)
4.2
Series D (Tax Exempt Refunding) Amended and Restated PCRB Loan and Trust Agreement dated as of April 1, 1999. (Exhibit 4.3.6, 1999 PSNH Form 10-K, File No. 1-6392)
4.3
Series E (Tax Exempt Refunding) Amended & Restated PCRB Loan and Trust Agreement dated as of April 1, 1999. (Exhibit 4.3.7, 1999 PSNH Form 10-K, File No. 1-6392)
4.4
Series A Loan and Trust Agreement among Business Finance Authority of the State of New Hampshire and PSNH and State Street Bank and Trust Company, as Trustee (Tax Exempt Pollution Control Bonds) dated as of October 1, 2001. (Exhibit 4.3.4, 2001 PSNH Form 10-K, File No. 1-6392)
4.5
Series B Loan and Trust Agreement among Business Finance Authority of the State of New Hampshire and PSNH and State Street Bank and Trust Company, as Trustee (Tax Exempt Pollution Control Bonds) dated as of October 1, 2001. (Exhibit 4.3.5, 2001 PSNH Form 10-K, File No. 1-6392)
4.6
Series C Loan and Trust Agreement among Business Finance Authority of the State of New Hampshire and PSNH and State Street Bank and Trust Company, as Trustee (Tax Exempt Pollution Control Bonds) dated as of October 1, 2001. (Exhibit 4.3.6, 2001 PSNH Form 10-K, File No. 1-6392)
4.7
Amended and Restated Credit Agreement dated December 9, 2005 between CL&P, WMECO, Yankee Gas and PSNH, the Banks Named Therein, and Citicorp USA, Inc., as Administrative Agent (Exhibit 99.2, PSNH Form 8-K dated December 9, 2005, File No. 1-6392)
(D)
Western Massachusetts Electric Company
4.1
Loan Agreement between Connecticut Development Authority and WMECO, (Pollution Control Bonds - Series A, Tax Exempt Refunding) dated as of September 1, 1993. (Exhibit 4.4.13, 1993 WMECO Form 10-K, File No. 0-7624)
4.2
Indenture between WMECO and the Bank of New York, as Trustee, dated as of September 1, 2003 (Exhibit 99.2, WMECO Form 8-K filed October 8, 2003, File No. 0-7624)
4.2.1
First Supplemental Indenture between WMECO and the Bank of New York, as Trustee, dated as of September 1, 2003 (Exhibit 99.3, WMECO Form 8-K filed October 8, 2003, File No. 0-7624)
4.2.2
Second Supplemental Indenture dated as of September 1, 2004, between WMECO and Bank of New York, as Trustee. (Exhibit 4.1 to WMECO Form 8-K filed September 27, 2004, File No. 0-7624)
4.2.3
Third Supplemental Indenture between WMECO and The Bank of New York Trust, as Trustee, dated as of August 1, 2005 (Exhibit 4.1, WMECO Form 8-K filed August 12, 2005, File No. 0-7624)
4.3
Amended and Restated Credit Agreement dated December 9, 2005 between CL&P, WMECO, Yankee Gas and PSNH, the Banks Named Therein, and Citicorp USA, Inc., as Administrative Agent (Exhibit 99.2, WMECO Form 8-K dated December 9, 2005, File No. 1-6392)
Material Contracts
(A)
NU
10.1
Lease dated as of April 14, 1992 between The Rocky River Realty Company and Northeast Utilities Service Company with respect to the Berlin, Connecticut headquarters. (Exhibit 10.29, 1992 NU Form 10-K, File No. 1-5324)
10.2
