Item 1.
Business
Please refer to the Glossary of Terms for definitions of defined terms and abbreviations used in this Annual Report on Form 10-K.
NU, headquartered in Boston, Massachusetts and 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:
●
The Connecticut Light and Power Company (CL&P), a regulated electric utility that serves residential, commercial and industrial customers in parts of Connecticut;
●
NSTAR Electric Company (NSTAR Electric), a regulated electric utility that serves residential, commercial and industrial customers in parts of Massachusetts;
●
Public Service Company of New Hampshire (PSNH), a regulated electric utility that serves residential, commercial and industrial customers in parts of New Hampshire and owns generation assets used to serve customers;
●
Western Massachusetts Electric Company (WMECO), a regulated electric utility that serves residential, commercial and industrial customers in parts of western Massachusetts and owns solar generating assets;
●
NSTAR Gas Company (NSTAR Gas), a regulated natural gas utility that serves residential, commercial and industrial customers in parts of Massachusetts; and
●
Yankee Gas Services Company (Yankee Gas), a regulated natural gas utility that serves residential, commercial and industrial customers in parts of Connecticut.
NU also owns certain unregulated businesses through its wholly owned subsidiaries, NU Enterprises and NSTAR LLC, which are included in its Parent and other companies’ results of operations.
Although NU, CL&P, NSTAR Electric, 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 Regulated companies' segments include the electric distribution segment, the natural gas distribution segment and the electric transmission segment. The electric distribution segment includes the generation businesses of PSNH and WMECO. The Regulated companies' segments represented substantially all of NU's total consolidated revenues for years ended December 31, 2012 and 2011.
MERGER WITH NSTAR
On April 10, 2012, NU completed its merger with NSTAR (Merger). Pursuant to the terms and conditions of the Agreement and Plan of Merger, as amended, NSTAR was merged with and into a wholly owned subsidiary of NU, which was subsequently renamed NSTAR LLC. NU’s consolidated financial statements include the results of operations of NSTAR LLC and its subsidiaries for the period after April 10, 2012.
ELECTRIC DISTRIBUTION SEGMENT
General
NU’s electric distribution segment consists of the distribution businesses of CL&P, NSTAR Electric, PSNH and WMECO, which are engaged in the distribution of electricity to retail customers in Connecticut, eastern Massachusetts, New Hampshire and western Massachusetts, respectively, plus the regulated electric generation businesses of PSNH and WMECO.
The following table shows the sources of 2012 electric franchise retail revenues for NU’s electric distribution companies, collectively, based on categories of customers, including the electric franchise retail revenues of NSTAR Electric from the date of merger, April 10, 2012, through December 31, 2012:
(Thousands of Dollars, except percentages)
% of Total
Residential
$
2,731,951
Commercial
1,563,709
Industrial
753,974
Streetlighting and Railroads
40,952
Miscellaneous and Eliminations
130,137
Total Retail Electric Revenues
$
5,220,723
100%
A summary of our distribution companies’ retail electric GWh sales and percentage changes for 2012, as compared to 2011, is as follows:
2012 (1)
Percentage
Change
Residential
19,719
14,766
33.5%
Commercial
24,117
14,301
68.6%
Industrial
5,462
4,418
23.6%
Other
28.6%
Total
49,718
33,812
47.0%
(1)
NU retail electric sales include the sales of NSTAR Electric from the date of merger, April 10, 2012, through December 31, 2012.
Actual retail electric sales for CL&P, NSTAR Electric and WMECO decreased in 2012, as compared to 2011, due primarily to the warmer than normal weather in the first quarter of 2012, as compared to colder than normal weather in the first quarter of 2011, while actual retail electric sales for PSNH were 0.1 percent higher than last year. In 2012, heating degree days were 11 percent lower in Connecticut and western Massachusetts, 7 percent lower in the Boston metropolitan area, and 9 percent lower in New Hampshire, as compared to 2011. On a weather normalized basis (based on 30-year average temperatures), the average NU combined consolidated total retail electric sales decreased 0.2 percent in 2012, as compared to 2011, assuming NSTAR Electric had been part of the NU combined electric distribution system for all periods under consideration. We believe these decreases were due primarily to increased conservation efforts among all our customer classes and the continued installation of distributed generation at our commercial and industrial customers’ facilities. For WMECO, the fluctuations in retail electric sales no longer impact earnings as the DPU approved a sales decoupling plan effective February 1, 2011. Under this decoupling plan, WMECO now has an established annual level of baseline distribution delivery service revenues of $125.4 million that it is able to recover. This effectively breaks the relationship between sales volume and revenues recognized.
Major Storms
On August 28, 2011, Tropical Storm Irene caused extensive damage to our distribution system. Approximately 800,000 CL&P, PSNH and WMECO customers were without power at the peak of the outages, with approximately 670,000 of those customers in Connecticut. Approximately 500,000 customer outages occurred on the NSTAR Electric distribution system in its aftermath.
On October 29, 2011, an unprecedented storm inundated our service territory with heavy snow causing significant damage to our distribution and transmission systems. Approximately 1.2 million of CL&P, PSNH and WMECO’s electric distribution customers were without power at the peak of the outages, with 810,000 of those customers in Connecticut, 237,000 in New Hampshire, and 140,000 in western 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; and the most severe in WMECO's history. The storm also caused approximately 200,000 customer outages on the NSTAR Electric distribution system.
On October 29, 2012, Hurricane Sandy caused extensive damage to our electric distribution system across all three states. Approximately 1.5 million of our 3.1 million electric distribution customers were without power during or following the storm, with approximately 850,000 of those customers in Connecticut, approximately 472,000 in Massachusetts, and approximately 137,000 in New Hampshire.
As of December 31, 2012, deferred storm restoration costs related to these major storms that are deferred for future recovery at CL&P, NSTAR Electric, PSNH, and WMECO were as follows:
(Millions of Dollars)
Tropical
Storm Irene
October
Snowstorm
Hurricane
Sandy
Total
CL&P
$
108.6
$
173.0
$
159.9
$
441.5
NSTAR Electric
21.9
13.9
27.8
63.6
PSNH
6.8
15.5
12.1
34.4
WMECO
3.2
23.3
4.2
30.7
Total
$
140.5
$
225.7
$
204.0
$
570.2
On February 8, 2013, a blizzard caused damage to the electric delivery systems of CL&P and NSTAR Electric. We have estimated that approximately 71,000 and 350,000 of CL&P and NSTAR Electric's distribution customers, respectively, were without power during or following the storm. We believe that this storm will cost between $100 million to $120 million, with approximately 90 percent of those costs relating to NSTAR Electric. Management expects the costs to meet the criteria for specific cost recovery in Connecticut and Massachusetts and, as a result, does not expect the storm to have a material impact on the results of operations of CL&P or NSTAR Electric. Each operating company will seek recovery of these anticipated deferred storm costs through its applicable regulatory recovery process.
ELECTRIC DISTRIBUTION - CONNECTICUT
THE CONNECTICUT LIGHT AND POWER COMPANY
CL&P’s distribution business consists primarily of the purchase, delivery and sale of electricity to its residential, commercial and industrial customers. As of December 31, 2012, CL&P furnished retail franchise electric service to approximately 1.2 million customers in 149 cities and towns in Connecticut, covering an area of 4,400 square miles. CL&P does not own any electric generation facilities.
The following table shows the sources of CL&P’s 2012 electric franchise retail revenues based on categories of customers:
A summary of CL&P’s retail electric GWh sales and percentage changes for 2012, as compared to 2011, is as follows:
Percentage
Change
Residential
9,978
10,092
(1.1)%
Commercial
9,414
9,525
(1.2)%
Industrial
2,426
2,414
0.5 %
Other
2.3 %
Total
22,109
22,315
(0.9)%
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. Connecticut utilities are entitled under state law 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.
Under Connecticut law, all of CL&P's customers are entitled to choose their energy suppliers, while CL&P remains their electric distribution company. For those customers who do not choose a competitive energy supplier, under SS rates for customers with less than 500 kilowatts of demand, and LRS rates for customers with 500 kilowatts or more of demand, CL&P purchases power under standard offer contracts and passes the cost of the power to customers through a combined GSC and FMCC charge on customers’ bills.
CL&P continues to supply approximately 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.
The distribution rates established by the PURA for CL&P are comprised of the following:
·
GSC charge (the electric generation services component), which recovers energy-related costs incurred as a result of providing electric generation service supply to all customers that have not migrated to competitive energy suppliers. The GSC charge is adjusted periodically and reconciled semi-annually in accordance with the directives of PURA. Expense/revenue reconciliation amounts are recovered in subsequent rates.
·
FMCC charge, which recovers any costs imposed by the FERC as part of the New England Standard Market Design, including locational marginal pricing, locational installed capacity payments, any cost approved by PURA to reduce FMCC charges (with conditions) and reliability must run contracts. The FMCC charge is adjusted periodically and reconciled semi-annually in accordance with the directives of PURA. Expense/revenue reconciliation amounts are recovered in subsequent rates.
·
SBC charge, established to fund expenses for the public education outreach program, costs associated with various hardship and low income programs, a program to compensate municipalities for losses in property tax revenue due to decreases in the value of electric generating facilities resulting directly from electric industry restructuring, displaced worker protection costs, unfunded storage and disposal costs for spent nuclear fuel generated before January 1, 2000, and decommissioning fund contributions. Any element of the SBC charge may be revised by PURA as the need arises. The SBC charge is reconciled annually to actual costs incurred, with any difference refunded to, or recovered from, customers.
·
CTA charge, which pays the principal and interest on RRBs as well as the reasonable and necessary costs related to the RRBs financing. The CTA charge is also assessed to recover stranded costs associated with electric industry restructuring as well as various IPP contracts that were not funded with the proceeds of the RRBs. The CTA charge is reconciled annually to actual costs incurred, with any difference refunded to, or recovered from, customers.
·
The Renewable Energy Investment Fund charge, which is used to promote investment in renewable energy sources. Funds collected by this charge are deposited into the Renewable Energy Investment Fund and administered by Connecticut Innovations, Incorporated. The Renewable Energy Investment Fund charge is set by statute and is currently 0.1 cent per kWh.
·
C&LM charge, established to implement cost-effective energy conservation programs and market transformation initiatives.
·
Transmission adjustment clause, which reconciles on a semi-annual basis the transmission revenues billed to customers against the transmission costs of acquiring such services, to recover 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 consisting of three generation projects 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.
CL&P, jointly with UI, has entered into three CfDs (each having a 80 percent to 20 percent sharing mechanism as described above), with developers of peaking generation units approved by the PURA (Peaker CfDs). These units have a total of approximately 500 MW of peaking capacity. The Peaker CfDs pay the developer the difference between capacity, forward reserve and energy market revenues and a cost-of-service payment stream for 30 years. The ultimate cost or benefit to CL&P under these contracts will depend on the costs of plant construction and operation and the prices that the projects receive for capacity and other products in the ISO-NE markets. CL&P's portion of the amounts paid or received under the Peaker CfDs will be recoverable from or refunded to CL&P's customers.
On June 30, 2010, PURA issued a final order in CL&P’s most recent retail distribution rate case approving distribution rates and establishing CL&P’s authorized distribution regulatory ROE at 9.4 percent.
On March 13, 2012, NU and NSTAR reached a comprehensive settlement agreement with both the Connecticut Attorney General and the Connecticut Office of Consumer Counsel related to the Merger. The settlement agreement covered a variety of matters, including a CL&P base distribution rate freeze until December 1, 2014. The settlement agreement also provided for a $25 million rate credit to CL&P customers and the establishment of a $15 million fund for energy efficiency and other initiatives to be disbursed at the direction of the DEEP. CL&P also agreed to forego rate recovery of $40 million of deferred storm costs associated with restoration activities following Tropical Storm Irene and the October 2011 snowstorm. On April 2, 2012, the PURA approved the settlement agreement and the Merger.
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 for the first half of 2013, and 70 percent of expected load for the second half of 2013. CL&P intends to purchase 10 percent of the SS load for the second half of 2013. None of the SS load for 2014 has been procured. CL&P’s contracts for its LRS loads extend through the second quarter of 2013, and CL&P intends to purchase 10 percent of the LRS load for the third quarter of 2013.
ELECTRIC DISTRIBUTION - MASSACHUSETTS
NSTAR ELECTRIC COMPANY
WESTERN MASSACHUSETTS ELECTRIC COMPANY
The electric distribution businesses of NSTAR Electric and WMECO consist primarily of the purchase, delivery and sale of electricity to residential, commercial and industrial customers within their respective franchise service territories. As of December 31, 2012, NSTAR Electric furnished retail franchise electric service to approximately 1.1 million customers in Boston and 80 surrounding cities and towns in Massachusetts, including Cape Cod and Martha’s Vineyard, covering an area of 1,702 square miles. WMECO provides retail franchise electric service to approximately 207,000 retail customers in 59 cities and towns in the western region of Massachusetts, covering an area of 1,500 square miles. Neither NSTAR Electric nor WMECO owns any fossil or hydro-electric generating facilities, and each purchases its respective energy requirements from competitive suppliers.
In 2009, WMECO was authorized by the DPU 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. In connection with the Attorney General settlement agreement (as defined below) that approved the Merger in Massachusetts, WMECO committed to increase its solar generation capacity to 8 MW. WMECO is continuing to evaluate sites suitable for development of the remaining 3.9 MW of capacity. WMECO will sell all energy and other products from its solar generation facilities into the ISO-NE market. NSTAR Electric does not own any solar generating facilities, but agreed to issue a request for proposals to enter into long-term contracts for 10 megawatts of solar power in connection with the Attorney General settlement agreement that approved the Merger in Massachusetts. NSTAR Electric has entered in two contracts for 5 MW of capacity, which contracts are still pending approval at the DPU.
The following table shows the sources of the 2012 electric franchise retail revenues of NSTAR Electric and WMECO based on categories of customers:
A summary of NSTAR Electric’s and WMECO’s retail electric GWh sales and percentage changes for 2012, as compared to 2011, is as follows:
Rates
NSTAR Electric and WMECO are each subject to regulation by the DPU, which has jurisdiction over, among other things, rates, accounting procedures, certain dispositions of property and plant, mergers and consolidations, issuances of long-term securities, acquisition of securities, standards of service, management efficiency and construction and operation of distribution, production and storage facilities. The present general rate structure for both NSTAR Electric and WMECO consists of various rate and service classifications covering residential, commercial and industrial services. Massachusetts utilities are entitled under state law to charge rates that are sufficient to allow them an opportunity to recover their reasonable operation and capital costs, to attract needed capital and maintain their financial integrity, while also protecting relevant public interests.
Under Massachusetts law, all customers of each of NSTAR Electric and WMECO are entitled to choose their energy suppliers, while NSTAR Electric or WMECO, as the case may be, remains their distribution company. Both NSTAR Electric and WMECO purchase power from competitive suppliers for, and pass through the cost to, their respective customers who do not choose a competitive energy supplier (basic service). Basic service charges are adjusted and reconciled on an annual basis. Most of the residential and small commercial and industrial customers of NSTAR Electric and WMECO have continued to buy their power from NSTAR Electric or WMECO, as the case may be, at basic service rates. Most large commercial and industrial customers have switched to a competitive energy supplier.
The Cape Light Compact, an inter-governmental organization consisting of the 21 towns and two counties on Cape Cod and Martha’s Vineyard, serves 200,000 customers through the delivery of energy efficiency programs, effective consumer advocacy, competitive electricity supply and green power options. NSTAR Electric continues to provide electric service to these customers including the delivery of power, meter reading, billing, and customer service.
NSTAR Electric continues to supply approximately 40 percent of its customer load at basic service rates while the other 60 percent of its customer load has migrated to competitive energy suppliers. WMECO continues to supply approximately 49 percent of its customer load at basic service rates while the other 51 percent of its customer load has migrated to competitive energy suppliers. Because customer migration is limited to energy supply service, it has no impact on the delivery business or operating income of NSTAR and WMECO.
The distribution rates established by the DPU for NSTAR Electric and WMECO are comprised of the following:
·
A distribution charge, which includes a fixed customer charge and a demand and/or energy charge to collect the costs of building and expanding the infrastructure to deliver power to its destination, as well as ongoing operating costs. The distribution charge also includes the recovery, on a fully reconciling basis, of certain DPU-approved safety and reliability program costs, a Pension and PBOP Rate Adjustment Mechanism (PAM) to recover incremental pension and PBOP benefit costs, a reconciling rate adjustment mechanism to recover costs associated with the residential assistance adjustment clause, a net-metering reconciliation surcharge to collect the lost revenues and credits associated with net-metering facilities installed by customers, and an Energy Efficiency Reconciling Factor (EERF) to recover energy efficiency program costs and lost base revenues in addition to those charges recovered in the energy conservation charge.
·
A basic service charge represents the collection of energy costs, including costs related to charge-offs of uncollected energy costs, through DPU-approved rate mechanisms. Electric distribution companies in Massachusetts are required to obtain and resell power to retail customers through basic service for those who choose not to buy energy from a competitive energy supplier. Basic service rates are reset every six months (every three months for large commercial and industrial customers). The price of basic service is intended to reflect the average competitive market price for electric power. Additionally, the DPU has authorized NSTAR Electric to recover the cost of its Dynamic Pricing Smart Grid Pilot Program through the basic service charge.
·
A transition charge represents costs to be collected primarily from previously held investments in generating plants, costs related to existing above-market power contracts, and contract costs related to long-term power contracts buy-outs.
·
A transmission charge to recover the costs of transporting electricity over high voltage lines from generating plants to substations, including costs allocated by ISO-NE to maintain the wholesale electric market.
·
An energy conservation charge represents a legislatively-mandated charge to collect costs for energy efficiency programs.
·
A renewable energy charge represents a legislatively-mandated charge to collect the costs to support the development and promotion of renewable energy projects.
Rate Settlement Agreement
On February 15, 2012, NU and NSTAR reached comprehensive settlement agreements with the Massachusetts Attorney General (Attorney General settlement agreement) and the DOER related to the Merger. The Attorney General settlement agreement covered a variety of rate-making and rate design issues, including a base distribution rate freeze through 2015 for NSTAR Electric and WMECO, a rate credit of $15 million to customers of NSTAR Electric and a rate credit of $3 million to customers of WMECO. The settlement agreement reached with the DOER covered the same rate-making and rate design issues as the Attorney General's settlement agreement, as well as a variety of matters impacting the advancement of Massachusetts clean energy policy established by the Green Communities Act and Global Warming Solutions Act. On April 4, 2012, the DPU approved the settlement agreements and the Merger.
NSTAR Electric is operating under a DPU-approved Rate Settlement Agreement (Rate Settlement Agreement) that was scheduled to expire on December 31, 2012. As noted above, the rates under the Rate Settlement Agreement are subject to a base distribution rate freeze through 2015 pursuant to the Attorney General settlement agreement. Pursuant to a 2008 DPU order, Massachusetts electric utilities must adopt rate structures that decouple the volume of energy sales from the utility’s revenues in their next rate case. The exact timing of NSTAR Electric’s next rate case has not yet been determined, but it will not be before 2015.
In WMECO’s January 31, 2011 rate decision, the DPU approved a revenue decoupling reconciliation mechanism that provides assurance that WMECO will recover a DPU pre-established level of baseline distribution delivery service revenue to manage all other distribution operating expenses and earn a level of return on its capital investment. The rates under the January 31, 2011 rate decision are subject to a base distribution rate freeze through 2015 pursuant to the Attorney General settlement agreement .
NSTAR Electric and WMECO are each subject to service quality (SQ) metrics that measure safety, reliability and customer service, and must pay to customers any charges incurred for failure to meet such metrics. Neither NSTAR Electric nor WMECO will be required to
pay an assessment charge for its 2012 performance results as both companies performed at or above target for all of their respective SQ metrics in 2012.
Sources and Availability of Electric Power Supply
As noted above, neither NSTAR Electric nor WMECO owns any generation assets (other than WMECO’s recently constructed solar generation), and both companies purchase their respective energy requirements from a variety of competitive sources through requests for proposals issued periodically, consistent with DPU regulations. NSTAR Electric and WMECO enter into supply contracts for basic service for 50 percent of their respective residential and small commercial and industrial customers twice a year for twelve month terms. Both NSTAR Electric and WMECO enter into supply contracts for basic service for 100 percent of large commercial and industrial customers every three months.
ELECTRIC DISTRIBUTION - NEW HAMPSHIRE
PUBLIC SERVICE COMPANY OF NEW HAMPSHIRE
PSNH’s distribution business consists primarily of the generation, delivery and sale of electricity to its residential, commercial and industrial customers. As of December 31, 2012, PSNH furnished retail franchise electric service to approximately 500,000 retail customers in 211 cities and towns in New Hampshire, covering an area of 5,628 square miles. 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 business includes the activities of its generation business.
The Clean Air Project, a wet flue gas desulphurization system (Scrubber), was constructed and placed in service by PSNH at its Merrimack Station in September 2011. The cost of the Scrubber is expected to 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 completed remaining project construction activities in 2012 and the final cost of the project was approximately $421 million.
The Clean Air Project was placed in service and began operations nearly two years before the statutory deadline of July 1, 2013. Tests to date indicate that the Scrubber reduces emissions of SO2 and mercury from Merrimack Station by over 90 percent, which is well in excess of state and federal requirements. Notwithstanding the Clean Air Project's environmental successes well in advance of the statutory deadline, competitors and environmental groups continue to challenge PSNH's right to recover the costs of this legally-mandated project. In particular, TransCanada, a Canadian energy company that is pursuing the transcontinental Keystone XL pipeline across the United States and is a participant in the U.S. competitive electricity market, and the Conservation Law Foundation, an environmental group which initially supported the law requiring installation of the Scrubber and which formally notified PSNH that it intended to sue PSNH under the Clean Air Act for not installing such emissions control technology, both now claim PSNH was imprudent for pursuing the Clean Air Project. PSNH is vigorously defending its constitutionally protected right to recover the costs of the Clean Air Project, which were invested to comply with the express mandates of state law.
The following table shows the sources of PSNH’s 2012 electric franchise retail revenues based on categories of customers:
A summary of PSNH’s retail electric GWh sales and percentage changes for 2012, as compared to 2011, is as follows:
Percentage
Change
Residential
3,138
3,141
(0.1)%
Commercial
3,315
3,315
0.0 %
Industrial
1,345
1,336
0.7 %
Other
(1.0)%
Total
7,821
7,815
0.1 %
Rates
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. New Hampshire utilities are entitled under state law 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.
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 2012, approximately 9.4 percent of all of PSNH’s customers (approximately 44 percent of load), mostly large commercial and industrial customers, had switched to competitive energy suppliers. This was an increase from 2011, when 2.6 percent of customers (approximately 36 percent of load) 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. On April 27, 2012, PSNH filed its proposed Alternative Default Energy Service Rate that addresses customer migration, with an effective date of July 1, 2012. The proposal, if implemented, would result in no impact to earnings and would allow for an increased contribution to fixed costs for all ES customers. Hearings were held on October 18, 2012 and November 26, 2012. A final decision is expected in the first quarter of 2013.
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.
The distribution rates established by the NHPUC for PSNH are comprised of the following:
·
ES charge, which recovers PSNH’s generation and purchased power costs from customers on a current basis and allows for an ROE of 9.81 percent on its generation investment.
·
SCRC, which allows PSNH to recover its stranded costs, including above-market expenses incurred under mandated power purchase obligations and other long-term investments and obligations. 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.
·
TCAM, which allows PSNH to recover its transmission related costs on a fully reconciling basis. The TCAM is adjusted on July 1 of each year.
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. On December 28, 2012, the NHPUC issued orders approving PSNH’s requests to adjust its ES and SCRC rates effective with service rendered on and after January 1, 2013. The orders approve an increase to the ES billing rate to reflect projected costs for 2013 and a decrease to the SCRC billing rate to reflect the full amortization of RRBs as of May 1, 2013. The impact to customers that purchase energy from PSNH is a net increase of 1.287 cents per kWh in total rates.
On June 28, 2010, the NHPUC approved a joint settlement of PSNH's rate case. Under the approved settlement, if PSNH's 12-month rolling average ROE for distribution exceeds 10 percent, amounts over the 10 percent level are to be allocated 75 percent to customers and 25 percent to PSNH. Additionally, the settlement provided that the authorized regulatory ROE on distribution plant would continue at the previously allowed level of 9.67 percent, and also permitted PSNH to file a request to collect certain exogenous costs and step increases on an annual basis. In 2012, PSNH filed for a step increase and a change in its accrual to its major storm reserve fund. On June 27, 2012, the NHPUC approved an annualized distribution rate increase of $7.1 million effective July 1, 2012, for the step increase. Additionally, PSNH was allowed a $3.5 million increase in the annual accrual to its major storm reserve fund effective July 1, 2012.
On November 22, 2011, the NHPUC opened a docket to review the Clean Air Project including the establishment of temporary rates for near-term recovery of Clean Air Project costs, a prudence review of PSNH's overall construction program, and establishment of permanent rates for recovery of prudently incurred Clean Air Project costs. On April 10, 2012, the NHPUC issued an order authorizing temporary rates, effective April 16, 2012, which recover a significant portion of the Clean Air Project costs, including a return on equity. The docket will continue for a comprehensive prudence review of the Clean Air Project and the establishment of a permanent rate. The temporary rates will remain in effect until a permanent rate allowing full recovery of all prudently incurred costs is approved. At that time,
the NHPUC will reconcile recoveries collected under the temporary rates with final approved rates. PSNH expects hearings to commence in this proceeding on or about the third quarter of 2013. PSNH believes that its actions related to Clean Air Project construction will be deemed prudent. The project was completed for $421 million, approximately $36 million below budget, and has reduced mercury and sulfur emissions by more than 90 percent. On September 6, 2012, a consultant for the NHPUC filed a report with the NHPUC concluding that PSNH had effectively managed the Clean Air Project.
Sources and Availability of Electric Power Supply
During 2012, approximately 59 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 41 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 2013 in a similar manner. Included in the 59 percent above are PSNH’s obligations to purchase power from approximately two dozen IPPs, the output of which it either uses to serve its customer load or sells into the ISO-NE market.
NATURAL GAS DISTRIBUTION SEGMENT
General
NU’s natural gas distribution segment consists of the distribution businesses of NSTAR Gas and Yankee Gas, which are engaged in the distribution of natural gas to retail customers in eastern Massachusetts and Connecticut, respectively.
The following table shows the sources of the 2012 natural gas franchise retail revenues of NSTAR Gas and Yankee Gas based on categories of customers:
(1)
NSTAR Gas’ revenue for the full-year ended December 31, 2012, has been provided for comparative purposes only.
A summary of NSTAR Gas’ and Yankee Gas’ retail firm natural gas sales and percentage changes in million cubic feet for 2012, as compared to 2011, is as follows:
(1)
NSTAR Gas’ sales data for the full-year ended December 31, 2012 compared to 2011 has been provided for comparative purposes only.
(2)
Special contracts are unique to the Yankee Gas customers who take service under such an arrangement and generally specify the amount of distribution revenue to be paid to Yankee Gas regardless of the customers’ usage.
Our firm natural gas sales are subject to many of the same influences as our retail electric sales, but have benefitted from lower natural gas prices and customer growth across all three customer classes. In 2012, excluding the impact of NSTAR Gas sales, actual sales decreased, as compared to 2011, due primarily to the warmer than normal weather in the first quarter of 2012, as compared to colder than normal weather in the first quarter of 2011. On a weather normalized basis, Yankee Gas’ 2012 sales increased due primarily to customer growth, lower cost of natural gas, the migration of interruptible customers switching to firm service rates, and the addition of gas-fired distributed generation in Yankee Gas’ service territory.
On a weather-normalized basis, the average NU combined consolidated total firm natural gas sales increased 2.7 percent in 2012, as compared to 2011, assuming NSTAR Gas had been part of the NU combined natural gas distribution system for all periods under consideration.
NSTAR GAS COMPANY
NSTAR Gas distributes natural gas to approximately 272,000 customers in 51 communities in central and eastern Massachusetts covering 1,067 square miles. Total throughput (sales and transportation) in 2012 was approximately 60.5 Bcf. NSTAR Gas provides firm natural gas sales service to retail customers who require a continuous natural gas supply throughout the year, such as residential customers who rely on gas for heating, hot water and cooking needs, and commercial and industrial customers who choose to purchase natural gas from NSTAR Gas.
Rates
NSTAR Gas generates revenues primarily through the sale and/or transportation of natural gas. Gas sales and transportation services are divided into two categories: firm, whereby NSTAR Gas must supply gas and/or transportation services to customers on demand; and interruptible, whereby NSTAR Gas may, generally during colder months, temporarily discontinue service to high volume commercial and industrial customers. Sales and transportation of gas to interruptible customers have no impact on NSTAR Gas’ operating income because a substantial portion of the margin for such service is returned to its firm customers as rate reductions.
The Attorney General settlement agreement that approved the Merger provided for a rate freeze through 2015 and a rate credit of $3 million to NSTAR Gas customers.
Retail natural gas delivery and supply rates are established by the DPU and are comprised of:
·
A distribution charge consisting of a fixed customer charge and a demand and/or energy charge that collects the costs of building and expanding the natural gas infrastructure to deliver natural gas supply to its customers. This also includes collection of ongoing operating costs;
·
A seasonal cost of gas adjustment clause (CGAC) that collects natural gas supply costs, pipeline and storage capacity costs, costs related to charge-offs of uncollected energy costs and working capital related costs. The CGAC is reset every six months. In addition, NSTAR Gas files interim changes to its CGAC factor when the actual costs of natural gas supply vary from projections by more than 5 percent; and
·
A local distribution adjustment clause (LDAC) that collects energy efficiency program costs, environmental costs, PAM related costs, and costs associated with the residential assistance adjustment clause. The LDAC is reset annually and provides for the recovery of certain costs applicable to both sales and transportation customers.
NSTAR Gas purchases financial contracts based on NYMEX natural gas futures in order to reduce cash flow variability associated with the purchase price for approximately one-third of its natural gas purchases. These purchases are made under a program approved by the Massachusetts Department of Public Utilities in 2006. This practice attempts to minimize the impact of fluctuations in prices to NSTAR Gas’ firm gas customers. These financial contracts do not procure gas supply. All costs incurred or benefits realized when these contracts are settled are included in the CGAC.
Sources and Availability of Natural Gas Supply
NSTAR Gas maintains a flexible resource portfolio consisting of natural gas supply contracts, transportation contracts on interstate pipelines, market area storage and peaking services. NSTAR Gas purchases transportation, storage, and balancing services from Tennessee Gas Pipeline Company and Algonquin Gas Transmission Company, as well as other upstream pipelines that transport gas from major producing regions in the U.S., including Gulf Coast, Mid-continent, and Appalachian Shale supplies to the final delivery points in the NSTAR Gas service area. NSTAR Gas purchases all of its natural gas supply from a firm portfolio management contract with a term of one year, which has a maximum quantity of approximately 139,500 MMBtu/day.
In addition to the firm transportation and natural gas supplies mentioned above, NSTAR Gas utilizes contracts for underground storage and LNG facilities to meet its winter peaking demands. The LNG facilities, described below, are located within NSTAR Gas’ distribution system and are used to liquefy and store pipeline gas during the warmer months for vaporization and use during the heating season. During the summer injection season, excess pipeline capacity and supplies are used to deliver and store natural gas in market area underground storage facilities located in the New York and Pennsylvania region. Stored natural gas is withdrawn during the winter season to supplement flowing pipeline supplies in order to meet firm heating demand. NSTAR Gas has firm underground storage contracts and total storage capacity entitlements of approximately 6.6 Bcf.
A portion of the storage of natural gas supply for NSTAR Gas during the winter heating season is provided by Hopkinton, a wholly-owned subsidiary of NSTAR LLC. The facilities consist of an LNG liquefaction and vaporization plant and three above-ground cryogenic storage tanks in Hopkinton, Massachusetts having an aggregate capacity of 3.0 Bcf of liquefied natural gas. NSTAR Gas also has access to facilities in Acushnet, Massachusetts that include additional storage capacity of 0.5 Bcf and additional vaporization capacity.
Based on information currently available regarding projected growth in demand and estimates of availability of future supplies of pipeline natural gas, NSTAR Gas believes that participation in planned and anticipated pipeline expansion projects will be required in order for it to meet current and future sales growth opportunities.
YANKEE GAS SERVICES COMPANY
Yankee Gas operates the largest natural gas distribution system in Connecticut as measured by number of customers (approximately 212,000 customers in 71 cities and towns), and size of service territory (2,187 square miles). Total throughput (sales and transportation) in 2012 was approximately 51 Bcf. Yankee Gas provides firm natural gas sales service to retail customers who require a continuous natural gas supply throughout the year, such as residential customers who rely on gas for heating, hot water and cooking needs, and commercial and industrial customers who choose to purchase natural gas from Yankee Gas. Yankee Gas also owns a 1.2 Bcf LNG facility in Waterbury, Connecticut, which is used primarily to assist it in meeting its supplier-of-last-resort obligations and also enables it to make economic purchases of natural gas, which typically occur during periods of low demand.
Retail natural gas service in Connecticut is partially unbundled: residential customers in Yankee Gas’ service territory buy gas supply and delivery only from Yankee Gas while commercial and industrial customers may choose their gas suppliers. Yankee Gas offers firm transportation service to its commercial and industrial customers who purchase gas from sources other than Yankee Gas as well as interruptible transportation and interruptible gas sales service to those commercial and industrial customers that have the capability to switch from natural gas to an alternative fuel on short notice, for whom Yankee Gas can interrupt service during peak demand periods or at any other time to maintain distribution system integrity.
Rates
Yankee Gas is subject to regulation by PURA, which has jurisdiction over, among other things, rates, accounting procedures, certain dispositions of property and plant, mergers and consolidations, issuances of long-term securities, standards of service, affiliate transactions, management efficiency and construction and operation of distribution, production and storage facilities.
Retail natural gas delivery and supply rates are established by the PURA and are comprised of:
·
A distribution charge consisting of a fixed customer charge and a demand and/or energy charge that collects the costs of building and expanding the natural gas infrastructure to deliver natural gas supply to its customers. This also includes collection of ongoing operating costs;
·
Purchased Gas Adjustment (PGA) clause, which allows Yankee Gas to recover the costs of the procurement of natural gas for its firm and seasonal customers. Differences between actual natural gas costs and collection amounts on August 31st of each year are deferred and then recovered or returned to customers during the following year. Carrying charges on outstanding balances are calculated using Yankee Gas' weighted average cost of capital in accordance with the directives of the PURA; and
·
Conservation Adjustment Mechanism (CAM), which allows 100 percent recovery of conservation costs through this mechanism, with a return. The reconciliation process produces deferrals for future recovery or refund in future customer rates each year.
On June 29, 2011 PURA issued a final decision in Yankee Gas’ rate proceeding, which it amended in September 2011. The final amended decision approved a regulatory ROE of 8.83 percent, based on a capital structure of 52.2 percent common equity and 47.8 percent debt, approved the inclusion in rates of costs associated with the WWL project, and also allowed for a substantial increase in annual spending for bare steel and cast iron pipe replacement, as requested by Yankee Gas.
Sources and Availability of Natural Gas Supply
PURA requires that Yankee Gas meet the needs of its firm customers under all weather conditions. Specifically, Yankee Gas must structure its supply portfolio to meet firm customer needs under a design day scenario (defined as the coldest day in 30 years) and under a design year scenario (defined as the average of the four coldest years in the last 30 years). Yankee Gas also owns a 1.2 Bcf LNG facility in Waterbury, Connecticut, which is used primarily to assist Yankee Gas in meeting its supplier-of-last-resort obligations and also enables Yankee Gas to make economic purchases of natural gas, typically in periods of low demand. Yankee Gas’ on-system stored LNG and underground storage supplies help to meet consumption needs during the coldest days of winter. Yankee Gas obtains its interstate capacity from the three interstate pipelines that directly serve Connecticut: the Algonquin, Tennessee and Iroquois Pipelines. Yankee Gas has long-term firm contracts for capacity on TransCanada Pipelines Limited Pipeline, Vector Pipeline, L.P., Tennessee Gas Pipeline, Iroquois Gas Transmission Pipeline, Algonquin Pipeline, Union Gas Limited, Dominion Transmission, Inc., National Fuel Gas Supply Corporation, Transcontinental Gas Pipeline Company, and Texas Eastern Transmission, L.P. pipelines. Based on information currently available regarding projected growth in demand and estimates of availability of future supplies of pipeline natural gas, Yankee Gas believes that its present sources of natural gas supply are adequate to meet existing load and allow for future growth in sales.
ELECTRIC TRANSMISSION SEGMENT
General
CL&P, NSTAR Electric, 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 rules by which they participate in the wholesale markets and acquire transmission services. Under these arrangements, ISO-NE, a non-profit corporation whose board of directors and staff are independent of all market participants, has served since 2005 as the regional transmission organization of the New England transmission system. ISO-NE works to ensure the reliability of the system, administers, subject to FERC approval, the independent system operator tariff, oversees the efficient and competitive functioning of the regional wholesale power market and determines which costs of all regional major transmission facilities are shared by consumers throughout New England.
Wholesale Transmission Rates
Wholesale transmission revenues are recovered through formula rates that are approved by the FERC. Our transmission revenues are recovered from New England customers through charges that recover costs of transmission and other transmission-related services provided by all regional transmission owners, with a portion of those revenues collected from the distribution businesses of CL&P, NSTAR Electric, PSNH and WMECO. These rates provide for the annual reconciliation and recovery or refund of estimated costs to actual costs. The difference between estimated and actual costs is deferred for future recovery from, or refunded to, transmission customers.
FERC ROE Proceedings
Pursuant to a series of orders involving the ROE for regionally planned New England transmission projects, the FERC set the base ROE at 11.14 percent and approved incentives that increased the ROE to 12.64 percent for those projects that were in-service by the end of 2008. Beginning in 2009, the ROE for all regional transmission investment approved by ISO-NE is 11.64 percent, which includes 50 basis points for joining a regional transmission organization. In addition, certain projects were granted additional ROE incentives by FERC under its transmission incentive policy. As a result, CL&P earns between 12.64 percent and 13.1 percent on its major transmission projects, NSTAR Electric earns between 11.64 percent and 12.64 percent on its major transmission projects, and WMECO earns 12.89 percent on the Massachusetts portion of GSRP.
On September 30, 2011, several New England state attorneys general, state regulatory commissions, consumer advocates and other parties filed a joint complaint with the FERC under Sections 206 and 306 of the Federal Power Act alleging that the base ROE used in calculating formula rates for transmission service under the ISO-NE Open Access Transmission Tariff by New England transmission owners, including CL&P, NSTAR Electric, PSNH and WMECO, is unjust and unreasonable. The complainants asserted that the current 11.14 percent rate, which became effective in 2006, is excessive due to changes in the capital markets and are seeking an order to reduce the rate, which would be effective September 30, 2011 through December 31, 2012. In response, the New England transmission owners filed testimony and analysis based on standard FERC methodology and precedent, demonstrating that the base ROE of 11.14 percent remained just and reasonable.
On May 3, 2012, the FERC issued an order establishing hearing and settlement procedures for the complaint. The settlement proceedings were subsequently terminated, as the parties had reached an impasse in their efforts to reach a settlement. In August 2012, the FERC trial judge assigned to the complaint established a schedule for the trial phase of the proceedings. Complainant testimony supporting a base ROE of 9 percent was filed on October 1, 2012. Additional testimony was filed on October 1, 2012 by a group of Massachusetts municipal electric companies, which recommended a base ROE of 8.2 percent. The New England transmission owners filed testimony and analysis on November 20, 2012, demonstrating they believe that the current base ROE continues to be just and reasonable. On January 18, 2013, the FERC trial staff filed testimony and analysis recommending a base ROE of 9.66 percent based on the midpoint of their analysis with a range of reasonableness of 6.82 percent to 12.51 percent. The New England transmission owners criticized trial staff's analysis in responsive testimony filed on February 12, 2013. Complainants' final testimony is due February 27, 2013. Hearings on this complaint are scheduled for May 2013 and a trial judge’s recommended decision is due in September 2013. A decision from FERC commissioners is expected in 2014. Refunds to customers, if any, as a result of a reduction in the NU transmission companies’ base ROE would be retroactive to October 1, 2011.
On December 27, 2012, several additional parties filed a separate complaint concerning the New England transmission owners' ROE with the FERC. This new complaint seeks to reduce the New England transmission owner’s base transmission ROE effective January 1, 2013, and to consolidate this new complaint with the joint complaint filed on September 30, 2011. The New England transmission owners have asked the FERC to reject this new complaint, and the FERC has not yet acted on it.
As of December 31, 2012, CL&P, NSTAR Electric, PSNH, and WMECO had approximately $2.1 billion of aggregate shareholder equity invested in their transmission facilities. As a result, each 10 basis point change in the authorized base ROE would change annual consolidated earnings by an approximate $2.1 million. We cannot at this time predict the ultimate outcome of this proceeding or the estimated impact on CL&P’s, NSTAR Electric’s, PSNH’s, or WMECO’s respective financial position, results of operations or cash flows.
FERC Order No. 1000: On October 25, 2012, ISO-NE and a majority of the New England transmission owners, including CL&P, NSTAR Electric, PSNH and WMECO, made a comprehensive compliance filing as required by FERC Order No. 1000 and Order No. 1000-A, issued on July 21, 2011 and May 17, 2012, respectively. The compliance filing first seeks to preserve the existing reliability planning process in New England, based on FERC’s previous approval of transmission owners’ rights under the Transmission Operating Agreement with ISO-NE, and the superiority of the current planning process, which has resulted in major transmission construction, large reliability benefits and reduction of market costs. The filing also contains a new process for public policy transmission planning that incorporates opportunities for competing, non-incumbent projects and cost allocation among the supporting states. In mid-January 2013, ISO-NE and the majority of New England transmission owners filed answers to various stakeholders that submitted protests to the compliance filing. We cannot predict the final outcome or impact on us; however implementation of FERC’s goals in New England, including within our service territories, may expose us to competition for construction of transmission projects, additional regulatory considerations, and potential delay with respect to future transmission projects.
Transmission Projects
NEEWS: GSRP, a project that involves the construction of 115 kV and 345 kV overhead lines by CL&P and WMECO from Ludlow, Massachusetts to Bloomfield, Connecticut, is the first, largest and most complicated project within the NEEWS family of projects. The $718 million project is expected to be fully placed in service in late 2013. As of December 31, 2012, the project was approximately 93 percent complete and we have placed $298 million in service.
The Interstate Reliability Project, which includes CL&P’s construction of an approximately 40-mile, 345 kV overhead line from Lebanon, Connecticut to the Connecticut-Rhode Island border in Thompson, Connecticut where it will connect to transmission enhancements being constructed by National Grid, is our second major NEEWS project. All siting applications have been filed by CL&P and National Grid. On January 2, 2013, the Connecticut Siting Council issued a final decision and order approving the Connecticut portion of the project. Decisions in Rhode Island and Massachusetts are expected between the end of 2013 and early 2014. The $218 million project is expected to be placed in service in late 2015.
Included as part of NEEWS are associated reliability related projects, approximately $70 million of which have been placed in service and approximately $30 million of which are in various phases of construction and will continue to go into service through 2013.
Through December 31, 2012, CL&P and WMECO had capitalized $212 million and $518.1 million, respectively, in costs associated with NEEWS, of which $79.4 million and $183.4 million, respectively, were capitalized in 2012.
Greater Hartford Central Connecticut Project (GHCC): In August 2012, ISO-NE presented its preliminary needs analysis for the GHCC to the ISO-NE Planning Advisory Committee. The results showed severe thermal overloads and voltage violations in each of the four study areas now and in the near future. A combination of 345 kV and 115 kV transmission solutions are being considered to address these reliability concerns and a set of preferred solutions are expected to be identified by ISO-NE in 2013. Approximately $300 million has been included in our five-year capital program for future projects being identified to enhance these reliability concerns, which have recently been confirmed by ISO-NE.
Cape Cod Reliability Projects: Transmission projects serving Cape Cod in the Southeastern Massachusetts (SEMA) reliability region consist of an expansion and upgrade of NSTAR Electric's existing transmission infrastructure including construction of a new 345 kV transmission line that will cross the Cape Cod Canal (The Lower SEMA Transmission Project) as well as a new 115kV transmission line and other 115kV upgrades in the center of Cape Cod. All regulatory and licensing and permitting is complete for the Lower SEMA Transmission Project. Construction commenced in September 2012 and is expected to be completed by mid-2013. The total estimated construction cost for the Cape Cod projects is approximately $150 million.
Northern Pass: Northern Pass is NPT's planned HVDC transmission line from the Québec-New Hampshire border to Franklin, New Hampshire and an associated alternating current radial transmission line between Franklin and Deerfield, New Hampshire. Northern Pass will interconnect at the Québec-New Hampshire border with a planned HQ HVDC transmission line. Effective April 10, 2012, as a result of the merger, NUTV owned 100 percent of NPT. NPT has identified a new route in the northern-most part of the project’s route where PSNH did not own any rights of way. We expect to file the new route with the DOE in the first quarter of 2013, and we believe that NPT will be completed in early 2017.
We estimate the costs of the Northern Pass transmission project will be approximately $1.2 billion (including capitalized AFUDC).
Greater Boston Reliability and Boston Network Improvements: As a result of continued analysis of the transmission needs to enhance system reliability and improve capacity in eastern Massachusetts, NSTAR Electric expects to implement a series of new transmission initiatives over the next five years. We have included $479 million in our five-year capital program related to these initiatives.
Transmission Rate Base
Under our FERC-approved tariff, transmission projects generally enter rate base after they are placed in commercial operation. At the end of 2012, our transmission rate base was approximately $4.2 billion, including approximately $2.2 billion at CL&P, $960 million at NSTAR Electric, $412 million at PSNH, and $620 million at WMECO.
CAPITAL EXPENDITURES
We project capital expenditures of approximately $5 billion from 2013 through 2015. Of the $5 billion, we expect to invest approximately $2.5 billion in our electric and natural gas distribution segments, including our generation businesses, and $2.3 billion in our electric transmission segment. In addition, we project capital expenditures of approximately $1.6 billion from 2016 through 2017 in our electric transmission segment.
FINANCING
Our credit facilities and indentures require that NU parent and certain of its subsidiaries, including CL&P, NSTAR Electric, NSTAR Gas, NSTAR LLC, PSNH, WMECO and Yankee Gas, comply with certain financial and non-financial covenants as are customarily included in such agreements, including maintaining a ratio of consolidated debt to total capitalization of no more than 65 percent. All such companies currently are, and expect to remain in compliance with these covenants.
As of December 31, 2012, approximately $730 million of NU's long-term debt will be paid in the next 12 months, consisting of $550 million for NU parent, $55 million for WMECO, and $125 million for CL&P.
NUCLEAR DECOMMISSIONING
General
CL&P, NSTAR Electric, PSNH, WMECO and several other New England electric utilities are stockholders in three inactive regional nuclear generation companies, CYAPC, MYAPC and YAEC (collectively, the Yankee Companies). The Yankee Companies have completed the physical decommissioning of their respective generation facilities and are now engaged in the long-term storage of their spent nuclear fuel. Each Yankee Company collects decommissioning and closure costs through wholesale FERC-approved rates charged under power purchase agreements with CL&P, NSTAR Electric, PSNH and WMECO and several other New England utilities. These companies in turn recover these costs from their customers through state regulatory commission-approved retail rates.
The ownership percentages of CL&P, NSTAR Electric, PSNH and WMECO in the Yankee Companies are set forth below:
CL&P
NSTAR Electric
PSNH
WMECO
Total
CYAPC
34.5%
14.0%
5.0%
9.5%
63.0%
YAEC
24.5%
14.0%
7.0%
7.0%
52.5%
MYAPC
12.0%
4.0%
5.0%
3.0%
24.0%
Our share of the obligations to support the Yankee Companies under FERC-approved contracts is the same as the ownership percentages above. As a result of the Merger, we consolidate the assets and obligations of CYAPC and YAEC on our consolidated balance sheet.
OTHER REGULATORY AND ENVIRONMENTAL MATTERS
General
We are regulated in virtually all aspects of our business by various federal and state agencies, including FERC, the SEC, and various state and/or local regulatory authorities with jurisdiction over the industry and the service areas in which each of our companies operates, including the PURA, which has jurisdiction over CL&P and Yankee Gas, the NHPUC, which has jurisdiction over PSNH, and the DPU, which has jurisdiction over NSTAR Electric, NSTAR Gas and WMECO.
Environmental Regulation
We are subject to various federal, state and local requirements with respect to water quality, air quality, toxic substances, hazardous waste and other environmental matters. Additionally, major generation and transmission facilities may not be constructed or significantly modified without a review of the environmental impact of the proposed construction or modification by the applicable federal or state agencies. PSNH owns approximately 1,200 MW of generation assets. In 2011, PSNH’s Clean Air Project, the installation of a wet flue gas desulphurization system at its Merrimack coal station to reduce its mercury and sulfur dioxide emissions, was placed into service. The Clean Air Project was fully operational by mid-2012 and is designed to capture more than 80 percent of the mercury in the coal from the coal burning stations and to reduce sulfur dioxide emissions by more than 90 percent, making Merrimack one of the cleanest coal-burning plants in the nation. The final cost of the project was approximately $421 million. Compliance with additional environmental laws and regulations, particularly air and water pollution control requirements, may cause changes in operations or require further investments in new equipment at existing facilities.
Water Quality Requirements
The Clean Water Act requires every “point source” discharger of pollutants into navigable waters to obtain a National Pollutant Discharge Elimination System (NPDES) permit from the EPA or state environmental agency specifying the allowable quantity and characteristics of its effluent. States may also require additional permits for discharges into state waters. We are in the process of maintaining or renewing all required NPDES or state discharge permits in effect for our facilities. In each of the last three years, the costs incurred by PSNH related to compliance with NPDES and state discharge permits have not been material.
On September 29, 2011, the EPA issued for public review and comment a draft renewal NPDES permit under the Clean Water Act for PSNH’s Merrimack Station. The draft permit would require PSNH to install a closed-cycle cooling system at the station. The EPA estimated that the net present value cost to install this system and operate it over a 20-year period would be approximately $112 million. On October 27, 2011, the EPA extended the initial 60-day public review and comment period on the draft permit for an additional 90 days until February 28, 2012. In its filed comments, PSNH stated that the data and studies supplied to the EPA demonstrates the fact that a closed-cycle cooling system is not warranted. The EPA has no deadline to consider comments and to issue a final permit. Merrimack Station can continue to operate under its current permit pending issuance of the final permit and subsequent resolution of appeals by PSNH and other parties. Due to the site specific characteristics of PSNH's other fossil fueled electric generating stations, we believe it is unlikely that there would be similar permit requirements imposed on them.
Air Quality Requirements
The Clean Air Act Amendments (CAAA), as well as New Hampshire law, impose stringent requirements on emissions of SO2 and NOX for the purpose of controlling acid rain and ground level ozone. In addition, the CAAA address the control of toxic air pollutants. Requirements for the installation of continuous emissions monitors and expanded permitting provisions also are included.
In December 2011, the EPA finalized the Mercury and Air Toxic Standards (MATS) that require the reduction of emissions of hazardous air pollutants from new and existing coal- and oil-fired electric generating units. Previously referred to as the Utility MACT (maximum achievable control technology) rules, it establishes emission limits for mercury, arsenic and other hazardous air pollutants from coal and oil-fired units. MATS is the first implementation of a nationwide emissions standard for hazardous air pollutants across all electric generating units and provides utility companies with up to five years to meet the requirements. PSNH owns and operates approximately 1,000 MW of fossil fueled electric generating units subject to MATS, including the two units at Merrimack Station, Newington Station and the two coal units at Schiller Station. We believe the Clean Air Project at our Merrimack Station, together with existing equipment, will enable the facility to meet the MATS requirements. A review of the potential impact of MATS on our other PSNH units is not yet complete. Additional incremental controls may be required for the two coal fired units at Schiller Station. To date, the financial impact of this potential control has not been determined.
NU’s carbon emission inventory accounts for and reports all direct carbon dioxide (CO2) methane (CH4) nitrous oxide (N2O) sulfur hexafluoride (SF6) emissions for operations of NU and its subsidiaries in carbon dioxide equivalents. Total carbon emissions include those from sources owned or operated by NU (Scope 1) and those that are a consequence of NU’s activities, but occur from sources owned or controlled by others, such as emissions from purchased electricity and line loss during the transmission and distribution of electricity (Scope 2). NU emissions expressed in thousand metric tons of carbon dioxide equivalent (CO2-e) for NU and its system companies for 2009 through 2011 are shown below.
Total CO2-e emissions (excludes CO2
from biomass and biofuels)
2,984
3,976
3,390
Data was collected and calculated using the World Resource Institute greenhouse gas protocol tools except for stationary combustion emissions associated with electric generating units where more accurate Continuous Emissions Monitoring System data was available. EPA reporting protocol was used for generation calculations where applicable.
Each of the states in which we do business also has Renewable Portfolio Standards (RPS) requirements, which generally require fixed percentages of our energy supply to come from renewable energy sources such as solar, hydropower, landfill gas, fuel cells and other similar sources.
New Hampshire’s RPS provision requires increasing percentages of the electricity sold to retail customers to have direct ties to renewable sources. In 2012, the total RPS obligation was 13 percent and it will ultimately reach 26.5 percent in 2025. Energy suppliers, like PSNH, purchase RECs from producers that generate energy from a qualifying resource and use them to satisfy the RPS requirements. PSNH also owns renewable sources and uses a portion of internally generated RECs and purchased RECs to meet its RPS obligations. To the extent that PSNH is unable to purchase sufficient RECs, it makes up the difference between the RECs purchased and its total obligation by making an alternative compliance payment for each REC requirement for which PSNH is deficient. The costs of both the RECs and alternative compliance payments are recovered by PSNH through its ES rates charged to customers.
The RECs generated from PSNH’s Northern Wood Power Project, a wood-burning facility, are typically sold to other energy suppliers or load carrying entities and the net proceeds from the sale of these RECs are credited back to customers.
Similarly, Connecticut's RPS statute requires increasing percentages of the electricity sold to retail customers to have direct ties to renewable sources. In 2012, the total RPS obligation was 16 percent and will ultimately reach 27 percent in 2020. CL&P is permitted to recover any costs incurred in complying with RPS from its customers through rates.
Massachusetts’ RPS program also requires electricity suppliers to meet renewable energy standards. For 2012, the requirement was 16.6 percent, and will ultimately reach 27.1 percent in 2020. NSTAR Electric and WMECO are permitted to recover any costs incurred in complying with RPS from its customers through rates. WMECO also owns renewable solar generation resources. The RECs generated from WMECO’s solar units are sold to other energy suppliers and the proceeds from these sales are credited back to customers.
Hazardous Materials Regulations
Prior to the last quarter of the 20th century when environmental best practices and laws were implemented, utility companies often disposed of residues from operations by depositing or burying them on-site or disposing of them at off-site landfills or other facilities. Typical materials disposed of include coal gasification byproducts, fuel oils, ash, and other materials that might contain polychlorinated biphenyls or that otherwise might be hazardous. 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, based upon currently available information, is our estimated environmental investigation and/or remediation costs for waste disposal sites for which we expect to bear legal liability. We 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 these practices. As of December 31, 2012, the liability recorded by us for our reasonably estimable and probable environmental remediation costs for known sites needing investigation and/or remediation, exclusive of recoveries from insurance or from third parties, was approximately $39.4 million, representing 77 sites. These costs could be significantly higher if remediation becomes necessary or when additional information as to the extent of contamination becomes available.
The most significant liabilities currently relate to future clean-up costs at former MGP facilities. These facilities were owned and operated by our predecessor companies from the mid-1800's to mid-1900's. By-products from the manufacture of gas using coal resulted in fuel oils, hydrocarbons, coal tar, purifier wastes, metals and other waste products that may pose risks to human health and the environment. We, through our subsidiaries, currently have partial or full ownership responsibilities at former MGP sites that have a reserve balance of $34.5 million of the total $39.4 million as of December 31, 2012.
HWP, a wholly owned subsidiary of NU, is continuing to evaluate additional potential remediation requirements at a river site in Massachusetts containing tar deposits associated with an MGP site that HWP sold to HG&E, a municipal electric utility, in 1902. HWP is at least partially responsible for this site and has already conducted substantial investigative and remediation activities. HWP's share of the remediation costs related to this site is not recoverable from customers.
Electric and Magnetic Fields
For more than twenty years, published reports have discussed the possibility of adverse health effects from electric and magnetic fields (EMF) associated with electric transmission and distribution facilities and appliances and wiring in buildings and homes. Although weak health risk associations reported in some epidemiology studies remain unexplained, most researchers, as well as numerous scientific review panels, considering all significant EMF epidemiology and laboratory studies, have concluded that the available body of scientific information does not support the conclusion that EMF affects human health.
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, we reduce EMF associated with new transmission lines by the use of designs that can be implemented without additional cost or at a modest cost. We do not believe that other capital expenditures are appropriate to minimize unsubstantiated risks.
Global Climate Change and Greenhouse Gas Emission Issues
Global climate change and greenhouse gas emission issues have received an increased focus from state governments and the federal government. The EPA initiated a rulemaking addressing greenhouse gas emissions and, on December 7, 2009, issued a finding that concluded that greenhouse gas emissions are “air pollution” that endanger public health and welfare and should be regulated. The largest source of greenhouse gas emissions in the U.S. is the electricity generating sector. The EPA has mandated greenhouse gas emission reporting beginning in 2011 for emissions for certain aspects of our business including stationary combustion, volume of gas supplied to large customers and fugitive emissions of SF6 gas and methane.
We are continually evaluating the regulatory risks and regulatory uncertainty presented by climate change concerns. Such concerns could potentially lead to additional rules and regulations that impact how we operate our business, both in terms of the generating facilities we own and operate as well as general utility operations. These could include federal “cap and trade” laws, carbon taxes, fuel and energy taxes, or regulations requiring additional capital expenditures at our generating facilities. We expect that any costs of these rules and regulations would be recovered from customers.
Connecticut, New Hampshire and Massachusetts are each members of the Regional Greenhouse Gas Initiative (RGGI), a cooperative effort by nine northeastern and mid-Atlantic states, to develop a regional program for stabilizing and reducing CO2 emissions from fossil fueled electric generating plants. Because CO2 allowances issued by any participating state are usable across all nine RGGI state programs, the individual state CO2 trading programs, in the aggregate, form one regional compliance market for CO2 emissions. A regulated power plant must hold CO2 allowances equal to its emissions to demonstrate compliance at the end of a three year compliance period that began in 2012.
PSNH anticipates that its generating units will emit between two million and four million tons of CO2 per year, depending on the capacity factor and the utilization of the plant, excluding emissions from the operation of PSNH’s Northern Wood Power Project. New Hampshire legislation provides up to 1.5 million banked CO2 allowances per year for PSNH’s fossil fueled electric generating plants during the 2012 through 2014 compliance period. PSNH expects to satisfy its remaining RGGI requirements by purchasing CO2 allowances at auction or in the secondary market. The cost of complying with RGGI requirements is recoverable from PSNH customers. Current legislation provides a portion of the RGGI auction proceeds in excess of $1 per allowance will be refunded to customers.
Because none of NU’s other subsidiaries, CL&P, NSTAR Electric or WMECO, currently owns any generating assets (other than two solar photovoltaic facilities owned by WMECO, which do not emit CO2), none of them is required to acquire CO2 allowances. However, the CO2 allowance costs borne by the generating facilities that are utilized by wholesale suppliers to satisfy energy supply requirements to CL&P, NSTAR Electric and WMECO will likely be included in the overall wholesale rates charged, which costs are then recoverable from customers.
Federal greenhouse gas legislation has stalled under the current administration. Recently, climate change law has been discussed as an initiative that will be moved forward in the current Congress. However, even without legislation, we can expect additional regulations from the EPA that could impact NU.
FERC Hydroelectric Project Licensing
Federal Power Act licenses may be issued for hydroelectric projects for terms of 30 to 50 years as determined by the FERC. Upon the expiration of an existing license, (i) the FERC may issue a new license to the existing licensee, (ii) the United States may take over the project, or (iii) the FERC may issue a new license to a new licensee, upon payment to the existing licensee of the lesser of the fair value or the net investment in the project, plus severance damages, less certain amounts earned by the licensee in excess of a reasonable rate of return.
PSNH owns nine hydroelectric generating stations with a current claimed capability representing winter rates of approximately 71 MW, eight of which are licensed by the FERC under long-term licenses that expire on varying dates from 2017 through 2047. PSNH and its hydroelectric projects are subject to conditions set forth in such licenses, the Federal Power Act and related FERC regulations, including provisions related to the condemnation of a project upon payment of just compensation, amortization of project investment from excess project earnings, possible takeover of a project after expiration of its license upon payment of net investment and severance damages and other matters. PSNH is currently involved with the early stages of relicensing at its Eastman Falls Hydro Station, which is comprised of two units, totaling 6.5 MW.
Licensed operating hydroelectric projects are not generally subject to decommissioning during the license term in the absence of a specific license provision that 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. PSNH is not presently encountering any of these challenges.
EMPLOYEES
As of December 31, 2012, we employed a total of approximately 8,842 employees, excluding temporary employees, of which 1,787 were employed by CL&P, 1,204 were employed by PSNH, 348 were employed by WMECO, and 1,619 employees employed by NSTAR Electric & Gas Corporation provided services to NSTAR Electric. Approximately 47.8 percent of our employees are members of the International Brotherhood of Electrical Workers, the Utility Workers Union of America or The United Steelworkers, and are covered by 13 collective bargaining agreements.
INTERNET INFORMATION
Our website address is www.nu.com. We make available through our website a link to the SEC's EDGAR website (http://www.sec.gov/edgar/searchedgar/companysearch.html), at which site NU's, CL&P's, NSTAR Electric’s, PSNH's and WMECO's Annual Reports on Form 10-K, Quarterly Reports on Form 10-Q, Current Reports on Form 8-K and any amendments to those reports may be reviewed. Printed copies of these reports may be obtained free of charge by writing to our Investor Relations Department at Northeast Utilities, 56 Prospect Street, Hartford, CT 06103.
Item 1A.
Item 1A.
Risk Factors
In addition to the matters set forth under “Safe Harbor Statement Under the Private Securities Litigation Reform Act of 1995” included immediately prior to Item 1, Business, above, we are subject to a variety of significant risks. Our susceptibility to certain risks, including those discussed in detail below, could exacerbate other risks. These risk factors should be considered carefully in evaluating our risk profile.
The Merger may present certain material risks to the Company’s business and operations.
The Merger, described in Item 1, Business, may present certain risks to our business and operations including, among other things, risks that:
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We may be unable to successfully integrate the businesses and workforces of NSTAR with our businesses and workforces;
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Conditions, terms, obligations or restrictions relating to the Merger imposed on us by regulatory authorities may adversely affect our business and operations;
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We may be unable to avoid potential liabilities and unforeseen increased expenses or delays associated with integration plans;
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We may be unable to successfully manage the complex integration of systems, technology, networks and other assets in a manner that minimizes any adverse impact on customers, vendors, suppliers, employees and other constituencies;
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We may experience inconsistencies in each companies’ standards, controls, procedures and policies.
Accordingly, there can be no assurance that the Merger will result in the realization of the full benefits of synergies, innovation and operational efficiencies that we currently expect, that these benefits will be achieved within the anticipated timeframe or that we will be able to fully and accurately measure any such synergies.
Cyber breaches, acts of war or terrorism, or grid disturbances could negatively impact our business.
Cyber intrusions targeting our information systems could impair our ability to properly manage our data, networks, systems and programs, adversely affect our business operations or lead to release of confidential customer information or critical operating information. While we have implemented measures designed to prevent cyber-attacks and mitigate their effects should they occur, our systems are vulnerable to unauthorized access and cyber intrusions. We cannot discount the possibility that a security breach may occur or quantify the potential impact of such an event.
Acts of war or terrorism could target our generation, transmission and distribution facilities or our data management systems. Such actions could impair our ability to manage these facilities or operate our system effectively, resulting in loss of service to customers.
Because our generation and transmission facilities are part of an interconnected regional grid, we face the risk of blackout due to a disruption on a neighboring interconnected system.
Any such cyber breaches, acts of war or terrorism, or grid disturbances could result in a significant decrease in revenues, significant expense to repair system damage or security breaches, and liability claims, which could have a material adverse impact on our financial position, results of operations or cash flows.
Our goodwill is valued and recorded at an amount that, if impaired and written down, could adversely affect our future operating results and total capitalization.
We have a significant amount of goodwill on our consolidated balance sheet. The carrying value of goodwill represents the fair value of an acquired business in excess of identifiable assets and liabilities as of the acquisition date. As of December 31, 2012, goodwill totaled $3.5 billion, of which $3.2 billion was attributable to the acquisition of NSTAR in April 2012. Total goodwill represented approximately 38 percent of our $9.2 billion of shareholders’ equity and approximately 12 percent of our total assets of $28.3 billion. We perform an analysis of our goodwill balances to test for impairment on an annual basis or whenever events occur or circumstances change that would indicate a potential for impairment. A determination that goodwill is deemed to be impaired would result in a non-cash charge that could materially adversely affect our results of operations and total capitalization.
Severe storms could cause significant damage to our electrical facilities requiring extensive capital expenditures, the recovery for which is subject to approval by regulators.
Severe weather, such as Tropical Storm Irene in August 2011, the October 29, 2011 snowstorm, Hurricane Sandy in October 2012, and the February 2013 blizzard, and other such major natural disasters, could cause widespread damage to our transmission and distribution facilities. The resulting cost of repairing damage to our facilities and the potential disruption of our operations could exceed our financial reserves and insurance.
Tropical Storm Irene, the October 29, 2011 snowstorm, and Hurricane Sandy caused significant damage to our transmission and distribution systems. As a result, along with previously deferred costs from other storms, we have recorded approximately $548 million (approximately $414 million at CL&P) for estimated restoration costs as regulatory assets as of December 31, 2012, subject to future recovery from customers. If, upon review, any of our state regulatory authorities finds that our actions were imprudent, some of those restoration costs may not be recoverable from customers. The inability to recover a significant amount of such costs could have an adverse effect on our financial position, results of operations and cash flows.
NU and its utility subsidiaries are exposed to significant reputational risks, which make them vulnerable to increased regulatory oversight or other sanctions.
Because utility companies, including our electric and natural gas utility subsidiaries, have large consumer customer bases, they are subject to adverse publicity focused on the reliability of their distribution services and the speed with which they are able to respond to electric outages, natural gas leaks and similar interruptions caused by storm damage or other unanticipated events. Adverse publicity of this nature could harm the reputations of NU and its subsidiaries, and may make state legislatures, utility commissions and other regulatory authorities less likely to view NU and its subsidiaries in a favorable light, and may cause NU and its subsidiaries to be subject to less favorable legislative and regulatory outcomes or increased regulatory oversight. Unfavorable regulatory outcomes can include more stringent laws and regulations governing our operations, such as reliability and customer service quality standards or vegetation management requirements, as well as fines, penalties or other sanctions or requirements. The imposition of any of the foregoing could have a material adverse effect on business, results of operations, cash flow and financial condition of NU and each of its utility subsidiaries.
The actions of regulators can significantly affect our earnings, liquidity and business activities.
The rates that our Regulated companies charge their respective retail and wholesale customers are determined by their state utility commissions and by FERC. These commissions also regulate the companies’ accounting, operations, the issuance of certain securities and certain other matters. FERC also regulates their transmission of electric energy, the sale of electric energy at wholesale, accounting, issuance of certain securities and certain other matters. The commissions’ policies and regulatory actions could have a material impact on the Regulated companies’ financial position, results of operations and cash flows.
Our transmission, distribution and generation systems may not operate as expected, and could require unplanned expenditures, which could adversely affect our financial position, results of operations and cash flows.
Our ability to properly operate our transmission, distribution and generation systems is critical to the financial performance of our business. Our transmission, distribution and generation businesses face several operational risks, including the breakdown or failure of or damage to equipment or processes (especially due to age); labor disputes; disruptions in the delivery of electricity and natural gas, including impacts on us or our customers; increased capital expenditure requirements, including those due to environmental regulation; information security risk, such as a breach of our systems on which sensitive utility customer data and account information are stored; catastrophic events such as fires, explosions, or other similar occurrences; extreme weather conditions beyond equipment and plant design capacity; other unanticipated operations and maintenance expenses and liabilities; and potential claims for property damage or personal injuries beyond the scope of our insurance coverage. The failure of our transmission, distribution and generation systems to operate as planned may result in increased capital costs, reduced earnings or unplanned increases in operation and maintenance costs. At PSNH, outages at generating stations may be deemed imprudent by the NHPUC resulting in disallowance of replacement power costs. Such costs that are not recoverable from our customers would have an adverse effect on our financial position, results of operations and cash flows.
Limits on our access to and increases in the cost of capital may adversely impact our ability to execute our business plan.
We use short-term debt and the long-term capital markets as a significant source of liquidity and funding for capital requirements not obtained from our operating cash flow. If access to these sources of liquidity becomes constrained, our ability to implement our business strategy could be adversely affected. In addition, higher interest rates would increase our cost of borrowing, which could adversely impact our results of operations. A downgrade of our credit ratings or events beyond our control, such as a disruption in global capital and credit markets, could increase our cost of borrowing and cost of capital or restrict our ability to access the capital markets and negatively affect our ability to maintain and to expand our businesses.
Our counterparties may not meet their obligations to us or may elect to exercise their termination rights, which could adversely affect our earnings.
We are exposed to the risk that counterparties to various arrangements who owe us money, have contracted to supply us with energy, coal, or other commodities or services, or who work with us as strategic partners, including on significant capital projects, will not be able to perform their obligations, will terminate such arrangements or, with respect to our credit facilities, fail to honor their commitments. Should any of these counterparties fail to perform their obligations or terminate such arrangements, we might be forced to replace the underlying commitment at higher market prices and/or have to delay the completion of, or cancel a capital project. Should any lenders under our credit facilities fail to perform, the level of borrowing capacity under those arrangements could decrease. In any such events, our financial position, results of operations, or cash flows could be adversely affected.
Difficulties in obtaining necessary rights of way, or siting, design or other approvals for major transmission projects, environmental concerns or actions of regulatory authorities, communities or strategic partners may cause delays or cancellation of such projects, which would adversely affect our earnings.
Various factors could result in increased costs or result in delays or cancellation of our transmission projects. These include the regulatory approval process, environmental and community concerns, design and siting issues, difficulties in obtaining required rights of way and actions of strategic partners. Should any of these factors result in such delays or cancellations, our financial position, results of operations, and cash flows could be adversely affected.
