Eversource 2009 Annual Report Download - page 26

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is delayed, there may be increased risk of failures in the existing electricity transmission system and supply interruptions or blackouts
may occur 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 before completion. Our projected earnings
and growth could be adversely affected were FERC to reduce these incentives in the future below the level presently anticipated.
Increases in electric and gas prices, the continued economic slowdown, focus on conservation and self-generation by
customers and changes in legislative and regulatory policy may adversely impact our business.
Energy consumption is significantly impacted by the general level of economic activity and cost of energy supply. Economic downturns
such as the one which began in 2008, or periods of high energy supply costs typically lead to reductions in energy consumption and
increased conservation, energy efficiency and self-generation on the part of customers and on legislative and regulatory policies. 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. 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 results of
operations, cash flows or financial position.
In addition, Connecticut, New Hampshire and Massachusetts have each announced policies aimed at increased energy efficiency and
conservation. In connection with such policies, all three states have investigated revenue decoupling as a mechanism to align the
interests of customers and utilities relative to conservation. In Connecticut, the DPUC authorized decoupling via a rate design that is
intended to recover proportionately greater distribution revenue through fixed charges, and proportionately less distribution revenue
through usage-based charges. In New Hampshire, the NHPUC conducted a decoupling docket and determined that utilities were free
to propose decoupling in the context of a rate case and demonstrate the effect decoupling would have on its risk profile and ROE. In
Massachusetts, the DPU conducted a generic decoupling docket and as a result required each utility to include rate decoupling in its
next rate case. At this time it is uncertain what mechanisms will ultimately be adopted by New Hampshire and Massachusetts and what
impact these decoupling mechanisms will have on our companies.
Changes in regulatory and/or legislative policy could negatively impact regional transmission cost allocation rules.
The existing New England transmission tariff allocates the costs of transmission investment that provide regional benefits to all
customers in New England. As new investment in regional transmission infrastructure occurs in any one state, there is a sharing of their
regional costs across New England. This regional cost allocation is set forth in the Transmission Operating Agreement signed by all of
the New England transmission owning utilities. However, effective February 1, 2010, this agreement can be modified with the approval
of a majority of the transmission owning utilities and FERC. In addition, other parties, such as state regulators, may seek certain
changes to the regional cost allocation, which could have adverse effects on our distribution companies' local rates. However, the
current cost allocation is presumed reasonable, and those other parties seeking change would have to show that the allocation is no
longer just and reasonable and demonstrate to FERC why such changes are necessary. We are working to retain the existing regional
cost allocation treatment but cannot predict the actions of the states or utilities in the region.
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 companies.
Under state law, our utility 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 costs prudently incurred
by our regulated companies, such as for construction, operation and maintenance, as well as a return on investment on their respective
regulated assets. Increases in these costs, coupled with increases in fuel and energy prices could lead to consumer or regulatory
resistance to the timely recovery of such prudently incurred costs, thereby adversely affecting our cash flows and results of operations.
In addition, CL&P 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 and WMECO receive approvals of recovery of these contract prices from the DPUC 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.
The energy requirements for PSNH are currently met primarily through PSNH's 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 necessary amount of energy to meet 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.