Indenture of Mortgage and Deed of Trust dated July 1, 1989 between Yankee Gas Services Company and the Connecticut National Bank, as Trustee (Exhibit 4.7, Yankee Energy System, Inc. Form 10-K for the fiscal year ended September 30, 1990, File No. 0-10721)
10.2.1
First Supplemental Indenture of Mortgage and of Trust dated April 1, 1992 between Yankee Gas Services Company and The Connecticut National Bank, as Trustee Yankee Energy System, Inc. Registration Statement on Form S-3, dated October 2, 1992, File No. 33-52750)
10.2.2
Fourth Supplemental Indenture of Mortgage and Deed of Trust dated April 1, 1997 between Yankee Gas Services Company and Fleet National Bank (formerly The Connecticut National Bank), as Trustee. (Exhibit 4.15 Yankee Energy System, Inc. Form 10-K for the fiscal year ended September 30, 1997, File No. 001-10721)
10.2.3
Fifth Supplemental Indenture of Mortgage and Deed of Trust dated January 1, 1999 between Yankee Gas Services Company and The Bank of New York, as Successor Trustee to Fleet Bank (formerly The Connecticut National Bank) (Exhibit 4.2 Yankee Energy System, Inc. Form 10-Q for the fiscal quarter ended March 31, 1999, File No. 001-10721)
10.2.4
Sixth Supplemental Indenture and Deed of Trust dated January 1, 2004 between Yankee Gas Services Company and The Bank of New York, as Successor Trustee to Fleet Bank (formerly The Connecticut National Bank) (Exhibit 10.5.6, 2004 NU Form 10-K, File No. 1-5324)
10.2.5
Seventh Supplemental Indenture and Deed of Trust dated November 1, 2004 between Yankee Gas Services Company and The Bank of New York, as Successor Trustee to Fleet Bank (formerly The Connecticut National Bank) (Exhibit 10.5.7, 2004 NU Form 10-K, File No. 1-5324)
10.2.6
Eighth Supplemental Indenture and Deed of Trust dated July 1, 2005 between Yankee Gas Services Company and The Bank of New York, as Successor Trustee to Fleet Bank (formerly the Connecticut National Bank) (Exhibit 10.5.8 to NU Form 10-Q for the Quarter Ended June 30, 2005, File No. 1-5324)
10.3
Employment Agreement of Lawrence E. DeSimone, dated as of October 25,2004 (Exhibit 10.28, 2004 NU Form 10-K, File No. 1-5324)
*10.4
Summary of Trustee Compensation
10.5
Northeast Utilities Deferred Compensation Plan for Trustees, amended and restated effective January 1, 2004 (Exhibit 10.32 to NU Form 10-Q for the Quarter Ended March 31, 2004, File No. 1-5324)
10.5.1
Amendment No. 3 to Northeast Utilities Deferred Compensation Plan for Trustees, effective January 1, 2005 (Exhibit 10.24.1 , 2005 NU Form 10-K, File No. 1-5324).
*10.5.2
Amendment No. 4 to Northeast Utilities Deferred Compensation Plans for Trustees, effective September 12, 2006.
10.6
Purchase and Sale Agreement dated as of May 1, 2006 between Select Energy, Inc. and Amerada Hess Corporation (Exhibit 10.32 to NU Form 10-Q for the Quarter Ended March 31, 2006, File No. 1-5324)
10.7
Purchase and Sale Agreement dated July 24, 2006 between HWP and Mt. Tom Generating Company LLC. (Exhibit 10.33 to NU Form 10-Q for the Quarter Ended June 30, 2006, File No. 1-5324)