Economic events or factors, changes in regulatory or legislative policy and/or regulatory decisions or construction of new generation may delay completion of or displace or result in the abandonment of our planned transmission projects or adversely affect our ability to recover our investments or result in lower than expected earnings.
Our transmission construction plans could be adversely affected by economic events or factors, new legislation, regulations, or judicial or regulatory interpretations of applicable law or regulations or regulatory decisions. Any of such events could cause delays in, or the inability to complete or abandonment of, economic or reliability related projects, which could adversely affect our ability to achieve forecasted earnings or to recover our investments or result in lower than expected rates of return. Recoverability of all such investments in rates may be subject to prudence review at the FERC. While we believe that all of such costs have been and will be prudently incurred, we cannot predict the outcome of future reviews should they occur.
In addition, our transmission projects may be delayed or displaced by new generation facilities, which could result in reduced transmission capital investments, reduced earnings, and limited future growth prospects.
Many of our transmission projects are expected to help alleviate identified reliability issues and reduce customers' costs. However, if, due to economic events or factors or further regulatory or other delays, the in-service date for one or more of these projects is delayed, there may be increased risk of failures in the electricity transmission system and supply interruptions or blackouts, which could have an adverse effect on our earnings.
The 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. Our projected earnings and growth could be adversely affected were FERC to reduce these incentives in the future below the levels presently anticipated.
Increases in electric and gas prices and/or a weak economy, can lead to changes in legislative and regulatory policy promoting energy efficiency, conservation, and self-generation and/or a reduction in our customers’ ability to pay their bills, which may adversely impact our business.
Energy consumption is significantly impacted by the general level of economic activity and cost of energy supply. Economic downturns or periods of high energy supply costs typically can lead to the development of legislative and regulatory policy designed to promote reductions in energy consumption and increased energy efficiency and self-generation by customers. This focus on conservation, energy efficiency and self-generation may result in a decline in electricity and gas sales in our service territories. If any such declines were to occur without corresponding adjustments in rates, then our revenues would be reduced and our future growth prospects would be limited.
In addition, a period of prolonged economic weakness could impact customers’ ability to pay bills in a timely manner and increase customer bankruptcies, which may lead to increased bad debt expenses or other adverse effects on our financial position, results of operations or cash flows.
Changes in regulatory and/or legislative policy could negatively impact our transmission planning and cost allocation rules.
The existing FERC-approved New England transmission tariff allocates the costs of transmission facilities that provide regional benefits to all customers of participating transmission-owning utilities. As new investment in regional transmission infrastructure occurs in any one state, its cost is shared across New England in accordance with a FERC approved formula found in the transmission tariff. All New England transmission owners' agreement to this regional cost allocation is set forth in the Transmission Operating Agreement. This agreement can be modified with the approval of a majority of the transmission owning utilities and approval by FERC. In addition, other parties, such as state regulators, may seek certain changes to the regional cost allocation formula, which could have adverse effects on the rates our distribution companies charge their retail customers.
FERC has issued rules requiring all regional transmission organizations and transmission owning utilities to make compliance changes to their tariffs and contracts in order to further encourage the construction of transmission for generation, including renewable generation. This compliance will require ISO-NE and New England transmission owners to develop methodologies that allow for regional planning and cost allocation for transmission projects chosen in the regional plan that are designed to meet public policy goals such as reducing greenhouse gas emissions or encouraging renewable generation. Such compliance may also allow non-incumbent utilities and other entities to participate in the planning and construction of new projects in our service area and regionally.
Changes in the Transmission Operating Agreement, the New England Transmission Tariff or legislative policy, or implementation of these new FERC planning rules, could adversely affect our transmission planning, our earnings and our prospects for growth.
Changes in regulatory or legislative policy or unfavorable outcomes in regulatory proceedings could jeopardize our full and/or timely recovery of costs incurred by our regulated distribution and generation businesses.
Under state law, our Regulated companies are entitled to charge rates that are sufficient to allow them an opportunity to recover their reasonable operating and capital costs, to attract needed capital and maintain their financial integrity, while also protecting relevant public interests. Each of these companies prepares and submits periodic rate filings with their respective state regulatory commissions for review and approval. There is no assurance that these state commissions will approve the recovery of all such costs incurred by our Regulated companies, such as for construction, operation and maintenance, as well as a return on investment on their respective regulated assets, including the construction costs incurred by PSNH for the Clean Air Project at its Merrimack Station. PSNH’s expenditures for the project are subject to prudence review by the NHPUC. The amount of costs incurred by the Regulated companies, coupled with increases in fuel and energy prices, could lead to consumer or regulatory resistance to the timely recovery of such costs, thereby adversely affecting our financial position, results of operations or cash flows.
Additionally, state legislators may enact laws that significantly impact our Regulated companies’ revenues, including by mandating electric or gas rate relief and/or by requiring surcharges to customer bills to support state programs not related to the utilities or energy policy. Such increases could pressure overall rates to our customers and our routine requests to regulators for rate relief.
In addition, CL&P, NSTAR Electric and WMECO procure energy for a substantial portion of their customers’ needs via requests for proposal on an annual, semi-annual or quarterly basis. CL&P, NSTAR Electric and WMECO receive approval to recover the costs of these contracts from the PURA and DPU, respectively. While both regulatory agencies have consistently approved the solicitation processes, results and recovery of costs, management cannot predict the outcome of future solicitation efforts or the regulatory proceedings related thereto.
PSNH meets most of its energy requirements through its own generation resources and fixed-price forward purchase contracts. PSNH’s remaining energy needs are met primarily through spot market 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 energy to meet its requirements. PSNH recovers these costs through its ES rate, subject to a prudence review by the NHPUC. We cannot predict the outcome of future regulatory proceedings related to recovery of these costs.
Migration of customers from PSNH energy service to competitive energy suppliers may increase the cost to the remaining customers of energy produced by PSNH generation assets.
The competitiveness of PSNH’s ES rates are sensitive to the cost of fuels, most notably natural gas, and customer load. Recently, PSNH’s ES rate has been higher than competitive energy prices offered to some customers. Further increases may occur as the costs associated with the Clean Air Project are fully phased into rates. Customers remaining on PSNH’s ES rate may experience an increase in cost due to the lower base over which to recover PSNH's fixed generation costs. Any such increase may in turn cause further migration and further impact PSNH’s ES rate. This trend could lead to PSNH continuing to lose retail customers and increasing the burden of supporting the cost of its generation facilities on remaining customers and being unable to support the cost of its generation facilities through an ES rate.
Judicial or regulatory proceedings or changes in regulatory or legislative policy could jeopardize full recovery of costs incurred by PSNH in constructing the Clean Air Project.
Pursuant to New Hampshire law, PSNH placed the Clean Air Project in service at its Merrimack Station in Bow, New Hampshire. PSNH’s recovery of costs in constructing the project is subject to prudence review by the NHPUC. A material prudence disallowance could adversely affect PSNH’s financial position, results of operations or cash flows. While we believe we have prudently incurred all expenditures to date, we cannot predict the outcome of any prudence reviews. Our projected earnings and growth could be adversely affected were the NHPUC to deny recovery of some or all of PSNH’s investment in the project.
The loss of key personnel or the inability to hire and retain qualified employees could have an adverse effect on our business, financial position and results of operations.
Our operations depend on the continued efforts of our employees. Retaining key employees and maintaining the ability to attract new employees are important to both our operational and financial performance. We cannot guarantee that any member of our management or any key employee at the NU parent or subsidiary level will continue to serve in any capacity for any particular period of time. In addition, a significant portion of our workforce, including many workers with specialized skills maintaining and servicing the electrical infrastructure, will be eligible to retire over the next five to ten years. Such highly skilled individuals cannot be quickly replaced due to the technically complex work they perform. We have developed strategic workforce plans to identify key functions and proactively implement plans to assure a ready and qualified workforce, but cannot predict the impact of these plans on our ability to hire and retain key employees.
Market performance or changes in assumptions require us to make significant contributions to our pension and other post-employment benefit plans.
We provide a defined benefit pension plan and other post-retirement benefits for a substantial number of employees, former employees and retirees. Our future pension obligations, costs and liabilities are highly dependent on a variety of factors beyond our control. These factors include estimated investment returns, interest rates, discount rates, health care cost trends, benefit changes, salary increases and the demographics of plan participants. If our assumptions prove to be inaccurate, our future costs could increase significantly. In 2008 and 2009, due to the financial crisis, the value of our pension assets declined. As a result, we made a contribution of approximately $222 million in 2012 and expect to make an approximate $285 million contribution in 2013. In addition, various factors, including underperformance of plan investments and changes in law or regulation, could increase the amount of contributions required to fund our pension plan in the future. Additional large funding requirements, when combined with the financing requirements of our construction program, could impact the timing and amount of future equity and debt financings and negatively affect our financial position, results of operations or cash flows.
Costs of compliance with environmental regulations, including climate change legislation, may increase and have an adverse effect on our business and results of operations.
Our subsidiaries' operations are subject to extensive federal, state and local environmental statutes, rules and regulations that govern, among other things, air emissions, water discharges and the management of hazardous and solid waste. Compliance with these requirements requires us to incur significant costs relating to environmental monitoring, installation of pollution control equipment, emission fees, maintenance and upgrading of facilities, remediation and permitting. The costs of compliance with existing legal requirements or legal requirements not yet adopted may increase in the future. An increase in such costs, unless promptly recovered, could have an adverse impact on our business and our financial position, results of operations or cash flows.
In addition, global climate change issues have received an increased focus from federal and state governments, which could potentially lead to additional rules and regulations that impact how we operate our business, both in terms of the power plants we own and operate as well as general utility operations. Although we would expect that any costs of these rules and regulations would be recovered from customers, their impact on energy use by customers and the ultimate impact on our business would be dependent upon the specific rules and regulations adopted and cannot be determined at this time. The impact of these additional costs to customers could lead to a further reduction in energy consumption resulting in a decline in electricity and gas sales in our service territories, which would have an adverse impact on our business and financial position, results of operations or cash flows.
Any failure by us to comply with environmental laws and regulations, even if due to factors beyond our control, or reinterpretations of existing requirements, could also increase costs. Existing environmental laws and regulations may be revised or new laws and regulations seeking to protect the environment may be adopted or become applicable to us. Revised or additional laws could result in significant additional expense and operating restrictions on our facilities or increased compliance costs, which may not be fully recoverable in distribution company rates. The cost impact of any such laws, rules or regulations would be dependent upon the specific requirements adopted and cannot be determined at this time. For further information, see Item 1, Business - Other Regulatory and Environmental Matters, included in this Annual Report on Form 10-K.
As a holding company with no revenue-generating operations, NU parent’s liquidity is dependent on dividends from its subsidiaries, primarily the Regulated companies, its commercial paper program, and its ability to access the long-term debt and equity capital markets.
NU parent is a holding company and as such, has no revenue-generating operations of its own. Its ability to meet its debt service obligations and to pay dividends on its common shares is largely dependent on the ability of its subsidiaries to pay dividends to or repay borrowings from NU parent, and/or NU parent’s ability to access its commercial paper program or the long-term debt and equity capital markets. Prior to funding NU parent, the Regulated companies have financial obligations that must be satisfied, including among others, their operating expenses, debt service, preferred dividends (in the case of CL&P and NSTAR Electric), and obligations to trade creditors. Additionally, the Regulated companies could retain their free cash flow to fund their capital expenditures in lieu of receiving equity contributions from NU parent. Should the Regulated companies not be able to pay dividends or repay funds due to NU parent, or if NU parent cannot access its commercial paper programs or the long-term debt and equity capital markets, NU parent’s ability to pay interest, dividends and its own debt obligations would be restricted.
Item 1B.
Item 1B.
Unresolved Staff Comments
We do not have any unresolved SEC staff comments.
Electric Generating Plants
As of December 31, 2012, PSNH owned the following electric generating plants:
*
Claimed capability represents winter ratings as of December 31, 2012. The combined nameplate capacity of the generating plants is approximately 1,200 MW.
As of December 31, 2012, WMECO owned the following electric generating plant:
** Claimed capability represents the direct current nameplate capacity of the plant.
CL&P did not own any electric generating plants during 2012.
Natural Gas Distribution System
As of December 31, 2012, Yankee Gas owned 28 active gate stations, 203 district regulator stations, and 3,265 miles of natural gas main pipeline. Yankee Gas also owns a 1.2 Bcf LNG facility in Waterbury, Connecticut.
As of December 31, 2012, NSTAR Gas owned 21 active gate stations, 145 district regulator stations, and 3,185 miles of natural gas main pipeline. NSTAR Gas and Hopkinton own a satellite vaporization plant and above ground cryogenic storage tanks. In addition, Hopkinton owns a liquefaction and vaporization plant. Combined, the tanks have an aggregate storage capacity equivalent to 3.5 Bcf of natural gas.
Franchises
CL&P. Subject to the power of alteration, amendment or repeal by the General Assembly of Connecticut and subject to certain approvals, permits and consents of public authority and others prescribed by statute, CL&P has, subject to certain exceptions not deemed material, valid franchises free from burdensome restrictions to provide electric transmission and distribution services in the respective areas in which it is now supplying such service.
In addition to the right to provide electric transmission and distribution services as set forth above, the franchises of CL&P include, among others, limited rights and powers, as set forth under Connecticut law and the special acts of the General Assembly constituting its charter, to manufacture, generate, purchase and/or sell electricity at retail, including to provide Standard Service, Supplier of Last Resort service and backup service, to sell electricity at wholesale and to erect and maintain certain facilities on public highways and grounds, all subject to such consents and approvals of public authority and others as may be required by law. The franchises of CL&P include the power of eminent domain. Connecticut law prohibits an electric distribution company from owning or operating generation assets. However, under "An Act Concerning Energy Independence," enacted in 2005, CL&P is permitted to own up to 200 MW of peaking facilities if the PURA determines that such facilities will be more cost effective than other options for mitigating FMCC and Locational Installed Capacity (LICAP) costs. In addition, under "An Act Concerning Electricity and Energy Efficiency," enacted in 2007, an electric distribution company, such as CL&P, is permitted to purchase an existing electric generating plant located in Connecticut that is offered for sale, subject to prior approval from the PURA and a determination by the PURA that such purchase is in the public interest. Finally, Connecticut law also allows CL&P to submit a proposal to the DEEP to build, own or operate one or more generation facilities up to 10 MWs using Class 1 renewable energy.
NSTAR ELECTRIC AND NSTAR GAS. Through their charters, which are unlimited in time, NSTAR Electric and NSTAR Gas have the right to engage in the business of delivering and selling electricity and natural gas within their respective service territories, and have powers incidental thereto and are entitled to all the rights and privileges of and subject to the duties imposed upon electric and natural gas companies under Massachusetts laws. The locations in public ways for electric transmission and distribution lines and gas distribution pipelines are obtained from municipal and other state authorities who, in granting these locations, act as agents for the state. In some cases the actions of these authorities are subject to appeal to the DPU. The rights to these locations are not limited in time and are subject to the action of these authorities and the legislature. Under Massachusetts law, with the exception of municipal-owned utilities, no other entity may provide electric or gas delivery service to retail customers within NSTAR’s service territory without the written consent of NSTAR Electric and/or NSTAR Gas. This consent must be filed with the DPU and the municipality so affected.
The Massachusetts restructuring legislation defines service territories as those territories actually served on July 1, 1997 and following municipal boundaries to the extent possible. The restructuring legislation further provides that until terminated by law or otherwise, distribution companies shall have the exclusive obligation to serve all retail customers within their service territories and no other person shall provide distribution service within such service territories without the written consent of such distribution companies. Pursuant to the Massachusetts restructuring legislation, the DPU (then, the Department of Telecommunications and Energy) was required to define service territories for each distribution company, including NSTAR Electric. The DPU subsequently determined that there were advantages to the exclusivity of service territories and issued a report to the Massachusetts Legislature recommending against, in this regard, any changes to the restructuring legislation.
PSNH. The NHPUC, pursuant to statutory requirements, has issued orders granting PSNH exclusive franchises to distribute electricity in the respective areas in which it is now supplying such service.
In addition to the right to distribute electricity as set forth above, the franchises of PSNH include, among others, rights and powers to manufacture, generate, purchase, and transmit electricity, to sell electricity at wholesale to other utility companies and municipalities and to erect and maintain certain facilities on certain public highways and grounds, all subject to such consents and approvals of public authority and others as may be required by law. PSNH’s status as a public utility gives it the ability to petition the NHPUC for the right to exercise eminent domain for its transmission and distribution services in appropriate circumstances.
PSNH is also subject to certain regulatory oversight by the Maine Public Utilities Commission and the Vermont Public Service Board.
WMECO. WMECO is authorized by its charter to conduct its electric business in the territories served by it, and has locations in the public highways for transmission and distribution lines. Such locations are granted pursuant to the laws of Massachusetts by the Department of Public Works of Massachusetts or local municipal authorities and are of unlimited duration, but the rights thereby granted are not vested. Such locations are for specific lines only and for extensions of lines in public highways. Further similar locations must
be obtained from the Department of Public Works of Massachusetts or the local municipal authorities. In addition, WMECO has been granted easements for its lines in the Massachusetts Turnpike by the Massachusetts Turnpike Authority and pursuant to state laws, has the power of eminent domain.
The Massachusetts restructuring legislation applicable to NSTAR Electric (described above) is also applicable to WMECO.
Yankee Gas. Yankee Gas holds valid franchises to sell gas in the areas in which Yankee Gas supplies gas service, which it acquired either directly or from its predecessors in interest. Generally, Yankee Gas holds franchises to serve customers in areas designated by those franchises as well as in most other areas throughout Connecticut so long as those areas are not occupied and served by another 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 PURA and certain approvals, permits and consents of public authorities and others prescribed by statute. Generally, Yankee Gas’ franchises include, among other rights and powers, the right and power to manufacture, generate, purchase, transmit and distribute 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.
Yankee Companies v. U.S. Department of Energy
In 1998, the Yankee Companies (CYAPC, YAEC and MYAPC) filed separate complaints against the DOE in the Court of Federal Claims seeking monetary damages resulting from the DOE's failure to begin accepting spent nuclear fuel for disposal by January 31, 1998 pursuant to the terms of the 1983 spent fuel and high level waste disposal contracts between the Yankee Companies and the DOE (DOE Phase I Damages). 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.
In December 2006, the DOE appealed the ruling, and the Yankee Companies filed cross-appeals. The Court of Appeals issued its decision on August 7, 2008, effectively agreeing with the trial court's findings as to the liability of the DOE but disagreeing with the method that the trial court used to calculate damages. The Court of Appeals vacated the decision and remanded the case for new findings consistent with its decision.
On September 7, 2010, the trial court issued its decision following remand, and judgment on the decision was entered on September 9, 2010. The judgment awarded CYAPC $39.7 million, YAEC $21.2 million and MYAPC $81.7 million. The DOE filed an appeal and the Yankee Companies cross-appealed on November 8, 2010. Briefs were filed and oral arguments in the appeal of the remanded case occurred on November 7, 2011. On May 18, 2012, the U.S. Court of Appeals for the Federal Circuit issued a unanimous panel decision in favor of the Yankee Companies upholding the trial court's awards to each company in the remanded cases, and increasing YAEC damages by approximately $17 million to cover certain wet pool operating expenses. On August 1, 2012, the DOE filed a petition asking the U.S. Court of Appeals for the Federal Circuit to reconsider its unanimous panel decision in favor of the Yankee Companies upholding the trial court's awards to each company in the remanded cases. On September 5, 2012, the U.S. Court of Appeals for the Federal Circuit denied the DOE’s petition. The decisions became final and non-appealable and interest on the judgments began to accrue on or about December 5, 2012, as the DOE elected not to file a petition for certiorari with the U.S. Supreme Court. In late January 2013, the proceeds from the DOE Phase 1 Damages claim were received by CYAPC, in the amount of $39.6 million; YAEC, in the amount of $38.3 million; and MYAPC, in the amount of $81.7 million. The funds were transferred to each Yankee Company’s respective decommissioning trust. The final application of the proceeds for the benefit of customers of CL&P, NSTAR Electric, PSNH and WMECO will be determined following rate proceedings to be filed by the Yankee Companies at FERC in the second quarter of 2013. Final FERC determinations are expected by the end of the third quarter of 2013.
In December 2007, the Yankee Companies each filed subsequent lawsuits against the DOE seeking recovery of actual damages incurred in the years following 2001 and 2002 related to the alleged failure of the DOE to provide for a permanent facility to store spent nuclear fuel generated in years after 2001 for CYAPC and YAEC and after 2002 for MYAPC (DOE Phase II Damages). On November 18, 2011, the court ordered the record closed in the YAEC case, and closed the record in the CYAPC and MYAPC cases subject to a limited opportunity of the government to reopen the records for further limited proceedings. The record is now closed, all post-trial briefing has been completed, and the case is awaiting the court decision.
The methodology for applying any DOE Phase II Damages that may be recovered from the DOE for the benefit of customers of CL&P, NSTAR Electric, PSNH and WMECO will be addressed in the same FERC rate proceedings.
2.
Conservation Law Foundation v. PSNH
On July 21, 2011, the Conservation Law Foundation (CLF) filed a citizens suit under the provisions of the federal Clean Air Act against PSNH alleging permitting violations at the company’s Merrimack generating station. The suit alleges that PSNH failed to have proper permits for replacement of the Unit 2 turbine at Merrimack, installation of activated carbon injection equipment for the unit, and violated a permit condition concerning operation of the electrostatic precipitators at the station. The suit seeks injunctive relief, civil penalties, and costs. CLF has pursued similar claims before the NHPUC, the N.H. Air Resources Council, and the N.H. Site Evaluation Committee, all of which have been denied. PSNH believes this suit is without merit and intends to defend it vigorously. On
September 27, 2012, the federal court dismissed portions of CLF’s suit pertaining to the installation of activated carbon injection and the electrostatic precipitators. An additional motion to dismiss the remaining counts is still pending.
3.
Other Legal Proceedings
For further discussion of legal proceedings, see Item 1, Business: "- Electric Distribution Segment," "- Natural Gas Distribution Segment" and "- Electric Transmission Segment," for information about various state regulatory and rate proceedings, civil lawsuits related thereto, and information about proceedings relating to power, transmission and pricing issues; "- Nuclear Decommissioning" for information related to high-level nuclear waste; and "- Other Regulatory and Environmental Matters" for information about proceedings involving surface water and air quality requirements, toxic substances and hazardous waste, electric and magnetic fields, licensing of hydroelectric projects, and other matters. In addition, see Item 1A, Risk Factors, for general information about several significant risks.
EXECUTIVE OFFICERS OF THE REGISTRANT
The following table sets forth the executive officers of NU as of February 15, 2013. All of the Company’s officers serve terms of one year and until their successors are elected and qualified:
Name
Age
Title
Jay S. Buth
Vice President, Controller and Chief Accounting Officer.
Gregory B. Butler
Senior Vice President, General Counsel and Secretary.
Christine M. Carmody*
Senior Vice President-Human Resources of NUSCO and NSTAR Electric & Gas.
James J. Judge
Executive Vice President and Chief Financial Officer.
Thomas J. May
President and Chief Executive Officer.
David R. McHale
Executive Vice President and Chief Administrative Officer.
Joseph R. Nolan, Jr.*
Senior Vice President-Corporate Relations of NUSCO and NSTAR Electric & Gas.
Leon J. Olivier
Executive Vice President and Chief Operating Officer.
* Deemed an executive officer of NU pursuant to Rule 3b-7 under the Securities Exchange Act of 1934.
Jay S. Buth. Mr. Buth became Vice President, Controller and Chief Accounting Officer of NU, CL&P, NSTAR Electric, NSTAR Gas, PSNH, WMECO, Yankee Gas, NUSCO and NSTAR Electric & Gas upon completion of the Merger. Previously, Mr. Buth was Vice President-Accounting and Controller of NU, CL&P, PSNH, WMECO, Yankee Gas and NUSCO from June 2009 through the completion of the Merger. From June 2006 through January 2009, Mr. Buth was the Vice President and Controller for New Jersey Resources Corporation, an energy services holding company that provides natural gas and wholesale energy services, including transportation, distribution and asset management.
Gregory B. Butler. Mr. Butler became Senior Vice President, General Counsel and Secretary of NU and Senior Vice President and General Counsel of NSTAR Electric, NSTAR Gas and NSTAR Electric & Gas upon completion of the Merger. He has served as Senior Vice President and General Counsel of CL&P, PSNH, WMECO, Yankee Gas and NUSCO since March 9, 2006. Mr. Butler was elected a Director of NSTAR Electric, NSTAR Gas and NSTAR Electric & Gas upon completion of the Merger. He has served as a Director of NUSCO since November 27, 2012, and of CL&P, PSNH, WMECO and Yankee Gas since April 22, 2009. Previously Mr. Butler served as Senior Vice President and General Counsel of NU from December 1, 2005 to April 2012. Mr. Butler became a Trustee of the NSTAR Foundation effective upon completion of the Merger. He has served as a Director of Northeast Utilities Foundation, Inc. since December 1, 2002.
Christine M. Carmody. Ms. Carmody became Senior Vice President-Human Resources of NUSCO upon completion of the Merger and of CL&P, PSNH, WMECO and Yankee Gas effective November 27, 2012. She has served as Senior Vice President-Human Resources of NSTAR Electric, NSTAR Gas and NSTAR Electric & Gas since August 1, 2008. Ms. Carmody was elected a Director of CL&P, PSNH, WMECO and Yankee Gas upon completion of the Merger, and of NSTAR Electric, NSTAR Gas, NUSCO and NSTAR Electric & Gas effective November 27, 2012. Previously, Ms. Carmody served as Vice President-Organizational Effectiveness of NSTAR, NSTAR Electric, NSTAR Gas and NSTAR Electric & Gas from June 2006 to August 2008. Ms. Carmody became a Director of Northeast Utilities Foundation, Inc. effective upon completion of the Merger. She has served as a Trustee of the NSTAR Foundation since August 1, 2008.
James J. Judge. Mr. Judge became Executive Vice President and Chief Financial Officer of NU, CL&P, NSTAR Electric, NSTAR Gas, PSNH, WMECO, Yankee Gas, NUSCO and NSTAR Electric & Gas upon completion of the Merger. Mr. Judge was elected a Director of CL&P, PSNH, WMECO, Yankee Gas and NUSCO upon completion of the Merger. He has served as a Director of NSTAR Electric, NSTAR Gas and NSTAR Electric & Gas since September 27, 1999. Previously, Mr. Judge served as Senior Vice President and Chief Financial Officer of NSTAR, NSTAR Electric, NSTAR Gas and NSTAR Electric & Gas from 1999 until April 2012. Mr. Judge became Treasurer and a Director of Northeast Utilities Foundation, Inc. effective upon completion of the Merger. He has served as a Trustee of the NSTAR Foundation since December 12, 1995.
Thomas J. May. Mr. May became President and Chief Executive Officer and a Trustee of NU, Chairman and a Director of CL&P, NSTAR Electric, NSTAR Gas, PSNH, WMECO and Yankee Gas, and Chairman, President and Chief Executive Officer and a Director
of NUSCO upon completion of the Merger. He has been President and Chief Executive Officer of NSTAR Electric & Gas since January 1, 2002. Mr. May has served as a Director of NSTAR Electric, NSTAR Gas and NSTAR Electric & Gas (or their predecessor companies) since September 27, 1999. Previously, Mr. May served as Chairman, President and Chief Executive Officer and a Trustee of NSTAR, and as Chairman, President and Chief Executive Officer of NSTAR Electric, NSTAR Gas and NSTAR Electric & Gas until the closing of the Merger. He served as Chairman, Chief Executive Officer and a Trustee since NSTAR was formed in 1999, and was elected President in 2002. Mr. May became a Director of Northeast Utilities Foundation, Inc. upon completion of the Merger. He has served as a Trustee of the NSTAR Foundation since August 18, 1987.
David R. McHale. Mr. McHale became Executive Vice President and Chief Administrative Officer of NU, CL&P, NSTAR Electric, NSTAR Gas, PSNH, WMECO, Yankee Gas, NUSCO and NSTAR Electric & Gas upon completion of the Merger. Mr. McHale has served as a Director of NSTAR Electric, NSTAR Gas and NSTAR Electric & Gas since November 27, 2012, of PSNH, WMECO, Yankee Gas and NUSCO since January 1, 2005, and of CL&P since January 15, 2007. Previously, Mr. McHale served as Executive Vice President and Chief Financial Officer of NU, CL&P, PSNH, WMECO, Yankee Gas and NUSCO from January 2009 to April 2012, and Senior Vice President and Chief Financial Officer of NU, CL&P, PSNH, WMECO, Yankee Gas and NUSCO from January 2005 to December 2008. Mr. McHale became a Trustee of the NSTAR Foundation upon completion of the Merger. He has served as a Director of Northeast Utilities Foundation, Inc. since January 1, 2005.
Joseph R. Nolan, Jr. Mr. Nolan became Senior Vice President-Corporate Relations of NUSCO, NSTAR Electric & Gas, NSTAR Electric and NSTAR Gas upon completion of the Merger. He became Senior Vice President-Corporate Relations of CL&P, PSNH, WMECO and Yankee Gas effective November 27, 2012. Mr. Nolan was elected a Director of CL&P, PSNH, WMECO and Yankee Gas upon completion of the Merger, and of NSTAR Electric, NSTAR Gas, NUSCO and NSTAR Electric & Gas effective November 27, 2012. Previously, Mr. Nolan served as Senior Vice President-Customer & Corporate Relations of NSTAR, NSTAR Electric, NSTAR Gas and NSTAR Electric and Gas from 2006 until the closing of the Merger. Mr. Nolan became a Director of Northeast Utilities Foundation, Inc. upon completion of the Merger. He has served as a Trustee of the NSTAR Foundation since October 1, 2000.
Leon J. Olivier. Mr. Olivier has served as Executive Vice President and Chief Operating Officer of NU and NUSCO since May 13, 2008, and of NSTAR Electric & Gas since the completion of the Merger. He became Chief Executive Officer of NSTAR Electric and NSTAR Gas upon completion of the Merger. Mr. Olivier has served as Chief Executive Officer of CL&P, PSNH, WMECO and Yankee Gas since January 15, 2007. Mr. Olivier was elected a Director of NSTAR Electric, NSTAR Gas and NSTAR Electric & Gas effective November 27, 2012, of PSNH, WMECO and Yankee Gas effective January 17, 2005, and of CL&P effective September 10, 2001. Previously, Mr. Olivier served as Executive Vice President-Operations of NU from February 13, 2007 to May 12, 2008. Mr. Olivier became a Trustee of the NSTAR Foundation upon completion of the Merger. He has served as a Director of Northeast Utilities Foundation, Inc. since April 1, 2006.
Item 4.
Item 4.
Mine Safety Disclosures
Not applicable.
PART II
Item 5.
Item 5.
Market for the Registrants' Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities
(a)
Market Information and (c) Dividends
NU. Our common shares are listed on the New York Stock Exchange. The ticker symbol is "NU," although it is frequently presented as "Noeast Util" and/or "NE Util" in various financial publications. The high and low sales prices of our common shares and the dividends declared, for the past two years, by quarter, are shown below.
Information with respect to dividend restrictions for us, CL&P, NSTAR Electric, PSNH, and WMECO is contained in Item 7, Management's Discussion and Analysis of Financial Condition and Results of Operations, under the caption "Liquidity" and Item 8, Financial Statements and Supplementary Data, in the Combined Notes to Consolidated Financial Statements, within this Annual Report on Form 10-K.
There is no established public trading market for the common stock of CL&P, NSTAR Electric, PSNH and WMECO. All of the common stock of CL&P, NSTAR Electric, PSNH and WMECO is held solely by NU.
During 2012 and 2011, CL&P approved and paid $100.5 million and $243.2 million, respectively, of common stock dividends to NU.
Since April 10, 2012, NSTAR Electric approved and paid $159.9 million of common stock dividends to NSTAR LLC.
During 2012 and 2011, PSNH approved and paid $90.7 million and $58.8 million, respectively, of common stock dividends to NU.
During 2012 and 2011, WMECO approved and paid $9.4 million and $26.3 million, respectively, of common stock dividends to NU.
(b)
Holders
As of January 31, 2013, there were 49,487 registered common shareholders of our company on record. As of the same date, there were a total of 332,767,098 common shares issued.
(c)
Securities Authorized for Issuance Under Equity Compensation Plans
For information regarding securities authorized for issuance under equity compensation plans, see Item 12, Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters, included in this Annual Report on Form 10-K.
(d)
Performance Graph
As allowed under Exchange Act Rule 14c-3 (17 CFR 240.14c-3), we provide the five-year cumulative performance graph annually, accompanying our Definitive Proxy Statement pursuant to section 14(a) of the Securities Exchange Act of 1934.
(e)
Purchases of Equity Securities by the Issuer and Affiliated Purchasers
The following table discloses purchases of shares of our common stock made by us or on our behalf for the periods shown below.
Period
Total Number
of Shares
Purchased
Average Price Paid per Share
Total Number of Shares Purchased as Part of Publicly Announced
Plans or Programs
Approximate Dollar
Value of Shares that
May Yet Be Purchased
Under the Plans and
Programs (at month end)
October 1 - October 31, 2012
714,846
$
39.53
-
-
November 1 - November 30, 2012
21,159
38.48
-
-
December 1 - December 31, 2012
258,263
38.98
-
-
Total
994,268
$
39.37
-
-
Item 7.
Item 7.
Management’s Discussion and Analysis of Financial Condition and Results of Operations
The following discussion and analysis should be read in conjunction with our consolidated financial statements and related combined notes included in this Annual Report on Form 10-K. References in this Annual Report to "NU," the "Company," "we," "us" and "our" refer to Northeast Utilities and its subsidiaries. All per share amounts are reported on a diluted basis.
Refer to the Glossary of Terms included in this Annual Report on Form 10-K for abbreviations and acronyms used throughout this Management's Discussion and Analysis of Financial Condition and Results of Operations.
The only common equity securities that are publicly traded are common shares of NU. The earnings and EPS of each business discussed below do not represent a direct legal interest in the assets and liabilities allocated to such business but rather represent a direct interest in our assets and liabilities as a whole. EPS by business is a financial measure not recognized under GAAP that is calculated by dividing the Net Income Attributable to Controlling Interest of each business by the weighted average diluted NU common shares outstanding for the period. The discussion below also includes non-GAAP financial measures referencing our 2012, 2011, and 2010 earnings and EPS excluding certain impacts related to NU's merger with NSTAR, a 2011 non-recurring charge at CL&P for the establishment of a reserve to provide bill credits to its residential customers and donations to charitable organizations, and certain non-recurring benefits from the settlement of tax issues in 2010. We use these non-GAAP financial measures to evaluate and to provide details of earnings results by business and to more fully compare and explain our 2012, 2011 and 2010 results without including the impact of these non-recurring items. Due to the nature and significance of these items on Net Income Attributable to Controlling Interest, we believe that the non-GAAP presentation is more representative of our financial performance and provides additional and useful information to readers of this report in analyzing historical and future performance by business. These non-GAAP financial measures should not be considered as an alternative to reported Net Income Attributable to Controlling Interest or EPS determined in accordance with GAAP as an indicator of operating performance.
Reconciliations of the above non-GAAP financial measures to the most directly comparable GAAP measures of consolidated diluted EPS and Net Income Attributable to Controlling Interest are included under "Financial Condition and Business Analysis - Overview - Consolidated" in Management's Discussion and Analysis, herein.
Financial Condition and Business Analysis
Merger with NSTAR:
On April 10, 2012, NU and NSTAR completed our merger. Pursuant to the terms and conditions of the Agreement and Plan of Merger, as amended (the Merger Agreement), NSTAR merged into NSTAR LLC, becoming a wholly-owned subsidiary of NU. Unless otherwise noted, the results of NSTAR LLC and its subsidiaries, hereinafter referred to as "NSTAR," are included from the date of merger, April 10, 2012, through December 31, 2012 throughout this Management's Discussion and Analysis of Financial Condition and Results of Operations.
The transaction was structured as a merger of equals in a tax-free exchange of shares. Pursuant to the Merger Agreement, NU issued to NSTAR shareholders 1.312 NU common shares for each issued and outstanding NSTAR common share. As a result, NU issued approximately 136 million common shares to the NSTAR shareholders.
Executive Summary
The following items in this executive summary are explained in more detail in this Annual Report:
Results and Outlook:
·
We earned $525.9 million, or $1.89 per share, in 2012, compared with $394.7 million, or $2.22 per share, in 2011. Excluding after-tax merger-related costs of $107.6 million, or $0.39 per share, we earned $633.5 million, or $2.28 per share, in 2012. Excluding after-tax merger-related costs of $11.3 million, or $0.06 per share, and a non-recurring charge at CL&P of $17.9 million, or $0.10 per share, we earned $423.9 million, or $2.38 per share, in 2011. The non-recurring 2011 charge at CL&P relates to the establishment of a reserve to provide bill credits to its residential customers and donations to charitable organizations (storm fund reserve). Improved earnings results in 2012 were due primarily to the inclusion of NSTAR effective April 10, 2012 as well as higher transmission segment earnings as a result of increased investments in the transmission infrastructure.
·
The addition of NSTAR effective April 10, 2012 provided an earnings contribution of $182.9 million in 2012. Due to the timing of the merger closing, NSTAR results for the first three months of 2012 are not reflected in NU’s 2012 results.
·
Our transmission segment earned $249.7 million, or $0.90 per share, in 2012, compared with $199.6 million, or $1.12 per share, in 2011.
·
Our electric distribution segment, which includes generation, earned $292.3 million, or $1.04 per share, in 2012, compared with $189.1 million, or $1.06 per share, in 2011. The 2012 results include $51.1 million, or $0.19 per share, of after-tax merger settlement agreement costs and the 2011 results include the CL&P storm fund reserve.
·
Our natural gas distribution segment earned $30.8 million, or $0.11 per share, in 2012, compared with $31.7 million, or $0.18 per share, in 2011. The 2012 results include $2.1 million, or $0.01 per share, of after-tax merger settlement agreement costs.
·
NU parent and other companies recorded net losses of $46.9 million, or $0.16 per share, in 2012, compared with net losses of $25.7 million, or $0.14 per share, in 2011. The 2012 and 2011 results include $54.4 million, or $0.19 per share, and $11.3 million, or $0.06 per share, respectively, of after-tax merger costs.
·
We project capital expenditures of approximately $5 billion from 2013 through 2015. Of the $5 billion, we expect to invest approximately $2.5 billion in our electric and natural gas distribution segments, and $2.3 billion in our electric transmission segment. In addition, we project capital expenditures of approximately $1.6 billion from 2016 through 2017 in our electric transmission segment.
Legislative, Regulatory, Policy and Other Items:
·
On June 15, 2012, Connecticut enacted the "Enhancing Emergency Preparedness and Response Act," which is intended to enhance the state’s emergency preparedness and response in the event of natural disasters. Among numerous provisions, the bill required the PURA to establish emergency performance standards for utilities and allows the PURA to levy penalties for failure to meet those standards.
·
On August 1, 2012, efforts to settle a complaint filed at FERC by various New England parties concerning the base ROE earned by New England transmission owners ended without a settlement. Soon thereafter, litigation began before a FERC trial judge. In the fourth quarter of 2012, additional testimony and complaints were filed. On January 18, 2013, the FERC trial staff filed testimony and analysis recommending a base ROE of 9.66 percent based on the midpoint of their analysis with a range of reasonableness of 6.82 percent to 12.51 percent. Hearings are scheduled for May 2013, a trial judge’s ruling is due in September 2013, and a FERC decision is expected in 2014.
·
On August 1, 2012, PURA issued a final decision in the investigation of CL&P’s performance related to both Tropical Storm Irene and the October 2011 snowstorm. The decision concluded that CL&P was deficient and inadequate in its preparation, response, and communication to both storms, and identified certain penalties that could be imposed on CL&P during its next rate case. However, PURA will consider and weigh the extent to which CL&P has taken steps to improve current practices in future storm response in determining any potential penalties. We believe such steps to improve current storm preparation and response practices have been successfully executed in recent storms, and that CL&P's response to these 2011 storms was prudent and consistent with industry standards, and that it is probable that it will be able to recover its deferred costs.
·
On August 3, 2012, Massachusetts Governor Patrick signed into law "An Act Relative to Competitively Priced Electricity in the Commonwealth." The Act establishes distribution rate case requirements for both electric and natural gas utility companies, as well as limiting settlement agreements, establishes new timing on rate case proceedings, and establishes requirements for all distribution companies to enter into additional long-term renewable energy distribution contracts.
·
On August 6, 2012, Massachusetts Governor Patrick signed into law "An Act relative to emergency service response of public utility companies" to help improve utility companies’ emergency response and communication, as well as indicate how any assessed penalties will be provided to customers.
·
On October 29, 2012, Hurricane Sandy caused extensive damage to our electric distribution system across all three states resulting in deferred storm restoration costs of $204 million. Approximately 1.5 million of our 3.1 million electric distribution customers were without power during or following the storm. We believe the storm restoration costs meet the criteria for specific cost recovery in each state in which we operate and, as a result, we do not expect the storm to have a material impact on our results of operations.
·
On December 11, 2012, in separate orders issued by the DPU, NSTAR Electric and WMECO received penalties of $4.1 million and $2 million, respectively, related to the investigation into the electric utilities’ responses to Tropical Storm Irene and the October 2011 snowstorm. The DPU stated that NSTAR Electric failed to communicate and prioritize restoration efforts in both storms and WMECO failed to prioritize restoration efforts in the October snowstorm. On December 28, 2012, NSTAR Electric and WMECO each filed appeals arguing the DPU penalties should be vacated. While we believe NSTAR Electric and WMECO should ultimately prevail upon appeal, we are unable to conclusively state that a favorable outcome is probable.
·
On January 16, 2013, PURA approved the $300 million plan CL&P filed on July 9, 2012 to improve the resiliency of the CL&P electric distribution system. The plan is consistent with the terms of the Connecticut settlement agreement among NU, NSTAR, and various Connecticut state agencies.
·
On February 8, 2013, a blizzard caused damage to the electric delivery systems of CL&P and NSTAR Electric. We have estimated that approximately 71,000 and 350,000 of CL&P and NSTAR Electric's distribution customers, respectively, were without power during or following the storm. We believe that this storm will cost between $100 million to $120 million, with approximately 90 percent of those costs relating to NSTAR Electric. We expect the storm restoration costs to meet the criteria for specific cost
recovery in each state in which we operate and, as a result, we do not expect the storm to have a material impact on our results of operations.
·
On February 19, 2013, Connecticut issued a final comprehensive energy strategy (strategy). The strategy includes a series of policy proposals that aim to expand energy choices, including natural gas, improve environmental conditions, create clean energy jobs, and enhance the quality of life for customers in the state. Many of the recommendations in the strategy will require actions by the PURA and potentially the legislature.
·
NPT has identified a new route in the northern-most part of the project’s route where PSNH did not own any rights of way. We expect to file the new route with the DOE in the first quarter of 2013, and we believe that NPT will be completed in early 2017. We estimate the costs of the Northern Pass transmission project will be approximately $1.2 billion.
Liquidity:
·
Cash and cash equivalents totaled $45.7 million as of December 31, 2012, compared with $6.6 million as of December 31, 2011, while cash capital expenditures totaled $1.5 billion in 2012, compared with $1.1 billion in 2011.
·
Cash flows provided by operating activities in 2012 totaled $1.05 billion, compared with operating cash flows of $901.1 million in 2011 (amounts are net of RRB payments). The improved cash flows were due primarily to the addition of NSTAR, which contributed $450.8 million of operating cash flows (net of RRB payments) to NU since the date of the merger, April 10, 2012. Offsetting the favorable NSTAR cash flow impact was an increase in storm restoration costs, NUSCO Pension Plan cash contributions, 2012 customer bill credits and NU Parent merger transaction cost payments.
·
In 2012, we issued $850 million of new long-term debt consisting of $400 million by NSTAR Electric, $300 million by NU Parent, and $150 million by WMECO. These new issuances were used primarily to repay $716.8 million of existing long-term debt, of which $663 million matured in 2012 ($400 million at NSTAR Electric and $263 million at NU Parent) and WMECO’s tax-exempt PCRBs of $53.8 million scheduled to mature in 2028. Additionally, CL&P remarketed $62 million of tax-exempt PCRBs in April 2012 and redeemed $116.4 million of tax-exempt PCRBs in October 2012. As of December 31, 2012, approximately $730 million of NU's current liabilities relate to long-term debt that will be paid in the next 12 months.
·
On March 26, 2012, CL&P entered into a five-year $300 million unsecured revolving credit facility. The credit facility is intended to finance short-term borrowings that CL&P incurred to fund costs of restoring power following Tropical Storm Irene and the October 2011 snowstorm. As of December 31, 2012, CL&P had $89 million in borrowings outstanding under this credit facility.
·
On July 25, 2012, NU and certain of its subsidiaries jointly entered into a five-year $1.15 billion revolving credit facility, and NSTAR Electric entered into a five-year $450 million revolving credit facility. The new facilities expire on July 25, 2017 and will be used primarily to backstop NU’s $1.15 billion commercial paper program and NSTAR Electric’s $450 million commercial paper program. As of December 31, 2012, NU and NSTAR Electric had $1.15 billion and $276 million in borrowings outstanding under their respective commercial paper programs.
·
On January 15, 2013, CL&P issued $400 million of 2.5 percent first mortgage bonds that will mature on January 15, 2023. The proceeds, net of issuance costs, were used to repay CL&P’s revolving credit facility borrowings of $89 million and $305.8 million of its commercial paper program borrowings.
·
On February 5, 2013, our Board of Trustees approved a common dividend payment of $0.3675 per share, payable March 28, 2013 to shareholders of record as of March 1, 2013. The dividend represented an increase of 7.1 percent over the $0.343 per share quarterly dividend paid in December 2012.
Overview
Consolidated: A summary of our earnings by business, which also reconciles the non-GAAP financial measures of consolidated non-GAAP earnings and EPS, as well as EPS by business, to the most directly comparable GAAP measures of consolidated Net Income Attributable to Controlling Interest and diluted EPS, for 2012, 2011 and 2010 is as follows:
(1)
Results include the operations of NSTAR from the date of merger, April 10, 2012, through December 31, 2012.
The after-tax merger and related costs for 2012 consisted of the following charges:
·
Transaction and integration-related costs of $34 million at NU parent related to investment advisory fees, attorney fees, and consulting costs;
·
Change in control costs and other compensation costs of $13.5 million at NU parent and NSTAR;
·
A $23.6 million charge at CL&P related to the Connecticut settlement agreement, pursuant to which CL&P agreed to forego recovery of $40 million (pre-tax) of deferred storm restoration costs associated with Tropical Storm Irene and the October 2011 snowstorm;
·
A $14.8 million charge at CL&P for customer bill credits related to the Connecticut settlement agreement;
·
An aggregate of $12.8 million of charges at NSTAR Electric, NSTAR Gas, and WMECO for customer bill credits related to the Massachusetts settlement agreement; and
·
An $8.9 million charge at NU parent for the establishment of a fund to advance Connecticut energy goals related to the Connecticut settlement agreement.
Excluding the impacts of the 2012 and 2011 merger and related settlement agreement costs and the 2011 storm fund reserve, our 2012 earnings increased by $209.6 million, as compared to 2011, due primarily to the inclusion of NSTAR effective April 10, 2012, and higher transmission segment earnings as a result of increased investments in the transmission infrastructure. On an earnings per share basis, the 2012 NSTAR earnings contribution of $182.9 million ($204.5 million in non-GAAP earnings) was partially offset by the issuance of approximately 136 million common shares to close the merger. Offsetting these favorable earnings impacts were lower retail electric and firm natural gas sales due primarily to significantly milder weather in the first quarter of 2012, compared with the first quarter of 2011, higher pension and healthcare costs, higher depreciation and property taxes.
Regulated Companies: Our Regulated companies consist of the electric distribution, natural gas distribution, and transmission segments. Generation activities of PSNH and WMECO are included in our electric distribution segment. A summary of our segment earnings for 2012, 2011 and 2010 is as follows:
(1)
Results include NSTAR Electric and NSTAR Gas earnings from the date of merger, April 10, 2012, through December 31, 2012.
(2)
Merger settlement agreement costs are attributable to the electric distribution segment ($51.1 million) and the natural gas distribution segment ($2.1 million).
(3)
The storm fund reserve is attributable to the electric distribution segment.
The higher 2012 transmission segment earnings, as compared to 2011, were due primarily to the inclusion of the NSTAR Electric transmission business and increased investments in the transmission infrastructure, including GSRP, which is under construction in western Massachusetts and northern Connecticut.
Our electric distribution segment earned $292.3 million in 2012, compared with $189.1 million in 2011. Excluding the impacts of the 2012 merger settlement agreement costs and the 2011 storm fund reserve, our electric distribution segment earned $343.4 million in 2012 and $207 million in 2011. The higher earnings were due primarily to the addition of NSTAR Electric. Excluding $10.9 million of after-tax merger settlement agreement costs, which related to customer bill credits, NSTAR Electric’s distribution business earned $150.2 million from April 10, 2012 through December 31, 2012. For further information regarding NSTAR Electric’s earnings, see "Results of Operations - NSTAR Electric Company and Subsidiaries - Earnings Summary" in this Management's Discussion and Analysis of Financial Condition and Results of Operations. Offsetting this favorable earnings impact was lower retail revenue, which was primarily the result of warmer than normal weather in the first quarter of 2012 as compared to colder than normal weather in the first quarter of 2011. In addition, our electric distribution segment had higher pension and employee benefit costs, higher depreciation and property taxes, and the DPU October snowstorm penalty ($2 million pre-tax) imposed on WMECO in December 2012, partially offset by the favorable impacts of the CL&P and PSNH 2010 distribution rate case decisions. As a result of these decisions, the CL&P rates increased effective July 1, 2011, which resulted in a full year favorable impact to earnings in 2012, while the PSNH rates increased effective July 1, 2012.
Our natural gas distribution segment earned $30.8 million in 2012, compared with $31.7 million in 2011. Excluding the impact of the merger settlement agreement costs, our natural gas distribution segment earned $32.9 million in 2012. The higher earnings were due primarily to the addition of NSTAR Gas’ results. Excluding $2.1 million of after-tax merger settlement agreement costs, which related to customer bill credits, NSTAR Gas’ earnings were $6.6 million from April 10, 2012 through December 31, 2012. Offsetting this favorable earnings impact was a decrease in total firm natural gas sales, which was primarily the result of warmer than normal weather in the first quarter of 2012 as compared to colder than normal weather in the first quarter of 2011, and higher pension expense, depreciation and property taxes. These costs were partially offset by lower operations and maintenance costs as well as the favorable impact of the Yankee Gas 2011 rate case decision resulting in the additional increase to annualized rates effective July 1, 2012.
A summary of our retail electric GWh sales and percentage changes, as well as changes in CL&P, NSTAR Electric, PSNH and WMECO retail electric GWh sales, and our firm natural gas sales and percentage changes in million cubic feet, as well as changes in Yankee Gas and NSTAR Gas’ sales in million cubic feet, for 2012, as compared to 2011, is as follows:
(1)
NU retail electric sales include the sales of NSTAR Electric from the date of merger, April 10, 2012, through December 31, 2012.
(2)
Results for NSTAR Electric represent its standalone retail electric sales for the year ended December 31, 2012 and 2011.
(1)
NU firm natural gas sales include the sales of NSTAR Gas from the date of merger, April 10, 2012, through December 31, 2012.
(2)
Special contracts are unique to the customers who take service under such an arrangement and generally specify the amount of distribution revenue to be paid to Yankee Gas regardless of the customers’ usage.
(3)
NSTAR Gas’ sales data for the year ended December 31, 2012 compared to 2011 has been provided for comparative purposes only.
Weather and, to a lesser extent, fluctuations in fuel costs, conservation measures, and economic conditions affect sales to our customers. Industrial sales are less sensitive to temperature variations than residential and commercial sales. Weather impacts electric sales primarily during the summer and natural gas sales during the winter in our service territories (natural gas sales are more sensitive to temperature variations than electric sales). Customer heating or cooling usage may not directly correlate with historical levels or with the level of degree-days that occur, particularly when weather patterns experienced are consistently colder or warmer. In addition, our electric and natural gas businesses are sensitive to variations in daily weather, are highly influenced by New England’s seasonal weather variations, and are susceptible to damage from major storms and other natural events and disasters that could adversely affect our ability to provide energy.
Our consolidated retail electric and firm natural gas sales were higher in 2012, as compared to 2011, due to the inclusion of NSTAR Electric and NSTAR Gas sales, respectively, from the date of merger, April 10, 2012, through December 31, 2012.
Actual retail electric sales for CL&P, NSTAR Electric and WMECO decreased in 2012, as compared to 2011, due primarily to the warmer than normal weather in the first quarter of 2012, as compared to colder than normal weather in the first quarter of 2011, while actual retail electric sales for PSNH were 0.1 percent higher than last year. In 2012, heating degree days were 11 percent lower in Connecticut and western Massachusetts, 7 percent lower in the Boston metropolitan area, and 9 percent lower in New Hampshire, as compared to 2011. On a weather normalized basis (based on 30-year average temperatures), the average NU combined consolidated total retail electric sales decreased 0.2 percent in 2012, as compared to 2011, assuming NSTAR Electric had been part of the NU combined electric distribution system for all periods under consideration. We believe these decreases were due primarily to increased conservation efforts among all our customer classes and the continued installation of distributed generation at our commercial and industrial customers’ facilities. For WMECO, the fluctuations in retail electric sales no longer impact earnings as the DPU approved a sales decoupling plan effective February 1, 2011. Under this decoupling plan, WMECO now has an established annual level of baseline distribution delivery service revenues of $125.4 million that it is able to recover. This effectively breaks the relationship between sales volume and revenues recognized.
Our firm natural gas sales are subject to many of the same influences as our retail electric sales, but have benefitted from lower natural gas prices and customer growth across all three customer classes. In 2012, excluding the impact of NSTAR Gas sales, actual sales decreased, as compared to 2011, due primarily to the warmer than normal weather in the first quarter of 2012, as compared to colder than normal weather in the first quarter of 2011. On a weather normalized basis, Yankee Gas’ 2012 sales increased due primarily to customer growth, lower cost of natural gas, the migration of interruptible customers switching to firm service rates, and the addition of gas-fired distributed generation in Yankee Gas’ service territory.
On a weather-normalized basis, the average NU combined consolidated total firm natural gas sales increased 2.7 percent in 2012, as compared to 2011, assuming NSTAR Gas had been part of the NU combined natural gas distribution system for all periods under consideration.
NU Parent and Other Companies: NU parent and other companies (which includes our competitive businesses held by NU Enterprises and, from April 10, 2012, NSTAR LLC) recorded net losses of $46.9 million in 2012, compared with net losses of $25.7 million in 2011. Excluding the impact of the 2012 and 2011 merger and related settlement agreement costs, NU parent and other companies recorded earnings of $7.5 million and net losses of $14.4 million, respectively. The NU parent merger and related settlement agreement costs primarily included fees paid to investment advisors and attorneys, a charge for the establishment of a fund to advance Connecticut energy goals related to the Connecticut settlement agreement, and change in control costs and other compensation costs. Excluding merger and related settlement agreement costs, improved results were due primarily to lower interest expense, a lower effective tax rate and the inclusion of NSTAR Communications.
Major Storm Restoration Costs: A storm must meet certain criteria specific to each state and utility company to be declared a major storm. Once a storm is declared major, all qualifying expenses incurred during storm restoration efforts, if deemed prudent, are deferred and recovered from customers in future periods. In Connecticut, qualifying storm restoration costs must exceed $5 million for a storm to be declared as a major storm. In Massachusetts, qualifying storm costs must exceed $1 million for NSTAR Electric and $300,000 for WMECO and an emergency response plan must be initiated for a storm to be declared a major storm. In New Hampshire, (1) at least 10 percent of customers must be without power with at least 200 concurrent locations requiring repairs (trouble spots), or (2) at least 300 concurrent trouble spots must be reported for a storm to be declared a major storm.
On October 29, 2012, Hurricane Sandy caused extensive damage to our electric distribution system across all three states resulting in deferred storm restoration costs of $204 million ($159.9 million for CL&P, $27.8 million for NSTAR Electric, $12.1 million for PSNH, and $4.2 million for WMECO). Approximately 1.5 million of our 3.1 million electric distribution customers were without power during or following the storm, with approximately 850,000 of those customers in Connecticut, approximately 472,000 in Massachusetts, and approximately 137,000 in New Hampshire. We expect the storm restoration costs to meet the criteria for specific cost recovery in Connecticut, Massachusetts, and New Hampshire and, as a result, we do not expect the storm to have a material impact on the results of operations of CL&P, NSTAR Electric, PSNH or WMECO. Each operating company will seek recovery of these deferred storm restoration costs through its applicable regulatory recovery process.
Liquidity
Consolidated: Cash and cash equivalents totaled $45.7 million as of December 31, 2012, compared with $6.6 million as of December 31, 2011.
On March 22, 2012, NU parent issued $300 million of 18-month floating rate Series D Senior Notes with a maturity date of September 20, 2013 and a coupon rate based on the three-month LIBOR rate plus a credit spread of 75 basis points, which resets every three months. As of December 31, 2012, the interest rate on these notes was 1.059 percent. The proceeds, net of issuance costs, were used to repay the NU parent $263 million Series A Senior Notes that matured on April 1, 2012, to repay short-term borrowings and for other general corporate purposes.
On March 22, 2012, the FERC approved CL&P's application requesting to increase its total short-term borrowing capacity from a maximum of $450 million to a maximum of $600 million through December 31, 2013.
On March 26, 2012, CL&P entered into a five-year $300 million unsecured revolving credit facility. The credit facility is intended to finance short-term borrowings that CL&P incurred to fund costs of restoring power following Tropical Storm Irene and the October 2011 snowstorm. Under this new facility, CL&P can borrow either on a short-term or a long-term basis subject to any necessary regulatory approval, and may borrow at prime rates or LIBOR-based rates, plus an applicable margin based on the higher of S&P’s or Moody’s credit ratings. As of December 31, 2012, CL&P had $89 million in borrowings outstanding under this credit facility. The weighted-average interest rate on these borrowings as of December 31, 2012 was 3.325 percent.
On April 2, 2012, CL&P remarketed $62 million of tax-exempt PCRBs that were subject to mandatory tender on that date. The PCRBs, which mature on May 1, 2031, carry a coupon rate of 1.55 percent during the current three-year fixed-rate period, and are subject to mandatory tender for purchase on April 1, 2015.
On May 16, 2012, the FERC granted authorization to allow NSTAR Electric to issue total short-term debt securities in an aggregate principal amount not to exceed $655 million outstanding at any one time, effective October 23, 2012 through October 23, 2014.
On July 25, 2012, NU, CL&P, NSTAR LLC, NSTAR Gas, PSNH, WMECO, and Yankee Gas jointly entered into a five-year $1.15 billion revolving credit facility. The new facility replaced (1) the NSTAR LLC revolving credit facility of $175 million that served to backstop a commercial paper program utilized by NSTAR LLC and was scheduled to expire on December 31, 2012, (2) the NSTAR Gas revolving credit facility of $75 million that expired on June 8, 2012, and (3) the CL&P, PSNH, WMECO, and Yankee Gas joint $400 million and NU parent $500 million unsecured revolving credit facilities that were scheduled to expire on September 24, 2013. The new facility expires on July 25, 2017. We expect the new facility to be used primarily to backstop the $1.15 billion commercial paper program at NU, which commenced July 25, 2012. As of December 31, 2012, NU had $1.15 billion in borrowings outstanding under this commercial paper program. The weighted-average interest rate on these borrowings as of December 31, 2012 was 0.46 percent, which is generally based on money market rates. As of December 31, 2012, there were inter-company loans of $987.5 million from NU to its subsidiaries ($405.1 million for CL&P, $63.3 million for PSNH, and $31.9 million for WMECO).
On July 25, 2012, NSTAR Electric entered into a five-year $450 million revolving credit facility. This new facility serves to backstop NSTAR Electric’s existing $450 million commercial paper program. The new facility expires on July 25, 2017. This new facility replaced a prior $450 million NSTAR Electric revolving credit facility that was scheduled to expire on December 31, 2012. As of December 31, 2012, NSTAR Electric had $276 million in short-term borrowings outstanding under its commercial paper program, leaving $174 million of available borrowing capacity. The weighted-average interest rate on these borrowings as of December 31, 2012 was 0.31 percent, which is generally based on money market rates.
On July 31, 2012, the DPU approved NSTAR Electric's application for a new two-year financing plan that provides for the issuance of long-term debt securities in an aggregate amount not to exceed $600 million prior to December 31, 2013.
On October 1, 2012, CL&P redeemed at par four different series of tax-exempt PCRBs totaling $116.4 million. The PCRBs carried coupons that ranged from 5.85 percent to 5.95 percent and maturity dates that ranged from 2016 through 2028. On October 1, 2012, WMECO redeemed at par $53.8 million of tax-exempt PCRBs. The PCRBs had a maturity date of 2028 and a coupon of 5.85 percent.
On October 4, 2012, WMECO issued at a premium $150 million of senior unsecured notes at a yield of 2.673 percent that will mature on September 15, 2021. The senior unsecured notes are part of the same series of WMECO’s existing 3.5 percent coupon Series F Notes that were initially issued in September 2011. As a result, the aggregate principal amount of WMECO’s outstanding Series F Notes now totals $250 million.
On October 15, 2012, NSTAR Electric issued at a discount $400 million of 2.375 percent Debentures at a yield of 2.406 percent that will mature on October 15, 2022. The proceeds, net of issuance costs, were used to pay $400 million of 4.875 percent Debentures that matured on October 15, 2012.
On January 15, 2013, CL&P issued $400 million of 2.5 percent first mortgage bonds that will mature on January 15, 2023. The proceeds, net of issuance costs, were used to repay CL&P’s revolving credit facility borrowings of $89 million and $305.8 million of its commercial paper program borrowings.
NU, CL&P, NSTAR Electric, PSNH and WMECO use their available capital resources to fund their respective construction expenditures, meet debt requirements, pay costs, including storm-related costs, pay dividends and fund other corporate obligations, such as pension contributions. The current growth in NU’s transmission construction expenditures utilizes a significant amount of cash for projects that have a long-term return on investment and recovery period. In addition, NU’s Regulated companies operate in an environment where recovery of its electric and natural gas distribution construction expenditures takes place over an extended period of time. This impacts the timing of the revenue stream designed to fully recover the total investment plus a return on the equity portion of the cost and related financing costs. These factors have resulted in NU’s current liabilities exceeding current assets by approximately $1.4 billion, $268 million, $198 million and $60 million at NU, CL&P, NSTAR Electric and WMECO, respectively, as of December 31, 2012.
As of December 31, 2012, approximately $730 million of NU's current liabilities relates to long-term debt that will be paid in the next 12 months, consisting of $550 million for NU parent, $55 million for WMECO, and $125 million for CL&P. NU, with its strong credit ratings, has several options available in the financial markets to repay or refinance these maturities with the issuance of new long-term debt. NU, CL&P, NSTAR Electric, and WMECO will reduce their short-term borrowings with cash received from operating cash flows or with the issuance of new long-term debt, as deemed appropriate given our capital requirements and maintenance of our credit rating and profile. Management expects the future operating cash flows of NU and its subsidiaries, along with the access to financial markets, will be sufficient to meet any future operating requirements and capital investment forecasted opportunities.
Cash flows provided by operating activities in 2012 totaled $1.05 billion, compared with operating cash flows of $901.1 million in 2011 and $832.6 million in 2010 (all amounts are net of RRB payments, which are included in financing activities on the accompanying consolidated statements of cash flows). The improved cash flows were due primarily to the addition of NSTAR, which contributed $450.8 million of operating cash flows (net of RRB payments) to NU since the date of the merger, April 10, 2012. Offsetting the favorable NSTAR cash flow impact was an increase of $100.6 million in cash disbursements made in 2012, compared to 2011, associated with CL&P, PSNH and WMECO storm restoration costs related to Tropical Storm Irene, the October 2011 snowstorm, and Hurricane Sandy, NUSCO Pension Plan cash contributions of $197.4 million in 2012, compared to $143.6 million in 2011, a total of $28 million of bill credits in 2012 to customers of CL&P and WMECO related to the merger, and $27 million in bill credits provided to CL&P residential customers in 2012 related to the October 2011 snowstorm. In addition, there were approximately $42 million of NU parent transaction cost payments related to the merger. The improved cash flows from 2010 to 2011 were due primarily to the impact of the CL&P and PSNH 2010 distribution rate case decisions that were effective July 1, 2010, the WMECO distribution rate case decision that was effective February 1, 2011, and income tax refunds of $76.6 million in 2011 largely attributable to accelerated depreciation tax benefits, compared to income tax payments of $84.5 million in 2010. Offsetting these benefits was $143.6 million of Pension Plan cash contributions in 2011, compared to $45 million in 2010, and approximately $157 million of cash disbursements made in 2011 associated with Tropical Storm Irene and the October snowstorm.
A summary of the current credit ratings and outlooks by Moody's, S&P and Fitch for senior unsecured debt of NU parent, NSTAR Electric, and WMECO and senior secured debt of CL&P and PSNH is as follows:
Moody's
S&P
Fitch
Current
Outlook
Current
Outlook
Current
Outlook
NU Parent
Baa2
Stable
BBB+
Stable
BBB+
Stable
CL&P
A3
Stable
A
Stable
A
Stable
NSTAR Electric
A2
Stable
A-
Stable
A+
Stable
PSNH
A3
Stable
A
Stable
A
Stable
WMECO
Baa2
Stable
A-
Stable
A-
Stable
On February 14, 2013, S&P revised its criteria for rating utility first mortgage bonds, resulting in one-level upgrades of CL&P and PSNH first mortgage bonds by S&P.
We paid common dividends of $375 million in 2012, compared with $194.6 million in 2011. This reflects an increase of approximately 17 percent in our common dividend beginning in the second quarter of 2012 following an increase of approximately 7 percent in the first quarter of 2012. On February 5, 2013, our Board of Trustees approved a common dividend payment of $0.3675 per share, payable March 28, 2013 to shareholders of record as of March 1, 2013. The dividend represented an increase of 7.1 percent over the $0.343 per share quarterly dividend paid in December 2012.
In 2012, CL&P, NSTAR LLC, PSNH, and WMECO paid $100.5 million, $141 million, $90.7 million, and $9.4 million, respectively, in common dividends to NU parent. Since April 10, 2012, NSTAR Electric and NSTAR Gas have paid $159.9 million and $12 million, respectively, in common dividends to NSTAR LLC. NU parent made equity contributions to CL&P and WMECO of $25 million and $50 million, respectively.
Cash capital expenditures included on the accompanying consolidated statements of cash flows and described in this "Liquidity" section do not include amounts incurred on capital projects but not yet paid, cost of removal, AFUDC related to equity funds, and the capitalized portions of pension and PBOP expense or income. A summary of our cash capital expenditures by company for the years ended December 31, 2012, 2011 and 2010 is as follows:
(1)
Cash capital expenditures include NSTAR from the date of merger, April 10, 2012, through December 31, 2012.
The increase in our cash capital expenditures was the result of the addition of NSTAR’s capital expenditures, effective April 10, 2012, and higher transmission segment cash capital expenditures of $113.8 million, primarily at WMECO and CL&P.
Business Development and Capital Expenditures
Consolidated: Our consolidated capital expenditures, including amounts incurred but not paid, cost of removal, AFUDC, and the capitalized portions of pension and PBOP expense or income (all of which are non-cash factors), totaled $1.5 billion in 2012, $1.2 billion in 2011, and $1 billion in 2010. These amounts included $43.1 million in 2012, $51.9 million in 2011, and $68.7 million in 2010, related to our corporate service companies, NUSCO and RRR.
Transmission Business: Transmission business capital expenditures increased by $189.6 million in 2012, compared with 2011, due primarily to increases at CL&P and WMECO related to the construction of GSRP and the addition of NSTAR Electric's capital expenditures since April 10, 2012. A summary of transmission capital expenditures by company in 2012, 2011 and 2010 is as follows:
(1)
Transmission capital expenditures include NSTAR Electric from the date of merger, April 10, 2012, through December 31, 2012.
NEEWS: GSRP, a project that involves the construction of 115 kV and 345 kV overhead lines by CL&P and WMECO from Ludlow, Massachusetts to Bloomfield, Connecticut, is the first, largest and most complicated project within the NEEWS family of projects. The $718 million project is expected to be fully placed in service in late 2013. As of December 31, 2012, the project was approximately 93 percent complete and we have placed $298 million in service.
The Interstate Reliability Project, which includes CL&P’s construction of an approximately 40-mile, 345 kV overhead line from Lebanon, Connecticut to the Connecticut-Rhode Island border in Thompson, Connecticut where it will connect to transmission enhancements being constructed by National Grid, is our second major NEEWS project. All siting applications have been filed by CL&P and National Grid. On January 2, 2013, the Connecticut Siting Council issued a final decision and order approving the Connecticut portion of the project. Decisions in Rhode Island and Massachusetts are expected between the end of 2013 and early 2014. The $218 million project is expected to be placed in service in late 2015.
Included as part of NEEWS are associated reliability related projects, approximately $70 million of which have been placed in service and approximately $30 million of which are in various phases of construction and will continue to go into service through 2013.
Through December 31, 2012, CL&P and WMECO had capitalized $212 million and $518.1 million, respectively, in costs associated with NEEWS, of which $79.4 million and $183.4 million, respectively, were capitalized in 2012.
Greater Hartford Central Connecticut Project (GHCC): In August 2012, ISO-NE presented its preliminary needs analysis for the GHCC to the ISO-NE Planning Advisory Committee. The results showed severe thermal overloads and voltage violations in each of the four study areas now and in the near future. A combination of 345 kV and 115 kV transmission solutions are being considered to address these reliability concerns and a set of preferred solutions are expected to be identified by ISO-NE in 2013. Approximately $300 million has been included in our five-year capital program for future projects being identified to enhance these reliability concerns, which have recently been confirmed by ISO-NE.
Cape Cod Reliability Projects: Transmission projects serving Cape Cod in the Southeastern Massachusetts (SEMA) reliability region consist of an expansion and upgrade of NSTAR Electric's existing transmission infrastructure including construction of a new 345 kV transmission line that will cross the Cape Cod Canal (The Lower SEMA Transmission Project) as well as a new 115kV transmission line and other 115kV upgrades in the center of Cape Cod. All regulatory and licensing and permitting is complete for the Lower SEMA Transmission Project. Construction commenced in September 2012 and is expected to be completed by mid-2013. The total estimated construction cost for the Cape Cod projects is approximately $150 million.
