Business
Please refer to the Glossary of Terms for definitions of defined terms and abbreviations used in this Annual Report on Form 10-K.
PENDING MERGER WITH NSTAR
On October 18, 2010, NU and NSTAR announced that each company’s Board of Trustees unanimously approved a Merger Agreement (the “agreement”), under which NSTAR will become a direct wholly owned subsidiary of NU. On October 14, 2011, NU and NSTAR extended the Termination Date of the agreement, as defined therein, from October 16, 2011 to April 16, 2012. The transaction is structured as a merger of equals in a tax-free exchange of shares. Under the terms of the agreement, NSTAR shareholders will receive 1.312 NU common shares for each NSTAR common share that they own (the “exchange ratio”). Following the merger, NU will provide electric and natural gas energy delivery service to approximately 3.5 million electric and natural gas customers through six regulated electric and natural gas utilities in Connecticut, Massachusetts and New Hampshire. On March 4, 2011, NU shareholders approved the agreement, approved an increase in the number of NU common shares authorized for issuance by 155 million common shares to 380 million common shares and fixed the number of trustees at 14. NSTAR shareholders approved the agreement on March 4, 2011.
Subject to the conditions in the agreement, our first quarterly dividend per common share paid after the closing of the merger will be increased to an amount that is at least equal, after adjusting for the exchange ratio, to NSTAR's last quarterly dividend paid prior to the closing.
Completion of the merger is subject to various customary conditions, including, among others, receipt of all required regulatory approvals. NU and NSTAR are awaiting approvals from PURA and the DPU.
In December 2010, the Connecticut Office of Consumer Counsel, supported by the Connecticut Attorney General, petitioned PURA to reconsider its earlier conclusion that it lacked jurisdiction to review the merger. On June 1, 2011, PURA declined to change its conclusion that it lacked jurisdiction over the merger. However, on January 18, 2012, PURA issued a decision that revised its June 1, 2011 decision. The January 18, 2012 decision ruled that NU and NSTAR must seek approval from PURA pursuant to Connecticut law prior to completing the merger. NU and NSTAR filed an application with PURA seeking approval of the merger on January 19, 2012. Hearings began February 14, 2012 and PURA is scheduled to issue a final decision on April 2, 2012.
On November 24, 2010, NU and NSTAR filed a joint petition requesting the DPU’s approval of the merger and filed supplemental testimony and a net benefit analysis with the DPU on April 8, 2011, in response to the DPU’s revision of its merger standard to a “net benefits” standard. On February 15, 2012, NU and NSTAR reached comprehensive merger-related settlement agreements with both the Massachusetts DOER and the Massachusetts AG. The first settlement agreement was reached with both the AG and the DOER and covers a variety of rate-making and rate design issues, including a distribution rate freeze until 2016 for NSTAR Electric Company, NSTAR Gas Company and WMECO. The second settlement agreement was reached with the DOER and covers a variety of matters impacting the advancement of Massachusetts clean energy goals established by the Green Communities Act and Global Warming Solutions Act.
Pursuant to the terms and provisions of the settlement agreements, the parties agree that the proposed merger between NU and NSTAR is consistent with the public interest and should be approved by the DPU. However, the settlement agreements allow the Attorney General and DOER to terminate their respective agreements for any reason at any time prior to approval by the DPU. All parties have requested that the DPU approve the merger on April 4, 2012. If both the DPU and PURA issue acceptable decisions by that date, we expect the merger will be consummated by April 16, 2012.
All other approvals required to consummate the merger have been received. For further information regarding regulatory approvals on the pending merger, see “Regulatory Developments and Rate Matters – Regulatory Approvals for Pending Merger with NSTAR,” in Item 7, Management's Discussion and Analysis of Financial Condition and Results of Operations, in this Annual Report on Form 10-K.
THE COMPANY
NU, headquartered in Hartford, Connecticut, is a public utility holding company subject to regulation by FERC under the Public Utility Holding Company Act of 2005. We are engaged primarily in the energy delivery business through the following wholly owned utility subsidiaries:
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The Connecticut Light and Power Company (CL&P), a regulated electric utility that serves residential, commercial and industrial customers in parts of Connecticut;
Public Service Company of New Hampshire (PSNH), a regulated electric utility that serves residential, commercial and industrial customers in parts of New Hampshire and owns generation assets used to serve customers;
Western Massachusetts Electric Company (WMECO), a regulated electric utility that serves residential, commercial and industrial customers in parts of western Massachusetts and owns solar generating assets; and
Yankee Gas Services Company (Yankee Gas), a regulated natural gas utility that serves residential, commercial and industrial customers in parts of Connecticut.