10.7.1
Guaranty dated July 24, 2006 of Energy Capital Partners I, LP for the benefit of HWP (Exhibit 10.33.1 to NU Form 10-Q for the Quarter Ended June 30, 2006, File No. 1-5324)
10.7.2
Guaranty dated July 24, 2006 of NU for the benefit of Mt. Tom Generating Company LLC (Exhibit 10.33.2 to NU Form 10-Q for the Quarter Ended June 30, 2006, File No. 1-5324)
10.8
Stock Purchase Agreement dated July 24, 2006 between NU Enterprises and NE Energy, Inc. (Exhibit 10.34 to NU Form 10-Q for the Quarter Ended June 30, 2006, File No. 1-5324)
10.8.1
Guaranty dated July 24, 2006 of Energy Capital Partners I, LP for the benefit of NU Enterprises (Exhibit 10.34.2 to NU Form 10-Q for the Quarter Ended June 30, 2006, File No. 1-5324)
10.8.2
Guaranty dated July 24, 2006 of NU for the benefit of NE Energy, Inc. (Exhibit 10.34.2 to NU Form 10-Q for the Quarter Ended June 30, 2006, File No. 1-5324)
10.9
Purchase and Sale Agreement dated July 24, 2006 by and among NGS, Select Energy, Northeast Utilities Service Company on the one hand, and NE Energy, Inc. on the other hand (Exhibit 10.35 to NU Form 10-Q for the Quarter Ended June 30, 2006, File No. 1-5324)
10.9.1
Guaranty dated July 24, 2006 of Energy Capital Partners I, LP for the benefit of NGS, Select and Northeast Utilities Service Company (Exhibit 10.35.1 to NU Form 10-Q for the Quarter Ended June 30, 2006, File No. 1-5324)
10.9.2
Guaranty dated July 24, 2006 of NU for the benefit of NE Energy, Inc. (Exhibit 10.35.2 to NU Form 10-Q for the Quarter Ended June 30, 2006, File No. 1-5324)
10.10
Stock Purchase Agreement dated as of February 1, 2006 by and among Ameresco, Inc. (“Ameresco”), NU Enterprises and NU (Exhibit 10.36 to NU Form 10-Q for the Quarter Ended June 30, 2006, File No. 1-5324)
10.10.1
Extension Letter dated March 1, 2006 among NU Enterprises, NU and Ameresco (Exhibit 10.36.1 to NU Form 10-Q for the Quarter Ended June 30, 2006, File No. 1-5324)
10.10.2
Extension Letter dated March 31, 2006 between NU Enterprises, NU and Ameresco (Exhibit 10.36.2 to NU Form 10-Q for the Quarter Ended June 30, 2006, File No. 1-5324)
10.10.3
Stock Purchase Agreement Amendment and Waiver dated as of May 5, 2006 among NU Enterprises, NU and Ameresco (Exhibit 10.36.3 to NU Form 10-Q for the Quarter Ended June 30, 2006, File No. 1-5324)
10.10.4
NU Indemnification Agreement dated as of May 5, 2006 (Exhibit 10.36.4 to NU Form 10-Q for the Quarter Ended June 30, 2006, File No. 1-5324)
10.10.5
Agreement to Purchase Contract Payments dated as of May 5, 2006 among NU, Ameresco and General Electric Capital Corporation (Exhibit 10.36.5 to NU Form 10-Q for the Quarter Ended June 30, 2006, File No. 1-5324)
(B)
NU, CL&P, PSNH and WMECO
10.1
Service Contract dated as of July 1, 1966 between each of NU, CL&P and WMECO and Northeast Utilities Service Company (NUSCO). (Exhibit 10.20, 1993 NU Form 10-K, File No. 1-5324)
*10.2
Form of Amendment and Renewal of Service Contract dated as of January 1, 2007.