Northern Pass: Northern Pass is NPT's planned HVDC transmission line from the Québec-New Hampshire border to Franklin, New Hampshire and an associated alternating current radial transmission line between Franklin and Deerfield, New Hampshire. Northern Pass will interconnect at the Québec-New Hampshire border with a planned HQ HVDC transmission line. Effective April 10, 2012, as a result of the merger, NUTV owned 100 percent of NPT. NPT has identified a new route in the northern-most part of the project’s route where PSNH did not own any rights of way. We expect to file the new route with the DOE in the first quarter of 2013, and we believe that NPT will be completed in early 2017.
We estimate the costs of the Northern Pass transmission project will be approximately $1.2 billion (including capitalized AFUDC).
Greater Boston Reliability and Boston Network Improvements: As a result of continued analysis of the transmission needs to enhance system reliability and improve capacity in eastern Massachusetts, NSTAR Electric expects to implement a series of new transmission initiatives over the next five years. We have included $479 million in our five-year capital program related to these initiatives.
Distribution Business: A summary of distribution capital expenditures by company for 2012, 2011 and 2010 is as follows:
(1)
Distribution capital expenditures include NSTAR Electric and NSTAR Gas from the date of merger, April 10, 2012, through December 31, 2012.
For the electric distribution business, basic business includes the relocation of plant, the purchase of meters, tools, vehicles, information technology, transformer replacements, and equipment facilities. Aging infrastructure relates to reliability and the replacement of overhead lines, plant substations, underground cable replacement, and equipment failures. Load growth includes requests for new business and capacity additions on distribution lines and substation overloads.
Clean Air Project: In June 2012, PSNH placed into service the last major elements of the Clean Air Project at Merrimack Station, a $421 million project that is utilizing wet scrubber technology to significantly reduce mercury and sulfur emissions from the station’s two coal units. The scrubber has been operating since the end of September 2011 and has reduced mercury and sulfur emissions by more than 95 percent.
CL&P System Resiliency Plan: On January 16, 2013, PURA approved the $300 million plan CL&P filed to improve the resiliency of its electric distribution system. Consistent with the terms of the Connecticut settlement agreement, the plan includes vegetation management (both enhanced tree trimming and trimming on a shorter cycle), structural hardening (strengthening field structures through upgrades to the current structure design and material standards as well as upgrades to the poles and conductors), and electrical hardening (upgrading electrical distribution conductors and protective devices on overhead circuits). CL&P expects to complete the plan in five years in two separate phases. Phase 1 of the plan, which will be primarily focused on vegetation management, is estimated to cost $32 million in 2013 and $53 million in 2014. Phase 2 of the plan is estimated to cost the remaining $215 million over the period from 2015 through 2017.
Projected Capital Expenditures: A summary of the projected capital expenditures for the Regulated companies' electric transmission business for 2013 through 2017 and for their distribution business for 2013 through 2015, including our corporate service companies' capital expenditures on behalf of the Regulated companies, is as follows:
Actual capital expenditures could vary from the projected amounts for the companies and periods above.
FERC Regulatory Issues
FERC Base ROE Complaint: On September 30, 2011, several New England state attorneys general, state regulatory commissions, consumer advocates and other parties filed a joint complaint with the FERC under Sections 206 and 306 of the Federal Power Act alleging that the base ROE used in calculating formula rates for transmission service under the ISO-NE Open Access Transmission Tariff by New England transmission owners, including CL&P, NSTAR Electric, PSNH and WMECO, is unjust and unreasonable. The complainants asserted that the current 11.14 percent rate, which became effective in 2006, is excessive due to changes in the capital markets and are seeking an order to reduce the rate, which would be effective September 30, 2011 through December 31, 2012. In response, the New England transmission owners filed testimony and analysis based on standard FERC methodology and precedent, demonstrating that the base ROE of 11.14 percent remained just and reasonable.
On May 3, 2012, the FERC issued an order establishing hearing and settlement procedures for the complaint. The settlement proceedings were subsequently terminated, as the parties had reached an impasse in their efforts to reach a settlement. In August 2012, the FERC trial judge assigned to the complaint established a schedule for the trial phase of the proceedings. Complainant testimony supporting a base ROE of 9 percent was filed on October 1, 2012. Additional testimony was filed on October 1, 2012 by a group of Massachusetts municipal electric companies, which recommended a base ROE of 8.2 percent. The New England transmission owners filed testimony and analysis on November 20, 2012, demonstrating they believe that the current base ROE continues to be just and reasonable. On January 18, 2013, the FERC trial staff filed testimony and analysis recommending a base ROE of 9.66 percent based on the midpoint of their analysis with a range of reasonableness of 6.82 percent to 12.51 percent. Hearings on this complaint are scheduled for May 2013 and a trial judge’s recommended decision is due in September 2013. A decision from FERC commissioners is expected in 2014. Refunds to customers, if any, as a result of a reduction in the NU transmission companies’ base ROE would be retroactive to October 1, 2011.
On December 27, 2012, several additional parties filed a separate complaint concerning the New England transmission owners' base ROE with the FERC. This new complaint seeks to reduce the New England transmission owner’s base transmission ROE effective January 1, 2013, and to consolidate this new complaint with the joint complaint filed on September 30, 2011. The New England transmission owners have asked the FERC to reject this new complaint. The FERC has not yet acted on this request.
As of December 31, 2012, CL&P, NSTAR Electric, PSNH, and WMECO had approximately $2.1 billion of aggregate shareholder equity invested in their transmission facilities. As a result, each 10 basis point change in the authorized base ROE would change annual consolidated earnings by an approximate $2.1 million. We cannot at this time predict the ultimate outcome of this proceeding or the estimated impact on CL&P’s, NSTAR Electric’s, PSNH’s, or WMECO’s respective financial position, results of operations or cash flows.
FERC Order No. 1000: On October 25, 2012, ISO-NE and a majority of the New England transmission owners, including CL&P, NSTAR Electric, PSNH and WMECO, made a comprehensive compliance filing as required by FERC Order No. 1000 and Order No. 1000-A, issued on July 21, 2011 and May 17, 2012, respectively. The compliance filing first seeks to preserve the existing reliability planning process in New England, based on FERC’s previous approval of transmission owners’ rights under the Transmission Operating Agreement with ISO-NE, and the superiority of the current planning process, which has resulted in major transmission construction, large reliability benefits and reduction of market costs. The filing also contains a new process for public policy transmission planning that incorporates opportunities for competing, non-incumbent projects and cost allocation among the supporting states. In mid-January 2013, ISO-NE and the majority of New England transmission owners filed answers to various stakeholders that submitted protests to the compliance filing. We cannot predict the final outcome or impact on us; however implementation of FERC’s goals in New England, including within our service territories, may expose us to competition for construction of transmission projects, additional regulatory considerations, and potential delay with respect to future transmission projects.
Regulatory Developments and Rate Matters
Federal:
EPA Proposed NPDES Permit: PSNH maintains a NPDES permit consistent with requirements of the Clean Water Act for Merrimack Station. In 1997, PSNH filed in a timely manner for a renewal of this permit. As a result, the existing permit was administratively continued. On September 29, 2011, the EPA issued a draft renewal NPDES permit for PSNH's Merrimack Station for public review and comment. The proposed permit contains many significant conditions to future operation. The proposed permit would require PSNH to install a closed-cycle cooling system (including cooling towers) at the station. The EPA estimated that the net present value cost to install this system and operate it over a 20-year period would be approximately $112 million.
On October 27, 2011, the EPA extended the initial 60-day period for public review and comment on the draft permit for an additional 90 days until February 28, 2012. PSNH and other electric utility groups filed thousands of pages of comments contesting EPA’s draft permit requirements. PSNH stated that the data and studies supplied to the EPA demonstrate the fact that a closed-cycle cooling system is not warranted. The EPA does not have a set deadline to consider comments and to issue a final permit. Merrimack Station is permitted to continue to operate under its present permit pending issuance of the final permit and subsequent resolution of matters appealed by PSNH and other parties. Due to the site specific characteristics of PSNH's other fossil generating stations, we believe it is unlikely that they would face similar permitting determinations.
Major Storms:
2013, 2012 and 2011 Major Storms: On August 28, 2011, Tropical Storm Irene caused extensive damage to our distribution system. Approximately 800,000 CL&P, PSNH and WMECO customers were without power at the peak of the outages, with approximately 670,000 of those customers in Connecticut. Approximately 500,000 customer outages occurred on the NSTAR Electric distribution system in its aftermath.
On October 29, 2011, an unprecedented storm inundated our service territory with heavy snow causing significant damage to our distribution and transmission systems. Approximately 1.2 million of CL&P, PSNH and WMECO’s electric distribution customers were without power at the peak of the outages, with 810,000 of those customers in Connecticut, 237,000 in New Hampshire, and 140,000 in western 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; and the most severe in WMECO's history. The storm also caused approximately 200,000 customer outages on the NSTAR Electric distribution system.
On October 29, 2012, Hurricane Sandy caused extensive damage to our electric distribution system across all three states. Approximately 1.5 million of our 3.1 million electric distribution customers were without power during or following the storm, with approximately 850,000 of those customers in Connecticut, approximately 472,000 in Massachusetts, and approximately 137,000 in New Hampshire.
As of December 31, 2012, deferred storm restoration costs related to these major storms that are deferred for future recovery at CL&P, NSTAR Electric, PSNH, and WMECO were as follows:
(Millions of Dollars)
Tropical
Storm Irene
October
Snowstorm
Hurricane
Sandy
Total
CL&P
$
108.6
$
173.0
$
159.9
$
441.5
NSTAR Electric
21.9
13.9
27.8
63.6
PSNH
6.8
15.5
12.1
34.4
WMECO
3.2
23.3
4.2
30.7
Total
$
140.5
$
225.7
$
204.0
$
570.2
On February 8, 2013, a blizzard caused damage to the electric delivery systems of CL&P and NSTAR Electric. We have estimated that approximately 71,000 and 350,000 of CL&P and NSTAR Electric's distribution customers, respectively, were without power during or following the storm. We believe that this storm will cost between $100 million to $120 million, with approximately 90 percent of those costs relating to NSTAR Electric. Management expects the costs to meet the criteria for specific cost recovery in Connecticut and Massachusetts and, as a result, does not expect the storm to have a material impact on the results of operations of CL&P or NSTAR Electric. Each operating company will seek recovery of these anticipated deferred storm costs through its applicable regulatory recovery process.
The magnitude of these storms’ restoration costs and damages met the criteria for cost deferral in Connecticut, New Hampshire, and Massachusetts and as a result, the storms had no material impact on the results of operations of CL&P, NSTAR Electric, PSNH and WMECO. As covered by the Connecticut settlement agreement, CL&P agreed to forego recovery of $40 million (pre-tax) of the deferred storm restoration costs associated with Tropical Storm Irene and the October 2011 snowstorm. We believe our response to all storms was prudent and therefore we believe it is probable that CL&P, NSTAR Electric, PSNH and WMECO will be allowed to recover the deferred storm restoration costs. Each operating company will seek recovery of its estimated deferred storm restoration costs through its applicable regulatory recovery process.
Connecticut:
Standard Service and Last Resort Service Rates: CL&P's residential and small commercial customers who do not choose competitive suppliers are served under SS rates, and large commercial and industrial customers who do not choose competitive suppliers are served under LRS rates. Effective January 1, 2013, the PURA approved a decrease to CL&P’s total average SS rate of approximately 4.5 percent and an increase to CL&P’s total average LRS rate of approximately 15.3 percent. The energy supply portion of the total average SS rate decreased from 8.443 cents per kWh to 7.68 cents per kWh while the energy supply portion of the total average LRS rate increased from 6.06 cents per kWh to 7.679 cents per kWh. These changes were due primarily to the market conditions for the procurement of energy. CL&P is fully recovering from customers the costs of its SS and LRS services.
CTA and SBC Reconciliation: On December 12, 2012, PURA approved CL&P’s 2011 CTA and SBC reconciliation as filed on March 30, 2012, which compared CTA and SBC revenues to revenue requirements. Prospectively, PURA has required CL&P to include only the billed revenues when filing its future CTA and SBC reconciliations. This adjustment to the filing will have no impact to CL&P’s financial position, results of operations or cash flows. CL&P will file its 2012 CTA and SBC reconciliation in March 2013.
FMCC Filing: Semi-annually, CL&P files with PURA its FMCC filing, which reconciles actual FMCC revenues and charges and GSC revenues and expenses, for the six-month period under consideration. The filing identifies a total net over or under recovery, which includes the remaining uncollected or non-refunded portions from previous filings. On February 22, 2013, CL&P filed with PURA its semi-annual FMCC filing for the period July 1, 2012 through December 31, 2012. This filing also reflects the January 1, 2012 through June 30, 2012 amounts as approved by PURA in the previous semi-annual filing. The filing identified a total net over recovery of $7.9 million for the period. PURA has not established a schedule for review of this filing, however, we do not expect the outcome of the PURA's review to have a material adverse impact on CL&P's financial position, results of operations or cash flows.
Conservation Adjustment Mechanism: On November 7, 2012, CL&P filed an application with PURA for the establishment of a CAM. The CAM would collect the costs associated with expanded energy efficiency programs beyond that already collected through the statutory charge and the revenues lost because of the expanded energy efficiency programs.
Procurement Fee Rate Proceedings: In prior years, CL&P submitted to the PURA its proposed methodology to calculate the variable incentive portion of its transition service procurement fee, which was effective for the years 2004, 2005 and 2006, and requested approval of the pre-tax $5.8 million 2004 incentive fee. At the time, CL&P had not recorded amounts related to the 2005 and 2006 procurement fee in earnings. CL&P recovered the $5.8 million pre-tax amount, which was recorded in 2005 earnings, through a CTA reconciliation process. On January 15, 2009, the PURA issued a final decision in this docket reversing its December 2005 draft decision and stated that CL&P was not eligible for the procurement incentive compensation for 2004. A $5.8 million pre-tax charge (approximately $3.5 million net of tax) was recorded in the 2008 earnings of CL&P, and an obligation to refund the $5.8 million to customers was established as of December 31, 2008. CL&P filed an appeal of this decision on February 26, 2009. On February 4, 2010, the Connecticut Superior Court reversed the PURA decision. The Court remanded the case back to the PURA for the correction of several specific errors. On February 22, 2010, the PURA appealed the Connecticut Superior Court’s February 4, 2010 decision to the Connecticut Appellate Court, which then transferred the appeal to the Connecticut Supreme Court. In lieu of a decision from the Connecticut Supreme Court, the parties involved, including CL&P, agreed to resolve all issues associated with the 2004, 2005 and 2006 procurement fee and settle the matter. On October 2, 2012, the PURA issued a decision approving the parties’ joint settlement agreement. As a result of the joint settlement agreement, CL&P is allowed to retain $11.5 million of procurement incentives for the years 2004, 2005 and 2006.
PURA Storm Review: On August 1, 2012, PURA issued a final decision in the investigation of CL&P’s performance related to both Tropical Storm Irene and the October 2011 snowstorm. The decision concluded that CL&P was deficient and inadequate in its preparation, response, and communication in both storms, and identified certain penalties that could be imposed on CL&P during its next rate case, including a reduction in allowed regulatory ROE and the disallowance of certain deferred storm restoration costs. However, PURA will consider and weigh the extent to which CL&P has taken steps in its restructuring of storm management and the establishment of new practices for execution in future storm response in determining any potential penalties. We believe such steps to improve current storm preparation and response practices have been successfully executed in recent storms. At this time, we cannot estimate the impact on CL&P’s financial position, results of operations or cash flows. We continue to believe that CL&P's response to these 2011 storms was prudent and consistent with industry standards, and that it is probable that it will be able to recover its deferred costs.
System Resiliency Plan: On January 16, 2013, PURA approved the $300 million plan CL&P filed on July 9, 2012 to improve the resiliency of the CL&P electric distribution system. For further information, see "Business Development and Capital Expenditures - Distribution Business" in this Management's Discussion and Analysis.
PURA Establishment of Performance Standards for Electric and Gas Companies Docket: On November 1, 2012, PURA issued its report to the Connecticut legislature concerning specific standards for acceptable performance for electric and gas companies under emergency situations. Emergency situations were defined as more than 10 percent of electric customers and 1 percent of gas customers being without service for more than 48 consecutive hours. The performance standards the electric and gas companies, including CL&P and Yankee Gas, were directed to incorporate into their emergency response plans (ERP), and implement into their operations, include (1) the National Incident Management System and utilization of the Incident Command System, (2) scalable action and trigger points for various levels of outages, (3) a damage assessment model and mode of delivery, (4) guidelines for setting
restoration priorities, (5) a description of how the utility will insure safety for the public and utility’s employees, (6) a storm matrix for various storm levels that identify the mutual aid and/or contractor resources necessary to restore customers within a prescribed period of time, (7) written communication protocols for timely and accurate information exchange between the EDC and a pre-determined list of state and local agencies and other utilities during emergency events, (8) training and drills/exercises to be conducted annually on a local level and every 3 years on a state-wide level, and (9) a written report to be filed with PURA within 60 days after the end of an event in order to assist in lessons learned and continual improvement. Electric and gas companies, including CL&P and Yankee Gas, will be subject to penalties levied by PURA for failure to meet these performance standards.
Massachusetts:
Basic Service Rates: Electric distribution companies in Massachusetts are required to obtain and resell power to retail customers through Basic Service for those customers who choose not to buy energy from a competitive energy supplier. Basic Service rates are reset every six months (every three months for large commercial and industrial customers). The price of Basic Service is intended to reflect the average competitive market price for electric power. NSTAR Electric and WMECO fully recover their energy costs through DPU-approved regulatory rate mechanisms.
DPU Storm Penalties: On December 11, 2012, in separate orders issued by the DPU, NSTAR Electric and WMECO received penalties related to the investigation into the electric utilities’ responses to Tropical Storm Irene and the October 2011 snowstorm. The DPU ordered penalties of $4.1 million and $2 million for NSTAR Electric and WMECO, respectively, stating that NSTAR Electric failed to communicate and prioritize restoration efforts in both storms and WMECO failed to prioritize restoration efforts in the October snowstorm. These penalties were ordered to be assessed in the form of customer credits in 2013. On December 28, 2012, NSTAR Electric and WMECO each filed appeals with the SJC arguing the DPU penalties should be vacated. In their filings, NSTAR Electric and WMECO stated that the DPU’s decision to assess the penalties was in error as the assessments were arbitrary and not supported by substantial evidence. While we believe that NSTAR Electric and WMECO should ultimately prevail upon appeal, we are unable to conclusively state that a favorable outcome is probable. Therefore, NSTAR Electric and WMECO recorded $4.1 million and $2 million, respectively, in pre-tax penalty charges as of December 31, 2012.
DPU Safety and Reliability Programs (CPSL): Since 2006, NSTAR Electric has been recovering incremental costs related to the Double Pole Inspection, Replacement/Restoration and Transfer Program and the Underground Electric Safety Program, which included stray-voltage remediation, manhole inspections, repairs, and upgrades, in accordance with this DPU approved program. Recovery of these CPSL costs is subject to review and approval by the DPU through a rate-reconciling mechanism. From 2006 through December 31, 2011, cumulative costs associated with the CPSL program resulted in an incremental revenue requirement to customers of approximately $83 million. These amounts included incremental operations and maintenance costs and the related revenue requirement for specific capital investments relative to the CPSL programs.
On May 28, 2010, the DPU issued an order on NSTAR Electric’s 2006 CPSL cost recovery filing (the May 2010 Order). The May 2010 Order was the basis NSTAR Electric used for recognizing revenue for the CPSL programs. On October 8, 2010, NSTAR Electric submitted a Compliance Filing with the DPU reconciling the cumulative CPSL program activity for the periods 2006 through 2009 in order to determine a proposed rate adjustment effective on January 1, 2011. The DPU allowed the proposed rates for the CPSL programs to go into effect on that date, subject to final reconciliation of CPSL program costs through a future DPU proceeding. NSTAR Electric updated the October 2010 filing with final activity through 2011 in February 2013.
NSTAR Electric cannot predict the timing of any subsequent DPU order related to its CPSL filings for the period 2006 through 2011. Therefore, NSTAR Electric continued to record its 2006 through 2011 revenues under the CPSL programs based on the May 2010 Order. While we do not believe that any subsequent DPU order would result in revenue recognition that is materially different than the amounts already recognized, it is reasonably possible that an order could have a material impact on NSTAR Electric’s results of operations, financial position and cash flows.
The April 4, 2012 DPU-approved comprehensive merger settlement agreement with the Massachusetts Attorney General concerning the Merger stipulates that NSTAR Electric must incur a revenue requirement of at least $15 million per year for 2012 through 2015 in order to continue these programs. CPSL revenues will end once NSTAR Electric has recovered its 2015-related CPSL costs. Realization of these revenues is subject to maintaining certain performance metrics over the four-year period and DPU approval. As of December 31, 2012, NSTAR Electric was in compliance with the performance metrics and has recognized the entire $15 million revenue requirement during 2012, which we believe is probable of approval from the DPU.
Basic Service Bad Debt Adder: In accordance with a generic DPU order, electric utilities in Massachusetts recover the energy-related portion of bad debt costs in their Basic Service rates. On February 7, 2007, NSTAR Electric filed its 2006 Basic Service reconciliation with the DPU proposing an adjustment related to the increase of its Basic Service bad debt charge-offs. On June 28, 2007, the DPU issued an order approving the implementation of a revised Basic Service rate. However, the DPU instructed NSTAR Electric to reduce distribution rates by an amount equal to the increase in its Basic Service bad debt charge-offs. This adjustment to NSTAR Electric’s distribution rates would eliminate the fully reconciling nature of the Basic Service bad debt adder.
NSTAR Electric deferred the unrecovered costs associated with energy-related bad debt as a regulatory asset, which totaled approximately $34 million as of December 31, 2011, as NSTAR Electric had concluded that these costs were probable of recovery in future rates. On June 18, 2010, NSTAR Electric filed an appeal of the DPU’s order with the SJC, which was heard by the SJC in
December 2011. On April 11, 2012, the SJC issued a procedural order waiving its standing 130-day rule for issuance of an order on the matter. Due to the delay, NSTAR Electric concluded that while an ultimate outcome on the matter in its favor remained more likely than not, it could no longer be deemed probable. As a result, NSTAR Electric recognized a reserve of $28 million ($17 million after-tax) as a charge to Operations and Maintenance in the first quarter of 2012 to reserve the related regulatory asset on its balance sheet.
On June 4, 2012, the SJC vacated the DPU's June 28, 2007 order and remanded the matter to the DPU for a "statement of reasons, including subsidiary findings, of its conclusion of law and relevant facts." The continued uncertainty of the outcome of the DPU’s proceeding leaves NU and NSTAR Electric unable to conclude that it is probable that the previously reserved amount will ultimately be recovered and therefore NSTAR Electric will continue to maintain a reserve on this amount until the ultimate outcome is determined by the DPU.
Renewable Energy Contract: On November 26, 2012, the DPU approved NSTAR Electric’s renewable energy contract with Cape Wind Associates, LLC, which has a term of 15 years, to purchase 129 MW of renewable energy from an offshore wind energy facility once it is constructed and placed in service.
New Hampshire:
Distribution Rates: In 2012, PSNH filed for a step increase and a change in its accrual to its major storm reserve fund. On June 27, 2012, the NHPUC approved an annualized distribution rate increase of $7.1 million, effective July 1, 2012, for the step increase. Additionally, PSNH was allowed a $3.5 million increase in the annual accrual to its major storm reserve fund effective July 1, 2012.
ES and SCRC Rates: On December 12, 2012, PSNH filed an updated request to its September 28, 2012 preliminary request with the NHPUC to adjust its ES and SCRC rates effective with services rendered on and after January 1, 2013. PSNH’s updated request proposed to increase the current ES billing rate to reflect projected costs for 2013 and to decrease the current SCRC billing rate to reflect the full amortization of RRBs at the end of April 2013. The net impact to customers that purchase energy from PSNH is a net increase of 1.287 cents per kWh in total rates. On December 28, 2012, the NHPUC approved the request.
ES Temporary Rates: On November 22, 2011, the NHPUC opened a docket to review the Clean Air Project including the establishment of temporary rates for near-term recovery of Clean Air Project costs, a prudence review of PSNH's overall construction program, and establishment of permanent rates for recovery of prudently incurred Clean Air Project costs. On April 10, 2012, the NHPUC issued an order authorizing temporary rates, effective April 16, 2012, which recover a significant portion of the Clean Air Project costs, including a return on equity. The docket will continue for a comprehensive prudence review of the Clean Air Project and the establishment of a permanent rate. The temporary rates will remain in effect until a permanent rate allowing full recovery of all prudently incurred costs is approved. At that time, the NHPUC will reconcile recoveries collected under the temporary rates with final approved rates.
The NHPUC had suspended the procedural schedule for the prudence review pending issuance of an order on preliminary substantive and procedural matters. On December 24, 2012, the NHPUC issued an Order ruling on the requirement of PSNH to respond to a number of discovery requests that PSNH had objected to, and deciding that PSNH had legal authority to seek a variance from the Clean Air Project Mandate in the event of "economic infeasibility." PSNH has sought rehearing of that December 24th Order. The NHPUC is considering PSNH’s rehearing request, and has again suspended the procedural schedule. PSNH expects hearings to commence in this proceeding on or about the third quarter of 2013. We cannot predict the outcome of the Clean Air Project prudence review, but believe all costs were incurred appropriately and are probable of recovery.
ES Filing: 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. On April 27, 2012, PSNH filed its proposed Alternative Default Energy Rate that addresses customer migration, with an effective date of July 1, 2012. The proposal, if implemented, would result in no impact to earnings and would allow for an increased contribution to fixed costs for all ES customers. On May 24, 2012, the NHPUC suspended the effectiveness of the proposed rates pending hearings. Hearings were held on October and November 2012 and a final decision is expected in the first quarter of 2013.
Default ES Rate: On January 18, 2013, the NHPUC opened a docket to investigate market conditions affecting PSNH’s energy service rate, how PSNH will maintain just and reasonable rates in light of those conditions, and any impact of PSNH’s generation ownership on the New Hampshire competitive electric market. The NHPUC noted that this proceeding will not undertake to determine whether continued ownership and operation of generation is in PSNH’s retail customers’ economic interest. No schedule or procedural process has been established for this proceeding.
Legislative and Policy Matters
Federal:
Moving Ahead for Progress in the 21st Century Act: On July 6, 2012, President Obama signed the "Moving Ahead for Progress in the 21st Century" Act, which included provisions that impact how minimum required contributions to qualified pension plans are calculated. The legislation allows NU to use a higher discount rate to calculate the plan's funded target liability, resulting in lower cash contribution
requirements. We have evaluated the impact of the legislation on future cash contributions to the NUSCO and NSTAR Pension Plans and will continue to follow our policy to fund these plans on an annual basis that is at least equal to the amounts that will satisfy the federal requirements, as amended by this legislation.
2013 Legislation: On January 2, 2013, President Obama signed into law the "American Taxpayer Relief Act of 2012," which extends certain tax rules allowing the accelerated deduction of depreciation from the "American Recovery and Reinvestment Act of 2009" to businesses through 2013. This extended stimulus is expected to provide us with cash flow benefits of between $200 million to $250 million in 2013 and 2014. We are still evaluating the other provisions of this legislation, which are not expected to have a significant impact on our financial position, results of operations or cash flows.
Connecticut:
Enhancing Emergency Preparedness and Response Act: On June 15, 2012, Connecticut enacted the "Enhancing Emergency Preparedness and Response Act," which is intended to enhance the state’s emergency preparedness and response in the event of natural disasters. Among numerous provisions, the bill requires the PURA to establish emergency performance standards for utilities and allows the PURA to levy penalties of up to 2.5 percent of annual distribution revenues for failure to meet performance standards. For further information, see "Regulatory Developments and Rate Matters - Connecticut" in this Management's Discussion and Analysis.
Comprehensive Energy Strategy: On February 19, 2013, Connecticut issued a final comprehensive energy strategy (strategy). The strategy includes a series of policy proposals that aim to expand energy choices, improve environmental conditions, create clean energy jobs, and enhance the quality of life for customers in the state. It also includes a seven-year initiative for expanding natural gas use with a goal of providing nearly 300,000 utility customers with access to natural gas, building an estimated 900 miles of new natural gas mains, and estimates of capital costs to be incurred by natural gas utility companies to connect customers on or near natural gas mains. In addition to natural gas expansion, the strategy also calls for a significant expansion of energy efficiency investment in Connecticut, a review of Connecticut’s Renewable Energy Portfolio Standards (possibly including Canadian hydroelectric generation as a qualifying resource), and investment in alternative fuel transportation. Many of the recommendations in the strategy will require actions by the PURA and potentially the legislature. As such, the full impact of the strategy is not reflected in our electric distribution, transmission or natural gas business segments five-year capital program.
Massachusetts:
Energy Act: On August 3, 2012, Massachusetts Governor Patrick signed into law "An Act Relative to Competitively Priced Electricity in the Commonwealth" (Energy Act). The more significant provisions of the Energy Act impacting our Massachusetts operating companies and customers are as follows:
·
Requires electric utility companies to file a distribution rate case every five years and natural gas companies every 10 years, limiting those companies to one settlement agreement in a 10-year period;
·
Extends the distribution rate case review period to 10 months;
·
Requires all distribution companies, through a competitive bidding process and subject to DPU approval, to enter into additional cost-effective long-term renewable energy contracts with terms of 10 to 20 years. Electric utility companies will be allowed a remuneration of 2.75 percent of the annual payments under the contracts to compensate them for accepting the financial obligation of the contracts;
·
Orders the DPU to open a proceeding for each electric and natural gas utility company to identify reconciliation factors and establish cost recovery from each customer class under cost-based criteria; and
·
Allows electric utility or distribution companies to construct, own and operate no more than 25 MW of solar generation facilities, a decrease from the initial allowance of up to 50 MW of solar generation facilities, subject to DPU approval, and requires that construction be completed prior to June 30, 2015.
Storm Response Act: On August 6, 2012, Massachusetts Governor Patrick signed into law "an act relative to emergency service response of public utility companies" (Storm Response Act), to help improve utility companies’ emergency response and communication. The Storm Response Act codified certain emergency response plan (ERP) provisions, which require utility companies to submit an annual ERP for DPU review and approval. The ERP will describe storm or emergency responsibilities of utility company employees, customer communication processes and systems, and deployment of resources. The Storm Response Act also requires that all future financial penalties levied on utility companies by the DPU for violation of DPU storm and emergency service performance standards will be provided to customers, and that transmission companies performing vegetation management activities within a right-of-way comply with certain notification provisions. We are currently evaluating this act and its potential impacts on NSTAR Electric’s, NSTAR Gas’ and WMECO’s financial positions, results of operations and cash flows; however, we do not expect the impacts to be material.
Critical Accounting Policies
The preparation of financial statements in conformity with GAAP requires management to make estimates, assumptions and, at times, difficult, subjective or complex judgments. Changes in these estimates, assumptions and judgments, in and of themselves, could materially impact our financial position, results of operations or cash flows. Our management communicates to and discusses with the Audit Committee of our Board of Trustees significant matters relating to critical accounting policies. Our critical accounting policies are
discussed below. See the combined notes to our consolidated financial statements for further information concerning the accounting policies, estimates and assumptions used in the preparation of our consolidated financial statements.
Regulatory Accounting: The accounting policies of the Regulated companies conform to GAAP applicable to rate-regulated enterprises and reflect the effects of the rate-making process.
The application of accounting guidance applicable to rate-regulated enterprises results in recording regulatory assets and liabilities. Regulatory assets represent the deferral of incurred costs that are probable of future recovery in customer rates. In some cases, we record regulatory assets before approval for recovery has been received from the applicable regulatory commission. We must use judgment to conclude that costs deferred as regulatory assets are probable of future recovery. We base our conclusion on certain factors, including, but not limited to, regulatory precedent. Regulatory liabilities represent revenues received from customers to fund expected costs that have not yet been incurred or probable future refunds to customers.
We use our best judgment when recording regulatory assets and liabilities; however, regulatory commissions can reach different conclusions about the recovery of costs, and those conclusions could have a material impact on our consolidated financial statements. We believe it is probable that the Regulated companies will recover the regulatory assets that have been recorded. If we determined that we could no longer apply the accounting guidance applicable to rate-regulated enterprises to our operations, or that we could not conclude that it is probable that costs would be recovered or reflected in future rates, the costs would be charged to earnings in the period in which the determination is made.
For further information, see Note 3, "Regulatory Accounting," to the consolidated financial statements.
Unbilled Revenues: The determination of retail energy sales to residential, commercial and industrial customers is based on the reading of meters, which occurs regularly throughout the month. Billed revenues are based on these meter readings and the majority of recorded annual revenues is based on actual billings. Because customers are billed throughout the month based on pre-determined cycles rather than on a calendar month basis, an estimate of electricity or natural gas delivered to customers for which the customers have not yet been billed is calculated as of the balance sheet date.
Unbilled revenues represent an estimate of electricity or natural gas delivered to customers but not yet billed. Unbilled revenues are included in Operating Revenues on the statement of income and are assets on the balance sheet that are reclassified to Accounts Receivable in the following month as customers are billed. Such estimates are subject to adjustment when actual meter readings become available, when there is a change in estimates and under other circumstances.
The Regulated companies estimate unbilled sales monthly using the daily load cycle method. The daily load cycle method allocates billed sales to the current calendar month based on the daily load for each billing cycle. The billed sales are subtracted from total month load, net of delivery losses, to estimate unbilled sales. Unbilled revenues are estimated by first allocating unbilled sales to the respective customer classes, then applying an estimated rate by customer class to those sales. The estimate of unbilled revenues is sensitive to numerous factors, such as energy demands, weather and changes in the composition of customer classes that can significantly impact the amount of revenues recorded.
For further information, see Note 1K, "Summary of Significant Accounting Policies - Revenues," to the consolidated financial statements.
Pension and PBOP: NUSCO and NSTAR Electric sponsor pension plans covering certain of our employees. In addition, NUSCO and NSTAR Electric & Gas sponsor PBOP plans to provide certain health care benefits, primarily medical and dental, and life insurance benefits to retired employees. For each of these plans, the development of the benefit obligation, funded status and net periodic benefit cost is based on several significant assumptions. We evaluate these assumptions at least annually and adjust them as necessary. Changes in these assumptions could have a material impact on our financial position, results of operations or cash flows.
Pre-tax net periodic benefit expense (excluding SERP) for the Pension Plans was $234.9 million, $127.7 million and $80.4 million for the years ended December 31, 2012, 2011 and 2010, respectively. The pre-tax net periodic benefit expense for the PBOP Plans was $72.3 million, $43.6 million and $41.6 million for the years ended December 31, 2012, 2011 and 2010, respectively. NSTAR pension and PBOP expense is included in NU consolidated amounts from the date of the merger, April 10, 2012, through December 31, 2012.
We develop key assumptions for purposes of measuring liabilities as of December 31st and expenses for the subsequent year. These assumptions include the long-term rate of return on plan assets, discount rate, compensation/progression rate, and health care cost trend rates and are discussed below.
Long-Term Rate of Return on Plan Assets: In developing this assumption, we consider historical and expected returns and input from our actuaries and consultants. Our expected long-term rate of return on assets is based on assumptions regarding target asset allocations and corresponding expected rates of return for each asset class. We routinely review the actual asset allocations and periodically rebalance the investments to the targeted asset allocations when appropriate. For the year ended December 31, 2012, our aggregate expected long-term rate of return assumptions of 8.25 percent on the NUSCO Pension and PBOP Plans and 7.30 percent for the NSTAR Pension and PBOP Plans were used to determine our Pension and PBOP expense. For the forecasted 2013 pension
and PBOP expense, our expected long-term rate of return of 8.25 percent for all plans was used, which reflects a change in target asset allocations within both the NUSCO and NSTAR Pension and PBOP Plans.
Discount Rate: Payment obligations related to the Pension Plans and PBOP Plans are discounted at interest rates applicable to the expected timing of each plan’s cash flows. The discount rate that is utilized in determining the pension and PBOP obligations is based on a yield-curve approach. This approach is based on a population of bonds with an average rating of AA based on bond ratings by Moody’s, S&P and Fitch, and uses bonds with above median yields within that population. The discount rates determined on this basis are 4.24 percent for the NUSCO Pension Plan, 4.13 percent for the NSTAR Pension Plan, 4.04 percent for the NUSCO PBOP Plans and 4.35 percent for the NSTAR PBOP Plan as of December 31, 2012.
Compensation/Progression Rate: This assumption reflects the expected long-term salary growth rate, which impacts the estimated benefits that pension plan participants receive in the future. We used a compensation/progression rate of 3.5 percent as of December 31, 2012 and 2011 for the NUSCO Pension Plan and 4 percent for the NSTAR Pension Plan as of December 31, 2012, which reflects our current expectation of future salary increases, including consideration of the levels of increases built into collective bargaining agreements.
Actuarial Determination of Expense: Pension and PBOP expense is determined by our actuaries and consists of service cost and prior service cost, interest cost based on the discounting of the obligations, amortization of actuarial gains and losses and amortization of the net transition obligation, offset by the expected return on plan assets. Actuarial gains and losses represent differences between assumptions and actual information or updated assumptions.
We determine the expected return on plan assets for the NUSCO Pension and PBOP Plans by applying our assumed rate of return to a four-year rolling average of plan asset fair values, which reduces year-to-year volatility. This calculation recognizes investment gains or losses over a four-year period from the years in which they occur. Investment gains or losses for this purpose are the difference between the calculated expected return and the actual return or loss based on the change in the fair value of assets during the year. As of December 31, 2012, investment gains and losses that remain to be reflected in the calculation of plan assets over the next four years were losses of $224.4 million and gains of $0.7 million for the NUSCO Pension Plan and PBOP Plans, respectively. As investment gains and losses are reflected in the average plan asset fair values, they are subject to amortization with other unrecognized actuarial gains or losses. The plans currently amortize unrecognized actuarial gains or losses as a component of pension and PBOP expense over the average future employee service period. As of December 31, 2012, the net unrecognized actuarial losses on the NUSCO Pension and PBOP Plan liabilities were $1.1 billion and $176.5 million, respectively. For the NSTAR Pension and PBOP Plans, the entire difference between the actual and expected return on plan assets as of December 31, 2012 is immediately reflected as a component of unrecognized actuarial gains or losses to be amortized over the estimated average future service period of the employees. As of December 31, 2012, the net unrecognized actuarial losses on the NSTAR Pension and PBOP Plan liabilities were approximately $724 million and $176 million, respectively.
Forecasted Expenses and Expected Contributions: Based upon the assumptions and methodologies discussed above, we estimate that the combined expense for the Pension and PBOP Plans will be $241 million and $46 million, respectively, in 2013. Pension and PBOP expense for subsequent years will depend on future investment performance, changes in future discount rates and other assumptions, and various other factors related to the populations participating in the plans. Pension and PBOP expense charged to earnings is net of the amounts capitalized.
We expect to continue our policy to contribute to the NUSCO PBOP Plans at the amount of PBOP expense excluding any curtailments and the NSTAR PBOP Plan at an amount that approximates benefit payments. NU's policy is to fund the Pension Plans annually in an amount at least equal to an amount that will satisfy the federal requirements. NU made contributions to the NUSCO Pension Plan totaling $197.4 million in 2012, of which $87.7 million was contributed by PSNH. NSTAR Electric contributed $25 million to the NSTAR Pension Plan in 2012. Our Pension Plan funded ratio (the value of plan assets divided by the funding target in accordance with the requirements and guidelines of the PPA) was 94.8 percent and 100.2 percent as of January 1, 2012 for the NUSCO Pension Plan and NSTAR Pension Plan, respectively. We currently estimate that aggregate contributions of $285 million to the Pension Plans will be made in 2013. Fluctuations in the average discount rate used to calculate expected contributions to the Pension Plans can have a significant impact on the amounts.
Sensitivity Analysis: The following represents the hypothetical increase to the Pension Plans’ (excluding SERP) and PBOP Plans’ reported annual cost as a result of a change in the following assumptions by 50 basis points:
Changes in pension and PBOP costs would not impact net income for the NSTAR Plans as their expenses are fully recovered in rates, which reconcile each year relative to the change in costs.
Health Care Cost: For the NUSCO PBOP Plans, the health care cost trend rate assumption is 7 percent, subsequently decreasing by 50 basis points per year to an ultimate rate of 5 percent in 2017. For the NSTAR PBOP Plan, the health care cost trend rate is 7.10 percent, subsequently decreasing to an ultimate rate of 4.50 percent in 2024. The effect of a hypothetical increase in the health care cost trend rate by one percentage point would be to have increased service and interest cost components of PBOP Plan expense by $8.9 million in 2012, with a $126.5 million impact on the postretirement benefit obligation.
See Note 10A, "Employee Benefits - Pension Benefits and Postretirement Benefits Other Than Pensions," to the consolidated financial statements for more information.
Goodwill: We recorded approximately $3.2 billion of goodwill associated with the merger with NSTAR on April 10, 2012. NU had existing goodwill of $0.3 billion related to Yankee Gas. NU has identified its reporting units for purposes of allocating goodwill as Electric Distribution, Electric Transmission and Natural Gas Distribution. Our reporting units for purposes of allocating and testing goodwill are consistent with our operating segments underlying our reportable segments. Electric Distribution and Electric Transmission reporting units include values for the respective components of CL&P, NSTAR Electric, PSNH and WMECO. The Natural Gas reporting unit includes the carrying values of NSTAR Gas and Yankee Gas.
We are required to test goodwill balances for impairment at least annually by applying a fair value-based test that requires us to use estimates and judgment. We have selected October 1st of each year as the annual goodwill impairment testing date. Goodwill impairment is deemed to exist if the carrying value of a reporting unit exceeds its estimated fair value and if the implied fair value of goodwill based on the estimated fair value of the reporting unit is less than the carrying amount of the goodwill. If goodwill were deemed to be impaired, it would be written down in the current period to the extent of the impairment.
We performed an impairment analysis as of October 1, 2012 for the Electric Distribution, Electric Transmission and Natural Gas Distribution reporting units. We determined that the fair value of the reporting units substantially exceeded the carrying values and no impairment exists. In performing the evaluation, we estimated the fair values of the reporting units and compared them to the carrying values of the reporting units, including goodwill. We estimated the fair values of the reporting units using a discounted cash flow approach and a market approach that analyzed company information and market transactions. This evaluation requires the input of several critical assumptions, including cash flow projections, operating cost escalation rates, rates of return, future growth rates, a risk-adjusted discount rate, long-term earnings and merger multiples of comparable companies.
We determine the discount rate using the capital asset pricing model methodology. This methodology uses a weighted average cost of capital in which the ROE is developed using risk-free rates, equity premiums and a beta representing the reporting unit’s volatility relative to the overall market. The resulting discount rate is intended to be comparable to a rate that would be applied by a market participant. The discount rate may change from year to year as it is based on external market conditions.
The 2012 goodwill impairment analysis resulted in a significant excess of fair value of our reporting units over the carrying value. The estimated fair value of our reporting units is sensitive to changes in assumptions, such as discount rates, peer company financial results, recent market transactions and forecasted cash flows.
Income Taxes: Income tax expense is estimated annually for each of the jurisdictions in which we operate. This process involves estimating current and deferred income tax expense or benefit and the impact of temporary differences resulting from differing treatment of items for financial reporting and income tax return reporting purposes. Such differences are the result of timing of the deduction for expenses, as well as any impact of permanent differences, non-tax deductible expenses, or other items, including items that directly impact our tax return as a result of a regulatory activity (flow-through items). The temporary differences and flow-through items result in deferred tax assets and liabilities that are included in the consolidated balance sheets. The income tax estimation process impacts all of our segments. We record income tax expense quarterly using an estimated annualized effective tax rate.
A reconciliation of expected tax expense at the statutory federal income tax rate to actual tax expense recorded is included in Note 11, "Income Taxes," to the consolidated financial statements.
We also account for uncertainty in income taxes, which applies to all income tax positions previously filed in a tax return and income tax positions expected to be taken in a future tax return that have been reflected on our balance sheets. We follow generally accepted accounting principles to address the methodology to be used in recognizing, measuring and classifying the amounts associated with tax positions that are deemed to be uncertain, including related interest and penalties. The determination of whether a tax position meets the recognition threshold under this guidance is based on facts and circumstances available to us. Once a tax position meets the recognition threshold, the tax benefit is measured using a cumulative probability assessment. Assigning probabilities in measuring a recognized tax position and evaluating new information or events in subsequent periods requires significant judgment and could change previous conclusions used to measure the tax position estimate. New information or events may include tax examinations or appeals (including information gained from those examinations), developments in case law, settlements of tax positions, changes in tax law and regulations, rulings by taxing authorities and statute of limitation expirations. Such information or events may have a significant impact on our financial position, results of operations and cash flows.
Accounting for Environmental Reserves: Environmental reserves are accrued when assessments indicate it is probable that a liability has been incurred and an amount can be reasonably estimated. Adjustments made to estimates of environmental liabilities could have a significant impact on earnings. We estimate these liabilities based on findings through various phases of the assessment, considering the most likely action plan from a variety of available remediation options (ranging from no action required to full site remediation and long-term monitoring), current site information from our site assessments, remediation estimates from third party engineering and remediation contractors, and our prior experience in remediating contaminated sites. Our estimates incorporate currently enacted state and federal environmental laws and regulations and data released by the EPA and other organizations. The estimates associated with each possible action plan are judgmental in nature partly because there are usually several different remediation options from which to choose. Our estimates are subject to revision in future periods based on actual costs or new information from other sources, including the level of contamination at the site, the extent of our responsibility or the extent of remediation required, recently enacted laws and regulations or a change in cost estimates due to certain economic factors.
For further information, see Note 12A, "Commitments and Contingencies - Environmental Matters," to the consolidated financial statements.
Fair Value Measurements: We follow fair value measurement guidance that defines fair value as the price that would be received for the sale of an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date (an exit price). We have applied this guidance to our Company's derivative contracts that are recorded at fair value, marketable securities held in NU’s supplemental benefit trust and WMECO’s spent nuclear fuel trust, the marketable securities held in CYAPC's and YAEC's nuclear decommissioning trusts, our valuations of investments in our pension and PBOP plans, and nonrecurring fair value measurements of nonfinancial assets such as goodwill and AROs.
Changes in fair value of the regulated company derivative contracts are recorded as Regulatory Assets or Liabilities, as we expect to recover the costs of these contracts in rates. These valuations are sensitive to the prices of energy and energy-related products in future years for which markets have not yet developed and assumptions are made.
We use quoted market prices when available to determine fair values of financial instruments. If quoted market prices are not available, fair value is determined using quoted prices for similar instruments in active markets, quoted prices for identical or similar instruments that are not active and model-derived valuations. When quoted prices in active markets for the same or similar instruments are not available, we value derivative contracts using models that incorporate both observable and unobservable inputs. Significant unobservable inputs utilized in the models include energy and energy-related product prices for future years for long-dated derivative contracts, future contract quantities under full requirements and supplemental sales contracts, and market volatilities. Discounted cash flow valuations incorporate estimates of premiums or discounts, reflecting risk adjusted profit that would be required by a market participant to arrive at an exit price, using available historical market transaction information. Valuations of derivative contracts also reflect our estimates of nonperformance risk, including credit risk.
For further information on market risk, see Item 7A, "Quantitative and Qualitative Disclosures about Market Risk," included in this Annual Report on Form 10-K.
For further information on derivative contracts and marketable securities, see Note 1I, "Summary of Significant Accounting Policies - Derivative Accounting," Note 5, "Derivative Instruments," and Note 6, "Marketable Securities," to the consolidated financial statements.
Other Matters
Accounting Standards Recently Adopted: For information regarding new accounting standards, see Note 1C, "Summary of Significant Accounting Policies - Recently Adopted Accounting Standards," to the consolidated financial statements.
Contractual Obligations and Commercial Commitments: Information regarding our contractual obligations and commercial commitments as of December 31, 2012 is summarized annually through 2017 and thereafter as follows:
(a)
Long-term debt maturities exclude fees and interest due for spent nuclear fuel disposal costs, net unamortized premiums and discounts, and other fair value adjustments.
(b)
Estimated interest payments on fixed-rate debt are calculated by multiplying the coupon rate on the debt by its scheduled notional amount outstanding for the period of measurement. Estimated interest payments on floating-rate debt are calculated by multiplying the average of the 2012 floating-rate resets on the debt by its scheduled notional amount outstanding for the period of measurement. This same rate is then assumed for the remaining life of the debt.
(c)
The capital lease obligations include imputed interest for NU and CL&P.
(d)
Amounts are not included on our consolidated balance sheets.
(e)
Other than the net mark-to-market changes on derivative contracts held by both the Regulated companies and NU Enterprises, these obligations are not included on our consolidated balance sheets.
(f)
Does not include unrecognized tax benefits for NU and CL&P as of December 31, 2012, as we cannot make reasonable estimates of the periods or the potential amounts of cash settlement with the respective taxing authorities. Also does not include an NU contingent commitment of approximately $40 million to an energy investment fund, which would be invested under certain conditions, as we cannot make reasonable estimates of the periods or the investment contributions.
(g)
Amount represents open purchase orders, excluding those obligations that are included in the capital leases, operating leases and estimated future annual long-term contractual costs. These payments are subject to change as certain purchase orders include estimates based on projected quantities of material and/or services that are provided on demand, the timing of which cannot be determined. Because payment timing cannot be determined, we include all open purchase order amounts in 2013.
(h)
These amounts represent NU's estimated minimum pension contributions to its qualified Pension Plan required under federal legislation. Contributions in 2014 through 2017 and thereafter will vary depending on many factors, including the performance of existing plan assets, valuation of the plan's liabilities and long-term discount rates, and are subject to change.
(i)
Excludes other long-term liabilities, including the unrecognized tax benefits described above, deferred contractual obligations, environmental reserves, employee medical insurance reserves ($17.4 million at NU and $11.3 million at CL&P), workers compensation and long-term disability insurance reserves ($50 million at NU and $19.9 million at CL&P) and the ARO liability reserves as we cannot make reasonable estimates of the timing of payments.
For further information regarding our contractual obligations and commercial commitments, see Note 8, "Short-Term Debt," Note 9, "Long-Term Debt," Note 10A, "Employee Benefits - Pension Benefits and Postretirement Benefits Other Than Pensions," Note 12B, "Commitments and Contingencies - Long-Term Contractual Arrangements," and Note 13, "Leases," to the consolidated financial statements.
RRB amounts are non-recourse to us, have no required payments over the next five years and are not included in this table. The Regulated companies' standard offer service contracts and default service contracts are also not included in this table.
Web Site: Additional financial information is available through our web site at www.nu.com.
RESULTS OF OPERATIONS - NORTHEAST UTILITIES AND SUBSIDIARIES
The following table provides the amounts and variances in operating revenues and expense line items for the consolidated statements of income for NU included in this Annual Report on Form 10-K for the years ended December 31, 2012, 2011, and 2010. The year ended December 31, 2012 amounts include the operations of NSTAR from the date of the merger, April 10, 2012, through December 31, 2012:
Comparison of 2012 to 2011:
Our Operating Revenues increased in 2012, as compared to 2011, due primarily to the addition of NSTAR, which included electric distribution revenues of approximately $1.7 billion, transmission revenues of approximately $50 million, natural gas revenues of approximately $200 million and other revenues of approximately $15 million, and the consolidation of CYAPC and YAEC revenues of approximately $40 million. Excluding the impact of NSTAR's operations and the consolidation of CYAPC and YAEC, our Operating Revenues decreased due to the following:
·
Lower electric distribution segment revenues related to the portions that are included in regulatory commission approved tracking mechanisms that recover certain incurred costs and do not impact earnings. The tracking mechanisms allow for rates to be changed periodically with overcollections refunded to customers or undercollections recovered from customers in future periods. The tracked electric distribution revenues decreased due primarily to lower energy and supply-related costs ($241.8 million), lower CL&P CTA revenues ($46.3 million), lower wholesale revenues ($44.4 million), lower retail transmission revenues ($17.8 million), partially offset by higher CL&P FMCC delivery-related revenues ($82.4 million), higher SCRC revenues at PSNH ($34.2 million) and higher CL&P retail SBC revenues ($22.5 million).
·
A decrease in natural gas segment revenues due primarily to a 4.3 percent decrease in Yankee Gas' sales volume related to the warmer than normal weather in the heating season of 2012, as compared to the heating season of 2011. In addition, there was a decrease in the cost of natural gas, which is fully recovered in revenues from sales to our customers.
Partially offset by:
·
Improved transmission segment revenues resulting from a higher level of investment in transmission infrastructure and the recovery of higher overall expenses, which are tracked and result in a related increase in revenues. The increase in expenses is directly related to the increase in transmission plant, primarily at WMECO, including costs associated with higher property taxes, depreciation and operation and maintenance expenses.
·
An increase at PSNH related to the sale of oil to a third party ($20.8 million) in the second quarter of 2012, resulting in a benefit to customers through lower ES rates that does not impact earnings.
·
The portion of electric distribution segment revenues that impacts earnings increased $8.8 million due primarily to CL&P regulatory incentives of $11.5 million and C&LM incentives of $6.2 million at CL&P, partially offset by a decrease in retail electric sales related to the warmer than normal winter weather in 2012, as compared to the winter of 2011.
Purchased Power, Fuel and Transmission increased in 2012, as compared to 2011, due primarily to the following:
Operations and Maintenance increased in 2012, as compared to 2011, due primarily to the addition of NSTAR's operations, which included operating expenses of $320.8 million and maintenance expense of $50.4 million. Excluding the impact of NSTAR's operations, Operations and Maintenance increased due primarily to:
·
Higher NU parent and other companies' expenses ($70.1 million) that were due primarily to the increase in costs related to the completion of NU’s merger with NSTAR ($55.9 million) and higher costs at NU’s unregulated contracting business related to an increased level of work in 2012 ($16.3 million).
·
The establishment of a reserve related to major storm restoration costs ($40 million) at CL&P and bill credits to customers at CL&P and WMECO ($25 million and $3 million, respectively) as a result of the Connecticut and Massachusetts settlement agreements. In addition, there were higher electric distribution business expenses ($31.6 million) mainly as a result of general and administrative expenses primarily related to higher pension costs.
Partially offsetting these increases was the absence in 2012 of the storm fund reserve established in 2011 to provide bill credits to residential customers as a result of the October 2011 snowstorm and to provide contributions to certain Connecticut charitable organizations ($30 million) at CL&P, a decrease in the amortization of the regulatory deferral allowed in the 2010 rate case decision ($21.4 million) at CL&P and lower maintenance costs at PSNH’s generation business due to less planned outage maintenance in 2012 ($17.8 million).
Depreciation increased in 2012, as compared to 2011, due primarily to the addition of NSTAR's utility plant balances ($148.4 million) and an increase as a result of the consolidation of CYAPC and YAEC ($40.3 million). Excluding the impact of NSTAR and the consolidation of CYAPC and YAEC, Depreciation increased due primarily to higher utility plant balances resulting from completed construction projects placed into service.
Amortization of Regulatory Assets, Net decreased in 2012, as compared to 2011, due primarily to a decrease in ES and TCAM amortization at PSNH ($46.9 million and $20.2 million, respectively), and higher CTA transition costs ($21.5 million) and lower CTA revenues ($46.3 million) at CL&P. Partially offsetting these decreases was an increase related to the addition of NSTAR's operations ($87.5 million), lower SBC costs ($7.6 million) and higher retail SBC revenues ($22.5 million) at CL&P, and an increase in SCRC amortization at PSNH ($13.5 million).
Amortization of RRBs increased in 2012, as compared to 2011, due primarily to the addition of NSTAR Electric’s amortization ($67.7 million).
Energy Efficiency Programs increased in 2012, as compared to 2011, due primarily to the addition of NSTAR's operations ($169.4 million). In addition, there was an increase in expenses at WMECO attributable to an increase in spending in accordance with DPU approved energy efficiency programs. The increase in energy efficiency spending is recovered in rates and therefore does not impact earnings.
Taxes Other Than Income Taxes increased in 2012, as compared to 2011, due primarily to the addition of NSTAR's operations ($96.4 million). In addition, there was an increase in property taxes as a result of an increase in Property, Plant and Equipment related to our regulated capital programs and an increase in the property tax rates.
(a) The 2012 results include the operations of NSTAR from the date of the merger, April 10, 2012, through December 31, 2012.
Interest Expense increased in 2012, as compared to 2011, due primarily to the addition of NSTAR's operations ($70.6 million). The additional increase in Interest on Long-Term Debt was a result of the $260 million in new long-term debt issuances in September 2011 and higher short-term borrowings resulting in higher interest expense.
(a) The 2012 results include the operations of NSTAR from the date of the merger, April 10, 2012, through December 31, 2012.
Other Income, Net decreased in 2012, as compared to 2011, due primarily to lower AFUDC related to equity funds at PSNH as the Clean Air Project was placed into service in September 2011, partially offset by net gains on the NU supplemental benefit trust in 2012, compared to net losses in 2011.
(a) The 2012 results include the operations of NSTAR from the date of the merger, April 10, 2012, through December 31, 2012.
Income Tax Expense increased in 2012, as compared to 2011, due primarily to higher pre-tax earnings ($141.4 million), less favorable adjustments for prior year’s taxes ($21.3 million) and lower items that directly impact our tax return as a result of regulatory actions (flow-through items) ($3.4 million), partially offset by Connecticut and Massachusetts settlement agreement impacts ($41 million) and merger impacts ($19.9 million).
Comparison of 2011 to 2010:
Operating Revenues
A summary of our retail electric sales and firm natural gas sales were as follows:
(1) The 2010 sales volumes for commercial customers have been adjusted to conform to current year presentation.
Our Operating Revenues decreased in 2011, as compared to 2010, due primarily to:
·
Lower electric distribution segment revenues related to the portions that are included in regulatory commission approved tracking mechanisms that recover certain incurred costs and do not impact earnings. The tracking mechanisms allow for rates to be changed periodically with overcollections refunded to customers or undercollections recovered from customers in future periods. The tracked electric distribution revenues decreased due primarily to lower energy and supply-related costs ($365.3 million), lower CTA revenues and stranded cost recoveries ($175.3 million), lower wholesale revenues ($85.2 million) and lower retail other revenues ($37.9 million), partially offset by higher CL&P FMCC delivery-related revenues ($28.6 million), higher retail transmission revenues ($12.2 million) and higher other tracked revenues ($28.7 million).
Partially offset by:
·
The portion of electric distribution segment revenues that impacts earnings increased $135.5 million due primarily to the rate case decisions that were effective during 2011.
·
Improved transmission segment revenues resulting from a higher level of investment in transmission infrastructure and the recovery of higher overall expenses, which are tracked and result in a related increase in revenues. The increase in expenses is directly related to the increase in transmission plant, including costs associated with higher property taxes, depreciation and operation and maintenance expenses. These were partially offset by a refund to transmission wholesale customers, compared to a recovery from those customers in 2010. The transmission rates provide for an annual reconciliation and recovery or refund of projected costs to actual costs. The difference between projected costs and actual costs are recovered from, or refunded to, customers each year.
Purchased Power, Fuel and Transmission decreased in 2011, as compared to 2010, due primarily to the following:
Operations and Maintenance increased in 2011, as compared to 2010, due primarily to:
·
Higher electric distribution expenses ($50.4 million) and higher natural gas expenses ($3.8 million), primarily related to CL&P’s establishment of a $30 million storm fund reserve 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 2011 snowstorm and to provide contributions to certain Connecticut charitable organizations. There were also higher boiler equipment and maintenance costs at PSNH’s generation business related to the absence in 2011 of insurance proceeds received in 2010 related to turbine damage, which reduced 2010 costs ($7.4 million). In addition, there were higher pension costs and higher general and administrative expenses. Partially offsetting these increases were lower costs that are recovered through distribution tracking mechanisms that have no earnings impact ($17.7 million), such as uncollectible expenses and customer Energy Independence Act incentives. In addition, there were lower transmission segment expenses ($8.1 million).
·
The partial amortization in 2011 of the allowed regulatory deferral, which was recorded in maintenance expense in 2010, as a result of the June 30, 2010 CL&P rate case decision ($54.9 million).
·
Higher NU parent and other companies expenses ($27.3 million) due primarily to higher costs at NU’s unregulated electrical contracting business related to an increased level of work in 2011 ($19.6 million), partially offset by a decrease in costs related to NU's then pending merger with NSTAR ($2.1 million).
Depreciation increased in 2011, as compared to 2010, due primarily to higher depreciation rates being used at PSNH and WMECO in 2011 as a result of distribution rate case decisions that were effective during 2011 and higher utility plant balances resulting from completed construction projects placed into service. Partially offsetting these increases was a lower depreciation rate being used at CL&P as a result of the distribution rate case decision that was effective July 1, 2010.
Amortization of Regulatory Assets, Net increased in 2011, as compared to 2010, due primarily to lower CTA transition costs ($197.7 million) partially offset by lower retail CTA revenue ($154.6 million) at CL&P, the absence in 2011 of the impact from the 2010 Healthcare Act related to income taxes ($26 million) and increases in ES amortization ($11.4 million) and TCAM amortization ($5.9 million) at PSNH. Partially offsetting these increases was lower amortization related to the previously deferred unrecovered stranded generation costs at CL&P ($38.2 million) and lower amortization of the SBC balance at CL&P ($29.7 million).
Amortization of Rate Reduction Bonds decreased in 2011, as compared to 2010, due to the maturity of CL&P’s RRBs in December 2010 and lower principal balances on the remaining PSNH and WMECO RRBs outstanding.
Energy Efficiency Programs increased in 2011, as compared to 2010, due primarily to an increase in expenses attributable to an increase in spending in accordance with DPU approved energy efficiency programs at WMECO.
Taxes Other Than Income Taxes increased in 2011, as compared to 2010, due primarily to an increase in property taxes as a result of an increase in Property, Plant and Equipment related to our capital program and an increase in the tax rate, offset by a decrease in the Connecticut Gross Earnings Tax due primarily to lower transmission segment revenues and lower CTA revenues in 2011, as compared to 2010.
(a) Percent greater than 100 percent not shown since it is not meaningful.
Interest Expense increased in 2011, as compared to 2010, due primarily to higher Other Interest in 2011, as compared to 2010, due to the prior year inclusion of a tax-related benefit, partially offset by lower Interest on RRBs in 2011, as compared to 2010, resulting from the maturity of CL&P’s RRBs in December 2010 and lower principal balances on the remaining PSNH and WMECO RRBs outstanding.
Other Income, Net decreased in 2011, as compared to 2010, due primarily to net losses on the NU supplemental benefit trust in 2011, compared to net gains in 2010, and the 2011 classification of C&LM and Energy Independence Act incentives; partially offset by higher AFUDC related to equity funds.
Income Tax Expense decreased in 2011, as compared to 2010, due primarily to the absence in 2011 of the impact from the 2010 Healthcare Act ($25.2 million), adjustments for prior year's taxes including adjustments to reconcile estimated taxes accrued to actual amounts reflected in our filed tax returns (return to provision adjustments) ($16.3 million), lower flow-through items ($4.6 million) and lower pre-tax earnings ($2.1 million); partially offset by higher state income taxes ($9.6 million).
RESULTS OF OPERATIONS - THE CONNECTICUT LIGHT AND POWER COMPANY AND SUBSIDIARY
The following table provides the amounts and variances in operating revenues and expense line items for the consolidated statements of income for CL&P included in this Annual Report on Form 10-K for the years ended December 31, 2012, 2011, and 2010:
Comparison of 2012 to 2011:
CL&P's Operating Revenues decreased in 2012, as compared to 2011, due primarily to:
·
A $133.6 million decrease in distribution revenues related to the portions that are included in PURA approved tracking mechanisms that recover certain incurred costs and do not impact earnings. The tracking mechanisms allow for rates to be changed periodically with overcollections refunded to customers or undercollections recovered from customers in future periods. The tracked distribution revenues decreased due primarily to lower GSC and FMCC supply-related revenues ($150.8 million), lower CTA revenues ($46.3 million), lower wholesale revenues ($33.5 million), and lower retail transmission revenues ($4.3 million). The lower GSC and FMCC supply-related revenues were due primarily to lower customer rates resulting from lower average supply prices and lower sales related to additional customer migration to third party electric suppliers in 2012. Partially offsetting these decreases were higher FMCC delivery-related revenues ($82.4 million) and higher retail SBC revenues ($22.5 million).
Partially offset by:
·
A $7.6 million increase in the portion of distribution revenues that impacts earnings in 2012, compared to 2011, due primarily to regulatory incentives of $11.5 million and C&LM incentives of $6.2 million, partially offset by lower sales volume related to warmer than normal winter weather in 2012, as compared to the winter of 2011.
·
A $7.2 million increase in transmission revenues resulting from an increased level of investment in transmission infrastructure and the recovery of higher overall expenses, which are subject to tracking mechanisms or processes (tracked) and result in a related increase in revenues. The increase in expenses is directly related to the increase in transmission plant, including costs associated with higher property taxes, depreciation and operation and maintenance expenses.
Purchased Power and Transmission decreased in 2012, as compared to 2011, due primarily to the following:
The decrease in GSC supply costs was due to lower average supply prices and lower sales. The lower sales were due primarily to additional customer migration to third party electric suppliers. These GSC supply costs are the contractual amounts CL&P must pay to
various suppliers that have been awarded the right to supply SS and LRS load through a competitive solicitation process. These costs are included in PURA approved tracking mechanisms and do not impact earnings.
Operations and Maintenance increased in 2012, as compared to 2011, due primarily to the establishment of a reserve related to major storm restoration costs ($40 million) and a bill credit to customers ($25 million) in the second quarter of 2012 as a result of the Connecticut settlement agreement. In addition, there were higher distribution business expenses as a result of higher general and administrative expenses primarily related to an increase in pension costs ($20.2 million) and higher routine distribution maintenance ($19.4 million). There were also higher distribution costs related to customer Energy Independence Act incentives, which are tracked and fully recoverable through tracking mechanisms ($6.5 million). Partially offsetting these increases was the absence in 2012 of the storm fund reserve established in 2011 to provide bill credits to residential customers as a result of the October 2011 snowstorm ($30 million) and a decrease in the amortization of the regulatory deferral allowed in the 2010 rate case decision ($21.4 million).
Depreciation increased in 2012, as compared to 2011, due primarily to higher utility plant balances resulting from completed construction projects placed into service related to CL&P’s capital programs.
Amortization of Regulatory Assets, Net decreased in 2012, as compared to 2011, due primarily to higher CTA transition costs ($21.5 million) and lower CTA revenues ($46.3 million). Partially offsetting these impacts were lower SBC costs ($7.6 million) and higher retail SBC revenues ($22.5 million).
(a) Percent greater than 100 percent not shown since it is not meaningful.
Interest on Long-Term Debt decreased in 2012, as compared to 2011, due primarily to the refinancing of the PCRBs at a lower interest rate in October 2011. Other Interest increased in 2012, as compared to 2011, due primarily to the absence of tax-related benefits recognized in 2011 and an increase in short-term borrowings resulting in higher interest expense.
Income Tax Expense
Income Tax Expense increased in 2012, as compared to 2011, due primarily to less favorable adjustments for prior year’s taxes ($22.4 million), an increase to pre-tax earnings ($13.8 million), partially offset by Connecticut settlement agreement impacts ($26.6 million), and lower state tax and other impacts ($5.2 million).
Comparison of 2011 to 2010:
Operating Revenues
CL&P's retail sales were as follows:
CL&P's Operating Revenues decreased in 2011, as compared to 2010, due primarily to:
·
A $545.4 million decrease in distribution revenues related to the portions that are included in PURA approved tracking mechanisms that recover certain incurred costs and do not impact earnings. The tracked distribution revenues decreased due primarily to lower GSC and FMCC supply-related revenues ($316.4 million), lower CTA revenues ($165.5 million), lower wholesale revenues ($81.7 million) and lower retail other revenues ($38.4 million). The lower GSC and FMCC supply-related revenues were due primarily to lower customer rates resulting from lower average supply prices and additional customer migration to third party electric suppliers in 2011, as compared to 2010. These lower revenues were partially offset by higher FMCC delivery-related revenues ($28.6 million) and higher retail transmission revenues ($14 million). The tracking mechanisms allow for rates to be changed periodically with overcollections refunded to customers or undercollections recovered from customers in future periods.
·
A $15.7 million decrease in transmission segment revenues was due primarily to a refund to transmission wholesale customers, compared to a recovery from those customers in 2010. The transmission rates provide for an annual reconciliation and recovery or refund of projected costs to actual costs. The difference between projected costs and actual costs are recovered from, or refunded to, customers each year. This decrease was partially offset by increased transmission segment revenues due to a higher level of investment in the transmission infrastructure.
Partially offset by:
·
The portion of distribution revenues that impacts earnings increased $110.4 million in 2011, as compared to 2010, due primarily to the retail rate increase effective January 1, 2011.
Purchased Power and Transmission decreased in 2011, as compared to 2010, due primarily to the following:
The decrease in GSC supply costs was due primarily to lower average supply prices and additional customer migration to third party electric suppliers in 2011, as compared to 2010. These GSC supply costs are the contractual amounts CL&P must pay to various suppliers that have been awarded the right to supply SS and LRS load through a competitive solicitation process. These costs are included in PURA approved tracking mechanisms and do not impact earnings.
Operations and Maintenance increased in 2011, as compared to 2010, as a result of higher distribution expenses ($60.4 million). Included in these costs was the establishment of a $30 million storm fund reserve 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 2011 snowstorm and to provide contributions to certain Connecticut charitable organizations, higher general and administrative expenses, including higher pension costs. In addition, there was an increase related to the partial amortization in 2011 of the allowed regulatory deferral, which was recorded in maintenance expense in 2010, as a result of the June 30, 2010 rate case decision ($54.9 million). Partially offsetting these increases were lower costs that are recovered through distribution tracking mechanisms and have no earnings impact ($16.4 million) and lower transmission segment expenses ($7.4 million).
Depreciation decreased in 2011, as compared to 2010, due primarily to a lower depreciation rate being used as a result of the 2010 distribution rate case decision that was effective July 1, 2010, partially offset by higher utility plant balances resulting from completed construction projects placed into service.