NU also owns certain unregulated businesses through its wholly owned subsidiary, NU Enterprises, which are included in its Parent and other companies’ results of operations.
Although NU, CL&P, PSNH and WMECO each report their financial results separately, we also include information in this report on a segment, or line-of-business, basis - the distribution segment (which also includes the generation businesses of PSNH and WMECO and our natural gas distribution business) and the transmission segment. Our distribution segment represented approximately 53 percent of our Regulated companies’ earnings and our electric transmission segment represented approximately 47 percent.
REGULATED ELECTRIC DISTRIBUTION
NU’s electric distribution segment consists of the distribution businesses of CL&P, PSNH and WMECO, which are engaged in the distribution of electricity to retail customers in Connecticut, New Hampshire and western Massachusetts, respectively, plus the regulated electric generation businesses of PSNH and WMECO. The following table shows the sources of 2011 electric franchise retail revenues for NU’s electric distribution companies, collectively, based on categories of customers:
A summary of changes in the electric distribution companies’ retail electric sales (GWh) for 2011, as compared to 2010, on an actual and weather normalized basis (using a 30-year average) is as follows:
Actual retail electric sales for all three electric companies were lower in 2011 compared to 2010 due primarily to milder weather in the summer of 2011, compared to warmer than normal weather in the summer of 2010. In 2011, cooling degree days in Connecticut and western Massachusetts were 20.9 percent lower than 2010, and in New Hampshire, cooling degree days were 23.7 percent lower than 2010.
On a weather-normalized basis, total retail electric sales decreased slightly in 2011, as compared to 2010. We believe the weather-normalized commercial sales for CL&P and WMECO decreased in 2011, compared to 2010, due to the slow economic recovery in these service areas. PSNH commercial sales increased in 2011 due to one large self-generating customer who experienced multiple generation outages and relied on PSNH for energy. Industrial sales for both CL&P and WMECO decreased in 2011, compared to 2010, due in part to weak manufacturing activity in Connecticut and western Massachusetts. Our commercial and industrial electric sales continue to be negatively impacted by utilization of distributed generation and conservation programs.
Major Storms
On August 28, 2011, Tropical Storm Irene caused extensive damage to our distribution system resulting in incremental restoration costs of $135.6 million. Approximately 800,000 of our 1.9 million electric distribution customers were without power at the peak of the outages, with approximately 670,000 of those customers in Connecticut.
On October 29, 2011, an unprecedented autumn snowstorm inundated our service territory with heavy snow, causing significant damage to our distribution and transmission systems resulting in incremental restoration costs of $218.5 million. Approximately 1.2 million of our electric distribution customers were without power at the peak of the outages, with approximately 810,000 of those customers in Connecticut, approximately 237,000 of those customers in New Hampshire, and approximately 140,000 of those customers in Massachusetts. In terms of customer outages, this was the most severe storm in CL&P’s history, surpassing Tropical
Storm Irene; the third most severe in PSNH’s history, following a December 2008 ice storm and a February 2010 winter storm; and the most severe in WMECO's history.
CL&P recorded a pre-tax charge for a storm fund reserve of $30 million, in the fourth quarter of 2011, to provide bill credits to its residential customers who remained without power after noon on Saturday, November 5, 2011 as a result of the October snowstorm, and to provide contributions to certain Connecticut charitable organizations. Approximately $27 million of the storm fund reserve was used to provide a one-time credit on the February 2012 bills of approximately 192,000 CL&P customers and approximately $3 million was paid to charitable organizations in December 2011. CL&P will not seek to recover this amount in its rates.