10.3
Memorandum of Understanding between CL&P, HELCO, HP&E, HWP and WMECO dated as of June 1, 1970 with respect to pooling of generation and transmission. (Exhibit 13.32, File No. 2-38177)
10.3.1
Amendment to Memorandum of Understanding between CL&P, HELCO, HP&E, HWP and WMECO dated as of February 2, 1982 with respect to pooling of generation and transmission. (Exhibit 10.21.1, 1993 NU Form 10-K, File No. 1-5324)
10.3.2
Amendment to Memorandum of Understanding between CL&P, HELCO, HP&E, HWP and WMECO dated as of January 1, 1984 with respect to pooling of generation and transmission. (Exhibit 10.21.2, 1994 NU Form 10-K, File No. 1-5324)
10.3.3
Second Amendment to Memorandum of Understanding between CL&P, HELCO, HP&E, HWP and WMECO dated as of June 8, 1999 with respect to pooling of generation and transmission. (Exhibit 10.23.3, 1999 NU Form 10-K, File No. 1-5324)
10.4
Stockholder Agreement dated as of July 1, 1964 among the stockholders of Connecticut Yankee Atomic Power Company (CYAPC). (Exhibit 10.1, 1994 NU Form 10-K, File No. 1-5324)
10.5
Capital Funds Agreement dated as of September 1, 1964 between CYAPC and CL&P, HELCO, PSNH and WMECO. (Exhibit 10.3, 1994 NU Form 10-K, File No. 1-5324)
10.6
Power Purchase Contract dated as of July 1, 1964 between CYAPC and each of CL&P, HELCO, PSNH and WMECO. (Exhibit 10.2, 1994 NU Form 10-K, File No. 1-5324)
10.7
Additional Power Purchase Contract dated as of April 30, 1984, between CYAPC and each of CL&P, PSNH and WMECO. (Exhibit 10.2.1, 1994 NU Form 10-K, File No. 1-5324)
10.8
Supplementary Power Contract dated as of April 1, 1987, between CYAPC and each of CL&P, PSNH and WMECO. (Exhibit 10.2.6, 1987 NU Form 10 K, File No. 1-5324)
10.9
Form of 1996 Amendatory Agreement between CYAPC and CL&P dated December 4, 1996. (Exhibit 10 (B) 10.9, 2003 NU Form 10-K, File No. 1-5324)
10.9.1
Form of First Supplemental to the 1996 Amendatory Agreement dated as of February 10, 1997 (Exhibit 10 (B) 10.9.1, 2003 NU Form 10-K, File No. 1-5324)
10.10
Amended and Restated Additional Power Contract between CYAPC and purchasers named therein, dated as of April 30, 1984 and restated as of July 1, 2004 ) (Exhibit 10.9.3, 2004 NU Form 10-K, File No. 1-5324)
*10.10.1
Revision to Attachment B to Amended and Restated Additional Power Contract, dated as of April 30, 1984, issued on August 15, 2007 and effective January 1, 2007 (as contained in Settlement Agreement dated August 15, 2006 among CYAPC, Connecticut Department of Public Utility Control, Connecticut Consumer Counsel, Maine Public Advocate and Maine Public Utility Commission, filed with the Federal Energy Regulatory Commission on August 15, 2006 in Dockets Nos. ER04-981-000 and EL04-109-000).
10.11
2000 Amendatory Agreement between CYAPC and CL&P dated as of July 28, 2000 (Exhibit 10.9.2, 2004 NU Form 10-K, File No. 1-5324)
10.12
Stockholder Agreement dated December 10, 1958 between Yankee Atomic Electric Company (YAEC) and CL&P, HELCO, PSNH and WMECO. (Exhibit 10.4, 1993 NU Form 10-K, File No. 1-5324)
10.13
Amended and Restated Power Purchase Contract dated as of April 1, 1985, between YAEC and each of CL&P, PSNH and WMECO. (Exhibit 10.5, 1988 NU Form 10-K, File No. 1-5324)
10.13.1
Amendment No. 4 to Power Contract, dated May 6, 1988, between YAEC and each of CL&P, PSNH and WMECO. (Exhibit 10.5.1, 1989 NU Form 10-K, File No. 1-5324)
10.13.2
Amendment No. 5 to Power Contract, dated June 26, 1989, between YAEC and each of CL&P, PSNH and WMECO. (Exhibit 10.5.2, 1989 NU Form 10-K, File No. 1-5324)