Amortization of Regulatory Assets, Net decreased in 2011, as compared to 2010, due primarily to lower amortization related to the previously deferred unrecovered stranded generation costs ($38.2 million) and lower amortization of the SBC balance ($29.7 million). Partially offsetting these decreases were lower CTA transition costs ($197.7 million), partially offset by lower retail CTA revenue ($154.6 million), and the absence in 2011 of the impact from the 2010 Healthcare Act related to income taxes ($12 million).
Amortization of Rate Reductions Bonds decreased in 2011, as compared to 2010, due to the maturity of RRBs in December 2010.
Taxes Other Than Income Taxes decreased in 2011, as compared to 2010, due primarily to a decrease in the Connecticut Gross Earnings Tax due primarily to lower transmission segment revenues and lower CTA revenues in 2011, as compared to 2010, partially offset by an increase in property taxes as a result of an increase in Property, Plant and Equipment related to CL&P’s capital program and an increase in the tax rate.
Interest Expense
(a) Percent greater than 100 percent not shown since it is not meaningful
Interest Expense decreased in 2011, as compared to 2010, due primarily to the absence of Interest on RRBs in 2011, as CL&P's RRBs matured in December 2010, and lower Interest on Long-Term Debt in 2011 related to lower interest rates on the refinancing of the PCRBs. Partially offsetting these decreases was higher Other Interest in 2011, as compared to 2010, due to the prior year inclusion of a tax-related benefit.
Other Income, Net
Other Income, Net decreased in 2011, as compared to 2010, due primarily to net losses on the NU supplemental benefit trust in 2011, compared to net gains in 2010, as well as the 2011 classification of C&LM and Energy Independence Act incentives.
Income Tax Expense
Income Tax Expense decreased in 2011, as compared to 2010, due primarily to the absence in 2011 of the impact from the 2010 Healthcare Act ($13.2 million), adjustments for prior year’s taxes including return to provision ($16.7 million), a decrease in pre-tax earnings ($7.3 million) and lower flow-through and other impacts ($5.2 million).
LIQUIDITY
CL&P had cash flows provided by operating activities of $211.9 million in 2012, compared with cash flows provided by operating activities of $513.3 million in 2011. The reduced cash flows were due primarily to $223.1 million of cash disbursements for storm restoration costs primarily associated with Tropical Storm Irene, the October 2011 snowstorm, and Hurricane Sandy made in 2012, as compared to approximately $132 million in 2011, $27 million in bill credits provided to residential customers in February 2012 related to the October 2011 snowstorm, $25 million in bill credits to customers associated with the Connecticut settlement agreement and changes in traditional working capital amounts principally due to the changes in the timing of payments of accounts payable and accrued liabilities. In addition, CL&P had lower recovery of its deferred operation and maintenance costs of $23.1 million in 2012, as
compared to 2011, a negative cash flow impact of $38.9 million resulting from changes in reserves for transmission refunds in 2012, as compared to 2011, and a decrease in income tax refunds of $14.6 million in 2012, as compared to 2011.
CL&P had cash flows provided by operating activities in 2011 of $513.3 million, compared with operating cash flows of $501.7 million in 2010 (2010 amount is net of RRB payments, which is included in financing activities). The improved cash flows in 2011 were due primarily to the impact of the PURA July 1, 2010 distribution rate case decision, which increased CL&P’s customer rates effective January 1, 2011, and income tax receipts in 2011 of $27.5 million largely attributable to accelerated depreciation tax benefits, compared to income tax payments of $71.5 million in 2010. Offsetting these benefits was approximately $132 million of cash disbursements for storm restoration costs associated with Tropical Storm Irene and the October 2011 snowstorm.
Cash capital expenditures included on the accompanying consolidated statements of cash flows do not include amounts incurred on capital projects but not yet paid, cost of removal, the AFUDC related to equity funds, and the capitalized portions of pension and PBOP expense or income. CL&P's cash capital expenditures totaled $449.1 million in 2012, compared with $424.9 million in 2011.
On March 22, 2012, the FERC approved CL&P's application requesting to increase its total short-term borrowing capacity from a maximum of $450 million to a maximum of $600 million through December 31, 2013.
On March 26, 2012, CL&P entered into a five-year $300 million unsecured revolving credit facility. The credit facility is intended to finance short-term borrowings that CL&P incurred to fund costs of restoring power following Tropical Storm Irene and the October 2011 snowstorm. Under this new facility, CL&P can borrow either on a short-term or a long-term basis subject to any necessary regulatory approval, and may borrow at prime rates or LIBOR-based rates, plus an applicable margin based on the higher of S&P’s or Moody’s credit ratings. As of December 31, 2012, CL&P had $89 million in borrowings outstanding under this credit facility. The weighted-average interest rate on these borrowings as of December 31, 2012 was 3.325 percent.
On April 2, 2012, CL&P remarketed $62 million of tax-exempt PCRBs that were subject to mandatory tender on that date. The PCRBs, which mature on May 1, 2031, carry a coupon rate of 1.55 percent during the current three-year fixed-rate period, and are subject to mandatory tender for purchase on April 1, 2015.
On July 25, 2012, NU, CL&P, NSTAR LLC, NSTAR Gas, PSNH, WMECO, and Yankee Gas jointly entered into a five-year $1.15 billion revolving credit facility. The new facility replaced (1) the NSTAR LLC revolving credit facility of $175 million that served to backstop a commercial paper program utilized by NSTAR LLC and was scheduled to expire on December 31, 2012, (2) the NSTAR Gas revolving credit facility of $75 million that expired on June 8, 2012, and (3) the CL&P, PSNH, WMECO, and Yankee Gas joint $400 million and NU parent $500 million unsecured revolving credit facilities that were scheduled to expire on September 24, 2013. The new facility expires on July 25, 2017. As of December 31, 2012, CL&P had $405.1 million in intercompany short-term borrowings under the NU commercial paper program. The weighted average interest rate on these borrowings as of December 31, 2012 was 0.46 percent.
On October 1, 2012, CL&P redeemed at par four different series of tax-exempt PCRBs totaling $116.4 million. The PCRBs carried coupons that ranged from 5.85 percent to 5.95 percent and maturities that ranged from 2016 through 2028.
On January 15, 2013, CL&P issued $400 million of 2.5 percent first mortgage bonds that will mature on January 15, 2023. The proceeds, net of issuance costs, were used to repay CL&P’s revolving credit facility borrowings of $89 million and $305.8 million of its commercial paper program borrowings.
Financing activities in 2012 included $100.5 million in common stock dividends paid to NU parent, an increase in intercompany short-term borrowings of $346.6 million, and an increase in short-term notes payable of $58 million.
CL&P uses available capital resources to fund its construction expenditures, meet debt requirements, pay costs, including storm-related costs, pay dividends and fund its other obligations. The current growth in CL&P’s transmission construction expenditures utilizes a significant amount of cash for projects that have a long-term return on investment and recovery period. In addition, CL&P operates in an environment where recovery of its distribution construction expenditures takes place over an extended period of time. As well, the future recovery of its deferred storm-related costs, which must be approved by the PURA, will take place over a six-year period for those costs deferred as a result of 2011 activity (as covered by the Connecticut Settlement Agreement) and over an extended period of time for those storm restoration costs incurred related to Hurricane Sandy. This impacts the timing of the revenue stream designed to fully recover the total investment plus a return on the equity portion of the cost and related financing costs. These factors have resulted in CL&P’s current liabilities exceeding current assets by approximately $268 million as of December 31, 2012.
As of December 31, 2012, $125 million of CL&P's current liabilities relates to long-term debt that will be paid in the next 12 months. CL&P, with its strong credit ratings, has several options available in the financial markets to repay or refinance these maturities with the issuance of new long-term debt. CL&P will reduce its short-term borrowings with cash received from operating cash flows or with the issuance of new long-term debt, as deemed appropriate given our capital requirements and maintenance of our credit rating and profile. Management expects the future operating cash flows of CL&P, along with the access to financial markets, will be sufficient to meet any future operating requirements and capital investment forecasted opportunities.
RESULTS OF OPERATIONS - NSTAR ELECTRIC COMPANY AND SUBSIDIARIES
The following table provides the amounts and variances in operating revenues and expense line items for the consolidated statements of income for NSTAR Electric included in this Annual Report on Form 10-K for the years ended December 31, 2012, 2011, and 2010:
NSTAR Electric's Operating Revenues decreased in 2012, as compared to 2011, due primarily to:
·
A $104.7 million decrease in distribution revenues related to the portions that are included in DPU approved tracking mechanisms that recover certain incurred costs and do not impact earnings. The tracking mechanisms allow for rates to be changed periodically with overcollections refunded to customers or undercollections recovered from customers in future periods. This decrease primarily related to lower purchased power and transmission costs ($34.2 million), lower retail transmission revenues ($19.8 million), lower PAM revenues ($19.1 million), lower transition revenues ($14.7 million), partially offset by an increase in energy efficiency program revenues ($8.3 million).
Partially offset by:
·
A $2.8 million increase in transmission revenues resulting from an increased level of investment in transmission infrastructure and the recovery of higher overall expenses, which are tracked and result in a related increase in revenues. The increase in expenses is directly related to the increase in transmission plant, including costs associated with higher property taxes, depreciation and operation and maintenance expenses.
Purchased Power and Transmission decreased in 2012, as compared to 2011, due primarily to the following:
The decrease in Basic Service costs was due primarily to lower average supply prices and additional customer migration to third party electric suppliers and the decrease in purchased power contracts was due primarily to the expiration of certain contracts. The decrease in transmission costs was due primarily to a lower transmission cost deferral that will be recovered in future periods. The increase in deferred fuel costs was due primarily to lower average supply prices, as compared to the prices projected when Basic Service rates were set. These costs are included in DPU approved tracking mechanisms and do not impact earnings.
Operations and Maintenance increased in 2012, as compared to 2011, due primarily to the cumulative adjustment recorded to establish a reserve against the regulatory asset related to Basic Service bad debt costs ($28 million). In addition, first quarter 2012 adjustments were recognized for changes in accounting estimates related primarily to the allowance for doubtful accounts, workers’ compensation, employee medical benefits, and general liability claims ($18.7 million). In addition, a bill credit to customers ($15 million) was recorded in the second quarter of 2012 as a result of the Massachusetts settlement agreement. Also contributing to the increase in costs was an incident in March 2012 involving a substation fire in the Back Bay/Prudential area of Boston ($11.8 million). These increases were partially offset by lower PAM-related amortizations ($23.1 million).
Amortization of Regulatory Assets, Net, increased in 2012, as compared to 2011, due primarily to higher amortization related to transition costs.
Energy Efficiency Programs increased in 2012, as compared to 2011, due primarily to the establishment of a reserve to reflect a billing adjustment made in the fourth quarter of 2012, and an increase in energy efficiency costs in accordance with the three-year program guidelines established by the DPU. All costs are fully recovered through DPU tracking mechanisms and therefore do not impact earnings.
Interest Expense
Other Interest expense increased in 2012, as compared to 2011, due primarily to a reduction in regulatory interest income primarily from deferred transition costs ($5.9 million) and reduced interest income from legal matters ($3.2 million), partially offset by a decrease in the interest expense related to tax issues ($2 million) due to the receipt of a 2001 through 2007 tax settlement in June 2011.
Income Tax Expense
Income Tax Expense decreased in 2012, as compared to 2011, due primarily to lower pre-tax earnings ($33.6 million), Massachusetts settlement agreement impacts ($5.9 million) and merger impacts ($1.2 million).
EARNINGS SUMMARY
The after-tax merger settlement agreement costs in 2012 consisted of approximately $17.9 million (pre-tax) of charges for customer bill credits related to the Massachusetts settlement agreement, transaction and integration-related costs, and compensation costs.
Excluding the merger settlement agreement costs, NSTAR Electric’s 2012 earnings were $51.4 million lower than 2011 due primarily to the first quarter 2012 adjustments recorded to establish a reserve against the regulatory asset related to Basic Service bad debt costs ($17 million), and for changes in accounting estimates related primarily to the allowance for doubtful accounts, workers’ compensation, employee medical benefits, and general liability claims ($11.4 million). Also contributing to the increase in costs was an incident in March 2012 involving a substation fire in the Back Bay/Prudential area of Boston ($7.2 million), a reserve recorded relating to lost base revenues based on developments during hearings in the merger proceeding ($3 million) and higher depreciation and property taxes ($17.3 million). These factors are partially offset by higher transmission revenues due to an increased level of investment in transmission infrastructure ($6.2 million).
NSTAR Electric’s 2011 earnings were $252.5 million, compared to $248.6 million in 2010. Major factors on an after-tax basis that contributed to the $3.9 million, increase include:
·
higher transmission revenues ($10.9 million);
·
higher lost base revenues and performance incentives related to the impacts of the Energy Efficiency Programs ($7 million); and
·
the absence in 2011 of the cumulative impact of a true-up adjustment resulting from a DPU order in May 2010 related to NSTAR Electric’s transition revenue for the years 2006 through 2009 ($3 million).
These increases were partially offset by:
·
lower distribution revenues (0.7 percent decrease in sales) due to cooler summer weather in 2011, as compared to the summer of 2010, and the impact of energy conservation programs ($5.4 million);
·
higher depreciation and property taxes ($7.3 million); and
·
higher operations and maintenance expenses ($8.8 million).
CAPITAL EXPENDITURES
A summary of capital expenditures, including amounts incurred but not paid, cost of removal, AFUDC, and the capitalized portions of pension and PBOP expense or income, is as follows:
LIQUIDITY
NSTAR Electric had cash flows provided by operating activities of $506.9 million in 2012 and $662 million in 2011 (amounts are net of RRB payments, which are included in financing activities). The decreased cash flows in 2012 were due primarily to the absence in 2012 of income tax refunds received during 2011. In 2012, NSTAR Electric made income tax payments of $88.1 million, as compared to income tax refunds of $62.2 million in 2011. In addition, NSTAR Electric provided $15 million in bill credits to its customers associated with the Massachusetts settlement agreement in 2012, and had regulatory undercollections of retail transmission revenues of $53 million in 2012, as compared to 2011. Partially offsetting these negative cash flow impacts was a reduction in Pension Plan contributions of $100 million in 2012, as compared to 2011.
RESULTS OF OPERATIONS - PUBLIC SERVICE COMPANY OF NEW HAMPSHIRE AND SUBSIDIARIES
The following table provides the amounts and variances in operating revenues and expense line items for the consolidated statements of income for PSNH included in this Annual Report on Form 10-K for the years ended December 31, 2012 and 2011:
PSNH's Operating Revenues decreased in 2012, as compared to 2011, due primarily to:
·
A $52.7 million decrease in distribution revenues related to the portions that are included in NHPUC approved tracking mechanisms that recover certain incurred costs and do not impact earnings. The tracking mechanisms allow for rates to be changed periodically with overcollections refunded to customers or undercollections recovered from customers in future periods. This decrease related primarily to lower purchased power and fuel costs ($88.3 million), lower wholesale revenues ($7.3 million) and lower retail transmission revenues ($5.8 million). These lower revenues were partially offset by higher SCRC revenues ($34.2 million) and RECs ($9.5 million).
Partially offset by:
·
An increase related to the sale of oil to a third party ($20.8 million) in the second quarter of 2012, resulting in a benefit to customers through lower ES rates that does not impact earnings.
·
A $9.9 million increase in transmission revenues resulting from an increased level of investment in transmission infrastructure and the recovery of higher overall expenses, which are tracked and result in a related increase in revenues. The increase in expenses is directly related to the increase in transmission plant, including costs associated with higher property taxes, depreciation and operation and maintenance expenses.
·
A $3.5 million increase in the portion of distribution revenues that impacts earnings in 2012, as compared to 2011, due primarily to the favorable impact of the 2010 rate case decision related to the additional increase to annualized rates that was effective July 1, 2012.
Purchased Power, Fuel and Transmission decreased in 2012, as compared to 2011, due primarily to a decrease in purchased power costs, partially offset by an increase in transmission costs. The decrease in purchased power costs was due primarily to lower market prices in 2012, as compared to 2011, as well as an increase in ES customer migration to third party suppliers.
Operations and Maintenance decreased in 2012, as compared to 2011, as a result of lower maintenance costs at the generation business due to less planned outage maintenance in 2012 ($17.8 million), partially offset by higher distribution general and administrative costs ($3 million).
Depreciation increased in 2012, as compared to 2011, due primarily to higher utility plant balances resulting from completed construction projects placed into service related to PSNH's capital programs.
Amortization of Regulatory Assets/(Liabilities), Net decreased in 2012, as compared to 2011, due primarily to a decrease in ES and TCAM amortization ($46.9 million and $20.2 million, respectively), partially offset by an increase in SCRC amortization ($13.5 million).
Taxes Other Than Income Taxes increased in 2012, as compared to 2011, due primarily to an increase in property taxes as a result of an increase in Property, Plant and Equipment related to PSNH’s capital program and an increase in the property tax rates.
Interest Expense
Interest Expense increased in 2012, as compared to 2011, due primarily to an increase in Interest on Long-Term Debt, which was primarily the result of a reduction in AFUDC related to borrowed funds as the Clean Air Project was placed into service in September 2011 ($5.5 million). The additional increase in Interest on Long-Term Debt was a result of the $160 million long-term debt issuance in September 2011.
Other Income, Net
Other Income, Net decreased in 2012, as compared to 2011, due primarily to lower AFUDC related to equity funds as the Clean Air Project was placed into service in September 2011.
Income Tax Expense
Income Tax Expense increased in 2012, as compared to 2011, due primarily to lower flow-through items ($4.1 million), higher state taxes ($3.8 million), an increase in pre-tax earnings ($2.7 million) and return to provision ($0.8 million).
LIQUIDITY
PSNH had cash flows provided by operating activities in 2012 of $174.2 million, compared with operating cash flows of $151.8 million in 2011 (amounts are net of RRB payments, which are included in financing activities). The improved cash flows in 2012 were due primarily to a reduction in NU Pension Plan contributions of $24.9 million in 2012, as compared to 2011, the absence in 2012 of a cash flow hedge settlement creating a favorable cash flow impact of $18.1 million, and an increased reduction in coal and fuel inventories in 2012. The reduction in fuel inventories in 2012 is primarily attributable to the sale of oil to a third party for $20.8 million. Offsetting these positive cash flow impacts were income tax payments in 2012 of $14.7 million, as compared to income tax refunds in 2011 of $29.3 million.
RESULTS OF OPERATIONS - WESTERN MASSACHUSETTS ELECTRIC COMPANY AND SUBSIDIARY
The following table provides the amounts and variances in operating revenues and expense line items for the consolidated statements of income for WMECO included in this Annual Report on Form 10-K for the years ended December 31, 2012 and 2011:
WMECO's Operating Revenues increased in 2012, as compared to 2011, due primarily to:
·
A $32.3 million increase in transmission revenues resulting from an increased level of investment in transmission infrastructure, primarily related to the NEEWS projects, and the recovery of higher overall expenses, which are tracked and result in a related increase in revenues. The increase in expenses is directly related to the increase in transmission plant, including costs associated with higher property taxes, depreciation and operation and maintenance expenses.
·
An increase in the portion of distribution revenues that impacts earnings related to the absence in 2012 of the establishment of a reserve related to a wholesale billing adjustment in the third quarter of 2011 ($5 million).
Partially offset by:
·
A $5.2 million decrease in distribution revenues related to the portions that are included in DPU approved tracking mechanisms that recover certain incurred costs and do not impact earnings. The tracking mechanisms allow for rates to be changed periodically with overcollections refunded to customers or undercollections recovered from customers in future periods. Included in these amounts are Basic Service, pension, transition and energy efficiency program costs.
Purchased Power and Transmission decreased in 2012, as compared to 2011, due primarily to lower purchased transmission costs ($14 million), lower Basic Service costs ($7 million) and lower purchased power costs ($3.4 million).
Operations and Maintenance increased in 2012, as compared to 2011, due to an increase in distribution business expenses primarily related to higher pension costs ($3.9 million), which are recovered through DPU approved tracking mechanisms and have no earnings impact. There were also higher routine distribution overhead line maintenance costs ($2.7 million), higher transmission operating costs ($2 million) and higher uncollectible expenses ($1.9 million). In addition, there was a bill credit to customers ($3 million) in the second quarter of 2012 as a result of the Massachusetts settlement agreement.
Depreciation increased in 2012, as compared to 2011, due primarily to higher utility plant balances resulting from completed construction projects placed into service related to WMECO's capital programs.
Amortization of Regulatory Assets, Net decreased in 2012, as compared to 2011, due primarily to a decrease in amortization of the transition charge deferral.
Energy Efficiency Programs increased in 2012, as compared to 2011, due primarily to an increase in expenses attributable to an increase in spending in accordance with DPU approved energy efficiency programs. The increase in energy efficiency spending is recovered in rates and therefore does not impact earnings.
Taxes Other Than Income Taxes increased in 2012, as compared to 2011, due primarily to an increase in property taxes as a result of an increase in Property, Plant and Equipment related to WMECO’s capital program and an increase in the property tax rates.
Interest Expense
Interest Expense increased in 2012, as compared to 2011, due primarily to higher Interest on Long-Term Debt resulting from a $100 million long-term debt issuance in September 2011 and a $150 million long-term debt issuance on October 4, 2012.
Income Tax Expense
Income Tax Expense increased in 2012, as compared to 2011, due primarily to higher pre-tax earnings ($9.2 million) and higher state taxes ($2.4 million), partially offset by Massachusetts settlement agreement impacts ($1.2 million) and a regulatory decision that reduced a non-plant flow through difference ($1.3 million).
LIQUIDITY
WMECO had cash flows provided by operating activities in 2012 of $77 million, compared with operating cash flows of $108 million in 2011 (amounts are net of RRB payments, which are included in financing activities). The reduced cash flows in 2012 were due primarily to unfavorable cash flow impacts of $6.6 million relating to C&LM and $16.1 million relating to the change in transmission regulatory tracking mechanisms. In addition, WMECO paid $3 million in bill credits to customers in 2012 associated with the Massachusetts settlement agreement.
Item 7A.
Item 7A.
Quantitative and Qualitative Disclosures about Market Risk
Market Risk Information
Commodity Price Risk Management: Our Regulated companies enter into energy contracts to serve our customers and the economic impacts of those contracts are passed on to our customers. Accordingly, the Regulated companies have no exposure to loss of future earnings or fair values due to these market risk-sensitive instruments.
The remaining unregulated wholesale portfolio held by Select Energy includes contracts that are market risk-sensitive, including a wholesale energy sales contract through December 31, 2013 with an agency comprised of municipalities and related purchase agreements. We have not entered into any energy contracts for trading purposes. As Select Energy's contract volumes are winding down, and as the wholesale energy sales contract is substantially hedged against price risks, we have limited exposure to commodity price risks. For Select Energy's wholesale energy portfolio derivatives, we utilize the sensitivity analysis methodology to disclose quantitative information of the potential loss of future pre-tax earnings for one or more hypothetical changes in commodity price components. A hypothetical 30 percent increase or decrease in forward energy, ancillary or capacity prices would not have a material impact on earnings. The method we use to determine the fair value of these contracts includes discounting expected future cash flows using a LIBOR swap curve. As such, the wholesale portfolio is also exposed to interest rate volatility. This exposure is not modeled in sensitivity analyses, and we do not believe that such exposure is material.
Other Risk Management Activities
We have implemented an Enterprise Risk Management methodology for identifying the principal risks of the Company. Enterprise Risk Management involves the application of a well-defined, enterprise-wide methodology that enables our Risk and Capital Committee, comprised of our senior officers, to oversee the identification, management and reporting of the principal risks of the business. Our management analyzes risks to determine materiality and other attributes such as likelihood and impact, velocity, and mitigation strategies. Management broadly considers our business model, the utility industry, the global economy and the current environment to identify risks.
However, there can be no assurances that the Enterprise Risk Management process will identify or manage every risk or event that could impact our financial position, results of operations or cash flows. The findings of this process are periodically discussed with our Board of Trustees.
Interest Rate Risk Management: As of December 31, 2012, approximately 91 percent of our long-term debt, including fees and interest due for spent nuclear fuel disposal costs, was at a fixed interest rate. The remaining long-term debt is at variable interest rates and is subject to interest rate risk that could result in earnings volatility. Assuming a one percentage point increase in our variable interest rate, annual interest expense would have increased by a pre-tax amount of $8.7 million.
Credit Risk Management: Credit risk relates to the risk of loss that we would incur as a result of non-performance by counterparties pursuant to the terms of our contractual obligations. We serve a wide variety of customers and 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 we realize interest receipts and payments related to balances outstanding in these margin accounts. This wide customer and supplier mix generates a need for a variety of contractual structures, products and terms that, in turn, require us to manage the portfolio of market risk inherent in those transactions in a manner consistent with the parameters established by our risk management process.
Our Regulated companies are subject to credit risk from certain long-term or high-volume supply contracts with energy marketing companies. Our Regulated companies manage the credit risk with these counterparties in accordance with established credit risk practices and monitor contracting risks, including credit risk. As of December 31, 2012, our Regulated companies did not hold cash collateral from counterparties. As of December 31, 2012, NU had cash posted with ISO-NE related to energy purchase transactions. In addition, Select Energy has also established written credit policies with regard to its counterparties to minimize overall credit risk on its remaining contracts. These policies require collateral under certain circumstances (including cash in advance and parent guarantees), and the use of standardized agreements, which allow for the netting of positive and negative exposures associated with a single counterparty in the event of default.
For further information on cash collateral deposited and posted with counterparties as well as any cash collateral netted against the fair value of the related derivative contracts, see Note 1G, "Summary of Significant Accounting Policies - Restricted Cash and Other Deposits," and Note 5, "Derivative Instruments," to the consolidated financial statements.
If the respective unsecured debt ratings of NU or its subsidiaries were reduced to below investment grade by either Moody’s or S&P, certain of NU’s contracts would require additional collateral in the form of cash to be provided to counterparties and independent system operators. NU would have been and remains able to provide that collateral.
Item 8.
Item 8.
Financial Statements and Supplementary Data
NU
Company Report on Internal Controls Over Financial Reporting
Report of Independent Registered Public Accounting Firm
Consolidated Financial Statements
CL&P
Company Report on Internal Controls Over Financial Reporting
Report of Independent Registered Public Accounting Firm
Consolidated Financial Statements
NSTAR Electric
Company Report on Internal Controls Over Financial Reporting
Reports of Independent Registered Public Accounting Firms
Consolidated Financial Statements
PSNH
Company Report on Internal Controls Over Financial Reporting
Report of Independent Registered Public Accounting Firm
Consolidated Financial Statements
WMECO
Company Report on Internal Controls Over Financial Reporting
Report of Independent Registered Public Accounting Firm
Consolidated Financial Statements
Company Report on Internal Controls Over Financial Reporting
Northeast Utilities
Management is responsible for the preparation, integrity, and fair presentation of the accompanying consolidated financial statements of Northeast Utilities and subsidiaries (NU or the Company) and of other sections of this annual report. NU’s internal controls over financial reporting were audited by Deloitte & Touche LLP.
Management is responsible for establishing and maintaining adequate internal controls over financial reporting. The Company’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 the 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 internal controls over financial reporting were effective as of December 31, 2012.
Management has excluded from our assessment of and conclusion on the effectiveness of internal controls over financial reporting the internal controls of NSTAR LLC, acquired on April 10, 2012, which is included in the consolidated financial statements of the Company as of and for the year ended December 31, 2012, constituting $11.3 billion and $5.1 billion of total and net assets, respectively, as of December 31, 2012, and $1,957.8 million and $182.9 million of revenues and net income attributable to controlling interest, respectively, for the period from April 10, 2012 through December 31, 2012.
February 27, 2013
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
To the Board of Trustees and Shareholders of Northeast Utilities:
We have audited the accompanying consolidated balance sheets of Northeast Utilities and subsidiaries (the "Company") as of December 31, 2012 and 2011, and the related consolidated statements of income, comprehensive income, common shareholders’ equity, and cash flows for each of the three years in the period ended December 31, 2012. Our audits also included the financial statement schedules listed in the Index at Item 15 of Part IV. We also have audited the Company's internal control over financial reporting as of December 31, 2012, based on criteria established in Internal Control - Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission. The Company's management is responsible for these financial statements and financial statement schedules, for maintaining effective internal control over financial reporting, and for its assessment of the effectiveness of internal control over financial reporting, included in the accompanying Company Report on Internal Controls Over Financial Reporting. Our responsibility is to express an opinion on these financial statements and financial statement schedules and an opinion on the Company's internal control over financial reporting based on our audits.
As described in the Company Report on Internal Controls Over Financial Reporting, management excluded from its assessment the internal control over financial reporting at NSTAR LLC and its subsidiaries, the post-merger parent company of NSTAR and its subsidiaries, which was acquired on April 10, 2012 and whose financial statements constitute 55 percent and 40 percent of net and total assets, respectively, 31 percent of revenues, and 35 percent of net income of the consolidated financial statement amounts as of and for the year ended December 31, 2012. Accordingly, our audit did not include the internal control over financial reporting at NSTAR LLC and its subsidiaries.
We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement and whether effective internal control over financial reporting was maintained in all material respects. Our audits of the financial statements included examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, and evaluating the overall financial statement presentation. Our audit of internal control over financial reporting included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, testing and evaluating the design and operating effectiveness of internal control based on the assessed risk. Our audits also included performing such other procedures as we considered necessary in the circumstances. We believe that our audits provide a reasonable basis for our opinions.
A company's internal control over financial reporting is a process designed by, or under the supervision of, the company's principal executive and principal financial officers, or persons performing similar functions, and effected by the company's board of directors, management, and other personnel to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company's internal control over financial reporting includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company's assets that could have a material effect on the financial statements.
Because of the inherent limitations of internal control over financial reporting, including the possibility of collusion or improper management override of controls, material misstatements due to error or fraud may not be prevented or detected on a timely basis. Also, projections of any evaluation of the effectiveness of the internal control over financial reporting to future periods are subject to the risk that the controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.
In our opinion, the consolidated financial statements referred to above present fairly, in all material respects, the financial position of Northeast Utilities and subsidiaries as of December 31, 2012 and 2011, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2012, in conformity with accounting principles generally accepted in the United States of America. Also, in our opinion, such financial statement schedules, when considered in relation to the basic consolidated financial statements taken as a whole, present fairly, in all material respects, the information set forth therein. Also, in our opinion, the Company maintained, in all material respects, effective internal control over financial reporting as of December 31, 2012, based on the criteria established in Internal Control - Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission.
As discussed in Note 2, "Merger of NU and NSTAR," to the consolidated financial statements, on April 10, 2012, the Company acquired NSTAR and its subsidiaries.
/s/ Deloitte & Touche LLP
Hartford, Connecticut
February 27, 2013
Company Report on Internal Controls Over Financial Reporting
The Connecticut Light and Power Company
Management is responsible for the preparation, integrity, and fair presentation of the accompanying consolidated financial statements of The Connecticut Light and Power Company and subsidiary (CL&P or the Company) and of other sections of this annual report. CL&P’s internal controls over financial reporting were audited by Deloitte & Touche LLP.
Management is responsible for establishing and maintaining adequate internal controls over financial reporting. The Company’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 the principal executive officer and principal financial officer, CL&P conducted an evaluation of the effectiveness of internal controls over financial reporting based on criteria established 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 internal controls over financial reporting were effective as of December 31, 2012.
February 27, 2013
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
To the Board of Directors and Stockholder of The Connecticut Light and Power Company:
We have audited the accompanying consolidated balance sheets of The Connecticut Light and Power Company and subsidiary (the "Company") as of December 31, 2012 and 2011, and the related consolidated statements of income, comprehensive income, common stockholder’s equity, and cash flows for each of the three years in the period ended December 31, 2012. Our audits also included the financial statement schedule listed in the Index at Item 15 of Part IV. These financial statements and financial statement schedule are the responsibility of the Company's management. Our responsibility is to express an opinion on the financial statements and financial statement schedule based on our audits.
We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. The Company is not required to have, nor were we engaged to perform, an audit of its internal control over financial reporting. Our audits included consideration of internal control over financial reporting as a basis for designing audit procedures that are appropriate in the circumstances, but not for the purpose of expressing an opinion on the effectiveness of the Company's internal control over financial reporting. Accordingly, we express no such opinion. An audit also includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.
In our opinion, such consolidated financial statements present fairly, in all material respects, the financial position of The Connecticut Light and Power Company and subsidiary as of December 31, 2012 and 2011, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2012, in conformity with accounting principles generally accepted in the United States of America. Also, in our opinion, such financial statement schedule, when considered in relation to the basic consolidated financial statements taken as a whole present fairly in all material respects the information set forth therein.
/s/ Deloitte & Touche LLP
Hartford, Connecticut
February 27, 2013
Company Report on Internal Controls Over Financial Reporting
NSTAR Electric Company
Management is responsible for the preparation, integrity, and fair presentation of the accompanying consolidated financial statements of NSTAR Electric Company and subsidiaries (NSTAR Electric or the Company) and of other sections of this annual report. NSTAR Electric’s internal controls over financial reporting were audited by Deloitte & Touche LLP.
Management is responsible for establishing and maintaining adequate internal controls over financial reporting. The Company’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 the principal executive officer and principal financial officer, NSTAR Electric conducted an evaluation of the effectiveness of internal controls over financial reporting based on criteria established 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 internal controls over financial reporting were effective as of December 31, 2012.
February 27, 2013
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
To the Board of Directors and Stockholder of NSTAR Electric Company:
We have audited the accompanying consolidated balance sheet of NSTAR Electric Company and subsidiaries (the "Company") as of December 31, 2012 and the related consolidated statements of income, comprehensive income, common stockholder’s equity, and cash flows for the year then ended. Our audit also included the financial statement schedule listed in the Index at Item 15 of Part IV. These financial statements and financial statement schedule are the responsibility of the Company's management. Our responsibility is to express an opinion on the financial statements and financial statement schedule based on our audit. The consolidated financial statements and financial statement schedule of the Company for the years ended December 31, 2011 and 2010 were audited by other auditors whose report, dated February 7, 2012, expressed an unqualified opinion on those statements and included an explanatory paragraph relating to the merger agreement signed with Northeast Utilities.
We conducted our audit in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. The Company is not required to have, nor were we engaged to perform, an audit of its internal control over financial reporting. Our audit included consideration of internal control over financial reporting as a basis for designing audit procedures that are appropriate in the circumstances, but not for the purpose of expressing an opinion on the effectiveness of the Company's internal control over financial reporting. Accordingly, we express no such opinion. An audit also includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audit provides a reasonable basis for our opinion.
In our opinion, such 2012 consolidated financial statements present fairly, in all material respects, the financial position of NSTAR Electric Company and subsidiaries as of December 31, 2012, and the results of their operations and their cash flows for the year then ended, in conformity with accounting principles generally accepted in the United States of America. Also, in our opinion, such 2012 financial statement schedule, when considered in relation to the basic consolidated financial statements taken as a whole presents fairly in all material respects the information set forth therein.
/s/ Deloitte & Touche LLP
Hartford, Connecticut
February 27, 2013
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
To the Directors and Shareholder of NSTAR Electric Company:
In our opinion, the consolidated balance sheets, consolidated statements of income, common stockholder's equity, and cash flows present fairly, in all material respects, the financial position of NSTAR Electric Company and its subsidiaries at December 31, 2011 and the results of their operations and their cash flows for each of the two years in the period ended December 31, 2011 in conformity with accounting principles generally accepted in the United States of America. In addition, in our opinion, the financial statement schedule for each of the two years in the period ended December 31, 2011 listed in the index appearing under Item 15(a)(2) presents fairly, in all material respects, the information set forth therein when read in conjunction with the related consolidated financial statements. These financial statements and financial statement schedule are the responsibility of the Company’s management. Our responsibility is to express an opinion on these financial statements and financial statement schedule based on our audits. We conducted our audits of these statements in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audits to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, and evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.
/s/ PricewaterhouseCoopers LLP
Boston, Massachusetts
February 7, 2012
Company Report on Internal Controls Over Financial Reporting
Public Service Company of New Hampshire
Management is responsible for the preparation, integrity, and fair presentation of the accompanying consolidated financial statements of Public Service Company of New Hampshire and subsidiaries (PSNH or the Company) and of other sections of this annual report. PSNH’s internal controls over financial reporting were audited by Deloitte & Touche LLP.
Management is responsible for establishing and maintaining adequate internal controls over financial reporting. The Company’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 the principal executive officer and principal financial officer, PSNH conducted an evaluation of the effectiveness of internal controls over financial reporting based on criteria established 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 internal controls over financial reporting were effective as of December 31, 2012.
February 27, 2013
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
To the Board of Directors and Stockholder of Public Service Company of New Hampshire:
We have audited the accompanying consolidated balance sheets of Public Service Company of New Hampshire and subsidiaries (the "Company") as of December 31, 2012 and 2011 and the related consolidated statements of income, comprehensive income, common stockholder’s equity, and cash flows for each of the three years in the period ended December 31, 2012. Our audits also included the financial statement schedule listed in the Index at Item 15 of Part IV. These financial statements and financial statement schedule are the responsibility of the Company's management. Our responsibility is to express an opinion on the financial statements and financial statement schedule based on our audits.
We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. The Company is not required to have, nor were we engaged to perform, an audit of its internal control over financial reporting. Our audits included consideration of internal control over financial reporting as a basis for designing audit procedures that are appropriate in the circumstances, but not for the purpose of expressing an opinion on the effectiveness of the Company's internal control over financial reporting. Accordingly, we express no such opinion. An audit also includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.
In our opinion, such consolidated financial statements present fairly, in all material respects, the financial position of Public Service Company of New Hampshire and subsidiaries as of December 31, 2012 and 2011, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2012, in conformity with accounting principles generally accepted in the United States of America. Also, in our opinion, such financial statement schedule, when considered in relation to the basic consolidated financial statements taken as a whole present fairly in all material respects the information set forth therein.
/s/ Deloitte & Touche LLP
Hartford, Connecticut
February 27, 2013
This Page Intentionally Left Blank
Company Report on Internal Controls Over Financial Reporting
Western Massachusetts Electric Company
Management is responsible for the preparation, integrity, and fair presentation of the accompanying consolidated financial statements of Western Massachusetts Electric Company and subsidiary (WMECO or the Company) and of other sections of this annual report. WMECO’s internal controls over financial reporting were audited by Deloitte & Touche LLP.
Management is responsible for establishing and maintaining adequate internal controls over financial reporting. The Company’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 the principal executive officer and principal financial officer, WMECO conducted an evaluation of the effectiveness of internal controls over financial reporting based on criteria established 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 internal controls over financial reporting were effective as of December 31, 2012.
February 27, 2013
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
To the Board of Directors and Stockholder of Western Massachusetts Electric Company:
We have audited the accompanying consolidated balance sheets of Western Massachusetts Electric Company and subsidiary (the "Company") as of December 31, 2012 and 2011 and the related consolidated statements of income, comprehensive income, common stockholder’s equity, and cash flows for each of the three years in the period ended December 31, 2012. Our audits also included the financial statement schedule listed in the Index at Item 15 of Part IV. These financial statements and financial statement schedule are the responsibility of the Company's management. Our responsibility is to express an opinion on the financial statements and financial statement schedule based on our audits.
We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. The Company is not required to have, nor were we engaged to perform, an audit of its internal control over financial reporting. Our audits included consideration of internal control over financial reporting as a basis for designing audit procedures that are appropriate in the circumstances, but not for the purpose of expressing an opinion on the effectiveness of the Company's internal control over financial reporting. Accordingly, we express no such opinion. An audit also includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.
In our opinion, such consolidated financial statements present fairly, in all material respects, the financial position of Western Massachusetts Electric Company and subsidiary as of December 31, 2012 and 2011, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2012, in conformity with accounting principles generally accepted in the United States of America. Also, in our opinion, such financial statement schedule, when considered in relation to the basic consolidated financial statements taken as a whole present fairly in all material respects the information set forth therein.
/s/ Deloitte & Touche LLP
Hartford, Connecticut
February 27, 2013
This Page Intentionally Left Blank
NORTHEAST UTILITIES AND SUBSIDIARIES
THE CONNECTICUT LIGHT AND POWER COMPANY AND SUBSIDIARY
NSTAR ELECTRIC COMPANY AND SUBSIDIARIES
PUBLIC SERVICE COMPANY OF NEW HAMPSHIRE AND SUBSIDIARIES
WESTERN MASSACHUSETTS ELECTRIC COMPANY AND SUBSIDIARY
COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Refer to the Glossary of Terms included in this combined Annual Report on Form 10-K for abbreviations and acronyms used throughout the combined notes to the consolidated financial statements.
1.
SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
A.
About NU, CL&P, NSTAR Electric, PSNH and WMECO
NU Consolidated: NU is a public utility holding company primarily engaged through its wholly owned regulated utility subsidiaries in the energy delivery business. NU's wholly owned regulated utility subsidiaries included CL&P, PSNH, WMECO and Yankee Gas prior to NU's merger with NSTAR. On April 10, 2012, NU acquired 100 percent of the outstanding common shares of NSTAR, at which time NSTAR (through a successor, NSTAR LLC) became a direct wholly owned subsidiary of NU along with its regulated utility subsidiaries, NSTAR Electric and NSTAR Gas. NU provides energy delivery service to approximately 3.5 million electric and natural gas customers through six regulated utilities in Connecticut, Massachusetts and New Hampshire. See Note 2, "Merger of NU and NSTAR," for further information regarding the merger.
NU, CL&P, NSTAR Electric, PSNH and WMECO are reporting companies under the Securities Exchange Act of 1934. NU is a public utility holding company under the Public Utility Holding Company Act of 2005. Arrangements among the regulated electric companies and other NU companies, outside agencies and other utilities covering interconnections, interchange of electric power and sales of utility property are subject to regulation by the FERC. The Regulated companies are subject to regulation of rates, accounting and other matters by the FERC and/or applicable state regulatory commissions (the PURA for CL&P and Yankee Gas, the DPU for NSTAR Electric, NSTAR Gas and WMECO, and the NHPUC as well as certain regulatory oversight by the Vermont Public Service Board and the Maine Public Utilities Commission for PSNH).
Regulated Companies: CL&P, NSTAR Electric, PSNH and WMECO furnish franchised retail electric service in Connecticut, Massachusetts and New Hampshire. NSTAR Gas is engaged in the distribution and sale of natural gas to customers within central and eastern Massachusetts. Yankee Gas owns and operates Connecticut's largest natural gas distribution system. CL&P, NSTAR Electric, PSNH and WMECO's results include the operations of their respective distribution and transmission businesses. PSNH and WMECO's distribution results include the operations of their respective generation businesses. NU also has a regulated subsidiary, NPT, which was formed to construct, own and operate the Northern Pass line, a new HVDC transmission line from Québec to New Hampshire that will interconnect with a new HVDC transmission line being developed by a transmission subsidiary of HQ.
Other: As of December 31, 2012, NU Enterprises’ primary business consisted of Select Energy’s remaining energy wholesale marketing contracts with a municipal authority that expires on December 31, 2013 and related purchase contracts and NGS’ operation and maintenance agreements as well as its subsidiary, E.S. Boulos Company, an electrical contractor based in Maine that NU Enterprises continues to own and manage. NUSCO, NSTAR Electric & Gas, RRR, Renewable Properties, Inc. and Properties, Inc. provide support services to NU, including its regulated companies. Harbor Electric Energy Company, a wholly-owned subsidiary of NSTAR Electric, provides distribution service and ongoing support to its only customer, the Massachusetts Water Resources Authority. NSTAR also has unregulated subsidiaries in telecommunications (NSTAR Communications, Inc.) and natural gas liquefaction and storage services (Hopkinton).
B.
Basis of Presentation
The consolidated financial statements of NU, CL&P, NSTAR Electric, PSNH and WMECO include the accounts of each of their respective subsidiaries. Intercompany transactions have been eliminated in consolidation.
The preparation of the consolidated financial statements in conformity with GAAP requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent liabilities as of the date of the consolidated financial statements and the reported amounts of revenues and expenses during the reporting period. Actual results could differ from those estimates.
NSTAR Electric continues to maintain reporting requirements as an SEC registrant. The information disclosed for NSTAR Electric represents its results of operations for each of the years ended December 31, 2012, 2011 and 2010 and the financial position as of December 31, 2012 and 2011, presented on a comparable basis. NU did not apply "push-down accounting" to NSTAR Electric, whereby the adjustments of assets and liabilities to fair value and the resultant goodwill would be shown on the financial statements of the acquired subsidiary. NU's consolidated financial information includes NSTAR LLC and its subsidiaries' results of operations from April 10, 2012 through December 31, 2012.
On April 10, 2012, upon consummation of the merger with NSTAR, NSTAR Electric's ownership in CYAPC and YAEC combined with CL&P's, PSNH's and WMECO's respective ownership interests in CYAPC and YAEC totaled greater than 50 percent, requiring NU to
consolidate CYAPC and YAEC from April 10, 2012 and forward. The investment in CYAPC and YAEC had previously been accounted for under the equity method by NU. The consolidation of CYAPC and YAEC results in NU recording nuclear decommissioning trust marketable securities of $340.4 million, regulatory assets of $214 million, long-term debt associated with the long-term spent nuclear fuel disposal liabilities of $179.3 million, net accumulated deferred income tax liability of $56.4 million and asset retirement obligations related to decommissioning activity of $311.4 million as of December 31, 2012. At the NU consolidated level, intercompany transactions between CL&P, NSTAR Electric, PSNH and WMECO and the CYAPC and YAEC companies have been eliminated in consolidation. For CL&P, NSTAR Electric, PSNH and WMECO, the investment in CYAPC and YAEC continue to be accounted for under the equity method. See Note 1J, "Summary of Significant Accounting Policies - Equity Method Investments," for further information.
NPT, a limited liability company, was formed to construct, own and operate the Northern Pass transmission project. NPT and Hydro Renewable Energy entered into a TSA whereby NPT will sell to Hydro Renewable Energy electric transmission rights over the Northern Pass for a 40-year term at cost of service rates. NPT will be required to maintain a capital structure of 50 percent debt and 50 percent equity. On April 10, 2012, upon consummation of the merger with NSTAR, an NSTAR subsidiary that owned 25 percent of NPT was merged into NUTV, resulting in NUTV owning 100 percent of NPT. Accordingly, 100 percent ownership of NPT was reflected in Common Shareholders' Equity as of December 31, 2012 on the accompanying consolidated balance sheet. See Note 2, "Merger of NU and NSTAR," and Note 19, "Common Shareholders' Equity and Noncontrolling Interests," for further information.
NU's utility subsidiaries are subject to the application of accounting guidance for entities with rate-regulated operations that considers the effect of regulation resulting from differences in the timing of the recognition of certain revenues and expenses from those of other businesses and industries. NU's utility subsidiaries' energy delivery business is subject to rate-regulation that is based on cost recovery and meets the criteria for application of rate-regulated accounting. See Note 3, "Regulatory Accounting," for further information.
Certain prior year amounts in NSTAR Electric's accompanying consolidated balance sheet, statements of income and cash flows have been reclassified between line items for comparative purposes and in order to conform to NU's presentation. The reclassifications did not affect NSTAR Electric's net income. The NSTAR Electric consolidated statements of cash flows were revised to correct an error in the presentation of cash deposits related to the RRBs. The impact of this revision was an increase in investing cash inflows from Other Investing Activities in an amount of $1.7 million and $24.1 million and a corresponding increase to financing cash outflows from Retirements of Rate Reduction Bonds for the years ended December 31, 2011 and 2010, respectively. These revisions had no impact on NSTAR Electric’s results of operations or cash balance and are not deemed material, individually or in the aggregate, to the previously issued consolidated financial statements.
Certain changes in classification and corresponding reclassifications of prior year data were made in the accompanying consolidated balance sheets and statements of income for NU, CL&P, PSNH and WMECO and statements of cash flows for NU, CL&P and WMECO for comparative purposes to conform the current year presentation. The consolidated statements of income reflect the reclassification of transmission expenses from Other Operating Expenses, as originally reported, to Purchased Power, Fuel and Transmission and the reclassification of energy efficiency expenses primarily from Other Operating Expenses, as originally reported, to Energy Efficiency Programs. In addition, Other Operating Expenses and Maintenance, as originally reported, were combined and are reported in aggregate as Operations and Maintenance. The reclassifications on the statements of income were as follows:
Effective January 1, 2012, NSTAR Electric changed its estimates with respect to the allowance for doubtful accounts, incurred but not reported claims on medical benefits, general and workers' compensation liabilities and compensation accruals. The total aggregate impact of these changes in estimates on NSTAR Electric's accompanying consolidated statements was a decrease to net income of $11.4 million, after-tax, for the year ended December 31, 2012.
In accordance with accounting guidance on noncontrolling interests in consolidated financial statements, the Preferred Stock of CL&P and the Preferred Stock of NSTAR Electric, which are not owned by NU or its consolidated subsidiaries and are not subject to mandatory redemption, have been presented as noncontrolling interests in the accompanying consolidated financial statements of NU. The Preferred Stock of CL&P and the Preferred Stock of NSTAR Electric are considered to be temporary equity and have been classified between liabilities and permanent shareholders' equity on the accompanying consolidated balance sheets of NU, CL&P and NSTAR Electric due to a provision in the preferred stock agreements of both CL&P and NSTAR Electric that grant preferred stockholders the right to elect a majority of the CL&P and NSTAR Electric Board of Directors, respectively, should certain conditions exist, such as if preferred dividends are in arrears for a specified amount of time. The Net Income reported in the accompanying consolidated statements of income and cash flows represents consolidated net income prior to apportionment to noncontrolling interests, which is represented by dividends on preferred stock of CL&P and NSTAR Electric.
NU evaluates events and transactions that occur after the balance sheet date but before financial statements are issued and recognizes in the financial statements the effects of all subsequent events that provide additional evidence about conditions that existed
as of the balance sheet date and discloses, but does not recognize, in the financial statements subsequent events that provide evidence about the conditions that arose after the balance sheet date but before the financial statements are issued. See Note 23, "Subsequent Events," for further information.
C.
Recently Adopted Accounting Standards
In the first quarter of 2012, NU adopted the Financial Accounting Standards Board’s (FASB) final Accounting Standards Update (ASU) on fair value measurement. The ASU did not have an impact on NU’s financial position, results of operations or cash flows, but required additional financial statement disclosures related to fair value measurements. For further information, see Note 5, "Derivative Instruments," to the consolidated financial statements.
In the first quarter of 2012, NU adopted the FASB’s final ASU on testing goodwill for impairment. The ASU provides the election to perform a qualitative assessment to determine whether it is more likely than not that the fair value of a reporting unit is less than its carrying value; if so, quantitative testing is required. The ASU does not change existing guidance relating to when an entity should test goodwill for impairment or the methodology to be utilized in performing quantitative testing. NU did not utilize the election provided by this ASU in its current year evaluation of goodwill.
In the first quarter of 2012, NU adopted the FASB’s final ASU on the presentation of comprehensive income. The ASU does not change existing guidance on which items should be presented in other comprehensive income but requires other comprehensive income to be presented as part of a single continuous statement of comprehensive income or in a statement of other comprehensive income immediately following the statement of net income. The ASU did not affect the calculation of net income, comprehensive income or EPS. The ASU did not have an impact on NU’s financial position, results of operations or cash flows.
D.
Cash and Cash Equivalents
Cash and cash equivalents include cash on hand and short-term cash investments that are highly liquid in nature and have original maturities of three months or less. At the end of each reporting period, any overdraft amounts are reclassified from Cash and Cash Equivalents to Accounts Payable on the accompanying consolidated balance sheets.
E.
Provision for Uncollectible Accounts
NU, including CL&P, NSTAR Electric, PSNH and WMECO, presents its receivables at net realizable value by maintaining a provision for uncollectible accounts receivables. This provision is determined based upon a variety of factors, including applying an estimated uncollectible account percentage to each receivable aging category, based upon historical collection and write-off experience and management's assessment of collectibility from individual customers. Management assesses the collectibility of receivables, and if circumstances change, collectibility estimates are adjusted accordingly. Receivable balances are written off against the provision for uncollectible accounts when the accounts are terminated and these balances are deemed to be uncollectible.
The PURA allows CL&P and Yankee Gas to accelerate the recovery of accounts receivable balances attributable to qualified customers under financial or medical duress (uncollectible hardship accounts receivable) outstanding for greater than 90 days. As a result of the January 2011 DPU rate case decision, WMECO is allowed to recover amounts associated with basic service and certain uncollectible hardship accounts receivable in rates. As of December 31, 2012, CL&P, WMECO and Yankee Gas had uncollectible hardship accounts receivable reserves in the amount of $65.2 million, $4.7 million and $6.4 million, respectively, with the corresponding bad debt expense recorded as Regulatory Assets or Other Long-Term Assets as these amounts are probable of recovery. As of December 31, 2011, these amounts totaled $68.6 million, $5.4 million and $6.8 million, respectively. These amounts are reflected in the total provision for uncollectible accounts in the table below.
The provision for uncollectible accounts, which is included in Receivables, Net on the accompanying consolidated balance sheets, was as follows:
(1)
NSTAR Electric amounts are not included in NU consolidated as of December 31, 2011.
(2)
NU, CL&P and WMECO balances as of December 31, 2011 have been reclassified to include the uncollectible hardship reserve in the total provision for uncollectible accounts.
F.
Fuel, Materials and Supplies and Allowance Inventory
Fuel, Materials and Supplies include natural gas, coal, biomass, oil and materials purchased primarily for construction or operation and maintenance purposes. Natural gas inventory, coal, biomass, and oil are valued at their respective weighted average cost. Materials and supplies are valued at the lower of average cost or market.
PSNH is subject to federal and state laws and regulations that regulate emissions of air pollutants, including SO2, CO2, and NOx related to its regulated generation units, and uses SO2, CO2, and NOx emissions allowances. At the end of each compliance period, PSNH is required to relinquish SO2, CO2, and NOx emissions allowances corresponding to the actual respective emissions emitted by its generating units over the compliance period. SO2 and NOx emissions allowances are obtained through an annual allocation from the federal and state regulators that are granted at no cost and through purchases from third parties. CO2 emissions allowances are acquired through auctions and through purchases from third parties.
SO2, CO2, and NOx emissions allowances are recorded within Fuel, Materials and Supplies and are classified on the balance sheet as short-term or long-term depending on the period in which they are expected to be utilized against actual emissions. As of December 31, 2012 and 2011, PSNH had $0.4 million and $0.8 million, respectively, of short-term SO2, CO2, and NOx emissions allowances classified as Fuel, Materials and Supplies on the accompanying consolidated balance sheets and $19.4 million and $19.4 million, respectively, of long-term SO2 and CO2 emissions allowances classified as Other Long-Term Assets on the accompanying consolidated balance sheets.
SO2, CO2, and NOx emissions allowances are charged to expense based on their weighted average cost as they are utilized against emissions volumes at PSNH's generating units. PSNH recorded expenses of $0.4 million, $5.1 million and $6.6 million for the years ended December 31, 2012, 2011, and 2010, respectively, which were included in Purchased Power, Fuel and Transmission on the accompanying consolidated statements of income. These costs are recovered from customers through energy supply revenues.
G.
Restricted Cash and Other Deposits
As of December 31, 2012, NU, CL&P and PSNH had $3.3 million, $1.3 million and $1.7 million, respectively, of restricted cash, primarily relating to amounts held in escrow, insurance proceeds on bondable property at PSNH and amounts related to the sale of land, which were included in Prepayments and Other Current Assets on the accompanying consolidated balance sheets. As of December 31, 2011, these amounts were $17.9 million, $9.4 million and $7 million for NU, CL&P and PSNH, respectively.
As of December 31, 2012, NU had $14.6 million of cash collateral posted not subject to master netting agreements, primarily with ISO-NE. As of December 31, 2011, there was no cash posted with ISO-NE and $10.9 million posted with other counterparties.
As of December 31, 2012, NU, NSTAR Electric, PSNH and WMECO had $69.4 million, $42.2 million, $22 million and $5.1 million, respectively, on deposit related to subsidiaries used to facilitate the issuance of RRBs. As of December 31, 2011, these amounts were $29.5 million, $40.9 million, $24.4 million and $5.1 million, respectively. These amounts are included in Prepayments and Other Current Assets and Other Long-Term Assets on the accompanying consolidated balance sheets. As of December 31, 2011, the NSTAR Electric amount was not included in NU consolidated.
H.
Fair Value Measurements
NU, including CL&P, NSTAR Electric, PSNH, and WMECO, applies fair value measurement guidance to derivative contracts recorded at fair value and to the marketable securities held in the NU supplemental benefit trust, WMECO's spent nuclear fuel trust and CYAPC's and YAEC's nuclear decommissioning trusts. Fair value measurement guidance is also applied to investment valuations used to calculate the funded status of NU's Pension and PBOP Plans, including NSTAR Electric's Pension Plan, and nonrecurring fair value measurements of nonfinancial assets such as goodwill and AROs.
Fair Value Hierarchy: In measuring fair value, NU uses observable market data when available and minimizes the use of unobservable inputs. Inputs used in fair value measurements are categorized into three fair value hierarchy levels for disclosure purposes. The entire fair value measurement is categorized based on the lowest level of input that is significant to the fair value measurement. NU evaluates the classification of assets and liabilities measured at fair value on a quarterly basis, and NU's policy is to recognize transfers between levels of the fair value hierarchy as of the end of the reporting period. The three levels of the fair value hierarchy are described below:
Level 1 - Inputs are quoted prices (unadjusted) in active markets for identical assets or liabilities as of the reporting date. Active markets are those in which transactions for the asset or liability occur in sufficient frequency and volume to provide pricing information on an ongoing basis.
Level 2 - Inputs are quoted prices for similar instruments in active markets, quoted prices for identical or similar instruments in markets that are not active, and model-derived valuations in which all significant inputs are observable.
Level 3 - Quoted market prices are not available. Fair value is derived from valuation techniques in which one or more significant inputs or assumptions are unobservable. Where possible, valuation techniques incorporate observable market inputs that can be validated to external sources such as industry exchanges, including prices of energy and energy-related products.
Determination of Fair Value: The valuation techniques and inputs used in NU's fair value measurements are described in Note 2, "Merger of NU and NSTAR," Note 5, "Derivative Instruments," Note 6, "Marketable Securities," Note 7, "Asset Retirement Obligations," and Note 14, "Fair Value of Financial Instruments," to the consolidated financial statements.
I.
Derivative Accounting
Many of CL&P's, NSTAR Electric's, PSNH's and WMECO’s contracts for the purchase and sale of energy or energy-related products are derivatives, along with NU Enterprises' remaining wholesale marketing contracts and NSTAR Gas' NYMEX futures. The accounting treatment for energy contracts entered into varies and depends on the intended use of the particular contract and on whether or not the contract is a derivative.
The application of derivative accounting is complex and requires management judgment in the following respects: identification of derivatives and embedded derivatives, election and designation of the "normal purchases or normal sales" (normal) exception, identifying, electing and designating hedge relationships, assessing and measuring hedge effectiveness, and determining the fair value of derivatives. All of these judgments can have a significant impact on the consolidated financial statements. Any change in the fair value of derivatives related to the Regulated companies is offset by a regulatory asset or liability, as this change will be recovered from or refunded to customers in future rates.
The fair value of derivatives is based upon the contract terms and conditions and the underlying market price or fair value per unit. When quantities are not specified in the contract, the Company determines whether the contract has a determinable quantity by using amounts referenced in default provisions and other relevant sections of the contract. The fair value of derivative assets and liabilities with the same counterparty are offset and recorded as a net derivative asset or liability on the consolidated balance sheets.
The judgment applied in the election of the normal exception (and resulting accrual accounting) includes the conclusion that it is probable at the inception of the contract and throughout its term that it will result in physical delivery of the underlying product and that the quantities will be used or sold by the business in the normal course of business. If facts and circumstances change and management can no longer support this conclusion, then the normal exception and accrual accounting is terminated and fair value accounting is applied prospectively.
The remaining wholesale marketing contracts that are marked-to-market derivative contracts are not considered to be held for trading purposes, and sales and purchase activity is reported on a net basis in Purchased Power, Fuel and Transmission on the accompanying consolidated statements of income.
For further information regarding derivative contracts of NU, CL&P, NSTAR Electric and WMECO and their accounting, see Note 5, "Derivative Instruments," to the consolidated financial statements.
J.
Equity Method Investments
Regional Decommissioned Nuclear Companies: CL&P, NSTAR Electric, PSNH and WMECO own common stock in three regional nuclear generation companies (CYAPC, YAEC and MYAPC, collectively referred to as the Yankee Companies), each of which owned a single nuclear generating facility that has been decommissioned. On April 10, 2012, upon consummation of the merger with NSTAR, NSTAR Electric's ownership in CYAPC and YAEC combined with CL&P's, PSNH's and WMECO's respective ownership interests in CYAPC and YAEC totaled greater than 50 percent, requiring NU to consolidate CYAPC and YAEC from April 10, 2012 and forward. The investment in CYAPC and YAEC had previously been accounted for under the equity method of accounting by NU. For CL&P, NSTAR Electric, PSNH and WMECO, the investment in CYAPC and YAEC continues to be accounted for under the equity method. At the NU consolidated level, intercompany transactions between CL&P, NSTAR Electric, PSNH and WMECO and the CYAPC and YAEC companies have been eliminated in consolidation.
Ownership interests in the Yankee Companies as of December 31, 2012 and 2011 were as follows:
(Percent)
CYAPC
YAEC
MYAPC
CL&P
34.5
24.5
12.0
NSTAR Electric
14.0
14.0
4.0
PSNH
5.0
7.0
5.0
WMECO
9.5
7.0
3.0
The total carrying values of CL&P's, NSTAR Electric's, PSNH's and WMECO's ownership interests in CYAPC, YAEC and MYAPC, which are included in Other Long-Term Assets on their respective accompanying consolidated balance sheets are as follows:
(1)
The NSTAR Electric carrying value was not included in NU consolidated as of December 31, 2011.
For further information on the Yankee Companies, see Note 12C, "Commitments and Contingencies - Deferred Contractual Obligations," to the consolidated financial statements.
Other Investments: As of December 31, 2012, NU had a 37.2 percent (14.5 percent of which related to NSTAR Electric) equity ownership interest in two companies that transmit electricity imported from the Hydro-Québec system in Canada. Prior to the merger with NSTAR on April 10, 2012, NU had a 22.7 percent equity ownership interest in these companies. These investments are accounted for under the equity method of accounting. NU’s investment totaled $6 million and $4.6 million as of December 31, 2012 and 2011, respectively, and NSTAR Electric's investment totaled $2.3 million and $3 million as of December 31, 2012 and 2011, respectively. The NSTAR Electric investment was not included in NU consolidated as of December 31, 2011. As of December 31, 2012 and 2011, NU also had an equity ownership interest of $6.8 million and $4.2 million in an energy investment fund, respectively.
Equity investments are included in Other Long-Term Assets on the accompanying consolidated balance sheets and net earnings related to these equity investments are included in Other Income, Net on the accompanying consolidated statements of income.
K.
Revenues
Regulated Companies: The Regulated companies' retail revenues are based on rates approved by the state regulatory commissions. In general, rates can only be changed through formal proceedings with the state regulatory commissions. The Regulated companies' rates are designed to recover their incurred costs, plus an allowed rate of return on certain unrecovered costs. The Regulated companies also utilize regulatory commission-approved tracking mechanisms to recover certain costs on a fully-reconciling basis. These tracking mechanisms require rates to be changed periodically, with overcollections refunded to customers or undercollections collected from customers in future periods. Beginning in 2011, WMECO was allowed to establish a revenue decoupling mechanism to recover a pre-established level of baseline distribution delivery service revenues per year, independent of actual customer usage. Such decoupling mechanisms effectively break the relationship between kWhs consumed by customers and revenues recognized.
Energy purchases under derivative instruments are recorded in Purchased Power, Fuel, and Transmission, and sales of energy associated with these purchases are recorded in Operating Revenues.
Regulated Companies' Unbilled Revenues: Because customers are billed throughout the month based on pre-determined cycles rather than on a calendar month basis, an estimate of electricity or natural gas delivered to customers for which the customers have not yet been billed is calculated as of the balance sheet date. Unbilled revenues are included in Operating Revenues on the consolidated statements of income and are assets on the consolidated balance sheets. Actual amounts billed to customers when meter readings become available may vary from the estimated amount.
The Regulated companies estimate unbilled sales monthly using the daily load cycle method. The daily load cycle method allocates billed sales to the current calendar month based on the daily load for each billing cycle. The billed sales are subtracted from total month load, net of delivery losses, to estimate unbilled sales. Unbilled revenues are estimated by first allocating unbilled sales to the respective customer classes, then applying an estimated rate by customer class to those sales.
Regulated Companies' Transmission Revenues - Wholesale Rates: Wholesale transmission revenues are based on formula rates that are approved by the FERC. Wholesale transmission revenues for CL&P, NSTAR Electric, PSNH, and WMECO are collected under the ISO New England Inc. Transmission, Markets and Services Tariff (ISO-NE Tariff). The ISO-NE Tariff includes Regional Network Service (RNS) and Schedule 21 - NU rate schedules to recover fees for transmission and other services for CL&P, PSNH and WMECO and the Schedule 21 - NSTAR rate schedules recover fees and other services for NSTAR Electric. The RNS rate, administered by ISO-NE and billed to all New England transmission users, including CL&P, NSTAR Electric, PSNH and WMECO's transmission businesses, is reset on June 1st of each year and recovers the revenue requirements associated with transmission facilities that benefit the entire New England region. The Schedule 21 - NU and Schedule 21 - NSTAR rates, administered by NU, recover the revenue requirements for local transmission facilities and other transmission costs not recovered under the RNS rate. The Schedule 21 - NU rate is reset on January 1st and June 1st of each year, while the Schedule 21 - NSTAR rate is reset on June 1st of each year. The Schedule 21 - NU and Schedule 21 - NSTAR rate calculations recover total transmission revenue requirements net of revenues received from other sources (i.e., RNS, rentals, etc.), thereby ensuring that NU recovers all of CL&P's, NSTAR Electric’s, PSNH's and WMECO's regional and local revenue requirements as prescribed in the ISO-NE Tariff. The RNS and Schedule 21 - NU and Schedule 21 - NSTAR rates provide for the annual reconciliation and recovery or refund of estimated (or projected) costs to actual costs. The financial impacts of differences between actual and projected costs are deferred for future recovery from, or refunded to, transmission customers.
Regulated Companies' Transmission Revenues - Retail Rates: A significant portion of the NU transmission segment revenue comes from ISO-NE charges to the distribution businesses of CL&P, NSTAR Electric, PSNH and WMECO, each of which recovers these costs through rates charged to their retail customers. CL&P, NSTAR Electric, PSNH and WMECO each have a retail transmission cost tracking mechanism as part of their rates, which allows the electric distribution companies to charge their retail customers for transmission costs on a timely basis.
L.
Operating Expenses
Costs related to fuel (and natural gas costs as it related to Yankee Gas and NSTAR Gas) included in Purchased Power, Fuel and Transmission on the accompanying consolidated statements of income were as follows:
M.
Allowance for Funds Used During Construction
AFUDC represents the cost of borrowed and equity funds used to finance construction and is included in the cost of the Regulated companies' utility plant. The portion of AFUDC attributable to borrowed funds is recorded as a reduction of Other Interest Expense, and the AFUDC related to equity funds is recorded as Other Income, Net on the accompanying consolidated statements of income. AFUDC costs are recovered from customers over the service life of the related plant in the form of increased revenue collected as a result of higher depreciation expense.
(1)
NSTAR Electric amounts are included in NU consolidated from the date of the merger, April 10, 2012, through December 31, 2012. NSTAR Electric amounts are not included in NU consolidated for the years ended December 31, 2011 and 2010.
The Regulated companies' average AFUDC rate is based on a FERC-prescribed formula that produces an average rate using the cost of a company's short-term financings as well as a company's capitalization (preferred stock, long-term debt and common equity). The average rate is applied to average eligible CWIP amounts to calculate AFUDC.
N.
Other Income, Net
Items included within Other Income, Net on the accompanying consolidated statements of income primarily consist of investment income/(loss), interest income, AFUDC related to equity funds and equity in earnings. For CL&P, NSTAR Electric, PSNH and WMECO, equity in earnings relate to investments in CYAPC, YAEC and MYAPC and also NSTAR Electric's investment in two regional transmission companies, which are all accounted for on the equity method. On an NU consolidated basis, equity in earnings relate to the investment in MYAPC and NU's investment in two regional transmission companies.
O.
Other Taxes
Gross receipts taxes levied by the state of Connecticut are collected by CL&P and Yankee Gas from their respective customers. These gross receipts taxes are shown on a gross basis with collections in Operating Revenues and payments in Taxes Other Than Income Taxes on the accompanying consolidated statements of income as follows:
Certain sales taxes are also collected by CL&P, NSTAR Electric, WMECO, Yankee Gas and NSTAR Gas from their respective customers as agents for state and local governments and are recorded on a net basis with no impact on the accompanying consolidated statements of income.
(1)
NSTAR Electric amounts are included in NU consolidated from the date of the merger, April 10, 2012, through December 31, 2012. NSTAR Electric amounts are not included in NU consolidated for the years ended December 31, 2011 and 2010.
The merger of NU with NSTAR on April 10, 2012 represented a significant non-cash transaction. Refer to Note 2, "Merger of NU and NSTAR," for further information on the purchase price of NSTAR.
Q.
Related Parties
NUSCO and NSTAR Electric & Gas, NU's service companies, provide centralized accounting, administrative, engineering, financial, information technology, legal, operational, planning, purchasing, and other services to NU's companies. RRR, Renewable Properties, Inc. and Properties, Inc., three other NU subsidiaries, construct, acquire or lease some of the property and facilities used by NU's companies.
As of both December 31, 2012 and 2011, CL&P, PSNH and WMECO had long-term receivables from NUSCO in the amounts of $25 million, $3.8 million and $5.5 million, respectively, which were included in Other Long-Term Assets on the accompanying consolidated balance sheets. These amounts related to the funding of investments held in trust by NUSCO in connection with certain postretirement benefits for CL&P, PSNH and WMECO employees and have been eliminated in consolidation on the NU financial statements.
NSTAR Electric’s consolidated balance sheets included $70.2 million and $75.9 million in Payable to Affiliated Companies as of December 31, 2012 and 2011, respectively. These amounts related to payments received from affiliates as a result of NSTAR Electric’s role as the sponsor of the NSTAR Pension Plan.