Estimated incremental restoration costs related to the two storms are summarized in the table below and consist of costs that are deferred for future recovery and costs that are capitalized:
We believe our response to both storms was prudent and therefore we believe it is probable that CL&P, PSNH and WMECO will be allowed to recover these storm costs. Each operating company will seek recovery of its estimated deferred storm costs through its applicable regulatory recovery process. For further information regarding various reviews on storm response and preparedness, see “Regulatory Developments and Rate Matters – 2011 Major Storms,” in Item 7, Management's Discussion and Analysis of Financial Condition and Results of Operations in this Annual Report on Form 10-K.
THE CONNECTICUT LIGHT AND POWER COMPANY - DISTRIBUTION
CL&P’s distribution business consists primarily of the purchase, delivery and sale of electricity to its residential, commercial and industrial customers. As of December 31, 2011, CL&P furnished retail franchise electric service to approximately 1.2 million customers in 149 cities and towns in Connecticut. CL&P does not own any electric generation facilities.
The following table shows the sources of CL&P’s 2011 electric franchise retail revenues based on categories of customers:
Rates
CL&P is subject to regulation by PURA, which, among other things, has jurisdiction over rates, accounting procedures, certain dispositions of property and plant, mergers and consolidations, issuances of long-term securities, standards of service, management efficiency and construction and operation of facilities. CL&P's present general rate structure consists of various rate and service classifications covering residential, commercial and industrial services. CL&P's retail rates include a delivery service component, which includes distribution, transmission, conservation, renewables, CTA, SBC and other charges that are assessed on all customers.
The CTA is a charge assessed to recover stranded costs associated with electric industry restructuring as well as various IPP contracts. The SBC recovers costs associated with various hardship and low income programs as well as payments to municipalities to compensate them for losses in property tax revenue due to decreases in the value of electric generating facilities resulting directly from electric industry restructuring. The CTA and SBC are annually reconciled to actual costs incurred, with any difference refunded to, or recovered from, customers.
Under Connecticut law, all of CL&P's customers are entitled to choose their energy suppliers, while CL&P remains their electric distribution company. Under SS rates for customers with less than 500 kilowatts of demand and LRS rates for customers with 500 kilowatts of demand or greater, CL&P purchases power for those customers who do not choose a competitive energy supplier and passes the cost to such customers through a combined GSC and FMCC charge on customers' bills. The combined GSC and FMCC
charges for both types of service recover all of CL&P’s costs of procuring energy from wholesale suppliers and are adjusted periodically and reconciled semi-annually in accordance with the directives of PURA.
CL&P continues to supply approximately 35 percent of its customer load at SS or LRS rates while the other 65 percent of its customer load has migrated to competitive energy suppliers. Because this customer migration is only for energy supply service, it has no impact on CL&P’s delivery business or its operating income.
Distribution Rates: On June 30, 2010, PURA issued a final order in CL&P’s most recent retail distribution rate case approving annualized distribution rate increases of $63.4 million effective July 1, 2010 and an incremental $38.5 million effective July 1, 2011. The 2010 increase was deferred from customer bills until January 1, 2011 to coincide with the decline in revenue requirements associated with the final payment of CL&P’s RRBs. In its decision, PURA also maintained CL&P’s authorized distribution segment regulatory ROE of 9.4 percent. In 2011, CL&P earned a distribution segment regulatory ROE of 9.4 percent, compared to 7.9 percent in 2010.
AMI: On August 29, 2011, PURA issued a draft decision rejecting the full deployment of AMI meters to all of CL&P’s customers at that time. PURA instead indicated that CL&P should begin installing AMI meters at a more moderate pace once industry standards are developed and CL&P has selected a specific technology to install. On September 2, 2011, the Commissioner of DEEP filed a motion with PURA to suspend the proceeding while the Bureau of Energy and Technology Policy conducts a process to establish an AMI policy for Connecticut, in accordance with the state law. On September 8, 2011, PURA granted DEEP’s motion and suspended its proceedings. No further schedule is available at this time from either DEEP or PURA. As a result, CL&P has removed the projected AMI capital costs of approximately $257 million from its current five-year capital program.
CL&P has a transmission adjustment clause as part of its retail distribution rates, which reconciles on a semi-annual basis the transmission revenues billed to customers against the transmission costs of acquiring such services, thereby recovering all of its transmission expenses on a timely basis.