10.13.3
Amendment No. 6 to Power Contract, dated July 1, 1989, between YAEC and each of CL&P, PSNH and WMECO. (Exhibit 10.5.3, 1989 NU Form 10-K, File No. 1-5324)
10.13.4
Amendment No. 7 to Power Contract, dated February 1, 1992, between YAEC and each of CL&P, PSNH and WMECO. (Exhibit 10.5.4, 1993 NU Form 10-K, File No. 1-5324)
10.13.5
Form of Amendment No. 8 to Power Contract, dated June 1, 2003, between YAEC and each of CL&P, PSNH and WMECO (Exhibit 10 (B) 10.11.5, 2003 NU Form 10-K, File No. 1-5324)
10.13.6
Form of Amendment No. 9 to Power Contract, dated November 17, 2005, between YAEC and each of CL&P, PSNH and WMECO (Exhibit 10.11.6 to 2005 NU Form 10-K, File No. 1-5324)
10.13.7
Form of Amendment No. 10 to Power Contract, dated April 14, 2006 between YAEC and each of CL&P, PSNH and WMECO (Exhibit 10.11.7 to NU Form 10-Q for the Quarter Ended June 30, 2006, File No. 1-5324)
10.14
Stockholder Agreement dated as of May 20, 1968 among stockholders of MYAPC. (Exhibit 10.6, 1997 NU Form 10-K, File No. 1-5324)
10.15
Capital Funds Agreement dated as of May 20, 1968 between MYAPC and CL&P, PSNH, HELCO and WMECO. (Exhibit 10.8, 1997 NU Form 10-K, File No. 1-5324)
10.15.1
Amendment No. 1 to Capital Funds Agreement, dated as of August 1, 1985, between MYAPC, CL&P, PSNH and WMECO. (Exhibit No. 10.8.1, 1994 NU Form 10-K, File No. 1-5324)
10.16
Power Purchase Contract dated as of May 20, 1968 between MYAPC and each of CL&P, HELCO, PSNH and WMECO. (Exhibit 10.7, 1997 Form 10-K, File No. 1-5324)
10.16.1
Amendment No. 1 to Power Contract dated as of March 1, 1983 between MYAPC and each of CL&P, PSNH and WMECO. (Exhibit 10.7.1, 1993 NU Form 10-K, File No. 1-5324)
10.16.2
Amendment No. 2 to Power Contract dated as of January 1, 1984 between MYAPC and each of CL&P, PSNH and WMECO. (Exhibit 10.7.2, 1993 NU Form 10-K, File No. 1-5324)
10.16.3
Amendment No. 3 to Power Contract dated as of October 1, 1984 between MYAPC and each of CL&P, PSNH and WMECO. (Exhibit No. 10.7.3, 1994 NU Form 10-K, File No. 1-5324)
10.17
Additional Power Contract dated as of February 1, 1984 between MYAPC and each of CL&P, PSNH and WMECO. (Exhibit 10.7.4, 1993 NU Form 10-K, File No. 1-5324)
10.18
1997 Amendatory Agreement dated as of August 6, 1997 between MYAPC and each of CL&P, PSNH and WMECO (Exhibit 10.14.5, 2005 NU Form 10-K, File No. 1-5324)
*10.19
Composite Conformed Rate Schedule 2004 reflecting the operative provisions of : I. Additional Power Contract dated as of February 1, 1984, II. 1997 Amendatory Agreement dated as of August 6, 1997, III. Settlement Agreement in Docket No. ER-04-55-000 and IV. Formula Rate.
10.20
Sharing Agreement between CL&P, WMECO, HP&E, HWP and PSNH dated as of June 1, 1992. (Exhibit 10.17, 1992 NU Form 10-K, File No. 1-5324)
10.21
Agreements among New England Utilities with respect to the Hydro-Quebec interconnection projects. (Exhibits 10(u) and 10(v); 10(w), 10(x), and 10(y), 1990 and 1988, respectively, Form 10-K of New England Electric System, File No. 1-3446.)
10.22
Transmission Operating Agreement dated as of February 1, 2005 between the Initial Participating Transmission Owners, Additional Participating Transmission Owners and ISO New England, Inc. (Exhibit 10.29, 2004 NU Form 10-K, File No. 1-5324)
*10.22.1
Rate Design and Funds Disbursement Agreement, effective June 30, 2006 among the Initial Participating Transmission Owners, Additional Participating Transmission Owners and ISO New England, Inc.