Included in the CL&P, NSTAR Electric, PSNH and WMECO consolidated balance sheets as of December 31, 2012 and 2011 were Accounts Receivable from Affiliated Companies and Accounts Payable to Affiliated Companies relating to transactions between CL&P, NSTAR Electric, PSNH and WMECO and other subsidiaries that are wholly owned by NU. These amounts have been eliminated in consolidation on the NU financial statements.
The NU Foundation is an independent not-for-profit charitable entity designed to fund initiatives or entities that emphasize economic development, workforce training and education, and a clean and healthy environment. The NSTAR Foundation is an independent not-for-profit entity designed to support local charitable organizations in NSTAR’s service territory that improve the quality of life for its customers. The Board of Directors of both the NU Foundation and NSTAR Foundation consist of certain NU officers. The NU Foundation and the NSTAR Foundation are not included in the consolidated financial statements of NU as they are not-for-profit entities and the Company does not have title to the Foundations' assets and cannot receive contributions back from the Foundations.
2.
MERGER OF NU AND NSTAR
On April 10, 2012, NU acquired 100 percent of the outstanding common shares of NSTAR. Pursuant to the terms and conditions of the Agreement and Plan of Merger, as amended, the "Merger Agreement," NSTAR merged into NSTAR LLC, becoming a wholly-owned subsidiary of NU.
NSTAR LLC is a holding company engaged through its subsidiaries in the energy delivery business serving electric and natural gas distribution customers in Massachusetts. The merger was structured as a merger of equals in a tax-free exchange of shares. As part of the merger, NSTAR shareholders received 1.312 NU common shares for each NSTAR common share owned (the "exchange ratio") as of the acquisition date. The exchange ratio was structured to result in a no-premium merger based on the average closing share price of each company's common shares for the 20 trading days preceding the announcement of the merger in October 2010. NU issued approximately 136 million common shares to the NSTAR shareholders as a result of the merger, which brought the total common shares outstanding to approximately 314 million shares as of April 10, 2012.
Purchase Price: Pursuant to the merger, all of the NSTAR common shares were exchanged at the fixed exchange ratio of 1.312 NU common shares for each NSTAR common share. The total consideration transferred in the merger was based on the closing price of NU common shares on April 9, 2012, the day prior to the date the merger was completed, and was calculated as follows:
*
Includes 109 thousand shares related to NSTAR stock-based compensation awards that vested immediately prior to the merger
Certain of NSTAR’s stock-based compensation awards, including deferred shares, performance shares and all outstanding stock options, were replaced with NU awards using the exchange ratio upon consummation of the merger. In accordance with accounting guidance for business combinations, the portion of the fair value of these awards attributable to service provided prior to the merger is included in the purchase price as it represents consideration transferred in the merger. See Note 10D, "Employee Benefits - Share-Based Payments," for further information.
Purchase Price Allocation: The allocation of the total purchase price to the estimated fair values of the assets acquired and liabilities assumed has been determined based on the accounting guidance for fair value measurements, which defines fair value as the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date. The allocation of the total purchase price includes adjustments to record the fair value of NSTAR’s unregulated telecommunications business, regulatory assets not earning a return, lease agreements, long-term debt and the preferred stock of NSTAR Electric. The fair values of NSTAR's assets and liabilities were determined based on significant estimates and assumptions, including Level 3 inputs, that are judgmental in nature. These estimates and assumptions include the timing and amounts of projected future cash flows and discount rates reflecting risk inherent in future cash flows.
The excess of the purchase price over the estimated fair values of the assets acquired and liabilities assumed was recognized as goodwill. The completed allocation of the purchase price is as follows:
(Billions of Dollars)
Current Assets
$
0.7
Property Plant and Equipment, Net
5.1
Goodwill
3.2
Other Long-Term Assets, excluding Goodwill
2.1
Current Liabilities
(1.3)
Long-Term Liabilities
(2.7)
Long-Term Debt and Other Long-Term Obligations
(2.1)
Total Purchase Price
$
5.0
The goodwill from the merger with NSTAR of $3.2 billion has been assigned to NU's reporting units based on relative fair values. NU's reporting units consist of Electric Distribution, Electric Transmission and Natural Gas Distribution. See the "Goodwill" section below for the allocation of goodwill to each reporting unit.
Pro Forma Financial Information: The following unaudited pro forma financial information reflects the pro forma combined results of operations of NU and NSTAR and reflects the amortization of purchase price adjustments assuming the merger had taken place on January 1, 2011. The unaudited pro forma financial information has been presented for illustrative purposes only and is not necessarily indicative of the consolidated results of operations that would have been achieved or the future consolidated results of operations of NU.
Pro forma net income does not include potential cost savings associated with the merger. Pro forma net income also excludes certain non-recurring merger costs and costs related to the Connecticut and Massachusetts settlement agreements described below, with the following aggregate after-tax impacts:
Regulatory Approvals: On February 15, 2012, NU and NSTAR reached comprehensive settlement agreements with the Massachusetts Attorney General and the DOER related to the merger. The Attorney General settlement agreement covered a variety of rate-making and rate design issues, including a base distribution rate freeze through 2015 for NSTAR Electric, NSTAR Gas and WMECO and $15 million, $3 million and $3 million in the form of rate credits to their respective customers. The settlement agreement reached with the DOER covered the same rate-making and rate design issues as the Attorney General's settlement agreement, as well as a variety of matters impacting the advancement of Massachusetts clean energy policy established by the Green Communities Act and Global Warming Solutions Act. On April 4, 2012, the DPU approved the settlement agreements and the merger of NU and NSTAR.
On March 13, 2012, NU and NSTAR reached a comprehensive settlement agreement with both the Connecticut Attorney General and the Connecticut Office of Consumer Counsel related to the merger. The settlement agreement covered a variety of matters, including a $25 million rate credit to CL&P customers, a CL&P base distribution rate freeze until December 1, 2014, and the establishment of a $15 million fund for energy efficiency and other initiatives to be disbursed at the direction of the DEEP. In the agreement, CL&P agreed to forego rate recovery of $40 million of the deferred storm restoration costs associated with restoration activities following Tropical Storm Irene and the October 2011 snowstorm. On April 2, 2012, the PURA approved the settlement agreement and the merger of NU and NSTAR.
The pre-tax financial impacts of the Connecticut and Massachusetts settlement agreements that were recognized by NU, CL&P, NSTAR Electric, and WMECO are summarized as follows:
NSTAR Revenues and Net Income: The impact of NSTAR on NU's accompanying consolidated statement of income includes operating revenues of $1,957.8 million and net income attributable to controlling interest of $182.9 million for the year ended December 31, 2012.
Goodwill: In a business combination, the excess of the purchase price over the estimated fair values of the assets acquired and liabilities assumed is recognized as goodwill. Goodwill is evaluated for impairment at least annually and more frequently if indicators of impairment arise. In accordance with the accounting standards, if the fair value of a reporting unit is less than its carrying value (including goodwill), the goodwill is tested for impairment. A loss is recognized if the implied fair value of a reporting unit's goodwill is less than the carrying value of its goodwill. NU uses October 1st as the annual goodwill impairment testing date.
On April 10, 2012, upon consummation of the merger with NSTAR, NU recorded approximately $3.2 billion of goodwill. With the completion of the NSTAR merger, NU reviewed its management structure and determined that the reporting units for the purpose of testing goodwill for impairment are Electric Distribution, Electric Transmission and Natural Gas Distribution. NU's reporting units are consistent with the operating segments underlying the reportable segments identified in Note 21, "Segment Information," to the consolidated financial statements. Accordingly, the goodwill resulting from the NSTAR merger has been allocated to the Electric Distribution, Electric Transmission and Natural Gas Distribution reporting units based on the estimated fair values of the reporting units as of the merger date.
As of December 31, 2011, the only reporting unit that maintained goodwill was the natural gas reportable segment, related to the acquisition of the parent of Yankee Gas in 2000. This goodwill is recorded at Yankee Gas. The goodwill balance at Yankee Gas as of December 31, 2012 and 2011 was $0.3 billion.
NU completed its impairment analysis of the NSTAR and Yankee Gas goodwill balances as of October 1, 2012 and determined that no impairment exists. In completing this analysis, the fair value of the reporting units was estimated using a discounted cash flow methodology and a market method utilizing comparable company information and market transactions.
The allocation of goodwill to NU's reporting units is as follows:
3.
REGULATORY ACCOUNTING
On April 10, 2012, NSTAR's regulated utility subsidiaries, NSTAR Electric and NSTAR Gas, became subsidiaries of NU. For NSTAR Electric, certain regulatory asset and liability balances as of December 31, 2011 have been reclassified to the current year presentation in order to align the reporting of regulatory activities subsequent to the closing of the merger.
NU's Regulated companies continue to be rate-regulated on a cost-of-service basis; therefore, the accounting policies of the Regulated companies apply GAAP applicable to rate-regulated enterprises and reflect the effects of the rate-making process.
Management believes it is probable that the Regulated companies will recover their respective investments in long-lived assets, including regulatory assets. If management determined that it could no longer apply the accounting guidance applicable to rate-regulated enterprises to the Regulated companies' operations, or that management could not conclude it is probable that costs would be recovered in future rates, the costs would be charged to net income in the period in which the determination is made.
Regulatory Assets: The components of regulatory assets are as follows:
(1)
NSTAR Electric amounts are not included in NU consolidated as of December 31, 2011.
Regulatory Costs Not Yet Approved: Additionally, the Regulated companies had $69.9 million ($3.9 million for CL&P, $25.4 million for NSTAR Electric, $35.7 million for PSNH, and $1.4 million for WMECO) and $32.4 million ($5 million for CL&P, $22.4 million for PSNH,
and $1.6 million for WMECO) of regulatory costs as of December 31, 2012 and 2011, respectively, which were included in Other Long-Term Assets on the accompanying consolidated balance sheets. For comparative purposes, NSTAR Electric had $9.5 million of such regulatory costs as of December 31, 2011. These amounts represent incurred costs that have not yet been approved for recovery by the applicable regulatory agency. Management believes it is probable that recovery of these costs will ultimately be approved.
For PSNH, of the total December 31, 2012 regulatory costs not yet approved, $12.1 million related to costs incurred for the 2012 Hurricane Sandy storm and $22.3 million related to costs incurred for the 2011 Tropical Storm Irene and the October snowstorm restorations that met the NHPUC criteria for cost deferral. As of December 31, 2011, the storm restoration costs incurred for the 2011 Tropical Storm Irene and the October snowstorm restorations totaled $21.7 million. Refer to the "Storm Restoration Costs" section below for further discussion. The NSTAR Electric balance as of December 31, 2012 and 2011 related to costs deferred in connection with the basic service bad debt adder. See Note 12H, "Commitments and Contingencies - Basic Service Bad Debt Adder," for further information.
Equity Return on Regulatory Assets: For rate-making purposes, the Regulated companies recover the carrying cost, including an allowed equity return, on certain regulatory assets. This equity return, which is not recorded on the accompanying consolidated balance sheets, totaled $2.5 million and $3.5 million for CL&P and $21.8 million and $7.6 million for PSNH as of December 31, 2012 and 2011, respectively. These carrying costs will be recovered in future rates.
Regulatory Assets - The following provides further information about regulatory assets:
Benefit Costs: NU's Pension, SERP and PBOP Plans are accounted for in accordance with accounting guidance on defined benefit pension and other postretirement plans. Under this accounting guidance, the funded status of pension and other postretirement plans is recorded with an offset to Accumulated Other Comprehensive Income/(Loss) and is remeasured annually. However, because the Regulated companies recover these costs from customers through rates, regulatory assets are recorded as an offset for the liability that is recognized for the funded status of the pension and postretirement plans. Regulatory accounting was also applied to the portions of the NUSCO and NSTAR Electric & Gas costs that support the Regulated companies, as these amounts are also recoverable. CL&P and PSNH do not collect carrying charges on these deferred benefit costs regulatory assets. WMECO's deferred benefit costs regulatory assets are earning a return at the same rate as the assets included in rate base. NSTAR Electric does not earn a return on the regulatory assets recorded to offset the funded status.
NSTAR Electric and WMECO each recover their qualified pension and postretirement expenses through rate reconciling mechanisms that fully track the change in net pension and postretirement expenses each year. CL&P and PSNH will recover benefit costs through rates as allowed by their applicable regulatory commissions. NSTAR Electric earns a carrying charge on the excess cumulative benefit plan trust fund contributions it has made over what it has cumulatively recognized as net periodic benefit expense, net of deferred income taxes. As of December 31, 2012 and 2011, these balances were $366.8 million and $428 million of the benefit costs regulatory asset, respectively.
Regulatory Assets Offsetting Derivative Liabilities: The regulatory assets offsetting derivative liabilities relate to the fair value of contracts used to purchase power and other related contracts that will be collected from customers in the future. See Note 5, "Derivative Instruments," to the consolidated financial statements for further information. These assets are excluded from rate base and are being recovered as the actual settlement occurs over the duration of the contracts.
Goodwill: Goodwill that originated from the merger that created NSTAR in 1999 is recoverable in rates over the remaining 27 year amortization period, without a carrying charge.
Storm Restoration Costs: The storm restoration cost deferrals relate to costs incurred at CL&P, NSTAR Electric, PSNH and WMECO for restorations that the Company expects to collect from customers. A storm must meet certain criteria to be declared a major storm with the criteria specific to each state jurisdiction and utility company. Once a storm is declared major, all qualifying expenses incurred during storm restoration efforts, if deemed prudent, are deferred and recovered from customers in future periods. In Connecticut, qualifying storm restoration costs must exceed $5 million for a storm to be declared a major storm. In Massachusetts, qualifying storm restoration costs must exceed $1 million for NSTAR Electric and $300,000 for WMECO and an emergency response plan must be initiated for a storm to be declared a major storm. In New Hampshire, (1) at least 10 percent of customers must be without power with at least 200 concurrent locations requiring repairs (trouble spots), or (2) at least 300 concurrent trouble spots must be reported for a storm to be declared a major storm.
In 2011, Tropical Storm Irene and the October snowstorm each caused extensive damage to NU’s distribution system. As of December 31, 2012 and 2011, CL&P had recorded total deferred storm restoration costs relating to Tropical Storm Irene and the October 2011 snowstorm as a regulatory asset of $281.6 million and $263.3 million, respectively. The CL&P storm restoration cost regulatory asset balance includes a reserve of $40 million recorded in connection with the Connecticut settlement agreement. See Note 2, "Merger of NU and NSTAR," for further information. As of December 31, 2012 and 2011, NSTAR Electric had recorded total deferred storm restoration costs for these 2011 storms of $35.8 million and $35.8 million, respectively, and WMECO had recorded $26.5 million and $26.7 million, respectively, as regulatory assets. PSNH recorded $22.3 million and $21.7 million for these 2011 storms in Other Long-Term Assets, as of December 31, 2012 and 2011, respectively, as previously described.
On August 1, 2012, PURA issued a final decision in the investigation of CL&P’s performance related to both Tropical Storm Irene and the October 2011 snowstorm. The decision concluded that CL&P was deficient and inadequate in its preparation, response, and communication to both storms, and identified certain penalties that could be imposed on CL&P during its next rate case, including a reduction in allowed regulatory ROE and the disallowance of certain deferred storm restoration costs. However, PURA will consider and weigh the extent to which CL&P has taken steps in its restructuring of storm management and the establishment of new practices for execution in future storm response in determining any potential penalties. CL&P believes such steps to improve current storm preparation and response practices have been successfully executed in recent storms. At this time, management cannot estimate the impact on CL&P’s financial position, results of operations or cash flows. CL&P continues to believe that its response to these 2011 storms was prudent, was consistent with industry standards, and that it is probable that it will be able to recover its deferred costs.
See Note 12E, "Commitments and Contingencies - DPU Penalties for 2011 Storm Responses," for a discussion of NSTAR Electric and WMECO's 2011 storm response.
On October 29, 2012, Hurricane Sandy caused extensive damage to NU’s electric distribution system across all three states. The cost of restoration that was deferred for future recovery from customers and recorded as a regulatory asset as of December 31, 2012 for CL&P, NSTAR Electric, and WMECO totaled $159.9 million, $27.8 million and $4.2 million, respectively. PSNH recorded $12.1 million in Other-Long Term Assets, as previously described. Management believes its response to the storm damage was prudent and therefore believes it is probable that CL&P, NSTAR Electric, PSNH and WMECO will be allowed to recover these deferred storm restoration costs. Accordingly, the storm did not have a material impact to the results of operations of CL&P, NSTAR Electric, PSNH or WMECO. Each operating company will seek recovery of these deferred storm restoration costs through its applicable regulatory recovery process.
The PSNH storm restoration costs deferral as of December 31, 2012 and 2011 related to costs incurred for a major storm in December 2008 and the February 2010 wind storm, both of which were approved for recovery and are included in rate base.
Income Taxes, Net: The tax effect of temporary book-tax differences (differences between the periods in which transactions affect income in the financial statements and the periods in which they affect the determination of taxable income, including those differences relating to uncertain tax positions) is accounted for in accordance with the rate-making treatment of the applicable regulatory commissions and accounting guidance for income taxes. Differences in income taxes between the accounting guidance and the rate-making treatment of the applicable regulatory commissions are recorded as regulatory assets. As these assets are offset by deferred income tax liabilities, no carrying charge is collected. For further information regarding income taxes, see Note 11, "Income Taxes," to the consolidated financial statements.
Securitized Assets: In March 2005, NSTAR Electric issued $674.5 million RRBs and used the majority of the proceeds from that issuance to effect purchase power contract buyouts. The collateralized amounts reflected as securitized regulatory assets for NSTAR Electric as of December 31, 2012 and 2011 were $14.1 million and $98.4 million, respectively. In April 2001, PSNH issued $525 million RRBs and used the majority of the proceeds from that issuance to buydown its power contracts with an affiliate, North Atlantic Energy Corporation. In May 2001, WMECO issued $155 million RRBs and used the majority of the proceeds from that issuance to buyout an IPP contract. These assets are not earning an equity return and are being recovered over the amortization period of their associated RRBs. NSTAR Electric RRBs are scheduled to fully amortize by March 15, 2013, PSNH RRBs are scheduled to fully amortize by May 1, 2013, and WMECO RRBs are scheduled to fully amortize by June 1, 2013.
NSTAR Electric's remaining balance primarily includes other costs related to purchase power contract divestitures and certain costs related to NSTAR Electric’s former generation business that are recovered with a return through the transition charge and amounted to $186.1 million and $259.8 million as of December 31, 2012 and 2011, respectively. These cost recoveries primarily occur through September 2016 for NSTAR Electric and are subject to adjustment by the DPU.
Contractual Obligations: Under the terms of contracts with CYAPC, YAEC and MYAPC, CL&P, NSTAR Electric, PSNH and WMECO are responsible for their proportionate share of the remaining costs of the nuclear facilities, including decommissioning. A portion of these amounts was recorded as contractual obligations regulatory assets. These obligations for CL&P are earning a return and are being recovered through the CTA. Amounts for NSTAR Electric are being recovered without a return through the transition charge and are anticipated to be recovered by 2015. Amounts for WMECO are being recovered without a return and are anticipated to be recovered by 2013, the scheduled completion date of stranded cost recovery. Amounts for PSNH were fully recovered by 2006. As a result of the April 10, 2012 merger with NSTAR and consolidation of CYAPC and YAEC, NU's regulatory asset balance also includes the regulatory assets of CYAPC and YAEC, which amounted to $214 million as of December 31, 2012. At the NU consolidated level, intercompany transactions between CL&P, NSTAR Electric, PSNH and WMECO and the CYAPC and YAEC companies are eliminated in consolidation.
Power Contracts Buy Out Agreements: NSTAR Electric's balance represents the recorded contract termination liability related to certain purchase power contract buy out agreements that NSTAR Electric executed in 2004 and their future recovery through NSTAR Electric’s transition charge. NSTAR Electric does not earn a return on this regulatory asset. The contracts’ termination payments will occur over time and will be collected from customers through NSTAR Electric’s transition charge over the same time period. The cost recovery period of these terminated contracts is through September 2016. PSNH's balance represents payments associated with the termination of various power purchase contracts that were recorded as regulatory assets and are amortized over the remaining life of the contracts.
Regulatory Tracker Deferrals: Regulatory tracker deferrals are approved rate mechanisms that allow utilities to recover costs in specific business segments through reconcilable tracking mechanisms that are reviewed at least annually by the applicable regulatory commission. The reconciliation process produces deferrals for future recovery or refund, which can be either under or over-collections to be included in future customer rates each year. Regulatory tracker deferrals are recorded as regulatory assets if costs are in excess of collections from customers and are recorded as regulatory liabilities if collections from customers are in excess of costs. All material regulatory tracker deferrals that are in a regulatory asset position are earning a return. The following regulatory reconciliation mechanisms were recorded as either regulatory assets or liabilities as of December 31, 2012 and 2011:
CL&P: The PURA has established several reconciliation mechanisms, which allow CL&P to recover costs associated with the procurement of energy for SS and LRS, congestion and other costs associated with power market rules approved by the FERC or as approved by the PURA, C&LM programs, the retail transmission of energy, certain regulatory and energy public policy costs, such as hardship protection costs and transition period property taxes, and stranded costs, such as the amortization of regulatory assets and IPP over market costs. As part of the CTA mechanism reconciliation process, CL&P had also established an obligation to refund the variable incentive portion of its transition service procurement fee, which totaled $26.3 million as of December 31, 2011 and was recorded as a regulatory liability. During 2012, PURA issued a decision approving a joint settlement agreement submitted October 2, 2012, by CL&P, UI, and the Connecticut Consumer Counsel, in resolution of all issues associated with the procurement incentive for 2004, 2005 and 2006. Under the joint settlement agreement, CL&P refunded to customers $5.7 million of funds collected and associated interest. CL&P will be allowed to retain approximately $11.5 million of procurement incentive along with the remaining accrued interest that it was not required to refund to customers.
NSTAR Electric and WMECO: Each company recovers certain of its costs on a fully reconciling basis through DPU-approved cost recovery mechanisms. These rate mechanisms recover costs associated with the procurement of energy for basic service, the retail transmission of energy, costs associated with electric industry restructuring, pension and postretirement benefits, and energy efficiency programs. Costs associated with industry restructuring include RRB debt service, nuclear decommissioning costs and above-market IPP costs. In addition, WMECO recovers costs associated with its investments in renewable energy, such as solar projects and credits given to customers who generate renewable energy.
In the January 31, 2011 rate case, WMECO received approval for a revenue decoupling reconciliation mechanism, which provides assurance that WMECO will recover a DPU pre-established level of baseline distribution delivery service revenue to manage all other distribution operating expenses and earn a level of return on its capital investment.
PSNH: The NHPUC permits PSNH to recover the costs of providing generation, restructuring costs as a result of deregulation, the retail transmission of energy, and the cost of C&LM programs through various reconciliation mechanisms.
Asset Retirement Obligations: The costs associated with the depreciation of the Regulated companies' ARO assets and accretion of the ARO liabilities are recorded as regulatory assets in accordance with regulatory accounting guidance. For CL&P, NSTAR Electric and WMECO, ARO assets, regulatory assets and liabilities offset and are excluded from rate base. PSNH's ARO assets, regulatory assets and liabilities are included in rate base. These costs are being recovered over the life of the underlying property, plant and equipment.
Other Regulatory Assets: Other Regulatory Assets primarily include environmental remediation costs, losses associated with the reacquisition or redemption of long-term debt, and costs related to previously recognized lost tax benefits as a result of a provision in the 2010 Healthcare Act that eliminated the tax deductibility of actuarially equivalent Medicare Part D benefits for retirees, partially offset by purchase price adjustments recorded in connection with the merger with NSTAR reflected in regulatory assets.
Regulatory Liabilities: The components of regulatory liabilities are as follows:
(1)
NSTAR Electric amounts are not included in NU consolidated as of December 31, 2011.
Cost of Removal: NU's Regulated companies currently recover amounts in rates for future costs of removal of plant assets over the lives of the assets. The estimated cost to remove utility assets from service is recognized as a component of depreciation expense and the cumulative amounts collected from customers but not yet expended is recognized as a regulatory liability. Expended costs that exceed amounts collected from customers are recognized as regulatory assets, as they are probable of recovery in future rates.
AFUDC Transmission Incentive: AFUDC was recorded on 100 percent of CL&P and WMECO's CWIP for their NEEWS projects through May 31, 2011, all of which was reserved as a regulatory liability to reflect rate base recovery for 100 percent of the CWIP as a result of FERC-approved transmission incentives. Effective June 1, 2011, FERC approved changes to the ISO-NE Tariff in order to include 100 percent of the NEEWS CWIP in regional rate base. As a result, CL&P and WMECO no longer record AFUDC on NEEWS CWIP. NSTAR Electric recorded AFUDC on reliability-related projects over $5 million through December 31, 2012, 50 percent of which was reserved as a regulatory liability to reflect rate base recovery for 50 percent of the CWIP as a result of FERC-approved transmission incentives.
Spent Nuclear Fuel Costs and Contractual Obligations: CL&P and WMECO currently recover amounts in rates for costs of disposal of spent nuclear fuel and high-level radioactive waste for the period prior to the sale of their ownership shares in the Millstone nuclear power stations. Collections in excess of these costs are recorded as regulatory liabilities. CL&P has also established a regulatory liability for the overrecovery of its proportionate share of the remaining costs, including decommissioning, of the MYAPC nuclear facility.
Wholesale Transmission Overcollections: CL&P, NSTAR Electric, PSNH and WMECO's transmission rates recover total transmission revenue requirements, recovering all regional and local revenue requirements for providing transmission service. These rates provide for annual reconciliations to actual costs and the difference between billed and actual costs is deferred. Regulatory liabilities are recorded for collections in excess of costs. Regulatory assets are recorded for costs in excess of collections, as they are probable of recovery in future rates.
Other Regulatory Liabilities: Other Regulatory Liabilities primarily includes amounts that are subject to various rate reconciling mechanisms that, as of each period end date, would result in refunds to customers.
4.
PROPERTY, PLANT AND EQUIPMENT AND ACCUMULATED DEPRECIATION
Utility property, plant and equipment is recorded at original cost. Original cost includes materials, labor, construction overhead and AFUDC for regulated property. The cost of repairs and maintenance, including planned major maintenance activities, is charged to Operating Expenses as incurred.
The following tables summarize the NU, CL&P, NSTAR Electric, PSNH and WMECO investments in utility property, plant and equipment by asset category:
(1)
These assets represent unregulated property and are primarily comprised of building improvements at RRR and software and equipment at NUSCO as of December 31, 2012 and 2011, and telecommunications equipment at NSTAR Communications, Inc. as of December 31, 2012.
(1)
NSTAR Electric amounts are not included in NU consolidated as of December 31, 2011.
Depreciation of utility assets is calculated on a straight-line basis using composite rates based on the estimated remaining useful lives of the various classes of property (estimated useful life for PSNH distribution). The composite rates are subject to approval by the appropriate state regulatory agency. The composite rates include a cost of removal component, which is collected from customers during the life of the property and is recognized as a regulatory liability. Depreciation rates are applied to property from the time it is placed in service.
Upon retirement from service, the cost of the utility asset is charged to the accumulated provision for depreciation. The actual incurred removal costs are applied against the related regulatory liability.
The depreciation rates for the various classes of utility property, plant and equipment aggregate to composite rates as follows:
The following table summarizes average useful lives of depreciable assets:
5.
DERIVATIVE INSTRUMENTS
The Regulated companies purchase and procure energy and energy-related products for their customers, which are subject to price volatility. The costs associated with supplying energy to customers are recoverable through customer rates. The Regulated companies manage the risks associated with the price volatility of energy and energy-related products through the use of derivative contracts, many of which meet the definition of and are designated as "normal purchases or normal sales" (normal) under the applicable accounting guidance, and the use of nonderivative contracts.
Derivative contracts that are not recorded as normal are recorded at fair value as current or long-term derivative assets or liabilities. For the Regulated companies, regulatory assets or liabilities are recorded for the changes in fair values of derivatives, as costs are, and management believes they will continue to be, recovered from or refunded in customers rates. For NU's remaining unregulated wholesale marketing contracts, changes in fair values of derivatives are included in Net Income. The costs and benefits of derivative contracts that meet the definition of normal are recognized in Operating Expenses or Operating Revenues on the accompanying consolidated statements of income, as applicable, as electricity or natural gas is delivered.
CL&P, NSTAR Electric and WMECO mitigate the risks associated with the price volatility of energy and energy-related products through the use of SS, LRS, and basic service contracts, which fix the price of electricity purchased for customers and are accounted for as normal. CL&P, NSTAR Electric and WMECO have entered into derivative and nonderivative contracts for the purchase of energy and energy-related products and contracts that are derivatives. NU also has NYMEX future contracts in order to reduce variability associated with the purchase price of approximately 11.5 million MMBtu of natural gas.
The costs or benefits from all of the Regulated companies' derivative contracts are recoverable from or refundable to customers, and therefore, changes in fair value are recorded as Regulatory Assets or Regulatory Liabilities on the accompanying consolidated balance sheets.
NU, through Select Energy, has one remaining fixed price forward sales contract that expires on December 31, 2013 to serve electrical load that is part of its remaining unregulated wholesale energy marketing portfolio. NU mitigates the price risk associated with this contract through the use of several forward purchase contracts. The contracts are accounted for at fair value, and changes in their fair values are recorded in Purchased Power, Fuel and Transmission on the accompanying consolidated statements of income.
The gross fair values of derivative assets and liabilities with the same counterparty are offset and reported as net Derivative Assets or Derivative Liabilities, with current and long-term portions, in the accompanying consolidated balance sheets. Cash collateral posted or collected under master netting agreements is recorded as an offset to the derivative asset or liability. The following tables present the gross fair values of contracts categorized by risk type and the net amounts recorded as current or long-term derivative asset or liability:
(1)
Amounts represent cash collateral posted under master netting agreements and the netting of derivative assets and liabilities. See "Credit Risk" below for discussion of cash collateral posted under master netting agreements.
(2)
Current derivative assets are included in Prepayments and Other Current Assets on the accompanying consolidated balance sheets. NSTAR Electric and WMECO derivative liabilities are included in Other Current Liabilities and Other Long-Term Liabilities on their accompanying consolidated balance sheets.
(3)
In addition to the amounts reflected in the table, as of December 31, 2011, NU had $2.3 million of hedging instruments that were classified as Level 2 in the fair value hierarchy, which related to a fair value hedge that expired on April 2, 2012 and was included in Prepayments and Other Current Assets on the accompanying consolidated balance sheet.
(4)
As of December 31, 2011, NSTAR Electric had $3.4 million of derivative liabilities classified as Level 3 within the fair value hierarchy and included in Other Long-Term Liabilities on the accompanying NSTAR Electric consolidated balance sheet. These amounts are not included in NU consolidated as of December 31, 2011.
The business activities of the Company that resulted in the recognition of derivative assets also create exposure to various counterparties. As of December 31, 2012, NU and CL&P's derivative assets are exposed to counterparty credit risk. Of these amounts, $96.5 million and $96.3 million, respectively, is contracted with investment grade entities and the remainder is contracted with multiple other counterparties.
For further information on the fair value of derivative contracts, see Note 1H, "Summary of Significant Accounting Policies - Fair Value Measurements," and Note 1I, "Summary of Significant Accounting Policies - Derivative Accounting," to the consolidated financial statements.
Derivatives Not Designated as Hedges
Commodity Supply and Price Risk Management: As required by regulation, CL&P has capacity-related contracts with generation facilities. These contracts and similar UI contracts have an expected capacity of 787 MW. CL&P has a sharing agreement with UI, with 80 percent of each contract allocated to CL&P and 20 percent allocated to UI. The capacity contracts extend through 2026 and obligate the utilities to make or receive payments on a monthly basis to or from the generation facilities based on the difference between a set capacity price and the forward capacity market price received in the ISO-NE capacity markets. In addition, CL&P has a contract to purchase 0.1 million MWh of energy per year through 2020.
NSTAR Electric has a renewable energy contract to purchase 0.1 million MWh of energy per year through 2018. NSTAR Electric also has a capacity related contract for up to 35 MW that extends through 2019.
WMECO has a renewable energy contract to purchase 0.1 million MWh of energy per year through 2028 with a facility that is expected to achieve commercial operation by November 2013.
As of December 31, 2012 and 2011, NU had approximately 24 thousand MWh and 123 thousand MWh, respectively, of supply volumes remaining in its unregulated wholesale portfolio when expected sales are compared with supply contracts.
The following table presents the realized and unrealized gains/(losses) associated with NU’s derivative contracts not designated as hedges (See Level 3 tables in the "Valuations using significant unobservable inputs" section for CL&P, NSTAR Electric and WMECO gains and losses on derivative contracts):
Hedging Instruments
Fair Value Hedge: NU parent had a fixed to floating interest rate swap on its $263 million, fixed rate senior note that matured on April 1, 2012. This interest rate swap qualified and was designated as a fair value hedge. Prior to the settlement of the swap on April 2, 2012, $2.5 million of interest benefit was recorded in Net Income in the first quarter of 2012. For the years ended December 31, 2011 and 2010, $10.5 million and $10.9 million of interest benefit was recorded in Net Income, respectively.
Cash Flow Hedges: In 2011, PSNH and WMECO settled interest rate swaps associated with $280 million and $50 million, respectively, of long-term debt issuances and as a result PSNH and WMECO recorded pre-tax reductions of $18.2 million and $6.9 million, respectively, to AOCI that are being amortized over the remaining lives of the associated debt. In addition, NU, CL&P, PSNH and WMECO continue to amortize interest rate swaps settled in prior years from AOCI into Interest Expense over the remaining life of the associated long-term debt. The pre-tax impact of cash flow hedging instruments on AOCI is as follows:
For further information, see Note 15, "Accumulated Other Comprehensive Income/(Loss)," to the consolidated financial statements.
Credit Risk
Certain of NU’s contracts contain credit risk contingent features. These features require NU to maintain investment grade credit ratings from the major rating agencies and to post collateral for contracts in a net liability position over specified credit limits. The following summarizes the fair value of derivative contracts that were in a net liability position and subject to credit risk contingent features, the fair value of cash collateral, and the additional collateral that would be required to be posted by NU if the unsecured debt credit ratings of NU parent were downgraded to below investment grade as of December 31, 2012 and 2011:
Fair Value Measurements of Derivative Instruments
Valuation of Derivative Instruments: Derivative contracts classified as Level 2 in the fair value hierarchy relate to the financial contracts for natural gas futures and the remaining unregulated wholesale marketing sourcing contracts to purchase energy for periods in which prices are quoted in an active market. Prices are obtained from broker quotes and are based on actual market activity. The contracts are valued using the mid-point of the bid-ask spread. Valuations of these contracts also incorporate discount rates using the yield curve approach.
The fair value of derivative contracts classified as Level 3 utilize significant unobservable inputs. The fair value is modeled using income techniques, such as discounted cash flow approaches adjusted for assumptions relating to exit price. Significant observable inputs for valuations of these contracts include energy and energy-related product prices in future years for which quoted prices in an active market exist. Fair value measurements categorized in Level 3 of the fair value hierarchy are prepared by individuals with expertise in valuation techniques, pricing of energy and energy-related products, and accounting requirements. The future power and capacity prices for periods that are not quoted in an active market or established at auction are based on available market data and are escalated based on estimates of inflation to address the full time period of the contract.
Valuations of derivative contracts using discounted cash flow methodology include assumptions regarding the timing and likelihood of scheduled payments and also reflect non-performance risk, including credit, using the default probability approach based on the counterparty's credit rating for assets and the company's credit rating for liabilities. Valuations incorporate estimates of premiums or discounts that would be required by a market participant to arrive at an exit price, using historical market transactions adjusted for the terms of the contract.
The following is a summary of NU’s, including CL&P’s, NSTAR Electric’s and WMECO’s, Level 3 derivative contracts and the range of the significant unobservable inputs utilized in the valuations over the duration of the contracts:
Range
Period Covered
Energy Prices:
NU
$43 - $90 per MWh
2018 - 2028
CL&P
$50 - $55 per MWh
2018 - 2020
WMECO
$43 - $90 per MWh
2018 - 2028
Capacity Prices:
NU
$1.40 - $10.53 per kW-Month
2016 - 2028
CL&P
$1.40 - $9.83 per kW-Month
2016 - 2026
NSTAR Electric
$1.40 - $3.39 per kW-Month
2016 - 2019
WMECO
$1.40 - $10.53 per kW-Month
2016 - 2028
Forward Reserve:
NU, CL&P
$0.35 - $0.90 per kW-Month
2013 - 2024
REC Prices:
NU
$25 - $85 per REC
2013 - 2028
NSTAR Electric
$25 - $71 per REC
2013 - 2018
WMECO
$25 - $85 per REC
2013 - 2028
Exit price premiums of 11 percent through 32 percent are also applied on these contracts and reflect the most recent market activity available for similar type contracts.
Significant increases or decreases in future power or capacity prices in isolation would decrease or increase, respectively, the fair value of the derivative liability. Any increases in the risk premiums would increase the fair value of the derivative liabilities. Changes in these fair values are recorded as a regulatory asset or liability and would not impact net income.
Valuations using significant unobservable inputs: The following tables present changes for the years ended December 31, 2012 and 2011, in the Level 3 category of derivative assets and derivative liabilities measured at fair value on a recurring basis. The derivative assets and liabilities are presented on a net basis. The fair value as of January 1, 2012 reflects a reclassification of remaining unregulated wholesale marketing sourcing contracts that had previously been presented as a portfolio along with the unregulated wholesale marketing sales contract as Level 3 under the highest and best use valuation premise. These contracts are now classified within Level 2 of the fair value hierarchy.
(1)
NSTAR Electric amounts are included in NU consolidated from the date of the merger, April 10, 2012, through December 31, 2012. NSTAR Electric amounts are not included in NU consolidated for the year ended December 31, 2011.
(2)
The Net Income impact for the year ended December 31, 2012 relates to the unregulated wholesale marketing sales contract and is offset by the gains/(losses) on the unregulated sourcing contracts classified as Level 2 in the fair value hierarchy, resulting in total net losses of $0.7 million.
6.
MARKETABLE SECURITIES (NU, WMECO)
NU maintains a supplemental benefit trust to fund certain of NU’s non-qualified executive retirement benefit obligations and WMECO maintains a spent nuclear fuel trust to fund WMECO’s prior period spent nuclear fuel liability, each of which hold marketable securities. These trusts are not subject to regulatory oversight by state or federal agencies. As of April 10, 2012, upon consummation of the merger with NSTAR and consolidation of CYAPC and YAEC, NU's marketable securities also includes legally restricted trusts for the decommissioning of nuclear power plants.
The Company elects to record mutual funds purchased by the NU supplemental benefit trust at fair value. As such, any change in fair value of these mutual funds is reflected in Net Income. These mutual funds, classified as Level 1 in the fair value hierarchy, totaled $47 million and $41.1 million as of December 31, 2012 and 2011, respectively, and are included in current Marketable Securities. Net gains on these securities of $5.9 million and net losses of $1.1 million for the years ended December 31, 2012 and 2011, respectively, were recorded in Other Income, Net on the accompanying consolidated statements of income. Dividend income is recorded when dividends are declared and is recorded in Other Income, Net on the accompanying consolidated statements of income. All other marketable securities are accounted for as available-for-sale.
Available-for-Sale Securities: The following is a summary of NU's available-for-sale securities held in the NU supplemental benefit trust, WMECO's spent nuclear fuel trust and CYAPC and YAEC's nuclear decommissioning trusts. These securities are recorded at fair value and included in current and long-term Marketable Securities on the accompanying consolidated balance sheets.
(1)
Unrealized gains and losses on debt securities for the NU supplemental benefit trust and WMECO spent nuclear fuel trust are recorded in AOCI and Other Long-Term Assets, respectively, on the accompanying consolidated balance sheets.
(2)
NU's December 31, 2012 amounts include CYAPC's and YAEC's marketable securities held in nuclear decommissioning trusts of $340.4 million, the majority of which are legally restricted and can only be used for the decommissioning of the nuclear power plants owned by these companies. Unrealized gains and losses for the nuclear decommissioning trusts are offset in Other Long-Term Liabilities on the accompanying consolidated balance sheet. All of the equity securities accounted for as available-for-sale securities are held in these trusts.
Unrealized Losses and Other-than-Temporary Impairment: There have been no significant unrealized losses, other-than-temporary impairments or credit losses for the NU supplemental benefit trust, the WMECO spent nuclear fuel trust, and in the trusts held by CYAPC and YAEC. Factors considered in determining whether a credit loss exists include the duration and severity of the impairment, adverse conditions specifically affecting the issuer, and the payment history, ratings and rating changes of the security. For asset-backed debt securities, underlying collateral and expected future cash flows are also evaluated.
Realized Gains and Losses: Realized gains and losses on available-for-sale securities are recorded in Other Income, Net for the NU supplemental benefit trust, Other Long-Term Assets for the WMECO spent nuclear fuel trust, and offset in Other Long-Term Liabilities for CYAPC and YAEC. NU utilizes the specific identification basis method for the NU supplemental benefit trust securities and the average cost basis method for the WMECO spent nuclear fuel trust and the CYAPC and YAEC nuclear decommissioning trusts to compute the realized gains and losses on the sale of available-for-sale securities.
Contractual Maturities: As of December 31, 2012, the contractual maturities of available-for-sale debt securities are as follows:
(1)
Amounts in the Less than one year NU category include securities in the nuclear decommissioning trusts, which are restricted and are classified in long-term Marketable Securities on the accompanying consolidated balance sheet.
Fair Value Measurements: The following table presents the marketable securities recorded at fair value on a recurring basis by the level in which they are classified within the fair value hierarchy:
U.S. government issued debt securities are valued using market approaches that incorporate transactions for the same or similar bonds and adjustments for yields and maturity dates. Corporate debt securities are valued using a market approach, utilizing recent trades of the same or similar instrument and also incorporating yield curves, credit spreads and specific bond terms and conditions. Asset-backed debt securities include collateralized mortgage obligations, commercial mortgage backed securities, and securities collateralized by auto loans, credit card loans or receivables. Asset-backed debt securities are valued using recent trades of similar instruments, prepayment assumptions, yield curves, issuance and maturity dates and tranche information. Municipal bonds are valued using a market approach that incorporates reported trades and benchmark yields. Other fixed income securities are valued using pricing models, quoted prices of securities with similar characteristics, and discounted cash flows.
7.
ASSET RETIREMENT OBLIGATIONS
In accordance with accounting guidance for conditional AROs, NU, including CL&P, NSTAR Electric, PSNH and WMECO, recognizes a liability for the fair value of an ARO on the obligation date if the liability's fair value can be reasonably estimated and is conditional on a future event. Settlement dates and future costs are reasonably estimated when sufficient information becomes available. Management has identified various categories of AROs, primarily certain assets containing asbestos and hazardous contamination and has performed fair value calculations, reflecting expected probabilities for settlement scenarios.
The fair value of an ARO is recorded as a liability in Other Long-Term Liabilities with a corresponding amount included in Property, Plant and Equipment, Net on the accompanying consolidated balance sheets. As the Regulated companies are rate-regulated on a cost-of-service basis, these companies apply regulatory accounting guidance and the costs associated with the Regulated companies' AROs are included in Regulatory Assets as of December 31, 2012 and 2011. The ARO assets are depreciated, and the ARO liabilities are accreted over the estimated life of the obligation with corresponding credits recorded as accumulated depreciation and ARO liabilities, respectively. Both the depreciation and accretion were recorded as increases to Regulatory Assets on the accompanying consolidated balance sheets as of December 31, 2012 and 2011. For further information, see Note 3, "Regulatory Accounting," to the consolidated financial statements.
A reconciliation of the beginning and ending carrying amounts of Regulated companies’ ARO liabilities are as follows:
The Liability Assumed Upon Consolidation of CYAPC and YAEC represents the CYAPC and YAEC ARO fair value as of the merger date. The fair value of the ARO for CYAPC and YAEC includes uncertainties of the fuel off-load dates related to the DOE’s timing of performance regarding its obligation to dispose of the spent nuclear fuel and high level waste. The incremental asset recorded as an offset to the ARO was fully depreciated since the plants have no remaining useful life. Any changes in the assumptions used to calculate the fair value of the ARO are recorded as an offset to the related regulatory asset. The assets held in the decommissioning trust are restricted for settling the asset retirement obligation and all other decommissioning obligations. For further information on the regulatory asset established or the assets held in trust to support this obligation, see Note 3, "Regulatory Accounting," and Note 6, "Marketable Securities," to the consolidated financial statements.
8.
SHORT-TERM DEBT
Limits: The amount of short-term borrowings that may be incurred by CL&P, NSTAR Electric and WMECO is subject to periodic approval by the FERC. On November 30, 2011, the FERC granted authorization to allow CL&P and WMECO to incur total short-term borrowings up to a maximum of $450 million and $300 million, respectively, effective January 1, 2012 through December 31, 2013. On March 22, 2012, the FERC approved CL&P's application requesting to increase its total short-term borrowing capacity from a maximum of $450 million to a maximum of $600 million for the authorization period through December 31, 2013. On May 16, 2012, the FERC granted authorization to allow NSTAR Electric to issue total short-term debt securities in an aggregate principal amount not to exceed $655 million outstanding at any one time, effective October 23, 2012 through October 23, 2014. As a result of the NHPUC having jurisdiction over PSNH's short-term debt, PSNH is not currently required to obtain FERC approval for its short-term borrowings.
PSNH is authorized by regulation of the NHPUC to incur short-term borrowings up to 10 percent of net fixed plant plus an additional $60 million until further ordered by the NHPUC. As of December 31, 2012, PSNH's short-term debt authorization under the 10 percent of net fixed plant test plus $60 million totaled approximately $280 million.
CL&P's certificate of incorporation contains preferred stock provisions restricting the amount of unsecured debt that CL&P may incur, including limiting unsecured indebtedness with a maturity of less than 10 years to 10 percent of total capitalization. In November 2003, CL&P obtained from its preferred stockholders a waiver of such 10 percent limit for a ten-year period expiring in March 2014, provided that all unsecured indebtedness does not exceed 20 percent of total capitalization. As of December 31, 2012, CL&P had $482 million of unsecured debt capacity available under this authorization.
Yankee Gas and NSTAR Gas are not required to obtain approval from any state or federal authority to incur short-term debt.
Credit Agreements and Commercial Paper Programs: On July 25, 2012, NU, CL&P, NSTAR LLC, NSTAR Gas, PSNH, WMECO, and Yankee Gas jointly entered into a five-year $1.15 billion revolving credit facility. The new facility replaced (1) the NSTAR LLC revolving credit facility of $175 million that served to backstop a commercial paper program utilized by NSTAR LLC and was scheduled to expire on December 31, 2012, (2) the NSTAR Gas revolving credit facility of $75 million that expired on June 8, 2012, and (3) the CL&P, PSNH, WMECO, and Yankee Gas joint three-year $400 million and NU parent three-year $500 million unsecured revolving credit facilities that were scheduled to expire on September 24, 2013. The new facility expires on July 25, 2017. Management expects the new facility to be used primarily to backstop the $1.15 billion commercial paper program at NU, which commenced July 25, 2012. The commercial paper program allows NU parent to issue commercial paper as a form of short-term debt. Under the terms of the agreement, NU parent may provide intercompany loans to its subsidiaries, including CL&P, PSNH and WMECO.
On July 25, 2012, NSTAR Electric entered into a five-year $450 million revolving credit facility. This new facility serves to backstop NSTAR Electric’s existing $450 million commercial paper program. The new facility expires on July 25, 2017. This new facility replaced a prior $450 million NSTAR Electric revolving credit facility that was scheduled to expire on December 31, 2012.
As of December 31, 2012, NU had $1.15 billion in short-term borrowings outstanding under its commercial paper program. The weighted-average interest rate on these borrowings as of December 31, 2012 was 0.46 percent, which is generally based on money market rates. As of December 31, 2012, there were inter-company loans of $987.5 million from NU to its subsidiaries ($405.1 million for CL&P, $63.3 million for PSNH, and $31.9 million for WMECO). As of December 31, 2012, NSTAR Electric had $276 million in short-term borrowings outstanding under its commercial paper program, leaving $174 million of available borrowing capacity. The weighted-average interest rate on these borrowings as of December 31, 2012 was 0.31 percent, which is generally based on money market rates.
As of December 31, 2011, CL&P and Yankee Gas had $31 million and $30 million, respectively, in short-term borrowings outstanding under the joint $400 million revolving credit facility with weighted average interest rates of 4.03 percent and 2.07 percent, respectively. As of December 31, 2011, NU parent had $256 million in short-term borrowings outstanding under its $500 million revolving credit facility with a weighted average interest rate of 2.20 percent. As of December 31, 2011, there were also $17.9 million, $4 million and $5.4 million in LOCs outstanding under the NU parent credit facility for NU, CL&P and PSNH, respectively. As of December 31, 2011, NSTAR Electric had $141.5 million in short-term borrowings outstanding under its existing commercial paper program with a weighted average interest rate of 0.16 percent.
Under the credit facilities, NU and its subsidiaries must comply with certain financial and non-financial covenants, including a consolidated debt to total capitalization ratio. NU and its subsidiaries were in compliance with these covenants as of December 31, 2012 and 2011. If NU or its subsidiaries were not in compliance with these covenants, an event of default would occur requiring all outstanding borrowings by such borrower to be repaid and additional borrowings by such borrower would not be permitted under the respective credit facility.
Amounts outstanding under the commercial paper program are included in Notes Payable for NU and NSTAR Electric and classified in current liabilities on the accompanying consolidated balance sheet as management anticipates that all borrowings under these credit facilities will be outstanding for no more than 364 days at one time. Intercompany loans from NU to PSNH and WMECO are included in Notes Payable to Affiliated Companies and classified in current liabilities on the accompanying consolidated balance sheet.
On January 15, 2013, CL&P issued $400 million of Series A First and Refunding Mortgage Bonds with a coupon rate of 2.5 percent and a maturity date of January 15, 2023. The proceeds, net of issuance costs, were used to pay short-term borrowings outstanding under the CL&P credit agreement and the NU commercial paper program. As a result, as of December 31, 2012, CL&P's credit agreement borrowings of $89 million and intercompany loans related to the commercial paper program of $305.8 million have been classified as Long-Term Debt on the accompanying consolidated balance sheet.
CL&P Credit Agreement: On March 26, 2012, CL&P entered into a five-year unsecured revolving credit facility in the amount of $300 million, which expires on March 26, 2017. Under this facility, CL&P can borrow either on a short-term or a long-term basis subject to regulatory approval. As of December 31, 2012, CL&P had $89 million in borrowings outstanding under this credit agreement with a weighted average interest rate of 3.325 percent.
Under this facility, CL&P may borrow at prime rates or LIBOR-based rates, plus an applicable margin based on the higher of S&P’s or Moody’s credit ratings.
In addition, CL&P must comply with certain financial and non-financial covenants, including a consolidated debt to total capitalization ratio. CL&P was in compliance with these covenants as of December 31, 2012. If CL&P was not in compliance with these covenants, an event of default would occur requiring all outstanding borrowings to be repaid and additional borrowings would not be permitted under this credit facility.
Working Capital: NU, CL&P, NSTAR Electric, PSNH and WMECO use their available capital resources to fund their respective construction expenditures, meet debt requirements, pay costs, including storm-related costs, pay dividends, and fund other corporate obligations, such as pension contributions. The current growth in NU’s transmission construction expenditures utilizes a significant amount of cash for projects that have a long-term return on investment and recovery period. In addition, NU’s Regulated companies operate in an environment where recovery of its electric and natural gas distribution construction expenditures takes place over an extended period of time. This impacts the timing of the revenue stream designed to fully recover the total investment plus a return on the equity portion of the cost and related financing costs. These factors have resulted in NU’s current liabilities exceeding current assets by approximately $1.4 billion, $268 million, $198 million and $60 million at NU, CL&P, NSTAR Electric and WMECO, respectively, as of December 31, 2012.
As of December 31, 2012, approximately $730 million of NU's current liabilities relates to long-term debt that will be paid in the next 12 months, consisting of $550 million for NU parent, $55 million for WMECO, and $125 million for CL&P. Approximately $32 million relates to the amortization of the purchase accounting fair value adjustment that will be amortized in the next twelve months. NU, with its strong credit ratings, has several options available in the financial markets to repay or refinance these maturities with the issuance of new long-term debt. NU, CL&P, NSTAR Electric, and WMECO will reduce their short-term borrowings with cash received from operating cash flows or with the issuance of new long-term debt, as deemed appropriate given capital requirements and maintenance of NU's credit rating and profile. Management expects the future operating cash flows of NU, CL&P, NSTAR Electric and WMECO along with the access to financial markets, will be sufficient to meet any future operating requirements and capital investment forecasted opportunities.
Money Pool: As of December 31, 2011, NU parent, CL&P, PSNH, WMECO, Yankee Gas and certain of NU's other subsidiaries were members of the Money Pool. Short-term borrowing needs of the member companies were met with available funds of other member companies, including funds borrowed by NU parent. Investing and borrowing subsidiaries received or paid interest based on the average daily federal funds rate. In NU's consolidated financial statements, Money Pool amounts payable to or receivable from members eliminated in consolidation. As of December 31, 2011, Money Pool amounts were as follows:
The net borrowings from/(lendings to) the Money Pool were recorded in Notes Payable to/Notes Receivable from Affiliated Companies on the accompanying consolidated balance sheets, respectively.
9.
LONG-TERM DEBT
Details of long-term debt outstanding for NU, including CL&P, NSTAR Electric, PSNH and WMECO are as follows:
(1)
On October 1, 2012, CL&P redeemed at par four different series of tax-exempt PCRBs totaling $116.4 million. The PCRBs had maturity dates ranging from 2016 through 2028 and coupon rates of 5.85 percent through 5.95 percent.
(2)
The $125 million of tax-exempt PCRBs were issued with an initial fixed rate term period ending on September 2, 2013, and are subject to mandatory tender for purchase on September 3, 2013, at which time CL&P expects to remarket the PCRBs.
(3)
On April 2, 2012, CL&P remarketed $62 million of tax-exempt PCRBs for a three-year period. The PCRBs, which mature on May 1, 2031, carry a coupon rate of 1.55 percent during the current three-year fixed rate period and are subject to mandatory tender for purchase on April 1, 2015.
(4)
On January 15, 2013, CL&P issued $400 million of 2.5 percent Series A First and Refunding Mortgage Bonds with a maturity date of January 15, 2023. The proceeds, net of issuance expenses, were used to repay the amounts outstanding under the CL&P revolver and the NU commercial paper program. As a result, these amounts have been classified as Long-Term Debt as of December 31, 2012.
(5)
NSTAR Electric amounts are not included in NU consolidated as of December 31, 2011.
(6)
On October 15, 2012, NSTAR Electric issued at a discount $400 million of 2.375 percent Debentures at a yield of 2.406 percent that will mature on October 15, 2022. The proceeds, net of issuance costs, were used to pay $400 million of 4.875 percent Debentures that matured on October 15, 2012.
(7)
On October 1, 2012, WMECO redeemed at par $53.8 million of tax-exempt PCRBs. The PCRBs had a maturity date of 2028 and a coupon of 5.85 percent.
(8)
On October 4, 2012, WMECO issued at a premium $150 million of senior unsecured notes at a yield of 2.673 percent that will mature on September 15, 2021. The senior notes are part of the same series of WMECO’s existing 3.5 percent coupon Series F Senior Notes that were initially issued in September 2011. As a result, the aggregate principal amount of WMECO’s outstanding Series F Senior Notes totaled $250 million.
(9)
On March 22, 2012, NU parent issued $300 million of floating rate Series D Senior Notes with a maturity date of September 20, 2013. The notes have a coupon rate based on the three-month LIBOR rate plus a credit spread of 0.75 percent and will reset quarterly. The notes had an interest rate of 1.059 percent as of December 31, 2012. The proceeds, net of issuance expenses, were used to repay at maturity the NU parent $263 million Series A Senior Notes that matured on April 1, 2012, to repay short-term borrowings outstanding under the NU parent Credit Agreement and for other general corporate purposes.
(10)
As of December 31, 2012, amount relates to the purchase price adjustment required to record the NSTAR long-term debt issuances at fair value on the date of the merger. As of December 31, 2011, amount related to a fixed to floating interest rate swap on the $263 million NU parent note that matured on April 1, 2012. The change in fair value of the interest component of the debt was recorded as an adjustment to Current Portion - Long Term Debt as of December 31, 2011 with an equal and offsetting adjustment to Current Derivative Assets.
Long-term debt maturities and cash sinking fund requirements on debt outstanding as of December 31, 2012 for the years 2013 through 2017 and thereafter, are shown below. These amounts exclude fees and interest due for spent nuclear fuel disposal costs, net unamortized premiums and discounts, and other fair value adjustments as of December 31, 2012:
The utility plant of CL&P, PSNH, Yankee Gas and NSTAR Gas is subject to the lien of each company's respective first mortgage bond indenture. NSTAR Electric, WMECO, NU Parent and NSTAR LLC debt is unsecured.
The PSNH Series A and Series C tax-exempt bonds are currently callable at 100 percent and 101 percent of par, respectively. The PSNH Series B tax-exempt bond will become callable in June 2013. CL&P’s $125 million and $62 million tax-exempt PCRBs, which are subject to mandatory tender for purchase on September 3, 2013 and April 1, 2015, respectively, cannot be redeemed prior to their respective tender dates. CL&P’s $120.5 million tax-exempt PCRBs will be subject to redemption at par on or after September 1, 2021. All other long-term debt securities are subject to make-whole provisions.
As of December 31, 2012, CL&P had $307.5 million of tax-exempt PCRBs outstanding. CL&P’s obligation to repay each series of PCRBs is secured by first mortgage bonds. Each such series of first mortgage bonds contains similar terms and provisions as the applicable series of PCRBs. If CL&P failed to meet its obligations under the PCRBs, then these first mortgage bonds would become outstanding.
As of December 31, 2012, PSNH had $287.5 million in PCRBs outstanding. PSNH's obligation to repay each series of PCRBs is secured by first mortgage bonds and bond insurance. Each such series of first mortgage bonds contains similar terms and provisions as the applicable series of PCRBs. If PSNH failed to meet its obligations under the PCRBs, then these first mortgage bonds would become outstanding. The 2001 Series A PCRBs, in the aggregate principal amount of $89.3 million, bears interest at a rate that is periodically set pursuant to auctions. PSNH is not obligated to purchase these PCRBs, which mature in 2021, from the remarketing agent. The weighted average effective interest rate on PSNH's Series A variable-rate PCRBs was 0.20 percent in 2012 and 0.21 percent in 2011.
NU's, including CL&P, NSTAR Electric, PSNH and WMECO, long-term debt agreements provide that NU and certain of its subsidiaries must comply with certain covenants as are customarily included in such agreements, including a minimum equity requirement for NSTAR Gas. Under the minimum equity requirement, the outstanding long-term debt of NSTAR Gas must not exceed equity. NU and these subsidiaries were in compliance with these covenants as of December 31, 2012 and 2011.
Yankee Gas has certain long-term debt agreements that contain cross-default provisions applicable to all of Yankee Gas’ outstanding first mortgage bond series. The cross-default provisions on Yankee Gas’ Series B Bonds would be triggered if Yankee Gas were to default on a payment due on indebtedness in excess of $2 million. The cross-default provisions on all other series of Yankee Gas’ first mortgage bonds would be triggered if Yankee Gas were to default in a payment due on indebtedness in excess of $10 million. No other debt issuances contain cross-default provisions as of December 31, 2012.
Spent Nuclear Fuel Obligation: Under the Nuclear Waste Policy Act of 1982, CL&P and WMECO must pay the DOE for the costs of disposal of spent nuclear fuel and high-level radioactive waste for the period prior to the sale of their ownership shares in the Millstone nuclear power stations.
The DOE is responsible for the selection and development of repositories for, and the disposal of, spent nuclear fuel and high-level radioactive waste. For nuclear fuel used to generate electricity prior to April 7, 1983 (Prior Period Spent Nuclear Fuel) for CL&P and WMECO, an accrual has been recorded for the full liability, and payment must be made by CL&P and WMECO to the DOE prior to the first delivery of spent fuel to the DOE. After the sale of Millstone, CL&P and WMECO remained responsible for their share of the disposal costs associated with the Prior Period Spent Nuclear Fuel. Until such payment to the DOE is made, the outstanding liability will continue to accrue interest at the 3-month Treasury bill yield rate. In addition, as a result of consolidating CYAPC, NU has consolidated $179.3 million in additional spent nuclear fuel obligations, including interest, as of December 31, 2012. Fees due to the DOE for the disposal of CL&P's and WMECO's Prior Period Spent Nuclear Fuel and CYAPC's and YAEC's spent nuclear fuel obligation include accumulated interest costs of $350 million and $219.3 million for NU ($177.8 million and $177.6 million for CL&P and $41.7 million and $41.7 million for WMECO) as of December 31, 2012 and 2011, respectively.
For further information, see Note 1B, "Summary of Significant Accounting Policies - Basis of Presentation," to the consolidated financial statements.
WMECO maintains a trust that holds marketable securities to fund amounts due to the DOE for the disposal of WMECO's Prior Period Spent Nuclear Fuel. CYAPC also maintain trusts to fund amounts due to the DOE for the disposal of spent nuclear fuel. For further information on these trusts, see Note 6, "Marketable Securities," to the consolidated financial statements.
10.
EMPLOYEE BENEFITS
A.
Pension Benefits and Postretirement Benefits Other Than Pensions
NUSCO sponsors a defined benefit retirement plan that covers most employees, including CL&P, PSNH, and WMECO employees, hired before 2006 (or as negotiated, for bargaining unit employees), referred to as the NUSCO Pension Plan. NSTAR Electric serves as plan sponsor for a defined benefit retirement plan that covers most employees of NSTAR Electric & Gas, hired before October 1, 2012, or as negotiated by bargaining unit employees, referred to as the NSTAR Pension Plan. Both plans are subject to the provisions of ERISA, as amended by the PPA of 2006. NUSCO and NSTAR Electric & Gas each maintain SERPs and other non-qualified defined benefit retirement plans (herein collectively referred to as the SERP Plans), which provide benefits in excess of Internal Revenue Code limitations to eligible current and retired participants that would have otherwise been provided under the Pension Plans.
NUSCO and NSTAR Electric & Gas also sponsor defined benefit postretirement plans that provide certain retiree health care benefits, primarily medical and dental, and life insurance benefits to retiring employees that meet certain age and service eligibility requirements (NUSCO PBOP Plans and NSTAR PBOP Plan, respectively). Under certain circumstances, eligible retirees are required to contribute to the costs of postretirement benefits. The benefits provided under the NUSCO and NSTAR PBOP Plans are not vested and the Company has the right to modify any benefit provision subject to applicable laws at that time.
The funded status of the Pension, SERP and PBOP Plans is calculated based on the difference between the benefit obligation and the fair value of plan assets. The funded status of the Pension, SERP and PBOP Plans is recorded on the consolidated balance sheets as a liability with an offset to Accumulated Other Comprehensive Income/(Loss). Pension, SERP and PBOP costs for the Regulated companies are recorded as Regulatory Assets as these amounts are recovered from customers. Regulatory accounting was also applied to the portions of the NUSCO and NSTAR Electric & Gas costs that support the Regulated companies, as these costs are also recovered from customers. Pension and PBOP costs for the unregulated companies are recorded on an after-tax basis to Accumulated Other Comprehensive Income/(Loss). For further information, see Note 3, "Regulatory Accounting," and Note 15, "Accumulated Other Comprehensive Income/(Loss)," to the consolidated financial statements. The SERP Plans do not have plan assets.
For the NUSCO Pension and PBOP Plans, the expected return on plan assets is calculated by applying the assumed rate of return to a four-year rolling average of plan asset fair values, which reduces year-to-year volatility. Investment gains or losses for this purpose are the difference between the calculated expected return and the actual return. As investment gains and losses are reflected in the average plan asset fair values, they are subject to amortization with other unrecognized actuarial gains or losses. For the NSTAR Pension and PBOP Plans, the entire difference between the actual return and calculated expected return on plan assets is reflected as a component of unrecognized actuarial gain or loss. Unrecognized actuarial gains or losses are amortized as a component of Pension and PBOP expense over the estimated average future employee service period.
Pension and SERP Plans: The funded status of each of the plans is recorded on the respective sponsor's balance sheet: NUSCO (NUSCO Pension and NUSCO SERP), NSTAR Electric (NSTAR Pension) and NSTAR Electric & Gas (NSTAR SERP). The NUSCO plans are accounted for under the multiple-employer approach while the NSTAR plans are accounted for under the multi-employer approach. Accordingly, the balance sheet of NSTAR Electric reflects the full funded status of the NSTAR Pension Plan.
The following tables provide information on the Pension and SERP Plan benefit obligations, fair values of Pension Plan assets, and funded status:
The following actuarial assumptions were used in calculating the Pension and SERP Plans' year end funded status:
Pension and SERP Expense: For the NUSCO Plans, NU allocates net periodic pension expense to its subsidiaries based on the actual participant demographic data for each subsidiary's participants. Benefit payments to participants and contributions are also tracked for each subsidiary. The actual investment return in the trust each year is allocated to each of the subsidiaries annually in proportion to the investment return expected to be earned during the year. For the NSTAR Pension Plan, the net periodic pension expense recorded at NSTAR Electric represents the full cost of the plan and then a portion of the costs are allocated to affiliated companies based on participant demographic data. The components of net periodic benefit expense, the portion of pension amounts capitalized related to employees working on capital projects, and intercompany allocations not included in the net periodic benefit expense amounts for the Pension and SERP Plans were as follows:
The following actuarial assumptions were used to calculate Pension and SERP expense amounts:
(1)
The NU consolidated amounts reflect the NSTAR Pension and SERP Plans from the date of the merger, April 10, 2012, through December 31, 2012.
NSTAR Electric continues to maintain reporting requirements as an SEC registrant. Included in the amounts above as of December 31, 2012 are $724 million of unrecognized actuarial losses included in Regulatory Assets for NSTAR Electric. For the year ended December 31, 2012, NSTAR Electric reclassified $62.8 million of actuarial losses and $0.6 million of prior service credit as net periodic benefit expense and $4.6 million of actuarial losses arose during the year. As of December 31, 2011, NSTAR Electric had $782.3 million of unrecognized actuarial losses and $0.6 million of prior service credit included in Regulatory Assets. For the year ended December 31, 2011, NSTAR Electric reclassified $48.4 million of actuarial losses and $0.7 million of prior service credit as net periodic benefit expense and $212 million of actuarial losses arose during the year.
PBOP Plans: The NUSCO Plans are accounted for under the multiple-employer basis while the NSTAR Plan is accounted for under the multi-employer basis. Accordingly, the funded status of the NUSCO PBOP Plans is allocated to its subsidiaries, including CL&P, PSNH and WMECO, while the NSTAR PBOP Plan is not reflected on the SEC registrant NSTAR Electric’s balance sheet.
NU annually funds postretirement costs through tax deductible contributions to external trusts.
The following tables represent information on PBOP Plan benefit obligations, fair values of plan assets, and funded status:
PBOP Expense: For the NUSCO Plans, NU allocates net periodic postretirement benefits expense to its subsidiaries based on the actual participant demographic data for each subsidiary's participants. Benefit payments to participants and contributions are also tracked for each subsidiary. The actual investment return in the trust is allocated to each of the subsidiaries annually in proportion to the investment return expected to be earned during the year. For the NSTAR Plan, NSTAR allocates the net periodic postretirement expenses to its subsidiaries based on actual participant demographic data for each of its subsidiaries. The net periodic postretirement expense allocated to NSTAR Electric was $34.1 million, $26 million, and $33 million for the years ended December 31, 2012, 2011 and 2010, respectively.
The components of net periodic postretirement benefit expense and intercompany allocations not included in the net periodic benefit expense amounts for the PBOP Plans were as follows:
(1)
The NU consolidated amounts include the NSTAR PBOP Plan from the date of the merger, April 10, 2012, through December 31, 2012.
For the NUSCO PBOP Plans, the health care cost trend assumption is 7 percent, subsequently decreasing 50 basis points per year to an ultimate rate of 5 percent in 2017. For the NSTAR PBOP Plan, the health care cost trend assumption is 7.10 percent, subsequently decreasing to an ultimate rate of 4.50 percent in 2024.
Assumed health care cost trend rates have a significant effect on the amounts reported for the health care plans. The effect of changing the assumed health care cost trend rate by one percentage point for the year ended December 31, 2012 would have the following effects:
Contributions: NU’s policy is to annually fund the NUSCO and NSTAR Pension Plans in an amount at least equal to an amount that will satisfy federal requirements. NU contributed $197.4 million to the NUSCO Pension Plan in 2012, of which $87.7 million was contributed by PSNH. NSTAR Electric contributed $25 million to the NSTAR Pension Plan for the year ended December 31, 2012. Based on the current status of the NUSCO Pension Plan, NU anticipates making a contribution of approximately $203 million in 2013, of which $107 million is required to meet minimum federal funding requirements. NSTAR Electric anticipates making a contribution of approximately $82 million in 2013 to the NSTAR Pension Plan, of which $38 million is required to meet minimum federal funding requirements.
For the PBOP Plans, it is NU’s policy to annually fund the NUSCO PBOP Plans in an amount equal to the PBOP Plans' postretirement benefit cost, excluding curtailment and termination benefits. NU contributed $50 million to the NUSCO PBOP Plans in 2012 and expects to make $25.7 million in contributions in 2013. NU contributes an amount that approximates annual benefit payments to the NSTAR PBOP Plan. NU contributed $22.7 million to the NSTAR PBOP Plan for the period April 10, 2012 to December 31, 2012 and expects to make $30 million in contributions in 2013.
Fair Value of Pension and PBOP Plan Assets: Pension and PBOP funds are held in external trusts. Trust assets, including accumulated earnings, must be used exclusively for Pension and PBOP payments. NU's investment strategy for its Pension and PBOP Plans is to maximize the long-term rates of return on these plans' assets within an acceptable level of risk. The investment strategy for each asset category includes a diversification of asset types, fund strategies and fund managers and establishes target asset allocations that are routinely reviewed and periodically rebalanced. In 2012, PBOP assets were comprised of specific assets within the defined benefit pension plan trust (401(h) assets) as well as assets held in the PBOP Plans. The investment policy and strategy of the 401(h) assets is consistent with those of the defined benefit pension plans, which are detailed below. NU's expected long-term rates of return on Pension and PBOP Plan assets are based on these target asset allocation assumptions and related expected long-term rates of return. In developing its expected long-term rate of return assumptions for the Pension and PBOP Plans, NU evaluated input from actuaries and consultants, as well as long-term inflation assumptions and historical returns. For the year ended December 31, 2012, management has assumed long-term rates of return of 8.25 percent on NUSCO Pension and PBOP Plan assets and 7.30 percent on the NSTAR Pension and PBOP Plan assets. These long-term rates of return are based on the assumed rates of return for the target asset allocations as follows:
The following table presents, by asset category, the Pension and PBOP Plan assets recorded at fair value on a recurring basis by the level in which they are classified within the fair value hierarchy:
(1)
The NSTAR Pension Plan amounts are not included in NU consolidated as of December 31, 2011.