CL&P, jointly with UI, has entered into four CfDs for a total of approximately 787 MW of capacity with three generation projects being built or modified and one demand response project. The capacity CfDs extend through 2026 and obligate the utilities to pay the difference between a set price and the value that the projects receive in the ISO-NE markets. The contracts have terms of up to 15 years beginning in 2009 and are subject to a sharing agreement with UI, whereby UI will have a 20 percent share of the costs and benefits of these contracts. CL&P's portion of the costs and benefits of these contracts will be paid by or refunded to CL&P's customers.
Sources and Availability of Electric Power Supply
As noted above, CL&P does not own any generation assets and purchases energy to serve its SS and LRS loads from a variety of competitive sources through periodic requests for proposals. CL&P enters into supply contracts for SS periodically for periods of up to three years to mitigate the risks associated with energy price volatility for its residential and small and medium load commercial and industrial customers. CL&P enters into supply contracts for LRS for larger commercial and industrial customers every three months. Currently, CL&P has contracts in place with various suppliers for all of its SS loads through 2012, and 40 percent of expected load for 2013. CL&P’s contracts for its LRS loads extend through the second quarter of 2012.
PUBLIC SERVICE COMPANY OF NEW HAMPSHIRE - DISTRIBUTION
PSNH’s distribution business consists primarily of the purchase, delivery and sale of electricity to its residential, commercial and industrial customers. As of December 31, 2011, PSNH furnished retail franchise electric service to approximately 498,000 retail customers in 211 cities and towns in New Hampshire. PSNH also owns and operates approximately 1,200 MW of primarily fossil fueled electricity generation plants. Included in those electric generating plants is PSNH’s 50 MW wood-burning Northern Wood Power Project at its Schiller Station in Portsmouth, New Hampshire, and approximately 70 MW of hydroelectric generation. PSNH’s distribution segment includes the activities of its generation business.
The Clean Air Project, a wet scrubber project, was constructed and placed in service by PSNH at its Merrimack Station in September 2011. The cost of the project will be recovered through PSNH's ES rates under New Hampshire law. By November 2011, both of Merrimack station’s coal-fired units were integrated with the scrubber, and the scrubber is now reducing emissions from the units. PSNH expects to complete remaining project construction activities in mid-2012. We currently expect the final costs of the project to be approximately $422 million.
The following table shows the sources of PSNH’s 2011 electric franchise retail revenues based on categories of customers:
PSNH is subject to regulation by the NHPUC, which has jurisdiction over, among other things, rates, certain dispositions of property and plant, mergers and consolidations, issuances of securities, standards of service, management efficiency and construction and operation of facilities.
PSNH’s ES rate recovers its generation and purchased power costs from customers on a current basis and allows for an ROE of 9.81 percent on its generation investment.
Under New Hampshire law, the SCRC allows PSNH to recover its stranded costs, including above-market expenses incurred under mandated power purchase obligations and other long-term investments and obligations. PSNH has financed a significant portion of its stranded costs through securitization by issuing RRBs secured by the right to recover these stranded costs from customers over time. PSNH recovers the costs of these RRBs through the SCRC rate. The amount of the RRB obligation decreases each quarter and the RRBs are scheduled to be retired as of May 1, 2013.
On an annual basis, PSNH files with the NHPUC an ES/SCRC cost reconciliation filing for the preceding year. The difference between revenues and costs are included in the ES/SCRC rate calculations and refunded to or recovered from customers in the subsequent period approved by the NHPUC.
The TCAM allows PSNH to recover on a fully reconciling basis its transmission related costs. The TCAM is adjusted on July 1 of each year.
Distribution Rates: On June 28, 2010, the NHPUC approved a joint settlement of PSNH’s rate case allowing a net distribution rate increase of $45.5 million on an annualized basis effective July 1, 2010, an annualized distribution rate decrease of $2.4 million effective July 1, 2011 and projected increases of $9.5 million and $11.1 million on July 1, 2012 and 2013, respectively. If PSNH’s 12-month trailing average regulatory ROE is greater than 10 percent, amounts over the 10 percent level will be allocated 75 percent to customers and 25 percent to PSNH. The settlement also provided that the authorized regulatory ROE on distribution only plant will continue at the previously allowed level of 9.67 percent. PSNH’s distribution segment regulatory ROE was 9.7 percent (including generation) in 2011, compared to 10.2 percent in 2010.