10.23
ISO New England, Inc. FERC Electric Tariff No. 3, Section II- Open Access Transmission Tariff, Schedule 21-NU (Northeast Utilities Companies Local Service Schedule), Issued on December 22, 2004 and Effective, With Notice on or after February 1, 2005 (Exhibit 10.30, 2005 NU Form 10-K, File No. 1-5324)
10.24
Employment Agreement with Cheryl W. Grisé, dated as of April 1, 2003 (Exhibit 10.45.6 to NU Form 10-Q for Quarter Ended March 31, 2003, File No. 1-5324)
*10.24.1
Terms of Separation arrangements for Cheryl W. Grisé.
10.25
Employment Agreement with Charles W. Shivery dated as of March 31, 2005 (Exhibit 10.24.2 to NU Form 10-Q for the Quarter Ended March 31, 2005, File No. 1-5324)
10.26
Employment Agreement with Gregory B. Butler, dated as of October 1, 2003 (Exhibit 10 (B) 10.31, 2003 NU Form 10-K, File No. 1-5324)
10.27
Employment Agreement with David R. McHale dated as of March 31, 2005 (Exhibit 10.30 to NU Form 10-Q for the Quarter Ended March 31, 2005, File No. 1-5324)
10.28
Description of terms of employment of Leon J. Olivier (Exhibit 10 (C) 10.3, 2003 NU Form 10-K, File No. 1-5324)
10.29
NU Incentive Plan, effective as of January 1, 1998. (Exhibit 10.35.1, 1998 NU Form 10-K, File No. 1-5324)
10.29.1
Amendment to NU Incentive Plan, effective as of February 23, 1999. (Exhibit 10.35.1.1, 1998 NU Form 10-K, File No. 1-5324)
*10.29.2
Amendment 2 to NU Incentive Plan, effective as of September 12, 2006.
10.30
Supplemental Executive Retirement Plan for Officers of NU System Companies, Amended and Restated effective as of January 1, 1992. (Exhibit 10.45.1, NU Form 10-Q for the Quarter Ended June 30, 1992, File No. 1-5324)
10.30.1
Amendment 1 to Supplemental Executive Retirement Plan, effective as of August 1, 1993. (Exhibit 10.35.1, 1993 NU Form 10-K, File No. 1-5324)
10.30.2
Amendment 2 to Supplemental Executive Retirement Plan, effective as of January 1, 1994. (Exhibit 10.35.2, 1993 NU Form 10-K, File No. 1-5324)
10.30.3
Amendment 3 to Supplemental Executive Retirement Plan, effective as of January 1, 1996. (Exhibit 10.36.3, 1995 NU Form 10-K, File No. 1-5324)
10.30.4
Amendment 4 to Supplemental Executive Retirement Plan, effective as of February 26, 2002. (Exhibit 10.35.4, 2001 NU Form 10-K, File No. 1-5324)
10.30.5
Amendment 5 to Supplemental Executive Retirement Plan, effective as of November 1, 2001. (Exhibit 10.35.5, 2001 NU Form 10-K, File No. 1-5324)
10.30.6
Amendment 6 to Supplemental Executive Retirement Plan, effective as of December 9, 2003 (Exhibit 10 (B) 10.18.6, 2003 NU Form 10-K, File No. 1-5324).
10.30.7
Amendment 7 to Supplemental Executive Retirement Plan, effective as of February 1, 2005 (Exhibit 10.18.7, 2004 NU Form 10-K, File No. 1-5324)
*10.30.8
Amendment 8 to Supplemental Executive Retirement Plan, effective as of January 1, 2006.
10.31
Trust under Supplemental Executive Retirement Plan dated May 2, 1994. (Exhibit 10.33, 2002 NU Form 10-K, File No. 1-5324)
10.31.1
First Amendment to Trust, effective as of December 10, 2002 (Exhibit 10 (B) 10.19.1, 2003 NU Form 10-K, File No. 1-5324)
10.32
Special Severance Program for Officers of NU System Companies, as adopted on July 15, 1998. (Exhibit 10.37, 1998 NU Form 10-K, File No. 1-5324)
10.32.1
Amendment to Special Severance Program, effective as of February 23, 1999. (Exhibit 10.37.1, 1998 NU Form 10-K, File No. 1-5324)
10.32.2
Amendment to Special Severance Program, effective as of September 14, 1999. (Exhibit 10.3, NU Form 10-Q for the Quarter Ended September 30, 1999, File No. 1-5324)
*10.32.3
Amendment 3 to Special Severance Program, effective September 12, 2006.