(2)
United States, International and Emerging Markets equity securities classified as Level 2 include investments in commingled funds and unrealized gains/(losses) on holdings in equity index swaps. Level 3 investments include hedge funds that are overlayed with equity index swaps and futures contracts and funds invested in equities that have redemption restrictions.
(3)
Fixed Income investments classified as Level 3 investments include fixed income funds that invest in a variety of opportunistic fixed income strategies, and hedge funds that are overlayed with fixed income futures.
(4)
The assets of the Pension Plans include a 401(h) account that has been allocated to provide health and welfare postretirement benefits under the PBOP Plans.
(5)
For NSTAR Electric, certain pension assets have been reclassified to the current year presentation in order to align the reporting of pension assets subsequent to the closing of the merger.
CL&P, PSNH and WMECO participate in the NUSCO Pension Plan and NUSCO PBOP Plans. Each company participating in the plans is allocated a portion of the total plan assets. As of December 31, 2012 and 2011, the NUSCO Pension Plan has total assets of $2,342.6 million and $2,005.9 million, respectively. CL&P, PSNH and WMECO’s portion of these total plan assets were 40 percent, 17 percent and 9 percent, respectively, as of December 31, 2012, and 43 percent, 14 percent and 10 percent, respectively, as of December 31, 2011. The NUSCO PBOP Plans had total plan assets of $334.9 million and $285.4 million as of December 31, 2012 and
2011, respectively. CL&P, PSNH and WMECO’s share of these assets were 39 percent, 21 percent and 9 percent, respectively, as of both December 31, 2012 and 2011.
The Company values assets based on observable inputs when available. Equity securities, exchange traded funds and futures contracts classified as Level 1 in the fair value hierarchy are priced based on the closing price on the primary exchange as of the balance sheet date. Commingled funds included in Level 2 equity securities are recorded at the net asset value provided by the asset manager, which is based on the market prices of the underlying equity securities. Swaps are valued using pricing models that incorporate interest rates and equity and fixed income index closing prices to determine a net present value of the cash flows. Fixed income securities, such as government issued securities, corporate bonds and high yield bond funds, are included in Level 2 and are valued using pricing models, quoted prices of securities with similar characteristics or discounted cash flows. The pricing models utilize observable inputs such as recent trades for the same or similar instruments, yield curves, discount margins and bond structures. Hedge funds and investments in opportunistic fixed income funds are recorded at net asset value based on the values of the underlying assets. The assets in the hedge funds and opportunistic fixed income funds are valued using observable inputs and are classified as Level 3 within the fair value hierarchy due to redemption restrictions. Private Equity investments and Real Estate and Other Assets are valued using the net asset value provided by the partnerships, which are based on discounted cash flows of the underlying investments, real estate appraisals or public market comparables of the underlying investments. These investments are classified as Level 3 due to redemption restrictions.
Fair Value Measurements Using Significant Unobservable Inputs (Level 3): The following tables present changes for the Level 3 category of Pension and PBOP Plan assets for the years ended December 31, 2012 and 2011:
B.
Defined Contribution Plans
NU maintains two defined contribution plans on behalf of eligible participants. The NUSCO 401(k) Savings Plan covers eligible employees, including CL&P, PSNH, WMECO, and effective October 1, 2012, certain newly-hired NSTAR Electric & Gas employees. The NSTAR 401(k) Savings Plan covers eligible employees of NSTAR Electric & Gas. These defined contribution plans provide for employee and employer contributions up to statutory limits.
The NUSCO 401(k) Savings Plan matches employee contributions up to a maximum of three percent of eligible compensation with one percent invested in cash and two percent invested in the NU common share fund. The NUSCO 401(k) Savings Plan also contains a K-Vantage feature (company contribution based on age and years of service), which covers the majority of NU non-represented employees hired on or after January 1, 2006 and certain NU bargaining unit employees, hired on or after January 1, 2007 or as subject to collective bargaining agreements. In addition, all newly hired non-represented NSTAR Electric & Gas employees and certain represented NSTAR Electric & Gas employees are eligible to participate in the K-Vantage program effective October 1, 2012 and November 1, 2012, respectively. Participants in the K-Vantage program are not eligible to actively participate in any NU defined benefit plan.
The NSTAR 401(k) Savings Plan matches employee contributions of 50 percent on up to the first 8 percent of eligible compensation. All employer contributions are invested in the NU common share fund.
The total defined contribution plan matching contributions, including the K-Vantage program contributions, are as follows:
(1)
NSTAR Electric amounts are included in NU consolidated from the date of the merger, April 10, 2012, through December 31, 2012. NSTAR Electric amounts are not included in NU consolidated for the years ended December 31, 2011 and 2010.
C.
Employee Stock Ownership Plan
NU maintains an ESOP for purposes of allocating shares to employees participating in the NUSCO 401(k) Savings Plan. Allocations of NU common shares were made from NU treasury shares to satisfy the NUSCO 401(k) Savings Plan obligation to provide a portion of the matching contribution in NU common shares.
For treasury shares used to satisfy the 401(k) Savings Plan matching contributions, compensation expense is recognized equal to the fair value of shares that have been allocated to participants. Any difference between the fair value and the average cost of the allocated treasury shares is charged or credited to Capital Surplus, Paid In. For the years ended December 31, 2012, 2011 and 2010, NU recognized $8.9 million, $8.8 million and $8.5 million, respectively, of expense related to the ESOP.
D.
Share-Based Payments
Share-based compensation awards are recorded using the fair value-based method at the date of grant. NU, CL&P, NSTAR Electric, PSNH and WMECO record compensation cost related to these awards, as applicable, for shares issued or sold to their respective employees and officers, as well as the allocation of costs associated with shares issued or sold to NU's service companies' employees and officers that support CL&P, NSTAR Electric, PSNH and WMECO.
Upon consummation of the merger with NSTAR, the NSTAR 1997 Share Incentive Plan and the NSTAR 2007 Long-Term Incentive Plan were assumed by NU. Share-based awards granted under the NSTAR Plans and held by NSTAR employees and officers were generally converted into outstanding NU share-based compensation awards with an estimated fair value of $53.2 million. Refer to Note 2, "Merger of NU and NSTAR," for further information regarding the merger transaction. Specifically, as of the merger closing, and as adjusted by the exchange ratio, (1) NU converted outstanding NSTAR stock options into 2,664,894 NU stock options valued at $30.5 million, (2) NU converted NSTAR deferred shares and NSTAR performance shares into 421,775 NU RSU’s valued at $15.5 million, and (3) NU converted NSTAR RSU retention awards into 195,619 NU RSU retention awards valued at $7.2 million.
NU Incentive Plan: NU maintains long-term equity-based incentive plans under the NU Incentive Plan in which NU, CL&P, PSNH and WMECO employees, officers and board members are entitled to participate. The NU Incentive Plan was approved in 2007, and authorized NU to grant up to 4,500,000 new shares for various types of awards, including RSUs and performance shares, to eligible employees, officers, and board members. As of December 31, 2012 and 2011, NU had 2,502,512 and 2,685,615 common shares, respectively, available for issuance under the NU Incentive Plan. In addition to the NU Incentive Plan, NU maintains an ESPP for eligible employees.
NSTAR Incentive Plans: Awards may continue to be granted following the merger under the NSTAR 2007 Long-Term Incentive Plan; however, no additional awards will be granted under the NSTAR 1997 Share Incentive Plan. The aggregate number of common shares initially authorized for issuance under the NSTAR 2007 Long-Term Incentive Plan was 3,500,000. As of December 31, 2012, there were 977,922 NU common shares available for issuance under the NSTAR 2007 Long-Term Incentive Plan.
NU accounts for its various share-based plans as follows:
·
RSUs - NU records compensation expense, net of estimated forfeitures, on a straight-line basis over the requisite service period based upon the fair value of NU's common shares at the date of grant. The par value of RSUs is reclassified to Common Stock from APIC as RSUs become issued as common shares.
·
Performance Shares - NU records compensation expense, net of estimated forfeitures, on a straight-line basis over the requisite service period. Performance shares vest based upon the extent to which Company goals are achieved. For the majority of performance shares, fair value is based upon the value of NU's common shares at the date of grant and compensation expense is recorded based upon the probable outcome of the achievement of Company targets. For the remaining performance shares, vesting is based upon the achievement of the Company's share price as compared to an index of similar equity securities. The fair value at the date of grant for these remaining performance shares was determined using a lattice model and compensation expense is recorded over the requisite service period.
·
Stock Options - Stock options issued under the NSTAR Incentive Plan that were outstanding immediately prior to the completion of the merger with NSTAR converted into fully vested options to acquire NU common shares, as adjusted by the exchange ratio. The fair value of these awards on the merger date was included in the purchase price as it represented consideration transferred in the merger. Accordingly, no compensation expense is recorded for these stock options. Additionally, no compensation expense is recorded for stock options issued under the NU Incentive Plan as these stock options were fully vested prior to January 1, 2006.
·
ESPP Shares - For shares sold under the ESPP, no compensation expense is recorded, as the ESPP qualifies as a non-compensatory plan.
RSUs: NU granted RSUs under the annual Long-Term incentive programs that are subject to three-year graded vesting schedules for employees, and one-year graded vesting schedules for board members. RSUs are paid in shares, reduced by amounts sufficient to satisfy withholdings for income taxes, subsequent to vesting. A summary of RSU transactions is as follows:
As of December 31, 2012 and 2011, the number and weighted average grant-date fair value of unvested RSUs was 1,417,688 and $34.70 per share, and 403,108 and $28.70 per share, respectively. The number and weighted average grant-date fair value of RSUs vested during 2012 was 471,323 and $30.20 per share, respectively. As of December 31, 2012, 765,631 RSUs were fully vested and an additional 1,346,804 are expected to vest.
Performance Shares: NU had granted performance shares under the annual Long-Term Incentive programs that vested based upon the extent to which the Company achieved targets at the end of three-year performance measurement periods. Performance shares are paid in shares, after the performance measurement period. A summary of performance share transactions is as follows:
Upon closing of the merger with NSTAR, 451,358 performance shares under the NU 2011 and 2012 Long-Term Incentive Programs converted to RSUs according to the terms of these programs. The remaining performance shares were measured based upon a modified performance period through the date of the merger, in accordance with the terms of the NU 2010 Incentive Program, with distribution in 2013.
The total compensation cost and associated future income tax benefit recognized by NU, CL&P, NSTAR Electric, PSNH and WMECO for share-based compensation awards were as follows:
(1)
NSTAR Electric amounts are included in NU consolidated from the date of the merger, April 10, 2012, through December 31, 2012. NSTAR Electric amounts are not included in NU consolidated for the years ended December 31, 2011 and 2010.
As of December 31, 2012, there was $26.1 million of total unrecognized compensation cost related to nonvested share-based awards for NU, $5.3 million for CL&P, $10.6 million for NSTAR Electric, $1.8 million for PSNH and $1.1 million for WMECO. This cost is expected to be recognized ratably over a weighted-average period of 1.90 years for NU, 2.03 years for CL&P, 1.76 years for NSTAR Electric and 1.84 years for PSNH and WMECO.
For the years ended December 31, 2012, 2011 and 2010, additional tax benefits totaling $8.5 million, $1.3 million and $0.9 million, respectively, increased cash flows from financing activities.
Stock Options: Stock options were granted under the NU and NSTAR Incentive Plans. Options currently outstanding expire ten years from the date of grant and are fully vested. The weighted average remaining contractual lives for the options outstanding as of December 31, 2012 is 4.8 years. A summary of stock option transactions is as follows:
Cash received for options exercised during the year ended December 31, 2012 totaled $26.3 million. The tax benefit realized from stock options exercised totaled $7.5 million for the year ended December 31, 2012.
Employee Share Purchase Plan: NU maintains an ESPP for eligible employees, which allows for NU common shares to be purchased by employees at the end of successive six-month offering periods at 95 percent of the closing market price on the last day of each six-month period. Employees are permitted to purchase shares having a value not exceeding 25 percent of their compensation as of the beginning of the offering period up to a limit of $25,000 per annum. The ESPP qualifies as a non-compensatory plan under accounting guidance for share-based payments, and no compensation expense is recorded for ESPP purchases.
During 2012, employees purchased 39,422 shares at discounted prices of $33.01 and $37.89. Employees purchased 35,476 shares in 2011 at discounted prices of $31.27 and $32.30. As of December 31, 2012 and 2011, 857,280 and 896,702 shares, respectively, remained available for future issuance under the ESPP.
An income tax rate of 40 percent is used to estimate the tax effect on total share-based payments determined under the fair value-based method for all awards. The Company generally settles stock option exercises and fully vested RSUs and performance shares with either the issuance of new common shares or the issuance of common shares purchased in the open market.
E.
Other Retirement Benefits
NU provides benefits for retirement and other benefits for certain current and past company officers of NU, including CL&P, PSNH and WMECO. These benefits are accounted for on an accrual basis and expensed over the service lives of the employees. The actuarially-determined liability for these benefits, which is included in Other Long-Term Liabilities on the accompanying consolidated balance sheets, as well as the related expense, were as follows:
11.
INCOME TAXES
The tax effect of temporary differences is accounted for in accordance with the rate-making treatment of the applicable regulatory commissions and relevant accounting authoritative literature. The components of income tax expense are as follows:
NU, CL&P, NSTAR Electric, PSNH and WMECO file a consolidated federal income tax return and unitary, combined and separate state income tax returns. These entities are also parties to a tax allocation agreement under which taxable subsidiaries do not pay any more taxes than they would have otherwise paid had they filed a separate company tax return, and subsidiaries generating tax losses, if any, are paid for their losses when utilized.
Deferred tax assets and liabilities are recognized for the future tax effects of temporary differences between the carrying amounts and the tax basis of assets and liabilities. The tax effects of temporary differences that give rise to the net accumulated deferred tax obligations are as follows:
For 2012, the state net operating loss carryforward has been partially reserved by a valuation allowance of $0.3 million (net of federal income tax).
Unrecognized Tax Benefits: A reconciliation of the activity in unrecognized tax benefits from January 1, 2010 to December 31, 2012, all of which would impact the effective tax rate, if recognized, is as follows:
(1)
NSTAR Electric amounts are not included in NU consolidated for the years ended December 31, 2011 and 2010.
Interest and Penalties: Interest on uncertain tax positions is recorded and generally classified as a component of Other Interest Expense. However, when resolution of uncertainties results in the Company receiving interest income, any related interest benefit is recorded in Other Income, Net on the accompanying consolidated statements of income. No penalties have been recorded. If
penalties are recorded in the future, then the estimated penalties would be classified as a component of Other Income, Net on the accompanying consolidated statements of income. The amount of interest expense/(income) on uncertain tax positions recognized and the related accrued interest payable/(receivable) by company are as follows:
(1)
NSTAR Electric amounts are included in NU consolidated from the date of the merger, April 10, 2012, through December 31, 2012. NSTAR Electric amounts are not included in NU consolidated for the years ended December 31, 2011 and 2010.
Tax Positions: During 2012, NU did not resolve any of its uncertain tax positions.
During 2011, NU recorded an after-tax benefit of $29.1 million related to various state tax settlements and certain other adjustments. This benefit was recorded as a reduction to both interest expense and income tax expense (including NU and CL&P tax expense reductions of approximately $22.4 million).
During 2010, NU settled various tax matters including state obligations, which resulted in the recognition during the year of an after-tax gain of approximately $35 million. This gain was recorded as a reduction to both interest expense and income tax expense (including NU and CL&P tax expense reductions of approximately $6 million and $4 million, respectively).
Open Tax Years: The following table summarizes NU, CL&P, NSTAR Electric, PSNH and WMECO's tax years that remain subject to examination by major tax jurisdictions as of December 31, 2012:
Description
Tax Years
Federal
Connecticut
2005-2012
Massachusetts
2009-2012
New Hampshire
2009-2012
Receipt of Federal Tax Refund: During 2011, NSTAR Electric received a $166.8 million refund from the IRS relating to the 2001 through 2007 tax years. The approved settlement and the receipt of the refund resolved all outstanding tax matters for these years.
NU is currently working to resolve the treatments and certain timing and other costs in the remaining open periods. While tax audits are currently ongoing, it is reasonably possible that one or more of these open tax years could be resolved within the next twelve months. Management estimates that potential resolutions of differences of a non-timing nature could result in a zero to $50 million decrease in unrecognized tax benefits by NU and a zero to $39 million decrease in unrecognized tax benefits by CL&P. These estimated changes could have an impact on NU's and CL&P's 2013 earnings of zero to $6 million and zero to $16 million, respectively. Other companies’ impacts are not expected to be material.
2013 Federal Legislation: On January 2, 2013, President Obama signed into law the "American Taxpayer Relief Act of 2012," which extends certain tax rules allowing the accelerated deduction of depreciation from the "American Recovery and Reinvestment Act of 2009" to businesses through 2013. This extended stimulus is expected to provide cash flow benefits of approximately $200 million to $250 million in 2013 and 2014. Management is still evaluating the other provisions of this legislation, which are not expected to have a significant impact on its future financial position, results of operations, or cash flows.
12.
COMMITMENTS AND CONTINGENCIES
A.
Environmental Matters
General: NU, CL&P, NSTAR Electric, PSNH and WMECO are subject to environmental laws and regulations intended to mitigate or remove the effect of past operations and improve or maintain the quality of the environment. These laws and regulations require the removal or the remedy of the effect on the environment of the disposal or release of certain specified hazardous substances at current and former operating sites. NU, CL&P, NSTAR Electric, PSNH and WMECO have an active environmental auditing and training program and believe that they are substantially in compliance with all enacted laws and regulations.
Environmental reserves are accrued when assessments indicate it is probable that a liability has been incurred and an amount can be reasonably estimated. The approach used estimates the liability based on the most likely action plan from a variety of available remediation options, including no action required or several different remedies ranging from establishing institutional controls to full site remediation and monitoring.
These estimates are subjective in nature as they take into consideration several different remediation options at each specific site. The reliability and precision of these estimates can be affected by several factors, including new information concerning either the level of
contamination at the site, the extent of NU, CL&P, NSTAR Electric, PSNH and WMECO's responsibility or the extent of remediation required, recently enacted laws and regulations or a change in cost estimates due to certain economic factors.
The amounts recorded as environmental liabilities included in Other Current Liabilities and Other Long-Term Liabilities on the accompanying consolidated balance sheets represent management's best estimate of the liability for environmental costs, and take into consideration site assessment, remediation and long-term monitoring costs. The environmental liability also takes into account recurring costs of managing hazardous substances and pollutants, mandated expenditures to remediate previously contaminated sites and any other infrequent and non-recurring clean up costs. A reconciliation of the activity in the environmental reserves is as follows:
(1)
NSTAR Electric amounts are included in NU consolidated from the date of the merger, April 10, 2012 through December 31, 2012. NSTAR Electric amounts are not included in NU consolidated for the years ended December 31, 2011 and 2010.
These liabilities are estimated on an undiscounted basis and do not assume that any amounts are recoverable from insurance companies or other third parties. The environmental reserves include sites at different stages of discovery and remediation and do not include any unasserted claims.
It is possible that new information or future developments could require a reassessment of the potential exposure to related environmental matters. As this information becomes available, management will continue to assess the potential exposure and adjust the reserves accordingly.
The number of environmental sites and reserves related to these sites for which remediation or long-term monitoring, preliminary site work or site assessment are being performed are as follows:
(1)
The NSTAR Electric reserve balance and number of sites are not included in NU consolidated amounts as of December 31, 2011.
Included in the NU number of sites and reserve amounts above are former MGP sites that were operated several decades ago and manufactured gas from coal and other processes, which resulted in certain by-products remaining in the environment that may pose a potential risk to human health and the environment. The reserve balance related to these former MGP sites was $34.5 million and $28.9 million as of December 31, 2012 and 2011, respectively, and relates primarily to the natural gas business segment.
As of December 31, 2012, for 8 environmental sites (3 for CL&P, 2 for PSNH, and 1 for WMECO) that are included in the Company's reserve for environmental costs, the information known and nature of the remediation options at those sites allow for the Company to estimate the range of losses for environmental costs. As of December 31, 2012, $2.6 million ($0.6 million for CL&P and $0.7 million for PSNH) had been accrued as a liability for these sites, which represent management's best estimates of the liabilities for environmental costs. These amounts are the best estimates with estimated ranges of additional losses from zero million to $15.2 million (zero to $1.3 million for CL&P, zero to $4.1 million for PSNH, and zero to $8.6 million for WMECO).
As of December 31, 2012, for 23 environmental sites (5 for CL&P,1 for NSTAR Electric, 4 for PSNH, and 3 for WMECO) included in the Company’s reserve for environmental costs, management cannot reasonably estimate the exposure to loss in excess of the reserve, or range of loss, as these sites are under investigation and/or there is significant uncertainty as to what remedial actions, if any, the Company may be required to undertake. As of December 31, 2012, $17 million ($1.7 million for CL&P, $0.2 million for PSNH, and $0.5 million for WMECO) had been accrued as a liability for these sites. As of December 31, 2012, for the remaining 46 environmental sites (11 for CL&P, 15 for NSTAR Electric, 10 for PSNH, and 2 for WMECO) included in the Company’s reserve for environmental costs, the $19.8 million accrual ($1.4 million for CL&P, $1.7 million for NSTAR Electric, $4 million for PSNH, and $0.1 million for WMECO) represents management’s best estimate of the liability and no additional loss is anticipated.
HWP: HWP, a subsidiary of NU, continues to investigate the potential need for additional remediation at a river site in Massachusetts containing tar deposits associated with an MGP site that HWP sold to HG&E, a municipal utility, dating back to 1902. HWP shares
responsibility for site remediation with HG&E and has conducted substantial investigative and remediation activities. The cumulative expense recorded to the reserve for this site since 1994 through December 31, 2012 was $19.5 million, of which $17.4 million had been spent, leaving $2.1 million in the reserve as of December 31, 2012. For the years ended December 31, 2012 and 2011, there were no charges recorded to the reserve and for the year ended December 31, 2010, a pre-tax charge of $2.6 million was recorded to reflect estimated costs associated with the site. HWP's share of the costs related to this site is not recoverable from customers.
In 2008, the MA DEP issued a letter to HWP and HG&E, representing guidance rather than a mandate, providing conditional authorization for additional investigatory and risk characterization activities and indicating that further removal of tar in certain areas was needed. HWP implemented several supplemental studies to further delineate and assess tar deposits in conformity with the MA DEP's guidance letter. In December 2012, the MADEP advised that all work to date with this site continues to meet regulatory expectations.
In 2010, HWP delivered a report to the MA DEP describing the results of its site investigation studies and testing. Subsequent communications and discussions with the MA DEP have focused on the course of action to achieve resolution of these matters, and are ongoing.
The $2.1 million reserve balance as of December 31, 2012 represents estimated costs that HWP considers probable over the remaining life of the project, including testing and related costs in the near term and field activities to be agreed upon with the MA DEP, further studies and long-term monitoring that are expected to be required by the MA DEP, and certain soft tar remediation activities. Various factors could affect management's estimates and require an increase to the reserve, which would be reflected as a charge to Net Income. Although a material increase to the reserve is not presently anticipated, management cannot reasonably estimate potential additional investigation or remediation costs because these costs would depend on, among other things, the nature, extent and timing of additional investigation and remediation that may be required by the MA DEP.
CERCLA: The federal Comprehensive Environmental Response, Compensation and Liability Act of 1980 (CERCLA) and its amendments or state equivalents impose joint and several strict liabilities, regardless of fault, upon generators of hazardous substances resulting in removal and remediation costs and environmental damages. Liabilities under these laws can be material and in some instances may be imposed without regard to fault or for past acts that may have been lawful at the time they occurred. Of the total sites included in the remediation and long-term monitoring phase, 10 sites (2 for CL&P, 4 for NSTAR Electric, 4 for PSNH and 1 for WMECO) are superfund sites under CERCLA for which the Company has been notified that it is a potentially responsible party but for which the site assessment and remediation are not being managed by the Company. As of December 31, 2012, a liability of $1 million ($0.4 million for CL&P, $0.1 million for NSTAR Electric and $0.4 million for PSNH) accrued on these sites represents management's best estimate of its potential remediation costs with respect to these superfund sites.
Environmental Rate Recovery: PSNH, NSTAR Gas and Yankee Gas have rate recovery mechanisms for environmental costs. CL&P recovers a certain level of environmental costs currently in rates but does not have an environmental cost recovery tracking mechanism. Accordingly, changes in CL&P's environmental reserves impact CL&P's Net Income. WMECO does not have a separate regulatory mechanism to recover environmental costs from its customers, and changes in WMECO's environmental reserves impact WMECO's Net Income.
Supply and Stranded Cost: CL&P, NSTAR Electric, PSNH and WMECO have various IPP contracts or purchase obligations for electricity, including payment obligations resulting from the buydown of electricity purchase contracts. Such contracts extend through 2024 for CL&P, 2030 for NSTAR Electric and 2023 for PSNH.
In addition, CL&P and UI have entered into four CfDs for a total of approximately 787 MW of capacity consisting of three generation projects 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 share 20 percent 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. The amounts of these payments are subject to changes in capacity and forward reserve prices that the projects receive in the ISO-NE capacity markets.
The contractual obligations table does not include CL&P's SS or LRS, or NSTAR Electric’s or WMECO’s default service contracts, the amounts of which vary with customers' energy needs. The contractual obligations table also does not include PSNH's short-term power supply management.
Renewable Energy: Renewable energy contracts include non-cancellable commitments under contracts of CL&P, NSTAR Electric, PSNH, and WMECO for the purchase of energy and capacity from renewable energy facilities. Such contracts have terms extending for 15 years at CL&P, up to 40 years at NSTAR Electric, up to 30 years for PSNH and 15 years for WMECO.
The table above does not include NSTAR Electric’s commitment to purchase 129MW of renewable energy from a wind facility to be
constructed offshore and certain other CL&P and NSTAR Electric commitments for the purchase of renewable energy and related products that are contingent on the future construction of facilities.
Peaker CfDs: In 2008, CL&P entered into three CfDs with developers of peaking generation units approved by the PURA (Peaker CfDs). These units have a total of approximately 500 MW of peaking capacity. As directed by the PURA, CL&P and UI have entered into a sharing agreement, whereby CL&P is responsible for 80 percent and UI for 20 percent of the net costs or benefits of these CfDs. The Peaker CfDs pay the developer the difference between capacity, forward reserve and energy market revenues and a cost-of-service payment stream for 30 years. The ultimate cost or benefit to CL&P under these contracts will depend on the costs of plant construction and operation and the prices that the projects receive for capacity and other products in the ISO-NE markets. CL&P's portion of the amounts paid or received under the Peaker CfDs will be recoverable from or refunded to CL&P's customers.
Natural Gas Procurement: NU’s natural gas distribution businesses have long-term contracts for the purchase, transportation and storage of natural gas in the normal course of business as part of its portfolio of supplies. These contracts extend through 2029.
Coal, Wood and Other: PSNH has entered into various arrangements for the purchase of wood, coal and the transportation services for fuel supply for its electric generating assets. Also included in the table above is a contract for capacity on the Portland Natural Gas Transmission System (PNGTS) pipeline that extends through 2019. The costs on this contract are not recoverable from customers.
Transmission Support Commitments: Along with other New England utilities, CL&P, NSTAR Electric, PSNH and WMECO entered into agreements in 1985 to support transmission and terminal facilities that were built to import electricity from the Hydro-Québec system in Canada. CL&P, NSTAR Electric, PSNH and WMECO are obligated to pay, over a 30-year period ending in 2020, their proportionate shares of the annual operation and maintenance expenses and capital costs of those facilities.
The total costs incurred under these agreements in 2012, 2011, and 2010 were as follows:
(1)
NSTAR Electric amounts are included in NU consolidated from the date of the merger, April 10, 2012 through December 31, 2012. NSTAR Electric amounts are not included in NU consolidated for the years ended December 31, 2011 and 2010.
C.
Deferred Contractual Obligations
CL&P, NSTAR Electric, PSNH and WMECO have decommissioning and plant closure cost obligations to the Yankee Companies, which have each completed the physical decommissioning of their respective nuclear facilities and are now engaged in the long-term storage of their spent fuel. The Yankee Companies collect decommissioning and closure costs through wholesale, FERC-approved rates charged under power purchase agreements with several New England utilities, including CL&P, NSTAR Electric, PSNH and WMECO. These companies in turn recover these costs from their customers through state regulatory commission-approved retail rates.
CL&P, NSTAR Electric, PSNH and WMECO's percentage share of the obligations to support the Yankee Companies under FERC-approved rate tariffs is the same as their respective ownership percentages in the Yankee Companies. For further information on the ownership percentages, see Note 1J, "Summary of Significant Accounting Policies - Equity Method Investments," to the consolidated financial statements.
The Yankee Companies are currently collecting amounts that management believes are adequate to recover the remaining decommissioning and closure cost estimates for the respective plants. Management believes CL&P, NSTAR Electric and WMECO will recover their shares of these decommissioning and closure obligations from their customers. PSNH has already recovered its share of these costs from its customers.
Spent Nuclear Fuel Litigation:
DOE Phase I Damages - In 1998, CYAPC, YAEC and MYAPC (Yankee Companies) filed separate complaints against the DOE in the Court of Federal Claims seeking monetary damages resulting from the DOE's failure to begin accepting spent nuclear fuel for disposal by January 31, 1998 pursuant to the terms of the 1983 spent fuel and high level waste disposal contracts between the Yankee Companies and the DOE (DOE Phase I Damages). 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.
In December 2006, the DOE appealed the ruling, and the Yankee Companies filed cross-appeals. The Court of Appeals issued its decision on August 7, 2008, effectively agreeing with the trial court's findings as to the liability of the DOE but disagreeing with the method that the trial court used to calculate damages. The Court of Appeals vacated the decision and remanded the case for new findings consistent with its decision.
On September 7, 2010, the trial court issued its decision following remand, and judgment on the decision was entered on September 9, 2010. The judgment awarded CYAPC $39.7 million, YAEC $21.2 million and MYAPC $81.7 million. The DOE filed an appeal and the Yankee Companies cross-appealed on November 8, 2010. Briefs were filed and oral arguments in the appeal of the remanded case occurred on November 7, 2011. On May 18, 2012, the U.S. Court of Appeals for the Federal Circuit issued a unanimous panel decision in favor of the Yankee Companies upholding the trial court's awards to each company in the remanded cases, and increasing YAEC damages by approximately $17 million to cover certain wet pool operating expenses. On August 1, 2012, the DOE filed a petition asking the U.S. Court of Appeals for the Federal Circuit to reconsider its unanimous panel decision in favor of the Yankee Companies upholding the trial court's awards to each company in the remanded cases. On September 5, 2012, the U.S. Court of Appeals for the Federal Circuit denied the DOE’s petition. The decisions became final and non-appealable and interest on the judgments began to accrue on or about December 5, 2012, as the DOE elected not to file a petition for certiorari with the U.S. Supreme Court.
As a result of the April 10, 2012 merger with NSTAR and NU's consolidation of CYAPC and YAEC, the consolidated financial statements reflect an aggregate receivable from the DOE for CYAPC and YAEC's Phase I damages awards of $77.9 million as of December 31, 2012.
In January 2013, the proceeds from the DOE Phase I Damages Claim were received by CYAPC in the amount of $39.6 million, YAEC in the amount of $38.3 million, and MYAPC in the amount of $81.7 million. The funds were transferred to each Yankee Company’s respective decommissioning trust. The final application of the proceeds for the benefit of customers of CL&P, NSTAR Electric, PSNH and WMECO will be determined following rate proceedings to be filed by each Yankee Company at FERC in the second quarter of 2013. Final FERC determinations are expected by the end of the third quarter of 2013.
DOE Phase II Damages - In December 2007, the Yankee Companies each filed subsequent lawsuits against the DOE seeking recovery of actual damages incurred in the years following 2001 and 2002 related to the alleged failure of the DOE to provide for a permanent facility to store spent nuclear fuel generated in years after 2001 for CYAPC and YAEC and after 2002 for MYAPC (DOE Phase II Damages). On November 18, 2011, the court ordered the record closed in the YAEC case, and closed the record in the CYAPC and MYAPC cases subject to a limited opportunity of the government to reopen the records for further limited proceedings. The record is now closed, all post-trial briefing has been completed, and the case is awaiting the court decision.
The methodology for applying any DOE Phase II Damages that may be recovered from the DOE for the benefit of customers of CL&P, NSTAR Electric, PSNH and WMECO will be addressed in the same FERC rate proceedings.
D.
Guarantees and Indemnifications
NU parent, or NSTAR LLC, as applicable, provides credit assurances on behalf of its subsidiaries, including CL&P, NSTAR Electric, PSNH and WMECO, in the form of guarantees in the normal course of business.
NU provided guarantees and various indemnifications on behalf of external parties as a result of the sales of former subsidiaries of NU Enterprises, with maximum exposures either not specified or not material.
NU also issued a guaranty for the benefit of Hydro Renewable Energy under which, beginning at the time the Northern Pass Transmission line goes into commercial operation, NU will guarantee the financial obligations of NPT under the TSA in an amount not to exceed $25 million. NU's obligations under the guaranty expire upon the full, final and indefeasible payment of the guaranteed obligations.
Management does not anticipate a material impact to Net Income as a result of these various guarantees and indemnifications.
The following table summarizes NU's guarantees of its subsidiaries, including CL&P, NSTAR Electric, PSNH and WMECO, as of December 31, 2012:
(1)
Surety bond expiration dates reflect bond termination dates, the majority of which will be renewed or extended.
(2)
The maximum exposure includes $13.5 million related to performance guarantees on wholesale purchase contracts, which expire December 31, 2013. Also included in the maximum exposure is $1 million related to insurance bonds with no expiration date that are billed annually on their anniversary date. The remaining $52.9 million of maximum exposure relates to surety bonds covering ongoing projects, which expire upon project completion.
Many of the underlying contracts that NU parent guarantees, as well as certain surety bonds, contain credit ratings triggers that would require NU parent to post collateral in the event that the unsecured debt credit ratings of NU, or NSTAR LLC, as applicable, are downgraded below investment grade.
E.
DPU Penalties for 2011 Storm Responses (NSTAR Electric, WMECO)
On December 11, 2012, in separate orders issued by the DPU, NSTAR Electric and WMECO received penalties related to the investigation into the electric utilities’ responses to Tropical Storm Irene and the October 2011 snowstorm. The DPU ordered penalties of $4.1 million and $2 million for NSTAR Electric and WMECO, respectively, stating that NSTAR Electric failed to communicate and prioritize restoration efforts in both storms and WMECO failed to prioritize restoration efforts in the October snowstorm. These penalties were ordered to be assessed in the form of customer credits in 2013. On December 28, 2012, NSTAR Electric and WMECO each filed appeals with the SJC arguing the DPU penalties should be vacated. In their filings, NSTAR Electric and WMECO stated that the DPU’s decision to assess the penalties was in error as the assessments were arbitrary and not supported by substantial evidence. While we believe that NSTAR Electric and WMECO should ultimately prevail upon appeal, we are unable to conclusively state that a favorable outcome is probable. Therefore, NSTAR Electric and WMECO recorded $4.1 million and $2 million, respectively, in pre-tax penalty charges as of December 31, 2012.
F.
FERC Base ROE Complaint
On September 30, 2011, several New England state attorneys general, state regulatory commissions, consumer advocates and other parties filed a joint complaint with the FERC under Sections 206 and 306 of the Federal Power Act alleging that the base ROE used in calculating formula rates for transmission service under the ISO-NE Open Access Transmission Tariff by New England transmission owners, including CL&P, NSTAR Electric, PSNH and WMECO, is unjust and unreasonable. The complainants asserted that the current 11.14 percent rate, which became effective in 2006, is excessive due to changes in the capital markets and are seeking an order to reduce the rate, which would be effective September 30, 2011 through December 31, 2012. In response, the New England transmission owners filed testimony and analysis based on standard FERC methodology and precedent, demonstrating that the base ROE of 11.14 percent remained just and reasonable.
On May 3, 2012, the FERC issued an order establishing hearing and settlement procedures for the complaint. The settlement proceedings were subsequently terminated, as the parties had reached an impasse in their efforts to reach a settlement. In August 2012, the FERC trial judge assigned to the complaint established a schedule for the trial phase of the proceedings. Complainant testimony supporting a base ROE of 9 percent was filed on October 1, 2012. Additional testimony was filed on October 1, 2012 by a group of Massachusetts municipal electric companies, which recommended a base ROE of 8.2 percent. The New England transmission owners filed testimony and analysis on November 20, 2012, demonstrating they believe that the current base ROE continues to be just and reasonable. On January 18, 2013, the FERC trial staff filed testimony and analysis recommending a base ROE of 9.66 percent based on the midpoint of their analysis with a range of reasonableness of 6.82 percent to 12.51 percent. Hearings on this complaint are scheduled for May 2013 and a trial judge’s recommended decision is due in September 2013. A decision from FERC commissioners is expected in 2014. Refunds to customers, if any, as a result of a reduction in the NU transmission companies’ base ROE would be retroactive to October 1, 2011.
On December 27, 2012, several additional parties filed a separate complaint concerning the New England transmission owners' ROE with the FERC. This new complaint seeks to reduce the New England transmission owner’s base transmission ROE effective January 1, 2013, and to consolidate this new complaint with the joint complaint filed on September 30, 2011. The New England transmission owners have asked the FERC to reject this new complaint. The FERC has not yet acted on this request.
Management cannot at this time predict the ultimate outcome of this proceeding or the estimated impacts on CL&P’s, NSTAR Electric’s, PSNH’s, or WMECO’s respective financial position, results of operations or cash flows.
G.
DPU Safety and Reliability Programs - CPSL (NSTAR Electric)
Since 2006, NSTAR Electric has been recovering incremental costs related to the Double Pole Inspection, Replacement/Restoration and Transfer Program and the Underground Electric Safety Program, which included stray-voltage remediation, manhole inspections, repairs, and upgrades, in accordance with this DPU approved program. Recovery of these CPSL costs is subject to review and approval by the DPU through a rate-reconciling mechanism. From 2006 through December 31, 2011, cumulative costs associated with the CPSL program resulted in an incremental revenue requirement to customers of approximately $83 million. These amounts included incremental operations and maintenance costs and the related revenue requirement for specific capital investments relative to the CPSL programs.
On May 28, 2010, the DPU issued an order on NSTAR Electric’s 2006 CPSL cost recovery filing (the May 2010 Order). The May 2010 Order was the basis NSTAR Electric used for recognizing revenue for the CPSL programs. On October 8, 2010, NSTAR Electric submitted a Compliance Filing with the DPU reconciling the cumulative CPSL program activity for the periods 2006 through 2009 in order to determine a proposed rate adjustment effective on January 1, 2011. The DPU allowed the proposed rates for the CPSL programs to go into effect on that date, subject to final reconciliation of CPSL program costs through a future DPU proceeding. NSTAR Electric updated the October 2010 filing with final activity through 2011 in February 2013.
NSTAR Electric cannot predict the timing of any subsequent DPU order related to its CPSL filings for the period 2006 through 2011. Therefore, NSTAR Electric continued to record its 2006 through 2011 revenues under the CPSL programs based on the May 2010 Order. While we do not believe that any subsequent DPU order would result in revenue recognition that is materially different than the amounts already recognized, it is reasonably possible that an order could have a material impact on NSTAR Electric’s results of operations, financial position and cash flows.
The April 4, 2012 DPU-approved comprehensive settlement agreement with the Massachusetts Attorney General concerning the merger stipulates that NSTAR Electric must incur a revenue requirement of at least $15 million per year for 2012 through 2015 in order to continue these programs. CPSL revenues will end once NSTAR Electric has recovered its 2015-related CPSL costs. Realization of these revenues is subject to maintaining certain performance metrics over the four-year period and DPU approval. As of December 31, 2012, NSTAR Electric was in compliance with the performance metrics and has recognized the entire $15 million revenue requirement during 2012, which we believe is probable of approval from the DPU.
H.
Basic Service Bad Debt Adder (NSTAR Electric)
In accordance with a generic DPU order, electric utilities in Massachusetts recover the energy-related portion of bad debt costs in their Basic Service rates. On February 7, 2007, NSTAR Electric filed its 2006 Basic Service reconciliation with the DPU proposing an adjustment related to the increase of its Basic Service bad debt charge-offs. On June 28, 2007, the DPU issued an order approving the implementation of a revised Basic Service rate. However, the DPU instructed NSTAR Electric to reduce distribution rates by an amount equal to the increase in its Basic Service bad debt charge-offs. This adjustment to NSTAR Electric’s distribution rates would eliminate the fully reconciling nature of the Basic Service bad debt adder.
NSTAR Electric deferred the unrecovered costs associated with energy-related bad debt as a regulatory asset, which totaled approximately $34 million as of December 31, 2011, as NSTAR Electric had concluded that these costs were probable of recovery in future rates. On June 18, 2010, NSTAR Electric filed an appeal of the DPU’s order with the SJC, which was heard by the SJC in December 2011. On April 11, 2012, the SJC issued a procedural order waiving its standing 130-day rule for issuance of an order on the matter. Due to the delay, NSTAR Electric concluded that while an ultimate outcome on the matter in its favor remained "more likely than not," it could no longer be deemed "probable." As a result, NSTAR Electric recognized a reserve of $28 million ($17 million after-tax) as a charge to Operations and Maintenance in the first quarter of 2012 to reserve the related regulatory asset on its balance sheet.
On June 4, 2012, the SJC vacated the DPU's June 28, 2007 order and remanded the matter to the DPU for a "statement of reasons, including subsidiary findings, of its conclusion of law and relevant facts." The continued uncertainty of the outcome of the DPU’s proceeding leaves NU and NSTAR Electric unable to conclude that it is probable that the previously reserved amount will ultimately be recovered and therefore NSTAR Electric will continue to maintain a reserve on this amount until the ultimate outcome is determined by the DPU.
I.
Litigation and Legal Proceedings
NU, including CL&P, NSTAR Electric, PSNH and WMECO, are involved in legal, tax and regulatory proceedings regarding matters arising in the ordinary course of business, which involve management's assessment to determine the probability of whether a loss will occur and, if probable, its best estimate of probable loss. The Company records and discloses losses when these losses are probable and reasonably estimable, discloses matters when losses are probable but not estimable or reasonably possible, and expenses legal costs related to the defense of loss contingencies as incurred.
13.
LEASES
NU, including CL&P, NSTAR Electric, PSNH and WMECO, has entered into lease agreements, some of which are capital leases, for the use of data processing and office equipment, vehicles and office space. In addition, CL&P, PSNH and WMECO incur costs associated with leases entered into by NUSCO and RRR, which are included below in their respective operating lease rental expenses and future minimum rental payments. These intercompany lease amounts are eliminated on an NU consolidated basis. The provisions of the NU, CL&P, NSTAR Electric, PSNH, and WMECO lease agreements generally contain renewal options. Certain lease agreements contain payments impacted by the commercial paper rate plus a credit spread or the consumer price index.
Operating lease rental payments charged to expense were as follows:
(1)
NSTAR Electric amounts are included in NU consolidated from the date of the merger, April 10, 2012, through December 31, 2012. NSTAR Electric amounts are not included in NU consolidated for the years ended December 31, 2011 and 2010.
Future minimum rental payments to external third parties excluding executory costs, such as property taxes, state use taxes, insurance, and maintenance, under long-term noncancelable leases, as of December 31, 2012 are as follows:
CL&P entered into certain contracts for the purchase of energy that qualify as leases. These contracts do not have minimum lease payments and therefore are not included in the tables above. However, such contracts have been included in the contractual obligations table in Note 12B, "Commitments and Contingencies - Long-Term Contractual Arrangements," to the consolidated financial statements.
14.
FAIR VALUE OF FINANCIAL INSTRUMENTS
The following methods and assumptions were used to estimate the fair value of each of the following financial instruments:
Preferred Stock, Long-Term Debt and Rate Reduction Bonds: The fair value of CL&P's and NSTAR Electric’s preferred stock is based upon pricing models that incorporate interest rates and other market factors, valuations or trades of similar securities and cash flow projections. The fair value of fixed-rate long-term debt securities and RRBs is based upon pricing models that incorporate quoted market prices for those issues or similar issues adjusted for market conditions, credit ratings of the respective companies and treasury benchmark yields. Adjustable rate securities are assumed to have a fair value equal to their carrying value. The fair values provided in the tables below are classified as Level 2 within the fair value hierarchy. Carrying amounts and estimated fair values are as follows:
(1)
NSTAR Electric amounts are not included in NU consolidated as of December 31, 2011.
Derivative Instruments: NU, including CL&P, NSTAR Electric and WMECO, holds various derivative instruments that are carried at fair value. For further information, see Note 5, "Derivative Instruments," to the consolidated financial statements.
Other Financial Instruments: Investments in marketable securities are carried at fair value on the accompanying consolidated balance sheets. For further information, see Note 1H, "Summary of Significant Accounting Policies - Fair Value Measurements," and Note 6, "Marketable Securities," to the consolidated financial statements.
The carrying value of other financial instruments included in current assets and current liabilities, including cash and cash equivalents and special deposits, approximates their fair value due to the short-term nature of these instruments.
15.
ACCUMULATED OTHER COMPREHENSIVE INCOME/(LOSS)
The accumulated balance for each component of other comprehensive income/(loss), net of tax, is as follows:
Qualified cash flow hedging items impacting Net Income in the tables above represent amounts that were reclassified from Accumulated Other Comprehensive Income/(Loss) into Net Income for interest rate swap agreements. For the year ended December 31, 2012, qualified cash flow hedging activity relates to the amortization of previously settled interest rate swap agreements. For the year ended December 31, 2011, activity related to qualified cash flow hedging activity was as follows:
It is estimated that a charge of $2 million will be reclassified from Accumulated Other Comprehensive Income/(Loss) as a decrease to earnings over the next 12 months as a result of amortization of the interest rate swap agreements, which have been settled. Included in this amount are estimated charges of $0.4 million, $1.2 million and $0.3 million for CL&P, PSNH and WMECO, respectively. As of December 31, 2012, it is estimated that a pre-tax amount of $10.5 million included in the Accumulated Other Comprehensive Income/(Loss) balance will be reclassified as a decrease to Net Income over the next 12 months related to Pension, SERP and PBOP adjustments for NU.
16.
DIVIDEND RESTRICTIONS
NU parent's ability to pay dividends may be affected by certain state statutes, the ability of its subsidiaries to pay common dividends and the leverage restriction tied to its consolidated total debt to total capitalization ratio requirement in its revolving credit agreement.
CL&P, NSTAR Electric, PSNH and WMECO are subject to Section 305 of the Federal Power Act that makes it unlawful for a public utility to make or pay a dividend from any funds "properly included in its capital account." Management believes that this Federal Power Act restriction, as applied to CL&P, NSTAR Electric, PSNH and WMECO, would not be construed or applied by the FERC to prohibit the payment of dividends for lawful and legitimate business purposes from retained earnings. In addition, certain state statutes may impose additional limitations on such companies and on Yankee Gas and NSTAR Gas. Such state law restrictions do not restrict payment of dividends from retained earnings or net income. CL&P, NSTAR Electric, PSNH, WMECO, Yankee Gas and NSTAR Gas also have revolving credit agreements that impose leverage restrictions including consolidated total debt to total capitalization ratio requirements. The Retained Earnings balances subject to these leverage restrictions are $1.803 billion for NU, $839.6 million for CL&P, $1.210 billion for NSTAR Electric, $395.1 million for PSNH and $160.6 million for WMECO as of December 31, 2012. PSNH is further required to reserve an additional amount under its FERC hydroelectric license conditions. As of December 31, 2012, approximately $12.3 million of PSNH's Retained Earnings is subject to restriction under its FERC hydroelectric license conditions. As of December 31, 2012, NU, CL&P, NSTAR Electric, PSNH, WMECO, Yankee Gas and NSTAR Gas were in compliance with all such provisions of its credit agreements that may restrict the payment of dividends.
17.
COMMON SHARES
The following table sets forth the NU common shares and the shares of CL&P, NSTAR Electric, PSNH and WMECO common stock authorized and issued as of December 31, 2012 and 2011 and the respective par values:
As a result of the merger with NSTAR on April 10, 2012, NU issued approximately 136 million common shares to the NSTAR shareholders.
As of December 31, 2012 and 2011, 18,455,749 and 18,894,078 NU common shares were held as treasury shares, respectively.
18.
PREFERRED STOCK NOT SUBJECT TO MANDATORY REDEMPTION (CL&P, NSTAR Electric)
The preferred stock of CL&P and NSTAR Electric is not subject to mandatory redemption and is presented as a noncontrolling interest of a subsidiary in the accompanying consolidated financial statements of NU.
CL&P Preferred Stock: CL&P's charter authorizes it to issue up to 9 million shares of preferred stock ($50 par value per share). CL&P amended its charter on January 3, 2012 to remove references to various series of preferred stock, including the Class A preferred stock, which are no longer outstanding. The issuance of additional preferred shares would be subject to approval by the PURA. Preferred stockholders have liquidation rights equal to the par value of the preferred stock, which they would receive in preference to any distributions to any junior stock. Were there to be a shortfall, all preferred stockholders would share ratably in available liquidation assets.
NSTAR Electric Preferred Stock: NSTAR Electric is authorized to issue 2,890,000 shares ($100 par value per share). NSTAR Electric has two outstanding series of cumulative preferred stock. Upon liquidation, holders of cumulative preferred stock are entitled to receive a liquidation preference before any distribution to holders of common stock. The liquidation preference for each outstanding series of cumulative preferred stock is equal to the par value, plus accrued and unpaid dividends. Were there to be a shortfall, holders of cumulative preferred stock would share ratably in available liquidation assets.
Details of preferred stock not subject to mandatory redemption are as follows (in millions except in redemption price and shares):
(1)
NSTAR Electric amounts are not included in NU consolidated as of December 31, 2011.
(1)
On April 10, 2012, in connection with the consummation of the merger with NSTAR, NU issued approximately 136 million common shares to the NSTAR shareholders. See Note 2, "Merger of NU and NSTAR," for further information.
(2)
The preferred stock of NSTAR Electric is not subject to mandatory redemption and has been presented as a noncontrolling interest in NSTAR Electric in the accompanying consolidated financial statements of NU. In addition, upon completion of the merger, an NSTAR subsidiary that held 25 percent of NPT was merged into NUTV, resulting in NUTV owning 100 percent of NPT. Accordingly, the noncontrolling interest balance was eliminated and 100 percent ownership of NPT is reflected in Common Shareholders' Equity as of December 31, 2012.
For the years ended December 31, 2012, 2011 and 2010, there was no change in ownership of the common equity of CL&P and NSTAR Electric.
20.
EARNINGS PER SHARE (NU)
Basic EPS is computed based upon the weighted average number of common shares outstanding during each period. Diluted EPS is computed on the basis of the weighted average number of common shares outstanding plus the potential dilutive effect if certain securities are converted into common shares. For the years ended December 31, 2012, 2011 and 2010, there were 4,266, 4,314 and 1,578 share awards, respectively, excluded from the computation as these awards were antidilutive.
The following table sets forth the components of basic and diluted EPS:
On April 10, 2012, NU issued approximately 136 million common shares as a result of the merger with NSTAR, which are reflected in weighted average common shares outstanding as of December 31, 2012.
RSUs and performance shares are included in basic weighted average common shares outstanding as of the date that all necessary vesting conditions have been satisfied. The dilutive effect of unvested RSUs and performance shares is calculated using the treasury stock method. Assumed proceeds of these units under the treasury stock method consist of the remaining compensation cost to be recognized and a theoretical tax benefit. The theoretical tax benefit is calculated as the tax impact of the intrinsic value of the units (the difference between the market value of the average units outstanding for the period, using the average market price during the period, and the grant date market value).
The dilutive effect of stock options to purchase common shares is also calculated using the treasury stock method. Assumed proceeds for stock options consist of cash proceeds that would be received upon exercise, and a theoretical tax benefit. The theoretical tax benefit is calculated as the tax impact of the intrinsic value of the stock options (the difference between the market value of the average stock options outstanding for the period, using the average market price during the period, and the exercise price).
21.
SEGMENT INFORMATION (NU)
Presentation: NU is organized between the Electric Distribution, Electric Transmission and Natural Gas Distribution segments and Other based on a combination of factors, including the characteristics of each segments' products and services, the sources of operating revenues and expenses and the regulatory environment in which each segment operates. These segments represented substantially all of NU's total consolidated revenues for the years ended December 31, 2012, 2011 and 2010. Revenues from the sale of electricity and natural gas primarily are derived from residential, commercial and industrial customers and are not dependent on any single customer. The Electric Distribution segment includes the generation activities of PSNH and WMECO.
Other operations in the tables below primarily consists of 1) the equity in earnings of NU parent from its subsidiaries and intercompany interest income, both of which are eliminated in consolidation, and interest income and expense related to the cash and debt of NU parent and NSTAR LLC, respectively, 2) the revenues and expenses of NU's service companies, most of which are eliminated in consolidation, 3) the operations of CYAPC and YAEC, and 4) the results of other subsidiaries, which are comprised of NU Enterprises, NSTAR Communications, Inc., RRR (a real estate subsidiary), the non-energy-related subsidiaries of Yankee and the remaining operations of HWP.
Cash flows used for investments in plant included in the segment information below are cash capital expenditures that do not include amounts incurred but not paid, cost of removal, AFUDC related to equity funds, and the capitalized portions of pension and PBOP expense or income.
As discussed in Note 1B, "Summary of Significant Accounting Policies - Basis of Presentation," certain reclassifications of prior year data were made in the accompanying consolidated statements of income for NU. Accordingly, the corresponding items of segment information have been recast for all prior years for comparative purposes.
Effective in the third quarter of 2012, NU’s reportable segments are the combined Electric Distribution, Electric Transmission and Natural Gas Distribution segments, based upon the level at which NU’s chief operating decision maker assesses performance and makes decisions about the allocation of company resources. Each of NU’s subsidiaries, including CL&P, NSTAR Electric, PSNH and WMECO, has one reportable segment. Therefore, separate Transmission and Distribution information is not disclosed for CL&P, NSTAR Electric, PSNH or WMECO. NU’s operating segments and reporting units are consistent with its reportable business segments.
NSTAR amounts are included in NU consolidated from the date of the merger, April 10, 2012, through December 31, 2012.
NU's segment information for the years ended December 31, 2012, 2011 and 2010 is as follows:
22.
VARIABLE INTEREST ENTITIES
The Company's variable interests outside of the consolidated group are not material and consist of contracts that are required by regulation and provide for regulatory recovery of contract costs and benefits through customer rates. NU, CL&P and NSTAR Electric hold variable interests in variable interest entities (VIEs) through agreements with certain entities that own single renewable energy or peaking generation power plants and with other independent power producers. NU, CL&P and NSTAR Electric do not control the activities that are economically significant to these VIEs or provide financial or other support to these VIEs. Therefore, NU, CL&P and NSTAR Electric do not consolidate any power plant VIEs.
23.
SUBSEQUENT EVENTS (NU, CL&P, NSTAR Electric)
See Note 9, "Long-Term Debt" to the consolidated financial statements for information regarding the January 2013 long-term debt issuance for CL&P.
See Note 12C, "Commitments and Contingencies - Deferred Contractual Obligations" to the consolidated financial statements for information regarding the receipt of the DOE proceeds by the Yankee Companies in January 2013.
See Note 11, "Income Taxes," for discussion of the federal legislation enacted on January 2, 2013.
On February 8, 2013, a blizzard caused damage to the electric delivery systems of CL&P and NSTAR Electric. Management believes that this storm will cost between $100 million to $120 million, with approximately 90 percent of those costs relating to NSTAR Electric. Management expects the costs to meet the criteria for specific cost recovery in Connecticut and Massachusetts and, as a result, does not expect the storm to have a material impact on the results of operations of CL&P or NSTAR Electric. Each operating company will seek recovery of these anticipated deferred storm costs through its applicable regulatory recovery process.
24.
QUARTERLY FINANCIAL DATA (UNAUDITED)
(1)
NSTAR Electric amounts are included in NU consolidated from the date of the merger, April 10, 2012, through December 31, 2012. NSTAR Electric amounts are not included in NU consolidated for the years ended December 31, 2011 and 2010.
(2)
NSTAR Electric's Net Income for the quarter ended December 31, 2012 decreased by $8.2 million, as compared to the quarter ended December 31, 2011, related to a pre-tax charge to establish a reserve of $13.7 million to reflect a billing adjustment, all of which related to prior year amounts.
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, NSTAR Electric, PSNH or WMECO.
Item 9A.
Item 9A.
Controls and Procedures
Management, on behalf of NU, CL&P, NSTAR Electric, PSNH and WMECO, is responsible for the preparation, integrity, and fair presentation of the accompanying Consolidated Financial Statements and other sections of this combined Annual Report on Form 10-K. NU, CL&P, NSTAR Electric, PSNH and WMECO’s internal controls over financial reporting were audited by Deloitte & Touche LLP.
Management, on behalf of NU, CL&P, NSTAR Electric, PSNH and WMECO, is responsible for establishing and maintaining adequate internal controls over financial reporting. The 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 GAAP. There are inherent limitations of internal controls over financial reporting that could allow material misstatements due to error or fraud to occur and not be prevented or detected on a timely basis by employees during the normal course of business. Additionally, internal controls over financial reporting may become inadequate in the future due to changes in the business environment. Under the supervision and with the participation of the principal executive officers and principal financial officer, an evaluation of the effectiveness of internal controls over financial reporting was conducted 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 internal controls over financial reporting at NU, CL&P, NSTAR Electric, PSNH and WMECO were effective as of December 31, 2012.
Management, on behalf of NU, CL&P, NSTAR Electric, PSNH and WMECO, evaluated the design and operation of the disclosure controls and procedures as of December 31, 2012 to determine whether they are effective in ensuring that the disclosure of required information is made timely and in accordance with the Securities Exchange Act of 1934 and the rules and regulations of the SEC. This evaluation was made under management's supervision and with management's participation, including the principal executive officers and principal financial officer as of the end of the period covered by this Annual Report on Form 10-K. There are inherent limitations of disclosure controls and procedures, including the possibility of human error and the circumventing or overriding of the controls and procedures. Accordingly, even effective disclosure controls and procedures can only provide reasonable assurance of achieving their control objectives. The principal executive officers and principal financial officer have concluded, based on their review, that the disclosure controls and procedures of NU, CL&P, NSTAR Electric, PSNH and WMECO are effective to ensure that information required to be disclosed by us in reports filed under the Securities Exchange Act of 1934 (i) is recorded, processed, summarized, and reported within the time periods specified in SEC rules and regulations 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 disclosures.
There have been no changes in internal controls over financial reporting for NU, CL&P, NSTAR Electric, PSNH and WMECO during the quarter ended December 31, 2012 that have materially affected, or are reasonably likely to materially affect, internal controls over financial reporting.
On April 10, 2012, NSTAR became a direct wholly owned subsidiary of NU. NU is currently in the process of integrating NSTAR’s operations, and will be conducting control reviews pursuant to Section 404 of the Sarbanes-Oxley Act of 2002. See Note 2, "Merger of NU and NSTAR," to the Combined Notes to the Consolidated Financial Statements in this Annual Report on Form 10-K for additional information regarding the merger.
Item 9B.
Item 9B.
Other Information
No information is required to be disclosed under this item as of December 31, 2012, as this information has been previously disclosed in applicable reports on Form 8-K during the fourth quarter of 2012.
PART III
Item 10.
Item 10.
Directors, Executive Officers and Corporate Governance
The information in Item 10 is provided as of February 15, 2013, except where otherwise indicated.
Certain information required by this Item 10 is omitted for NSTAR Electric, PSNH and WMECO pursuant to Instruction I(2)(c) to Form 10-K, Omission of Information by Certain Wholly Owned Subsidiaries.
NU
In addition to the information provided below concerning the executive officers of NU, incorporated herein by reference is the information to be contained in the sections captioned "Election of Trustees," "Governance of Northeast Utilities" and the related subsections, "Selection of Trustees," and "Section 16(a) Beneficial Ownership Reporting Compliance" of NU's definitive proxy statement for solicitation of proxies, expected to be filed with the SEC on or about March 21, 2013.
NU and CL&P
Each member of CL&P’s Board of Directors is an employee of CL&P, NU or an affiliate. Directors are elected annually to serve for one year until their successors are elected and qualified.
Set forth below is certain information as of February 15, 2013 concerning CL&P’s Directors and NU’s and CL&P’s executive officers:
Name
Age
Title
Thomas J. May
President and Chief Executive Officer of NU; Chairman of CL&P.
Leon J. Olivier
Executive Vice President and Chief Operating Officer of NU; Chief Executive Officer of the Regulated companies; Director of CL&P.
James J. Judge
Executive Vice President and Chief Financial Officer of NU and the Regulated companies; Director of CL&P.
Gregory B. Butler
Senior Vice President, General Counsel and Secretary of NU; Senior Vice President and General Counsel of the Regulated companies; Director of CL&P.
Christine M. Carmody 1
Senior Vice President-Human Resources of NUSCO, NSTAR Electric & Gas, and the Regulated companies; Director of CL&P.
William P. Herdegen III 2
President and Chief Operating Officer and a Director of CL&P.
David R. McHale
Executive Vice President and Chief Administrative Officer of NU and the Regulated companies; Director of CL&P.
James A. Muntz
Senior Vice President-Transmission of NU and the Regulated companies.
Joseph R. Nolan, Jr. 1
Senior Vice President-Corporate Relations NUSCO, NSTAR Electric & Gas, and the Regulated companies; Director of CL&P.
Jay S. Buth
Vice President, Controller and Chief Accounting Officer of NU and the Regulated companies.
Deemed an executive officer of NU pursuant to Rule 3b-7 under the Securities Exchange Act of 1934.
Mr. Herdegen is the President and Chief Operating Officer and Director of CL&P and is therefore an executive officer solely of CL&P.
Thomas J. May. Mr. May became President and Chief Executive Officer and a Trustee of NU, Chairman and a Director of CL&P, NSTAR Electric, NSTAR Gas, PSNH, WMECO and Yankee Gas, and Chairman, President and Chief Executive Officer and a Director of NUSCO upon completion of the Merger. He has been President and Chief Executive Officer of NSTAR Electric & Gas since January 1, 2002. Mr. May has served as a Director of NSTAR Electric, NSTAR Gas and NSTAR Electric & Gas (or their predecessor companies) since September 27, 1999. Previously, Mr. May served as Chairman, President and Chief Executive Officer and a Trustee of NSTAR, and as Chairman, President and Chief Executive Officer of NSTAR Electric, NSTAR Gas and NSTAR Electric & Gas until the closing of the Merger. He served as Chairman, Chief Executive Officer and a Trustee since NSTAR was formed in 1999, and was elected President in 2002. Mr. May became a Director of Northeast Utilities Foundation, Inc. upon completion of the Merger. He has served as a Trustee of the NSTAR Foundation since August 18, 1987.
Leon J. Olivier. Mr. Olivier has served as Executive Vice President and Chief Operating Officer of NU and NUSCO since May 13, 2008, and of NSTAR Electric & Gas since the completion of the Merger. He became Chief Executive Officer of NSTAR Electric and NSTAR Gas upon completion of the Merger. Mr. Olivier has served as Chief Executive Officer of CL&P, PSNH, WMECO and Yankee Gas since January 15, 2007. Mr. Olivier was elected a Director of NSTAR Electric, NSTAR Gas and NSTAR Electric & Gas effective November 27, 2012, of PSNH, WMECO and Yankee Gas effective January 17, 2005, and of CL&P effective September 10, 2001. Previously, Mr. Olivier served as Executive Vice President-Operations of NU from February 13, 2007 to May 12, 2008. Mr. Olivier became a Trustee of the NSTAR Foundation upon completion of the Merger. He has served as a Director of Northeast Utilities Foundation, Inc. since April 1, 2006.
James J. Judge. Mr. Judge became Executive Vice President and Chief Financial Officer of NU, CL&P, NSTAR Electric, NSTAR Gas, PSNH, WMECO, Yankee Gas, NUSCO and NSTAR Electric & Gas upon completion of the Merger. Mr. Judge was elected a Director of CL&P, PSNH, WMECO, Yankee Gas and NUSCO upon completion of the Merger. He has served as a Director of NSTAR Electric, NSTAR Gas and NSTAR Electric & Gas since September 27, 1999. Previously, Mr. Judge served as Senior Vice President and Chief Financial Officer of NSTAR, NSTAR Electric, NSTAR Gas and NSTAR Electric & Gas from 1999 until April 2012. Mr. Judge became Treasurer and a Director of Northeast Utilities Foundation, Inc. effective upon completion of the Merger. He has served as a Trustee of the NSTAR Foundation since December 12, 1995.
Gregory B. Butler. Mr. Butler became Senior Vice President, General Counsel and Secretary of NU and Senior Vice President and General Counsel of NSTAR Electric, NSTAR Gas and NSTAR Electric & Gas upon completion of the Merger. He has served as Senior Vice President and General Counsel of CL&P, PSNH, WMECO, Yankee Gas and NUSCO since March 9, 2006. Mr. Butler was elected a Director of NSTAR Electric, NSTAR Gas and NSTAR Electric & Gas upon completion of the Merger. He has served as a Director of NUSCO since November 27, 2012, and of CL&P, PSNH, WMECO and Yankee Gas since April 22, 2009. Previously Mr. Butler served as Senior Vice President and General Counsel of NU from December 1, 2005 to April 2012. Mr. Butler became a Trustee of the NSTAR Foundation effective upon completion of the Merger. He has served as a Director of Northeast Utilities Foundation, Inc. since December 1, 2002.
Christine M. Carmody. Ms. Carmody became Senior Vice President-Human Resources of NUSCO upon completion of the Merger and of CL&P, PSNH, WMECO and Yankee Gas effective November 27, 2012. She has served as Senior Vice President-Human Resources of NSTAR Electric, NSTAR Gas and NSTAR Electric & Gas since August 1, 2008. Ms. Carmody was elected a Director of CL&P, PSNH, WMECO and Yankee Gas upon completion of the Merger, and of NSTAR Electric, NSTAR Gas, NUSCO and NSTAR Electric & Gas effective November 27, 2012. Previously, Ms. Carmody served as Vice President-Organizational Effectiveness of NSTAR, NSTAR Electric, NSTAR Gas and NSTAR Electric & Gas from June 2006 to August 2008. Ms. Carmody became a Director of Northeast Utilities Foundation, Inc. effective upon completion of the Merger. She has served as a Trustee of the NSTAR Foundation since August 1, 2008.
William P. Herdegen III. Mr. Herdegen has served as President and Chief Operating Officer of CL&P since September 11, 2012. Previously, Mr. Herdegen served as Vice President of Transmission and Distribution Engineering and Operations for Kansas City Power & Light Company from 2008 until his retirement on September 7, 2012, as Vice President, Distribution and Customer Operations from 2005 to 2008, and as Vice President, Distribution Operations from 2001 to 2005. Mr. Herdegen began his utility career at Commonwealth Edison, where he held various positions, including Vice President, Engineering, Construction and Maintenance, corporate project manager, operations manager, business unit supply manager, district manager, and field engineer.
David R. McHale. Mr. McHale became Executive Vice President and Chief Administrative Officer of NU, CL&P, NSTAR Electric, NSTAR Gas, PSNH, WMECO, Yankee Gas, NUSCO and NSTAR Electric & Gas upon completion of the Merger. Mr. McHale has served as a Director of NSTAR Electric, NSTAR Gas and NSTAR Electric & Gas since November 27, 2012, of PSNH, WMECO, Yankee Gas and NUSCO since January 1, 2005, and of CL&P since January 15, 2007. Previously, Mr. McHale served as Executive Vice President and Chief Financial Officer of NU, CL&P, PSNH, WMECO, Yankee Gas and NUSCO from January 2009 to April 2012, and Senior Vice President and Chief Financial Officer of NU, CL&P, PSNH, WMECO, Yankee Gas and NUSCO from January 2005 to December 2008. Mr. McHale became a Trustee of the NSTAR Foundation upon completion of the Merger. He has served as a Director of Northeast Utilities Foundation, Inc. since January 1, 2005.
James A. Muntz. Mr. Muntz has served as President - Transmission of NUSCO since November 1, 2008, Senior Vice President - Transmission of CL&P, PSNH and WMECO since June 19, 2007, and Senior Vice President - Transmission of NSTAR Electric & Gas since January 16, 2013. He served as President and Chief Operating Officer of CL&P from November 18, 2011 to September 11, 2012. Previously, Mr. Muntz served as Senior Vice President - Transmission of NUSCO from June 19, 2007 to October 31, 2008 and Vice President - Transmission Products of CL&P, PSNH and WMECO from January 17, 2005 to June 19, 2007. Mr. Muntz has served as President of NPT since April 21, 2010.
Joseph R. Nolan, Jr. Mr. Nolan became Senior Vice President-Corporate Relations of NUSCO, NSTAR Electric & Gas, NSTAR Electric and NSTAR Gas upon completion of the Merger. He became Senior Vice President-Corporate Relations of CL&P, PSNH, WMECO and Yankee Gas effective November 27, 2012. Mr. Nolan was elected a Director of CL&P, PSNH, WMECO and Yankee Gas upon completion of the Merger, and of NSTAR Electric, NSTAR Gas, NUSCO and NSTAR Electric & Gas effective November 27, 2012. Previously, Mr. Nolan served as Senior Vice President-Customer & Corporate Relations of NSTAR, NSTAR Electric, NSTAR Gas and NSTAR Electric and Gas from 2006 until the closing of the Merger. Mr. Nolan became a Director of Northeast Utilities Foundation, Inc. upon completion of the Merger. He has served as a Trustee of the NSTAR Foundation since October 1, 2000.