In March 2011, PSNH filed with the NHPUC to collect certain exogenous costs, step increases, and storm costs, as permitted by its 2010 rate case settlement. These rate increases were offset by the scheduled termination, on June 30, 2011, of a rate recoupment charge, also from the 2010 rate case settlement. During the second quarter of 2011, the NHPUC issued rate orders approving net increases in revenue requirements effective July 1, 2011 to (1) recover exogenous costs, (2) implement a step increase program for capital additions and the reliability enhancement program, and (3) allow for the recovery of the 2010 windstorm costs. Together with the scheduled termination of the rate recoupment charge, the net impact of these rate changes was a $2.4 million decrease in rates effective July 1, 2011.
Under New Hampshire law, all of PSNH's customers are entitled to choose competitive energy suppliers, with PSNH providing default energy service under its ES rate for those customers who do not elect to use a third party supplier. Prior to 2009, PSNH experienced only a minimal amount of customer migration. However, customer migration levels began to increase significantly in 2009 as energy costs decreased from their historic high levels and competitive energy suppliers with more pricing flexibility were able to offer electricity supply at lower prices than PSNH. By the end of 2011, approximately 2.6 percent of all of PSNH’s customers (approximately 36 percent of load), mostly large commercial and industrial customers, had switched to competitive energy suppliers. The increased level of migration has caused an increase in the ES rate, as fixed costs of PSNH’s generation assets must be spread over a smaller group of customers and lower sales volume. The customers that did not choose a third party supplier, predominately residential and small commercial and industrial customers, are now paying a larger proportion of these fixed costs. On July 26, 2011, the NHPUC ordered PSNH to file a rate proposal that would mitigate the impact of customer migration expected to occur when the ES rate is higher than market prices. On January 26, 2012, the NHPUC rejected the PSNH proposal and ordered PSNH to file a new proposal, no later than June 30, 2012, addressing certain issues raised by the NHPUC.
PSNH cannot predict if the upward pressure on ES rates due to customer migration will continue into the future, as future migration levels are dependent on market prices and supplier alternatives. If future market prices once more exceed the average ES rate level, some or all of these customers on third party supply may migrate back to PSNH.
On November 22, 2011, the NHPUC opened a docket to consider the in-service status of the Clean Air Project, the appropriate rate treatment, PSNH’s prudence in construction of the project and the propriety of setting temporary rates. Hearings on temporary rates are scheduled for March 12 and 13, 2012. Following hearings on temporary rates, it is expected that recovery of costs of the Clean Air
Project will begin during the second quarter of 2012. No formal schedule for the comprehensive prudence review or for permanent rates has been established.
During 2011, approximately 72 percent of PSNH’s load was met through its own generation, long-term power supply provided pursuant to orders of the NHPUC, and contracts with third parties. The remaining 28 percent of PSNH's load was met by short-term (less than one year) purchases and spot purchases in the competitive New England wholesale power market. PSNH expects to meet its load requirements in 2012 in a similar manner. Included in the 72 percent above are PSNH obligations to purchase power from approximately two dozen IPPs, the output of which it either uses to serve its customer load or sells into the ISO-NE market.
WESTERN MASSACHUSETTS ELECTRIC COMPANY - DISTRIBUTION
WMECO’s distribution business consists primarily of the purchase, delivery and sale of electricity to residential, commercial and industrial customers. As of December 31, 2011, WMECO furnished retail franchise electric service to approximately 206,000 retail customers in 59 cities and towns in the western region of Massachusetts. WMECO does not own any fossil or hydro-electric generating facilities and purchases its energy requirements from competitive suppliers. In 2009, pursuant to the Massachusetts Green Communities Act, WMECO was authorized to install 6 MW of solar energy generation in its service territory. In October 2010, WMECO completed development of a 1.8 MW solar generation facility on a site in Pittsfield, Massachusetts and in December 2011 completed development of a 2.3 MW solar generation facility in Springfield, Massachusetts. WMECO is continuing to evaluate sites suitable for development of the remaining 1.9 MW of the authorized 6 MW of capacity. WMECO will sell all energy and other products from its solar generation facilities into the ISO-NE market.