10.33
Northeast Utilities Deferred Compensation Plan for Executives, amended and restated effective January 1, 2004 (Exhibit 10.33 to NU Form 10-Q for the Quarter Ended March 31, 2004, File No 1-5324)
10.33.1
Amendment No. 1 to Northeast Utilities Deferred Compensation Plans for Executives, effective January 1, 2005 (Exhibit 10.25.1 , 2005 NU Form 10-K, File No. 1-5324).
*10.33.2
Amendment No. 2 to Northeast Utilities Deferred Compensation Plans for Executives, effective September 12, 2006.
*10.33.3
Amendment No. 3 to Northeast Utilities Deferred Compensation Plans for Executives, effective January 1, 2006.
10.34
Northeast Utilities System's Second Amended and Restated Tax Allocation Agreement dated as of September 21, 2005 (Exhibit D.4 to Amendment No. 1 to U5S Annual Report for the year ended December 31, 2004, filed September 30, 2005, File No. 1-5324)
(C)
NU and CL&P
10.1
CL&P Transition Property Purchase and Sale Agreement between CL&P Funding LLC and CL&P, dated as of March 30, 2001. (Exhibit 10.55, 2001 CL&P Form 10-K, File No. 0-11419)
10.2
CL&P Transition Property Servicing Agreement CL&P Funding LLC and CL&P, dated as of March 30, 2001. (Exhibit 10.56, 2001 CL&P Form 10-K, File No. 0-11419)
(D)
NU and PSNH
10.1
Revised and Conformed Agreement to Settle PSNH Restructuring, dated August 2, 1999, conformed June 23 and executed on September 22, 2000. (Exhibit 10.15.1, 2001 PSNH Form 10-K, File No. 1-6392)
10.2
PSNH Purchase and Sale Agreement with PSNH Funding LLC dated as of April 25, 2001. (Exhibit 10.57, 2001 PSNH Form 10-K, File No. 1-6392)
10.3
PSNH Servicing Agreement with PSNH Funding LLC dated as of April 25, 2001. (Exhibit 10.58, 2001 PSNH Form 10-K, File No. 1-6392)
10.4
PSNH Purchase and Sale Agreement with PSNH Funding LLC2 dated as of January 30, 2002. (Exhibit 10.59 2001 PSNH Form 10-K, File No. 1-6392)
10.5
PSNH Servicing Agreement with PSNH Funding LLC2 dated as of January 30, 2002. (Exhibit 10.60, 2001 PSNH Form 10-K, File No. 1-6392)
(E)
NU and WMECO
10.1
Lease and Agreement, dated as of December 15, 1988, by and between WMECO and Bank of New England, N.A., with BNE Realty Leasing Corporation of North Carolina. (Exhibit 10.63, 1988 WMECO Form 10-K, File No. 0-7624)
10.2
WMECO Transition Property Purchase and Sale Agreement between WMECO Funding LLC and WMECO, dated as of May 17, 2001. (Exhibit 10.61, 2001 WMECO Form 10-K, File No. .0-7624)
10.3
WMECO Transition Property Servicing Agreement between WMECO Funding LLC and WMECO, dated as of May 17, 2001. (Exhibit 10.62, 2001 WMECO Form 10-K, File No. .0-7624)
*12
Ratio of Earnings to Fixed Charges
*13
Annual Report to Security Holders (Each of the Annual Reports is filed only with the Form 10-K of that respective registrant)
13.1
Annual Report of CL&P
13.2
Annual Report of WMECO
13.3
Annual Report of PSNH
*21
Subsidiaries of the Registrant
*23
Consent of the Independent Registered Public Accounting Firm
*31
Rule 13-a - 14(a)/15 d - 14(a) Certifications
(a)
Northeast Utilities
Certification of Charles W. Shivery, Chairman, President and Chief Executive Officer of NU required by Rule 13a - 14(a)/15d - 14(a) of the Securities Exchange Act of 1934, as amended, as adopted pursuant to Section 302 of the Sarbanes-Oxley Act of 2002, dated February 20, 2007
(b)
The Connecticut Light and Power Company