Jay S. Buth. Mr. Buth became Vice President, Controller and Chief Accounting Officer of NU, CL&P, NSTAR Electric, NSTAR Gas, PSNH, WMECO, Yankee Gas, NUSCO and NSTAR Electric & Gas upon completion of the Merger. Previously, Mr. Buth was Vice President-Accounting and Controller of NU, CL&P, PSNH, WMECO, Yankee Gas and NUSCO from June 2009 through the completion of the Merger. From June 2006 through January 2009, Mr. Buth was the Vice President and Controller for New Jersey Resources Corporation, an energy services holding company that provides natural gas and wholesale energy services, including transportation, distribution and asset management.
There are no family relationships between any director or executive officer and any other trustee, director or executive officer of NU or CL&P and none of the above executive officers or directors serves as an executive officer or director pursuant to any agreement or understanding with any other person. Our executive officers hold the offices set forth opposite their names until the next annual meeting of the Board of Trustees, in the case of NU, and the Board of Directors, in the case of CL&P, and until their successors have been elected and qualified.
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. CL&P relies on NU’s audit committee and audit committee experts.
CODE OF ETHICS AND STANDARDS OF BUSINESS CONDUCT
Each of NU, CL&P, NSTAR Electric, PSNH and WMECO has adopted a Code of Ethics for Senior Financial Officers (Chief Executive Officer, Chief Financial Officer and Controller) and the Standards of Business Conduct, which are applicable to all Trustees, directors, officers, employees, contractors and agents of NU, CL&P, NSTAR Electric, PSNH and WMECO. The Code of Ethics and the Standards of Business Conduct have both been posted on the NU web site and are available at www.nu.com/investors/corporate_gov/default.asp on the Internet. Any amendments to or waivers from the Code of Ethics and Standards of Business Conduct for executive officers, directors or Trustees will be posted on the website. Any such amendment or waiver would require the prior consent of the Board of Trustees or an applicable committee thereof.
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:
Richard J. Morrison
Assistant Secretary
Northeast Utilities
P.O. Box 270
Hartford, CT 06141
Item 11.
Item 11.
Executive Compensation
NU
The information required by this Item 11 for NU is incorporated herein by reference to certain information contained in NU’s definitive proxy statement for solicitation of proxies, which is expected to be filed with the SEC on or about March 21, 2013, under the sections captioned "Compensation Discussion and Analysis" plus the related subsections, and "Compensation Committee Report" plus the related subsections following such Report.
NSTAR ELECTRIC, PSNH and WMECO
Certain information required by this Item 11 has been omitted for NSTAR Electric, PSNH and WMECO pursuant to Instruction I(2)(c) to Form 10-K, Omission of Information by Certain Wholly Owned Subsidiaries.
CL&P
The information in this Item 11 relates solely to CL&P.
COMPENSATION DISCUSSION AND ANALYSIS
CL&P is a wholly-owned subsidiary of NU. Its board of directors consists entirely of executive officers of NU system companies. CL&P does not have a compensation committee, and the Compensation Committee of NU’s Board of Trustees determines compensation for the executive officers of CL&P, including their salaries, annual incentive awards and long-term incentive awards. All of CL&P’s "Named Executive Officers," as defined below, also serve as officers of NU and one or more other subsidiaries of NU. Compensation set by the Compensation Committee of NU (the "Committee") and set forth herein is for services rendered to NU and its subsidiaries by such officers in all capacities.
EXECUTIVE SUMMARY
On April 10, 2012, NU acquired all of the outstanding common shares of NSTAR and NSTAR became a direct wholly owned subsidiary of NU. Immediately after the merger, the pre-merger shareholders of NU owned 56.3 percent of NU’s common shares, and the pre-merger NSTAR shareholders owned 43.7 percent of NU’s common shares.
This discussion describes NU’s material compensation policies and practices generally. It also describes their application to the compensation awards and decisions made with respect to 2012 by both the pre-merger and post-merger compensation committees for the Named Executive Officers, as presented in the tables and narratives that follow. While the following discussion focuses primarily on the 2012 information that is presented in the accompanying tables and narratives, it also addresses decisions that were taken in other periods to the extent that these decisions are relevant to the full understanding of the compensation decisions for 2012.
Summary of 2012 Performance
In 2012, NU completed one of the most significant mergers in the utility industry, creating one of the nation’s largest utilities, with four regulated electric and two regulated natural gas utilities serving 3.5 million customers in three states and a market capitalization of approximately $12.5 billion, the fifteenth largest in the utility industry. Leading up to the merger, the executive team successfully built the foundation for the merged company to deliver positive financial results and refine NU’s operations to deliver excellent service for customers. As a result of the merger, NU has become more diverse and better positioned to provide value to its customers and our shareholders.
At the time of the announcement of the merger, NU identified the substantial financial, strategic and operational benefits it expected the merger to provide. During 2012, the management of the newly combined company immediately came together as an efficient team to deliver those benefits. The following is a summary of some of the most important accomplishments:
Financial Highlights
·
NU’s 2012 reported earnings of $2.28 per share exceeded its stretch earnings per share target of $2.27, despite the difficult environment resulting from the sluggish economy, mild winter weather and the effect of increases in pension and healthcare costs.
·
In completing the merger, NU negotiated multi-year rate settlements in Connecticut and Massachusetts that position NU to maintain its strong financial condition and achieve positive financial performance for its shareholders.
·
Reflecting the benefits of the merger, during 2012 NU achieved a total shareholder return of 12.1 percent, substantially outperforming the Edison Electric Institute (EEI) Index return of 2.1 percent and other major utility companies that have completed a significant merger in the past 18-24 months.
·
NU’s cumulative total shareholder returns of 67.7 percent, 48.9 percent, 260.9 percent and 399.1 percent over the past three-, five-, 10- and 15-year periods outperformed the industry and the market over these same periods. NU also ranked in the top performing quartile of the EEI Index for each of the listed time periods.
Operational and Merger Effectiveness Highlights
·
NU implemented its "One Company" shared services operating model that allowed it to lower operating costs while improving customer service and enhancing emergency preparedness by effectively deploying the resources of the merged company.
·
NU developed an enhanced $3.7 billion five-year transmission capital plan to better improve the efficiency of New England’s congested energy markets, improve reliability and increase revenues over the long-term compared to what either pre-merger company could have achieved on its own.
·
NU met or exceeded the Massachusetts-mandated electric and gas service targets, as measured by the Service Quality Index; and NU’s electric and gas systems improved the Months Between Interruptions, On-Time Gas System Response, System Average Interruption Duration, Customer Average Interruption Duration, Calls Answered Rate and Meters Read On Time metrics.
Achievement of the 2012 performance goals and the Committee’s assessment of NU and executive performance are fully described in the section captioned "2012 Annual Incentive Program." Specific decisions regarding executive compensation based upon the Committee’s assessment of NU and executive performance and the market data described in this Compensation Discussion and Analysis (CD&A) are set forth below.
NAMED EXECUTIVE OFFICERS
The executive officers of CL&P listed in the Summary Compensation Table in this Item 11 whose compensation is discussed in this CD&A are CL&P’s Chief Executive Officer (CEO), Executive Vice President and Chief Financial Officer (CFO), and the three other most highly compensated executive officers other than CL&P’s CEO and CFO who were serving as executive officers at the end of 2012 (collectively, referred to as the "Named Executive Officers" or "NEOs"). Each Named Executive Officer of CL&P also serves as an executive officer of NU and one or more other subsidiaries of NU. Compensation for such NEOs discussed in this CD&A was for all services provided by such individuals in all capacities to NU and its subsidiaries. For 2012, CL&P’s Named Executive Officers are:
·
Leon J. Olivier, Chief Executive Officer of CL&P
·
David R. McHale, Executive Vice President and Chief Financial Officer until April 10, 2012; Executive Vice President and Chief Administrative Officer from April 10, 2012 to present
·
James J. Judge, Executive Vice President and Chief Financial Officer from April 10, 2012 to present
·
Thomas J. May, President and Chief Executive Officer of NU, and Chairman of CL&P, from April 10, 2012 to present
·
Gregory B. Butler, Senior Vice President, General Counsel and Secretary of NU; Senior Vice President and General Counsel of CL&P
·
James A. Muntz, Senior Vice President-Transmission of NU and CL&P
·
Charles W. Shivery, Chairman of CL&P, until April 10, 2012; Chairman of the Board of NU
SEC rules require that the Named Executive Officers also include (i) all individuals who served as principal executive officer and principal financial officer during 2012 and (ii) up to two additional individuals who would have been one of the three other most highly compensated executive officers if they had been serving as an executive officer at the end of 2012. Therefore, each of the individuals named above is considered to be a Named Executive Officer for this Compensation Discussion and Analysis. For the NEOs who came from NSTAR, Messrs. May and Judge, the disclosure pertains to compensation earned by each of them subsequent to the Merger. While Mr. Muntz is considered to be a Named Executive Officer, his post-merger compensation is not subject to approval by the Committee, as he is not a senior executive officer as defined by NU’s post-merger Compensation Committee Charter.
OVERVIEW OF OUR COMPENSATION PROGRAM
The Role of the Compensation Committee. The NU Board of Trustees has delegated to the Committee overall responsibility for establishing the compensation program for all executive officers, including the Named Executive Officers. In this role, the Committee sets compensation policy and compensation levels, reviews and approves performance goals and evaluates executive performance. Although this discussion and analysis refers principally to compensation for the Named Executive Officers, the same compensation principles and practices generally apply to all executive officers. The compensation of the Chief Executive Officer is subject to the further review and approval of the independent Board members.
Elements of Compensation. Total direct compensation is delivered primarily through a combination of three elements: base salary, annual cash incentive awards and long term equity-based incentive awards. Compensation is also provided through certain retirement, perquisite, severance, and health and welfare benefit programs.
Compensation Objectives. The objectives of NU’s compensation program are to attract and retain superior executive talent, to motivate our executives to achieve short-term and long-term performance goals set each year, and to provide base salary, performance-based annual incentive compensation and long-term incentive compensation opportunities that are competitive with the market. With respect to incentive compensation, the Committee believes it is important to balance short-term goals, such as generating earnings, with longer-term goals, such as long-term value creation, maintaining a strong balance sheet, system reliability and great customer service. NU’s compensation program utilizes performance-based compensation programs to reward individual and corporate performance and to link the interests of executives with its customers and shareholders. The Committee continually increases expectations to incentivize executives and employees to achieve continuous improvement in discharging NU’s responsibilities to its customers to provide energy services reliably, safely, with respect for the environment and its employees, and at a reasonable cost, while providing an above-average return to its shareholders.
Setting Compensation Levels. In order to ensure that NU achieves its goal of providing market-based compensation levels to attract and retain top quality management, the Committee provides executive officers with target compensation opportunities over time approximately equal to median compensation levels for executive officers of companies comparable to NU. To achieve that goal, the Committee and its compensation consultant work together to determine the market values of executive officer compensation elements (base salaries, annual incentives and long-term incentives) as well as total compensation, using compensation data obtained from other companies. The Committee reviews compensation data obtained from utility and general industry surveys and a group of peer utility companies. The Committee then reviews the compensation elements for each executive officer with respect to the median of these market value benchmarks and considers individual performance, experience and internal pay equity to determine total compensation.
Role of the Compensation Consultant. NU’s post-merger Committee has retained Pay Governance LLC ("Pay Governance") as its independent compensation consultant. Prior to the merger, the Committee had retained Semler Brossy Consulting Group LLC as its independent compensation consultant. Pay Governance reports directly to the Committee and does not provide any other services to NU. Pay Governance works cooperatively with NU’s management to develop analyses and proposals for presentation to the Committee. The Committee generally relies on Pay Governance for peer group market data and information as to market practices and trends to assess the competitiveness of the compensation NU pays to its senior executive officers and to review the Committee’s proposed compensation decisions. The Committee has assessed the independence of Pay Governance pursuant to SEC and New York Stock Exchange rules and concluded that it is independent and that no conflicts of interest exist that would prevent Pay Governance from independently advising the Committee.
Role of Management. The role of management of NU and specifically the role of NU’s Chief Executive Officer and its Senior Vice President of Human Resources is to provide current compensation information to the compensation consultant and to provide analysis and recommendations on executive officer compensation to the Committee based on the market value of the position, individual performance, experience and internal pay equity. Neither of these executives makes recommendations that affect their own compensation.
Set forth below is a description of the sources of the compensation data used by the Committee when reviewing pre-merger 2012 compensation:
·
Utility and general industry survey data. The pre-merger Committee reviewed compensation information obtained from surveys of diverse groups of utility and general industry companies that represent NU’s market for executive officer talent. The Committee used this information, which it obtained from Semler Brossy Consulting Group LLC, to determine base salaries and incentive opportunities. Then the Committee reviewed the utility-specific executive officer positions as compared to utility-specific market values.
·
Peer group data. The pre-merger Committee also evaluated compensation data obtained from reviews of proxy statements from a group of peer utility companies. In support of pre-merger executive pay decisions during 2012, the peer group consisted of utilities with annual revenues that ranged from $2.3 billion to $10.6 billion, with median annual revenues of $4.6 billion. The Committee considered data only for those executive officer positions where there was a title match, which in 2012 included NU’s Chief Executive Officer, Chief Financial Officer, Chief Operating Officer and General Counsel positions. For 2012, the pre-merger peer group consisted of the following 18 companies:
Alliant Energy Corporation
Integrys Energy Group Inc.
Pinnacle West Capital Corporation
Ameren Corporation
NiSource Inc.
Progress Energy, Inc.
CenterPoint Energy, Inc.
NSTAR
SCANA Corporation
CMS Energy Corporation
NV Energy, Inc.
TECO Energy, Inc.
DTE Energy Company
OGE Energy Corp.
Wisconsin Energy Corporation
Great Plains Energy Incorporated
Pepco Holdings, Inc.
Xcel Energy Inc.
The Committee periodically adjusts the target percentages of annual and long-term incentives based on the survey data and the recommendations of the compensation consultant to ensure that they are approximately equal to competitive median levels. In February 2012, the Committee also used this peer group for performance comparisons under the 2012 - 2014 Long-Term Incentive Program.
The Committee also determines perquisites to the extent they serve business purposes and sets supplemental benefits at levels that provide market-based compensation opportunities to the executive officers. The Committee periodically reviews the general market for supplemental benefits and perquisites using utility and general industry survey data, sometimes including data obtained from companies in the peer group.
Mix of Compensation Elements. The target mix of compensation for NU’s Chief Executive Officer and the other Named Executive Officers is approximately equal to the competitive median market mix. More senior positions involve increased responsibility for implementing our long-term business plans and strategies, and a greater proportion of total compensation is based on performance with a long-term focus.
The Committee determines the compensation for each senior executive officer based on the relative authority, duties and responsibilities of each officer. The responsibilities of NU’s CEO for the strategic direction and daily operations and management of the Northeast Utilities System companies, as President and Chief Executive Officer of NU and Chairman of each of the Regulated companies, are greater than the duties and responsibilities of the other executive officers. As a result, the compensation of NU’s CEO is higher than the compensation of the other executive officers. Assisted by the compensation consultant, the Committee regularly reviews market compensation data for executive officer positions similar to those held by the executive officers, including the CEO, and this market data continues to indicate that chief executive officers are typically paid significantly more than other executive officers. For 2012, prior to the merger closing, target annual incentive and long-term incentive compensation opportunities for NU’s CEO were 100 percent and 300 percent of base salary respectively. For the remaining Named Executive Officers, pre-merger target annual incentive compensation opportunities ranged from 50 percent to 65 percent of base salary and target long-term incentive compensation opportunities ranged from 100 percent to 150 percent of base salary.
The following table sets forth the contribution to 2012 pre-merger Total Direct Compensation (TDC) of each element of compensation, at target, reflected as a percentage of TDC, for the Named Executive Officers. The amounts shown in this table are at target and therefore will not match the amounts appearing in the Summary Compensation Table.
(1)
The annual incentive compensation element and performance units under the long-term incentive compensation element are performance-based.
(2)
Restricted Share Units ("RSUs") vest over three years contingent upon continued employment.
(3)
Messrs. May and Judge were not executive officers when targets were set in January 2012.
Analysis of Risk. The Committee periodically assesses the potential risks that may be caused by the compensation programs and mitigates risks by rigorously analyzing the setting of goals and the minimum performance thresholds and ceilings for the incentive programs, continuously monitoring performance and enterprise risk, and retaining discretion with respect to actual payouts. The Committee has the ability to reduce compensation amounts, set caps on incentive compensation and provides meaningful base compensation, all of which serve to reduce compensation risk. In addition, the executives must comply with share ownership guidelines that more closely link their interests to those of shareholders, are subject to clawback of incentive compensation under certain circumstances, and are provided limited perquisites.
Results of NU’s Say on 2011 Pay Proposal. NU provides its shareholders with the required opportunity to cast an annual advisory vote on executive compensation (a "say-on-pay" proposal). At NU’s Annual Meeting of Shareholders held in October 2012, 95.77 percent of the votes cast on the say-on-pay proposal were voted to approve the compensation of the Named Executive Officers, as described in NU’s 2012 proxy statement. The Committee will continue to consider the outcome of NU’s say-on-pay votes when making future compensation decisions for the Named Executive Officers.
ELEMENTS OF 2012 COMPENSATION
Base Salary
Base salary is designed to attract and retain key executives by providing an element of total compensation competitive with that of other executives employed by companies of similar size and complexity in the utility and general industries. In establishing base salary, the Committee relies on compensation data obtained from third-party surveys of companies and from an industry peer group to ensure that the compensation opportunities NU offers are capable of attracting and retaining executives with the experience and talent required to achieve our strategic objectives.
When setting or adjusting base salaries, the Committee considers annual individual performance appraisals; market pay movement across industries (determined through market analysis); targeted market pay positioning for each executive officer; individual experience and years of service; strategic importance of a position; and internal equity.
Individuals who are performing well in strategic positions are likely to have their base salaries increased more significantly than other individuals. From time-to-time, economic conditions and corporate performance have caused salary increases to be postponed. The Committee prefers to reflect subpar corporate performance through the variable pay components.
In February 2012, the pre-merger Committee adjusted the base salaries of the Named Executive Officers (except for Mr. Shivery) by 3 percent to 3.5 percent.
Incentive Compensation
The annual incentive program and the long-term incentive program are provided under the Northeast Utilities Incentive Plan, which was approved by NU’s shareholders at the 2007 Annual Meeting of Shareholders and, with respect to the material terms of performance goals, was re-approved by NU’s shareholders at the 2012 Annual Meeting of Shareholders. The annual incentive program provides cash compensation intended to reward performance under NU’s annual operating plans. The long-term incentive program is designed to reward demonstrated performance and leadership, motivate future performance, align the interests of the executive officers with those of NU’s shareholders and retain the executive officers during the term of grants. The annual and long-term programs are designed to strike a balance between the short and long-term objectives so that the programs work in tandem.
2012 ANNUAL INCENTIVE PROGRAM
Target award levels under the Annual Incentive Program are expressed as a percentage of each Named Executive Officer’s base salary. For each of the Named Executive Officers, target award levels throughout 2012 ranged from 50 percent to 100 percent of base salary. Based on the Committee’s assessment, in its discretion, of the financial and operational performance of NU, as well as its assessment of each Named Executive Officer’s individual performance, awards under the Program may be made within a range of 0 percent to 200 percent of target. The annual target award level set by the pre-merger Committee for NU’s CEO, Mr. Shivery and, following the completion of the merger by the post-merger Committee for NU’s CEO, Mr. May, was set at 100 percent of base pay for 2012. The maximum possible award is 200 percent of base salary.
In early 2012, when completion of the Merger was still uncertain, the committees responsible for compensation at each of NU and NSTAR established goals under their respective annual incentive programs. The principal financial goal set by the NSTAR Executive Personnel Committee was based on NSTAR earnings per share, which had been NSTAR’s long-standing principal financial metric. The pre-merger NU Committee set a 2012 financial goal expressed in both Adjusted Net Income and Earnings Per Share. In view of the fact that the Merger was completed in early April 2012, the Committee determined later in 2012 that it would need to exercise more discretion at the end of the year to determine the level of achievement for the purpose of 2012 annual incentive awards for the Named Executive Officers. The Committee determined to be guided in its discretion by the earnings per share goal and the level of operational and merger effectiveness performance achieved by the post-merger combined management team. While retaining discretion with respect to these measures, the Committee emphasized the need for the management team to also focus on meeting or exceeding the rigorous regulatory metrics established for NU, as well as the goals established by the NSTAR and NU compensation committees prior to the merger.
Later in 2012, the Committee met with Pay Governance, which provided the Committee with a competitive assessment analysis of our executive compensation levels. Included in the analysis was a recommended change to the utility peer group that is used for the purposes of assisting the Committee in establishing and maintaining market-based compensation levels. The change was made to better assess market competitiveness due to the larger size of the post-merger company. The Committee adopted this recommendation. The post-merger peer group consists of the 20 companies listed below, which have revenues of $3.3 billion to $14.9 billion, with median annual revenues of $8.6 billion, more in line with the revenues of post-merger NU:
Alliant Energy Corporation
Edison International
Public Service Enterprise Group, Inc.
Ameren Corporation
Entergy Corporation
SCANA Corporation
CenterPoint Energy, Inc.
Integrys Energy Group, Inc.
Sempra Energy
Consolidated Edison Inc.
OGE Energy Corp.
TECO Energy, Inc.
CMS Energy Corp.
Pepco Holdings, Inc.
Wisconsin Energy Corp.
Dominion Resources, Inc.
PG&E Corp.
Xcel Energy Inc.
DTE Energy Company
PPL Corporation
In late 2012 and early 2013, prior to the actions taken by the Committee at its February 4, 2013 meeting, the Committee met three times to discuss post-merger compensation programs generally and to assess the performance of NU and the management team. As part of the compensation assessment, the Committee determined at its January 2013 meeting that it was appropriate to set the elements of target base and incentive compensation, including 2012 annual incentive payments, based on the median of the post-merger utility peer group. With respect to annual incentive targets, adjustments were made to the targets of some of the senior executive officers, but not NU’s CEO, Mr. May, whose target remained at 100 percent of base salary. The minimum annual incentive target for senior executive officers is now 45 percent of base salary. The Committee also discussed performance weighting, and after consultation with Pay Governance, the Committee determined at its January 2013 meeting that in assessing 2012 performance for all executive officers, it would base 50 percent of the annual incentive award on its assessment of NU’s financial performance and 50 percent on its operational/merger effectiveness performance.
With respect to 2012 performance, management prepared a comprehensive review of NU’s performance for the year. Based on that analysis, NU’s Chief Executive Officer recommended to the Committee payout levels for the senior executive officers based on NU’s overall financial and operational/merger effectiveness performance, along with his assessment of each executive officer’s individual performance. Other than with respect to the earnings per share goal, in exercising its discretion to determine award levels for financial and operational/merger effectiveness performance results, the Committee did not use pre-determined or quantifiable formulas based on the degree of achievement of performance metrics. The Committee used its discretion to consider a substantial number of financial and operational results, including its assessment of the difficulty of achieving those results. The Committee determined, based on its assessment of the various financial and operational/merger effectiveness performance results discussed below, to set the level of achievement of combined financial and operational/merger effectiveness performance results at 180 percent of target, reflecting the overall superior performance of NU and the executive team.
Financial Performance Factors Considered by the Committee
The Committee determined in its discretion that the financial performance of NU was outstanding and that the award for 2012 financial performance (weighted 50 percent) would be 200 percent of target. The Committee considered the following financial results:
·
The completion of the transformational merger transaction, which reduces regulatory risks and provides both the potential for above-average growth and the foundation for improved customer service levels.
·
The price/earnings multiple applicable to NU’s common shares at year-end increased from slightly below the industry average at the time of the merger announcement to significantly above the average price/earnings multiple. This premium price/earnings multiple resulted in the creation of approximately $1.3 billion in incremental shareholder value.
·
NU achieved earnings per share of $2.28, exceeding the stretch target despite the difficult environment noted above, through continuous performance improvement and cost reductions, while at the same time improving customer service performance.
·
Reflecting the benefits of the merger, during 2012 NU had top-tier total shareholder return of 12.1 percent, substantially outperforming the EEI Index return of 2.1 percent, and outperforming other major utility companies that have completed a significant merger in the past 18-24 months.
·
NU implemented effective refinancing programs resulting in significant annualized interest cost savings of approximately $30 million.
·
NU’s credit rating at Standard & Poor’s improved to "A-," among the highest in the utility industry, as a result of NU’s more diverse operations, stronger financial condition and improved cash flows, providing the foundation for favorable financing opportunities in the future. The industry average credit rating at Standard & Poor’s is "BBB."
·
NU achieved operations and maintenance cost reductions through successful integration activities, resulting in significant cost savings.
·
NU executed a robust $1.7 billion capital program targeted to improve system reliability while maintaining NU’s financial integrity.
·
Cumulative total shareholder returns were 67.7 percent, 48.9 percent, 260.9 percent and 399.1 percent over the past three-five-10-and 15-year periods, significantly outperforming the industry and the market over those same periods. NU also ranked in the top performing quartile of the EEI Index for each of the periods noted.
Operational and Merger Effectiveness Performance Factors Considered by the Committee
The Committee determined in its discretion that the operational and merger effectiveness performance of NU was excellent, and set the award for 2012 operational performance (weighted 50 percent) at 160 percent of target. In doing so, the Committee considered the following results:
·
NU implemented a "One Company" shared services operating model that allowed us to lower operating costs while improving customer service and enhanced emergency preparedness by effectively deploying the resources of the merged company. NU demonstrated the benefits of our One Company approach during restoration efforts from Superstorm Sandy, when it quickly deployed crews from Massachusetts and New Hampshire upon completion of restoration activities to the hard-hit Connecticut area.
·
NU developed an enhanced $3.7 billion five-year transmission capital plan to better improve the efficiency of New England’s congested energy markets, improve reliability and increase revenues over the long-term compared to what either predecessor company could have achieved on its own.
·
NU met or exceeded the Massachusetts-mandated electric and gas service targets, as measured by the Service Quality Index, and the electric and gas systems improved the Months Between Interruptions, On-Time Gas System Response, System Average Interruption Duration Index, Customer Average Interruption Duration, Calls Answered Rate and Meters Read On Time metrics. NU’s internal metric results were as follows:
o
Average months between service interruptions equaled 13.4 months, exceeding the target of 12.4 months
o
On-time response to gas customer emergency calls was 99.5 percent, exceeding the target of 99 percent
o
Electric service outage restoration time of 104.1 minutes was significantly better than the target of 111.6 minutes
o
99.2 percent of meters were read on time, exceeding the 99 percent target, and
o
88.2 percent of customer calls were answered within 30 seconds, exceeding the 85.6 percent target
·
NU’s natural gas distribution subsidiaries ranked numbers 1 and 2 as compared to their peer utilities in the J.D. Power Gas Customer Satisfaction survey.
·
NU achieved a number of successful legal and regulatory outcomes, and our energy efficiency programs performed very effectively, meeting aggressive internal and state-wide savings targets.
·
NU significantly improved its safety performance in Days Away Restricted Duty (DART) and Preventable Motor Vehicle Accidents (PMVA) compared to target and prior year performance. DART for 2012 was 1.85 accidents per 100 employees, compared to target of 2.07, while PMVAs for 2012 equaled 2.92 per million miles traveled compared to the target of 4.11. All performance comparisons showed a double-digit rate of improvement.
Individual Performance Factors Considered by the Committee
Following the completion of the merger, the goal of the Committee for 2012 was to incentivize the newly combined company’s executives to come together as a highly effective, integrated team to achieve or exceed the adjusted earnings per share target and other financial, operational and merger effectiveness objectives. While emphasizing the importance of the executives to work as a team, the Committee made annual incentive award payments based also on the assessment of each executive’s individual performance. The Committee assessed the team performance of NU’s Chief Executive Officer and the Named Executive Officers to determine the individual incentive awards as disclosed in the Summary Compensation Table. Based on the Committee’s review of NU’s overall performance, considered by the Committee to have been outstanding for the several reasons set forth above, the Committee approved annual incentive program payouts for the Named Executive Officers at levels that ranged from 173 percent to 185 percent of target. These awards reflected the individual and team contributions of Mr. Shivery, Mr. May, Mr. McHale, Mr. Judge, Mr. Olivier, Mr. Butler and Mr. Muntz in the overall performance of NU.
In arriving at Mr. May’s annual incentive payment of $2,100,000, which was 185 percent of target and reflective of his and NU’s outstanding performance, the Committee and NU’s Board considered the totality of NU’s excellent financial and operating/merger effectiveness performance and Mr. May’s strategic leadership in enabling NU to achieve its excellent performance, along with the success of the merger closing, Mr. May’s leadership in bringing the new executive team together, and his work with key stakeholders.
PRE-MERGER LONG-TERM INCENTIVE PROGRAMS
General
Under the Long-Term Incentive Programs enacted prior to the Merger, the Committee recommended a long-term incentive target grant value for NU’s Chief Executive Officer as a percentage of base salary on the date of grant. This recommendation was presented to NU’s Board of Trustees for approval. The Committee also approved long-term incentive target grant values for each of the other NEOs as a percentage of base salary on the date of grant. For the 2012 - 2014 Long-Term Incentive Program, adopted prior to the completion of the Merger, each grant, at target, consisted of 75 percent performance shares and 25 percent RSUs.
For the 2012 - 2014 program, the pre-merger Committee recommended to NU’s Board of Trustees a long-term incentive compensation target for NU’s Chief Executive Officer at 300 percent of base salary, which the Board approved. The Committee established long-term incentive compensation targets at 100 percent to 150 percent of base salary for the remaining NEOs.
Up to and including 2012, of the Named Executive Officers, only Messrs. Shivery, McHale, Olivier, Butler and Muntz participated in the Northeast Utilities Long-Term Incentive Programs. Messrs. May and Judge did not participate in these programs.
Restricted Share Units (RSUs)
General
Each RSU granted under the long-term incentive program entitles the holder to receive one NU common share at the time of vesting. All RSUs granted under the long-term incentive program provided for vesting in equal annual installments over three years. RSU holders are eligible to receive reinvested dividend units on outstanding RSUs held by them to the same extent that dividends are declared and paid on our common shares. Reinvested dividend units are accounted for as additional RSUs that accrue and are distributed with the common shares issued upon vesting and distribution of the underlying RSUs. Common shares, including any additional common shares in respect of reinvested dividend units, are not issued for any RSUs that do not vest.
The Committee determined RSU grants for each officer participating in the long-term incentive program. RSU grants are based on a percentage of base salary and measured in dollars. The percentage used for each officer is based on the executive officer’s position in the Company and ranges from 5 percent to 75 percent of salary. The Committee reserves the right to increase or decrease the RSU grant from target for each officer under special circumstances. Based on input from NU’s Chief Executive Officer, the Committee determined the final RSU grants for each of the other executive officers, including the other NEOs.
All RSUs are granted on the date of the Committee meeting at which they are approved. RSU grants are subsequently converted from dollars into common share equivalents by dividing the value of each grant by the average closing price for NU common shares over a ten-day average price period prior to the date of the grant.
RSU Grants under the 2012 - 2014 Program
Under the pre-merger 2012 - 2014 program, the target RSU grant totaled approximately $2,567,632 for the 33 officers participating in the long-term incentive program. The Committee did not adjust any officer’s RSU grant from target for the 2012 - 2014 program. Accordingly, the final total RSU grant for officers, including NU’s Chief Executive Officer, was unchanged from target. Using the ten-day average trading price and dividing the final total RSU grant by $34.52 resulted in an aggregate of 74,381 RSUs. The following RSU grants at 100 percent of target were approved, reflected in RSUs: Mr. Shivery: 23,247; Mr. McHale: 6,051; Mr. Olivier: 6,369; Mr. Butler: 4,722; and Mr. Muntz: 3,073. Upon his retirement, a portion of Mr. Shivery’s RSUs under this program vested pro rata based on 2012 employee service (and the remaining RSUs were forfeited).
Performance Units
General
Performance units are a performance-based component of the long-term incentive program. A new three-year program commences every year. To further strengthen the alignment of the performance elements with shareholders’ interests, the performance-based component of NU’s long-term incentive programs evolved from 100 percent performance cash in the 2008 - 2010 program to 100 percent performance shares beginning with the 2011 - 2013 program.
The pre-merger Committee approved the 2012 - 2014 program in early 2012. Performance share grants are converted from dollars into common share equivalents by dividing the value of each grant by the prior ten-day average closing price for NU common shares. During the three-year performance program period, the dividends that would have been paid with respect to the performance shares to holders of performance share grants are accounted for as additional common shares that accrue and are distributed with the common shares, if any, at the end of the program.
Awards under the programs noted above are earned to the extent to which NU achieve goals in the four metrics described below during the three years of the program, except as reduced at the discretion of the Committee. The Committee determines the actual awards, if
any, only after the end of the final year in the respective program. The four metrics used under the 2010 - 2012, 2011 - 2013 and 2012 - 2014 programs were
·
Cumulative Adjusted Net Income (20 percent)
·
Average adjusted return on equity ("ROE") (20 percent)
·
Average credit rating of NU (excluding the regulated utilities) (20 percent)
·
Relative total shareholder return of NU as compared to the return of the utility companies listed in the performance peer group (40 percent)
Before any amount is payable with respect to a metric, NU must achieve a minimum level of performance under that metric, so that in the event it does not achieve a minimum level of performance, no payment is made for that metric. If NU achieves the minimum level of performance for any goal, then the resulting payout will equal 50 percent of the target for that goal. If NU achieves the maximum level of performance for any goal, then the resulting payout will equal 150 percent of target for that goal.
Set forth below are descriptions of each of the three long-term performance programs that were in effect during 2012.
2010 - 2012 Performance Units
The Committee approved the 2010-2012 performance unit grants in early 2010, consisting of one-half performance cash and one-half performance shares. Immediately prior to the completion of the Merger, the achievement of goals applicable to performance shares in the 2010 - 2012 program was measured up to the closing of the Merger. The Committee determined that NU achieved goals under each of the four metrics during the 2010 - 2012 program on a pro-rata basis through April 10, 2012 and, accordingly, that awards under the program were payable at an overall level of 134 percent of target. Payment was made following the end of 2012 (the end of the original performance period) conditioned upon continued employment through such date. Performance shares outstanding immediately before the closing of the Merger attributable to the period from April 10, 2012 to December 31, 2012 were forfeited. The pre-merger Committee granted to each executive officer whose performance shares were forfeited an award of RSUs with a value equal to the value of such forfeited performance units at target.
The table set forth below describes the goals under the 2010 - 2012 program and NU’s actual results during that period:
As a result of NU’s financial performance during the shortened performance period, the Committee approved the following performance cash awards: Mr. Shivery: $1,182,674; Mr. McHale: $299,939; Mr. Olivier: $314,236; Mr. Butler: $232,534; and Mr. Muntz $152,343. In addition, the Committee approved the following performance share awards: Mr. Shivery: 50,863 shares; Mr. McHale: 12,900 shares; Mr. Olivier: 13,514 shares; Mr. Butler: 10,000 shares; and Mr. Muntz: 6,553 shares. In respect of performance units that were forfeited, the Committee approved the following RSU grants: Mr. Shivery: 19,405 RSUs; Mr. McHale: 4,922 RSUs; Mr. Olivier: 5,156 RSUs; Mr. Butler: 3,815 RSUs; and Mr. Muntz: 2,500 RSUs. These awards were determined pursuant to formulas set forth in the 2010 - 2012 Long-Term Incentive Program and were not subject to the discretion of the Committee. Based upon applicable vesting schedules and due to his retirement, Mr. Shivery’s RSUs in respect of forfeited performance units fully vested.
2011 - 2013 Performance Shares
Under the 2011 - 2013 program, each performance grant consisted solely of a performance share grant. As previously approved by the Committee, on April 10, 2012, upon completion of the Merger, all performance shares outstanding under the 2011 - 2013 program were converted to RSUs assuming a target level of performance. These RSUs were made subject to the vesting schedule that applies to the RSU component already granted as part of the 2011 - 2013 program: Mr. Shivery: 76,530 RSUs; Mr. McHale: 19,338 RSUs; Mr. Olivier: 20,357 RSUs; Mr. Butler: 15,020 RSUs; and Mr. Muntz: 9,823 RSUs. Based upon applicable vesting schedules and due to his retirement, Mr. Shivery’s RSUs under this program fully vested.
2012 - 2014 Performance Shares
Under the 2012 - 2014 program, each performance grant also consisted solely of a performance share grant. As previously approved by the Committee, on April 10, 2012, upon completion of the Merger, all performance shares outstanding under the 2012 - 2014 program were converted to RSUs assuming a target level of performance. These RSUs were made subject to the vesting schedule that applies to the RSU component already granted as part of the 2012 - 2014 program: Mr. Shivery: 70,294 RSUs; Mr. McHale: 18,296 RSUs; Mr. Olivier: 19,259 RSUs; Mr. Butler: 14,279 RSUs; and Mr. Muntz: 9,293 RSUs. Upon his retirement, a portion of Mr. Shivery’s RSUs under this program vested pro rata based on 2012 employee service (and the remaining RSUs were forfeited).
OTHER
Retirement Benefits
Retirement Benefits for certain legacy NU employees, including Messrs. Shivery, McHale, Olivier, Butler and Muntz. NU provides a qualified defined benefit pension plan for certain legacy NU employees, including Mr. Shivery, who retired in 2012, and Messrs. McHale, Olivier, Butler and Muntz, which is a final average pay plan subject to tax code limits. Because of such limits, NU also maintains a supplemental non-qualified pension plan (Northeast Utilities Supplemental Plan) for certain legacy NU executives, including Messrs. Shivery, who retired in 2012, McHale, Butler and Muntz. Benefits under this Plan are based on base pay over tax code limits, deferred base salary and certain annual and long-term incentives, which is consistent with the goal of providing a benefit that replaces a percentage of pre-retirement income. This plan provides a make-whole benefit that compensates for benefits lost due to tax code limits, plus a target benefit that varies based on officer service. The target benefit ensures that upon reaching 25 years of service, total retirement benefits will equal a target percentage of final average compensation. The target benefit is available to those reaching age 60 with five years of employment with NU. Mr. Butler is (and Mr. Shivery was, upon retirement) eligible for a 60% percent target benefit. Mr. McHale (whose officer service began later) is eligible for a 50 percent target benefit.
Mr. Olivier’s employment agreement provides retirement benefits similar to those of a previous employer instead of the Supplemental Plan benefits described above. Under this agreement, he will receive a pension based on a prescribed formula if he meets certain eligibility requirements. Mr. Shivery’s employment agreement provided for a special retirement benefit determined using the Supplemental Plan target benefit formula plus three years of service. Messrs. McHale, Olivier and Butler are also eligible to receive certain taxable health and welfare benefits in certain circumstances. Mr. Muntz’s employment agreement includes, depending on his age at termination of employment, a special annual retirement benefit calculated using certain service credits and offset amounts.
Retirement Benefits for certain legacy NSTAR employees, including Messrs. May and Judge. NU offers certain legacy NSTAR employees, including Messrs. May and Judge, the opportunity to participate in the NSTAR qualified defined benefit pension plan. This is a final average pay plan subject to tax code limits. Because of such limits, NU also maintains two supplemental non-qualified programs for these and certain other executives. The plans make up for benefits barred by such limits and provide (together with the qualified pension plan) benefits for vested participants equal to 60 percent of pre-retirement compensation (reduced by the value of 50 percent of primary Social Security benefits). Benefits are based on base salary and annual cash incentive payments, which is consistent with the goal of providing a retirement benefit that replaces a percentage of pre-retirement income.
See the narrative accompanying the "Pension Benefits" table and accompanying notes for more detail on the above plans.
401K Plan
401(k) Plan Benefits for certain legacy NU employees, including Messrs. Shivery, McHale, Olivier, Butler and Muntz. NU provides the Northeast Utilities qualified 401(k) savings plan for eligible legacy NU employees, including Messrs. Shivery, McHale, Olivier, Butler and Muntz. Under this plan, NU matches up to 3 percent of base salary, one-third of which match is made in cash available for investment in various fund alternatives, and two-thirds of which is made in common shares (ESOP shares), subject to tax code limits.
401(k) Plan Benefits for certain legacy NSTAR employees, including Messrs. May and Judge. NU provides the NSTAR qualified 401(k) savings plan for certain eligible legacy NSTAR employees, including Messrs. May and Judge. Under this plan, NU matches 50 percent of the first 8 percent of eligible base salary and annual cash incentive contributed, subject to tax code limits.
Deferred Compensation
Deferred Compensation Plan Benefits for certain legacy NU executives, including Messrs. Shivery, McHale, Olivier, Butler and Muntz. NU maintains an unfunded non-qualified deferred compensation plan for certain legacy NU executives, including Messrs. Shivery, McHale, Olivier, Butler and Muntz. This plan permits deferral of up to 100 percent of base salary and annual incentives, which may be invested in the same deemed investments as the qualified plan (except Company shares). NU matches deferrals up to a maximum of 3 percent of base salary in excess of the tax code limit of $250,000. The match is deemed invested in NU common shares and generally vests in three years.
Deferred Compensation Plan Benefits for certain legacy NSTAR executives, including Messrs. May and Judge. NU maintains a non-qualified deferred compensation plan for eligible legacy NSTAR executives, including Messrs. May and Judge. This plan permits deferral of up to 50 percent of base salary and all annual incentive payments and stock incentive awards. Participants may establish
investment measurements based on a wide range of publicly available individual securities and mutual funds. The Company maintains a Rabbi Trust and replicates all investment elections with actual investments.
See the Non-qualified Deferred Compensation Table and accompanying notes for additional details on the above plans.
Perquisites
NU provides financial planning, health services, vehicle leasing, access to tickets to sporting events and limited perquisites that it believes are consistent with peer companies. The current level of perquisites does not factor into decisions on total compensation.
CONTRACTUAL AGREEMENTS
NU maintains contractual agreements with all of the Named Executive Officers that provide for potential compensation in the event of certain terminations following a Change in Control. The agreements are consistent with general industry practice, and NU believes they are necessary to attract and retain high quality executives and to ensure executive focus on NU’s business during the period leading up to a potential Change in Control. With respect to the "double-trigger" agreements allowing voluntary termination for "good reason," NU believes this form of agreement provides executives with compensation in the event of a Change in Control, while still providing an incentive to remain employed for the transition period that follows.
Our agreements with Messrs. McHale, Olivier, Butler and Muntz provide for compensation in the event of a Change in Control followed by involuntary termination of employment (other than for cause) or voluntary termination for "good reason" during the applicable period. The 2012 merger did not constitute a change in control under the agreements with Messrs. Butler and McHale. Mr. Shivery’s change of control provisions expired in 2011 when he reached age 65, and he retired in 2012. These agreements are described more fully below under "Potential Payments Upon Termination or Change in Control."
For Messrs. May and Judge and other eligible legacy NSTAR executives, NU maintains Change in Control agreements. Severance benefits are payable if, within 24 months following a change in control, the executive is involuntarily terminated (other than for cause) or voluntarily terminates employment for "good reason." These agreements are described more fully below under "Potential Payments upon Termination or Change in Control."
SHARE OWNERSHIP GUIDELINES
On January 10, 2013, the Committee approved revised share ownership guidelines to further emphasize the importance of share ownership by certain executive officers. The guidelines call for NU’s Chief Executive Officer to own common shares equal to six times base salary, the other senior executive officers to own a number of common shares equal to three times base salary and all other officers to own a number of common shares equal to one to two times base salary.
NU requires that executive officers attain these ownership levels within five years. All executive officers, including the Named Executive Officers, have satisfied the share ownership guidelines or are expected to satisfy them within the applicable timeframe. Common shares, whether held of record, in street name, or in individual 401(k) accounts, and RSUs satisfy the guidelines. Unexercised stock options and unvested performance shares do not count toward the ownership guidelines.
TAX AND ACCOUNTING CONSIDERATIONS
NU’s annual and long-term incentive plans were approved by shareholders and 2012 annual incentive and performance share awards under those plans were structured to qualify as performance-based compensation under Section 162(m) of the Internal Revenue Code. However, NU believes that the availability of a tax deduction for other forms of compensation is secondary to the goal of providing market-based compensation to attract and retain highly qualified executives. In addition, NU’s compensation program plans were amended in 2008 to comply with Section 409A of the Internal Revenue Code.
NU has adopted the provisions of Financial Accounting Standards Board (FASB) Accounting Standards Codification (ASC) Topic 718, Compensation-Stock Compensation. In general, NU and the Committee do not take accounting considerations into account in structuring compensation arrangements.
EQUITY GRANT PRACTICES
Equity awards noted in the compensation tables are made at the February meeting of the Compensation Committee (subject to the further approval of the Board of Trustees of the Chief Executive Officer’s award) when the Committee also determines base salary, annual and long term incentive compensation targets and annual incentive awards. The date of this meeting is chosen several months in advance, and therefore awards are not coordinated with the release of material non-public information.
SUMMARY COMPENSATION TABLE
The table below summarizes the total compensation paid or earned by CL&P’s NEOs, consisting of our principal executive officer (Mr. Olivier), principal financial officer (Mr. Judge) and former principal financial officer (Mr. McHale), the three other most highly compensated executive officers serving at the end of 2012 (Messrs. May, Butler and Muntz), and CL&P’s former Chairman, Mr. Shivery, who would have been one of the three other most highly compensated executive officers if he had been serving as CL&P’s Chairman at the end of 2012, determined in accordance with the applicable SEC disclosure rules. The table provides information for 2011 and 2010 if the executive officer was included in the Summary Compensation Table for those years. For Messrs. May and Judge, the disclosure pertains to each of their compensation subsequent to the Merger. 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 behalf for the fiscal year ended December 31, 2012. The compensation shown for each Named Executive Officer was for all services in all capacities to NU and its subsidiaries. All salaries, annual incentive amounts and long-term incentive amounts shown for each Named Executive Officer were paid for all services rendered to NU and its subsidiaries, including CL&P, in all capacities.
(1)
Mr. Shivery retired as President and CEO of NU and Chairman of CL&P upon the completion of the Merger on April 10, 2012. Mr. Shivery currently serves as the non-executive Chairman of the Board of NU. The compensation information for Mr. Shivery includes his compensation as Chairman of the Board of NU for the period from April 10, 2012 through December 31, 2012.
(2)
Messrs. May and Judge became Named Executive Officers for NU and CL&P upon the completion of the Merger on April 10, 2012. They were not executive officers of NU or CL&P in 2011 or 2010. The compensation information for Messrs. May and Judge reflects compensation for the period from April 10, 2012 through December 31, 2012.
(3)
Mr. Muntz did not meet the requirements for inclusion in the Summary Compensation Table and was not a Named Executive Officer for 2011 or 2010. Mr. Muntz became a Named Executive Officer in 2012.
(4)
Includes amounts deferred in 2012 under the Deferral Plan, as follows: Mr. Olivier: $116,608, Mr. Muntz: $274,289, Mr. Shivery: $9,506; Mr. McHale: $9,415. For more information, see the Executive Contributions in the Last Fiscal Year column of the Non-Qualified Deferred Compensation Plans Table.
(5)
No discretionary bonus awards were made to any of the Named Executive Officers in the fiscal years ended 2010, 2011 and 2012.
(6)
Reflects the aggregate grant date fair value of restricted share units (RSUs) and performance shares granted in each fiscal year, calculated in accordance with FASB ASC Topic 718.
In 2010, 2011 and 2012, certain Named Executive Officers were granted RSUs that vest in equal annual installments over three years as long-term incentive compensation. NU deferred the distribution of common shares upon vesting of RSUs granted to Mr. Shivery until 2013, the calendar year after the year in which his employment terminated. RSU holders are eligible to receive dividend equivalent units on outstanding RSUs held by them to the same extent that dividends are declared and paid on NU common shares. Dividend equivalent units are accounted for as additional common shares that accrue and are distributed simultaneously with the common shares issued upon vesting of the underlying RSUs.
In 2012, certain Named Executive Officers were granted performance shares as long-term compensation. These performance shares would have vested on December 31, 2014, based on the extent to which four performance conditions would have been achieved. The grant date values for the performance shares, assuming achievement of the highest level of all four performance conditions, were as follows: Mr. Shivery: $3,650,993; Mr. McHale: $950,257; Mr. Olivier: $1,000,303; Mr. Butler: $741,642; and Mr. Muntz: $482,667. However, as previously approved by the Committee, on April 10, 2012, upon completion of the Merger, all performance shares outstanding under the 2012 - 2014 program were converted to RSUs assuming a target level of performance. These RSUs generally vest according to the schedule that applies to the RSU component already granted as part of the 2012 - 2014 program, except that a portion of Mr. Shivery’s RSUs vested upon his retirement pro rata based on 2012 employee service (and the remaining RSUs were forfeited): Mr. Shivery: 70,294 RSUs; Mr. McHale: 18,296 RSUs; Mr. Olivier: 19,259 RSUs; Mr. Butler: 14,279 RSUs; and Mr. Muntz: 9,293 RSUs.
(7)
NU did not grant stock options to any of the Named Executive Officers in 2012. NU has not granted any stock options since 2002.
(8)
Includes payments to the Named Executive Officers under the 2012 Annual Incentive Program (Mr. Shivery: $570,393; Mr. May; $2,100,000; Mr. McHale: $640,000; Mr. Judge; $640,000; Mr. Olivier: $660,000; Mr. Butler: $495,000; and Mr. Muntz: $458,300). Also includes performance cash payments under the 2010 - 2012 Long-Term Incentive Program (Mr. Shivery: $1,182,674; Mr. McHale: $299,939; Mr. Olivier: $314,236; Mr. Butler: $232,534; and Mr. Muntz: $152,343). In April 2012, upon completion of the Merger, the achievement of goals applicable to performance units in the 2010 - 2012 program was measured up to the completion of the Merger.
(9)
Includes the actuarial increase in the present value from December 31, 2011 to December 31, 2012 of the Named Executive Officer’s accumulated benefits under all of the defined benefit pension plans determined using interest rate and mortality rate assumptions consistent with those appearing under the caption entitled "Management’s Discussion and Analysis and Results of Operations" in this Annual Report on Form 10-K. The Named Executive Officer may not be fully vested in such amounts. 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 in 2012.
(10)
Includes matching contributions of $7,500 allocated by us to the account of each of the Named Executive Officers under the 401k Plan; and employer matching contributions under the Deferral Plan for the Named Executive Officers who made deferral elections in late 2011 for salary earned in 2012 (Mr. Olivier: $9,991; Mr. Muntz: $5,159; Mr. Shivery: $2,006; and Mr. McHale: $9,115). Mr. Butler did not participate in the Deferral Plan in 2012. For Mr. May, the value shown includes $58,742 attributable to a previously granted $6.155 million present value life insurance benefit; financial planning services valued at $6,400; health services valued at $6,400; and $8,779 paid by the Company for Company-leased vehicles. These perquisites are made available to senior executives, however, none of the other Named Executive Officer received perquisites valued in the aggregate in excess of $10,000.
GRANTS OF PLAN-BASED AWARDS DURING 2012
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, 2012. The table also discloses the underlying stock awards and the grant date for equity-based awards. NU has not granted any stock options since 2002.
(1)
Reflects the number of performance shares granted to each of the Named Executive Officers on February 14, 2012 under the 2012 - 2014 Long-Term Incentive Program. Performance shares were granted with a three-year Performance Period that would have ended on December 31, 2014. However, upon the completion of the Merger, all performance shares outstanding under the 2012 - 2014 program were converted to RSUs assuming a target level of performance. These RSUs will vest according to the schedule that applies to the RSU component already granted as part of the 2012 - 2014 program. For Mr. Shivery, a pro rata portion of his converted RSUs (based on 2012 employee service) vested upon his retirement, and his remaining converted RSUs were forfeited.
(2)
Reflects the number of RSUs granted to each of the Named Executive Officers on February 14, 2012 under the 2012 - 2014 Long-Term Incentive Program. RSUs generally vest in equal installments on February 25, 2013, 2014 and 2015. NU will distribute common shares in respect to vested RSUs on a one-for-one basis immediately upon vesting, after reduction for applicable withholding taxes, except for Mr. Shivery. For Mr. Shivery, a portion of his RSUs under this Program vested pro rata (based on 2012 employee service) and the remaining RSUs were forfeited. Accordingly, Mr. Shivery became entitled to a distribution of such common shares (after reduction for applicable withholding taxes) in respect of vested RSUs in three approximately equal annual installments beginning in January 2013 (January of the calendar year after he retired). Holders of RSUs are eligible to receive dividend equivalent units on outstanding RSUs held by them to the same extent that dividends are declared and paid on NU common shares. Dividend equivalent units are accounted for as additional common shares that accrue and are distributed simultaneously with the common shares distributed in respect of the underlying RSUs. The Annual Incentive Program does not include an equity component.
(3)
Reflects the grant-date fair value, determined in accordance with FASB ASC Topic 718, of: (i) RSUs and performance shares granted to the Named Executive Officers on February 14, 2012, under the 2012 - 2014 Long-Term Incentive Program. The Annual Incentive Program does not include an equity component.
(4)
Amounts reflect the range of potential payouts, if any, under the 2012 Annual Incentive Program for each Named Executive Officer, as described in the Compensation Discussion and Analysis. The payment in 2013 for performance in 2012 is set forth in the Non-Equity Incentive Plan Compensation column of the Summary Compensation Table. The threshold payment under
the Annual Incentive Program is 50 percent of target. However, based on Adjusted Net Income and individual performance, the actual payment under the Annual Incentive Program could be zero.
(5)
Reflects the range of potential payouts, if any, pursuant to performance share awards under the 2012 - 2014 Long-Term Incentive Program, as described in the Compensation Discussion and Analysis.
EQUITY GRANTS OUTSTANDING AT DECEMBER 31, 2012
The following table sets forth option and RSU grants outstanding at the end of our fiscal year ended December 31, 2012 for each of the Named Executive Officers. All outstanding options were fully vested as of December 31, 2012.
(1)
Options held by Messrs. May and Judge were granted by NSTAR prior to the completion of the Merger and assumed by NU upon the completion of the Merger.
(2)
Awards and market values of awards appearing in the table and the accompanying notes have been rounded to whole units.
(3)
An additional 83,573 unvested RSUs vested on February 25, 2013 (Mr. McHale: 25,050; Mr. Olivier: 26,327; Mr. Butler: 19,475; and Mr. Muntz: 12,721). An additional 57,344 unvested RSUs will vest on February 25, 2014 (Mr. McHale: 17,175; Mr. Olivier: 18,077; Mr. Butler: 13,370; and Mr. Muntz: 8,722). An additional 27,893 unvested RSUs will vest on February 25, 2015 (Mr. McHale: 8,349; Mr. Olivier: 8,788; Mr. Butler: 6,516; and Mr. Muntz: 4,240).
In 2011, the NU Board of Trustees approved a special grant of 76,406 RSUs to Mr. Shivery to recognize the critical role he had in the successful leadership of NU through the close of the Merger, and the role he will play as NU’s non-executive Chairman of the Board during the post-merger integration period. These RSUs, plus accrued dividend equivalents, totaled 81,601 RSUs at December 31, 2012. The RSUs will vest eighteen months after the completion of the Merger, coinciding with Mr. Shivery’s commitment to remain as NU’s non-executive Chairman of the Board through that date. If Mr. Shivery dies or becomes disabled prior to the vesting date, then the RSUs will vest as of the date of death or disability. If Mr. Shivery does not serve on the NU Board through eighteen months after the completion of the Merger, then the RSUs will be forfeited.
In connection with the Merger, in November 2010, NU and NSTAR each established retention pools in an aggregate amount of $10 million to be allocated to key employees, including some or all executive officers, to help ensure their continued dedication to each company both before and after completion of the Merger. Awards were in the form of RSUs and generally vest subject to three years of continuous service following completion of the merger. Full payment will also be made if an participating executive dies, becomes disabled, or is terminated by NU without "cause" before the end of the retention period, in which case the retention payment will be reduced by the amount of any cash severance payable to the executive upon or during the year following termination. Awards granted to former NSTAR executive officers were assumed by NU upon the completion of the Merger. An additional 242,853 unvested RSUs granted pursuant to the retention pools will vest subject to three years of continuous service following completion of the Merger (Mr. McHale: 69,012; Mr. Judge: 70,323; Mr. Olivier: 51,759; Mr. Butler: 51,759). Mr. Muntz did not participate in this program.
Mr. Muntz’s total includes 11,210 unvested RSUs from a special grant in 2008.
(4)
The market value of RSUs is determined by multiplying the number of RSUs by $39.08, the closing price per share of NU common shares on December 31, 2012, the last trading day of the year.
OPTIONS EXERCISED AND STOCK VESTED IN 2012
The following table reports amounts realized on equity compensation during the fiscal year ended December 31, 2012. The Stock Awards columns report the vesting of RSU grants to the Named Executive Officers in 2012.
(1)
Represents the amounts realized upon option exercises, which is the difference between the option exercise price and the market price at the time of exercise.
(2)
Includes RSUs granted to the Named Executive Officers under our long-term incentive programs, including dividend reinvestments, as follows:
Name
2009 Program
2010 Program
2011 Program
2012 Program
Charles W. Shivery *
12,567
42,009
104,775
26,367
David R. McHale
3,079
2,727
8,575
-
Leon J. Olivier
3,226
2,856
9,028
-
Gregory B. Butler
2,387
2,113
6,663
-
James A. Muntz
1,564
1,385
4,356
-
*
Mr. Shivery’s unvested RSUs under the 2010 and 2011 Programs fully vested upon his retirement. His unvested RSUs under the 2012 Program vested upon his retirement pro rata based on 2012 employee service (and his remaining RSUs under this program were forfeited).
In all cases, the distribution of common shares is reduced by that number of shares valued in an amount sufficient to satisfy tax withholding obligations, which amount is distributed in cash. 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)
Values realized on vesting for Messrs. Shivery, McHale, Olivier, Butler and Muntz are based on $35.67 per share, the closing price of NU common shares on February 27, 2012. Values realized by Messrs. May and Judge on vesting for awards are based on $36.79 per share, the closing price of NU common shares on April 9, 2012.
PENSION BENEFITS IN 2012
The Pension Benefits Table shows the estimated present value of accumulated retirement benefits payable to each Named Executive Officer upon retirement based on the assumptions described below. The table distinguishes between benefits available under the Retirement Plans, the Supplemental Plans, and any additional benefits available under contractual agreements. See the narrative above in the Compensation Discussion and Analysis under the heading "ELEMENTS OF 2012 COMPENSATION - OTHER- Retirement Benefits" and "ELEMENTS OF 2012 COMPENSATION - CONTRACTUAL AGREEMENTS" for more detail on benefits under these plans and our agreements.
The values shown in the Pension Benefits Table for Messrs. Shivery, McHale, Butler and Muntz were calculated as of December 31, 2012, based on benefit payments in the form of a one-half spousal contingent annuitant option. For Mr. Olivier, NU assumed a lump sum payment of his special retirement benefits under his agreement, and payment of his Retirement Plan benefit as a life annuity with a one-third spousal contingent annuitant option (the typical payment form under that Plan). For Messrs. May and Judge, NU assumed a lump sum payment of benefits.
The values shown in this Table for Messrs. Shivery, McHale, Olivier, Butler and Muntz were based on benefit payments commencing at the earliest possible ages for retirement with unreduced benefits: Mr. Shivery: age 65, Mr. May: age 60, Mr. McHale: age 60, Mr. Judge: age 60, Mr. Olivier: age 60, Mr. Butler: age 62, and Mr. Muntz: age 65.
In addition, NU determined benefits under the Retirement Plans using tax code limits in effect on December 31, 2012. For Messrs. Shivery, McHale, Butler and Muntz, the values shown reflect actual 2012 salary and annual incentives earned in 2012 but paid in 2013 (per applicable Supplemental Plan rules). For Messrs. May and Judge, the values shown reflect actual 2012 salary and annual incentives earned in 2011 but paid in 2012 (per applicable Supplemental Plan rules).
The present value of benefits at retirement age were determined using the discount rate of 4.24 percent (4.13 percent for Messrs. May and Judge) under Statement of Financial Accounting Standards No. 87 for the 2012 fiscal year end measurement (as of December 31, 2012). This present value assumes no pre-retirement mortality, turnover or disability. However, for the postretirement period beginning at retirement age, NU used the RP2000 Combined Healthy mortality table as published by the Society of Actuaries projected to 2012 with projection scale AA (same table used for financial reporting under FAS 87). Additional assumptions appear under the caption entitled "Management’s Discussion and Analysis and Results of Operations" in this Annual Report on Form 10-K.
(1)
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 received a special retirement benefit that provided credit for service with his previous employer, Boston Edison Company (BECO), when calculating the value of his defined benefit pension, offset by the pension benefit provided by BECO. 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 under this benefit was calculated using the actuarial assumptions currently used by the Retirement Plan. Mr. Olivier was rehired by NU from Entergy in September 2001. Mr. Olivier’s current employment agreement provides for certain supplemental pension benefits in lieu of benefits under the Supplemental Plan, in order to provide a benefit similar to that provided by Entergy. Under this arrangement, Mr. Olivier became eligible during 2011 to receive a special benefit, subject to reduction for termination prior to age 65, consisting 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 NU, he is eligible to 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. Amounts reported in the table assume the termination of his employment with NU’s consent on December 31, 2012, and payment of the lump sum benefit of $3,214,047 offset by Retirement Plan benefits.
(2)
Mr. Muntz’s actual service with NU totaled 11 years at December 31, 2012. However, Mr. Muntz’s employment agreement provides that upon reaching age 55 (which occurred in December 2012), he is entitled to a special annual retirement benefit in the event his employment terminates for any reason other than for cause. This special annual benefit confers credit upon
Mr. Muntz for 21 years of service with his previous employer, Exelon Corporation (Exelon), when calculating his pension, and offsets the resulting benefit by: (i) an amount approximating his annual Exelon pension benefit, and (ii) the benefit otherwise payable from the Retirement and Supplemental Plans excluding such additional service credit. This special annual benefit provides for an annuity payable at the same time and in the same form as his Retirement or Supplemental Plan benefit (as applicable).
NONQUALIFIED DEFERRED COMPENSATION IN 2012
See the narrative above in the Compensation Discussion and Analysis under the heading “ELEMENTS OF 2012 COMPENSATION - OTHER- Deferred Compensation” for more detail on our non-qualified deferred compensation plans.
(1)
Includes deferrals under the Deferral Plans (Mr. Shivery: $6,554,466; Mr. McHale: $9,415; Mr. Olivier: $116,608; and Mr. Muntz: $274,289). Named Executive Officers who participate in the Deferral Plans are provided with a variety of investment opportunities, which the individual can modify and reallocate at any time. Contributions by the Named Executive Officer are vested at all times; however, the applicable employer matching contribution vests after three years and will be forfeited if the executive’s employment terminates, other than for retirement, death or disability, prior to vesting, but will become fully vested upon a change of control. The amounts reported in this column for each Named Executive Officer are reflected as compensation to such Named Executive Officer in the Summary Compensation Table.
With respect to Mr. Shivery, other amounts relate to the value of RSUs automatically deferred under the terms of our long-term incentive programs, calculated using the closing prices of NU common shares on the applicable February 27 and April 10, 2012 vesting dates ($35.67 per share and $35.91 per share, respectively). For more information, see the footnotes to the Options Exercised and Stock Vested table.
(2)
Includes employer matching contributions made to the applicable Deferral Plan as of December 31, 2012 and posted on January 31, 2012, as reported in the All Other Compensation column of the Summary Compensation Table, except for Mr. Shivery, who received matching contributions through his retirement date (April 10, 2012): (Mr. Shivery: $24,824; Mr. McHale: $9,115; Mr. Olivier: $9,091; and Mr. Muntz: $5,159). The employer matching contribution is deemed to be invested in common shares but is paid in cash at the time of distribution.
(3)
Includes distributions to under the applicable Deferral Plan during fiscal year 2012 pursuant to their deferral elections, plus the value of previously vested deferred RSUs or other awards distributed in 2012 pursuant to deferral schedules, valued for Mr. Shivery at the closing price of NU common shares on his October 12, 2012 distribution date ($38.68 per share).
(4)
Includes the total market value of Deferral Plan balances at December 31, 2012, plus the value of vested RSUs or other awards for which the distribution of common shares is currently deferred, based on $39.08, the closing price of NU common shares on December 31, 2012, the last trading day of the year. The aggregate balances reflect a significant level of earnings on previously earned and deferred compensation.
POTENTIAL PAYMENTS UPON TERMINATION OR CHANGE OF CONTROL
Generally, a "change of control" means a change in ownership or control of NU effected through (i) the acquisition of 20 percent or more of the combined voting power of common shares or other voting securities (30 percent for Messrs. May and Judge, excluding certain defined transactions), (ii) the acquisition of more than 50 percent of common shares excluding certain defined transactions (for Messrs. May and Judge), (iii) a change in the majority of NU’s Board of Trustees, unless approved by a majority of the incumbent Trustees, (iv) certain reorganizations, mergers or consolidations where substantially all of the persons who were the beneficial owners of the outstanding common shares immediately prior to such business combination do not beneficially own more than 50 percent (75 percent for Mr. Olivier and Muntz) of the voting power of the resulting business entity (excluding in certain cases defined transactions), and (v) complete liquidation or dissolution of NU, or a sale or disposition of all or substantially all of the assets of NU other than, for Messrs.
McHale and Butler, to an entity with respect to which following completion of the transaction more than 50 percent (75 percent for Messrs. Olivier and Muntz) of common shares or other voting securities is then owned by all or substantially all of the persons who were the beneficial owners of common shares and other voting securities immediately prior to such transaction.
In the event of a change of control, the Named Executive Officers are generally entitled to receive compensation and benefits following either involuntary termination of employment without "cause" or voluntary termination of employment for "good reason" within the applicable period (generally two years following change of control or shareholder approval thereof). The Committee believes that termination for good reason is conceptually the same as termination "without cause" and, in the absence of this provision, potential acquirers would have an incentive to constructively terminate executives to avoid paying severance. Termination for "cause" generally means termination due to a felony or certain other convictions; fraud, embezzlement, or theft in the course of employment; intentional, wrongful damage to company property; gross misconduct or gross negligence in the course of employment or gross neglect of duties harmful to the company; or a material breach of obligations under the agreement. "Good reason" for termination generally exists after assignment of duties inconsistent with executive’s position, a material reduction in compensation or benefits, a transfer more than 50 miles from the executive’s pre-change of control principal business location (or for Messrs. May and Judge, a transfer outside the Greater Boston Metropolitan Area), or requiring business travel to a substantially greater extent than required pre-change of control (for Messrs. May and Judge).
The discussion and tables below show compensation payable to each Named Executive Officer, except for Mr. Shivery, in the event of: (i) termination for cause; (ii) voluntary termination; (iii) involuntary not-for-cause termination; (iv) termination in the event of disability; (v) death; and (vi) termination following change of control. The amounts shown assume that each termination was effective as of December 31, 2012, the last business day of the fiscal year as required under SEC reporting requirements.
The summaries above do not purport to be complete and are qualified in their entirety by the actual terms and provisions of the agreements and plans, copies of which have been filed as exhibits to this Annual Report on Form 10-K.
Payments Upon Termination
Regardless of the manner in which the employment of a Named Executive Officer terminates, he is entitled to receive certain amounts earned during his term of employment. Such amounts include:
·
Vested RSUs and certain other vested awards;
·
Amounts contributed and any vested matching contributions under the Deferral Plans;
·
Pay for unused vacation; and
·
Amounts accrued and vested under the Retirement, Supplemental and 401k Plans (except in the event of a termination for cause under the Supplemental Plans).
As a result, we do not include these amounts in the tables.
See the section above captioned “PENSION BENEFITS IN 2012” for information about the Retirement Plans, the Supplemental Plans and Other Special Benefits, and the section captioned “NONQUALIFIED DEFERRED COMPENSATION IN 2012.”
I.
Post-Employment Compensation: Termination for Cause
(1)
Represents actuarial present values at year-end 2012 of amounts payable solely under Mr. Olivier’s employment agreement upon termination (which are in addition to amounts due under the Retirement and Supplemental Plans). Under Mr. Olivier’s agreement, he would receive upon termination a lump sum payment of $2,050,000, offset by the value of Retirement Plan benefits.
II.
Post-Employment Compensation: Voluntary Termination
(1)
Represents actual 2012 annual incentive awards, determined as described in the Compensation Discussion and Analysis.
(2)
Represents actual performance cash awards under the 2010 - 2012 Long-Term Incentive Program for Messrs. McHale, Olivier, Butler and Muntz.
(3)
Represents actual performance share awards under the 2010 - 2012 Long-Term Incentive Program for Messrs. McHale, Olivier, Butler and Muntz.
(4)
Represents values of RSUs granted to Messrs. Olivier, Butler and Muntz under the NU long-term incentive programs that, at year-end 2012, were unvested under applicable vesting schedules. Under these programs, RSUs vest pro rata based on credited service years and age at termination, and time worked during the vesting period. The values were calculated by multiplying the number of RSUs by $39.08, the closing price of NU common shares on December 31, 2012, the last trading day of the year. Excludes retention pool RSU grants, which would not vest upon voluntary termination.
(5)
Represents actuarial present values at year-end 2012 of amounts payable solely under employment agreements (which are in addition to amounts due under the Retirement and Supplemental Plans). Under Mr. Olivier’s agreement, he would receive a lump sum payment of $2,050,000, offset by the value of Retirement Plan benefits. Amounts shown are year-end 2012 present values payable upon termination.
III.
Post-Employment Compensation: Involuntary Termination, Not for Cause
(1)
Represents actual 2012 Named Executive Officer annual incentive awards, determined as described in the Compensation Discussion and Analysis.
(2)
Represents actual performance cash awards under the 2010 - 2012 Long-Term Incentive Program for Messrs. McHale, Olivier, Butler and Muntz.
(3)
Represents actual performance share awards under the 2010-2012 Long-Term Incentive Program for Messrs. McHale, Olivier, Butler and Muntz.
(4)
Represents values of RSUs under the NU long-term incentive programs that, at year-end 2012, were unvested under applicable vesting schedules. Under these programs, RSUs vest pro rata based on credited service years and age at termination, and time worked during the vesting period. Under the retention program, RSUs vest fully upon termination without cause and the value is reduced by separation payments. The values were calculated by multiplying the number of RSUs by $39.08, the closing price of NU common shares on December 31, 2012, the last trading day of the year.
(5)
Represents actuarial present values at year-end 2012 of amounts payable solely under employment agreements upon termination (which are in addition to amounts due under the Retirement and Supplemental Plans). Mr. Olivier’s agreement provides for a lump sum payment of $3,101,153 offset by the value of Retirement Plan benefits. Agreements with Messrs. McHale and Butler provide for two years age and service credit under the Supplemental Plan.
(6)
Represents value of Company matching contributions under the Deferral Plans that were unvested under applicable vesting schedules (other amounts in the Deferral Plans represent previously vested Company matching contributions, where applicable, and earned compensation contributed by executives).
(7)
Represents estimated cost to NU at year-end 2012 of providing post-employment welfare benefits beyond those available to non-executives upon involuntary termination. The amount reported in the table for Messrs. McHale and Butler represents (a) the value of two years employer contributions toward active health, long-term disability, and life insurance benefits, plus (b)a payment to offset any taxes thereon (gross-up).
(8)
Represents the cost to NU of reimbursing Messrs. McHale and Butler for two years of financial planning and tax preparation fees.
(9)
Represents consideration for agreements not to compete with NU following termination. Employment agreements with these executives provide for a lump-sum payment equal to the sum of their base salary plus annual incentive award. These payments do not replace, offset or otherwise affect the calculation or payment of the annual incentive awards.
(10)
Represents severance payments in addition to any non-compete agreement payments described in the prior note.
IV.
Post-Employment Compensation: Termination Upon Disability
(1)
Represents actual 2012 Named Executive Officer annual incentive awards, determined as described in the Compensation Discussion and Analysis.
(2)
Represents actual performance cash awards under the 2010 - 2012 Long-Term Incentive Program for Messrs. McHale, Olivier, Butler and Muntz.
(3)
Represents actual performance share awards under the 2010-2012 Long-Term Incentive Program for Messrs. McHale, Olivier, Butler and Muntz.
(4)
Represents values of RSUs and other awards under the NU long-term incentive programs and retention awards that, at year-end 2012, were unvested under applicable vesting schedules. Under these programs and awards, upon termination due to disability, awards vest in full or on a prorated basis based on credited service years and age at termination, and time worked during the vesting period. The values were calculated by multiplying the number of RSUs by $39.08, the closing price of NU common shares on December 31, 2012, the last trading day of the year.
(5)
Represents the actuarial present values at the end of 2012 of the amounts payable solely as the result of employment agreements upon termination (which are in addition to amounts payable under the Retirement and Supplemental Plans). Under Mr. Olivier’s agreement, a disability termination results in a lump sum payment of $3,101,153, offset by the value of Retirement Plan benefits.
(6)
Represents value of NU matching contributions under the Deferral Plans that were unvested under applicable vesting schedules (other amounts in the Deferral Plans represent previously vested NU matching contributions, where applicable, and earned compensation contributed by executives).
V.
Post-Employment Compensation: Death
(1)
Represents actual 2012 Named Executive Officer annual incentive awards, determined as described in the Compensation Discussion and Analysis.
(2)
Represents actual performance cash awards under the 2010 - 2012 Long-Term Incentive Program for Messrs. McHale, Olivier, Butler and Muntz.
(3)
Represents actual performance share awards under the 2010-2012 Long-Term Incentive Program for Messrs. McHale, Olivier, Butler and Muntz.
(4)
Represents values of RSUs and other awards under the NU long-term incentive programs and retention awards that, at year-end 2012, were unvested under applicable vesting schedules. Under these programs and awards, upon termination due to death, awards vest in full or on a prorated basis based on credited service years and age at termination, and time worked during the vesting period. The values were calculated by multiplying the number of RSUs by $39.08, the closing price of NU common shares on December 31, 2012, the last trading day of the year.
(5)
Represents the actuarial present values at the end of 2012 of the amounts payable to a surviving spouse solely under agreements (which are in addition to amounts due under the Retirement and Supplemental Plans). Under Mr. Olivier’s agreement, this benefit would be a lump sum payment of $3,214,047, offset by the value of Retirement Plan benefits. Under Mr. Muntz’s agreement, a lump sum payment (calculated as described in the Pension Benefits Table) would be payable to his estate upon death. Pension amounts shown in the table are year-end 2012 present values of benefits immediately payable to the spouse or estate.
(6)
Represents value of NU matching contributions under the Deferral Plans that were unvested under applicable vesting schedules (other amounts in the Deferral Plans represent previously vested NU matching contributions, where applicable, and earned compensation contributed by executives).
Payments Made Upon a Change of Control
The agreements with Messrs. May, McHale, Judge, and Butler a include change of control benefits. Messrs. Olivier and Muntz participate in the Special Severance Program for Officers (SSP), which also provides change of control benefits. The agreements and the SSP are binding on NU and on certain of its majority-owned subsidiaries, including CL&P.
Pursuant to the agreements and the SSP, if an involuntary non-"cause" termination of employment occurs following a change of control (see definition of "cause" above under the heading of "POTENTIAL PAYMENTS UPON TERMINATION OR CHANGE OF CONTROL"), or in the event of a voluntary termination for "good reason" (as described above under such heading), then the Named Executive Officers generally will receive the benefits listed below:
·
For Messrs. McHale and Butler, a lump sum severance payment of two-times (one-times for Messrs. Olivier and Muntz, three-times for Messrs. May and Judge) the sum of the executive’s base salary plus annual incentive award for the relevant year (Base Compensation), plus for Messrs. McHale and Butler consideration for two year non-compete and non-solicitation covenants (one year covenants for Messrs. Olivier and Muntz) in the form of a lump sum payment equal to Base Compensation;
·
Three years health benefits continuation (two years for Messrs. Olivier and Muntz);
·
For Messrs. McHale and Butler, three years additional age and service credit under the applicable Supplemental Plans (a lump sum payment equal to the value of such credit under those and the applicable qualified pension plan for Messrs. May and Judge);
·
Automatic vesting and distribution of long-term performance awards (with performance units vesting at target) and certain other awards; and
·
A lump sum equal to any excise taxes incurred under the Internal Revenue Code due to receipt of change of control payments, plus an amount to offset any taxes incurred on such payments (gross-up), except for Messrs. Olivier and Muntz. (NU has discontinued the practice of providing such gross-up payments in contractual agreements for newly elected executives.)
With respect to the NSTAR merger, no compensation or benefits were payable to Mr. Shivery because his change of control provisions expired in 2011 when he reached age 65, and he retired in 2012. For Messrs. McHale and Butler, the NSTAR merger did not constitute a change of control under their agreements. For Messrs. Olivier and Muntz, no compensation or benefits will be payable unless employment terminates during the applicable change of control period in the circumstances described below. For Messrs. May and Judge, under the terms of the NSTAR Long-Term Incentive Plan and their agreements, unvested 2010 NSTAR long-term performance awards immediately vested upon completion of the merger and automatically were converted to NU awards of equivalent economic value and terms (2011 and 2012 awards were converted but remained unvested and subject to their original vesting terms). No other benefits will be payable to these executives unless employment terminates during the applicable period in the circumstances described below.
The above summaries do not purport to be complete and are qualified in their entirety by the actual terms and provisions of the agreements and plans, copies of which have been filed as exhibits to this Annual Report on Form 10-K.
VI.
Post-Employment Compensation: Termination Following a Change of Control
(1)
Represents actual 2012 annual incentive awards, determined as described in the Compensation Discussion and Analysis.
(2)
Represents actual performance cash awards under the 2010 - 2012 Long-Term Incentive Program for Messrs. McHale, Olivier, Butler and Muntz.
(3)
Represents actual performance share awards under the 2010 - 2012 Long-Term Incentive Program for Messrs. McHale, Olivier, Butler and Muntz.
(4)
Represents values of RSUs and other awards under the NU long-term incentive programs and retention awards that, at year-end 2012, were unvested under applicable vesting schedules. Under these programs, upon termination in certain cases without cause or for good reason following a change of control, awards generally vest in full. Retention awards vest in full in such circumstances, and the payout value is reduced by any separation payments as described in the notes below. For Messrs. McHale, Judge, Olivier, and Butler, retention program grants are fully eliminated when offset by separation payments.
The values were calculated by multiplying the number of shares subject to awards by $39.08, the closing price of NU common shares on December 31, 2012, the last trading day of the year.
(5)
Represents actuarial present value at year-end 2012 of amounts payable solely under of agreements (which are in addition to amounts payable under the Retirement and Supplemental Plans). For Messrs. May, McHale, Judge and Butler, pension benefits were calculated by adding three years of service (and a lump sum of this benefit value is payable to Messrs. May, Judge and Butler). Mr. Olivier’s agreement provides for a lump sum payment of $3,101,153, offset by his Retirement Plan benefit value. Pension amounts shown in the table are present values at year-end 2012 of benefits payable upon termination as described with respect to the Pension Benefits Table above.
(6)
Represents value of NU matching contributions under the Deferral Plans that were unvested under applicable vesting schedules (other amounts in the Deferral Plans represent previously vested NU matching contributions, where applicable, and earned compensation contributed by executives).
(7)
Represents the cost to NU at year-end 2012 (estimated by our benefits consultants) of providing post-employment welfare benefits to Named Executive Officers beyond those benefits provided to non-executives upon involuntary termination. The amounts shown in the table for Messrs. McHale and Butler represent (a) the value of three years employer contributions toward active health, long-term disability, and life insurance benefits, plus (b) a payment to offset any taxes on the value of these benefits (gross-up), less (c) the value of one year retiree health coverage at retiree rates. The amounts reported in the table for Messrs. Olivier and Muntz represent (a) the value of two years employer contributions toward active health benefits, plus (b) a payment to offset any taxes on the value of these benefits (gross-up), less (c) the value of two years retiree health coverage at retiree rates. For Messrs. May and Judge, amounts represent the value of three years continued welfare plan participation.
(8)
Represents cost of reimbursing financial planning and tax preparation fees for three years.
(9)
Represents payments made to offset costs to Messrs. McHale and Butler associated with certain excise taxes under Section 280G of the Internal Revenue Code. Executives may be subject to certain excise taxes under Section 280G if they receive payments and benefits related to a termination following a Change of Control that exceed specified Internal Revenue Service limits. Contractual agreements with the above executives provide for a grossed-up reimbursement of these excise taxes. The amounts in the table are based on the Section 280G excise tax rate of 20 percent, the statutory federal income tax withholding rate of 35 percent, the Connecticut state income tax rate of 6.5 percent, and the Medicare tax rate of 1.45 percent.
(10)
Represents payments made under agreements or the SSP as consideration for agreement not to compete with NU following termination of employment equal to the sum of base salary plus relevant annual incentive award. These payments do not replace, offset or otherwise affect the calculation or payment of the annual incentive awards.
(11)
Represents severance payments in addition to any non-compete agreement payments described in the prior note. For Messrs. McHale, and Butler, this payment equals two-times the sum of base salary plus relevant annual incentive award (one-times the sum for Messrs. Olivier and Muntz, three-times the sum for Messrs. May and Judge). These payments do not replace, offset or otherwise affect the calculation or payment of the annual incentive awards.
Charles W. Shivery
The following table sets forth the payments that Charles W. Shivery, NU’s former President and Chief Executive Officer and CL&P’s former Chairman, became entitled to receive due to his retirement on April 10, 2012.
Post-Employment Compensation: Charles W. Shivery
(1)
Represents the payout Mr. Shivery became eligible to receive under the 2012 Annual Incentive Program.
(2)
Consists of the value of unvested RSUs that vested upon Mr. Shivery’s retirement under the 2010 - 2012 Long-Term Incentive Program, the 2011 - 2013 Long-Term Incentive Program and the 2012 - 2014 Long-Term Incentive Program. Under the 2012 - 2014 Program, 25,678 RSUs vested pro rata based on 2012 employee service and the remaining unvested RSUs were
forfeited. The value realized on vesting is based on $35.91 per share, the closing price of NU common shares on April 10, 2012.
All of these RSUs were previously awarded to Mr. Shivery based on his service as President and Chief Executive Officer of NU and Chairman of the Regulated companies, including CL&P, prior to retiring in 2012.
On October 12, 2012, NU distributed to Mr. Shivery 19,753 of his vested RSUs under the 2010 - 2012 Long-Term Incentive program (19,753 RSUs) following a six-month delay required for deferred compensation paid to “key employees” under Section 409A of the Internal Revenue Code, and withheld 8,238 shares to satisfy Mr. Shivery’s tax obligations. Mr. Shivery realized $778,867 in ordinary income as a result of this transaction. Pursuant to previously established deferral schedules, Mr. Shivery’s remaining RSUs became distributable in installments in January of 2013, 2014 and 2015.
(3)
Pension values are the total accrued pension benefit payable as an annuity that pays 75 percent to his surviving spouse. At the time of his retirement, Mr. Shivery began receiving his qualified retirement benefit. In compliance with Section 409A of the Internal Revenue Code, the start of Mr. Shivery’s Supplemental Executive Retirement Plan (SERP) payments was delayed until six months after his retirement. On November 1, 2012, NU paid six-months of Mr. Shivery’s SERP “target” benefit $418,024. Mr. Shivery’s monthly SERP “target” benefits are $68,655. Assumptions used in the calculation of this benefit are further discussed with respect to the Pension Benefits table.
(4)
Under the Retirement Plan, Mr. Shivery became eligible to receive health benefits upon retirement. Mr. Shivery did not receive any health and welfare benefits in excess of the benefits offered to all employees.
Item 12.
Item 12.
Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters
NU
In addition to the information below under "Securities Authorized for Issuance Under Equity Compensation Plans," incorporated herein by reference is the information contained in the sections "Common Share Ownership of Certain Beneficial Owners" and "Common Share Ownership of Trustees and Management" of NU’s definitive proxy statement for solicitation of proxies, expected to be filed with the SEC on or about March 21, 2013.
NSTAR ELECTRIC, PSNH and WMECO
Certain information required by this Item 12 has been omitted for NSTAR Electric, PSNH and WMECO pursuant to Instruction I(2)(c) to Form 10-K, Omission of Information by Certain Wholly-Owned Subsidiaries.
CL&P
COMMON SHARE OWNERSHIP OF DIRECTORS AND MANAGEMENT
NU owns 100 percent of the outstanding common stock of CL&P. The table below shows the number of NU’s common shares beneficially owned as of February 15, 2013, by each of CL&P’s directors and each Named Executive Officer of CL&P, as well as the number of common shares beneficially owned by all of CL&P’s directors and executive officers as a group. The table also includes information about options, restricted share units and deferred shares credited to the accounts of CL&P’s directors and executive officers under certain compensation and benefit plans. No equity securities of CL&P are owned by any of the Trustees, directors or executive officers of NU or CL&P. The address for the shareholders listed below is c/o Northeast Utilities, Prudential Center, 800 Boylston Street, Boston, Massachusetts 02199 for Messrs. May, Judge and Nolan and Ms. Carmody; c/o Northeast Utilities, 56 Prospect Street, Hartford, Connecticut 06103-2818 for Messrs. Butler, McHale, Muntz, Olivier, and Shivery; and c/o Northeast Utilities, 107 Selden Street, Berlin, Connecticut 06037 for Mr. Herdegen.
*
Less than 1% of Northeast Utilities common shares outstanding.
(1)
The persons named in the table have sole voting and investment power with respect to all shares beneficially owned by each of them, except as note below.
(2)
Includes common shares issuable upon exercise of outstanding stock options exercisable within the 60-day period after February 15, 2013, as follows: Ms. Carmody: 50,512; Mr. May: 1,086,336; and Mr Nolan: 38,923.
Also includes restricted share units, deferred restricted share units and/or deferred shares, including dividend equivalents, as to which none of the individuals has voting or investment power, and phantom common shares, representing employer matching contributions distributable only in cash, held by executive officers who participate in the Northeast Utilities Deferred Compensation Plan for Executives as follows; Mr. Butler: 103,186 shares; Mr. Herdegen: 19,754 ; Mr. McHale: 136,212 shares; Mr. Muntz: 43,356 shares; Mr. Olivier: 124,668 shares; and Mr. Shivery: 366,356 shares. Also includes restricted share units and/or unvested and vested deferred shares, as to which none of the individuals has voting or investment power, held by executive officers who participate in the NSTAR 2007 Long Term Incentive Plan, as follows: Ms. Carmody: 54,405; Mr. Judge 180,961; Mr. May 978,769; and Mr. Nolan: 101,375.
Also includes unvested performance shares reported at target payouts, plus accumulated dividend equivalents, as to which none of the individuals has voting or investment power, as follows: Mr. Butler: 9,100 shares; Ms. Carmody: 4,500; Mr. Herdegen: 3,800 ; Mr. Judge: 13,100; Mr. May 52,000; Mr. McHale: 13,100 shares; Mr. Muntz: 5,600 shares; Mr. Nolan: 5,100 and Mr. Olivier: 13,800 shares. Actual payouts of the performance shares, if any, at the conclusion of relevant performance periods will depend on the extent to which performance goals are satisfied.
(3)
Includes common shares held in the 401(k) Plan in the employer stock ownership plan account over which the holder has sole voting and investment power (Mr. Butler: 3,773 shares; Ms. Carmody: 5,703 shares; Mr. Judge: 21,201 shares; Mr. May 62,144 shares; Mr. McHale: 4,525 shares; Mr. Muntz: 146 shares; Mr. Nolan: 14,707 shares; Mr. Olivier: 2,303 shares; and Mr. Shivery: 2,382 shares).
(4)
Includes common shares held as units in the 401(k) Plan invested in the NU Common Shares Fund over which the holder has sole voting and investment power (Mr. Butler: 466 shares; Mr. McHale: 2,037 shares; Mr. Muntz: 2,005 shares; and Mr. Olivier: 246 shares).
(5)
Includes 52,496 shares owned jointly by Mr. Butler and his spouse with whom he shares voting and investment power.
(6)
Includes 119 shares held by Mr. McHale in the 401(k) Plan TRAESOP/PAYSOP account over which Mr. McHale has sole voting and investment power.
(7)
Includes 4,000 shares owned jointly by Mr. Shivery and his spouse with whom he shares voting and investment power.
(8)
Includes 1,175,771 common shares issuable upon exercise of outstanding stock options exercisable within the 60-day period after February 15, 2013, and 2,245,215 unissued common shares. See note 2.
SECURITIES AUTHORIZED FOR ISSUANCE UNDER EQUITY COMPENSATION PLANS
The following table sets forth the number of NU common shares issuable under NU equity compensation plans, as well as their weighted exercise price, as of December 31, 2012, in accordance with the rules of the SEC:
(a)
Includes 1,545,757 common shares to be issued upon exercise of options, 2,183,319 common shares for distribution of restricted share units, and 150,937 performance shares issuable at target, all pursuant to the terms of our Incentive Plan.
(b)
The weighted-average exercise price in Column (b) does not take into account restricted share units or performance shares, which have no exercise price.
(c)
Includes 857,280 common shares issuable under our Employee Share Purchase Plan II.
(d)
All of our current compensation plans under which equity securities of NU are authorized for issuance have been approved by shareholders of NU or the former shareholders of NSTAR, the predecessor of NSTAR LLC.
Item 13.
Item 13.
Certain Relationships and Related Transactions, and Director Independence
NU
Incorporated herein by reference is the information contained in the sections captioned "Trustee Independence" and "Certain Relationships and Related Transactions" of NU’s definitive proxy statement for solicitation of proxies, expected to be filed with the SEC on or about March 21, 2013.
NSTAR ELECTRIC, PSNH and WMECO
Certain information required by this Item 13 has been omitted for NSTAR Electric, PSNH and WMECO pursuant to Instruction I(2)(c) to Form 10-K, Omission of Information by Certain Wholly-Owned Subsidiaries.
CL&P
NU’s Code of Ethics for Senior Financial Officers applies to the Senior Financial Officers (Chief Executive Officer, Chief Financial Officer and Controller) of NU, CL&P and certain other NU subsidiaries. Under the Code, one’s position as a Senior Financial Officer in the company may not be used to improperly benefit such officer or his or her family or friends. Under the Code, specific activities that may be considered conflicts of interest include, but are not limited to, directly or indirectly acquiring or retaining a significant financial interest in an organization that is a customer, vendor or competitor, or that seeks to do business with the company; serving, without proper safeguards, as an officer or director of, or working or rendering services for an organization that is a customer, vendor or competitor, or that seeks to do business with the company. Waivers of the provisions of the Code of Ethics for Trustees, executive officers or directors must be approved by NU’s Board of Trustees. Any such waivers will be disclosed pursuant to legal requirements.
NU’s Standards of Business Conduct, which applies to all Trustees, directors, officers and employees of NU and its subsidiaries, including CL&P, contains a Conflict of Interest Policy that requires all such individuals to disclose any potential conflicts of interest. Such individuals are expected to discuss their particular situations with management to ensure appropriate steps are in place to avoid a conflict of interest. All disclosures must be reviewed and approved by management to ensure a particular situation does not adversely impact the individual’s primary job and role.
NU’s Related Party Transactions Policy is administered by the Corporate Governance Committee of NU’s Board of Trustees. The Policy generally defines a "Related Party Transaction" as any transaction or series of transactions in which (i) NU or a subsidiary is a participant, (ii) the aggregate amount involved exceeds $120,000 and (iii) any "Related Party" has a direct or indirect material interest. A "Related Party" is defined as any Trustee or nominee for Trustee, any executive officer, any shareholder owning more than 5 percent of NU's total outstanding shares, and any immediate family member of any such person. Management submits to the Corporate Governance Committee for consideration any Related Party Transaction into which NU or a subsidiary proposes to enter. The Corporate Governance Committee recommends to the NU Board of Trustees for approval only those transactions that are in NU’s best interests. If management causes the company to enter into a Related Party Transaction prior to approval by the Corporate Governance Committee, the transaction will be subject to ratification by the NU Board of Trustees. If the NU Board of Trustees determines not to ratify the transaction, then management will make all reasonable efforts to cancel or annul such transaction.
The directors of CL&P are employees of CL&P and/or other subsidiaries of NU, and thus are not considered independent.
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 NU’s definitive proxy statement for solicitation of proxies, expected to be filed with the SEC on or about March 21, 2013.
CL&P, NSTAR ELECTRIC, PSNH and WMECO
Pre-Approval of Services Provided by Principal Auditors
None of CL&P, NSTAR Electric, PSNH or WMECO is subject to the audit committee requirements of the SEC, the national securities exchanges or the national securities associations. CL&P, NSTAR Electric, PSNH and WMECO obtain audit services from the independent auditor engaged by the Audit Committee of NU’s Board of Trustees. NU’s 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 provided that such offices are held by Trustees who are "independent" within the meaning of the Sarbanes-Oxley Act of 2002 and that all such pre-approvals are presented to the NU Audit Committee at the next regularly scheduled meeting of the Committee.
The following relates to fees and services for the entire NU system, including NU, CL&P, NSTAR Electric, PSNH and WMECO.
Fees Paid to Principal Independent Registered Public Accountants
Northeast Utilities and its subsidiaries paid Deloitte & Touche LLP fees aggregating $4,459,500 and $4,366,359 for the years ended December 31, 2012 and 2011, respectively, comprised of the following:
1.
Audit Fees
The aggregate fees billed to Northeast Utilities 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, 2012 and 2011 totaled $4,356,000 and $2,956,000, respectively. The audit fees were incurred for audits of Northeast Utilities’ annual consolidated financial statements and those of its subsidiaries (including NSTAR in 2012), reviews of financial statements included in Northeast Utilities’ Quarterly Reports on Form 10-Q and those of 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, 2012 and 2011, as well as auditing the implementation of new accounting standards and the accounting for new contracts.
2.
Audit Related Fees
The aggregate fees billed to us and our subsidiaries by the Deloitte Entities for audit related services rendered for the years ended December 31, 2012 and 2011 totaled $88,000 and $519,000, respectively. 2011 audit related fees were primarily for audit procedures related to the merger with NSTAR.
3.
Tax Fees
The aggregate fees billed to Northeast Utilities and its subsidiaries by the Deloitte Entities for tax services for the years ended December 31, 2012 and 2011 totaled $14,000 and $39,859, respectively. These services related primarily to the reviews of tax returns and reviewing the tax impacts of proposed transactions in 2011.
4.
All Other Fees
The aggregate fees billed to us and our subsidiaries by the Deloitte Entities for services other than the services described above for the years ended December 31, 2012 and 2011 totaled $1,500 and $851,500, respectively. All other fees in 2012 and 2011 included a license fee for access to an accounting research tool. All other fees in 2011 consisted primarily of consulting services related to the Company's consideration of implementing enterprise resource planning systems.
The Audit Committee pre-approves all auditing services and permitted non-audit services (including the fees and terms thereof) to be performed for us by our independent registered public accountants, 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 its 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. During 2012, all services described above were pre-approved by the Audit Committee.
The 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 the independence of the registered public accountants and has concluded that the Deloitte Entities were and are independent of us in all respects.
PART IV
Item 15.
Item 15.
Exhibits and Financial Statement Schedules
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.
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.
POWER OF ATTORNEY
Each person whose signature appears below constitutes and appoints Gregory B. Butler, James J. Judge and Jay S. Buth and each of them, his or her true and lawful attorneys-in-fact and agents, with full power of substitution and resubstitution, for him or her and in his or her name, place and stead, in any and all capacities, to sign any and all amendments to this Annual Report on Form 10-K, and to file the same, with all exhibits thereto, and other documents in connection therewith, with the Securities and Exchange Commission, granting unto said attorneys-in-fact and agents, and each of them, full power and authority to do and perform each and every act and thing requisite and necessary to be done, as fully to all intents and purposes as he or she might or could do in person, hereby ratifying and confirming all that said attorneys-in-fact and agents or any of them, or their or his or her substitute or substitutes, may lawfully do or cause to be done by virtue hereof.
Signature
Title
Date
/s/
Thomas J. May
President and Chief Executive Officer
February 27, 2013
Thomas J. May
and a Trustee
(Principal Executive Officer)
/s/
James J. Judge
Executive Vice President and
Chief Financial Officer
(Principal Financial Officer)
February 27, 2013
James J. Judge
/s/
Jay S. Buth
Vice President, Controller
February 27, 2013
Jay S. Buth
and Chief Accounting Officer
/s/
Charles W. Shivery
Chairman of the Board of Trustees
February 27, 2013
Charles W. Shivery
/s/
Richard H. Booth
Trustee
February 27, 2013
Richard H. Booth
/s/
John S. Clarkeson
Trustee
February 27, 2013
John S. Clarkeson
/s/
Cotton M. Cleveland
Trustee
February 27, 2013
Cotton M. Cleveland
/s/
Sanford Cloud, Jr.
Trustee
February 27, 2013
Sanford Cloud, Jr.
/s/
James S. DiStasio
Trustee
February 27, 2013
James S. DiStasio
/s/
Francis A. Doyle
Trustee
February 27, 2013
Francis A. Doyle
/s/
Charles K. Gifford
Trustee
February 27, 2013
Charles K. Gifford
/s/
Paul A. La Camera
Trustee
February 27, 2013
Paul A. La Camera
/s/
Kenneth R. Leibler
Trustee
February 27, 2013
Kenneth R. Leibler
/s/
William C. Van Faasen
Trustee
February 27, 2013
William C. Van Faasen
/s/
Frederica M. Williams
Trustee
February 27, 2013
Frederica M. Williams
/s/
Dennis R. Wraase
Trustee
February 27, 2013
Dennis R. Wraase
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.
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.
POWER OF ATTORNEY
Each person whose signature appears below constitutes and appoints Gregory B. Butler, James J. Judge and Jay S. Buth and each of them, his or her true and lawful attorneys-in-fact and agents, with full power of substitution and resubstitution, for him or her and in his or her name, place and stead, in any and all capacities, to sign any and all amendments to this Annual Report on Form 10-K, and to file the same, with all exhibits thereto, and other documents in connection therewith, with the Securities and Exchange Commission, granting unto said attorneys-in-fact and agents, and each of them, full power and authority to do and perform each and every act and thing requisite and necessary to be done, as fully to all intents and purposes as he or she might or could do in person, hereby ratifying and confirming all that said attorneys-in-fact and agents or any of them, or their or his or her substitute or substitutes, may lawfully do or cause to be done by virtue hereof.
Signature
Title
Date
/s/
Thomas J. May
Chairman and a Director
February 27, 2013
Thomas J. May
/s/
Leon J. Olivier
Chief Executive Officer and a Director
February 27, 2013
Leon J. Olivier
(Principal Executive Officer)
/s/
James J. Judge
Executive Vice President and
February 27, 2013
James J. Judge
Chief Financial Officer and a Director
(Principal Financial Officer)
/s/
Jay S. Buth
Vice President, Controller
February 27, 2013
Jay S. Buth
and Chief Accounting Officer
/s/
Gregory B. Butler
Senior Vice President and General Counsel
February 27, 2013
Gregory B. Butler
and a Director
/s/
Christine M. Carmody
Senior Vice President-Human Resources
February 27, 2013
Christine M. Carmody
and a Director
/s/
William P. Herdegen III
President and Chief Operating Officer
February 27, 2013
William P. Herdegen III
and a Director
/s/
David R. McHale
Executive Vice President and
February 27, 2013
David R. McHale
Chief Administrative Officer and a Director
/s/
Joseph R. Nolan, Jr.
Senior Vice President-Corporate Relations
February 27, 2013
Joseph R. Nolan, Jr.
and a Director
NSTAR 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.
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.
POWER OF ATTORNEY
Each person whose signature appears below constitutes and appoints Gregory B. Butler, James J. Judge and Jay S. Buth and each of them, his or her true and lawful attorneys-in-fact and agents, with full power of substitution and resubstitution, for him or her and in his or her name, place and stead, in any and all capacities, to sign any and all amendments to this Annual Report on Form 10-K, and to file the same, with all exhibits thereto, and other documents in connection therewith, with the Securities and Exchange Commission, granting unto said attorneys-in-fact and agents, and each of them, full power and authority to do and perform each and every act and thing requisite and necessary to be done, as fully to all intents and purposes as he or she might or could do in person, hereby ratifying and confirming all that said attorneys-in-fact and agents or any of them, or their or his or her substitute or substitutes, may lawfully do or cause to be done by virtue hereof.
Signature
Title
Date
/s/
Thomas J. May
Chairman and a Director
February 27, 2013
Thomas J. May
/s/
Leon J. Olivier
Chief Executive Officer and a Director
February 27, 2013
Leon J. Olivier
(Principal Executive Officer)
/s/
James J. Judge
Executive Vice President and
February 27, 2013
James J. Judge
Chief Financial Officer and a Director
(Principal Financial Officer)
/s/
Jay S. Buth
Vice President, Controller
February 27, 2013
Jay S. Buth
and Chief Accounting Officer
/s/
Gregory B. Butler
Senior Vice President and General Counsel
February 27, 2013
Gregory B. Butler
and a Director
/s/
Christine M. Carmody
Senior Vice President-Human Resources
February 27, 2013
Christine M. Carmody
and a Director
/s/
Craig A. Hallstrom
President and Chief Operating Officer
February 27, 2013
Craig A. Hallstrom
and a Director
/s/
David R. McHale
Executive Vice President and
February 27, 2013
David R. McHale
Chief Administrative Officer and a Director
/s/
Joseph R. Nolan, Jr.
Senior Vice President-Corporate Relations
February 27, 2013
Joseph R. Nolan, Jr.
and a Director
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.
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.
POWER OF ATTORNEY
Each person whose signature appears below constitutes and appoints Gregory B. Butler, James J. Judge and Jay S. Buth and each of them, his or her true and lawful attorneys-in-fact and agents, with full power of substitution and resubstitution, for him or her and in his or her name, place and stead, in any and all capacities, to sign any and all amendments to this Annual Report on Form 10-K, and to file the same, with all exhibits thereto, and other documents in connection therewith, with the Securities and Exchange Commission, granting unto said attorneys-in-fact and agents, and each of them, full power and authority to do and perform each and every act and thing requisite and necessary to be done, as fully to all intents and purposes as he or she might or could do in person, hereby ratifying and confirming all that said attorneys-in-fact and agents or any of them, or their or his or her substitute or substitutes, may lawfully do or cause to be done by virtue hereof.
Signature
Title
Date
/s/
Thomas J. May
Chairman and a Director
February 27, 2013
Thomas J. May
/s/
Leon J. Olivier
Chief Executive Officer and a Director
February 27, 2013
Leon J. Olivier
(Principal Executive Officer)
/s/
James J. Judge
Executive Vice President and
February 27, 2013
James J. Judge
Chief Financial Officer and a Director
(Principal Financial Officer)
/s/
Jay S. Buth
Vice President, Controller
February 27, 2013
Jay S. Buth
and Chief Accounting Officer
/s/
Gregory B. Butler
Senior Vice President and General Counsel
February 27, 2013
Gregory B. Butler
and a Director
/s/
Christine M. Carmody
Senior Vice President-Human Resources
February 27, 2013
Christine M. Carmody
and a Director
/s/
Gary A. Long
President and Chief Operating Officer
February 27, 2013
Gary A. Long
and a Director
/s/
David R. McHale
Executive Vice President and
February 27, 2013
David R. McHale
Chief Administrative Officer and a Director
/s/
Joseph R. Nolan, Jr.
Senior Vice President-Corporate Relations
February 27, 2013
Joseph R. Nolan, Jr.
and a Director
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.
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.
POWER OF ATTORNEY
Each person whose signature appears below constitutes and appoints Gregory B. Butler, James J. Judge and Jay S. Buth and each of them, his or her true and lawful attorneys-in-fact and agents, with full power of substitution and resubstitution, for him or her and in his or her name, place and stead, in any and all capacities, to sign any and all amendments to this Annual Report on Form 10-K, and to file the same, with all exhibits thereto, and other documents in connection therewith, with the Securities and Exchange Commission, granting unto said attorneys-in-fact and agents, and each of them, full power and authority to do and perform each and every act and thing requisite and necessary to be done, as fully to all intents and purposes as he or she might or could do in person, hereby ratifying and confirming all that said attorneys-in-fact and agents or any of them, or their or his or her substitute or substitutes, may lawfully do or cause to be done by virtue hereof.
S-1
S-2
S-3
S-4
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. Management contracts and compensation plans or arrangements are designated with a (+).
Exhibit
Number
Description
3.
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 filed 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 CL&P Form 10-K, File No. 000-00404)
3.1.1
Certificate of Amendment to Certificate of Incorporation of CL&P, dated December 26, 1996 (Exhibit 3.2.2, 1996 CL&P Form 10-K filed March 25, 1997, File No. 001-11419)
3.1.2
Certificate of Amendment to Certificate of Incorporation of CL&P, dated April 27, 1998 (Exhibit 3.2.3, 1998 CL&P Form 10-K filed March 23, 1999, File No. 000-00404)
3.1.3
Amended and Restated Certificate of Incorporation of CL&P, dated effective January 3, 2012 (Exhibit 3(i), CL&P Current Report on Form 8-K filed January 9, 2012, File No. 000-00404)
3.2
By-laws of CL&P, as amended to January 1, 1997 (Exhibit 3.2.3, 1996 CL&P Form 10-K filed March 25, 1997, File No. 001-11419)
(C)
NSTAR Electric Company
3.1
NSTAR Electric Company, fka Boston Edison Company, Restated Articles of Organization (Exhibit 3.1, NSTAR Electric Form 10-Q for the Quarter Ended June 30, 1994 filed August 12, 1994, File No. 001-02301)
3.2
NSTAR Electric Company, fka Boston Edison Company, Bylaws dated April 19, 1977, as amended January 22, 1987, January 28, 1988, May 24, 1988, November 22, 1989, July 22, 1999, September 20, 1999, January 2, 2007 and March 1, 2011 (Exhibit 3.2, NSTAR Electric 2011 Form 10-K filed February 7, 2012, File No. 001-02301)
(D)
Public Service Company of New Hampshire
3.1
Articles of Incorporation, as amended to May 16, 1991 (Exhibit 3.3.1, 1993 PSNH Form 10-K filed March 25, 1994, File No. 001-06392)
3.2
By-laws of PSNH, as in effect June 27, 2008 (Exhibit 3, PSNH Form 10-Q for the Quarter Ended June 30, 2008 filed August 7, 2008, File No. 001-06392)
(E)
Western Massachusetts Electric Company
3.1
Articles of Organization of WMECO, restated to February 23, 1995 (Exhibit 3.4.1, 1994 WMECO Form 10-K filed March 27, 1995, File No. 001-07624)
3.2
By-laws of WMECO, as amended to April 1, 1999 (Exhibit 3.1, WMECO Form 10-Q for the Quarter Ended June 30, 1999 filed August 13, 1999, File No. 000-07624)
3.2.1
By-laws of WMECO, as further amended to May 1, 2000 (Exhibit 3.1, WMECO Form 10-Q for the Quarter Ended June 30, 2000 filed August 11, 2000, File No. 000-07624)
E-1
4.
Instruments defining the rights of security holders, including indentures
(A)
Northeast Utilities
4.1
Indenture between NU and The Bank of New York as Trustee dated as of April 1, 2002 (Exhibit A-3, NU 35-CERT filed April 16, 2002, File No. 070-09535)
4.1.1
Third Supplemental Indenture between NU and The Bank of New York Trust Company N.A., as Trustee, dated as of June 1, 2008, relating to $250 million of Senior Notes, Series C, due 2013, (Exhibit 4.1, NU Current Report on Form 8-K filed June 10, 2008, File No. 001-05324)
4.1.2
Fourth Supplemental Indenture between NU and The Bank of New York Trust Company N.A., as Trustee, dated as of March 15, 2012, relating to $300 million of Senior Notes, Series D, due 2013, (Exhibit 4.1, NU Current Report on Form 8-K filed March 28, 2012, File No. 001-05324)
4.2
Credit Agreement, dated July 25, 2012, by and among NU, CL&P, NSTAR Gas, NSTAR LLC, PSNH, WMECO, Yankee Gas Services Company and the Banks named therein, pursuant to which Bank of America, N.A. serves as Administrative Agent (Exhibit 4.1, NU Form 10-Q for the Quarter Ended September 30, 2012, filed November 7, 2012, File No. 001-05324)
(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 NU Form 10-K, File No. 001-05324)
4.1.1
Series D 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 filed March 27, 1995, File No. 001-11419)
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, CL&P Current Report on Form 8-K filed September 22, 2004, File No. 000-00404)
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, CL&P Current Report on Form 8-K filed September 22, 2004, File No. 000-00404)
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 (Exhibit 99.5, CL&P Current Report on Form 8-K filed April 13, 2005, File No. 000-00404)
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, CL&P Current Report on Form 8-K filed April 13, 2005, File No. 000-00404)
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 (Exhibit 99.2, CL&P Current Report on Form 8-K filed June 7, 2006, File No. 000-00404)
4.2.3
Supplemental Indenture (2007 Series A Bonds and 2007 Series B Bonds) between CL&P and Deutsche Bank Trust Company Americas, as Trustee dated as of March 1, 2007 (Exhibit 99.2, CL&P Current Report on Form 8-K filed March 29, 2007, File No. 000-00404)
4.2.4
Supplemental Indenture (2007 Series C Bonds and 2007 Series D Bonds) between CL&P and Deutsche Bank Trust Company Americas, as Trustee dated as of September 1, 2007 (Exhibit 4, CL&P Current Report on Form 8-K filed September 19, 2007, File No. 000-00404)
4.2.5
Supplemental Indenture (2008 Series A Bonds) between CL&P and Deutsche Bank Trust Company Americas, as Trustee dated as of May 1, 2008 (Exhibit 4, CL&P Current Report on Form 8-K filed May 29, 2008, File No. 000-00404)
4.2.6
Supplemental Indenture (2009 Series A Bonds) between CL&P and Deutsche Bank Trust Company Americas, as Trustee dated as of February 1, 2009 (Exhibit 4, CL&P Current Report on Form 8-K filed February 19, 2009, File No. 000-00404)
E-2
4.2.7
Supplemental Indenture (2011 Series A and Series B Bonds) between CL&P and Deutsche Bank Trust Company Americas, as Trustee dated as of October 1, 2011 (Exhibit 4.1, CL&P Current Report on Form 8-K filed October 28, 2011, File No. 000-00404)
4.2.8
Supplemental Indenture (2013 Series A Bond) between CL&P and Deutsche Bank Trust Company Americas, as Trustee dated as of January 1, 2013 (Exhibit 4.1, CL&P Current Report on Form 8-K filed January 22, 2013, File No. 000-00404)
4.3
Amended and Restated Loan Agreement between Connecticut Development Authority and CL&P dated as of May 1, 1996 and Amended and Restated as of January 1, 1997 (Pollution Control Revenue Bond - 1996A Series) (Exhibit 4.2.24, 1996 CL&P Form 10-K filed March 25, 1997, File No. 001-11419)
4.3.1
First Amendment to Amended and Restated Loan Agreement, between the Connecticut Development Authority and CL&P dated as of October 1, 2008 (Pollution Control Revenue Bond-1996A Series) (Exhibit 10.1, CL&P Form 10-Q for the Quarter Ended September 30, 2008, filed November 10, 2008, File No. 000-00404)
4.4
Amended and Restated Indenture of Trust between Connecticut Development Authority and Fleet National Bank, the Trustee dated as of May 1, 1996 and Amended and Restated as of January 1, 1997 (Pollution Control Revenue Bond-1996A Series) (Exhibit 4.2.24.1, 1996 CL&P Form 10-K, filed March 25, 1997, File No. 001-11419)
4.4.1
First Amendment to Amended and Restated Indenture of Trust between Connecticut Development Authority and U.S. Bank National Association, as Trustee dated as of October 1, 2008 (Exhibit 10.2 CL&P Form 10-Q for the Quarter Ended September 30, 2008, filed November 10, 2008, File No. 000-00404)
4.5
Loan Agreement between Connecticut Development Authority and CL&P (Pollution Control Revenue Refunding Bonds - 2011A Series) dated as of October 1, 2011 (Exhibit 1.1, CL&P Current Report on Form 8-K filed October 28, 2011, File No. 000-00404)
4.6
Loan Agreement between Connecticut Development Authority and CL&P (Pollution Control Revenue Refunding Bonds - 2011B Series) dated as of October 1, 2011 (Exhibit 1.2, CL&P Current Report on Form 8-K filed October 28, 2011, File No. 000-00404)
4.7
Credit Agreement, dated March 26, 2012, by CL&P and the Banks named therein, pursuant to which Union Bank, N.A., serves as Administrative Agent (Exhibit 4.1, NU Form 10-Q for the Quarter Ended March 31, 2012, filed May 10, 2012, File No. 001-05324)
4.8
Credit Agreement, dated July 25, 2012, by and among NU, CL&P, NSTAR Gas, NSTAR LLC, PSNH, WMECO, Yankee Gas Services Company and the Banks named therein, pursuant to which Bank of America, N.A. serves as Administrative Agent (Exhibit 4.1, NU Form 10-Q for the Quarter Ended September 30, 2012, filed November 7, 2012, File No. 001-05324)
(C)
NSTAR Electric Company
4.1
Indenture between Boston Edison Company and the Bank of New York (as successor to Bank of Montreal Trust Company)(Exhibit 4.1, NSTAR Electric Form 10-Q for the Quarter Ended September 30, 1988, File No. 001-02301)
4.1.1
A Form of 4.875% Debenture Due April 15, 2014 (Exhibit 4.3, Boston Edison Company Current Report on Form 8-K filed April 15, 2004, File No. 001-02301)
4.1.2
A Form of 5.75% Debenture Due March 15, 2036 (Exhibit 99.2, Boston Edison Company Current Report on Form 8-K filed March 17, 2006, File No. 001-02301)
4.1.3
A Form of 5.625% Debenture Due November 15, 2017 (Exhibit 99.2, NSTAR Electric Company Current Report on Form 8-K filed November 20, 2007 and filed February 17, 2009, File No. 001-02301)
4.1.4
A Form of 5.50% Debenture Due March 15, 2040 (Exhibit 99.2, NSTAR Electric Company Current Report on Form 8-K filed March 15, 2010, File No. 001-02301)
4.1.5
A Form of 2.375% Debenture due 2022. (Exhibit 4, NSTAR Electric Company Current Report on Form 8-K filed October 18, 2012, File No. 001-02301)
4.2
Credit Agreement, dated July 25, 2012, by and between NSTAR Electric and the Banks named therein, pursuant to which Barclays Bank PLC serves as Administrative Agent and Swing Line Lender (Exhibit 4.1, NU Form 10-Q for the Quarter Ended September 30, 2012, filed November 7, 2012, File No. 001-05324)
E-3
(D)
Public Service Company of New Hampshire
4.1
First Mortgage Indenture between PSNH and First Fidelity Bank, National Association, New Jersey, now First Union National Bank, Trustee, dated as of August 15, 1978 (Composite including all amendments effective June 1, 2011) (included as Exhibit C to the Eighteen Supplemental Indenture filed as Exhibit 4.1 to PSNH Current Report on Form 8-K filed June 2, 2011, File No. 001-06392)
4.1.1
Twelfth Supplemental Indenture between PSNH and First Union National Bank dated as of December 1, 2001 (Exhibit 4.3.1.2, 2001 PSNH Form 10-K filed March 22, 2002, File No. 001-06392)
4.1.2
Thirteenth Supplemental Indenture between PSNH and Wachovia Bank, National Association, successor to First Union National Bank, as successor to First Fidelity Bank, National Association, as Trustee dated as of July 1, 2004 (Exhibit 99.2, PSNH Current Report on Form 8-K filed October 5, 2004, File No. 001-06392)
4.1.3
Fourteenth Supplemental Indenture between PSNH and Wachovia Bank, National Association successor to First Union National Bank, as successor to First Fidelity Bank, National Association, as Trustee dated as of October 1, 2005 (Exhibit 99.2, PSNH Current Report on Form 8-K filed October 6, 2005, File No. 001-06392)
4.1.4
Fifteenth Supplemental Indenture between PSNH and Wachovia Bank, National Association successor to First Union National Bank, as successor to First Fidelity Bank, National Association, as Trustee dated as of September 1, 2007 (Exhibit 4.1, PSNH Current Report on Form 8-K filed September 25, 2007, File No. 001-06392)
4.1.5
Sixteenth Supplemental Indenture between PSNH and U.S. Bank National Association, Trustee, dated as of May 1, 2008 (Exhibit 4.1 to PSNH Current Report on Form 8-K filed May 29, 2008 (File No.001-06392)
4.1.6
Seventeenth Supplemental Indenture, between PSNH and U.S. Bank National Association, as Trustee dated as of December 1, 2009 (Exhibit 4.1, PSNH Current Report on Form 8-K filed December 15, 2009 (File No. 001-06392)
4.1.7
Eighteenth Supplemental Indenture, between PSNH and U.S. Bank National Association, as Trustee dated as of May 1, 2011 (Exhibit 4.1, PSNH Current Report on Form 8-K filed June 2, 2011 (File No. 001-06392)
4.1.8
Nineteenth Supplemental Indenture, between PSNH and U.S. Bank National Association, as Trustee dated as of September 1, 2011 (Exhibit 4.1, PSNH Current Report on Form 8-K filed September 16, 2011 (File No. 001-06392)
4.2
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 NU Form 10-K filed March 22, 2002, File No. 001-05324)
4.3
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 NU Form 10-K filed March 22, 2002, File No. 001-05324)
4.4
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 NU Form 10-K filed March 22, 2002, File No. 001-05324)
4.5
Credit Agreement, dated July 25, 2012, by and among NU, CL&P, NSTAR Gas, NSTAR LLC, PSNH, WMECO, Yankee Gas Services Company and the Banks named therein, pursuant to which Bank of America, N.A. serves as Administrative Agent (Exhibit 4.1, NU Form 10-Q for the Quarter Ended September 30, 2012, filed November 7, 2012, File No. 001-05324)
(E)
Western Massachusetts Electric Company
4.1
Loan Agreement between Connecticut Development Authority and WMECO, (Pollution Control Revenue Bonds - Series A, Tax Exempt Refunding) dated as of September 1, 1993 (Exhibit 4.4.13, 1993 WMECO Form 10-K filed March 25,1994, File No. 000-07624)
4.2
Indenture between WMECO and The Bank of New York, as Trustee, dated as of September 1, 2003 (Exhibit 99.2, WMECO Current Report on Form 8-K filed October 8, 2003, File No. 000-07624)
E-4
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 Current Report on Form 8-K filed October 8, 2003, File No. 000-07624)
4.2.2
Second Supplemental Indenture between WMECO and The Bank of New York, as Trustee dated as of September 1, 2004 (Exhibit 4.1, WMECO Current Report on Form 8-K filed September 27, 2004, File No. 000-07624)
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 Current Report on Form 8-K filed August 12, 2005, File No. 000-07624)
4.2.4
Fourth Supplemental Indenture between WMECO and The Bank of New York Trust, as Trustee, dated as of August 1, 2007 (Exhibit 4.1, WMECO Current Report on Form 8-K filed August 20, 2007, File No. 000-07624)
4.2.5
Fifth Supplemental Indenture between WMECO and The Bank of New York Trust Company, N.A., as Trustee, dated as of March 1, 2010 (Exhibit 4.1, WMECO Current Report on Form 8-K filed March 10, 2010, File No. 000-07624)
4.2.6
Sixth Supplemental Indenture between WMECO and The Bank of New York Trust Company, N.A., as Trustee, dated as of September 15, 2011 (Exhibit 4.1, WMECO Current Report on Form 8-K filed September 19, 2011, File No. 000-07624)
4.3
Credit Agreement, dated July 25, 2012, by and among NU, CL&P, NSTAR Gas, NSTAR LLC, PSNH, WMECO, Yankee Gas Services Company and the Banks named therein, pursuant to which Bank of America, N.A. serves as Administrative Agent (Exhibit 4.1, NU Form 10-Q for the Quarter Ended September 30, 2012, filed November 7, 2012, File No. 001-05324)
10.
Material Contracts
(A)
NU
10.1
Lease between The Rocky River Realty Company and Northeast Utilities Service Company dated as of April 14, 1992 with respect to the Berlin, Connecticut headquarters (Exhibit 10.29.1, 1992 NU Form 10-K, File No. 001-05324)
10.2
Indenture of Mortgage and Deed of Trust between Yankee Gas Services Company and the Connecticut National Bank, as Trustee, dated July 1, 1989 (Exhibit 4.7, Yankee Energy System, Inc. Form 10-K for the year ended September 30, 1990, File No. 001-10721)
10.2.1
First Supplemental Indenture of Mortgage and Deed of Trust between Yankee Gas Services Company and The Connecticut National Bank, as Trustee, dated April 1, 1992 (Yankee Energy System, Inc. Registration Statement on Form S-3, dated October 2, 1992, File No. 33-52750)
10.2.2
Sixth Supplemental Indenture of Mortgage and Deed of Trust between Yankee Gas Services Company and The Bank of New York, as Successor Trustee to Fleet Bank (formerly The Connecticut National Bank) dated January 1, 2004 (Exhibit 10.5.6, 2004 NU Form 10-K filed March 17, 2005, File No. 001-05324)
10.2.3
Seventh Supplemental Indenture of Mortgage and Deed of Trust between Yankee Gas Services Company and The Bank of New York, as Successor Trustee to Fleet Bank (formerly The Connecticut National Bank) dated November 1, 2004 (Exhibit 10.5.7, 2004 NU Form 10-K filed March 17, 2005, File No. 001-05324)
10.2.4
Eighth Supplemental Indenture of Mortgage and Deed of Trust between Yankee Gas Services Company and The Bank of New York, as Successor Trustee to Fleet Bank (formerly the Connecticut National Bank) dated July 1, 2005 (Exhibit 10.5.8, NU Form 10-Q for the Quarter Ended June 30, 2005 filed August 8, 2005, File No. 001-05324)
10.2.5
Ninth Supplemental Indenture of Mortgage and Deed of Trust between Yankee Gas Services Company and The Bank of New York Mellon Trust Company, N.A., successor as Trustee to The Bank of New York, as successor to Fleet National Bank (formerly known as The Connecticut National Bank) dated as of October 1, 2008 (Exhibit 10-1, NU Form 10-Q for the Quarter Ended September 30, 2008 filed November 10, 2008, File No. 001-05324)
E-5
10.2.6
Tenth Supplemental Indenture of Mortgage and Deed of Trust between Yankee Gas Services Company and The Bank of New York Mellon Trust Company, N.A., successor as Trustee to The Bank of New York, as successor to Fleet National Bank (formerly known as The Connecticut National Bank), dated as of April 1, 2010 (Exhibit 10, NU Form 10-Q for the Quarter Ended March 31, 2010 filed May 7, 2010, File No. 001-05324)
10.3
Indenture dated as of January 12, 2000 between NSTAR LLC, successor to NSTAR, and Bank One Trust Company N.A. (Exhibit 4.1 to NSTAR Registration Statement on Form S-3, File No. 333-94735)
10.3.1
Form of 4.50% Debenture Due 2019 (Exhibit 99.2, NSTAR Form 8-K filed November 16, 2009, File No. 001-14768)
* +10.4
Northeast Utilities Board of Trustees' Compensation Arrangement Summary
+10.5
Amended and Restated Northeast Utilities Deferred Compensation Plan for Trustees, effective January 1, 2009 (Exhibit 10.6, NU Form 10-Q for the Quarter Ended September 30, 2008 filed November 10, 2008, File No. 001-05324)
10.6
Transmission Service Agreement by and between Northern Pass Transmission LLC, as Owner and H.Q. Hydro Renewable Energy, Inc., as Purchaser dated October 4, 2010 (Exhibit 10.6, 2010 NU Form 10-K filed February 25, 2011, File No. 001-05324)
(D)
NU, CL&P, PSNH and WMECO
10.1
Form of Service Contract between each of NU, CL&P and WMECO and Northeast Utilities Service Company (NUSCO) dated as of July 1, 1966 (Exhibit 10.20, 1993 NU Form 10-K filed March 25, 1994, File No. 001-05324)
10.1.1
Form of Renewal of Service Contract (Exhibit 10.2, 2006 NU Form 10-K filed March 1, 2007, File No. 001-05324)
10.2
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. 001-03446)
10.3
Transmission Operating Agreement between the Initial Participating Transmission Owners, Additional Participating Transmission Owners and ISO New England, Inc. dated as of February 1, 2005 (Exhibit 10.29, 2004 NU Form 10-K filed March 17, 2005, File No. 001-05324)
10.3.1
Rate Design and Funds Disbursement Agreement among the Initial Participating Transmission Owners, Additional Participating Transmission Owners and ISO New England, Inc., effective June 30, 2006 (Exhibit 10.22.1, 2006 NU Form 10-K filed March 1, 2007, File No. 001-05324)
10.4
Northeast Utilities Service Company Transmission and Ancillary Service Wholesale Revenue Allocation Methodology among The Connecticut Light and Power Company, Western Massachusetts Electric Company, Public Service Company of New Hampshire, Holyoke Water Power Company and Holyoke Power and Electric Company Trustee dated as of January 1, 2008 (Exhibit 10.1, NU Form 10-Q for the Quarter Ended March 31, 2008 filed May 9, 2008, File No. 001-05324)
+10.5
Amended and Restated Employment Agreement with Gregory B. Butler, effective January 1, 2009 (Exhibit 10.7, 2008 NU Form 10-K filed February 27, 2009, File No. 001-05324)
+10.6
Amended and Restated Employment Agreement with David R. McHale, effective January 1, 2009 (Exhibit 10.8, 2008 NU Form 10-K filed February 27, 2009, File No. 001-05324)
+10.7
Amended and Restated Memorandum Agreement between Northeast Utilities and Leon J. Olivier effective January 1, 2009 (Exhibit 10.9, 2008 NU Form 10-K filed February 27, 2009, File No. 001-05324)
+10.8
Amendment and Restatement of Agreement between Northeast Utilities and James A. Muntz effective January 1, 2009 (Exhibit 10.17, 2012 NU Form 10-K filed February 24, 2012, File No. 001-05324)
+10.9
Amended and Restated Incentive Plan Effective January 1, 2009 (Exhibit 10.3, NU Form 10-Q for the Quarter Ended September 30, 2008 filed November 10, 2008, File No. 001-05324)
+10.10
Amended and Restated Supplemental Executive Retirement Plan for Officers of Northeast Utilities System Company effective January 1, 2009 (Exhibit 10.5, NU Form 10-Q for the Quarter Ended September 30, 2008 filed November 10, 2008, File No. 001-05324)
E-6
+10.11
Trust under Supplemental Executive Retirement Plan dated May 2, 1994 (Exhibit 10.33, 2002 NU Form 10-K filed March 21, 2003, File No. 001-05324)
+10.11.1
First Amendment to Trust Under Supplemental Executive Retirement Plan, effective as of December 10, 2002 (Exhibit 10 (B) 10.19.1, 2003 NU Form 10-K filed March 12, 2004, File No. 001-05324)
+10.11.2
Second Amendment to Trust Under Supplemental Executive Retirement Plan , effective as of November 12, 2008 (Exhibit 10.12.2, 2008 NU Form 10-K filed February 27, 2009, File No. 001-05324)
+10.12
Special Severance Program for Officers of NU System Companies as of January 1, 2009, (Exhibit 10.2, NU Form 10-Q for the Quarter Ended September 30, 2008 filed November 10, 2008, File No. 001-05324)
+10.13
Amended and Restated Northeast Utilities Deferred Compensation Plan for Executives effective as of January 1, 2009 (Exhibit 10.4 NU Form 10-Q for Quarter Ended September 30, 2008 filed November 10, 2008, File No. 001-05324)
+10.14
Northeast Utilities Retention Agreement (Exhibit 10.1, NU Registration Statement on Form S-4, filed November 22, 2010, File No. 333-170754)
10.15
Northeast Utilities System's Third Amended and Restated Tax Allocation Agreement dated as of April 10, 2012, (Exhibit 10.1 NU Form 10-Q for Quarter Ended June 30, 2012 filed August 7, 2012, File No. 001-05324)
(C)
NU and CL&P
10.1
CL&P Agreement Re: Connecticut NEEWS Projects by and between CL&P and The United Illuminating Company dated July 14, 2010 (Exhibit 10, CL&P Form 10-Q for the Quarter Ended June 30, 2010 filed August 6, 2010, File No. 000-00404)
(C)
NU and NSTAR Electric
10.1
NSTAR Electric Company Restructuring Settlement Agreement dated July 1997
(Exhibit 10.12, Boston Edison 1997 Form 10-K filed March 30, 1998, File No. 001-02301)
10.2
Amended and Restated Power Purchase Agreement (NEA A PPA), dated August 19, 2004, by and between Boston Edison and Northeast Energy Associates L.P. (Exhibit 10.18, 2005 NSTAR Form 10-K filed February 21, 2006, File No. 001-14768)
10.3
Amended and Restated Power Purchase Agreement (NEA B PPA), dated August 19, 2004, by and between ComElectric and Northeast Energy Associates L. P. (Exhibit 10.19, 2005 NSTAR Form 10-K filed February 21, 2006, File No. 001-14768)
10.4
Amended and Restated Power Purchase Agreement (CECO 1 PPA), dated August 19, 2004 by and between ComElectric and Northeast Energy Associates L. P. (Exhibit 10.20, 2005 NSTAR Form 10-K filed February 21, 2006, File No. 001-14768)
10.5
Amended and Restated Power Purchase Agreement (CECO 2 PPA), dated August 19, 2004 by and between ComElectric and Northeast Energy Associates L. P. (Exhibit 10.21, 2005 NSTAR Form 10-K filed February 21, 2006, File No. 001-14768)
10.6
The Bellingham Execution Agreement, dated August 19, 2004 between Boston Edison, ComElectric and Northeast Energy Associates L. P. (Exhibit 10.22, 2005 NSTAR Form 10-K filed February 21, 2006, File No. 001-14768)
10.7
Second Restated NEPOOL Agreement among NSTAR Electric and various other electric utilities operating in New England, dated August 16, 2004 (Exhibit 10.2.1.1, 2005 NSTAR Form 10-K filed February 21, 2006, File No. 001-14768)
10.8
Transmission Operating Agreement among NSTAR Electric and various electric transmission providers in New England and ISO New England Inc., dated February 1, 2005 (Exhibit 10.2.1.2, 2005 NSTAR Form 10-K filed February 21, 2006, File No. 001-14768)
10.9
Market Participants Service Agreement among NSTAR Electric and various other electric utilities operating in New England, NEPOOL and ISO New England Inc., dated February 1, 2005 (Exhibit 10.2.1.3, 2005 NSTAR Form 10-K filed February 21, 2006, File No. 001-14768)
E-7
10.10
Rate Design and Funds Disbursement Agreement among NSTAR Electric and various other electric transmission providers in New England, dated February 1, 2005 (Exhibit 10.2.1.4, 2005 NSTAR Form 10-K filed February 21, 2006, File No. 001-14768)
10.11
Participants Agreement among NSTAR Electric, various electric utilities operating in New England, NEPOOL and ISO-New England, Inc., dated February 1, 2005. (Exhibit 10.2.1.4, 2006 NSTAR Form 10-K filed February 16, 2007, File No. 001-14768)
+10.12
NSTAR Excess Benefit Plan, effective August 25, 1999 (Exhibit 10.1 1999 NSTAR Form 10-K/A filed September 29, 2000, File No. 001-14768)
+10.12.1
NSTAR Excess Benefit Plan, incorporating the NSTAR 409A Excess Benefit Plan, as amended and restated effective January 1, 2008, dated December 24, 2008 (Exhibit 10.1.1 2008 NSTAR Form 10-K filed February 9, 2009, File No. 001-14768)
+10.13
NSTAR Supplemental Executive Retirement Plan, effective August 25, 1999 (Exhibit 10.2,1999 NSTAR Form 10-K/A filed September 29, 2000, File No. 001-14768)
+10.13.1
NSTAR Supplemental Executive Retirement Plan, incorporating the NSTAR 409A Supplemental Executive Retirement Plan, as amended and restated effective January 1, 2008, dated December 24, 2008 (Exhibit 10.2.1, 2008 NSTAR Form 10-K filed February 9, 2009, File No. 001-14768)
+10.14
Special Supplemental Executive Retirement Agreement between Boston Edison Company and Thomas J. May dated March 13, 1999, regarding Key Executive Benefit Plan and Supplemental Executive Retirement Plan (Exhibit 10.3, 1999 NSTAR Form 10-K/A filed September 9, 2000, File No. 001-14768)
+10.15
Amended and Restated Change in Control Agreement by and between NSTAR and Thomas J. May dated November 15, 2007 (Exhibit 10.5, 2007 NSTAR Form 10-K filed February 11, 2008, File No. 001-14768)
+10.16
NSTAR Deferred Compensation Plan, (Restated Effective August 25, 1999) (Exhibit 10.10, 1999 NSTAR Form 10-K/A filed September 29, 2000, File No. 001-14768)
+10.16.1
NSTAR Deferred Compensation Plan, incorporating the NSTAR 409A Deferred Compensation Plan, as amended and restated effective January 1, 2008, dated December 24, 2008 (Exhibit 10.6.1, 2008 NSTAR Form 10-K filed February 9, 2009, File No. 001-14768)
+10.17
NSTAR 1997 Share Incentive Plan, as amended June 30, 1999 and assumed by NSTAR effective August 28, 2000, as amended January 24, 2002 (Exhibit 10.1, NU Registration Statement on Form S-8 filed on May 8, 2012)
+10.18
NSTAR 2007 Long Term Incentive Plan, effective May 3, 2007 (Exhibit 10.2, NU Registration Statement on Form S-8 filed on May 8, 2012)
+10.18.1
Deferred Common Share/Dividend Equivalent Award, Stock Option Grant, Option Certificate and Performance Share Award/Dividend Equivalent Award Agreement Under the NSTAR 2007 Long Term Incentive Plan, by and between NSTAR and Thomas J. May, dated January 24, 2008 (Exhibit 10.8.1, 2007 NSTAR Form 10-K filed February 11, 2008, File No. 001-14768)
+10.18.2
Deferred Common Share/Dividend Equivalent Award, Stock Option Grant, Option Certificate and Performance Share Award/Dividend Equivalent Award Agreement Under the NSTAR 2007 Long Term Incentive Plan, by and between NSTAR and James J. Judge, dated January 24, 2008 (Exhibit 10.8.2, 2007 NSTAR Form 10-K filed February 11, 2008, File No. 001-14768)
+10.18.3
Deferred Common Share/Dividend Equivalent Award, Stock Option Grant, Option Certificate and Performance Share Award/Dividend Equivalent Award Agreement Under the NSTAR 2007 Long Term Incentive Plan by and between NSTAR and NSTAR’s other Senior Vice Presidents and Vice Presidents, dated January 24, 2008 (in form) (Exhibit 10.8.6, 2007 NSTAR Form 10-K filed February 11, 2008, File No. 001-14768)
+10.19
Amended and Restated Change in Control Agreement by and between James J. Judge and NSTAR, dated November 15, 2007 (Exhibit 10.9, 2007 NSTAR Form 10-K filed February 11, 2008, File No. 001-14768)
+10.20
NSTAR Trustees’ Deferred Plan (Restated Effective August 25, 1999), dated October 20, 2000 (Exhibit 10.4, NSTAR Form 10-Q for the quarter ended September 30, 2000 filed November 14, 2000, File No. 001-14768)
E-8
10.20.1
NSTAR Trustees’ Deferred Plan, incorporating the 409A Trustees’ Deferred Plan, effective January 1, 2008, dated December 24, 2008 (Exhibit 10.10.1, 2008 NSTAR Form 10-K filed February 9, 2009, File No. 001-14768)
+10.21
Master Trust Agreement between NSTAR and State Street Bank and Trust Company (Rabbi Trust), effective August 25, 1999 (Exhibit 10.5, NSTAR Form 10-Q for the Quarter Ended September 30, 2000 filed November 14, 2000, File No. 001-14768)
+10.22
Amended and Restated Change in Control Agreement by and between NSTAR’s other Senior Vice Presidents and NSTAR (in form), dated November 15, 2007 (Exhibit 10.15, 2007 NSTAR Form 10-K filed February 11, 2008, File No. 001-14768)
+10.23
Amended and Restated Change in Control Agreement between NSTAR’s Vice Presidents and NSTAR (in form), dated November 15, 2007 (Exhibit 10.16, 2007 NSTAR Form 10-K filed February 11, 2008, File No. 001-14768)
+10.24
Currently effective Change in Control Agreement between NSTAR’s Vice Presidents and NSTAR (in form) (Exhibit 10.17, 2009 NSTAR Form 10-K filed February 25, 2010, File No. 001-14768)
+10.25
Executive Retention Award Agreement, dated November 19, 2010, by and between NSTAR and James J. Judge (Exhibit 99.2, NSTAR Current Report on Form 8-K filed November 22, 2010, File No. 001-14768)
10.26
MDTE Order approving Rate Settlement Agreement dated December 31, 2005 (Exhibit 99.2, NSTAR Current Report on Form 8-K filed January 4, 2006, File No. 001-14768)
(D)
NU and PSNH
10.1
PSNH Purchase and Sale Agreement with PSNH Funding LLC dated as of April 25, 2001 (Exhibit 10.57, 2001 NU Form 10-K filed March 22, 2002, File No. 001-05324)
10.2
PSNH Servicing Agreement with PSNH Funding LLC dated as of April 25, 2001 (Exhibit 10.58, 2001 NU Form 10-K filed March 22, 2002, File No. 001-05324)
(E)
NU and WMECO
10.1
Lease and Agreement by and between WMECO and Bank of New England, N.A., with BNE Realty Leasing Corporation of North Carolina dated as of December 15, 1988, (Exhibit 10.63, 1988 NU Form 10-K, File No. 001-05324)
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 NU Form 10-K filed March 22, 2002, File No. 000-05324)
10.3
WMECO Transition Property Servicing Agreement between WMECO Funding LLC and WMECO, dated as of May 17, 2001 (Exhibit 10.62, 2001 NU Form 10-K filed March 22, 2002, File No. 000-05324)
*12.
Ratio of Earnings to Fixed Charges
(A)
Northeast Utilities
(B)
The Connecticut Light and Power Company
(C)
NSTAR Electric Company
(D)
Public Service Company of New Hampshire
(E)
Western Massachusetts Electric Company
*21.
Subsidiaries of the Registrant
E-9
*23.
Consents of Independent Registered Public Accounting Firms
23.1
Deloitte & Touche LLP
23.2
PricewaterhouseCoopers LLP
*31.
Rule 13a - 14(a)/15 d - 14(a) Certifications
(A)
Northeast Utilities
Certification of Thomas J. May, 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 27, 2013
31.1
Certification of James J. Judge, Executive 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 27, 2013
(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 27, 2013
31.1
Certification of James J. Judge, Executive 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 27, 2013
(C)
NSTAR Electric Company
Certification of Leon J. Olivier, Chief Executive Officer of NSTAR Electric Company, 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 27, 2013
31.1
Certification of James J. Judge, Executive Vice President and Chief Financial Officer of NSTAR Electric Company, 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 27, 2013
(D)
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 27, 2013
31.1
Certification of James J. Judge, Executive 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 27, 2013
(E)
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 27, 2013
31.1
Certification of James J. Judge, Executive 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 27, 2013
E-10
*32
18 U.S.C. Section 1350 Certifications
(A)
Northeast Utilities
Certification of Thomas J. May, President and Chief Executive Officer of Northeast Utilities and James J. Judge, Executive 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 27, 2013
(B)
The Connecticut Light and Power Company
Certification of Leon J. Olivier, Chief Executive Officer of The Connecticut Light and Power Company and James J. Judge, Executive Vice President and Chief Financial Officer of The Connecticut Light and Power Company, pursuant to 18 U.S.C. Section 1350 as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, dated February 27, 2013
(C)
NSTAR Electric Company
Certification of Leon J. Olivier, Chief Executive Officer of NSTAR Electric Company and James J. Judge, Executive Vice President and Chief Financial Officer of NSTAR Electric Company, pursuant to 18 U.S.C. Section 1350 as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, dated February 27, 2013
(D)
Public Service Company of New Hampshire
Certification of Leon J. Olivier, Chief Executive Officer of Public Service Company of New Hampshire and James J. Judge, Executive Vice President and Chief Financial Officer of Public Service Company of New Hampshire, pursuant to 18 U.S.C. Section 1350 as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, dated February 27, 2013
(E)
Western Massachusetts Electric Company
Certification of Leon J. Olivier, Chief Executive Officer of Western Massachusetts Electric Company and David R. McHale, Executive Vice President and Chief Financial Officer of Western Massachusetts Electric Company, pursuant to 18 U.S.C. Section 1350 as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, dated February 27, 2013
*101.INS
XBRL Instance Document
*101.SCH
XBRL Taxonomy Extension Schema
*101.CAL
XBRL Taxonomy Extension Calculation
*101.DEF
XBRL Taxonomy Extension Definition
*101.LAB
XBRL Taxonomy Extension Labels
*101.PRE
XBRL Taxonomy Extension Presentation
E-11