Certification of Leon J. Olivier, Chief Executive Officer of CL&P required by Rule 13a - 14(a)/15d - 14(a) of the Securities Exchange Act of 1934, as amended, as adopted pursuant to Section 302 of the Sarbanes-Oxley Act of 2002, dated February 20, 2007
(c)
Public Service Company of New Hampshire
Certification of Leon J. Olivier, Chief Executive Officer of PSNH required by Rule 13a - 14(a)/15d - 14(a) of the Securities Exchange Act of 1934, as amended, as adopted pursuant to Section 302 of the Sarbanes-Oxley Act of 2002, dated February 20, 2007
(d)
Western Massachusetts Electric Company
Certification of Leon J. Olivier, Chief Executive Officer of WMECO required by Rule 13a - 14(a)/15d - 14(a) of the Securities Exchange Act of 1934 , as amended, as adopted pursuant to Section 302 of the Sarbanes-Oxley Act of 2002, dated February 20, 2007
*31.1
Rule 13-a - 14(a)/15 d - 14(a) Certifications
(a)
Northeast Utilities
Certification of David R. McHale, Senior Vice President and Chief Financial Officer of NU required by Rule 13a - 14(a)/15d - 14(a) of the Securities Exchange Act of 1934, as amended, as adopted pursuant to Section 302 of the Sarbanes-Oxley Act of 2002, dated February 20, 2007
(b)
The Connecticut Light and Power Company
Certification of David R. McHale, Senior Vice President and Chief Financial Officer of CL&P required by Rule 13a - 14(a)/15d - 14(a) of the Securities Exchange Act of 1934, as amended, as adopted pursuant to Section 302 of the Sarbanes-Oxley Act of 2002, dated February 20, 2007
(c)
Public Service Company of New Hampshire
Certification of David R. McHale, Senior Vice President and Chief Financial Officer of PSNH required by Rule 13a - 14(a)/15d - 14(a) of the Securities Exchange Act of 1934, as amended, as adopted pursuant to Section 302 of the Sarbanes-Oxley Act of 2002, dated February 20, 2007
(d)
Western Massachusetts Electric Company
Certification of David R. McHale, Senior Vice President and Chief Financial Officer of WMECO required by Rule 13a - 14(a)/15d - 14(a) of the Securities Exchange Act of 1934, as amended, as adopted pursuant to Section 302 of the Sarbanes-Oxley Act of 2002, dated February 20, 2007
*32
Section 1350 Certificates
(a)
Northeast Utilities
Certification of Charles W. Shivery, Chairman, President and Chief Executive Officer of Northeast Utilities, and David R. McHale, Senior Vice President and Chief Financial Officer of Northeast Utilities, pursuant to 18 U.S.C. Section 1350 as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, dated February 20, 2007
(b)
The Connecticut Light and Power Company
Certification of Leon J. Olivier, Chief Executive Officer of CL&P, and David R. McHale, Senior Vice President and Chief Financial Officer of CL&P, pursuant to 18 U.S.C. Section 1350 as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, dated February 20, 2007
(c)
Public Service Company of New Hampshire
Certification of Leon J. Olivier, Chief Executive Officer of PSNH, and David R. McHale, Senior Vice President and Chief Financial Officer of PSNH, pursuant to 18 U.S.C. Section 1350 as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, dated February 20, 2007
(d)
Western Massachusetts Electric Company
Certification of Leon J. Olivier, Chief Executive Officer of WMECO, and David R. McHale, Senior Vice President and Chief Financial Officer of WMECO, pursuant to 18 U.S.C. Section 1350 as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, dated February 20, 2007